UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2019
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ______ to _______

Commission
 
Exact name of registrant as specified in its charter;
 
IRS Employer
File Number
 
State or other jurisdiction of incorporation or organization
 
Identification No.
001-14881
 
BERKSHIRE HATHAWAY ENERGY COMPANY
 
94-2213782
 
 
(An Iowa Corporation)
 
 
 
 
666 Grand Avenue, Suite 500
 
 
 
 
Des Moines, Iowa 50309-2580
 
 
 
 
515-242-4300
 
 
 
 
 
 
 
001-05152
 
PACIFICORP
 
93-0246090
 
 
(An Oregon Corporation)
 
 
 
 
825 N.E. Multnomah Street
 
 
 
 
Portland, Oregon 97232
 
 
 
 
888-221-7070
 
 
 
 
 
 
 
333-90553
 
MIDAMERICAN FUNDING, LLC
 
47-0819200
 
 
(An Iowa Limited Liability Company)
 
 
 
 
666 Grand Avenue, Suite 500
 
 
 
 
Des Moines, Iowa 50309-2580
 
 
 
 
515-242-4300
 
 
 
 
 
 
 
333-15387
 
MIDAMERICAN ENERGY COMPANY
 
42-1425214
 
 
(An Iowa Corporation)
 
 
 
 
666 Grand Avenue, Suite 500
 
 
 
 
Des Moines, Iowa 50309-2580
 
 
 
 
515-242-4300
 
 
 
 
 
 
 
000-52378
 
NEVADA POWER COMPANY
 
88-0420104
 
 
(A Nevada Corporation)
 
 
 
 
6226 West Sahara Avenue
 
 
 
 
Las Vegas, Nevada 89146
 
 
 
 
702-402-5000
 
 
 
 
 
 
 
000-00508
 
SIERRA PACIFIC POWER COMPANY
 
88-0044418
 
 
(A Nevada Corporation)
 
 
 
 
6100 Neil Road
 
 
 
 
Reno, Nevada 89511
 
 
 
 
775-834-4011
 
 



Registrant
Securities registered pursuant to Section 12(b) of the Act:
BERKSHIRE HATHAWAY ENERGY COMPANY
None
PACIFICORP
None
MIDAMERICAN FUNDING, LLC
None
MIDAMERICAN ENERGY COMPANY
None
NEVADA POWER COMPANY
None
SIERRA PACIFIC POWER COMPANY
None

Registrant
Name of exchange on which registered:
BERKSHIRE HATHAWAY ENERGY COMPANY
None
PACIFICORP
None
MIDAMERICAN FUNDING, LLC
None
MIDAMERICAN ENERGY COMPANY
None
NEVADA POWER COMPANY
None
SIERRA PACIFIC POWER COMPANY
None

Registrant
Securities registered pursuant to Section 12(g) of the Act:
BERKSHIRE HATHAWAY ENERGY COMPANY
None
PACIFICORP
None
MIDAMERICAN FUNDING, LLC
None
MIDAMERICAN ENERGY COMPANY
None
NEVADA POWER COMPANY
Common Stock, $1.00 stated value
SIERRA PACIFIC POWER COMPANY
Common Stock, $3.75 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Registrant
Yes
No
BERKSHIRE HATHAWAY ENERGY COMPANY
 
X
PACIFICORP
 
X
MIDAMERICAN FUNDING, LLC
 
X
MIDAMERICAN ENERGY COMPANY
X
 
NEVADA POWER COMPANY
X
 
SIERRA PACIFIC POWER COMPANY
 
X

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Registrant
Yes
No
BERKSHIRE HATHAWAY ENERGY COMPANY
 
X
PACIFICORP
 
X
MIDAMERICAN FUNDING, LLC
X
 
MIDAMERICAN ENERGY COMPANY
 
X
NEVADA POWER COMPANY
 
X
SIERRA PACIFIC POWER COMPANY
 
X




Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Registrant
Yes
No
BERKSHIRE HATHAWAY ENERGY COMPANY
X
 
PACIFICORP
X
 
MIDAMERICAN FUNDING, LLC
 
X
MIDAMERICAN ENERGY COMPANY
X
 
NEVADA POWER COMPANY
X
 
SIERRA PACIFIC POWER COMPANY
X
 

Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files).Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Registrant
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
Emerging growth company
BERKSHIRE HATHAWAY ENERGY COMPANY
 
 
X
 
 
PACIFICORP
 
 
X
 
 
MIDAMERICAN FUNDING, LLC
 
 
X
 
 
MIDAMERICAN ENERGY COMPANY
 
 
X
 
 
NEVADA POWER COMPANY
 
 
X
 
 
SIERRA PACIFIC POWER COMPANY
 
 
X
 
 

If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes o No x

All shares of outstanding common stock of Berkshire Hathaway Energy Company are privately held by a limited group of investors. As of January 31, 2020, 76,549,232 shares of common stock, no par value, were outstanding.

All shares of outstanding common stock of PacifiCorp are indirectly owned by Berkshire Hathaway Energy Company. As of January 31, 2020, 357,060,915 shares of common stock, no par value, were outstanding.

All of the member's equity of MidAmerican Funding, LLC is held by its parent company, Berkshire Hathaway Energy Company, as of January 31, 2020.

All shares of outstanding common stock of MidAmerican Energy Company are owned by its parent company, MHC Inc., which is a direct, wholly owned subsidiary of MidAmerican Funding, LLC. As of January 31, 2020, 70,980,203 shares of common stock, no par value, were outstanding.

All shares of outstanding common stock of Nevada Power Company are owned by its parent company, NV Energy, Inc., which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of January 31, 2020, 1,000 shares of common stock, $1.00 stated value, were outstanding.




All shares of outstanding common stock of Sierra Pacific Power Company are owned by its parent company, NV Energy, Inc. As of January 31, 2020, 1,000 shares of common stock, $3.75 par value, were outstanding.

Berkshire Hathaway Energy Company, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing portions of this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10‑K.

This combined Form 10-K is separately filed by Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies.




TABLE OF CONTENTS
 
PART I
 
 
 
Mine Safety Disclosures
 
 
 
PART II
 
 
 
 
 
 
PART III
 
 
 
 
 
 
PART IV
 
 
 
 


i


Definition of Abbreviations and Industry Terms

When used in Forward-Looking Statements, Part I - Items 1 through 4, Part II - Items 5 through 7A, and Part III - Items 10 through 14, the following terms have the definitions indicated.
Entity Definitions
BHE
 
Berkshire Hathaway Energy Company
Berkshire Hathaway
 
Berkshire Hathaway Inc.
Berkshire Hathaway Energy or the Company
 
Berkshire Hathaway Energy Company and its subsidiaries
PacifiCorp
 
PacifiCorp and its subsidiaries
MidAmerican Funding
 
MidAmerican Funding, LLC and its subsidiaries
MidAmerican Energy
 
MidAmerican Energy Company
NV Energy
 
NV Energy, Inc. and its subsidiaries
Nevada Power
 
Nevada Power Company and its subsidiaries
Sierra Pacific
 
Sierra Pacific Power Company
Nevada Utilities
 
Nevada Power Company and Sierra Pacific Power Company
Registrants
 
Berkshire Hathaway Energy, PacifiCorp, MidAmerican Energy, MidAmerican Funding, Nevada Power and Sierra Pacific
Subsidiary Registrants
 
PacifiCorp, MidAmerican Energy, MidAmerican Funding, Nevada Power and Sierra Pacific
Northern Powergrid
 
Northern Powergrid Holdings Company
Northern Natural Gas
 
Northern Natural Gas Company
Kern River
 
Kern River Gas Transmission Company
BHE Canada
 
BHE Canada Holdings Corporation
AltaLink
 
AltaLink, L.P.
BHE U.S. Transmission
 
BHE U.S. Transmission, LLC
HomeServices
 
HomeServices of America, Inc. and its subsidiaries
BHE Pipeline Group or Pipeline Companies
 
Northern Natural Gas and Kern River
BHE Transmission
 
AltaLink and BHE U.S. Transmission
BHE Renewables
 
BHE Renewables, LLC and CalEnergy Philippines
ETT
 
Electric Transmission Texas, LLC
Domestic Regulated Businesses
 
PacifiCorp, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company, Northern Natural Gas Company and Kern River Gas Transmission Company
Regulated Businesses
 
PacifiCorp, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company, Northern Natural Gas Company, Kern River Gas Transmission Company and AltaLink, L.P.
Utilities
 
PacifiCorp, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company
Northern Powergrid Distribution Companies
 
Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc
Topaz
 
Topaz Solar Farms LLC
Topaz Project
 
550-megawatt solar project in California
Agua Caliente
 
Agua Caliente Solar, LLC
Agua Caliente Project
 
290-megawatt solar project in Arizona
Bishop Hill II
 
Bishop Hill Energy II LLC
Bishop Hill Project
 
81-megawatt wind-powered generating facility in Illinois
Pinyon Pines I
 
Pinyon Pines Wind I, LLC
Pinyon Pines II
 
Pinyon Pines Wind II, LLC
Pinyon Pines Projects
 
168-megawatt and 132-megawatt wind-powered generating facilities in California
Jumbo Road
 
Jumbo Road Holdings, LLC
Jumbo Road Project
 
300-megawatt wind-powered generating facility in Texas
Solar Star Funding
 
Solar Star Funding, LLC
Solar Star Projects
 
A combined 586-megawatt solar project in California
Solar Star I
 
Solar Star California XIX, LLC
Solar Star II
 
Solar Star California XX, LLC
 
 
 
Certain Industry Terms
 
 
2017 Tax Reform
 
The Tax Cuts and Jobs Act enacted on December 22, 2017, effective January 1, 2018
AESO
 
Alberta Electric System Operator
AFUDC
 
Allowance for Funds Used During Construction
AUC
 
Alberta Utilities Commission
Bcf
 
Billion cubic feet
BTER
 
Base Tariff Energy Rate
California ISO
 
California Independent System Operator Corporation
CPUC
 
California Public Utilities Commission
DEAA
 
Deferred Energy Accounting Adjustment
Dodd-Frank Reform Act
 
Dodd-Frank Wall Street Reform and Consumer Protection Act
Dth
 
Decatherm
DSM
 
Demand-side Management
EBA
 
Energy Balancing Account
ECAC
 
Energy Cost Adjustment Clause
ECAM
 
Energy Cost Adjustment Mechanism
EEIR
 
Energy Efficiency Implementation Rate
EEPR
 
Energy Efficiency Program Rate
EIM
 
Energy Imbalance Market
EPA
 
United States Environmental Protection Agency
ERCOT
 
Electric Reliability Council of Texas
FERC
 
Federal Energy Regulatory Commission
GAAP
 
Accounting principles generally accepted in the United States of America
GEMA
 
Gas and Electricity Markets Authority
GHG
 
Greenhouse Gases
GWh
 
Gigawatt Hour
ICC
 
Illinois Commerce Commission
IPUC
 
Idaho Public Utilities Commission
IRP
 
Integrated Resource Plan
IUB
 
Iowa Utilities Board
kV
 
Kilovolt
LNG
 
Liquefied Natural Gas
LDC
 
Local Distribution Company
MATS
 
Mercury and Air Toxics Standards
MISO
 
Midcontinent Independent System Operator, Inc.
MW
 
Megawatt
MWh
 
Megawatt Hour
NERC
 
North American Electric Reliability Corporation
NRC
 
Nuclear Regulatory Commission
OATT
 
Open Access Transmission Tariff
OCA
 
Iowa Office of Consumer Advocate
Ofgem
 
Office of Gas and Electric Markets
OPUC
 
Oregon Public Utility Commission
PCAM
 
Power Cost Adjustment Mechanism
PTAM
 
Post Test-year Adjustment Mechanism
PTC
 
Production Tax Credit
PUCN
 
Public Utilities Commission of Nevada
RCRA
 
Resource Conservation and Recovery Act
RAC
 
Renewable Adjustment Clause
REC
 
Renewable Energy Credit
RPS
 
Renewable Portfolio Standards
RRA
 
Renewable Energy Credit and Sulfur Dioxide Revenue Adjustment Mechanism
RTO
 
Regional Transmission Organization
SEC
 
United States Securities and Exchange Commission
SIP
 
State Implementation Plan
TAM
 
Transition Adjustment Mechanism
UPSC
 
Utah Public Service Commission
WECC
 
Western Electricity Coordinating Council
WPSC
 
Wyoming Public Service Commission
WUTC
 
Washington Utilities and Transportation Commission

ii



iii




iv


Forward-Looking Statements

This report contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon the relevant Registrant's current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control of each Registrant and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:
general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including income tax reform, initiatives regarding deregulation and restructuring of the utility industry, and reliability and safety standards, affecting the respective Registrant's operations or related industries;
changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce facility output, accelerate facility retirements or delay facility construction or acquisition;
the outcome of regulatory rate reviews and other proceedings conducted by regulatory agencies or other governmental and legal bodies and the respective Registrant's ability to recover costs through rates in a timely manner;
changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and private generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply or the respective Registrant's ability to obtain long-term contracts with customers and suppliers;
performance, availability and ongoing operation of the respective Registrant's facilities, including facilities not operated by the Registrants, due to the impacts of market conditions, outages and repairs, transmission constraints, weather, including wind, solar and hydroelectric conditions, and operating conditions;
the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the control of each respective Registrant or by a breakdown or failure of the Registrants' operating assets, including severe storms, floods, fires, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, litigation, wars, terrorism, embargoes, and cyber security attacks, data security breaches, disruptions, or other malicious acts;
a high degree of variance between actual and forecasted load or generation that could impact a Registrant's hedging strategy and the cost of balancing its generation resources with its retail load obligations;
changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs;
the financial condition, creditworthiness and operational stability of the respective Registrant's significant customers and suppliers;
changes in business strategy or development plans;
availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in interest rates;
changes in the respective Registrant's credit ratings;
risks relating to nuclear generation, including unique operational, closure and decommissioning risks;
hydroelectric conditions and the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings;
the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts;
the impact of inflation on costs and the ability of the respective Registrants to recover such costs in regulated rates;
fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar;
increases in employee healthcare costs;
the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and other postretirement benefits expense and funding requirements;

v


changes in the residential real estate brokerage, mortgage and franchising industries and regulations that could affect brokerage, mortgage and franchising transactions;
the ability to successfully integrate future acquired operations into a Registrant's business;
unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future facilities and infrastructure additions;
the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;
the impact of new accounting guidance or changes in current accounting estimates and assumptions on the financial results of the respective Registrants; and
other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the SEC or in other publicly disseminated written documents.

Further details of the potential risks and uncertainties affecting the Registrants are described in the Registrants' filings with the SEC, including Item 1A and other discussions contained in this Form 10-K. Each Registrant undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors should not be construed as exclusive.


vi


PART I

Item 1.    Business

GENERAL

BHE is a holding company that owns a highly diversified portfolio of locally managed businesses principally engaged in the energy industry and is a consolidated subsidiary of Berkshire Hathaway. As of January 31, 2020, Berkshire Hathaway, Mr. Walter Scott, Jr., a member of BHE's Board of Directors (along with his family members and related or affiliated entities) and Mr. Gregory E. Abel, BHE's Chairman, beneficially owned 90.9%, 8.1% and 1.0%, respectively, of BHE's voting common stock.

Berkshire Hathaway Energy's operations are organized as eight business segments: PacifiCorp, MidAmerican Funding (which primarily consists of MidAmerican Energy), NV Energy (which primarily consists of Nevada Power and Sierra Pacific), Northern Powergrid (which primarily consists of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which consists of Northern Natural Gas and Kern River), BHE Transmission (which consists of BHE Canada and BHE U.S. Transmission), BHE Renewables and HomeServices. BHE, through these locally managed and operated businesses, owns four utility companies in the United States serving customers in 11 states, two electricity distribution companies in Great Britain, two interstate natural gas pipeline companies in the United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States.

BHE owns a highly diversified portfolio of primarily regulated businesses that generate, transmit, store, distribute and supply energy and serve customers and end-users across geographically diverse service territories, including 18 states in the Western and Midwestern United States and in Great Britain and Canada.
88% of Berkshire Hathaway Energy's consolidated operating income during 2019 was generated from rate-regulated businesses.
The Utilities serve 5.1 million electric and natural gas customers in 11 states in the United States, Northern Powergrid serves 3.9 million end-users in northern England and AltaLink serves approximately 85% of Alberta, Canada's population.
As of December 31, 2019, the Company owns approximately 33,600 MWs of generation capacity in operation and under construction:
Approximately 29,000 MWs of generation capacity is owned by its regulated electric utility businesses;
Approximately 4,600 MWs of generation capacity is owned by its nonregulated subsidiaries, the majority of which provides power to utilities under long-term contracts;
Owned generation capacity in operation and under construction consists of 36% wind and solar, 32% natural gas, 26% coal, 5% hydroelectric and geothermal and 1% nuclear and other; and,
Cumulative investments in wind, solar, geothermal and biomass generation facilities is approximately $29 billion.
The Company owns approximately 33,400 miles of transmission lines and owns a 50% interest in ETT that has approximately 1,200 miles of transmission lines.
The BHE Pipeline Group owns approximately 16,300 miles of pipeline with a market area design capacity of approximately 8.5 Bcf of natural gas per day, serves customers and end-users in 14 states and transported approximately 8% of the total natural gas consumed in the United States during 2019.
HomeServices closed over $134.6 billion of home sales in 2019, up 3.6% from 2018, and continued to grow its brokerage, mortgage and franchise businesses, with services in 49 states. HomeServices' franchise business has approximately 380 franchisees primarily in the United States and internationally.

As of December 31, 2019, the Company had approximately 23,000 employees, of which approximately 8,200 were covered by union contracts. The majority of the union employees are employed by the Utilities and are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the United Utility Workers Association and the International Brotherhood of Boilermakers. HomeServices currently has over 43,000 real estate agents who are independent contractors and not employees.


1


BHE was incorporated under the laws of the state of Iowa in 1999 and its principal executive offices are located at 666 Grand Avenue, Suite 500, Des Moines, Iowa 50309-2580, its telephone number is (515) 242-4300 and its internet address is www.brkenergy.com.

PACIFICORP

General

PacifiCorp, an indirect wholly owned subsidiary of BHE, is a United States regulated electric utility company headquartered in Oregon that serves 1.9 million retail electric customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp is principally engaged in the business of generating, transmitting, distributing and selling electricity. PacifiCorp's combined service territory covers approximately 141,400 square miles and includes diverse regional economies across six states. No single segment of the economy dominates the combined service territory, which helps mitigate PacifiCorp's exposure to economic fluctuations. In the eastern portion of the service territory, consisting of Utah, Wyoming and southeastern Idaho, the principal industries are manufacturing, mining or extraction of natural resources, agriculture, technology, recreation and government. In the western portion of the service territory, consisting of Oregon, southern Washington and northern California, the principal industries are agriculture, manufacturing, forest products, food processing, technology, government and primary metals. In addition to retail sales, PacifiCorp buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants to balance and optimize the economic benefits of electricity generation, retail customer loads and existing wholesale transactions. Certain PacifiCorp subsidiaries support its electric utility operations by providing coal mining services.

PacifiCorp's operations are conducted under numerous franchise agreements, certificates, permits and licenses obtained from federal, state and local authorities. The average term of the franchise agreements is approximately 23 years. Several of these franchise agreements allow the municipality the right to seek amendment to the franchise agreement at a specified time during the term. PacifiCorp generally has an exclusive right to serve electric customers within its service territories and, in turn, has an obligation to provide electric service to those customers. In return, the state utility commissions have established rates on a cost-of-service basis, which are designed to allow PacifiCorp an opportunity to recover its costs of providing services and to earn a reasonable return on its investments.

PacifiCorp was incorporated under the laws of the state of Oregon in 1989 and its principal executive offices are located at 825 N.E. Multnomah Street, Portland, Oregon 97232, its telephone number is (888) 221-7070 and its internet address is www.pacificorp.com. PacifiCorp delivers electricity to customers in Utah, Wyoming and Idaho under the trade name Rocky Mountain Power and to customers in Oregon, Washington and California under the trade name Pacific Power.

BHE controls substantially all of PacifiCorp's voting securities, which include both common and preferred stock.

Regulated Electric Operations

Customers

The GWhs and percentages of electricity sold to PacifiCorp's retail customers by jurisdiction for the years ended December 31 were as follows:

 
2019
 
2018
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
Utah
24,490

 
45
%
 
24,514

 
45
%
 
24,134

 
44
%
Oregon
13,089

 
24

 
12,867

 
23

 
13,200

 
24

Wyoming
9,393

 
17

 
9,393

 
17

 
9,330

 
17

Washington
4,145

 
7

 
3,949

 
7

 
4,221

 
8

Idaho
3,485

 
6

 
3,643

 
7

 
3,603

 
6

California
741

 
1

 
749

 
1

 
762

 
1

Total
55,343

 
100
%
 
55,115

 
100
%
 
55,250

 
100
%


2


Electricity sold to PacifiCorp's retail and wholesale customers by class of customer and the average number of retail customers for the years ended December 31 were as follows:
 
2019
 
2018
 
2017
GWhs sold:
 
 
 
 
 
 
 
 
 
 
 
Residential
16,668

 
27
%
 
16,227

 
26
%
 
16,625

 
27
%
Commercial
18,151

 
30

 
18,078

 
28

 
17,726

 
28

Industrial, irrigation and other
20,524

 
34

 
20,810

 
33

 
20,899

 
33

Total retail
55,343

 
91

 
55,115

 
87

 
55,250

 
88

Wholesale
5,480

 
9

 
8,309

 
13

 
7,218

 
12

Total GWhs sold
60,823

 
100
%
 
63,424

 
100
%
 
62,468

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands):
 
 
 
 
 
 
 
 
 
 
 
Residential
1,682

 
87
%
 
1,651

 
87
%
 
1,622

 
87
%
Commercial
214

 
11

 
212

 
11

 
208

 
11

Industrial, irrigation and other
37

 
2

 
37

 
2

 
37

 
2

Total
1,933

 
100
%
 
1,900

 
100
%
 
1,867

 
100
%


Variations in weather, economic conditions and various conservation, energy efficiency and private generation measures and programs can impact customer usage. Wholesale sales are impacted by market prices for energy relative to the incremental cost to generate power.

The annual hourly peak customer demand, which represents the highest demand on a given day and at a given hour, occurs in the summer when air conditioning and irrigation systems are heavily used. The winter also experiences a peak demand due to heating requirements. During 2019, PacifiCorp's peak demand was 10,334 MWs in the summer and 8,604 MWs in the winter.


3



Generating Facilities and Fuel Supply

PacifiCorp has ownership interest in a diverse portfolio of generating facilities. The following table presents certain information regarding PacifiCorp's owned generating facilities as of December 31, 2019:
 
 
 
 
 
 
 
 
Facility
 
Net Owned
 
 
 
 
 
 
Installed /
 
Net Capacity
 
Capacity
Generating Facility
 
Location
 
Energy Source
 
Repowered(1)
 
(MWs)(2)
 
(MWs)(2)
COAL:
 
 
 
 
 
 
 
 
 
 
Jim Bridger Nos. 1, 2, 3 and 4
 
Rock Springs, WY
 
Coal
 
1974-1979
 
2,123

 
1,415

Hunter Nos. 1, 2 and 3
 
Castle Dale, UT
 
Coal
 
1978-1983
 
1,363

 
1,158

Huntington Nos. 1 and 2
 
Huntington, UT
 
Coal
 
1974-1977
 
909

 
909

Dave Johnston Nos. 1, 2, 3 and 4
 
Glenrock, WY
 
Coal
 
1959-1972
 
745

 
745

Cholla No. 4(3)
 
Joseph City, AZ
 
Coal
 
1981
 
395

 
395

Naughton Nos. 1 and 2
 
Kemmerer, WY
 
Coal
 
1963-1968
 
357

 
357

Wyodak No. 1
 
Gillette, WY
 
Coal
 
1978
 
332

 
266

Craig Nos. 1 and 2
 
Craig, CO
 
Coal
 
1979-1980
 
837

 
161

Colstrip Nos. 3 and 4
 
Colstrip, MT
 
Coal
 
1984-1986
 
1,480

 
148

Hayden Nos. 1 and 2
 
Hayden, CO
 
Coal
 
1965-1976
 
441

 
77

 
 
 
 
 
 
 
 
8,982

 
5,631

NATURAL GAS:
 
 
 
 
 
 
 
 
 
 
Lake Side 2
 
Vineyard, UT
 
Natural gas/steam
 
2014
 
631

 
631

Lake Side
 
Vineyard, UT
 
Natural gas/steam
 
2007
 
546

 
546

Currant Creek
 
Mona, UT
 
Natural gas/steam
 
2005-2006
 
524

 
524

Chehalis
 
Chehalis, WA
 
Natural gas/steam
 
2003
 
477

 
477

Gadsby Steam
 
Salt Lake City, UT
 
Natural gas
 
1951-1955
 
238

 
238

Hermiston
 
Hermiston, OR
 
Natural gas/steam
 
1996
 
461

 
231

Gadsby Peakers
 
Salt Lake City, UT
 
Natural gas
 
2002
 
119

 
119

Naughton No. 3(4)
 
Kemmerer, WY
 
Natural gas
 
1971
 
27

 
27

 
 
 
 
 
 
 
 
3,023

 
2,793

HYDROELECTRIC:
 
 
 
 
 
 
 
 
 
 
Lewis River System
 
WA
 
Hydroelectric
 
1931-1958
 
578

 
578

North Umpqua River System
 
OR
 
Hydroelectric
 
1950-1956
 
204

 
204

Klamath River System
 
CA, OR
 
Hydroelectric
 
1903-1962
 
170

 
170

Bear River System
 
ID, UT
 
Hydroelectric
 
1908-1984
 
105

 
105

Rogue River System
 
OR
 
Hydroelectric
 
1912-1957
 
52

 
52

Minor hydroelectric facilities
 
Various
 
Hydroelectric
 
1895-1986
 
26

 
26

 
 
 
 
 
 
 
 
1,135

 
1,135

WIND:
 
 
 
 
 
 
 
 
 
 
Marengo
 
Dayton, WA
 
Wind
 
2007-2008
 
210

 
210

Glenrock
 
Glenrock, WY
 
Wind
 
2008-2009 / 2019
 
139

 
139

Seven Mile Hill
 
Medicine Bow, WY
 
Wind
 
2008 / 2019
 
119

 
119

Dunlap Ranch
 
Medicine Bow, WY
 
Wind
 
2010
 
111

 
111

Leaning Juniper
 
Arlington, OR
 
Wind
 
2006 / 2019
 
100

 
100

Rolling Hills
 
Glenrock, WY
 
Wind
 
2009 / 2019
 
100

 
100

High Plains
 
McFadden, WY
 
Wind
 
2009 / 2019
 
99

 
99

Goodnoe Hills
 
Goldendale, WA
 
Wind
 
2008 / 2019
 
94

 
94

Foote Creek(5)
 
Arlington, WY
 
Wind
 
1999
 
41

 
41

McFadden Ridge
 
McFadden, WY
 
Wind
 
2009 / 2019
 
28

 
28

 
 
 
 
 
 
 
 
1,041

 
1,041

OTHER:
 
 
 
 
 
 
 
 
 
 
Blundell
 
Milford, UT
 
Geothermal
 
1984, 2007
 
32

 
32

 
 
 
 
 
 
 
 
32

 
32

Total Available Generating Capacity
 
 
 
 
 
14,213

 
10,632

 
 
 
 
 
 
 
 
 
 
 
PROJECTS UNDER CONSTRUCTION:
 
 
 
 
 
 
 
 
 
 
Various wind projects
 
 
 
 
 
1,190

 
1,190

 
 
 
 
 
 
 
 
15,403

 
11,822


4



(1)
Repowered dates are associated with component replacements on existing wind-powered generating facilities commonly referred to by the Internal Revenue Service (“IRS”) as repowering. IRS rules provide for re-establishment of the PTCs for an existing wind-powered generating facility upon the replacement of a significant portion of its components. If the degree of component replacement in such projects meets IRS guidelines, PTCs are re-established for ten years at rates that depend upon the date on which construction begins.
(2)
Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates PacifiCorp's ownership of Facility Net Capacity.
(3)
In December 2019, PacifiCorp initiated steps towards retiring Cholla Unit 4 by December 31, 2020 consistent with the preferred portfolio in PacifiCorp’s 2019 IRP that ceasing operations at Cholla Unit 4 as early as the end of 2020 provides economic benefits to customers. Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion.
(4)
PacifiCorp removed the unit from coal-fueled service on January 30, 2019, and determined in its 2019 IRP that converting Naughton Unit 3 to a natural gas-fueled generation resource provides economic benefits to customers. Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion.
(5)
In June 2019, PacifiCorp acquired the remaining joint owner's 21% interest in the Foote Creek I facility, and is in the process of repowering the facility.

The following table shows the percentages of PacifiCorp's total energy supplied by energy source for the years ended December 31:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Coal
53
%
 
54
%
 
56
%
Natural gas
19

 
16

 
11

Hydroelectric(1)
4

 
5

 
7

Wind and other(1)
4

 
5

 
5

Total energy generated
80

 
80

 
79

Energy purchased - short-term contracts and other
10

 
10

 
11

Energy purchased - long-term contracts (renewable)(1)
10

 
10

 
10

 
100
%
 
100
%
 
100
%

(1)
All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements, (b) sold to third parties in the form of RECs or other environmental commodities, or (c) excluded from energy purchased.

PacifiCorp is required to have resources available to continuously meet its customer needs and reliably operate its electric system. The percentage of PacifiCorp's energy supplied by energy source varies from year to year and is subject to numerous operational and economic factors such as planned and unplanned outages, fuel commodity prices, fuel transportation costs, weather, environmental considerations, transmission constraints and wholesale market prices of electricity. PacifiCorp evaluates these factors continuously in order to facilitate economical dispatch of its generating facilities. When factors for one energy source are less favorable, PacifiCorp places more reliance on other energy sources. For example, PacifiCorp can generate more electricity using its low cost hydroelectric and wind-powered generating facilities when factors associated with these facilities are favorable. In addition to meeting its customers' energy needs, PacifiCorp is required to maintain operating reserves on its system to mitigate the impacts of unplanned outages or other disruption in supply, and to meet intra-hour changes in load and resource balance. This operating reserve requirement is dispersed across PacifiCorp's generation portfolio on a least-cost basis based on the operating characteristics of the portfolio. Operating reserves may be held on hydroelectric, coal-fueled, natural gas-fueled or certain types of interruptible load. PacifiCorp manages certain risks relating to its supply of electricity and fuel requirements by entering into various contracts, which may be accounted for as derivatives and may include forwards, options, swaps and other agreements. Refer to "General Regulation" in Item 1 of this Form 10-K for a discussion of energy cost recovery by jurisdiction and to PacifiCorp's Item 7A in this Form 10-K for a discussion of commodity price risk and derivative contracts.

Coal

PacifiCorp has interests in coal mines that support its coal-fueled generating facilities and jointly operates the Bridger surface and Bridger underground coal mines. These mines supplied 19%, 17% and 16% of PacifiCorp's total coal requirements during the years ended December 31, 2019, 2018 and 2017, respectively. The remaining coal requirements are acquired through long and short-term third-party contracts.


5


Most of PacifiCorp's coal reserves are held through agreements with the federal Bureau of Land Management and from certain states and private parties. The agreements generally have multi-year terms that may be renewed or extended, and require payment of rents and royalties. In addition, federal and state regulations require that comprehensive environmental protection and reclamation standards be met during the course of mining operations and upon completion of mining activities.

Coal reserve estimates are subject to adjustment as a result of the development of additional engineering and geological data, new mining technology and changes in regulation and economic factors affecting the utilization of such reserves. PacifiCorp's recoverable coal reserves of operating mines as of December 31, 2019, based on recent engineering studies, were as follows (in millions):
Coal Mine
 
Location
 
Generating Facility Served
 
Mining Method
 
Recoverable Tons
 
 
 
 
 
 
 
 
 
Bridger
 
Rock Springs, WY
 
Jim Bridger
 
Surface
 
14

(1
)
Bridger
 
Rock Springs, WY
 
Jim Bridger
 
Underground
 
3

(1
)
Trapper
 
Craig, CO
 
Craig
 
Surface
 
4

(2
)
 
 
 
 
 
 
 
 
21

 

(1)
These coal reserves are leased and mined by Bridger Coal Company, a joint venture between Pacific Minerals, Inc. and a subsidiary of Idaho Power Company. Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp, has a two-thirds interest in the joint venture. The amounts included above represent only PacifiCorp's two-thirds interest in the coal reserves.
(2)
These coal reserves are leased and mined by Trapper Mining Inc., a cooperative in which PacifiCorp has an ownership interest of 21%. The amount included above represents only PacifiCorp's 21% interest in the coal reserves. PacifiCorp does not operate the Trapper mine.

Recoverability by surface mining methods typically ranges from 90% to 95%. Recoverability by underground mining techniques ranges from 50% to 70%. To meet applicable standards, PacifiCorp blends coal from its owned mines with contracted coal and utilizes emissions reduction technologies for controlling sulfur dioxide and other emissions. For fuel needs at PacifiCorp's coal-fueled generating facilities in excess of coal reserves available, PacifiCorp believes it will be able to purchase coal under both long- and short-term contracts to supply its generating facilities over their currently expected remaining useful lives.

Natural Gas

PacifiCorp uses natural gas as fuel for its generating facilities that use combined-cycle, simple-cycle and steam turbines. Oil and natural gas are also used for igniter fuel and standby purposes. These sources are presently in adequate supply and available to meet PacifiCorp's needs.

PacifiCorp enters into forward natural gas purchases at fixed or indexed market prices. PacifiCorp purchases natural gas in the spot market with both fixed and indexed market prices for physical delivery to fulfill any fuel requirements not already satisfied through forward purchases of natural gas and sells natural gas in the spot market for the disposition of any excess supply if the forecasted requirements of its natural gas-fueled generating facilities decrease. PacifiCorp also utilizes financial swap contracts to mitigate price risk associated with its forecasted fuel requirements.

Hydroelectric

The amount of electricity PacifiCorp is able to generate from its hydroelectric facilities depends on a number of factors, including snowpack in the mountains upstream of its hydroelectric facilities, reservoir storage, precipitation in its watersheds, generating unit availability and restrictions imposed by oversight bodies due to competing water management objectives.

PacifiCorp operates the majority of its hydroelectric generating portfolio under long-term licenses. The FERC regulates 99% of the net capacity of this portfolio through 15 individual licenses, which have terms of 30 to 50 years. The licenses for major hydroelectric generating facilities expire at various dates through 2059. A portion of this portfolio is licensed under the Oregon Hydroelectric Act. For discussion of PacifiCorp's hydroelectric relicensing activities, including updated information regarding the Klamath River hydroelectric system, refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K.


6


Wind and Other Renewable Resources

PacifiCorp has pursued renewable resources as a viable, economical and environmentally prudent means of supplying electricity and complying with laws and regulations. Renewable resources have low to no emissions and require little or no fossil fuel. PacifiCorp's wind-powered generating facilities include those facilities where a significant portion of the equipment is currently being replaced to become eligible for federal renewable electricity PTCs for 10 years from the date the repowered facilities are placed in-service. PTCs for PacifiCorp's currently eligible wind-powered generating facilities began expiring in 2016 with final expiration in 2020. PacifiCorp is in the process of repowering all of its wind-powered generating facilities by the end of 2020 to requalify the facilities for federal renewable electricity PTCs for 10 years. The repowering project will extend the lives of the existing wind facilities by 10 years or more while increasing the anticipated electrical generation from the repowered wind facilities, on average, by approximately 26%. In addition to the discussion contained herein regarding repowering activities, refer to "Regulatory Matters" in Item 1 of this Form 10-K.

Wholesale Activities

PacifiCorp purchases and sells electricity in the wholesale markets as needed to balance its generation with its retail load obligations. PacifiCorp may also purchase electricity in the wholesale markets when it is more economical than generating electricity from its own facilities and may sell surplus electricity in the wholesale markets when it can do so economically. When prudent, PacifiCorp enters into financial swap contracts and forward electricity sales and purchases for physical delivery at fixed prices to reduce its exposure to electricity price volatility.

Energy Imbalance Market

PacifiCorp and the California ISO implemented an EIM in November 2014, which reduces costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, more effectively integrates renewables and enhances reliability through improved situational awareness and responsiveness. The EIM expands the real-time component of the California ISO's market technology to optimize and balance electricity supply and demand every five minutes across the EIM footprint. The EIM is voluntary and available to all balancing authorities in the western United States. EIM market participants submit bids to the California ISO market operator before each hour for each generating resource they choose to be dispatched by the market. Each bid is comprised of a dispatchable operating range, ramp rate and prices across the operating range. The California ISO market operator uses sophisticated technology to select the least-cost resources to meet demand and send simultaneous dispatch signals to every participating generator across the EIM footprint every five minutes. In addition to generation resource bids, the California ISO market operator also receives continuous real-time updates of the transmission grid network, meteorological and load forecast information that it uses to optimize dispatch instructions. Outside the EIM footprint, utilities in the western United States do not utilize comparable technology and are largely limited to transactions within the borders of their balancing authority area to balance supply and demand intra-hour using a combination of manual and automated dispatch. The EIM delivers customer benefits by leveraging automation and resource diversity to result in more efficient dispatch, more effective integration of renewables and improved situational awareness. Benefits are expected to increase further with renewable resource expansion and as more entities join the EIM, bringing incremental resource diversity.

PacifiCorp will continue to monitor regional market expansion efforts, including creation of a regional Independent System Operator ("ISO"). California Senate Bill No. 350, which was passed in October 2015, authorized the California legislature to consider making changes to current laws that would create an independent governance structure for a regional ISO during the 2017 legislative session. The California legislature did not pass any legislation related to a regional ISO during its 2019 legislative session, which adjourned September 13, 2019.

Transmission and Distribution

PacifiCorp operates one balancing authority area in the western portion of its service territory ("PacifiCorp-West") and one balancing authority area in the eastern portion of its service territory ("PacifiCorp-East"). A balancing authority area is a geographic area with transmission systems that control generation to maintain schedules with other balancing authority areas and ensure reliable operations. In operating the balancing authority areas, PacifiCorp is responsible for continuously balancing electricity supply and demand by dispatching generating resources and interchange transactions so that generation internal to the balancing authority area, plus net imported power, matches customer loads. Deliveries of energy over PacifiCorp's transmission system are managed and scheduled in accordance with FERC requirements.


7


PacifiCorp's transmission system is part of the Western Interconnection, which includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico. PacifiCorp's transmission system, together with contractual rights on other transmission systems, enables PacifiCorp to integrate and access generation resources to meet its customer load requirements. PacifiCorp's transmission and distribution systems included approximately 16,600 miles of transmission lines in ten states, 64,600 miles of distribution lines and 900 substations as of December 31, 2019.

PacifiCorp's transmission and distribution system is managed on a coordinated basis to obtain maximum load-carrying capability and efficiency. Portions of PacifiCorp's transmission and distribution systems are located:

On property owned or used through agreements by PacifiCorp;
Under or over streets, alleys, highways and other public places, the public domain and national forests and state and federal lands under franchises, easements or other rights that are generally subject to termination;
Under or over private property as a result of easements obtained primarily from the title holder of record; or
Under or over Native American reservations through agreements with the United States Secretary of Interior or Native American tribes.
It is possible that some of the easements and the property over which the easements were granted may have title defects or may be subject to mortgages or liens existing at the time the easements were acquired.

PacifiCorp's Energy Gateway Transmission Expansion Program represents plans to build approximately 2,000 miles of new high-voltage transmission lines, with an estimated cost exceeding $6 billion, primarily in Wyoming, Utah, Idaho and Oregon. The $6 billion estimated cost includes: (a) the 135-mile, 345-kV Populus to Terminal transmission line between the Terminal substation near the Salt Lake City Airport and the Populus substation in Downey, Idaho placed in-service in 2010; (b) the 100-mile, 345/500-kV Mona to Oquirrh transmission line between the Mona substation in central Utah and the Oquirrh substation in the Salt Lake Valley placed in-service in 2013; (c) the 170-mile, 345-kV transmission line between the Sigurd Substation in central Utah and the Red Butte Substation in southwest Utah placed in-service in May 2015; and (d) the 140-mile, 500-kV transmission line between Aeolus Substation near Medicine Bow in Wyoming and Jim Bridger generating facility expected to be placed in-service in 2020, (e) other segments that are expected to be placed in-service in future years, depending on load growth, siting, permitting and construction schedules. The transmission line segments are intended to: (a) address customer load growth; (b) improve system reliability; (c) reduce transmission system constraints; (d) provide access to diverse generation resources, including renewable resources; and (e) improve the flow of electricity throughout PacifiCorp's six-state service area. Proposed transmission line segments are evaluated to ensure optimal benefits and timing before committing to move forward with permitting and construction. Through December 31, 2019, $2.5 billion had been spent and $1.6 billion, including AFUDC, had been placed in-service.

Future Generation, Conservation and Energy Efficiency

Energy Supply Planning

As required by certain state regulations, PacifiCorp uses an IRP to develop a long-term resource plan to ensure that PacifiCorp can continue to provide reliable and cost-effective electric service to its customers while maintaining compliance with existing and evolving environmental laws and regulations. The IRP process identifies the amount and timing of PacifiCorp's expected future resource needs, accounting for planning uncertainty, risks, reliability, state energy policies and other factors. The IRP is prepared following a public process, which provides an opportunity for stakeholders to participate in PacifiCorp's resource planning process. PacifiCorp files its IRP on a biennial basis with the state commissions in each of the six states where PacifiCorp operates. Five states indicate whether the IRP meets the state commission's IRP standards and guidelines, a process referred to as "acknowledgment" in some states.


8


In October 2019, PacifiCorp filed its 2019 IRP with its state commissions. The IRP includes new transmission investments that will facilitate growth in new renewable energy resources, new storage resources, and expansion in new energy efficiency measures and demand-response programs. The IRP also includes accelerated coal-fueled generation facility retirements and the need for incremental flexible capacity resources beginning in 2026. Delivery of new transmission infrastructure that will facilitate approximately 4,400 MWs of new renewable energy resources, incremental to new renewable capacity that will come online by the end of 2020, and the addition of approximately 600 MWs of new storage capacity is planned through 2023. The IRP outlines PacifiCorp's plan to procure these near-term generating facilities through a Request for Proposals ("RFP") process that will determine how many of the new resources identified in the IRP will be developed as owned assets or power purchase agreements. Over the next 20 years, the IRP calls for retiring approximately 4,500 MWs of coal-fueled generating capacity while adding approximately 8,900 MWs of new renewable resources, incremental to new renewable capacity of approximately 2,000 MWs that will come online by the end of 2020, and approximately 2,800 MWs of new storage capacity. All or some of the renewable energy attributes associated with generation from these renewable resources may be used in future years to comply with RPS or other regulatory requirements, sold to third parties in the form of RECs or other environmental commodities, or excluded from energy purchased.

Requests for Proposals

PacifiCorp issues individual RFPs, each of which typically focuses on a specific category of generation resources consistent with the IRP or other customer-driven demands. The IRP and the RFPs provide for the identification and staged procurement of resources to meet load or renewable portfolio standard requirements. Depending upon the specific RFP, applicable laws and regulations may require PacifiCorp to file draft RFPs with the UPSC, the OPUC and the WUTC. Approval by the UPSC, the OPUC or the WUTC may be required depending on the nature of the RFPs. In 2019, PacifiCorp completed the agreements for acquisition of follow-on wind turbine equipment for the final two projects associated with the 2017R RFP. PacifiCorp is not currently administering active resource RFPs.

Energy Efficiency Programs

PacifiCorp has provided a comprehensive set of DSM programs to its customers since the 1970s. The programs are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. PacifiCorp offers services to customers such as energy engineering audits and information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, PacifiCorp offers rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors, process equipment and systems, as well as incentives for energy project management, efficient building operations and efficient construction. Incentives are also paid to solicit participation in load management programs by residential, business and agricultural customers through programs such as PacifiCorp's residential and small commercial air conditioner load control program and irrigation equipment load control programs. Although subject to prudence reviews, state regulations allow for contemporaneous recovery of costs incurred for the DSM programs through state-specific energy efficiency surcharges to retail customers or for recovery of costs through rates. During 2019, PacifiCorp spent $152 million on these DSM programs, resulting in an estimated 551,088 MWhs of first-year energy savings and an estimated 284 MWs of peak load management. In addition to these DSM programs, PacifiCorp has load curtailment contracts with a number of large industrial customers that deliver up to 305 MWs of load reduction when needed, depending on the customers' actual loads. Recovery of the costs associated with the large industrial load management program are captured in the retail special contract agreements with those customers approved by their respective state commissions or through PacifiCorp's general rate case process.

Employees

As of December 31, 2019, PacifiCorp had approximately 5,300 employees, of which approximately 3,000 were covered by union contracts, principally with the International Brotherhood of Electrical Workers, the Utility Workers Union of America and the International Brotherhood of Boilermakers.


9


MIDAMERICAN FUNDING AND MIDAMERICAN ENERGY

General

MidAmerican Funding and MHC

MidAmerican Funding, a wholly owned subsidiary of BHE, is a holding company headquartered in Iowa that owns all of the outstanding common stock of MHC Inc. ("MHC"), which is a holding company owning all of the common stock of MidAmerican Energy and Midwest Capital Group, Inc. ("Midwest Capital"). MidAmerican Funding and MidAmerican Energy are indirect consolidated subsidiaries of Berkshire Hathaway. MidAmerican Funding conducts no business other than activities related to its debt securities and the ownership of MHC. MHC conducts no business other than the ownership of its subsidiaries and related corporate services. MidAmerican Energy is a substantial portion of MidAmerican Funding's and MHC's assets, revenue and earnings.

MidAmerican Funding was formed as a limited liability company under the laws of the state of Iowa in 1999 and its principal executive offices are located at 666 Grand Avenue, Suite 500, Des Moines, Iowa 50309-2580 and its telephone number is (515) 242-4300.

MidAmerican Energy

MidAmerican Energy, an indirect wholly owned subsidiary of BHE, is a United States regulated electric and natural gas utility company headquartered in Iowa that serves 0.8 million retail electric customers in portions of Iowa, Illinois and South Dakota and 0.8 million retail and transportation natural gas customers in portions of Iowa, South Dakota, Illinois and Nebraska. MidAmerican Energy is principally engaged in the business of generating, transmitting, distributing and selling electricity and in distributing, selling and transporting natural gas. MidAmerican Energy's service territory covers approximately 11,000 square miles. Metropolitan areas in which MidAmerican Energy distributes electricity at retail include Council Bluffs, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; and the Quad Cities (Davenport and Bettendorf, Iowa and Rock Island, Moline and East Moline, Illinois). Metropolitan areas in which it distributes natural gas at retail include Cedar Rapids, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities; and Sioux Falls, South Dakota. MidAmerican Energy has a diverse customer base consisting of urban and rural residential customers and a variety of commercial and industrial customers. Principal industries served by MidAmerican Energy include electronic data storage; processing and sales of food products; manufacturing, processing and fabrication of primary metals, farm and other non-electrical machinery; cement and gypsum products; and government. In addition to retail sales and natural gas transportation, MidAmerican Energy sells electricity principally to markets operated by RTOs and natural gas to other utilities and market participants on a wholesale basis. MidAmerican Energy is a transmission-owning member of the MISO and participates in its capacity, energy and ancillary services markets.

MidAmerican Energy's regulated electric and natural gas operations are conducted under numerous franchise agreements, certificates, permits and licenses obtained from federal, state and local authorities. The franchise agreements, with various expiration dates, are typically for 20- to 25-year terms. Several of these franchise agreements give either party the right to seek amendment to the franchise agreement at one or two specified times during the term. MidAmerican Energy generally has an exclusive right to serve electric customers within its service territories and, in turn, has an obligation to provide electricity service to those customers. In return, the state utility commissions have established rates on a cost-of-service basis, which are designed to allow MidAmerican Energy an opportunity to recover its costs of providing services and to earn a reasonable return on its investment. In Illinois, MidAmerican Energy's regulated retail electric customers may choose their energy supplier.


10


The percentages of MidAmerican Energy's operating revenue and operating income derived from the following business activities for the years ended December 31 were as follows:

 
2019
 
2018
 
2017
Operating revenue:
 
 
 
 
 
Regulated electric
76
%
 
75
%
 
75
%
Regulated gas
23

 
25

 
25

Other
1

 

 

 
100
%
 
100
%
 
100
%
 
 
 
 
 
 
Operating income:
 
 
 
 
 
Regulated electric
86
%
 
85
%
 
86
%
Regulated gas
13

 
15

 
14

Other
1

 

 

 
100
%
 
100
%
 
100
%

MidAmerican Energy was incorporated under the laws of the state of Iowa in 1995 and its principal executive offices are located at 666 Grand Avenue, Suite 500, Des Moines, Iowa 50309-2580, its telephone number is (515) 242-4300 and its internet address is www.midamericanenergy.com.

Regulated Electric Operations

Customers

The GWhs and percentages of electricity sold to MidAmerican Energy's retail customers by jurisdiction for the years ended December 31 were as follows:
 
2019
 
2018
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
Iowa
24,073

 
92
%
 
23,670

 
92
%
 
22,365

 
91
%
Illinois
1,894

 
7

 
1,944

 
7

 
1,891

 
8

South Dakota
234

 
1

 
237

 
1

 
236

 
1

 
26,201

 
100
%
 
25,851

 
100
%
 
24,492

 
100
%


11


Electricity sold to MidAmerican Energy's retail and wholesale customers by class of customer and the average number of retail customers for the years ended December 31 were as follows:

 
2019
 
2018
 
2017
GWhs sold:
 
 
 
 
 
 
 
 
 
 
 
Residential
6,575

 
18
%
 
6,763

 
18
%
 
6,207

 
18
%
Commercial
3,921

 
11

 
3,897

 
11

 
3,761

 
11

Industrial
14,127

 
39

 
13,587

 
37

 
12,957

 
39

Other
1,578

 
4

 
1,604

 
4

 
1,567

 
5

Total retail
26,201

 
72

 
25,851

 
70

 
24,492

 
73

Wholesale
10,000

 
28

 
11,181

 
30

 
9,165

 
27

Total GWhs sold
36,201

 
100
%
 
37,032

 
100
%
 
33,657

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands):
 
 
 
 
 
 
 
 
 
 
 
Residential
675

 
86
%
 
670

 
86
%
 
662

 
86
%
Commercial
95

 
12

 
94

 
12

 
92

 
12

Industrial
2

 

 
2

 

 
2

 

Other
14

 
2

 
14

 
2

 
14

 
2

Total
786

 
100
%
 
780

 
100
%
 
770

 
100
%

Variations in weather, economic conditions and various conservation and energy efficiency measures and programs can impact customer usage. Wholesale sales are impacted by market prices for energy relative to the incremental cost to generate power.

There are seasonal variations in MidAmerican Energy's electricity sales that are principally related to weather and the related use of electricity for air conditioning. Additionally, electricity sales are priced higher in the summer months compared to the remaining months of the year. As a result, 40% to 50% of MidAmerican Energy's regulated electric revenue is reported in the months of June, July, August and September.

A degree of concentration of sales exists with certain large electric retail customers. Sales to the ten largest customers, from a variety of industries, comprised 21%, 20% and 19% of total retail electric sales in 2019, 2018 and 2017, respectively. Sales to electronic data storage customers included in the ten largest customers comprised 12%, 9% and 9% of total retail electric sales in 2019, 2018 and 2017, respectively.

The annual hourly peak demand on MidAmerican Energy's electric system usually occurs as a result of air conditioning use during the cooling season. Peak demand represents the highest demand on a given day and at a given hour. On July 19, 2019, retail customer usage of electricity caused a new record hourly peak demand of 5,095 MWs on MidAmerican Energy's electric distribution system, which is 44 MWs greater than the previous record hourly peak demand of 5,051 MWs set July 12, 2018.


12


Generating Facilities and Fuel Supply

MidAmerican Energy has ownership interest in a diverse portfolio of generating facilities. The following table presents certain information regarding MidAmerican Energy's owned generating facilities as of December 31, 2019:
 
 
 
 
 
 
 
 
Facility
 
Net
 
 
 
 
 
 
Year Installed /
 
Net Capacity
 
Owned Capacity
Generating Facility
 
Location
 
Energy Source
 
Repowered(1)
 
(MWs)(2)
 
(MWs)(2)
WIND:
 
 
 
 
 
 
 
 
 
 
Ida Grove
 
Ida Grove, IA
 
Wind
 
2016-2019
 
501

 
501

Orient
 
Greenfield, IA
 
Wind
 
2018-2019
 
501

 
501

Highland
 
Primghar, IA
 
Wind
 
2015
 
475

 
475

Rolling Hills
 
Massena, IA
 
Wind
 
2011
 
443

 
443

Beaver Creek
 
Ogden, IA
 
Wind
 
2017-2018
 
340

 
340

North English
 
Montezuma, IA
 
Wind
 
2018-2019
 
340

 
340

Pomeroy
 
Pomeroy, IA
 
Wind
 
2007-2011 / 2018-2019
 
286

 
286

Arbor Hill
 
Greenfield, IA
 
Wind
 
2018-2019
 
281

 
281

Lundgren
 
Otho, IA
 
Wind
 
2014
 
250

 
250

O'Brien
 
Primghar, IA
 
Wind
 
2016
 
250

 
250

Palo Alto
 
Palo Alto, IA
 
Wind
 
2019
 
248

 
248

Century
 
Blairsburg, IA
 
Wind
 
2005-2008 / 2017-2018
 
200

 
200

Eclipse
 
Adair, IA
 
Wind
 
2012
 
200

 
200

Intrepid
 
Schaller, IA
 
Wind
 
2004-2005 / 2017
 
176

 
176

Adair
 
Adair, IA
 
Wind
 
2008 / 2019
 
175

 
175

Prairie
 
Montezuma, IA
 
Wind
 
2017-2018
 
168

 
168

Carroll
 
Carroll, IA
 
Wind
 
2008 / 2019
 
150

 
150

Walnut
 
Walnut, IA
 
Wind
 
2008 / 2019
 
150

 
150

Vienna
 
Gladbrook, IA
 
Wind
 
2012-2013
 
150

 
150

Adams
 
Lennox, IA
 
Wind
 
2015
 
150

 
150

Wellsburg
 
Wellsburg, IA
 
Wind
 
2014
 
139

 
139

Laurel
 
Laurel, IA
 
Wind
 
2011
 
120

 
120

Macksburg
 
Macksburg, IA
 
Wind
 
2014
 
119

 
119

Morning Light
 
Adair, IA
 
Wind
 
2012
 
100

 
100

Victory
 
Westside, IA
 
Wind
 
2006 / 2017-2018
 
99

 
99

Ivester
 
Wellsburg, IA
 
Wind
 
2018
 
91

 
91

Charles City
 
Charles City, IA
 
Wind
 
2008 / 2018
 
75

 
75

 
 
 
 
 
 
 
 
6,177

 
6,177

COAL:
 
 
 
 
 
 
 
 
 
 
Louisa
 
Muscatine, IA
 
Coal
 
1983
 
749

 
659

Walter Scott, Jr. Unit No. 3
 
Council Bluffs, IA
 
Coal
 
1978
 
698

 
552

Walter Scott, Jr. Unit No. 4
 
Council Bluffs, IA
 
Coal
 
2007
 
817

 
487

Ottumwa
 
Ottumwa, IA
 
Coal
 
1981
 
720

 
375

George Neal Unit No. 3
 
Sergeant Bluff, IA
 
Coal
 
1975
 
510

 
367

George Neal Unit No. 4
 
Salix, IA
 
Coal
 
1979
 
643

 
261

 
 
 
 
 
 
 
 
4,137

 
2,701

NATURAL GAS AND OTHER:
 
 
 
 
 
 
 
 
 
 
Greater Des Moines
 
Pleasant Hill, IA
 
Gas
 
2003-2004
 
483

 
483

Electrifarm
 
Waterloo, IA
 
Gas or Oil
 
1975-1978
 
183

 
183

Pleasant Hill
 
Pleasant Hill, IA
 
Gas or Oil
 
1990-1994
 
155

 
155

Sycamore
 
Johnston, IA
 
Gas or Oil
 
1974
 
144

 
144

River Hills
 
Des Moines, IA
 
Gas
 
1966-1967
 
118

 
118

Riverside Unit No. 5
 
Bettendorf, IA
 
Gas
 
1961
 
114

 
114

Coralville
 
Coralville, IA
 
Gas
 
1970
 
66

 
66

Moline
 
Moline, IL
 
Gas
 
1970
 
64

 
64

28 portable power modules
 
Various
 
Oil
 
2000
 
56

 
56

Parr
 
Charles City, IA
 
Gas
 
1969
 
33

 
33

 
 
 
 
 
 
 
 
1,416

 
1,416

 
 
 
 
 
 
 
 
 
 
 
NUCLEAR:
 
 
 
 
 
 
 
 
 
 
Quad Cities Unit Nos. 1 and 2
 
Cordova, IL
 
Uranium
 
1972
 
1,821

 
455

 
 
 
 
 
 
 
 
 
 
 
HYDROELECTRIC:
 
 
 
 
 
 
 
 
 
 
Moline Unit Nos. 1-4
 
Moline, IL
 
Hydroelectric
 
1941
 
4

 
4

 
 
 
 
 
 
 
 
 
 
 
Total Available Generating Capacity
 
 
 
 
 
13,555

 
10,753

 
 
 
 
 
 
 
 
 
 
 
PROJECTS UNDER CONSTRUCTION:
 
 
 
 
 
 
 
 
Various wind projects
 
 
 
 
 
 
 
626

 
626

 
 
 
 
14,181

 
11,379


13


(1)
Repowered dates are associated with component replacements on existing wind-powered generating facilities commonly referred to by the Internal Revenue Service (“IRS”) as repowering. IRS rules provide for re-establishment of the PTCs for an existing wind-powered generating facility upon the replacement of a significant portion of its components. If the degree of component replacement in such projects meets IRS guidelines, PTCs are re-established for ten years at rates that depend upon the date on which construction begins.
(2)
Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates MidAmerican Energy's ownership of Facility Net Capacity.

The following table shows the percentages of MidAmerican Energy's total energy supplied by energy source for the years ended December 31:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Coal
33
%
 
42
%
 
40
%
Nuclear
10

 
10

 
11

Natural gas
1

 
2

 
1

Wind and other(1)
44

 
36

 
38

Total energy generated
88

 
90

 
90

Energy purchased - short-term contracts and other
10

 
8

 
8

Energy purchased - long-term contracts (renewable)(1)
1

 
1

 
1

Energy purchased - long-term contracts (non-renewable)
1

 
1

 
1

 
100
%
 
100
%
 
100
%

(1)
All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements, (b) sold to third parties in the form of RECs or other environmental commodities, or (c) excluded from energy purchased.

MidAmerican Energy is required to have resources available for dispatch by MISO to continuously meet its customer needs and reliably operate its electric system. The percentage of MidAmerican Energy's energy supplied by energy source varies from year to year and is subject to numerous operational and economic factors such as planned and unplanned outages, fuel commodity prices, fuel transportation costs, weather, environmental considerations, transmission constraints, and wholesale market prices of electricity. MidAmerican Energy evaluates these factors continuously in order to facilitate economical dispatch of its generating facilities by MISO. When factors for one energy source are less favorable, MidAmerican Energy places more reliance on other energy sources. For example, MidAmerican Energy can generate more electricity using its low cost wind-powered generating facilities when factors associated with these facilities are favorable. When factors associated with wind resources are less favorable, MidAmerican Energy must increase its reliance on more expensive generation or purchased electricity. Refer to "General Regulation" in Item 1 of this Form 10-K for a discussion of energy cost recovery by jurisdiction.

Coal

All of the coal-fueled generating facilities operated by MidAmerican Energy are fueled by low-sulfur, western coal from the Powder River Basin in northeast Wyoming. MidAmerican Energy's coal supply portfolio includes multiple suppliers and mines under short-term and multi-year agreements of varying terms and quantities through 2023. MidAmerican Energy believes supplies from these sources are presently adequate and available to meet MidAmerican Energy's needs. MidAmerican Energy's coal supply portfolio has substantially all of its expected 2020 requirements under fixed-price contracts. MidAmerican Energy regularly monitors the western coal market for opportunities to enhance its coal supply portfolio.

14



MidAmerican Energy has a multi-year long-haul coal transportation agreement with BNSF Railway Company ("BNSF"), an affiliate company, for the delivery of coal to all of the MidAmerican Energy-operated coal-fueled generating facilities other than the George Neal Energy Center. Under this agreement, BNSF delivers coal directly to MidAmerican Energy's Walter Scott, Jr. Energy Center and to an interchange point with Canadian Pacific Railway Company for short-haul delivery to the Louisa Energy Center. MidAmerican Energy has a multi-year long-haul coal transportation agreement with Union Pacific Railroad Company for the delivery of coal to the George Neal Energy Center.

Nuclear

MidAmerican Energy is a 25% joint owner of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station"), a nuclear power plant, which is currently licensed by the NRC for operation until December 14, 2032. Exelon Generation Company, LLC ("Exelon Generation"), a subsidiary of Exelon Corporation, is the 75% joint owner and the operator of Quad Cities Station. Approximately one-third of the nuclear fuel assemblies in each reactor core at Quad Cities Station is replaced every 24 months. MidAmerican Energy has been advised by Exelon Generation that the following requirements for Quad Cities Station can be met under existing supplies or commitments: uranium requirements through 2021 and partial requirements through 2025; uranium conversion requirements through 2021 and partial requirements through 2025; enrichment requirements through 2021 and partial requirements through 2025; and fuel fabrication requirements through 2022. MidAmerican Energy has been advised by Exelon Generation that it does not anticipate it will have difficulty in contracting for uranium, uranium conversion, enrichment or fabrication of nuclear fuel needed to operate Quad Cities Station during these time periods. In reaction to concerns about the profitability of Quad Cities Station and Exelon Generation's ability to continue its operation, in December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the zero emission credits will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station.

Natural Gas

MidAmerican Energy uses natural gas and oil as fuel for intermediate and peak demand electric generation, igniter fuel, transmission support and standby purposes. These sources are presently in adequate supply and available to meet MidAmerican Energy's needs.

Wind and Other

MidAmerican Energy owns more wind-powered generating capacity than any other United States rate-regulated electric utility and believes wind-powered generation offers a viable, economical and environmentally prudent means of supplying electricity and complying with laws and regulations. Pursuant to ratemaking principles approved by the IUB, all of MidAmerican Energy's wind-powered generating facilities in-service at December 31, 2019, are authorized to earn over their regulatory lives a fixed rate of return on equity ranging from 11.0% to 12.2% on the depreciated cost of their original construction, which excludes the cost of later replacements, in any future Iowa rate proceeding. MidAmerican Energy's wind-powered generating facilities, including those facilities where a significant portion of the equipment was replaced, commonly referred to as repowered facilities, are eligible for federal renewable electricity PTCs for 10 years from the date the facilities are placed in-service. PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold. PTCs for MidAmerican Energy's wind-powered generating facilities currently in-service began expiring in 2014, with final expiration in 2029. MidAmerican Energy has repowered, or plans to repower, 2,234 MWs of the 2,284 MWs of wind-powered generating facilities for which PTCs have expired or will expire by the end of 2022. MidAmerican Energy anticipates energy generation from the repowered facilities will increase between 19% and 30% depending upon the technology being repowered.

Of the 6,260 MWs (nominal ratings) of wind-powered generating facilities in-service as of December 31, 2019, 6,155 MWs were generating PTCs, including 1,221 MWs of repowered facilities. Of those facilities currently not generating PTCs, 55 MWs are scheduled to be repowered by the end of 2020. PTCs earned by MidAmerican Energy's wind-powered generating facilities placed in-service prior to 2013, except for repowered facilities, are included in MidAmerican Energy's Iowa energy adjustment clause, through which MidAmerican Energy is allowed to recover fluctuations in its electric retail energy costs. Facilities earning PTCs that currently benefit customers through the Iowa energy adjustment clause totaled 1,000 MWs (nominal ratings) as of December 31, 2019, with the eligibility of those facilities to earn PTCs expiring by the end of 2022. MidAmerican Energy earned PTCs totaling $378 million and $308 million in 2019 and 2018, respectively, of which 19% and 33%, respectively, were included in the Iowa energy adjustment clause.


15


Regional Transmission Organizations

MidAmerican Energy sells and purchases electricity and ancillary services related to its generation and load in wholesale markets pursuant to the tariffs in those markets. MidAmerican Energy participates predominantly in the MISO energy and ancillary service markets, which provide MidAmerican Energy with wholesale opportunities over a large market area. MidAmerican Energy can enter into wholesale bilateral transactions in addition to market activity related to its assets. MidAmerican Energy is authorized to participate in the Southwest Power Pool, Inc. and PJM Interconnection, L.L.C. ("PJM") markets and can contract with several other major transmission-owning utilities in the region. MidAmerican Energy can utilize both financial swaps and physical fixed-price electricity sales and purchases contracts to reduce its exposure to electricity price volatility.

MidAmerican Energy's decisions regarding additions to or reductions of its generation portfolio may be impacted by the MISO's minimum reserve margin requirement. The MISO requires each member to maintain a minimum reserve margin of its accredited generating capacity over its peak demand obligation based on the member's forecast filed with the MISO each year. The MISO's reserve requirement was 7.9% for the summer of 2019 and will increase to 8.9% for the summer of 2020. MidAmerican Energy's owned and contracted capacity accredited for the 2019-2020 MISO capacity auction was 5,471 MWs compared to a peak demand obligation of 4,730 MWs, or a reserve margin of 15.7%. Accredited capacity represents the amount of generation available to meet the requirements of MidAmerican Energy's retail customers and consists of MidAmerican Energy-owned generation, interruptible retail customer load, certain customer private generation that MidAmerican Energy is contractually allowed to dispatch and the net amount of capacity purchases and sales. Accredited capacity may vary from the nominal, or design, capacity ratings, particularly for wind turbines whose output is dependent upon wind levels at any given time. Additionally, the actual amount of generating capacity available at any time may be less than the accredited capacity due to regulatory restrictions, transmission constraints, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling, modifications or other reasons.

Transmission and Distribution

MidAmerican Energy's transmission and distribution systems included 4,100 miles of transmission lines in four states, 38,700 miles of distribution lines and 380 substations as of December 31, 2019. Electricity from MidAmerican Energy's generating facilities and purchased electricity is delivered to wholesale markets and its retail customers via the transmission facilities of MidAmerican Energy and others. MidAmerican Energy participates in the MISO capacity, energy and ancillary services markets as a transmission-owning member and, accordingly, operates its transmission assets at the direction of the MISO. The MISO manages its energy and ancillary service markets using reliability-constrained economic dispatch of the region's generation. For both the day-ahead and real-time (every five minutes) markets, the MISO analyzes generation commitments to provide market liquidity and transparent pricing while maintaining transmission system reliability by minimizing congestion and maximizing efficient energy transmission. Additionally, through its FERC-approved OATT, the MISO performs the role of transmission service provider throughout the MISO footprint and administers the long-term planning function. MISO and related costs of the participants are shared among the participants through a number of mechanisms in accordance with the MISO tariff.

Regulated Natural Gas Operations

MidAmerican Energy is engaged in the distribution of natural gas to customers in its service territory and the related procurement, transportation and storage of natural gas for the benefit of those customers. MidAmerican Energy purchases natural gas from various suppliers and contracts with interstate natural gas pipelines for transportation of the gas to MidAmerican Energy's service territory and for storage and balancing services. MidAmerican Energy sells natural gas and delivery services to end-use customers on its distribution system; sells natural gas to other utilities, municipalities and energy marketing companies; and transports natural gas through its distribution system for end-use customers who have independently secured their supply of natural gas. During 2019, 56% of the total natural gas delivered through MidAmerican Energy's distribution system was associated with transportation service.

Natural gas property consists primarily of natural gas mains and service lines, meters, and related distribution equipment, including feeder lines to communities served from natural gas pipelines owned by others. The natural gas distribution facilities of MidAmerican Energy included 24,000 miles of natural gas main and service lines as of December 31, 2019.


16


Customer Usage and Seasonality

The percentages of natural gas sold to MidAmerican Energy's retail customers by jurisdiction for the years ended December 31 were as follows:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Iowa
76
%
 
76
%
 
76
%
South Dakota
13

 
13

 
13

Illinois
10

 
10

 
10

Nebraska
1

 
1

 
1

 
100
%
 
100
%
 
100
%

The percentages of natural gas sold to MidAmerican Energy's retail and wholesale customers by class of customer, total Dths of natural gas sold, total Dths of transportation service and the average number of retail customers for the years ended December 31 were as follows:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Residential
45
%
 
43
%
 
41
%
Commercial(1)
22

 
21

 
20

Industrial(1)
4

 
5

 
4

Total retail
71

 
69

 
65

Wholesale(2)
29

 
31

 
35

 
100
%
 
100
%
 
100
%
 
 
 
 
 
 
Total Dths of natural gas sold (in thousands)
125,655

 
126,272

 
114,298

Total Dths of transportation service (in thousands)
112,143

 
102,198

 
92,136

Total average number of retail customers (in thousands)
766

 
759

 
751


(1)
Commercial and industrial customers are classified primarily based on the nature of their business and natural gas usage. Commercial customers are non-residential customers that use natural gas principally for heating. Industrial customers are non-residential customers that use natural gas principally for their manufacturing processes.
(2)
Wholesale sales are generally made to other utilities, municipalities and energy marketing companies for eventual resale to end-use customers.

There are seasonal variations in MidAmerican Energy's regulated natural gas business that are principally due to the use of natural gas for heating. Typically, 50-60% of MidAmerican Energy's regulated natural gas revenue is reported in the months of January, February, March and December.

On January 29, 2019, MidAmerican Energy recorded its all-time highest peak-day delivery through its distribution system of 1,314,526 Dths. This peak-day delivery consisted of 68% traditional retail sales service and 32% transportation service. MidAmerican Energy's 2019/2020 winter heating season peak-day delivery as of February 3, 2020, was 1,197,419 Dths, reached on January 19, 2020. This preliminary peak-day delivery consisted of 61% traditional retail sales service and 39% transportation service.

Fuel Supply and Capacity

MidAmerican Energy uses several strategies designed to maintain a reliable natural gas supply and reduce the impact of volatility in natural gas prices on its regulated retail natural gas customers. These strategies include the purchase of a geographically diverse supply portfolio from producers and third-party energy marketing companies, the use of interstate pipeline storage services and MidAmerican Energy's LNG peaking facilities, and the use of financial derivatives to fix the price on a portion of the anticipated natural gas requirements of MidAmerican Energy's customers. Refer to "General Regulation" in Item 1 of this Form 10-K for a discussion of the purchased gas adjustment clauses ("PGA").


17


MidAmerican Energy contracts for firm natural gas pipeline capacity to transport natural gas from key production areas and liquid market centers to its service territory through direct interconnects to the pipeline systems of several interstate natural gas pipeline systems, including Northern Natural Gas, an affiliate company. MidAmerican Energy has multiple pipeline interconnections into several larger markets within its distribution system. Multiple pipeline interconnections create competition among pipeline suppliers for transportation capacity to serve those markets, thus reducing costs. In addition, multiple pipeline interconnections increase delivery reliability and give MidAmerican Energy the ability to optimize delivery of the lowest cost supply from the various production areas and liquid market centers into these markets. Benefits to MidAmerican Energy's distribution system customers are shared among all jurisdictions through a consolidated PGA.

At times, the natural gas pipeline capacity available through MidAmerican Energy's firm capacity portfolio may exceed the requirements of retail customers on MidAmerican Energy's distribution system. Firm capacity in excess of MidAmerican Energy's system needs can be released to other companies to achieve optimum use of the available capacity. Past IUB and South Dakota Public Utilities Commission ("SDPUC") rulings have allowed MidAmerican Energy to retain 30% of the respective jurisdictional revenue on the resold capacity, with the remaining 70% being returned to customers through the PGAs.

MidAmerican Energy utilizes interstate pipeline natural gas storage services to meet retail customer requirements, manage fluctuations in demand due to changes in weather and other usage factors and manage variation in seasonal natural gas pricing. MidAmerican Energy typically withdraws natural gas from storage during the heating season when customer demand is historically at its peak and injects natural gas into storage during off-peak months when customer demand is historically lower. MidAmerican Energy also utilizes its three LNG facilities to meet peak day demands during the winter heating season. Interstate pipeline storage services and MidAmerican Energy's LNG facilities reduce dependence on natural gas purchases during the volatile winter heating season and can deliver a significant portion of MidAmerican Energy's anticipated retail sales requirements on a peak winter day. For MidAmerican Energy's 2019/2020 winter heating season preliminary peak-day of January 19, 2020, supply sources used to meet deliveries to traditional retail sales service customers included 66% from purchases delivered on interstate pipelines, 32% from interstate pipeline storage services and 2% from MidAmerican Energy's LNG facilities.

MidAmerican Energy attempts to optimize the value of its regulated transportation capacity, natural gas supply and leased storage arrangements by engaging in wholesale transactions. IUB and SDPUC rulings have allowed MidAmerican Energy to retain 50% of the respective jurisdictional margins earned on certain wholesale sales of natural gas, with the remaining 50% being returned to customers through the PGAs.

MidAmerican Energy is not aware of any factors that would cause material difficulties in meeting its anticipated retail customer demand for the foreseeable future.

Energy Efficiency Programs

MidAmerican Energy has provided a comprehensive set of demand- and energy-reduction programs to its Iowa electric and natural gas customers since 1990. The programs, collectively referred to as energy efficiency programs, are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. Current programs offer services to customers such as energy engineering audits and information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, MidAmerican Energy offers rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors, process equipment and systems, as well as incentives for efficient construction. Incentives are also paid to residential customers who participate in the air conditioner load control program and nonresidential customers who participate in the nonresidential load management program. In Iowa, legislation passed in 2018 provides that projected cumulative average annual costs for a natural gas energy efficiency plan cannot exceed 1.5% of expected Iowa natural gas retail rate revenue and, for an electric demand response plan and separately for an electric energy efficiency plan other than demand response, cannot exceed 2.0% of expected annual Iowa electric retail rate revenue. Although subject to prudence reviews, state regulations allow for contemporaneous recovery of costs incurred for energy efficiency programs through state-specific energy efficiency service charges paid by all retail electric and natural gas customers. In 2019, $78 million was expensed for MidAmerican Energy's energy efficiency programs, which resulted in estimated first-year energy savings of 185,000 MWhs of electricity and 424,000 Dths of natural gas and an estimated peak load reduction of 316 MWs of electricity and 5,585 Dths per day of natural gas.

Employees

As of December 31, 2019, MidAmerican Funding and its subsidiaries, which includes MidAmerican Energy, had approximately 3,500 employees, of which approximately 1,500 were covered by union contracts. MidAmerican Energy has three separate contracts with locals of the International Brotherhood of Electrical Workers and the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union.

18



NV ENERGY (NEVADA POWER AND SIERRA PACIFIC)

General

NV Energy, an indirect wholly owned subsidiary of BHE, is an energy holding company headquartered in Nevada whose principal subsidiaries are Nevada Power and Sierra Pacific. Nevada Power and Sierra Pacific are indirect consolidated subsidiaries of Berkshire Hathaway. Nevada Power is a United States regulated electric utility company serving 1.0 million retail customers primarily in the Las Vegas, North Las Vegas, Henderson and adjoining areas. Sierra Pacific is a United States regulated electric and natural gas utility company serving 0.4 million retail electric customers and 0.2 million retail and transportation natural gas customers in northern Nevada. The Nevada Utilities are principally engaged in the business of generating, transmitting, distributing and selling electricity and, in the case of Sierra Pacific, in distributing, selling and transporting natural gas. Nevada Power and Sierra Pacific have electric service territories covering approximately 4,500 square miles and 41,200 square miles, respectively. Sierra Pacific has a natural gas service territory covering approximately 900 square miles in Reno and Sparks. Principal industries served by the Nevada Utilities include gaming, recreation, warehousing, manufacturing and governmental services. Sierra Pacific also serves the mining industry. The Nevada Utilities buy and sell electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants to balance and optimize economic benefits of electricity generation, retail customer loads and wholesale transactions.

The Nevada Utilities' electric and natural gas operations are conducted under numerous nonexclusive franchise agreements, revocable permits and licenses obtained from federal, state and local authorities. The expiration of these franchise agreements ranges from 2020 through 2032 for Nevada Power and 2020 through 2049 for Sierra Pacific. The Nevada Utilities operate under certificates of public convenience and necessity as regulated by the PUCN, and as such the Nevada Utilities have an obligation to provide electricity service to those customers within their service territory. In return, the PUCN has established rates on a cost-of-service basis, which are designed to allow the Nevada Utilities an opportunity to recover all prudently incurred costs of providing services and an opportunity to earn a reasonable return on their investment.

NV Energy's monthly net income is affected by the seasonal impact of weather on electricity and natural gas sales and seasonal retail electricity prices from the Nevada Utilities'. For 2019, 74% of NV Energy annual net income was recorded in the months of June through September.

Regulated electric utility operations is Nevada Power's only segment while regulated electric utility operations and regulated natural gas operations are the two segments of Sierra Pacific.

The percentages of Sierra Pacific's operating revenue and operating income derived from the following business activities for the years ended December 31 were as follows:
 
2019
 
2018
 
2017
Operating revenue:
 
 
 
 
 
Electric
87
%
 
88
%
 
88
%
Gas
13

 
12

 
12

 
100
%
 
100
%
 
100
%
 
 
 
 
 
 
Operating income:
 
 
 
 
 
Electric
88
%
 
89
%
 
88
%
Gas
12

 
11

 
12

 
100
%
 
100
%
 
100
%

Nevada Power was incorporated under the laws of the state of Nevada in 1929 and its principal executive offices are located at 6226 West Sahara Avenue, Las Vegas, Nevada 89146, its telephone number is (702) 402-5000 and its internet address is www.nvenergy.com.

Sierra Pacific was incorporated under the laws of the state of Nevada in 1912 and its principal executive offices are located at 6100 Neil Road, Reno, Nevada 89511, its telephone number is (775) 834-4011 and its internet address is www.nvenergy.com.


19


Regulated Electric Operations

Customers

The Nevada Utilities' sell electricity to retail customers in a single state jurisdiction. Electricity sold to the Nevada Utilities' retail and wholesale customers by class of customer and the average number of retail customers for the years ended December 31 were as follows:
 
2019
 
2018
 
2017
Nevada Power:
 
 
 
 
 
 
 
 
 
 
 
GWhs sold:
 
 
 
 
 
 
 
 
 
 
 
Residential
9,311

 
41
%
 
9,970

 
43
%
 
9,501

 
42
%
Commercial
4,657

 
20

 
4,778

 
20

 
4,656

 
20

Industrial
5,344

 
24

 
5,534

 
24

 
6,201

 
28

Other
193

 
1

 
214

 
1

 
212

 
1

Total fully bundled
19,505

 
86

 
20,496

 
88

 
20,570

 
91

Distribution only service
2,613

 
12

 
2,521

 
11

 
1,830

 
8

Total retail
22,118

 
98

 
23,017

 
99

 
22,400

 
99

Wholesale
527

 
2

 
274

 
1

 
314

 
1

Total GWhs sold
22,645

 
100
%
 
23,291

 
100
%
 
22,714

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands):
 
 
 
 
 
 
 
 
 
 
 
Residential
840

 
88
%
 
825

 
88
%
 
810

 
88
%
Commercial
109

 
12

 
108

 
12

 
106

 
12

Industrial
2

 

 
2

 

 
2

 

Total
951

 
100
%
 
935

 
100
%
 
918

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Sierra Pacific:
 
 
 
 
 
 
 
 
 
 
 
GWhs sold:
 
 
 
 
 
 
 
 
 
 
 
Residential
2,491

 
22
%
 
2,483

 
23
%
 
2,492

 
24
%
Commercial
2,973

 
26

 
2,998

 
27

 
2,954

 
28

Industrial
3,716

 
32

 
3,387

 
31

 
3,176

 
30

Other
16

 

 
16

 

 
16

 

Total fully bundled
9,196

 
80

 
8,884

 
81

 
8,638

 
82

Distribution only service
1,629

 
14

 
1,516

 
14

 
1,394

 
13

Total retail
10,825

 
94

 
10,400

 
95

 
10,032

 
95

Wholesale
662

 
6

 
558

 
5

 
561

 
5

Total GWhs sold
11,487

 
100
%
 
10,958

 
100
%
 
10,593

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands):
 
 
 
 
 
 
 
 
 
 
 
Residential
304

 
86
%
 
300

 
86
%
 
295

 
86
%
Commercial
48

 
14

 
47

 
14

 
47

 
14

Total
352

 
100
%
 
347

 
100
%
 
342

 
100
%

Variations in weather, economic conditions, particularly for gaming, mining and wholesale customers and various conservation, energy efficiency and private generation measures and programs can impact customer usage. Wholesale sales are impacted by market prices for energy relative to the incremental cost to generate power.

There are seasonal variations in the Nevada Utilities' electric business that are principally related to weather and the related use of electricity for air conditioning. Typically, 48-50% of Nevada Power's and 36-38% of Sierra Pacific's regulated electric revenue is reported in the months of June through September.


20


The annual hourly peak customer demand on the Nevada Utilities' electric systems occurs as a result of air conditioning use during the cooling season. Peak demand represents the highest demand on a given day and at a given hour. On July 29, 2019, customer usage of electricity caused an hourly peak demand of 5,611 MWs on Nevada Power's electric system, which is 513 MWs less than the record hourly peak demand of 6,124 MWs set July 28, 2016. On August 28, 2019, customer usage of electricity caused an hourly peak demand of 1,808 MWs on Sierra Pacific's electric system, which is 52 MWs less than the record hourly peak demand of 1,860 MWs set July 19, 2018.

Generating Facilities and Fuel Supply

The Nevada Utilities have ownership interest in a diverse portfolio of generating facilities. The following table presents certain information regarding the Nevada Utilities' owned generating facilities as of December 31, 2019:
 
 
 
 
 
 
 
 
Facility
 
Net Owned
 
 
 
 
 
 
 
 
Net Capacity
 
Capacity
Generating Facility
 
Location
 
Energy Source
 
Installed
 
(MWs)(1)
 
(MWs)(1)
Nevada Power:
 
 
 
 
 
 
 
 
 
 
NATURAL GAS:
 
 
 
 
 
 
 
 
 
 
Clark
 
Las Vegas, NV
 
Natural gas
 
1973-2008
 
1,102

 
1,102

Lenzie
 
Las Vegas, NV
 
Natural gas
 
2006
 
1,102

 
1,102

Harry Allen
 
Las Vegas, NV
 
Natural gas
 
1995-2011
 
628

 
628

Higgins
 
Primm, NV
 
Natural gas
 
2004
 
530

 
530

Silverhawk
 
Las Vegas, NV
 
Natural gas
 
2004
 
520

 
520

Las Vegas
 
Las Vegas, NV
 
Natural gas
 
1994-2003
 
272

 
272

Sun Peak
 
Las Vegas, NV
Natural gas/oil
 
1991
 
210

 
210

 
 
 
 
 
 
 
 
4,364

 
4,364


 
 
 
 
 
 
 
 
 
 
RENEWABLES:
 
 
 
 
 
 
 
 
 
 
Nellis
 
Las Vegas, NV
 
Solar
 
2015
 
15

 
15

Goodsprings
 
Goodsprings, NV
 
Waste heat
 
2010
 
5

 
5

 
 
 
 
 
 
 
 
20

 
20

 
 
 
 
 
 
 
 
 
 
 
Total Nevada Power
 
 
 
 
 
 
 
4,384

 
4,384

 
 
 
 
 
 
 
 
 
 
 
Sierra Pacific:
 
 
 
 
 
 
 
 
 
 
NATURAL GAS:
 
 
 
 
 
 
 
 
 
 
Tracy
 
Sparks, NV
 
Natural gas
 
1974-2008
 
753

 
753

Ft. Churchill
 
Yerington, NV
Natural gas
 
1968-1971
 
226

 
226

Clark Mountain
 
Sparks, NV
 
Natural gas
 
1994
 
132

 
132

 
 
 
 
 
 
 
 
1,111

 
1,111

COAL:
 
 
 
 
 
 
 
 
 
 
Valmy Unit Nos. 1 and 2
 
Valmy, NV
 
Coal
 
1981-1985
 
522

 
261

 
 
 
 
 
 
 
 
 
 
 
Total Sierra Pacific
 
 
 
 
 
 
 
1,633

 
1,372

 
 
 
 
 
 
 
 
 
 
 
Total NV Energy
 
 
 
 
 
 
 
6,017

 
5,756


(1)
Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates Nevada Power or Sierra Pacific's ownership of Facility Net Capacity.



21


The following table shows the percentages of the Nevada Utilities' total energy supplied by energy source for the years ended December 31:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Nevada Power:
 
 
 
 
 
Natural gas
65
%
 
64
%
 
61
%
Coal
5

 
6

 
7

Total energy generated
70

 
70

 
68

Energy purchased - long-term contracts (non-renewable)
11

 
10

 
15

Energy purchased - long-term contracts (renewable)(1)
17

 
16

 
15

Energy purchased - short-term contracts and other
2

 
4

 
2

 
100
%
 
100
%
 
100
%
 
 
 
 
 
 
Sierra Pacific:
 
 
 
 
 
Natural gas
46
%
 
48
%
 
44
%
Coal
11

 
8

 
5

Total energy generated
57

 
56

 
49

Energy purchased - long-term contracts (non-renewable)
27

 
29

 
38

Energy purchased - long-term contracts (renewable)(1)
13

 
12

 
11

Energy purchased - short-term contracts and other
3

 
3

 
2

 
100
%
 
100
%
 
100
%

(1)
All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements, (b) sold to third parties in the form of RECs or other environmental commodities, or (c) excluded from energy purchased.

The Nevada Utilities are required to have resources available to continuously meet their customer needs and reliably operate their electric systems. The percentage of the Nevada Utilities' energy supplied by energy source varies from year-to-year and is subject to numerous operational and economic factors such as planned and unplanned outages; fuel commodity prices; fuel transportation costs; weather; environmental considerations; transmission constraints; and wholesale market prices of electricity. The Nevada Utilities evaluate these factors continuously in order to facilitate economical dispatch of their generating facilities. When factors for one energy source are less favorable, the Nevada Utilities place more reliance on other energy sources. As long as the Nevada Utilities' purchases are deemed prudent by the PUCN, through their annual prudency review, the Nevada Utilities are permitted to recover the cost of fuel and purchased power. The Nevada Utilities also have the ability to reset quarterly the BTERs, with PUCN approval, based on the last twelve months fuel costs and purchased power and to reset quarterly DEAA.

The Nevada Utilities have adopted an approach to managing the energy supply function that has three primary elements. The first element is a set of management guidelines for procuring and optimizing the supply portfolio that is consistent with the requirements of a load serving entity with a full requirements obligation, and with the growth of private generation serving a small but growing group of customers with partial requirements. The second element is an energy risk management and control approach that ensures clear separation of roles between the day-to-day management of risks and compliance monitoring and control and ensures clear distinction between policy setting (or planning) and execution. Lastly, the Nevada Utilities pursue a process of ongoing regulatory involvement and acknowledgment of the resource portfolio management plans.

The Nevada Utilities have entered into multiple long-term power purchase contracts (three or more years) with suppliers that generate electricity utilizing renewable resources, natural gas and coal. Nevada Power has entered into contracts with a total capacity of 3,284 MWs with contract termination dates ranging from 2022 to 2067. Included in these contracts are 3,024 MWs of capacity of renewable energy, of which 1,815 MWs of capacity are under development or construction and not currently available. Sierra Pacific has entered into contracts with a total capacity of 1,184 MWs with contract termination dates ranging from 2022 to 2046. Included in these contracts are 998 MWs of capacity of renewable energy, of which 476 MWs of capacity are under development or construction and not currently available.


22


The Nevada Utilities manage certain risks relating to their supply of electricity and fuel requirements by entering into various contracts, which may be accounted for as derivatives, including forwards, futures, options, swaps and other agreements. Refer to NV Energy's "General Regulation" section in Item 1 of this Form 10-K for a discussion of energy cost recovery by jurisdiction and Nevada Power's Item 7A and Sierra Pacific's Item 7A in this Form 10-K for a discussion of commodity price risk and derivative contracts.

Natural Gas

The Nevada Utilities rely on first-of-the-month indexed physical gas purchases for the majority of natural gas needed to operate their generating facilities. To secure natural gas supplies for the generating facilities, the Nevada Utilities execute purchases pursuant to a PUCN approved four season laddering strategy. In 2019, natural gas supply net purchases averaged 310,683 and 167,283 Dths per day with the winter period contracts averaging 250,432 and 193,767 Dths per day and the summer period contracts averaging 353,197 and 148,595 Dths per day for Nevada Power and Sierra Pacific, respectively. The Nevada Utilities believe supplies from these sources are presently adequate and available to meet its needs.

The Nevada Utilities contract for firm natural gas pipeline capacity to transport natural gas from production areas to their service territory through direct interconnects to the pipeline systems of several interstate natural gas pipeline systems, including Nevada Power who contracts with Kern River, an affiliated company. Sierra Pacific utilizes natural gas storage contracted from interstate pipelines to meet retail customer requirements and to manage the daily changes in demand due to changes in weather and other usage factors. The stored natural gas is typically replaced during off-peak months when the demand for natural gas is historically lower than during the heating season.

Coal

Sierra Pacific relies on spot market solicitations for coal supplies and will regularly monitor the western coal market for opportunities to meet these needs. Sierra Pacific has a transportation services contract with Union Pacific Railroad Company to ship coal from various origins in central Utah, western Colorado and Wyoming that expires December 31, 2025. Sierra Pacific has no commitments to purchase coal for 2020 or beyond. The Navajo Generating Station was shut down in November 2019 and Nevada Power has no coal requirements going forward.

Energy Imbalance Market

The Nevada Utilities participate in the EIM operated by the California ISO, which reduces costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, more effectively integrates renewables and enhances reliability through improved situational awareness and responsiveness. The EIM expands the real-time component of the California ISO's market technology to optimize and balance electricity supply and demand every five minutes across the EIM footprint. The EIM is voluntary and available to all balancing authorities in the western United States. EIM market participants submit bids to the California ISO market operator before each hour for each generating resource they choose to be dispatched by the market. Each bid is comprised of a dispatchable operating range, ramp rate and prices across the operating range. The California ISO market operator uses sophisticated technology to select the least-cost resources to meet demand and send simultaneous dispatch signals to every participating generator across the EIM footprint every five minutes. In addition to generation resource bids, the California ISO market operator also receives continuous real-time updates of the transmission grid network, meteorological and load forecast information that it uses to optimize dispatch instructions. Outside the EIM footprint, utilities in the western United States do not utilize comparable technology and are largely limited to transactions within the borders of their balancing authority area to balance supply and demand intra-hour using a combination of manual and automated dispatch. The EIM delivers customer benefits by leveraging automation and resource diversity to result in more efficient dispatch, more effective integration of renewables and improved situational awareness. Benefits are expected to increase further with renewable resource expansion and as more entities join the EIM bringing incremental diversity.

The Nevada Utilities will continue to monitor regional market expansion efforts, including creation of a regional Independent System Operator ("ISO"). California Senate Bill No. 350, which was passed in October 2015, authorized the California legislature to consider making changes to current laws that would create an independent governance structure for a regional ISO during the 2017 legislative session. The California legislature did not pass any legislation related to a regional ISO during its 2019 legislative session, which adjourned September 13, 2019.

23



Transmission and Distribution

The Nevada Utilities' transmission system is part of the Western Interconnection, a regional grid in the United States. The Western Interconnection includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico. The Nevada Utilities' transmission system, together with contractual rights on other transmission systems, enables the Nevada Utilities to integrate and access generation resources to meet their customer load requirements. Nevada Power's transmission and distribution systems included approximately 2,200 miles of transmission lines, 26,400 miles of distribution lines and 210 substations as of December 31, 2019. Sierra Pacific's transmission and distribution systems included approximately 2,300 miles of transmission lines, 17,900 miles of distribution lines and 200 substations as of December 31, 2019.

ON Line is a 231-mile, 500-kV transmission line connecting Nevada Power's and Sierra Pacific's service territories. ON Line provides the ability to jointly dispatch energy throughout Nevada and provide access to renewable energy resources in parts of northern and eastern Nevada, which enhances the Nevada Utilities' ability to manage and optimize their generating facilities. ON Line provides between 600 and 900 MWs of transfer capability with interconnection between the Robinson Summit substation on the Sierra Pacific system and the Harry Allen substation on the Nevada Power system. ON Line was a joint project between the Nevada Utilities and Great Basin Transmission, LLC. The Nevada Utilities own a 25% interest in ON Line and have entered into a long-term transmission use agreement with Great Basin Transmission, LLC for its 75% interest in ON Line until 2054. The Nevada Utilities share of its 25% interest in ON Line and the long-term transmission use agreement is split 95% for Nevada Power and 5% for Sierra Pacific. In December 2019, the PUCN approved an order to update the split starting January 1, 2020 to 75% for Nevada Power and 25% for Sierra Pacific to more accurately reflect the benefits obtained from the transmission line.

Future Generation, Conservation and Energy Efficiency

Energy Supply Planning

Within the energy supply planning process, there are four key components covering different time frames:

IRPs are filed by the Nevada Utilities for approval by the PUCN every three years and the Nevada Utilities may, as necessary, file amendments to their IRPs. IRPs are prepared in compliance with Nevada laws and regulations and cover a 20-year period. Nevada law governing the IRP process was modified in 2017 and now requires joint filings by Nevada Power and Sierra Pacific. IRPs develop a comprehensive, integrated plan that considers customer energy requirements and propose the resources to meet those requirements in a manner that is consistent with prevailing market fundamentals. The ultimate goal of the IRPs is to balance the objectives of minimizing costs and reducing volatility while reliably meeting the electric needs of the Nevada Utilities' customers. Costs incurred to complete projects approved through the IRP process still remain subject to review for reasonableness by the PUCN.
Energy Supply Plans ("ESP") are filed with the PUCN for approval and operate in conjunction with the PUCN-approved 20-year IRP. The ESP has a one- to three-year planning horizon and is an intermediate-term resource procurement and risk management plan that establishes the supply portfolio strategies within which intermediate-term resource requirements will be met with PUCN approval required for executing contracts of longer than three years.
Distributed Resource Plans ("DRP") are filed with the PUCN for approval and operate in conjunction with the PUCN-approved 20-year IRP. The DRP establishes a formal process to aid in the cost-effective integration of distributed resources into the Nevada Utilities' distribution and transmission process and ultimately the NV Energy utilities' electricity grid.
Action plans are filed with the PUCN for approval and operate in conjunction with the PUCN-approved 20-year IRP and PUCN-approved ESP. The action plan establishes tactical execution activities with a one-month to twelve-month focus.

In April 2019, in compliance with Senate Bill No. 146, the Nevada Utilities filed their first DRP which was the first amendment to the 2019-2038 triennial IRP. In May 2019, the Nevada Utilities filed their second amendment to the IRP requesting approval for a change to the Demand-Side Action Plan to achieve a 1.25% annual energy savings target, additions to the generation portion of the Supply-Side Action Plan including a new agreement with Idaho Power Company for the orderly retirement of the North Valmy Station and updates to the Transmission Action Plan including several new transmission projects needed to serve growing distribution and transmission load. In June 2019, the Nevada Utilities filed their third amendment to the IRP requesting approval to proceed with system investments primarily related to transmission interconnections for renewable energy projects and approval for three power purchase agreements totaling 1,190-MWs of solar photovoltaic generation. The PUCN issued orders in August 2019 and December 2019 approving the significant elements of all three amendments.


24


There is the potential for continued price volatility in the Nevada Utilities' service territories, particularly during peak periods. Dependence on generation from the wholesale market can lead to power price volatilities depending on available power supply and prevailing natural gas prices. The Nevada Utilities face load obligation uncertainty due to the potential for customer switching. Some counterparties in these areas have significant credit difficulties, representing credit risk to the Nevada Utilities. Finally, the Nevada Utilities' own credit situation can have an impact on its ability to enter into transactions.

Emissions Reduction and Capacity Replacement Plan

In compliance with Senate Bill No. 123, Nevada Power retired 255 MWs of coal-fueled generation in 2019 in addition to the 557 MWs of coal-fueled generation retired in 2017. Consistent with the Emissions Reduction and Capacity Replacement Plan ("ERCR Plan"), between 2014 and 2016, Nevada Power acquired 536 MWs of natural gas generating resources, executed long-term power purchase agreements for 200 MWs of nameplate renewable energy capacity and constructed a 15-MW solar photovoltaic facility. Nevada Power has the option to acquire 35 MWs of nameplate renewable energy capacity in the future under the ERCR Plan, subject to PUCN approval.

Energy Efficiency Programs

The Nevada Utilities have provided a comprehensive set of energy efficiency, demand response and conservation programs to their Nevada electric customers. The programs are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. Current programs offer services to customers such as energy audits and customer education and awareness efforts that provide information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, the Nevada Utilities have offered rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors, process equipment and systems, as well as incentives for efficient construction. Incentives are also paid to residential customers who participate in the air conditioner load control program and nonresidential customers who participate in the nonresidential load management program. Energy efficiency program costs are recovered through annual rates set by the PUCN, and adjusted based on the Nevada Utilities' annual filing to recover current program costs and any over or under collections from the prior filing, subject to prudence review. During 2019, Nevada Power spent $33 million on energy efficiency programs, resulting in an estimated 231,756 MWhs of electric energy savings and an estimated 195 MWs of electric peak load management. During 2019, Sierra Pacific spent $11 million on energy efficiency programs, resulting in an estimated 100,339 MWhs of electric energy savings and an estimated 23 MWs of electric peak load management.

Regulated Natural Gas Operations

Sierra Pacific is engaged in the distribution of natural gas to customers in its service territory and the related procurement, transportation and storage of natural gas for the benefit of those customers. Sierra Pacific purchases natural gas from various suppliers and contracts with interstate natural gas pipelines for transportation of the natural gas from the production areas to Sierra Pacific's service territory and for storage services to manage fluctuations in system demand and seasonal pricing. Sierra Pacific sells natural gas and delivery services to end-use customers on its distribution system; sells natural gas to other utilities, municipalities and energy marketing companies; and transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. During 2019, 10% of the total natural gas delivered through Sierra Pacific's distribution system was for transportation service.

Natural gas property consists primarily of natural gas mains and service lines, meters, and related distribution equipment, including feeder lines to communities served from natural gas pipelines owned by others. The natural gas distribution facilities of Sierra Pacific included 3,460 miles of natural gas mains and service lines as of December 31, 2019.


25


Customer Usage and Seasonality

The percentages of natural gas sold to Sierra Pacific's retail and wholesale customers by class of customer, total Dths of natural gas sold, total Dths of transportation service and the average number of retail customers for the years ended December 31 were as follows:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Residential
57
%
 
55
%
 
53
%
Commercial(1)
29

 
28

 
27

Industrial(1)
10

 
11

 
9

Total retail
96

 
94

 
89

Wholesale(2)
4

 
6

 
11

 
100
%
 
100
%
 
100
%
 
 
 
 
 
 
Total Dths of natural gas sold (in thousands)
19,846

 
18,334

 
19,313

Total Dths of transportation service (in thousands)
2,217

 
2,250

 
1,977

Total average number of retail customers (in thousands)
170

 
167

 
165


(1)
Commercial and industrial customers are classified primarily based on the nature of their business and natural gas usage. Commercial customers are non-residential customers with monthly gas usage less than 12,000 therms during five consecutive winter months. Industrial customers are non-residential customers that use natural gas in excess of 12,000 therms during one or more winter months.

(2)
Wholesale sales are generally made to other utilities, municipalities and energy marketing companies for eventual resale to end-use customers.

There are seasonal variations in Sierra Pacific's regulated natural gas business that are principally due to the use of natural gas for heating. Typically, 47-56% of Sierra Pacific's regulated natural gas revenue is reported in the months of December through March.

On February 21, 2019, Sierra Pacific recorded its highest peak-day natural gas delivery of 140,287 Dths, which is 23,287 Dths less than the record peak-day delivery of 163,574 Dths set on December 9, 2013. This peak-day delivery consisted of 94% traditional retail sales service and 6% transportation service.

Fuel Supply and Capacity

The purchase of natural gas for Sierra Pacific's regulated natural gas operations is done in combination with the purchase of natural gas for Sierra Pacific's regulated electric operations. In response to energy supply challenges, Sierra Pacific has adopted an approach to managing the energy supply function that has three primary elements, as discussed earlier under Generating Facilities and Fuel Supply. Similar to Sierra Pacific's regulated electric operations, as long as Sierra Pacific's purchases of natural gas are deemed prudent by the PUCN, through its annual prudency review, Sierra Pacific is permitted to recover the cost of natural gas. Sierra Pacific also has the ability, with PUCN approval, to reset quarterly the BTERs, based on the last twelve months fuel costs, and to reset quarterly DEAA.

Employees

As of December 31, 2019, Nevada Power had approximately 1,400 employees, of which approximately 700 were covered by a union contract with the International Brotherhood of Electrical Workers.

As of December 31, 2019, Sierra Pacific had approximately 1,000 employees, of which approximately 500 were covered by a union contract with the International Brotherhood of Electrical Workers.


26


NORTHERN POWERGRID

Northern Powergrid, an indirect wholly owned subsidiary of BHE, is a holding company which owns two companies that distribute electricity in Great Britain, Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc. In addition to the Northern Powergrid Distribution Companies, Northern Powergrid also owns a meter asset rental business that leases meters to energy suppliers in the United Kingdom and Ireland, an engineering contracting business that provides electrical infrastructure contracting services primarily to third parties and a hydrocarbon exploration and development business that is focused on developing integrated upstream gas projects in Europe and Australia.

The Northern Powergrid Distribution Companies serve 3.9 million end-users and operate in the north-east of England from North Northumberland through Tyne and Wear, County Durham and Yorkshire to North Lincolnshire, an area covering 10,000 square miles. The principal function of the Northern Powergrid Distribution Companies is to build, maintain and operate the electricity distribution network through which the end-user receives a supply of electricity.

The Northern Powergrid Distribution Companies receive electricity from the national grid transmission system and from generators that are directly connected to the distribution network and distribute it to end-users' premises using their networks of transformers, switchgear and distribution lines and cables. Substantially all of the end-users in the Northern Powergrid Distribution Companies' distribution service areas are directly or indirectly connected to the Northern Powergrid Distribution Companies' networks and electricity can only be delivered to these end-users through their distribution systems, thus providing the Northern Powergrid Distribution Companies with distribution volumes that are relatively stable from year to year. The Northern Powergrid Distribution Companies charge fees for the use of their distribution systems to the suppliers of electricity.

The suppliers purchase electricity from generators, sell the electricity to end-user customers and use the Northern Powergrid Distribution Companies' distribution networks pursuant to an industry standard "Distribution Connection and Use of System Agreement." During 2019, RWE Npower PLC and certain of its affiliates and British Gas Trading Limited represented 17% and 12%, respectively, of the total combined distribution revenue of the Northern Powergrid Distribution Companies. Variations in demand from end-users can affect the revenues that are received by the Northern Powergrid Distribution Companies in any year, but such variations have no effect on the total revenue that the Northern Powergrid Distribution Companies are allowed to recover in a price control period. Under- or over-recoveries against price-controlled revenues are carried forward into prices for future years.

The Northern Powergrid Distribution Companies' combined service territory features a diverse economy with no dominant sector. The mix of rural, agricultural, urban and industrial areas covers a broad customer base ranging from domestic usage through farming and retail to major industry including automotives, chemicals, mining, steelmaking and offshore marine construction. The industry within the area is concentrated around the principal centers of Newcastle, Middlesbrough, Sheffield and Leeds.

The price controlled revenue of the Northern Powergrid Distribution Companies is set out in the special conditions of the licenses of those companies. The licenses are enforced by the regulator, GEMA, through the Ofgem and limit increases to allowed revenues (or may require decreases) based upon the rate of inflation, other specified factors and other regulatory action. Changes to the price controls can be made by the regulator, but if a licensee disagrees with a change to its license it can appeal the matter to the United Kingdom's Competition and Markets Authority ("CMA"). It has been the convention in Great Britain for regulators to conduct periodic regulatory reviews before making proposals for any changes to the price controls. The current electricity distribution price control became effective April 1, 2015 and will continue through March 31, 2023.


27


GWhs and percentages of electricity distributed to the Northern Powergrid Distribution Companies' end-users and the total number of end-users as of and for the years ended December 31 were as follows:
 
2019
 
2018
 
2017
Northern Powergrid (Northeast) Limited:
 
 
 
 
 
 
 
 
 
 
 
Residential
4,982

 
36
%
 
5,125

 
36
%
 
5,227

 
36
%
Commercial(1)
1,644

 
12

 
1,782

 
13

 
2,222

 
15

Industrial(1)
7,097

 
51

 
7,134

 
50

 
6,963

 
48

Other
156

 
1

 
198

 
1

 
214

 
1

 
13,879

 
100
%
 
14,239

 
100
%
 
14,626

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Northern Powergrid (Yorkshire) plc:
 
 
 
 
 
 
 
 
 
 
 
Residential
7,311

 
35
%
 
7,509

 
36
%
 
7,612

 
36
%
Commercial(1)
2,391

 
12

 
2,558

 
12

 
3,116

 
15

Industrial(1)
10,722

 
52

 
10,716

 
51

 
10,275

 
48

Other
236

 
1

 
268

 
1

 
290

 
1

 
20,660

 
100
%
 
21,051

 
100
%
 
21,293

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Total electricity distributed
34,539

 
 
 
35,290

 
 
 
35,919

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of end-users (in thousands):
 
 
 
 
 
 
 
 
 
 
 
Northern Powergrid (Northeast) Limited
1,612

 
 
 
1,603

 
 
 
1,602

 
 
Northern Powergrid (Yorkshire) plc
2,314

 
 
 
2,301

 
 
 
2,301

 
 
 
3,926

 
 
 
3,904

 
 
 
3,903

 
 

(1)
The increase in industrial and decrease in commercial is largely due to the Great Britain-wide customer reclassifications which are in progress (as a result of Ofgem approved industry changes), negatively impacting commercial volumes by 100 GWhs in 2018 compared to 2017.

As of December 31, 2019, the combined electricity distribution network of the Northern Powergrid Distribution Companies included approximately 17,400 miles of overhead lines, 42,300 miles of underground cables and 770 major substations.

BHE PIPELINE GROUP

Northern Natural Gas

Northern Natural Gas, an indirect wholly owned subsidiary of BHE, owns the largest interstate natural gas pipeline system in the United States, as measured by pipeline miles, which reaches from west Texas to Michigan's Upper Peninsula. Northern Natural Gas primarily transports and stores natural gas for utilities, municipalities, gas marketing companies and industrial and commercial users. Northern Natural Gas' pipeline system consists of two commercial segments. Its traditional end-use and distribution market area in the northern part of its system, referred to as the Market Area, includes points in Iowa, Nebraska, Minnesota, Wisconsin, South Dakota, Michigan and Illinois. Its natural gas supply and delivery service area in the southern part of its system, referred to as the Field Area, includes points in Kansas, Texas, Oklahoma and New Mexico. The Market Area and Field Area are separated at a Demarcation Point ("Demarc"). Northern Natural Gas' pipeline system consists of 14,600 miles of natural gas pipelines, including 6,100 miles of mainline transmission pipelines and 8,500 miles of branch and lateral pipelines, with a Market Area design capacity of 6.3 Bcf per day, a Field Area delivery capacity of 1.7 Bcf per day to the Market Area and 1.4 Bcf per day to the West Texas area and over 79 Bcf of firm service and operational storage cycle capacity in five storage facilities. Northern Natural Gas' pipeline system is configured with approximately 2,250 active receipt and delivery points which are integrated with the facilities of LDCs. Many of Northern Natural Gas' LDC customers are part of combined utilities that also use natural gas as a fuel source for electric generation. Northern Natural Gas delivered over 1.4 trillion cubic feet ("Tcf") of natural gas to its customers in 2019.

Northern Natural Gas' transportation rates and most of its storage rates are cost-based. These rates are designed to provide Northern Natural Gas with an opportunity to recover its costs of providing services and earn a reasonable return on its investments. In addition, Northern Natural Gas has fixed rates that are market-based for certain of its firm storage contracts with contract terms that expire in 2028.


28


Northern Natural Gas' operating revenue for the years ended December 31 was as follows (in millions):
 
2019
 
2018
 
2017
Transportation:
 
 
 
 
 
 
 
 
Market Area
$
544

64
%
 
$
518

58
%
 
$
504

73
%
Field Area - deliveries to Demarc
106

12

 
102

11

 
36

5

Field Area - other deliveries
95

11

 
71

9

 
50

8

Total transportation
745

87

 
691

78

 
590

86

Storage
65

8

 
68

8

 
71

10

Total transportation and storage revenue
810

95

 
759

86

 
661

96

Gas, liquids and other sales
42

5

 
128

14

 
28

4

Total operating revenue
$
852

100
%
 
$
887

100
%
 
$
689

100
%

Substantially all of Northern Natural Gas' Market Area transportation revenue is generated from reservation charges, with the balance from usage charges. Northern Natural Gas transports natural gas primarily to local distribution markets and end-users in the Market Area. Northern Natural Gas provides service to 80 utilities, including MidAmerican Energy, an affiliate company, which serve numerous residential, commercial and industrial customers. Most of Northern Natural Gas' transportation capacity in the Market Area is committed to customers under firm transportation contracts, where customers pay Northern Natural Gas a monthly reservation charge for the right to transport natural gas through Northern Natural Gas' system. Reservation charges are required to be paid regardless of volumes transported or stored. As of December 31, 2019, approximately 85% of Northern Natural Gas' customers' entitlement in the Market Area have terms beyond 2021 and approximately 55% beyond 2023. As of December 31, 2019, the weighted average remaining contract term for Northern Natural Gas' Market Area firm transportation contracts is over seven years.

Northern Natural Gas' Field Area customers consist primarily of energy marketing companies and midstream companies, which take advantage of the price spread opportunities created between Field Area supply points and Demarc. In addition, there are a growing number of midstream customers that are delivering gas south in the Field Area to the Waha Hub market. The remaining Field Area transportation service is sold to power generators connected to Northern Natural Gas' system in Texas and New Mexico that are contracted on a long-term basis with a weighted average remaining contract term of six years, and various LDCs, energy marketing companies and midstream companies for both connected and off-system markets.

Northern Natural Gas' storage services are provided through the operation of one underground natural gas storage field in Iowa and two underground natural gas storage facilities in Kansas. Additionally, Northern Natural Gas has two LNG storage peaking units, one in Iowa and one in Minnesota, that support its transportation service. The three underground natural gas storage facilities and two LNG storage peaking units have a total firm service and operational storage cycle capacity of over 79 Bcf and over 2.2 Bcf per day of peak delivery capability. These storage facilities provide operational flexibility for the daily balancing of Northern Natural Gas' system and provide services to customers for their winter peaking and year-round load swing requirements. Northern Natural Gas has 65.1 Bcf of firm storage contracts with cost-based and market-based rates. Firm storage contracts with cost-based rates, representing 57.1 Bcf, have an average remaining contract term of six years and are contracted at maximum tariff rates. The remaining firm storage contracts with market-based rates, representing 8.0 Bcf, have an average remaining contract term of eight years.

Except for quantities of natural gas owned and managed for operational and system balancing purposes, Northern Natural Gas does not own the natural gas that is transported through its system. The sale of natural gas for operational and system balancing purposes accounts for the majority of the remaining operating revenue.

During 2019, Northern Natural Gas had two customers that each accounted for greater than 10% of its transportation and storage revenue and its ten largest customers accounted for 61% of its system-wide transportation and storage revenue. Northern Natural Gas has agreements with terms through 2027 and 2034 to retain the majority of its two largest customers' volumes. The loss of any of these significant customers, if not replaced, could have a material adverse effect on Northern Natural Gas.


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Northern Natural Gas' extensive pipeline system, which is interconnected with many interstate and intrastate pipelines in the national grid system, has access to multiple major supply basins. Direct access is available from producers in the Anadarko, Permian and Hugoton basins, some of which have recently experienced increased production from shale and tight sands formations adjacent to Northern Natural Gas' pipeline. Since 2011, the pipeline has connected 2,395,000 Dths per day of supply access from the Wolfberry shale formation in west Texas and from the Granite Wash tight sands formations in the Texas panhandle and in Oklahoma. Additionally, Northern Natural Gas has interconnections with several interstate pipelines and several intrastate pipelines with receipt, delivery, or bi-directional capabilities. Because of Northern Natural Gas' location and multiple interconnections it is able to access natural gas from other key production areas, such as the Rocky Mountain, Williston, including the Bakken formation, and western Canadian basins. The Rocky Mountain basins are accessed through interconnects with Trailblazer Pipeline Company, Tallgrass Interstate Gas Transmission, LLC, Cheyenne Plains Gas Pipeline Company, LLC, Colorado Interstate Gas Company and Rockies Express Pipeline, LLC ("REX"). The western Canadian basins are accessed through interconnects with Northern Border Pipeline Company ("Northern Border"), Great Lakes Gas Transmission Limited Partnership ("Great Lakes") and Viking Gas Transmission Company ("Viking"). This supply diversity and access to both stable and growing production areas provides significant flexibility to Northern Natural Gas' system and customers.

Northern Natural Gas' system experiences significant seasonal swings in demand and revenue typically with approximately 60% of transportation revenue occurring during the months of November through March. This seasonality provides Northern Natural Gas with opportunities to deliver additional value-added services, such as firm and interruptible storage services. As a result of Northern Natural Gas' geographic location in the middle of the United States and its many interconnections with other pipelines, Northern Natural Gas has the opportunity to augment its steady end user and LDC revenue by capitalizing on opportunities for shippers to reach additional markets, such as Chicago, Illinois, other parts of the Midwest, and Texas, through interconnects.

Kern River

Kern River, an indirect wholly owned subsidiary of BHE, owns an interstate natural gas pipeline system that extends from supply areas in the Rocky Mountains to consuming markets in Utah, Nevada and California. Kern River's pipeline system consists of 1,700 miles of natural gas pipelines, including 1,400 miles of mainline section and 300 miles of common facilities, with a design capacity of 2,166,575 Dths, or 2.2 Bcf, per day. Kern River owns the entire mainline section, which extends from the system's point of origination near Opal, Wyoming, through the Central Rocky Mountains to Daggett, California. The mainline section consists of 1,300 miles of 36-inch diameter pipeline and 100 miles of various laterals that connect to the mainline. The common facilities are jointly owned by Kern River and Mojave Pipeline Company ("Mojave") as tenants-in-common. Except for quantities of natural gas owned for operational purposes, Kern River does not own the natural gas that is transported through its system. Kern River's transportation rates are cost-based. The rates are designed to provide Kern River with an opportunity to recover its costs of providing services and earn a reasonable return on its investments.

Kern River's rates are based on a levelized rate design with recovery of 70% of the original investment during the initial long-term contracts ("Period One rates"). After expiration of the initial term, eligible customers have the option to elect service at rates ("Period Two rates") that are lower than Period One rates because they are designed to recover the remaining 30% of the original investment. To the extent that eligible customers do not contract for service at Period Two rates, the volumes are turned back and sold at market rates for varying terms. As of December 31, 2019, initial Period One contracts total 331,921 Dths per day. Period Two contracts total 1,054,029 Dths per day and 606,112 Dths per day of total turned back volume has an average remaining contract term of more than two years. The remaining capacity is sold on a short-term basis at market rates.

As of December 31, 2019, approximately 83% of Kern River's design capacity of 2,166,575 Dths per day is contracted pursuant to long-term firm natural gas transportation service agreements, whereby Kern River receives natural gas on behalf of customers at designated receipt points and transports the natural gas on a firm basis to designated delivery points. In return for this service, each customer pays Kern River a fixed monthly reservation fee based on each customer's maximum daily quantity, which represents nearly 84% of total operating revenue, and a commodity charge based on the actual amount of natural gas transported pursuant to its long-term firm natural gas transportation service agreements and Kern River's tariff.

These long-term firm natural gas transportation service agreements expire between March 2021 and April 2033 and have a weighted-average remaining contract term of over eight years. Kern River's customers include electric and natural gas distribution utilities, major oil and natural gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies and financial institutions. As of December 31, 2019, 73% of the firm capacity under contract has primary delivery points in California, with the flexibility to access secondary delivery points in Nevada and Utah. Historically, Kern River has provided approximately 22% of California's demand for natural gas.


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During 2019, Kern River had two customers, including Nevada Power Company, d/b/a NV Energy, that each accounted for greater than 10% of its revenue. The loss of these significant customers, if not replaced, could have a material adverse effect on Kern River.

Competition

The Pipeline Companies compete with other pipelines on the basis of cost, flexibility, reliability of service and overall customer service, with the customer's decision being made primarily on the basis of delivered price, which includes both the natural gas commodity cost and its transportation cost. Natural gas also competes with alternative energy sources, including coal, nuclear energy, wind, geothermal, solar and fuel oil. Legislation and governmental regulations, the weather, the futures market, production costs and other factors beyond the control of the Pipeline Companies influence the price of the natural gas commodity.

The tremendous increase in production from unconventional sources, such as shale gas, has reduced volatility and decreased natural gas prices across North America. This overall reduction in commodity prices has been beneficial as it reduces overall costs for Northern Natural Gas' customers and for their end-use businesses. The dramatic increase in production has also affected the supply patterns and flows. The impact has varied among pipelines according to the location and the number of competitors attached to these new supply sources. For example, the significant increase in production in the Permian area has dramatically increased short-term transportation and revenue for Northern Natural Gas by transporting excess production from the Permian area to Demarc. This increase is expected to subside as additional pipelines are constructed out of the Permian area to alleviate the current short-term constraints.

Electric power generation has been the source of most of the growth in demand for natural gas over the last 10 years, and this trend is expected to continue in the future. The growth of natural gas in this sector is influenced by regulation, new sources of natural gas, competition with other energy sources, primarily coal and renewables, and increased consumption of electricity as a result of economic growth. Short-term market shifts have been driven by relative costs of coal-fueled generation versus natural gas-fueled generation. A long-term market shift away from the use of coal in power generation could be driven by environmental regulations. The future demand for natural gas could be increased by regulations limiting or discouraging coal use. However, natural gas demand could potentially be adversely affected by laws mandating or encouraging renewable power sources that produce fewer GHG emissions than natural gas.

The Pipeline Companies' ability to extend existing customer contracts, remarket expiring contracted capacity or market new capacity is dependent on competitive alternatives, the regulatory environment and the market supply and demand factors at the relevant dates these contracts are eligible to be renewed or extended. The duration of new or renegotiated contracts will be affected by current commodity and transportation prices, competitive conditions and customers' judgments concerning future market trends and volatility.

Subject to regulatory requirements, the Pipeline Companies attempt to recontract or remarket capacity at the maximum rates allowed under their tariffs, although at times the Pipeline Companies discount these rates to remain competitive. The Pipeline Companies' existing contracts mature at various times and in varying amounts of entitlement. The Pipeline Companies manage the recontracting process to mitigate the risk of a significant negative impact on operating revenue.

Historically, the Pipeline Companies have been able to provide competitively priced services because of access to a variety of relatively low cost supply basins, cost control measures and the relatively high level of firm entitlement that is sold on a seasonal and annual basis, which lowers the per unit cost of transportation. To date, the Pipeline Companies have avoided significant pipeline system bypasses.

Northern Natural Gas needs to compete aggressively to serve existing load and add new load. Northern Natural Gas has been successful in competing for a significant amount of the increased demand related to residential and commercial needs and the construction of new power plants and new fertilizer or other industrial plants. The growth related to utilities has historically been driven by population growth and increased commercial and industrial needs. Northern Natural Gas has been generally successful in negotiating increased transportation rates for customers who received discounted service when such contract terms are renegotiated and extended.

Northern Natural Gas' major competitors in the Market Area include ANR Pipeline Company, Northern Border, Natural Gas Pipeline Company of America LLC, Great Lakes and Viking. In the Field Area, where the majority of Northern Natural Gas' capacity is used for transportation services provided on a short-term firm basis, Northern Natural Gas competes with a large number of interstate and intrastate pipeline companies.


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Northern Natural Gas' attractive competitive position relative to other pipelines in the upper Midwest is reinforced each winter as customers expect, and receive, reliable deliveries of natural gas for their critical markets. Northern Natural Gas provides customers access to multiple supply basins that allow customers to obtain reliable supplies at competitive prices, not subject to the natural gas grid dynamics from pipeline competition that would limit customers to a singular supply source. Northern Natural Gas' Field Area has access to diverse Mid-Continent, Permian and Rockies supplies delivered to Market Area customers at Demarc at significantly lower prices than their alternative supply source. The benefits of Northern Natural Gas' system is particularly demonstrated during extreme winter conditions such as the polar vortex of 2013-2014 and severe cold weather that impacted Northern Natural Gas' Market Area in January 2019. During these periods of high market demand, customers have received all of their scheduled deliveries, without interruption, due to Northern Natural Gas' extensive, reticulated pipeline system.

Other than the short-term transportation associated with the Permian business, Northern Natural Gas expects the current level of Field Area contracting to Demarc to continue in the foreseeable future, as Market Area customers presently need to purchase competitively-priced supplies from the Field Area to support their existing and growth demand requirements. However, the revenue received from these Field Area contracts is expected to vary in relationship to the difference, or "spread," in natural gas prices between the MidContinent and Permian Regions and the price of the alternative supplies that are available to Northern Natural Gas' Market Area. This spread affects the value of the Field Area transportation capacity because natural gas from the MidContinent and Permian Regions that is transported through Northern Natural Gas' Field Area competes directly with natural gas delivered directly into the Market Area from Canada and other supply areas, including new shale gas producing areas outside of the Field Area.

Kern River competes with various interstate pipelines in developing expansion projects and entering into long-term agreements to serve market growth in Southern California; Las Vegas, Nevada; and Salt Lake City, Utah. Kern River also competes with various interstate pipelines and their customers to market unutilized capacity under shorter term transactions. Kern River provides its customers with supply diversity through interconnections with pipelines such as Northwest Pipeline LLC, Colorado Interstate Gas Company, Overland Trails Transmission, LLC, Dominion Energy Questar Pipeline LLC and Dominion Energy Questar Overthrust Pipeline LLC; and storage facilities such as Spire Storage West LLC and Clear Creek Storage Company, LLC. These interconnections, in addition to the direct interconnections to natural gas processing facilities in Wyoming and California, allow Kern River to access natural gas reserves in Colorado, northwestern New Mexico, Wyoming, Utah, California and the Western Canadian Sedimentary Basin.

Kern River is the only interstate pipeline that presently delivers natural gas directly from the Rocky Mountain gas supply region to end-users in the Southern California market. This enables direct connect customers to avoid paying a "rate stack" (i.e., additional transportation costs attributable to the movement from one or more interstate pipeline systems to an intrastate system within California). Kern River's levelized rate structure and access to upstream pipelines, storage facilities and economic Rocky Mountain gas reserves increases its competitiveness and attractiveness to end-users. Kern River believes it has an advantage relative to other interstate pipelines serving Southern California because its relatively new pipeline can be economically expanded and has required significantly less capital expenditures and ongoing maintenance than other systems to comply with the Pipeline Safety Improvement Act of 2002.

BHE TRANSMISSION

BHE Canada

BHE Canada, an indirect wholly owned subsidiary of BHE, primarily owns AltaLink, a regulated electric transmission-only utility company headquartered in Alberta, Canada serving approximately 85% of Alberta's population. AltaLink's high voltage transmission lines and related facilities transmit electricity from generating facilities to major load centers, cities and large industrial plants throughout its 87,000 square mile service territory, which covers a diverse geographic area including most major urban centers in central and southern Alberta. AltaLink's transmission facilities, consisting of approximately 8,200 miles of transmission lines and 310 substations as of December 31, 2019, are an integral part of the Alberta Integrated Electric System ("AIES").

The AIES is a network or grid of transmission facilities operating at high voltages ranging from 69 kVs to 500 kVs. The grid delivers electricity from generating units across Alberta, Canada through approximately 16,000 miles of transmission. The AIES is interconnected to British Columbia's transmission system that links Alberta with the North American western interconnected system.

AltaLink is a transmission facility owner within the electricity industry in Alberta and is permitted to charge a tariff rate for the use of its transmission facilities. Such tariff rates are established on a cost-of-service basis, which are designed to allow AltaLink an opportunity to recover its costs of providing services and to earn a reasonable return on its investments. Transmission tariffs are approved by the AUC and are collected from the AESO.

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The electricity industry in Alberta consists of four principal segments. Generators sell wholesale power into the power pool operated by the AESO and through direct contractual arrangements. Alberta's transmission system or grid is composed of high voltage power lines and related facilities that transmit electricity from generating facilities to distribution networks and directly connected end-users. Distribution facility owners are regulated by the AUC and are responsible for arranging for, or providing, regulated rate and regulated default supply services to convey electricity from transmission systems and distribution-connected generators to end-use customers. Retailers can procure energy through the power pool, through direct contractual arrangements with energy suppliers or ownership of generation facilities and arrange for its distribution to end-use customers.

The AESO mandate is defined in the Electric Utilities Act and its regulations, and requires the AESO to assess both current and future needs of Alberta's interconnected electrical system. In September 2019, the AESO released the 2019 Long-Term Outlook (LTO), which is the AESO's forecast of Alberta's load and generation over the next 20 years, and is used as one input to guide the AESO in planning Alberta's transmission system. The 2019 LTO includes a Reference Case Scenario, which is the AESO's main corporate forecast for long-term load growth and generation development in Alberta, and a set of alternative scenarios that are developed to understand future uncertainties. The Reference Case Scenario forecasts Alberta's electricity demand to grow at an annual rate of 0.9 percent over the next 20 years and a total of approximately 13 gigawatts of new generation capacity to be added for the same period. Other scenarios are developed based on modifying assumptions used in the Reference Case Scenario to reflect higher cogeneration development, alternative renewable policy, higher economic growth, lower economic growth, and a more diversified Alberta economy. The AESO indicates that it will continue monitoring economic, policy and industry development and if a scenario becomes more likely, the AESO may adopt it as its main forecast. The AESO is presently developing the Long-Term Plan which is expected to be released in the first quarter of 2020.

BHE U.S. Transmission

BHE U.S. Transmission, a wholly owned subsidiary of BHE, is engaged in various joint ventures to develop, own and operate transmission assets and is pursuing additional investment opportunities in the United States. Currently, BHE U.S. Transmission has two joint ventures with transmission assets that are operational.

BHE U.S. Transmission indirectly owns a 50% interest in ETT, along with subsidiaries of American Electric Power Company, Inc. ("AEP"). ETT owns and operates electric transmission assets in the ERCOT and, as of December 31, 2019, had total assets of $3.1 billion. ETT's transmission system includes approximately 1,200 miles of transmission lines and 36 substations as of December 31, 2019.

BHE U.S. Transmission also indirectly owns a 25% interest in Prairie Wind Transmission, LLC, a joint venture with AEP and Westar Energy, Inc., to build, own and operate a 108-mile, 345-kV transmission project in Kansas. The project had total assets of $143 million as of December 31, 2019.


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BHE RENEWABLES

The subsidiaries comprising the BHE Renewables reportable segment own interests in several independent power projects in the United States and one in the Philippines. The following table presents certain information concerning these independent power projects as of December 31, 2019:
 
 
 
 
 
 
 
 
Power
 
 
 
Facility
 
Net
 
 
 
 
 
 
 
 
Purchase
 
 
 
Net
 
Owned
 
 
 
 
Energy
 
Year
 
Agreement
 
Power
 
Capacity
 
Capacity
Generating Facility
 
Location
 
Source
 
Installed
 
Expiration
 
Purchaser(1)
 
(MWs)(2)
 
(MWs)(2)
WIND:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Grande Prairie
 
Nebraska
 
Wind
 
2016
 
2036
 
OPPD
 
400

 
400

Jumbo Road
 
Texas
 
Wind
 
2015
 
2033
 
AE
 
300

 
300

Santa Rita
 
Texas
 
Wind
 
2018
 
2025-2038
 
KC, CODTX, MES
 
300

 
300

Walnut Ridge
 
Illinois
 
Wind
 
2018
 
2028
 
USGSA
 
212

 
212

Pinyon Pines I
 
California
 
Wind
 
2012
 
2,035
 
SCE
 
168

 
168

Pinyon Pines II
 
California
 
Wind
 
2012
 
2,035
 
SCE
 
132

 
132

Bishop Hill II
 
Illinois
 
Wind
 
2012
 
2,032
 
Ameren
 
81

 
81

Marshall
 
Kansas
 
Wind
 
2016
 
2036
 
MJMEC, KPP, KMEA & COIMO
 
72

 
72

 
 
 
 
 
 
 
 
 
 
 
 
1,665

 
1,665

SOLAR:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Topaz
 
California
 
Solar
 
2013-2014
 
2039
 
PG&E
 
550

 
550

Solar Star 1
 
California
 
Solar
 
2013-2015
 
2035
 
SCE
 
310

 
310

Solar Star 2
 
California
 
Solar
 
2013-2015
 
2035
 
SCE
 
276

 
276

Agua Caliente
 
Arizona
 
Solar
 
2012-2013
 
2039
 
PG&E
 
290

 
142

Alamo 6
 
Texas
 
Solar
 
2017
 
2042
 
CPS
 
110

 
110

Community Solar Gardens(6)
 
Minnesota
 
Solar
 
2016-2018
 
2041-2043
 
(5)
 
98

 
98

Pearl
 
Texas
 
Solar
 
2017
 
2042
 
CPS
 
50

 
50

 
 
 
 
 
 
 
 
 
 
 
 
1,684

 
1,536

NATURAL GAS:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cordova
 
Illinois
 
Natural Gas
 
2001
 
NA
 
NA
 
512

 
512

Power Resources
 
Texas
 
Natural Gas
 
1988
 
NA
 
NA
 
212

 
212

Saranac
 
New York
 
Natural Gas
 
1994
 
NA
 
NA
 
245

 
196

Yuma
 
Arizona
 
Natural Gas
 
1994
 
2024
 
SDG&E
 
50

 
50

 
 
 
 
 
 
 
 
 
 
 
 
1,019

 
970

GEOTHERMAL:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Imperial Valley Projects
 
California
 
Geothermal
 
1982-2000
 
(3)
 
(3)
 
345

 
345

 
 
 
 
 
 
 
 
 
 
 
 
345

 
345

HYDROELECTRIC:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Casecnan Project(4)
 
Philippines
 
Hydroelectric
 
2001
 
2021
 
NIA
 
150

 
128

Wailuku
 
Hawaii
 
Hydroelectric
 
1993
 
2023
 
HELCO
 
10

 
10

 
 
 
 
 
 
 
 
 
 
 
 
160

 
138

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Available Generating Capacity
 
 
 
 
 
 
 
 
 
 
 
4,873

 
4,654



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(1)
Arizona Public Service ("APS"); NextEra Energy Marketing, LLC ("NEM"); City of Riverside, CA ("CORCA"); Imperial Irrigation District ("IID"); Sacramento Municipal Utility District ("SMUD"); Salt River Project ("SRP"); San Diego Gas & Electric Company ("SDG&E"); Pacific Gas and Electric Company ("PG&E"), Ameren Illinois Company ("Ameren"), Southern California Edison ("SCE"), the Philippine National Irrigation Administration ("NIA"); Hawaii Electric Light Company, Inc. ("HELCO"); Austin Energy ("AE"); Omaha Public Power District ("OPPD"); Kimberly-Clark Corporation ("KC"); City of Denton, TX ("CODTX"); MidAmerican Energy Services, LLC ("MES"); U.S. General Services Administration ("USGSA"); Missouri Joint Municipal Electric Commission ("MJMEC"); Kansas Power Pool ("KPP"); Kansas Municipal Energy Agency ("KMEA"); City of Independence, MO ("COIMO"); and CPS Energy ("CPS").
(2)
Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates BHE Renewables' ownership of Facility Net Capacity.
(3)
Approximately 17% of the Company's interests in the Imperial Valley Projects' Contract Capacity are currently sold to Southern California Edison Company under long-term power purchase agreements expiring in 2020 through 2026. Certain long-term power purchase agreement renewals for 252 MWs have been entered into with other parties at fixed prices that expire from 2028 to 2039, of which 202 MWs mature in 2039.
(4)
Under the terms of the agreement with the NIA, CalEnergy Philippines will own and operate the Casecnan project for a 20-year cooperation period which ends December 11, 2021, after which ownership and operation of the project will be transferred to the NIA at no cost on an "as-is" basis. NIA also pays CalEnergy Philippines for delivery of water pursuant to the agreement.
(5)
The power purchasers are commercial, industrial and not-for-profit organizations.
(6)
The community solar gardens project is consolidated in the table above for convenience as it consists of 98 distinct entities that each own an approximately 1-MW solar garden with independent but substantially similar terms and conditions.

Additionally, BHE Renewables has invested $3.5 billion in twenty-one wind projects sponsored by third parties, commonly referred to as tax equity investments.

The percentages of BHE Renewables' operating revenue derived from the following business activities for the years ended December 31 were as follows:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Solar
48
%
 
51
%
 
52
%
Wind
21

 
18

 
17

Geothermal
19

 
19

 
19

Hydro
2

 
5

 
6

Natural gas
10

 
7

 
6

Total operating revenue
100
%
 
100
%
 
100
%

HOMESERVICES

HomeServices, a majority-owned subsidiary of BHE, is the largest residential real estate brokerage firm in the United States. In addition to providing traditional residential real estate brokerage services, HomeServices offers other integrated real estate services, including mortgage originations and mortgage banking; title and closing services; property and casualty insurance; home warranties; relocation services; and other home-related services. HomeServices' real estate brokerage business is subject to seasonal fluctuations because more home sale transactions tend to close during the second and third quarters of the year. As a result, HomeServices' operating results and profitability are typically higher in the second and third quarters relative to the remainder of the year. HomeServices' owned brokerages currently operate in over 900 offices in 30 states and the District of Columbia with over 43,000 real estate agents under 47 brand names. The United States residential real estate brokerage business is subject to the general real estate market conditions, is highly competitive and consists of numerous local brokers and agents in each market seeking to represent sellers and buyers in residential real estate transactions.

In October 2012, HomeServices acquired a 66.7% interest in one of the largest residential real estate brokerage franchise networks in the United States, which offers and sells independently owned and operated residential real estate brokerage franchises. In April 2018, HomeServices acquired the remaining 33.3% interest.

HomeServices' franchise network currently includes approximately 380 franchisees primarily in the United States and internationally in over 1,600 brokerage offices with nearly 53,000 real estate agents under two brand names. In exchange for certain fees, HomeServices provides the right to use the Berkshire Hathaway HomeServices or Real Living brand names and other related service marks, as well as providing orientation programs, training and consultation services, advertising programs and other services.

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OTHER ENERGY BUSINESSES

Effective January 1, 2016, MidAmerican Energy Company transferred its nonregulated energy operations to MidAmerican Energy Services, LLC ("MES"), a subsidiary of BHE. MES is a nonregulated energy business consisting of competitive electricity and natural gas retail sales. MES' electric operations predominantly include sales to retail customers in Illinois, Ohio, Texas, Pennsylvania, Maryland and other states that allow customers to choose their energy supplier. MES' natural gas operations predominantly include sales to retail customers in Iowa and Illinois. Electricity and natural gas are purchased from producers and third party energy marketing companies and sold directly to commercial, industrial and governmental end-users. MES does not own electricity or natural gas production assets but hedges its contracted sales obligations either with physical supply arrangements or financial products. As of December 31, 2019, MES' contracts in place for the sale of electricity totaled 18,571 GWhs with an average term of 2.4 years and for the sale of natural gas totaled 25,717,425 Dths with an average term of 1.3 years. In addition, MES manages natural gas supplies for a number of smaller commercial end-users, which includes the sale of natural gas to these customers to meet their supply requirements. Refer to Item 7A in this Form 10-K for a discussion of commodity price risk and derivative contracts.

GENERAL REGULATION

BHE's regulated subsidiaries and certain affiliates are subject to comprehensive governmental regulation, which significantly influences their operating environment, prices charged to customers, capital structure, costs and, ultimately, their ability to recover costs and earn a reasonable return on invested capital. In addition to the discussion contained herein regarding general regulation, refer to "Regulatory Matters" in Item 1 of this Form 10-K for further discussion regarding certain regulatory matters.

Domestic Regulated Public Utility Subsidiaries

The Utilities are subject to comprehensive regulation by various state, federal and local agencies. The more significant aspects of this regulatory framework are described below.

State Regulation

Historically, state regulatory commissions have established retail electric and natural gas rates on a cost-of-service basis, which are designed to allow a utility the opportunity to recover what each state regulatory commission deems to be the utility's reasonable costs of providing services, including a fair opportunity to earn a reasonable return on its investments based on its cost of debt and equity. In addition to return on investment, a utility's cost of service generally reflects a representative level of prudent expenses, including cost of sales, operating expense, depreciation and amortization and income and other tax expense, reduced by wholesale electricity and other revenue. The allowed operating expenses are typically based on actual historical costs adjusted for known and measurable or forecasted changes. State regulatory commissions may adjust cost of service for various reasons, including pursuant to a review of: (a) the utility's revenue and expenses during a defined test period, (b) the utility's level of investment and (c) changes in income tax laws. State regulatory commissions typically have the authority to review and change rates on their own initiative; however, they may also initiate reviews at the request of a utility, utility customers or organizations representing groups of customers. In certain jurisdictions, the utility and such parties, however, may agree with one another not to request a review of or changes to rates for a specified period of time.

The retail electric rates of the Utilities are generally based on the cost of providing traditional bundled services, including generation, transmission and distribution services. The Utilities have established energy cost adjustment mechanisms and other cost recovery mechanisms in certain states, which help mitigate their exposure to changes in costs from those assumed in establishing base rates.


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With certain limited exceptions, the Utilities have an exclusive right to serve retail customers within their service territories and, in turn, have an obligation to provide service to those customers. In some jurisdictions, certain classes of customers may choose to purchase all or a portion of their energy from alternative energy suppliers, and in some jurisdictions retail customers can generate all or a portion of their own energy. Under Oregon law, PacifiCorp has the exclusive right and obligation to provide electricity distribution services to all residential and nonresidential customers within its allocated service territory; however, nonresidential customers have the right to choose an alternative provider of energy supply. The impact of this right on PacifiCorp's consolidated financial results has not been material. In Washington, state law does not provide for exclusive service territory allocation. PacifiCorp's service territory in Washington is surrounded by other public utilities with whom PacifiCorp has from time to time entered into service area agreements under the jurisdiction of the WUTC. Under California law, PacifiCorp has the exclusive right and obligation to provide electricity distribution services to all residential and nonresidential customers within its allocated service territory; however, cities, counties and certain other public agencies have the right to choose to generate energy supply or elect an alternative provider of energy supply through the formation of a Community Choice Aggregator ("CCA"). To date, no CCA activity has occurred in PacifiCorp's California service territory. If a CCA is formed, PacifiCorp would continue to provide CCA customers transmission, distribution, metering and billing services and the CCA would provide generation supply. In addition, PacifiCorp would likely be able to collect costs from CCA customers for the generation-related costs that PacifiCorp incurred while they were customers of PacifiCorp. PacifiCorp would remain the electricity provider of last resort for these customers. In Illinois, state law has established a competitive environment so that all Illinois customers are free to choose their retail service supplier. For customers that choose an alternative retail energy supplier, MidAmerican Energy continues to have an ongoing obligation to deliver the supplier's energy to the retail customer. MidAmerican Energy bills the retail customer for such delivery services. MidAmerican Energy also has an obligation to serve customers at regulated cost-based rates and has a continuing obligation to serve customers who have not selected a competitive electricity provider. The impact of this right on MidAmerican Energy's financial results has not been material. In Nevada, Chapter 704B of the Nevada Revised Statutes allows retail electric customers with an average annual load of one MW or more to file a letter of intent and application with the PUCN to acquire electric energy and ancillary services from another energy supplier. The law requires customers wishing to choose a new supplier to receive the approval of the PUCN to meet public interest standards. In particular, departing customers must secure new energy resources that are not under contract to the Nevada Utilities, the departure must not burden the Nevada Utilities with increased costs or cause any remaining customers to pay increased costs and the departing customers must pay their portion of any deferred energy balances, all as determined by the PUCN. Also, the Utilities and the state regulatory commissions are individually evaluating how best to integrate private generation resources into their service and rate design, including considering such factors as maintaining high levels of customer safety and service reliability, minimizing adverse cost impacts and fairly allocating costs among all customers.

In Nevada, large natural gas customers using 12,000 therms per month with fuel switching capability are allowed to participate in the incentive natural gas rate tariff. Once a service agreement has been executed, a customer can compare natural gas prices under this tariff to alternative energy sources and choose its source of natural gas. In addition, natural gas customers using greater than 1,000 therms per day have the ability to secure their own natural gas supplies under the gas transportation tariff.

PacifiCorp

Rate Filings

Under Utah law, the UPSC must issue a written order within 240 days of a public utility’s application for a general rate change, absent an order, the proposed rates go into effect as filed and are not subject to refund; the UPSC may allow interim rates to take effect within 45 days of an application, subject to refund or surcharge, if an adequate prima facie showing is established in hearing that the interim rate change is justified.

The OPUC has the authority to suspend proposed new rates for a period not to exceed more than six months, with an additional three-month extension, beyond the 30-day time period when the new rates would otherwise go into effect. Absent suspension or other action from the OPUC, new rates automatically go into effect 30 days from filing by the utility. Upon suspension by the OPUC, the OPUC is authorized to allow collection of an interim rate, subject to refund, during the pendency of the OPUC’s review of the rate request.

In Wyoming, the WPSC can allow interim rates to go into effect 30 days after the initial application but may require a bond to secure a refund for the amount. The WPSC may suspend the rates for final approval for a period not to exceed 10 months.

The WUTC has the authority to suspend proposed new rates, subject to hearing, for a period not to exceed 10 months beyond the 30-day time period when the new rate would otherwise go into effect.

Under Idaho law, the IPUC can suspend a filing for an initial period not to exceed five months, and an additional extension of 60 days with a showing of good cause.

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The CPUC has the authority to suspend proposed new rates, subject to hearing, for a period not to exceed 18 months. The CPUC may extend the suspension period on a case-by-case period.

Adjustment Mechanisms

In addition to recovery through base rates, PacifiCorp also achieves recovery of certain costs through various adjustment mechanisms as summarized below.
State Regulator
 
Base Rate Test Period
 
Adjustment Mechanism
UPSC
 
Forecasted or historical with known and measurable changes(1)
 
EBA under which 100% of the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates. Wheeling revenue is also included in the mechanism.
 
 
 
 
 
 
 
 
 
Balancing account to provide for 100% recovery or refund of the difference between the level of REC revenues included in base rates and actual REC revenues after adjusting for a REC incentive authorized by the UPSC.
 
 
 
 
 
 
 
 
 
Recovery mechanism for single capital investments that in total exceed 1% of existing rate base when a general rate case has occurred within the preceding 18 months.
 
 
 
 
 
OPUC
 
Forecasted
 
PCAM under which 90% of the difference between forecasted net variable power costs and PTCs established under the annual TAM and actual net variable power costs and PTCs is deferred and reflected in future rates. The difference between the forecasted and actual net variable power costs and PTCs must fall outside of an established asymmetrical deadband, with a negative annual power cost variance deadband of $15 million, and a positive annual power cost variance deadband of $30 million and is subject to an earnings test of +/- 1% on PacifiCorp's allowed return on equity.
 
 
 
 
 
 
 
 
 
Annual TAM based on forecasted net variable power costs and PTCs.
 
 
 
 
 
 
 
 
 
RAC to recover the revenue requirement of new renewable resources and associated transmission costs that are not reflected in general rates.
 
 
 
 
 
 
 
 
 
Balancing account for proceeds from the sale of RECs.
 
 
 
 
 
WPSC
 
Forecasted or historical with known and measurable changes(1)
 
ECAM under which 70% of the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates. Chemical costs and start-up fuel costs are also included in the mechanism.
 
 
 
 
 
 
 
 
 
REC and sulfur dioxide revenue adjustment mechanism to provide for recovery or refund of 100% of any difference between actual REC and sulfur dioxide revenues and the level in rates.
 
 
 
 
 
WUTC
 
Historical with known and measurable changes
 
PCAM under which the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates after applying a $4 million deadband for positive or negative net power cost variances. For net power cost variances between $4 million and $10 million, amounts to be recovered from customers are allocated 50/50 and amounts to be credited to customers are allocated 75/25 (customers/PacifiCorp). Positive or negative net power cost variances in excess of $10 million are allocated 90/10 (customers/PacifiCorp).
 
 
 
 
 
 
 
 
 
Deferral mechanism of costs for up to 24 months of new base load generation resources and eligible renewable resources and related transmission that qualify under the state's emissions performance standard and are not reflected in base rates.
 
 
 
 
 
 
 
 
 
REC revenue tracking mechanism to provide credit of 100% of REC revenues to customers.
 
 
 
 
 
 
 
 
 
Decoupling mechanism under which the difference between actual annual revenues and authorized revenues per customer is deferred and reflected in future rates, subject to an earnings test. Under the earnings test, 50% of any excess earnings over PacifiCorp's authorized return on equity is returned to customers in addition to any surcharge or surcredit related to the revenue variance. The earnings test is asymmetrical and adjustments are not made when PacifiCorp earns at or below authorized returns on equity. To trigger a rate adjustment, the deferral balance must exceed plus or minus 2.5% of the authorized revenue at the end of each deferral period by rate class. Rate adjustments must not exceed a surcharge of 5% of the actual normalized revenue by class.

 
 
 
 
 
IPUC
 
Historical with known and measurable changes
 
ECAM under which 90% of the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates. Also provides for recovery or refund of 100% of the difference between the level of REC revenues included in base rates and actual REC revenues and differences in actual PTCs compared to the amount in base rates.
 
 
 
 
 

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CPUC
 
Forecasted
 
PTAM for major capital additions that allows for rate adjustments outside of the context of a traditional general rate case for the revenue requirement associated with capital additions exceeding $50 million on a total-company basis. Filed as eligible capital additions are placed into service.
 
 
 
 
 
 
 
 
 
ECAC that allows for an annual update to actual and forecasted net power costs.
 
 
 
 
 
 
 
 
 
PTAM for attrition, a mechanism that allows for an annual adjustment to costs other than net power costs.
 
 
 
 
 
 
 
 
 
CEMA for catastrophic events, allows for deferral and cost recovery of reasonable costs incurred as the result of catastrophic events, which are events for which a state or federal agency has declared a state of emergency.


(1)
PacifiCorp has relied on both historical test periods with known and measurable adjustments, as well as forecasted test periods.

MidAmerican Energy

Rate Filings

Under Iowa law, there are two options for temporary collection of higher rates following the filing of a request for a base rate increase. Collection can begin, subject to refund, either (1) within 10 days of filing, without IUB review, or (2) 90 days after filing, with approval by the IUB, depending upon the ratemaking principles and precedents utilized. In either case, if the IUB has not issued a final order within ten months after the filing date, the temporary rates become final and any difference between the requested rate increase and the temporary rates may then be collected subject to refund until receipt of a final order. Under Illinois law, new base rates may become effective 45 days after the filing of a request with the ICC, or earlier with ICC approval. The ICC has authority to suspend the proposed new rates, subject to hearing, for a period not to exceed approximately eleven months after filing. South Dakota law authorizes the South Dakota Public Utilities Commission to suspend new base rates for up to six months during the pendency of rate proceedings; however, a utility may implement all or a portion of the proposed new rates six months after the filing of a request for a rate increase subject to refund pending a final order in the proceeding.

Iowa law also permits rate-regulated utilities to seek ratemaking principles with the IUB prior to the construction of certain types of new generating facilities. Pursuant to this law, MidAmerican Energy has applied for and obtained IUB ratemaking principles orders for a 484-MW (MidAmerican Energy's share) coal-fueled generating facility, a 495-MW combined cycle natural gas-fueled generating facility and 6,639 MWs (nominal ratings) of wind-powered generating facilities, including 421 MWs (nominal ratings) under construction, as of December 31, 2019. These ratemaking principles established cost caps for the projects, below which such costs are deemed prudent by the IUB, and authorized a fixed rate of return on equity for the respective generating facilities over the regulatory life of the facilities in any future Iowa rate proceeding. As of December 31, 2019, the generating facilities in service totaled $8.1 billion, or 44%, of MidAmerican Energy's regulated property, plant and equipment, net and were subject to these ratemaking principles at a weighted average return on equity of 11.5% with a weighted average remaining life of 33 years.

Ratemaking principles for several wind-powered generation projects have established mechanisms in Iowa where electric rate base may be reduced. The current revenue sharing mechanism originates from Wind XI and Wind XII ratemaking principles proceedings and reduces rate base for Iowa electric returns on equity exceeding an established benchmark. For 2018, sharing was triggered by MidAmerican Energy's actual equity return being above a threshold calculated annually in accordance with the IUB’s 2016 Wind XI order. The threshold, not to exceed 11%, was the weighted average equity return of rate base with returns authorized via ratemaking principles proceedings and all other rate base. For all other rate base, the return is based on interest rates on 30-year A-rated utility bond yields plus 400 basis points, with a minimum return of 9.5%. In 2018 pursuant to this mechanism, MidAmerican Energy shared with customers 100% of the revenue in excess of the trigger. In December 2018, the IUB issued an order approving ratemaking principles related to MidAmerican Energy's Wind XII project. The ratemaking principles continued the revenue sharing mechanism for 2019 and beyond, maintaining the return on equity threshold for sharing and reducing the customer sharing percentage from 100% to 90%. A second mechanism, the retail customer benefit mechanism, reduces electric rate base for the value of higher cost retail energy displaced by covered wind-powered production and applies to the wind-powered generating facilities placed in-service in 2016 under the Wind X project and facilities to be constructed under the Wind XII project approved by the IUB in 2018.


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Adjustment Mechanisms

Under its current Iowa, Illinois and South Dakota electric tariffs, MidAmerican Energy is allowed to recover fluctuations in electric energy costs for its retail electric sales through fuel, or energy, cost adjustment mechanisms. The Iowa mechanism also includes PTCs associated with wind-powered generating facilities placed in-service prior to 2013, except for PTCs earned by repowered facilities. Eligibility for PTCs associated with MidAmerican Energy's earliest projects began expiring in 2014. Facilities currently earning PTCs that benefit customers through the Iowa energy adjustment clause totaled 1,000 MWs (nominal ratings) as of December 31, 2019, with the eligibility of those facilities to earn PTCs expiring by the end of 2022. Additionally, MidAmerican Energy has transmission adjustment clauses to recover certain transmission charges related to retail customers in all jurisdictions. The transmission adjustment mechanisms recover costs billed by the MISO for regional transmission service. The Illinois adjustment mechanism additionally recovers MidAmerican Energy's entire transmission revenue requirement attributable to Illinois. The adjustment mechanisms reduce the regulatory lag for the recovery of energy and transmission costs related to retail electric customers in these jurisdictions and accomplish, with limited timing differences, a pass-through of the related costs to these customers. Recoveries through these adjustment mechanisms are reflected in operating revenue, and the related costs are reflected in cost of fuel and energy, operations and maintenance expense or income tax benefit, as applicable.

Of the wind-powered generating facilities placed in-service as of December 31, 2019, 3,933 MWs (nominal ratings) have not been included in the determination of MidAmerican Energy's Iowa retail electric base rates. In accordance with the related ratemaking principles, until such time as these generation assets are reflected in base rates and ceasing thereafter, MidAmerican Energy will continue to reduce its revenue from Iowa energy adjustment clause recoveries by $12 million each calendar year.

MidAmerican Energy's cost of natural gas purchased for resale is collected for each jurisdiction through a uniform PGA, which is updated monthly to reflect changes in actual costs. Subject to prudence reviews, the PGA accomplishes a pass-through of MidAmerican Energy's cost of natural gas purchased for resale to its customers and, accordingly, has no direct effect on net income.

MidAmerican Energy's electric and natural gas energy efficiency program costs are collected through bill riders that are adjusted annually based on actual and expected costs in accordance with the energy efficiency plans filed with and approved by the respective state regulatory commission. As such, the energy efficiency program costs, which are reflected in operations and maintenance expense, and related recoveries, which are reflected in operating revenue, have no direct impact on net income.

MidAmerican Energy has income tax rider mechanisms in Iowa and Illinois that were established in response to 2017 Tax Reform, which enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the United States federal corporate income tax rate from 35% to 21%. South Dakota implemented changes to base rates in response to 2017 Tax Reform. As a result of 2017 Tax Reform, MidAmerican Energy re-measured its accumulated deferred income tax balances at the 21% rate and increased regulatory liabilities pursuant to the approved mechanisms. In December 2018, the IUB approved in final form a tax expense revision mechanism that reduces customer electric rates for the impact of the lower income tax rate on current operations, as calculated annually, and defers the amortization of excess accumulated deferred income taxes created by their re-measurement at the 21% income tax rate to a regulatory liability, the disposition of which will be determined in MidAmerican Energy's next rate case. In 2018, Iowa Senate File 2417 was signed into law, which, among other items, reduces the state of Iowa corporate tax rate from 12% to 9.8% effective in 2021. The impacts of Iowa Senate File 2417 will be included in the Iowa tax expense revision mechanism.

NV Energy (Nevada Power and Sierra Pacific)

Rate Filings

Nevada statutes require the Nevada Utilities to file electric general rate cases at least once every three years with the PUCN. Sierra Pacific may also file natural gas general rate cases with the PUCN. The Nevada Utilities are also subject to a two-part fuel and purchased power adjustment mechanism. The Nevada Utilities make quarterly filings to reset the BTERs, based on the last 12 months of fuel and purchased power costs. The difference between actual fuel and purchased power costs and the revenue collected in the BTERs is deferred into a balancing account. The DEAA rate clears amounts deferred into the balancing account. Nevada regulations allow an electric or natural gas utility that adjusts its BTERs on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest. During required annual DEAA proceedings, the prudence of fuel and purchased power costs is reviewed, and if any costs are disallowed on such grounds, the disallowances will be incorporated into the next quarterly BTERs change. Also, on an annual basis, the Nevada Utilities (a) seek a determination that energy efficiency program expenditures were reasonable, (b) request that the PUCN reset base and amortization EEPR, and (c) request that the PUCN reset base and amortization EEIR.


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EEPR and EEIR

EEPR was established to allow the Nevada Utilities to recover the costs of implementing energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by the Nevada Utilities and approved by the PUCN in the integrated resource plan proceedings. When the Nevada Utilities' regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, they are obligated to refund energy efficiency implementation revenue previously collected for that year.

Net Metering

Nevada enacted Assembly Bill 405 ("AB 405") on June 15, 2017. The legislation, among other things, established net metering crediting rates for private generation customers with installed net metering systems less than 25 kilowatts. Under AB 405, private generation customers will be compensated at 95% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for the first 80 MWs of cumulative installed capacity of all net metering systems in Nevada, 88% of the rate for the next 80 MWs, 81% of the rate for the next 80 MWs and 75% of the rate for any additional private generation capacity. As of December 31, 2019, the cumulative installed and applied-for capacity of net metering systems under AB 405 in Nevada was 206 MWs.

Natural Disaster Mitigation Measures

Senate Bill 329 ("SB 329"), Natural Disaster Mitigation Measures, was signed into law on May 22, 2019. The legislation requires the Nevada Utilities to submit a natural disaster protection plan to the PUCN. The PUCN adopted natural disaster protection plan regulations on January 29, 2020, that require the Nevada Utilities to file their natural disaster protection plan for approval on or before March 1 of every third year, with the first filing due on March 1, 2020. The regulations also require annual updates to be filed on or before September 1 of the second and third years of the plan. The plan must include procedures, protocols and other certain information as it relates to the efforts of the Nevada Utilities to prevent or respond to a fire or other natural disaster. The expenditures incurred by the Nevada Utilities in developing and implementing the natural disaster protection plan are required to be held in a regulatory asset account, with the Nevada Utilities filing an application for recovery on or before March 1 of each year. The Nevada Utilities are required to submit their initial natural disaster protection plan to the PUCN on or before March 1, 2020 and file their first application seeking recovery of 2019 expenditures on March 1, 2020.            

Federal Regulation

The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act, the Natural Gas Act ("NGA"), the Energy Policy Act of 2005 ("Energy Policy Act") and other federal statutes. The FERC regulates rates for wholesale sales of electricity; transmission of electricity, including pricing and regional planning for the expansion of transmission systems; electric system reliability; utility holding companies; accounting and records retention; securities issuances; construction and operation of hydroelectric facilities; and other matters. The FERC also has the enforcement authority to assess civil penalties of up to $1.3 million per day per violation of rules, regulations and orders issued under the Federal Power Act. The Utilities have implemented programs and procedures that facilitate and monitor compliance with the FERC's regulations described below. MidAmerican Energy is also subject to regulation by the NRC pursuant to the Atomic Energy Act of 1954, as amended ("Atomic Energy Act"), with respect to its ownership interest in the Quad Cities Station.

Wholesale Electricity and Capacity

The FERC regulates the Utilities' rates charged to wholesale customers for electricity and transmission capacity and related services. Much of the Utilities' wholesale electricity sales and purchases occur under market-based pricing allowed by the FERC and are therefore subject to market volatility. The Utilities are precluded from selling at market-based rates in the PacifiCorp-East, PacifiCorp-West, Nevada Utilities, Idaho Power Company and NorthWestern Energy balancing authority areas. Wholesale electricity sales in those specific balancing authority areas are permitted at cost-based rates. PacifiCorp and the Nevada Utilities have been granted the authority to bid into the California EIM at market-based rates.


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The Utilities' authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the Utilities are required to submit triennial filings to the FERC that demonstrate a lack of market power over sales of wholesale electricity and electric generation capacity in their respective market areas. PacifiCorp, the Nevada Utilities and certain affiliates, representing the BHE Northwest Companies, file together for market power study purposes. The BHE Northwest Companies' most recent triennial filing was made in June 2019 and is under review by the FERC. MidAmerican Energy and certain affiliates file together for market power study purposes of the FERC-defined Northeast Region. The most recent triennial filing for the Northeast Region was made in June 2017 and an order accepting it was issued in January 2018. MidAmerican Energy and certain affiliates file together for market power study purposes of the FERC-defined Central Region. The most recent triennial filing for the Central Region was made in December 2017 and an order accepting it was issued in November 2018. Under the FERC's market-based rules, the Utilities must also file with the FERC a notice of change in status when there is a change in the conditions that the FERC relied upon in granting market-based rate authority.

Transmission

PacifiCorp's and the Nevada Utilities' wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp's and the Nevada Utilities' OATT, respectively. These services are offered on a non-discriminatory basis, which means that all potential customers are provided an equal opportunity to access the transmission system. PacifiCorp's and the Nevada Utilities' transmission business is managed and operated independently from its wholesale marketing business in accordance with the FERC's Standards of Conduct. PacifiCorp and the Nevada Utilities have made several required compliance filings in accordance with these rules.

In December 2011, PacifiCorp adopted a cost-based formula rate under its OATT for its transmission services. Cost-based formula rates are intended to be an effective means of recovering PacifiCorp's investments and associated costs of its transmission system without the need to file rate cases with the FERC, although the formula rate results are subject to discovery and challenges by the FERC and intervenors. A significant portion of these services are provided to PacifiCorp's energy supply management function.

MidAmerican Energy participates in the MISO as a transmission-owning member. Accordingly, the MISO is the transmission provider under its FERC-approved OATT. While the MISO is responsible for directing the operation of MidAmerican Energy's transmission system, MidAmerican Energy retains ownership of its transmission assets and, therefore, is subject to the FERC's reliability standards discussed below. MidAmerican Energy's transmission business is managed and operated independently from its wholesale marketing business in accordance with the FERC Standards of Conduct.

MidAmerican Energy constructed and owns four Multi-Value Projects ("MVPs") located in Iowa and Illinois that added approximately 250 miles of 345-kV transmission line to MidAmerican Energy's transmission system since 2012. The MISO OATT allows for broad cost allocation for MidAmerican Energy's MVPs, including similar MVPs of other MISO participants. Accordingly, a significant portion of the revenue requirement associated with MidAmerican Energy's MVP investments is shared with other MISO participants based on the MISO's cost allocation methodology, and a portion of the revenue requirement of the other participants' MVPs is allocated to MidAmerican Energy. The transmission assets and financial results of MidAmerican Energy's MVPs are excluded from the determination of its retail electric rates.

The FERC has established an extensive number of mandatory reliability standards developed by the NERC and the WECC, including planning and operations, critical infrastructure protection and regional standards. Compliance, enforcement and monitoring oversight of these standards is carried out by the FERC; the NERC; and the WECC for PacifiCorp, Nevada Power, and Sierra Pacific; and the Midwest Reliability Organization for MidAmerican Energy.

Hydroelectric

The FERC licenses and regulates the operation of hydroelectric systems, including license compliance and dam safety programs. Most of PacifiCorp's hydroelectric generating facilities are licensed by the FERC as major systems under the Federal Power Act, and certain of these systems are licensed under the Oregon Hydroelectric Act. Under the Federal Power Act, 18 developments associated with PacifiCorp's hydroelectric generating facilities licensed with the FERC are classified as "high hazard potential," meaning it is probable in the event of a dam failure that loss of human life in the downstream population could occur. The FERC provides guidelines utilized by PacifiCorp in development of public safety programs consisting of a dam safety program and emergency action plans.

PacifiCorp's Klamath River hydroelectric system is the only significant hydroelectric system for which PacifiCorp has a pending relicensing process with the FERC. Refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for an update regarding hydroelectric relicensing for PacifiCorp's Klamath River hydroelectric system.

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Nuclear Regulatory Commission

General

MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its license and 25% ownership interest in Quad Cities Station. Exelon Generation, the operator and 75% owner of Quad Cities Station, is under contract with MidAmerican Energy to secure and keep in effect all necessary NRC licenses and authorizations.

The NRC regulates the granting of permits and licenses for the construction and operation of nuclear generating stations and regularly inspects such stations for compliance with applicable laws, regulations and license terms. Current licenses for Quad Cities Station provide for operation until December 14, 2032. The NRC review and regulatory process covers, among other things, operations, maintenance and environmental and radiological aspects of such stations. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses.

Federal regulations provide that any nuclear operating facility may be required to cease operation if the NRC determines there are deficiencies in state, local or utility emergency preparedness plans relating to such facility, and the deficiencies are not corrected. Exelon Generation has advised MidAmerican Energy that an emergency preparedness plan for Quad Cities Station has been approved by the NRC. Exelon Generation has also advised MidAmerican Energy that state and local plans relating to Quad Cities Station have been approved by the Federal Emergency Management Agency.

The NRC also regulates the decommissioning of nuclear-powered generating facilities, including the planning and funding for the eventual decommissioning of the facilities. In accordance with these regulations, MidAmerican Energy submits a biennial report to the NRC providing reasonable assurance that funds will be available to pay its share of the costs of decommissioning Quad Cities Station. MidAmerican Energy has established a trust for the investment of funds collected for nuclear decommissioning of Quad Cities Station.

Under the Nuclear Waste Policy Act of 1982 ("NWPA"), the United States Department of Energy ("DOE") is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Exelon Generation, as required by the NWPA, signed a contract with the DOE under which the DOE was to receive spent nuclear fuel and high-level radioactive waste for disposal beginning not later than January 1998. The DOE did not begin receiving spent nuclear fuel on the scheduled date and remains unable to receive such fuel and waste. The costs to be incurred by the DOE for disposal activities were previously being financed by fees charged to owners and generators of the waste. In accordance with a 2013 ruling by the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit"), the DOE, in May 2014, provided notice that, effective May 16, 2014, the spent nuclear fuel disposal fee would be zero. In 2004, Exelon Generation, reached a settlement with the DOE concerning the DOE's failure to begin accepting spent nuclear fuel in 1998. As a result, Quad Cities Station has been billing the DOE, and the DOE is obligated to reimburse the station for all station costs incurred due to the DOE's delay. Exelon Generation has constructed an interim spent fuel storage installation ("ISFSI") at Quad Cities Station consisting of two pads to store spent nuclear fuel in dry casks in order to free space in the storage pool. The first dry cask was placed in-service in 2005. The first pad at the ISFSI is expected to be full and the second pad placed into operation during 2020. The first and second pads at the ISFSI are expected to facilitate storage of casks to support operations at Quad Cities Station through the end of its operating licenses.    
    
Nuclear Insurance

MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in Quad Cities Station through a combination of insurance purchased by Exelon Generation, insurance purchased directly by MidAmerican Energy, and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988 ("Price-Anderson"), which was amended and extended by the Energy Policy Act. The general types of coverage maintained are: nuclear liability, property damage or loss and nuclear worker liability, as discussed below.

Exelon Generation purchases private market nuclear liability insurance for Quad Cities Station in the maximum available amount of $450 million, which includes coverage for MidAmerican Energy's ownership. In accordance with Price-Anderson, excess liability protection above that amount is provided by a mandatory industry-wide Secondary Financial Protection program under which the licensees of nuclear generating facilities could be assessed for liability incurred due to a serious nuclear incident at any commercial nuclear reactor in the United States. Currently, MidAmerican Energy's aggregate maximum potential share of an assessment for Quad Cities Station is approximately $69 million per incident, payable in installments not to exceed $10 million annually.

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The insurance for nuclear property damage losses covers property damage, stabilization and decontamination of the facility, disposal of the decontaminated material and premature decommissioning arising out of a covered loss. For Quad Cities Station, Exelon Generation purchases primary and excess property insurance protection for the combined interests in Quad Cities Station, with coverage limits for nuclear damage losses up to $1.5 billion. MidAmerican Energy also directly purchases extra expense coverage for its share of replacement power and other extra expenses in the event of a covered accidental outage at Quad Cities Station. The property and related coverages purchased directly by MidAmerican Energy and by Exelon Generation, which includes the interests of MidAmerican Energy, are underwritten by an industry mutual insurance company and contain provisions for retrospective premium assessments to be called upon based on the industry mutual board of directors' discretion for adverse loss experience. Currently, the maximum retrospective amounts that could be assessed against MidAmerican Energy from industry mutual policies for its obligations associated with Quad Cities Station total $9 million.

The master nuclear worker liability coverage, which is purchased by Exelon Generation for Quad Cities Station, is an industry-wide guaranteed-cost policy with an aggregate limit of $450 million for the nuclear industry as a whole, which is in effect to cover tort claims of workers in nuclear-related industries.

United States Mine Safety

PacifiCorp's mining operations are regulated by the Federal Mine Safety and Health Administration, which administers federal mine safety and health laws and regulations, and state regulatory agencies. The Federal Mine Safety and Health Administration has the statutory authority to institute a civil action for relief, including a temporary or permanent injunction, restraining order or other appropriate order against a mine operator who fails to pay penalties or fines for violations of federal mine safety standards. Federal law requires PacifiCorp to have a written emergency response plan specific to each underground mine it operates, which is reviewed by the Federal Mine Safety and Health Administration every six months, and to have at least two mine rescue teams located within one hour of each mine. Information regarding PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Reform Act is included in Exhibit 95 to this Form 10-K.

Interstate Natural Gas Pipeline Subsidiaries

The Pipeline Companies are regulated by the FERC, pursuant to the NGA and the Natural Gas Policy Act of 1978. Under this authority, the FERC regulates, among other items, (a) rates, charges, terms and conditions of service and (b) the construction and operation of interstate pipelines, storage and related facilities, including the extension, expansion or abandonment of such facilities. The Pipeline Companies hold certificates of public convenience and necessity issued by the FERC, which authorize them to construct, operate and maintain their pipeline and related facilities and services.

FERC regulations and the Pipeline Companies' tariffs allow each of the Pipeline Companies to charge approved rates for the services set forth in their respective tariff. Generally, these rates are a function of the cost of providing services to their customers, including prudently incurred operations and maintenance expenses, taxes, depreciation and amortization and a reasonable return on their invested capital. Both Northern Natural Gas' and Kern River's tariff rates have been developed under a rate design methodology whereby substantially all of their fixed costs, including a return on invested capital and income taxes, are collected through reservation charges, which are paid by firm transportation and storage customers regardless of volumes shipped. Commodity charges, which are paid only with respect to volumes actually shipped, are designed to recover the remaining, primarily variable, costs. Kern River's reservation rates have historically been approved using a "levelized" cost-of-service methodology so that the rate remains constant over the levelization period. This levelized cost of service has been achieved by using a FERC-approved depreciation schedule in which depreciation increases as the cost of capital decreases on declining rate base.

Both Northern Natural Gas' and Kern River's rates are subject to change in future general rate proceedings. Rates for natural gas pipelines are changed by filings under either Section 5 or Section 4 of the Natural Gas Act. Section 5 proceedings are initiated by the FERC or the pipeline's customers for a potential reduction to rates that the FERC finds are no longer just and reasonable. In a Section 5 proceeding, the FERC has the burden of demonstrating that the currently effective rates of the pipeline are no longer just and reasonable, and of establishing just and reasonable rates. Any rate decrease as a result of a Section 5 proceeding would be implemented prospectively upon the issuance of a final FERC order calculating the new just and reasonable rates. Section 4 rate proceedings are initiated by the natural gas pipeline, who must demonstrate that the new proposed rates are just and reasonable. The new rates as a result of a Section 4 proceeding are typically implemented six months after the Section 4 filing and are subject to refund upon issuance of a final order by the FERC.

Natural gas transportation companies may not grant any undue preference to any customer. FERC regulations also restrict each pipeline's marketing affiliates' access to certain non-public information regarding their affiliated interstate natural gas transmission pipelines.

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Interstate natural gas pipelines are also subject to regulations administered by the Office of Pipeline Safety within the Pipeline and Hazardous Materials Safety Administration, an agency within the United States Department of Transportation ("DOT"). Federal pipeline safety regulations are issued pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended ("NGPSA"), which establishes safety requirements in the design, construction, operation and maintenance of interstate natural gas facilities, and requires an entity that owns or operates pipeline facilities to comply with such plans. Major amendments to the NGPSA include the Pipeline Safety Improvement Act of 2002 ("2002 Act"), the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 ("2006 Act"), the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 ("2011 Act") and the Protecting Our Infrastructure Of Pipelines And Enhancing Safety Act Of 2016 ("2016 Act").

The 2002 Act established additional safety and pipeline integrity regulations for all natural gas pipelines in high-consequence areas. The 2002 Act imposed major new requirements in the areas of operator qualifications, risk analysis and integrity management. The 2002 Act mandated more frequent periodic inspection or testing of natural gas pipelines in high-consequence areas, which are locations where the potential consequences of a natural gas pipeline accident may be significant or may do considerable harm to persons or property. Pursuant to the 2002 Act, the DOT promulgated regulations that require natural gas pipeline operators to develop comprehensive integrity management programs, to identify applicable threats to natural gas pipeline segments that could impact high-consequence areas, to assess these segments and to provide ongoing mitigation and monitoring. The regulations require recurring inspections of high-consequence area segments every seven years after the initial baseline assessment which was completed by Kern River in early 2011 and Northern Natural Gas in 2012.

The 2006 Act required pipeline operators to institute human factors management plans for personnel employed in pipeline control centers. DOT regulations published pursuant to the 2006 Act required development and implementation of written control room management procedures.

The 2011 Act was a response to natural gas pipeline incidents, most notably the San Bruno natural gas pipeline explosion that occurred in September 2010 in California. The 2011 Act increased the maximum allowable civil penalties for violations, directs operator assistance for Federal authorities conducting investigations and authorized the DOT to hire additional inspection and enforcement personnel. The 2011 Act also directed the DOT to study several topics, including the definition of high-consequence areas, the use of automatic shutoff valves in high-consequence areas, expansion of integrity management requirements beyond high-consequence areas and cast iron pipe replacement. The studies are complete, and a number of notices of proposed rulemaking have been issued. The Pipeline and Hazardous Materials Safety Administration issued the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements and Other Related Amendments final rule in October 2019. The primary change is the expansion of the pipeline integrity assessment requirements to cover moderate-consequence areas and reconfirming maximum allowable operating pressures. Pipeline operators must develop procedures to address assessment requirements and define and map locations by mid-2021 and complete 50% of the required integrity testing by 2028 and the remaining testing by 2034. The BHE Pipeline Group is assessing the impact of the rule. This is the first of three parts of the anticipated new rules. Additional final rules are expected in 2020.

The 2016 Act required the Pipeline and Hazardous Materials Safety Administration to set federal minimum safety standards for underground natural gas storage facilities and authorized emergency order authority. In January 2020, the Pipeline and Hazardous Materials Safety Administration issued a final rule regarding underground natural gas storage facilities that incorporates by reference the American Petroleum Institute's Recommended Practice 1171, "Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs", clarifies certain aspects of the mandatory nature of the standard and defines regulatory completion dates for underground storage facility risk assessments. Northern Natural Gas has three underground natural gas storage fields which fall under this regulation and does not expect the impact of complying with the final rule to be significant. Kern River does not have underground natural gas storage facilities.

The DOT and related state agencies routinely audit and inspect the pipeline facilities for compliance with their regulations. The Pipeline Companies conduct internal audits of their facilities every four years with more frequent reviews of those deemed higher risk. The Pipeline Companies also conduct preliminary audits in advance of agency audits. Compliance issues that arise during these audits or during the normal course of business are addressed on a timely basis. The Pipeline Companies believe their pipeline systems comply in all material respects with the NGPSA and with DOT regulations issued pursuant to the NGPSA.


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Northern Powergrid Distribution Companies

The Northern Powergrid Distribution Companies, as holders of electricity distribution licenses, are subject to regulation by GEMA. GEMA regulates distribution network operators ("DNOs") within the terms of the Electricity Act 1989 and the terms of DNO licenses, which are revocable with 25 years notice. Under the Electricity Act 1989, GEMA has a duty to ensure that DNOs can finance their regulated activities and DNOs have a duty to maintain an investment grade credit rating. GEMA discharges certain of its duties through its staff within Ofgem. Each of fourteen licensed DNOs distributes electricity from the national grid transmission system and distribution-connected generators to end users within its respective distribution services area.

DNOs are subject to price controls, enforced by Ofgem, that limit the revenue that may be recovered and retained from their electricity distribution activities. The regulatory regime that has been applied to electricity distributors in Great Britain encourages companies to look for efficiency gains in order to improve profits. The distribution price control formula also adjusts the revenue received by DNOs to reflect a number of factors, including, but not limited to, the rate of inflation (as measured by the United Kingdom's Retail Prices Index) and the quality of service delivered by the licensee's distribution system. The current price control, Electricity Distribution 1 ("ED1"), has been set for a period of eight years, starting April 1, 2015, although the formula has been, and may be, reviewed by the regulator following public consultation. The procedure and methodology adopted at a price control review are at the reasonable discretion of Ofgem. Ofgem's judgment of the future allowed revenue of licensees is likely to take into account, among other things:
the actual operating and capital costs of each of the licensees;
the operating and capital costs that each of the licensees would incur if it were as efficient as, in Ofgem's judgment, the more efficient licensees;
the actual value of certain costs which are judged to be beyond the control of the licensees;
the taxes that each licensee is expected to pay;
the regulatory value ascribed to the expenditures that have been incurred in the past and the efficient expenditures that are to be incurred in the forthcoming regulatory period;
the rate of return to be allowed on expenditures that make up the regulatory asset value;
the financial ratios of each of the licensees and the license requirement for each licensee to maintain investment grade status;
an allowance in respect of the repair of the pension deficits in the defined benefit pension schemes sponsored by each of the licensees; and
any under- or over-recoveries of revenues, relative to allowed revenues, in the previous price control period.

A number of incentive schemes also operate within the current price control period to encourage DNOs to provide an appropriate quality of service to end users. This includes specified payments to be made for failures to meet prescribed standards of service. The aggregate of these guaranteed standards payments is uncapped, but may be excused in certain prescribed circumstances that are generally beyond the control of the DNOs.

A new price control can be implemented by GEMA without the consent of the DNOs, but if a licensee disagrees with a change to its license it can appeal the matter to the United Kingdom's CMA, as can certain other parties. Any appeals must be notified within 20 working days of the license modification by GEMA. If the CMA determines that the appellant has relevant standing, then the statute requires that the CMA complete its process within six months, or in some exceptional circumstances seven months. The Northern Powergrid Distribution Companies appealed Ofgem's proposals for the resetting of the formula that commenced April 1, 2015, as did one other party, and the CMA subsequently revised GEMA's decision.

The current eight-year electricity distribution price control period runs from April 1, 2015 through March 31, 2023. The current price control was the first to be set for electricity distribution in Great Britain since Ofgem completed its review of network regulation (known as the RPI-X @ 20 project). The key changes to the price control calculations, compared to those used in previous price controls are that:
the period over which new regulatory assets are depreciated is being gradually lengthened, from 20 years to 45 years, with the change being phased over eight years;
allowed revenues will be adjusted during the price control period, rather than at the next price control review, to partially reflect cost variances relative to cost allowances;

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the allowed cost of debt will be updated within the price control period by reference to a long-run trailing average based on external benchmarks of utility debt costs;
allowed revenues will be adjusted in relation to some new service standard incentives, principally relating to speed and service standards for new connections to the network; and
there was scope for a mid-period review and adjustment to revenues in the latter half of the period for any changes in the outputs required of licensees for certain specified reasons, although GEMA made no adjustments under this provision.

Under the current price control, as revised by the CMA, and excluding the effects of incentive schemes and any deferred revenues from the prior price control, the base allowed revenue of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc remains constant in all subsequent years within the price control period (ED1) through 2022-23, before the addition of inflation. Nominal base allowed revenues will increase in line with inflation.

Ofgem also monitors DNO compliance with license conditions and enforces the remedies resulting from any breach of condition. License conditions include the prices and terms of service, financial strength of the DNO, the provision of information to Ofgem and the public, as well as maintaining transparency, non-discrimination and avoidance of cross-subsidy in the provision of such services. Ofgem also monitors and enforces certain duties of a DNO set out in the Electricity Act 1989, including the duty to develop and maintain an efficient, coordinated and economical system of electricity distribution. Under changes to the Electricity Act 1989 introduced by the Utilities Act 2000, GEMA is able to impose financial penalties on DNOs that contravene any of their license duties or certain of their duties under the Electricity Act 1989, as amended, or that are failing to achieve a satisfactory performance in relation to the individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the licensee's revenue.

AltaLink

AltaLink is regulated by the AUC, pursuant to the Electric Utilities Act (Alberta), the Public Utilities Act (Alberta), the Alberta Utilities Commission Act (Alberta) and the Hydro and Electric Energy Act (Alberta). The AUC is an independent, quasi-judicial agency established by the province of Alberta, Canada, which is responsible for, among other things, approving the tariffs of transmission facility owners, including AltaLink, and distribution utilities, acquisitions of such transmission facility owners or utilities, and construction and operation of new transmission projects in Alberta. The AUC also investigates and rules on regulated rate disputes and system access problems. The AUC regulates and oversees Alberta's electricity transmission sector with broad authority that may impact many of AltaLink's activities, including its tariffs, rates, construction, operations and financing.

The AUC has various core functions in regulating the Alberta electricity transmission sector, including the following:
regulating and adjudicating issues related to the operation of electric utilities within Alberta;
processing and approving general tariff applications relating to revenue requirements and rates of return including deemed capital structure for regulated utilities while ensuring that utility rates are just and reasonable and approval of the transmission tariff rates of regulated transmission providers paid by the AESO, which is the independent transmission system operator in Alberta, Canada that controls the operation of AltaLink's transmission system;
approving the need for new electricity transmission facilities and permits to build and licenses to operate electricity transmission facilities;
reviewing operations and accounts from electric utilities and conducting on-site inspections to ensure compliance with industry regulation and standards;
adjudicating enforcement issues including the imposition of administrative penalties that arise when market participants violate the rules of the AESO; and
collecting, storing, analyzing, appraising and disseminating information to effectively fulfill its duties as an industry regulator.

AltaLink's tariffs are regulated by the AUC under the provisions of the Electric Utilities Act in respect of rates and terms and conditions of service. The Electric Utilities Act and related regulations require the AUC to consider that it is in the public interest to provide consumers the benefit of unconstrained transmission access to competitive generation and the wholesale electricity market. In regulating transmission tariffs, the AUC must facilitate sufficient investment to ensure the timely upgrade, enhancement or expansion of transmission facilities, and foster a stable investment climate and a continued stream of capital investment for the transmission system.


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Under the Electric Utilities Act, AltaLink prepares and files applications with the AUC for approval of tariffs to be paid by the AESO for the use of its transmission facilities, and the terms and conditions governing the use of those facilities. The AUC reviews and approves such tariff applications based on a cost-of-service regulatory model under a forward test year basis. Under this model, the AUC provides AltaLink with a reasonable opportunity to (i) recover the net book value of assets and all prudently incurred costs; (ii) earn a fair return on equity; and (iii) recover its forecast costs, including operating expenses, depreciation, borrowing costs and taxes associated with its regulated transmission business. The AUC must approve tariffs that are just, reasonable and not unduly preferential, arbitrary or unjustly discriminatory. AltaLink's transmission tariffs are not dependent on the price or volume of electricity transported through its transmission system.

The AESO is an independent system operator in Alberta, Canada that oversees the AIES and wholesale electricity market. The AESO is responsible for directing the safe, reliable and economic operation of the AIES, including long-term transmission system planning. AltaLink and the other transmission facility owners receive substantially all of their transmission tariff revenues from the AESO. The AESO, in turn, charges wholesale tariffs, approved by the AUC, in a manner that promotes fair and open access to the AIES and facilitates a competitive market for the purchase and sale of electricity. The AESO monitors compliance with approved reliability standards, which are enforced by the Market Surveillance Administrator, which may impose penalties on transmission facility owners for non-compliance with the approved reliability standards.

The AESO determines the need and plans for the expansion and enhancement of a congestion free transmission system in Alberta in accordance with applicable law and reliability standards. The AESO's responsibilities include long-term transmission planning and management, including assessing and planning for the current and future transmission system capacity needs of the AESO market participants. When the AESO determines an expansion or enhancement of the transmission system is needed, with limited exceptions, it submits an application to the AUC for approval of the proposed expansion or enhancement. The AESO then determines which transmission provider should submit an application to the AUC for a permit and license to construct and operate the designated transmission facilities. Generally the transmission provider operating in the geographic area where the transmission facilities expansion or enhancement is to be located is selected by the AESO to build, own and operate the transmission facilities. In addition, Alberta law provides that certain transmission projects may be subject to a competitive process open to qualified bidders.

Independent Power Projects

The Yuma, Cordova, Saranac, Power Resources, Topaz, Agua Caliente, Solar Star, Bishop Hill II, Jumbo Road, Marshall, Grande Prairie, Walnut Ridge, Pinyon Pines, Santa Rita, Alamo 6 and Pearl independent power projects are Exempt Wholesale Generators ("EWG") under the Energy Policy Act, while the Community Solar Gardens, Imperial Valley and Wailuku independent power projects are currently certified as Qualifying Facilities ("QF") under the Public Utility Regulatory Policies Act of 1978. Both EWGs and QFs are generally exempt from compliance with extensive federal and state regulations that control the financial structure of an electric generating plant and the prices and terms at which electricity may be sold by the facilities.

The Yuma, Cordova, Saranac, Imperial Valley, Topaz, Agua Caliente, Solar Star, Bishop Hill II, Marshall, Grande Prairie, Walnut Ridge and Pinyon Pines independent power projects have obtained authority from the FERC to sell their power using market-based rates. This authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the respective independent power projects are required to submit triennial filings to the FERC that demonstrate a lack of market power over sales of wholesale electricity and electric generation capacity in their respective market areas. The Pinyon Pines, Solar Star, Topaz and Yuma independent power projects and power marketer CalEnergy, LLC file together for market power study purposes of the FERC-defined Southwest Region. The most recent triennial filing for the Southwest Region was made in June 2019 and is awaiting FERC action. The Cordova and Saranac independent power projects and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Northeast Region. The most recent triennial filing for the Northeast Region was made in June 2017 and an order accepting it was issued in January 2018. The Bishop Hill II and Walnut Ridge independent power projects and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Central Region. The most recent triennial filing for the Central Region was made in December 2017 and an order accepting it was issued in November 2018. The Marshall and Grande Prairie independent power projects and power marketer CalEnergy, LLC file together for market power study purposes in the FERC-defined Southwest Power Pool Region. The most recent triennial filing for the Southwest Power Pool Region was made in December 2018 and an order accepting it was issued July 2019.


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The entire output of Jumbo Road, Santa Rita, Alamo 6, Pearl and Power Resources is within the Electric Reliability Council of Texas ("ERCOT") and market-based authority is not required for such sales solely within ERCOT as the ERCOT market is not a FERC-jurisdictional market. Similarly, Wailuku sells its output solely to the Hawaii Electric Light Company within the Hawaii electric grid, which is not a FERC-jurisdictional market and therefore, Wailuku does not require market-based rate authority.

EWGs are permitted to sell capacity and electricity only in the wholesale markets, not to end users. Additionally, utilities are required to purchase electricity produced by QFs at a price that does not exceed the purchasing utility's "avoided cost" and to sell back-up power to the QFs on a non-discriminatory basis, unless they have successfully petitioned the FERC for an exemption from this purchase requirement. Avoided cost is defined generally as the price at which the utility could purchase or produce the same amount of power from sources other than the QF on a long-term basis. The Energy Policy Act eliminated the purchase requirement for utilities with respect to new contracts under certain conditions. New QF contracts are also subject to FERC rate filing requirements, unlike QF contracts entered into prior to the Energy Policy Act. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates other than the utilities' avoided cost.

The Philippine Congress has passed the Electric Power Industry Reform Act of 2001 ("EPIRA"), which is aimed at restructuring the Philippine power industry, privatizing the National Power Corporation ("NPC") and introducing a competitive electricity market, among other initiatives. Under the EPIRA, Power Sector Assets and Liabilities Management Corporation ("PSALM") is tasked, among others, to dispose of and privatize the assets of NPC. PSALM recently issued statements that public bidding of the administration and management of the contracted energy of the Casecnan Project's energy conversion and power purchase agreement to interested parties will be made in 2021. It is still not known what impact, if any, the implementation of this change in independent power producer administrator may have on the Casecnan Project's future operations.

Residential Real Estate Brokerage Company

HomeServices is regulated by the United States Consumer Financial Protection Bureau which enforces the Truth In Lending Act ("TILA") and the Real Estate Settlement Procedures Act ("RESPA"); the United States Federal Trade Commission with respect to certain franchising activities; and by state agencies where it operates. TILA regulates lending practices. RESPA regulates real estate settlement services including real estate closing practices, lender servicing and escrow account practices and business relationships among settlement service providers and third parties to the transaction.


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REGULATORY MATTERS

In addition to the discussion contained herein regarding regulatory matters, refer to "General Regulation" in Item 1 of this Form 10-K for further discussion regarding the general regulatory framework.

PacifiCorp

Multi-State Process

In November 2019, PacifiCorp completed negotiations with the Multi-State Process Workgroup, resulting in a new cost allocation agreement, the 2020 Protocol. The agreement establishes a common allocation method to be used in Utah, Oregon, Wyoming, Idaho and California through 2023, and a separate method for Washington during the same time period that is based on a system approach for cost allocations and provides a path forward for Washington to achieve compliance with Washington's newly-enacted Clean Energy Transformation Act. The agreement establishes a process for the 2020 Protocol signatories to resolve remaining outstanding cost-allocations to be implemented in a new, permanent and long-term allocation method at the end of the four years. In December 2019, PacifiCorp submitted the 2020 Protocol to the UPSC, the OPUC, the WPSC and the IPUC for approval. WUTC approval of the agreement is being sought in the general rate case filing submitted in December 2019, and CPUC approval will be requested in a future rate case. In January 2020, the OPUC issued an order adopting the 2020 Protocol.

Retirement Plan Settlement Charge

During 2018, the PacifiCorp Retirement Plan incurred a settlement charge of $22 million as a result of excess lump sum distributions over the defined threshold for the year ended December 31, 2018. In December 2018, PacifiCorp submitted filings with the UPSC, the OPUC, the WPSC and the WUTC seeking approval to defer the settlement charge. Also in December 2018, an advice letter was filed with the CPUC requesting a memorandum account to track the costs associated with pension and postretirement settlements and curtailments. In April 2019, the WUTC approved PacifiCorp's requested deferral. In May 2019, the UPSC denied PacifiCorp's request. In October 2019, the request for a memorandum account was re-filed as an application with the CPUC. A hearing was held before the WPSC in October 2019 and in November 2019 the WPSC denied PacifiCorp's request. In January 2020, the OPUC issued an order denying PacifiCorp's request.

2017 Tax Reform

2017 Tax Reform enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the United States federal corporate income tax rate from 35% to 21%. In 2018, PacifiCorp agreed to refund or defer the impact of the tax law change with each of its state regulatory commissions. The status of the remaining 2017 Tax Reform proceedings is noted in the applicable state sections below.

Utah

In March 2018, PacifiCorp filed its annual EBA with the UPSC seeking approval to recover $3 million, or 0.1%, in deferred net power costs from customers for the period January 1, 2017 through December 31, 2017, reflecting the difference between base and actual net power costs in the 2017 deferral period. The rate change was approved by the UPSC effective May 1, 2018 on an interim basis. A hearing was held in February 2019, and final approval was issued in March 2019.

In March 2019, PacifiCorp filed its annual EBA with the UPSC seeking approval to recover $24 million, or 1.1%, in deferred net power costs from customers for the period January 1, 2018 through December 31, 2018, reflecting the difference between base and actual net power costs in the 2018 deferral period. The rate change was approved by the UPSC effective May 1, 2019 on an interim basis. Following a decision from the Utah Supreme Court in June 2019 that found the UPSC did not have authority to approve interim rates in conjunction with the EBA, the UPSC directed PacifiCorp to terminate the interim rate change pending final approval in the proceeding. The hearing on final approval was held in February 2020, and a final decision from the UPSC is pending.

The EBA was originally implemented as a pilot program that was designed to terminate at the end of 2019. In November 2019, the UPSC issued an order that determined continuing the EBA is in the public interest, making the EBA a permanent cost recovery mechanism.


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In May 2019, Utah House Bill 411 went into effect. The legislation, among other things, authorizes the UPSC to approve a renewable energy program for communities seeking 100% renewable electricity. Participating cities were required to adopt a resolution with a goal to be on 100% renewable electricity by 2030 before December 31, 2019. Customers within a participating community may opt out of the program and maintain existing rates. Rates approved for the program may not result in any shift of costs or benefits to nonparticipating customers. Several communities in Utah, including Salt Lake City, have either recently set renewable goals or are actively considering them.

Oregon

In December 2018, PacifiCorp proposed to reduce customer rates to reflect the lower annual current income tax expense in Oregon resulting from 2017 Tax Reform. PacifiCorp reached an all-party settlement on the amortization of the current income tax expense benefits and the deferral of the decision regarding the ratemaking treatment of excess deferred income tax balances until no later than PacifiCorp's next general rate proceeding. The settlement, which resulted in a rate reduction of $48 million, or 3.7%, effective February 1, 2019, was approved by the OPUC in January 2019.

In December 2018, PacifiCorp filed a 2019 RAC application requesting recovery of $37 million, or a 2.8% increase in rates, associated with repowering of approximately 900 MWs of company-owned and installed wind facilities expected to be completed in 2019. In March 2019, the application was updated to request recovery of $32 million, or a 2.5% increase in rates. In August 2019, PacifiCorp filed an all-party settlement for the 2019 RAC that was approved by the OPUC in September 2019, providing for a total rate increase of $24 million, or 1.8%, subject to final cost updates. The settlement agreement provides for rates to be increased as the repowering projects are completed. Based on the in-service dates and final cost updates, the first rate increase of $9 million or 0.7% was effective October 1, 2019, for four repowered facilities, the second rate increase of $1 million, or 0.1%, was effective December 1, 2019, for one repowered facility and the third rate increase of $5 million or 0.4%, was effective January 1, 2020, for two repowered facilities. A final rate increase under the settlement agreement is expected to be effective March 1, 2020 for the final two remaining repowered facilities that are expected to be placed in service by the end of February 2020.

As part of the commission-approved RAC settlement, parties agreed that the Oregon-allocated net book value of certain undepreciated equipment replaced as a result of those repowerings captured in the 2019 RAC will be depreciated and offset with excess deferred income taxes resulting from 2017 Tax Reform. In 2019, accelerated depreciation of $120 million and offsetting amortization of excess deferred income taxes was recognized based on repowering activities completed through December 31, 2019.

In April 2019, PacifiCorp submitted its annual TAM filing in Oregon requesting a decrease of $15 million, or an average rate decrease of 1.2%, based on forecast net power costs and loads for calendar year 2020. The filing includes the customer benefits of repowering, including an increase in PTC. In September 2019, PacifiCorp filed an all-party settlement for the 2020 TAM. The settlement provides for a rate decrease of $20 million from the 2019 TAM, or an average rate decrease of 1.6%, effective January 1, 2020. In October 2019, the OPUC approved the all-party settlement.

In May 2019, PacifiCorp filed an application for deferral of incremental costs associated with implementing wildfire mitigation measures in Oregon. Operations and maintenance costs associated with the implementation measures are estimated to be $5 million in 2019.

In November 2019, PacifiCorp filed a 2020 RAC application requesting an annual increase in rates of $1 million, or 0.1%, associated with repowering the Glenrock III wind facility effective April 1, 2020 and an annual increase in rates of $3 million, or 0.3%, associated with repowering the Dunlap wind facility effective October 15, 2020. As part of its application, PacifiCorp proposed to offset the Oregon-allocated net book value of the replaced undepreciated wind equipment in this filing with revenues related to PacifiCorp's OATT deferral from 2017 through 2019. An all-party settlement was filed in January 2020 supporting the filed request, and a final decision from the OPUC is pending.

In November 2019 PacifiCorp requested authorization to establish an automatic adjustment clause and rate schedule for the costs and revenues related to the Oregon Corporate Activity Tax ("OCAT") that applies to tax years beginning on or after January 1, 2020. Concurrent with this filing, PacifiCorp also requested authorization to defer the OCAT tax expense. In January, 2020, the OPUC authorized the automatic adjustment clause, rate schedule and application for deferral. PacifiCorp is authorized to begin recovering the estimated OCAT expense effective February 1, 2020. The recovery adjustment for 2020 is 0.41%. The rate will be applied as a percentage surcharge on customers' bills.


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In February 2020, PacifiCorp filed a general rate case in Oregon requesting an increase in base rates of $78 million, or 6.0%, effective January 1, 2021, a separate tariff rider to recover costs associated with the early retirement of Cholla Unit 4 for an increase of $17 million annually from January 2021 through April 2025 and an annual credit to customers of $25 million for amortization of remaining deferred income tax benefits associated with 2017 Tax Reform over a three-year period beginning January 2021. The request for the increase in base rates reflects recovery of Energy Vision 2020 investments, updated depreciation rates and rate design modernization proposals. 

In February 2020, PacifiCorp submitted its annual TAM filing in Oregon requesting a decrease of $49 million, or 3.7%, effective January 1, 2021, based on forecast net power costs and loads for the calendar year 2021. The filing includes the customer benefits of repowering, including an increase in PTCs.

Wyoming

In April 2018, PacifiCorp filed a partial settlement related to the impact of 2017 Tax Reform with the WPSC that provided a rate reduction of $23 million, or 3.3%, effective July 1, 2018 through June 30, 2019, with the remaining tax savings to be deferred with offsets to other costs. In June 2018, PacifiCorp filed reports with the WPSC with the calculation of the full impact of the tax law change on revenue requirement of $28 million annually, comprised of $20 million in current tax savings and $8 million for the amortization of excess deferred income tax balances. In March 2019, the WPSC issued a written order approving the continued annual rate reduction of $23 million until base rates are reset in the next general rate proceeding and a $4 million offset to PacifiCorp's 2018 ECAM rates. The order reflected $20 million of current tax savings and was updated to reflect a projection of $7 million for amortization of excess deferred income tax balances. In April 2019, PacifiCorp filed a new application updating the amount of benefits being returned to customers. PacifiCorp continued the interim rate reduction that includes the previously approved $23 million and an additional $4 million reduction to offset the 2019 ECAM, effective June 15, 2019. A settlement agreement was filed in November 2019 in which the parties agreed to an additional rate reduction of $9 million effective December 1, 2019 through the end of calendar year 2020. The WPSC approved the settlement agreement at its hearing held in November 2019.

In April 2019, PacifiCorp submitted a compliance filing to the WPSC regarding bonus tax depreciation resulting in a $2 million rate reduction for the period June 15, 2019 through June 14, 2020.

In February 2019, PacifiCorp filed a certificate of public convenience and necessity application with the WPSC requesting to repower the existing Foote Creek I wind facility, which was approved without conditions in April 2019. In connection with the repowering of Foote Creek, PacifiCorp acquired the joint owner's 21% interest in the facility in June 2019.

In April 2019, PacifiCorp filed its annual ECAM and RRA application with the WPSC. The filing requests approval to recover from customers $7 million, or approximately 1.0%, in deferred net power costs for the period January 1, 2018 through December 31, 2018. The rate change went into effect on an interim basis June 15, 2019. In August, a joint notice of no contest was filed with the WPSC on behalf of PacifiCorp and the Wyoming Industrial Energy Consumers, the only intervenor in the proceeding. Interim rates were approved by the WPSC as final in November 2019. PacifiCorp offset this increase with other rate credits that went into effect on June 15, 2019.

In July 2019, Wyoming Senate Enrolled Act No. 74 went into effect. The legislation, among other things, requires electric utilities to make a good faith effort to sell a coal-fired generation facility in Wyoming before it can receive recovery in rates for capital costs associated with new generation facilities built, in whole or in part, to replace the retiring coal-fueled generation facility. The electric utility is obligated to purchase the electricity from the facility through a power purchase agreement at a price that is no greater than the utility's avoided cost as determined by the WPSC. Costs associated with an approved power purchase agreement are expected to be recoverable in rates from Wyoming customers. PacifiCorp is working with the WPSC and other stakeholders on rules to implement the legislation. The overall impacts of this legislation cannot be determined at this time.

Washington

In June 2019, PacifiCorp submitted its 2018 PCAM filing with the WUTC seeking approval to credit $7 million to the PCAM balancing account. No rate changes were requested.

In November 2019, PacifiCorp submitted its 2019 decoupling filing with the WUTC for the twelve months ended June 30, 2019. In January 2020, the WUTC approved PacifiCorp's 2019 decoupling filing, which resulted in a $12 million surcredit to customers effective February 1, 2020.


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In December 2019, PacifiCorp submitted its 2021 Washington general rate case requesting an overall decrease to rates of approximately $4 million, or 1.1%, effective January 1, 2021. The case includes an increase in revenue requirement of $3 million, offset by a proposed ten-year annual surcredit of $7 million, including interest, to customers primarily associated with the amortization of excess deferred income taxes from 2017 Tax Reform. The case includes a request for approval of a new cost allocation methodology, updated depreciation rates, recovery of Energy Vision 2020 investments, and rate design modernization proposals.

Idaho

In May 2018, the IPUC approved a rate reduction of $6 million, or 2.2%, effective June 1, 2018 through May 31, 2019, to pass back a portion of the current tax benefits associated with 2017 Tax Reform. In March 2019, an all-party settlement resolving the treatment of the remaining tax savings was filed with the IPUC. In May 2019, the IPUC approved the all-party settlement resulting in the rate reduction for current tax savings being adjusted to $8 million per year, effective June 1, 2019, and $3 million related to amortization of excess deferred income taxes from 2017 Tax Reform being applied as an offset to the 2019 ECAM.

In March 2019, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $15 million, or 0.4%, for deferred costs in 2018. This filing includes recovery of the difference in actual net power costs to the base level in rates, an adder for recovery of the Lake Side 2 resource, recovery of Deer Creek Mine investment and changes in PTCs and RECs. In May 2019, the IPUC approved recovery of the $15 million, effective June 1, 2019, to be offset by the $3 million related to amortization of excess deferred income taxes stemming from the all-party settlement related to 2017 Tax Reform.

California

In April 2018, PacifiCorp filed a general rate case with the CPUC for an overall rate increase of $1 million, or 0.9%, effective January 1, 2019. A CPUC decision was issued in February 2020, resulting in an approximate $6 million, or 6%, rate decrease effective February 6, 2020.

On September 21, 2018, California's governor signed legislation to strengthen California's ability to prevent and recover from catastrophic wildfires, including California Senate Bill 901 ("SB 901"). SB 901 requires electric utilities to prepare and submit wildfire mitigation plans that describe the utilities' plans to prevent, combat and respond to wildfires affecting their service territories. PacifiCorp filed its wildfire mitigation plan with the CPUC on February 6, 2019. The wildfire mitigation plan incorporates the requirements outlined in SB 901, including situational awareness, system hardening, vegetation management and procedures for proactive de-energization in certain high risk areas during times of extreme danger.

SB 901 also authorized utilities, including PacifiCorp, to establish two memorandum accounts to track costs related to California Wildfire Mitigation. In March 2019, PacifiCorp received approval to establish a Fire Risk Mitigation Memorandum Account ("FRMMA"), effective January 1, 2019, to track a range of fire risk mitigation activities incremental to what is already included in PacifiCorp's rates. The CPUC also granted PacifiCorp the ability to track costs related to complying with the implementation of proactive safety power shut-off, or de-energization events, in the FRMMA.

In May 2019, the CPUC issued a decision approving PacifiCorp's 2019 Wildfire Mitigation Plan. In June 2019, following approval of its 2019 Wildfire Mitigation Plan, PacifiCorp filed to establish a second Wildfire Mitigation Plan Memorandum Account ("WMPMA") to track costs related to the implementation of its approved 2019 Plan. The WMPMA was approved effective June 4, 2019. Cost recovery is contingent on the CPUC's review of activities tracked in the memorandum accounts. In January 2020, the CPUC approved the resolution establishing procedural rules for the review and disposition of 2020 Wildfire Mitigation Plans. PacifiCorp submitted its 2020 Wildfire Mitigation Plan in February 2020.

SB 901 also required the CPUC to develop a financial stress test methodology to determine the maximum amount an electrical corporation's shareholders can pay for 2017 catastrophic wildfire damages without harming ratepayers or impacting the utility's ability to provide adequate and safe service. The CPUC's final decision in June 2019 regarding this test does not have an impact on PacifiCorp as its assets did not cause catastrophic wildfires in California in 2017.

In July 2019, California's governor signed California Assembly Bill ("AB 1054") into law. AB 1054 is comprehensive legislation addressing wildfire risk in the state of California. The new law authorizes a wildfire fund which would operate as an insurance fund to support the creditworthiness of electrical utilities, if certain utilities participate by making the required contributions, among other things. In August, PacifiCorp notified the CPUC that it will not participate in the wildfire fund.


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AB 1054 also amends CPUC requirements for recovery of wildfire-related costs regardless of participation in the insurance fund. The CPUC must allow cost recovery of the costs and expenses of a "covered wildfire" which is defined as a fire ignited on or after July 12, 2019, if they are determined to be just and reasonable, meaning the electrical corporation's conduct related to the ignition was consistent with actions that a reasonable utility would have undertaken in good faith under similar circumstances, and based on the information available to the electrical corporation at the relevant point in time.

In December 2019, PacifiCorp filed an application notifying the CPUC of the early retirement of the Cholla Unit 4 generating facility and requesting authorization to establish a memorandum account associated with the retirement and decommissioning of Cholla Unit 4. The proposed memorandum account would track costs associated with the unrecovered plant balance, decommissioning and other closure-related costs. PacifiCorp requested an effective date of December 27, 2019 for the proposed memorandum account.

NV Energy (Nevada Power and Sierra Pacific)

Regulatory Rate Reviews

In June 2019, Sierra Pacific filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue increase of $5 million but requested an annual revenue reduction of $5 million. In September 2019, Sierra Pacific filed an all-party settlement for the electric regulatory rate review. The settlement resolves all cost of capital and revenue requirement issues and provides for an annual revenue reduction of $5 million and requires Sierra Pacific to share 50% of regulatory earnings above 9.7% with its customers. The rate design portion of the regulatory rate review was not a part of the settlement and a hearing on rate design was held in November 2019. In December 2019, the PUCN issued an order approving the stipulation but made some adjustments to the methodology for the weather normalization component of historical sales in rates, which resulted in an additional annual revenue reduction of $3 million. The new rates were effective January 1, 2020. In January 2020, Sierra Pacific filed a petition for rehearing challenging the PUCN's adjustments to the weather normalization methodology. In February 2020, the PUCN issued an order granting the petition for rehearing.

In August 2019, as a part of the annual DEAA filing, the PUCN issued an order confirming the methodology of calculating the earnings sharing and directed Nevada Power, in its next regulatory rate review in June 2020, to address the return of the earnings sharing to customers.

2017 Tax Reform

In February 2018, the Nevada Utilities made filings with the PUCN proposing a tax rate reduction rider for the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. In March 2018, the PUCN issued an order approving the rate reduction proposed by the Nevada Utilities. The new rates were effective April 1, 2018. The order extended the procedural schedule to allow parties additional discovery relevant to 2017 Tax Reform and a hearing was held in July 2018. In September 2018, the PUCN issued an order directing the Nevada Utilities to record the amortization of any excess protected accumulated deferred income tax arising from the 2017 Tax Reform as a regulatory liability effective January 1, 2018. Subsequently, the Nevada Utilities filed a petition for reconsideration relating to the amortization of protected excess accumulated deferred income tax balances resulting from the 2017 Tax Reform. In November 2018, the PUCN issued an order granting reconsideration and reaffirming the September 2018 order. In December 2018, the Nevada Utilities filed a petition for judicial review. In January 2019, intervening parties filed statements of intent to participate in the petition for judicial review. The Nevada Utilities have filed opening briefs and the intervening parties have filed answering briefs. The hearing occurred in January 2020 and a ruling is expected in the first half of 2020.
 
In November 2019, FERC issued an order requiring public utilities with transmission formula rates under an OATT to include a mechanism in those transmission formula rates to deduct any excess accumulated deferred income taxes (“ADIT”) from, or add any deficient ADIT, to their rate base. Public utilities with transmission formula rates are also required to incorporate a mechanism to decrease or increase their income tax allowances by any amortized excess or deficient ADIT and to incorporate a new permanent worksheet into their transmission formula rates that will annually track information related to excess or deficient ADIT. Although the Nevada Utilities have a stated rate rather than a formula rate, they will need to demonstrate their compliance with these changes within their next FERC transmission rate proceeding.


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EEPR and EEIR

In March 2019, the Nevada Utilities each filed an application to reset the EEIR and EEPR and to refund the EEIR revenue received in 2018, including carrying charges. In August 2019, the PUCN issued an order accepting a stipulation requiring the Nevada Utilities to refund the 2018 revenue and reset the rates as filed effective October 1, 2019. The current EEIR liability for Nevada Power and Sierra Pacific is $8 million and $2 million, respectively, as of December 31, 2019.

Price Stability Tariff (formerly the Optional Pricing Program)

In November 2018, the Nevada Utilities made filings with the PUCN to implement the Optional Pricing Program ("OPP"). The Nevada Utilities have designed the OPP to provide certain customers, namely those eligible to file an application pursuant to Chapter 704B of the Nevada Revised Statutes, with a market-based pricing option for renewable resources. The OPP provides for an energy rate that would replace the BTER and deferred energy accounting adjustment. The goal is to have an energy rate that yields an all-in effective rate that is competitive with market options available to such customers. In February 2019, the PUCN granted several intervenors the ability to participate in the proceeding. In June 2019, the Nevada Utilities withdrew their filings but currently plans to refile a modified tariff named the Price Stability Tariff in 2020 that responds to issues raised by intervenors.

Market Price Energy Program

In October 2019, the Nevada Utilities filed an application with the PUCN for approval of Market Price Energy Program ("MPE Program"). The MPE Program allows eligible customers to receive bundled electric service which reflects the market price of energy using energy resources that will not subject the customer to a potential impact fee, should the customer subsequently exercise its rights under Chapter 704B and elect an alternative energy supplier. In October 2019, the PUCN granted several intervenors the ability to participate in the proceeding. In January 2020, the Nevada Utilities filed a settlement stipulation, which was approved by the PUCN on January 29, 2020.

Chapter 704B Applications

Chapter 704B of the Nevada Revised Statutes allows retail electric customers with an average annual load of one MW or more to file with the PUCN an application to purchase energy from alternative providers of a new electric resource and become distribution only service customers. On a case-by-case basis, the PUCN will assess the application and may deny or grant the application subject to conditions, including paying an impact fee, paying on-going charges and receiving approval for specific alternative energy providers and terms. The impact fee and on-going charges are assessed to alleviate the burden on other Nevada customers for the applicant's share of previously committed investments and long-term renewable contracts and are set at a level designed such that the remaining customers are not subjected to increased costs. In June 2019, the Nevada Legislature passed Senate Bill 547 ("SB 547") which modifies the 704B process. The modifications outlined in SB 547, among others, require a utility to establish limits in their integrated resource plan on the amount of load that can take service under Chapter 704B, requires customers taking service under Chapter 704B continue to pay for public program costs and requires the alternative energy providers to be licensed by the PUCN. In addition, SB 547 requires customers to file a 704B application with the PUCN in January allowing for alignment with the capacity amount established in the integrated resource plan.

As of December 31, 2019, there were two PUCN-approved applications for two fully bundled retail customers whose total estimated peak demand is approximately 10 MWs, as of the date their applications were filed with the PUCN. One of these customers transitioned to distribution only service effective January 1, 2020, and the other customer has extended its transition to on or before September 1, 2020. As of December 31, 2019, there were no applications pending before the PUCN for approval.        

Northern Powergrid Distribution Companies

GEMA, through the Ofgem, published its RIIO-2 sector methodology decision in May 2019, continuing the process of developing the next set of price control arrangements that will be implemented for transmission and gas distribution networks in Great Britain. Ofgem explicitly stated that this decision did not apply for Northern Powergrid's next price control, ("ED2"), which will begin in April 2023. However, it also stated that some of the proposals may be capable of application to that price control and, in December 2019, published a decision on the framework for ED2 that confirmed the same overall approach will apply.

Regarding allowed return on capital, Ofgem has stated that it currently considers that a cost of equity of 4.3% (plus inflation calculated using the United Kingdom's consumer prices index including owner occupiers' housing costs) would be appropriate for energy networks, which is approximately 220 basis points lower than the current comparable cost of equity. This cost of equity assumption is based on a proposed debt capitalization assumption for the next price control of 60%, which is lower than the 65% debt capitalization assumption for the current price control.

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In respect of ED1, in October 2019 GEMA published a decision to make allowance for certain additional costs totaling £12 million, plus RPI inflation from 2012-2013, that it judged to be beyond the control of the licensees, beyond the routine adjustments for such costs that occur annually. The adjustments, which reflect additional costs, for the licensees will flow into allowed revenues through the standard price control mechanisms and do not affect Northern Powergrid's overall financial position compared to when the current price control was set.

BHE Pipeline Group

Northern Natural Gas

In July 2018, FERC issued a final rule adopting procedures for determining whether natural gas pipelines were collecting unjust and unreasonable rates in light of the reduction in the federal corporate tax rate from 2017 Tax Reform. Pursuant to the final rule, in October 2018, Northern Natural Gas filed an informational filing on FERC Form No. 501-G and a Statement Demonstrating Why No Rate Adjustment is Necessary. In January 2019, FERC initiated a Section 5 investigation to determine whether the rates currently charged by Northern Natural Gas are just and reasonable. As required by the FERC Section 5 order, Northern Natural Gas filed a cost and revenue study in April 2019. In July 2019, Northern Natural Gas filed a Section 4 rate case requesting increases in its transportation and storage rates. In September 2019, FERC consolidated the Section 5 investigation and the Section 4 rate case into one procedural process set for hearing commencing June 2020. In January 2020, the FERC approved Northern Natural Gas' filing to implement its interim rates, including an increase of 77% from its current Market Area transmission reservation rate, subject to refund, effective January 1, 2020.
Kern River

In October 2018, Kern River filed an informational filing on FERC Form No. 501-G and a Statement Explaining Why No Rate Adjustment is Necessary, along with a Tax Reform Credit Rate Settlement in a companion docket. Kern River's Tax Reform Credit Rate Settlement offered an 11% rate credit against the Maximum Base Tariff Rates for firm service and any one-part rate that includes fixed costs which would result in an expected annual rate credit of $13 million. In November 2018, FERC approved Kern River's Tax Reform Credit effective November 15, 2018.

BHE Transmission

AltaLink

General Tariff Application

In August 2018, AltaLink filed its 2019-2021 GTA with the AUC, delivering on the first three years of its commitment to keep rates lower or flat at the approved 2018 revenue requirement of C$904 million for customers for the next five years. In addition, AltaLink proposes to provide a further tariff reduction over the three years by refunding previously collected accumulated depreciation surplus of an additional C$31 million. In November 2018, the AUC approved the 2019 interim refundable transmission tariff at C$74 million per month effective January 2019. In April 2019, AltaLink filed an update to its 2019-2021 GTA application primarily to reflect its 2018 actual results and the impact of the AUC’s decision on AltaLink's 2014-2015 Deferral Account Reconciliation Application. The application requests the approval of revised revenue requirements of C$879 million, C$882 million and C$885 million for 2019, 2020 and 2021, respectively. The forecast revenue requirement is based on an 8.5% return on equity and 37% deemed equity as approved by the AUC for 2019 and 2020.

In July 2019, AltaLink filed a 2019-2021 partial negotiated settlement application with the AUC. The application consisted of negotiated reductions totaling a C$38 million net decrease to the three-year total revenue requirement applied for in AltaLink's 2019-2021 GTA updated in April 2019. However, this may be partially offset by AltaLink's request for an additional C$20 million of forecast transmission line clearance capital as part of an excluded matter. The 2019-2021 negotiated settlement agreement excluded certain matters related to the new salvage study and salvage recovery approach, additional capital spending and incremental asset retirements. AltaLink's salvage proposal is estimated to save customers C$267 million between 2019 and 2023. Excluded matters were examined by the AUC in a hearing held in November 2019. If AltaLink is successful at hearing on the excluded matters and the negotiated settlement is approved, the revised revenue requirements will be C$873 million for 2019 and C$870 million for each of 2020 and 2021. In August 2019, AltaLink responded to information requests with respect to its 2019-2021 negotiated settlement application and the excluded matters as described above. In November 2019, a hearing to examine the excluded matters was completed with a briefing filed in January 2020. A decision from the AUC is expected in the second quarter of 2020.


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2018 Generic Cost of Capital Proceeding

In July 2017, the AUC denied the utilities' request in the 2018 Generic Cost of Capital ("GCOC") proceeding that the interim determinations of 8.5% return on equity and deemed capital structures for 2018 be made final, by stating that it is not prepared to finalize 2018 values in the absence of an evidentiary process. In August 2018, the AUC issued its decision on the 2018 GCOC proceeding to set the deemed capital structure and generic return on equity for 2018, 2019 and 2020. In its decision, the AUC set the return on equity at 8.5% for 2018, 2019 and 2020, and AltaLink's common equity ratio at 37% for 2018, 2019 and 2020.

2021 Generic Cost of Capital Proceeding

In December 2018, the AUC initiated the 2021 GCOC proceeding to consider returning to a formula-based approach in determining the return on equity for a given year, starting with 2021. In April 2019, after receiving comments from interested parties, the AUC expanded the scope of the proceeding to include a traditional non-formulaic GCOC inquiry as well as the consideration of returning to a formula-based approach. The AUC also issued a process timeline for the proceeding to commence in January 2020, with a hearing scheduled in April 2020.

In January 2020, AltaLink filed company and expert evidence, recommending a range of 8.75% to 10.5% return on equity, on a recommended equity ratio of 40% for 2021 and 2022. The Consumers' Coalition of Alberta, the Utilities Consumer Advocate and the City of Calgary filed intervenor evidence recommending a range of 5.0% to 6.9% return on equity, and an AltaLink common equity ratio of 35% to 37% for 2021 and 2022.

2014-2015 Deferral Account Reconciliation Application

In April 2017, AltaLink filed its application with the AUC with respect to its 2014 projects and deferral accounts and specific 2015 projects. The application included approximately C$2.0 billion in net capital additions. In December 2017, AltaLink amended its application to include the remaining capital projects completed in 2015. The amended 2014 and 2015 Deferral Account Reconciliation Application includes 110 completed projects with total gross capital additions, including AFUDC, of C$4,017 million. A hearing was held in September 2018 after the completion of an extensive information request process earlier in the year.

In December 2018 and January 2019, the AUC issued decisions approving C$3,833 million out of the C$4,017 million capital project additions, included in the application. Project costs of C$155 million were deferred to a future hearing. The AUC disallowed capital additions of approximately C$29 million including applicable AFUDC, pending receipt of additional supporting documentation for certain items. In February 2019, AltaLink filed its 2014-2015 Deferral Account Reconciliation Application compliance filing to reflect the findings, conclusions and directions arising from these decisions. In addition, the AUC ruled that it will put in placeholder amounts for the approved costs of the assets in the 2014-2015 Deferral Account Reconciliation Application proceeding until the AUC-initiated proceeding to consider the issue of transmission asset utilization. In August 2019, the AUC issued its decision with respect to AltaLink's 2014-2015 Deferral Account Reconciliation Application compliance filing. The AUC ruled that AltaLink has complied with all significant directives from the December 2018 and January 2019 decisions In September 2019, AltaLink filed a second compliance filing reflecting the directives from the AUC's August 2019 decision and final AUC approval was received in November 2019.

2016-2018 Deferral Account Reconciliation Application

In July 2019, AltaLink filed its 2016-2018 Deferral Account Reconciliation Application with the AUC. The application includes 116 projects with total gross capital additions, including AFUDC, of C$976 million. In December 2019, the AUC announced a series of technical meetings to address AltaLink's responses to certain information requests. The balance of the process steps and related schedule will be established following the AUC's ruling on the disputed information requests, which is expected by March 2020.

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Alberta Electric System Operator Tariff Decision

In September 2019, the AUC issued its decision with respect to the 2018 AESO tariff. As part of this decision, the AUC approved AltaLink's proposal to refund contributions made by distribution facility owners relative to transmission projects built and owned by transmission facility owners. The proposal will benefit distribution customers by flowing through the lower cost of capital of the transmission facility owner rather than the higher cost of capital of the distribution facility owner. As directed by the AUC, AltaLink would pay FortisAlberta the unamortized contribution balance of approximately C$375 million and add the amount to AltaLink's rate base if the decision is upheld. The AUC directed the AESO to consult with AltaLink to provide a joint proposal to implement AltaLink's contribution proposal. In September 2019, FortisAlberta filed a review and variance application with the AUC requesting the AUC re-evaluate its findings with respect to AltaLink's customer contribution proposal relative to distribution facility owners. In October 2019, the AUC granted FortisAlberta's request to proceed to a review and variance with the record closed in November 2019, after submissions from FortisAlberta, AltaLink, and other interested parties. FortisAlberta also filed for permission to appeal the decision with the Court of Appeal, which will not be heard until after the AUC’s review proceeding.

In December 2019, the AUC reopened the record of the review and variance proceeding and, in January 2020, issued specific information requests to each of FortisAlberta and AltaLink to clarify the evidence previously filed. AltaLink and FortisAlberta filed responses to the AUC information requests in January 2020. In February 2020, FortisAlberta filed a motion with the AUC requesting the appointment of a review panel to convene an oral hearing.

First Nations Asset Transfer Application

In November 2018, the AUC approved, with conditions, AltaLink's application filed in April 2017 to sell and transfer approximately C$100 million of transmission assets located on reserve lands to new limited partnerships with First Nations. The transfers are part of the agreement which allowed AltaLink to route the Southwest Project on reserve land. In June 2019, AltaLink closed the transaction with the Piikani Nation by transferring transmission assets of C$53 million to PiikaniLink, L.P. In January 2020, AltaLink closed the transaction with the Blood Tribe by transferring transmission assets of C$35 million to KainaiLink, L.P.

BHE U.S. Transmission

A significant portion of ETT's revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base regulatory rate review scheduled for no later than February 1, 2021. In January 2017, the PUCT approved ETT's request to suspend a base regulatory rate review filing scheduled for February 2017. Results of a base regulatory rate review would be prospective except for any deemed disallowance by the PUCT of the transmission investment since the initial base regulatory rate review in 2007. In June 2018, the PUCT approved ETT's application to reduce its transmission revenue by $28 million to reflect the lower federal income tax rate due to 2017 Tax Reform with the amortization of excess accumulated deferred federal income taxes expected to be addressed in the next base rate case.

ENVIRONMENTAL LAWS AND REGULATIONS

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. The Company has cumulative investments in wind, solar, geothermal and biomass generating facilities of approximately $29 billion and plans to spend an additional $6 billion on the construction of wind-powered generating facilities, repowering certain existing wind-powered generating facilities and funding of wind tax equity investments through 2021. Refer to "Liquidity and Capital Resources" of each respective Registrant in Item 7 of this Form 10-K for discussion of each Registrant's renewable generation-related capital expenditures.


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Climate Change

In December 2015, an international agreement was negotiated by 195 nations to create a universal framework for coordinated action on climate change in what is referred to as the Paris Agreement. The Paris Agreement reaffirms the goal of limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius; establishes commitments by all parties to make nationally determined contributions and pursue domestic measures aimed at achieving the commitments; commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the United States agreed to reduce greenhouse gas emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global greenhouse gas emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. On June 1, 2017, President Trump announced the United States would begin the process of withdrawing from the Paris Agreement. Under the terms of the Paris Agreement, withdrawal cannot occur until four years after its effective date, making the United States' withdrawal effective in November 2020.

GHG Performance Standards

Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilities with the "Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") and oral argument was scheduled for April 17, 2017. However, oral argument was deferred and the court held the case in abeyance for an indefinite period of time. On December 6, 2018, the EPA announced revisions to new source performance standards for new and reconstructed coal-fueled units. EPA proposes to revise carbon dioxide emission limits for new coal-fueled facilities to 1,900 pounds per MWh for small units and 2,000 pounds per MWh for large units. The EPA would define the best system of emission reduction for new and modified units as the most efficient demonstrated steam cycle, combined with best operating practices. The EPA accepted comments on the proposal through March 18, 2019. Until such time as the EPA undertakes further action on the proposed reconsideration or the court takes action, any new fossil-fueled generating facilities constructed by the relevant Registrants will be required to meet the GHG new source performance standards.
    
Affordable Clean Energy Rule

In June 2014, the EPA released proposed regulations to address GHG emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on the "Best System of Emission Reduction." In August 2015, the final Clean Power Plan was released, which established the Best System of Emission Reduction as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The Clean Power Plan was stayed by the United States Supreme Court in February 2016 while litigation proceeded. On October 10, 2017, the EPA issued a proposal to repeal the Clean Power Plan, which was intended to achieve an overall reduction in carbon dioxide emissions from existing fossil-fueled electric generating units of 32% below 2005 levels. On June 19, 2019, the EPA repealed the Clean Power Plan and issued the Affordable Clean Energy rule, which fully replaced the Clean Power Plan. In the Affordable Clean Energy rule, the EPA determined that the best system of emissions reduction for existing coal-fueled power plants is heat rate improvements and identified a set of candidate technologies and measures that could improve heat rates. Measures taken to meet the standards of performance must be achieved at the source itself. States have until July 2022 to submit compliance plans to the EPA. The Affordable Clean Energy rule is not expected to have a material impact on the Registrants. PacifiCorp, MidAmerican Energy, Nevada Power and Sierra Pacific have historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of their generating fleets to include deployment of renewable and lower carbon generating resources, and advanced customer energy efficiency programs.

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Regional and State Activities

Several states have promulgated or otherwise participate in state-specific or regional laws or initiatives to report or mitigate GHG emissions. These are expected to impact the relevant Registrant, and include:

In June 2013, Nevada Senate Bill 123 ("SB 123") was signed into law. Among other things, SB 123 and regulations thereunder required Nevada Power to file with the PUCN an emission reduction and capacity replacement plan by May 1, 2014. In May 2014, Nevada Power filed its emissions reduction capacity replacement plan. The plan provided for the retirement or elimination of 300 MWs of coal-fueled generating capacity by December 31, 2014, another 250 MWs of coal-fueled generating capacity by December 31, 2017, and another 250 MWs of coal generating capacity by December 31, 2019, along with replacement of such capacity with a mixture of constructed, acquired or contracted renewable and non-technology specific generating units. The plan also sets forth the expected timeline and costs associated with decommissioning coal-fueled generating units that will be retired or eliminated pursuant to the plan. The PUCN has the authority to approve or modify the emission reduction and capacity replacement plan filed by Nevada Power. The PUCN may approve variations to Nevada Power's resource plans relative to requirements under SB 123. Refer to Nevada Power's Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information on the ERCR Plan.

Under the authority of California's Global Warming Solutions Act, which includes a series of policies aimed at returning California greenhouse gas emissions to 1990 levels by 2020, the California Air Resources Board adopted a GHG cap-and-trade program with an effective date of January 1, 2012; compliance obligations were imposed on entities beginning in 2013. PacifiCorp is subject to the cap-and-trade program as a retail service provider in California and an importer of wholesale energy into California. In 2015, Governor Jerry Brown issued an executive order to reduce emissions to 40% below 1990 levels by 2030 and 80% by 2050. In September 2016, California Senate Bill 32 was signed into law establishing greenhouse gas emissions reduction targets of 40% below 1990 levels by 2030.

The states of California, Washington and Oregon have adopted GHG emissions performance standards for base load electricity generating resources. Under the laws in California and Oregon, the emissions performance standards provide that emissions must not exceed 1,100 pounds of carbon dioxide per MWh. In September 2018, the Washington Department of Commerce amended the emissions performance standards to provide that GHG emissions for base load electricity generating resources must not exceed 925 pounds of carbon dioxide per MWh. These GHG emissions performance standards generally prohibit electric utilities from entering into long-term financial commitments (e.g., new ownership investments, upgrades, or new or renewed contracts with a term of five or more years) unless any base load generation supplied under long-term financial commitments comply with the GHG emissions performance standards.

In September 2016, the Washington State Department of Ecology issued a final rule regulating GHG emissions from sources in Washington. The rule regulates greenhouse gases including carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride beginning in 2017 with three-year compliance periods thereafter (i.e., 2017-2019, 2020-2022, etc.). Under the rule, the Washington State Department of Ecology established GHG emissions reduction pathways for all covered entities. Covered entities may use emission reduction units, which may be traded with other covered entities, to meet their compliance requirements. PacifiCorp's resources that are covered under the rule include the Chehalis generating facility, which is a natural gas combined-cycle plant located in Washington state. PacifiCorp received its baseline emission order on December 17, 2017, which specified the emission reduction requirements for the Chehalis generating facility every three years beginning in 2017. The reduction requirements average 1.7% per year. However, the Washington State Department of Ecology suspended the compliance obligations of the Clean Air Rule after a Thurston County Superior Court judge ruled the state lacks authority to mandate reductions from indirect emitters. On January 16, 2020, the Washington Supreme Court affirmed that the rule limits the applicability of emission standards to actual emitters and cannot be expanded to non-emitters. The court also found that the rule itself is severable, so that the Department of Ecology may continue to enforce the rule as it applies to emitters. The case was remanded for further proceedings. Pending further action by the lower court, the rule itself remains suspended, but entities subject to the rule are required to continue reporting emissions.


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The Regional Greenhouse Gas Initiative, a mandatory, market-based effort to reduce GHG emissions in ten Northeastern and Mid-Atlantic states, required, beginning in 2009, the reduction of carbon dioxide emissions from the power sector of 10% by 2018. In May 2011, New Jersey withdrew from participation in the Regional Greenhouse Gas Initiative. Following a program review in 2012, the nine Regional Greenhouse Gas Initiative states implemented a new 2014 cap which was approximately 45% lower than the 2012-2013 cap. The cap is reduced each year by 2.5% from 2015 to 2020. In December 2017, an updated model rule was released by the Regional Greenhouse Gas Initiative states which includes an additional 30% regional cap reduction between 2020 and 2030.

Renewable Portfolio Standards

Each state's RPS described below could significantly impact the relevant Registrant's consolidated financial results. Resources that meet the qualifying electricity requirements under each RPS vary from state to state. Each state's RPS requires some form of compliance reporting and the relevant Registrant can be subject to penalties in the event of noncompliance. Each Registrant believes it is in material compliance with all applicable RPS laws and regulations.

In 1983, Iowa became the first state in the United States to adopt a RPS requiring the state utilities to own or to contract for a combined total of 105 MWs of renewable generating capacity and associated energy production. The IUB allocated the 105-MW requirement between the two utilities in Iowa based on each utility's percentage of their combined estimated Iowa retail peak demand in 1990 resulting in MidAmerican Energy being allocated a RPS requirement of 55.2 MWs. The utility must meet its RPS obligation by either owning renewable energy production facilities located in Iowa or entering into long-term contracts to purchase or wheel electricity from renewable production facilities located in the utility's service area.

Since 1997, NV Energy has been required to comply with a RPS. Current law requires the Nevada Utilities to meet 18% of their energy requirements with renewable resources for 2014, 20% for 2015 through 2019, 22% for 2020 and 2024, and 25% for 2025 and thereafter. The RPS also requires 5% of the portfolio requirement come from solar resources through 2015 and increasing to 6% in 2016. Nevada law also permits energy efficiency measures to be used to satisfy a portion of the RPS through 2025, subject to certain limitations. In November 2018, Nevada voters approved a measure to increase the state's RPS to 50% by 2030; the measure must be voted on and approved a second time, in November 2020, in order to take effect.

Utah's Energy Resource and Carbon Emission Reduction Initiative provides that, beginning in the year 2025, 20% of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost effective. Retail electric sales will be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of energy efficiency and DSM programs. Qualifying renewable energy sources can be located anywhere within the WECC, and RECs can be used.

The Oregon Renewable Energy Act ("OREA") provides a comprehensive renewable energy policy and RPS for Oregon. Subject to certain exemptions and cost limitations established in the law, PacifiCorp and other qualifying electric utilities must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in 2015 through 2019, and 20% in 2020 through 2024. In March 2016, Oregon Senate Bill 1547-B ("SB 1547-B"), the Clean Electricity and Coal Transition Plan, was signed into law. SB 1547-B requires coal-fueled resources be eliminated from Oregon's allocation of electricity by January 1, 2030, and increases the current RPS target from 25% in 2025 to 50% by 2040. SB 1547-B also implements new REC banking provisions, as well as the following interim RPS targets: 27% in 2025 through 2029, 35% in 2030 through 2034, 45% in 2035 through 2039, and 50% by 2040 and subsequent years. As required by the OREA, the OPUC has approved an automatic adjustment clause to allow an electric utility, including PacifiCorp, to recover prudently incurred costs of its investments in renewable energy generating facilities and associated transmission costs.

Washington's Energy Independence Act establishes a renewable energy target for qualifying electric utilities, including PacifiCorp. The requirements are 3% of retail sales by January 1, 2012 through 2015, 9% of retail sales by January 1, 2016 through 2019 and 15% of retail sales by January 1, 2020 and each year thereafter. In April 2013, Washington State Senate Bill 5400 ("SB 5400") was signed into law. SB 5400 expands the geographic area in which eligible renewable resources may be located to beyond the Pacific Northwest, allowing renewable resources located in all states served by PacifiCorp to qualify. SB 5400 also provides PacifiCorp with additional flexibility and options to meet Washington's renewable mandates. In May 2019, the state of Washington enacted Senate Bill 5116, the Clean Energy Transformation Act. The legislation, among other things, requires Washington utilities to be carbon neutral by January 1, 2030 and institutes a planning target of 100% non-emitting generation by 2045. Electric utilities must also eliminate from rates coal-fired resources by December 31, 2025. PacifiCorp has begun discussions with regulators and other Washington investor-owned utilities regarding compliance obligations and implementation.


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The California RPS required all California retail sellers to procure an average of 20% of retail load from renewable resources by December 31, 2013, 25% by December 31, 2016 and 33% by December 31, 2020. In October 2015, California Senate Bill No. 350 became law and increased the RPS target to 50% by December 31, 2030. The state's RPS was further expanded in September 2018, when California Senate Bill 100 ("SB 100"), the 100 Percent Clean Energy Act of 2018 was signed into law. In addition to requiring retail sellers to meet a RPS target of 60% by 2030, SB 100 enabled a longer-term planning target for 100% of total California retail sales to come from eligible renewable energy resources and zero-carbon resources by December 31, 2045. In December 2011, the CPUC adopted a decision confirming that multi-jurisdictional utilities, such as PacifiCorp, are not subject to the percentage limits within the three product content categories of RPS-eligible resources established by the legislation that have been imposed on other California retail sellers.

Clean Air Act Regulations

The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in SIPs, which are a collection of regulations, programs and policies to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA. The major Clean Air Act programs most directly affecting the Registrants' operations are described below.

National Ambient Air Quality Standards

Under the authority of the Clean Air Act, the EPA sets minimum national ambient air quality standards for six principal pollutants, consisting of carbon monoxide, lead, nitrogen oxides, particulate matter, ozone and sulfur dioxide, considered harmful to public health and the environment. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area that are determined to contribute to the nonattainment are required to reduce emissions. Most air quality standards require measurement over a defined period of time to determine the average concentration of the pollutant present. Currently, with the exceptions described in the following paragraphs, air quality monitoring data indicates that all counties where the relevant Registrant's major emission sources are located are in attainment of the current national ambient air quality standards.

On June 4, 2018, EPA published final designations for much of the United States. Relevant to the Registrants, these designations include classifying Yuma County, Arizona; Clark County, Nevada; and the Northern Wasatch Front, Southern Wasatch Front and Duchesne and Uintah counties in Utah as nonattainment-marginal. These areas will be required to meet the 2015 standard three years from the August 3, 2018, effective date. All other areas relevant to the Registrants were designated attainment/unclassifiable with this same action.

In January 2010, the EPA finalized a one-hour air quality standard for nitrogen dioxide at 100 parts per billion. In February 2012, the EPA published final designations indicating that based on air quality monitoring data, all areas of the country are designated as "unclassifiable/attainment" for the 2010 nitrogen dioxide national ambient air quality standard. On April 6, 2018, EPA issued a decision to retain the 2010 nitrogen dioxide national ambient air quality standard without revision.

In June 2010, the EPA finalized a new national ambient air quality standard for sulfur dioxide. Under the 2010 rule, areas must meet a one-hour standard of 75 parts per billion utilizing a three-year average. The rule utilizes source modeling in addition to the installation of ambient monitors where sulfur dioxide emissions impact populated areas. Attainment designations were due by June 2012; however, citing a lack of sufficient information to make the designations, the EPA did not issue its final designations until July 2013 and determined, at that date, that a portion of Muscatine County, Iowa was in nonattainment for the one-hour sulfur dioxide standard. MidAmerican Energy's Louisa coal-fueled generating facility is located just outside of Muscatine County, south of the violating monitor. In its final designation, the EPA indicated that it was not yet prepared to conclude that the emissions from the Louisa coal-fueled generating facility contribute to the monitored violation or to other possible violations, and that in a subsequent round of designations, the EPA will make decisions for areas and sources outside Muscatine County. MidAmerican Energy does not believe a subsequent nonattainment designation will have a material impact on the Louisa coal-fueled generating facility. Although the EPA's July 2013 designations did not impact PacifiCorp's nor the Nevada Utilities' generating facilities, the EPA's assessment of sulfur dioxide area designations will continue with the deployment of additional sulfur dioxide monitoring networks across the country. On February 25, 2019, EPA issued a decision to retain the 2010 sulfur dioxide national ambient air quality standard without revision.


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The Sierra Club filed a lawsuit against the EPA in August 2013 with respect to the one-hour sulfur dioxide standards and its failure to make certain attainment designations in a timely manner. In March 2015, the United States District Court for the Northern District of California ("Northern District of California") accepted as an enforceable order an agreement between the EPA and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed the EPA to complete designations in three phases: the first phase by July 2, 2016; the second phase by December 31, 2017; and the final phase by December 31, 2020. The first phase of the designations require the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2010 sulfur dioxide standard; and 2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of sulfur dioxide in 2012 or emitted more than 2,600 tons of sulfur dioxide and had an emission rate of at least 0.45 lbs/sulfur dioxide per million British thermal unit in 2012 and, as of March 2, 2015, had not been announced for retirement. MidAmerican Energy's George Neal Unit 4 and the Ottumwa Generating Station (in which MidAmerican Energy has a majority ownership interest, but does not operate), are included as units subject to the first phase of the designations, having emitted more than 2,600 tons of sulfur dioxide and having an emission rate of at least 0.45 lbs/sulfur dioxide per million British thermal unit in 2012. States may submit to the EPA updated recommendations and supporting information for the EPA to consider in making its determinations. Iowa submitted documentation to the EPA in April 2016 supporting its recommendation that Des Moines, Wapello and Woodbury Counties be designated as being in attainment of the standard. In July 2016, the EPA's final designations were published in the Federal Register indicating portions of Muscatine County, Iowa were in nonattainment with the 2010 sulfur dioxide standard, Woodbury County, Iowa was unclassifiable, and Des Moines and Wapello Counties were unclassifiable/attainment.

In December 2012, the EPA finalized more stringent fine particulate matter national ambient air quality standards, reducing the annual standard from 15 micrograms per cubic meter to 12 micrograms per cubic meter and retaining the 24-hour standard at 35 micrograms per cubic meter. The EPA did not set a separate secondary visibility standard, choosing to rely on the existing secondary 24-hour standard to protect against visibility impairment. In December 2014, the EPA issued final area designations for the 2012 fine particulate matter standard. Based on these designations, the areas in which the relevant Registrant operates generating facilities have been classified as "unclassifiable/attainment." Unless additional monitoring suggests otherwise, the relevant Registrant does not anticipate that any impacts of the revised standard will be significant.

In December 2014, the Utah SIP for fine particulate matter was adopted by the Utah Air Quality Board. PacifiCorp's Lake Side, Lake Side 2, Gadsby Steam and Gadsby Peakers generating facilities operate within nonattainment areas for fine particulate matter; however, the SIP did not impose significant new requirements on PacifiCorp's impacted generating facilities, nor did the EPA's comments on the Utah SIP identify requirements for PacifiCorp's existing generating facilities that would have a material impact on its consolidated financial results.

Mercury and Air Toxics Standards

In March 2011, the EPA proposed a rule that requires coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards. The final MATS became effective on April 16, 2012, and required that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to comply with the new standards by April 16, 2015 with the potential for individual sources to obtain an extension of up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The relevant Registrants have completed emission reduction projects to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants.

MidAmerican Energy retired certain coal-fueled generating units as the least-cost alternative to comply with the MATS. Walter Scott, Jr. Energy Center Units 1 and 2 were retired in 2015, and George Neal Energy Center Units 1 and 2 were retired in April 2016. A fifth unit, Riverside Generating Station, was limited to natural gas combustion in March 2015.


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Numerous lawsuits have been filed in the D.C. Circuit challenging the MATS. In April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014, the United States Supreme Court agreed to hear the MATS appeal on the limited issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. Oral argument in the case was held before the United States Supreme Court in March 2015, and a decision was issued by the United States Supreme Court in June 2015, which reversed and remanded the MATS rule to the D.C. Circuit for further action. The United States Supreme Court held that the EPA had acted unreasonably when it deemed cost irrelevant to the decision to regulate generating facilities, and that cost, including costs of compliance, must be considered before deciding whether regulation is necessary and appropriate. The United States Supreme Court's decision did not vacate or stay implementation of the MATS rule. In December 2015, the D.C. Circuit issued an order remanding the rule to the EPA, without vacating the rule. As a result, the relevant Registrants continue to have a legal obligation under the MATS rule and the respective permits issued by the states in which each respective Registrant operates to comply with the MATS rule, including operating all emissions controls or otherwise complying with the MATS requirements.

On December 27, 2018, the EPA issued a proposed revised supplemental cost finding for the MATS, as well as the required risk and technology review under Clean Air Act Section 112. EPA proposes to determine that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112; however, EPA proposes to retain the emission standards and other requirements of the MATS rule, because EPA is not proposing to remove coal- and oil-fueled power plants from the list of sources regulated under Section 112. The public comment period on the proposal closes April 8, 2019. Until EPA takes final action on the rule, the relevant Registrants cannot fully determine the impacts of the proposed changes to the MATS rule.

Cross-State Air Pollution Rule

The EPA promulgated an initial rule in March 2005 to reduce emissions of nitrogen oxides and sulfur dioxide, precursors of ozone and particulate matter, from down-wind sources in the eastern United States, including Iowa, to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the Cross-State Air Pollution Rule ("CSAPR") was promulgated to address interstate transport of sulfur dioxide and nitrogen oxides emissions in 27 eastern and Midwestern states.

The first phase of the rule was implemented January 1, 2015. In November 2015, the EPA released a proposed rule that would further reduce nitrogen oxides emissions in 2017. The final “CSAPR Update Rule” was published in the Federal Register in October 2016 and required additional reductions in nitrogen oxides emissions beginning in May 2017. On December 6, 2018, EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. EPA determined that 2023 is an appropriate future analytic year to evaluate remaining good neighbor obligations and that there will be no remaining nonattainment or maintenance receptors with respect to the 2008 ozone NAAQS in the eastern United States in that year. Accordingly, the 20 CSAPR Update-affected states would not contribute significantly to nonattainment in, or interfere with maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the CSAPR Update and the CSAPR Close-Out rules were challenged in the D.C. Circuit Court. The D.C. Circuit ruled September 13, 2019, that because the EPA allowed upwind States to continue to significantly contribute to downwind air quality problems beyond statutory deadlines, the CSAPR Update Rule provided only a partial remedy that did not fully address interstate ozone transport, and remanded the CSAPR Update Rule back to the EPA. The D.C. Circuit Court issued an opinion October 1, 2019, finding that because the CSAPR Close-Out Rule relied on the same faulty reasoning as the CSAPR Update rule, the CSAPR Close-Out Rule must be vacated.

The CSAPR provisions are not anticipated to have a material impact on the Registrants. MidAmerican Energy operates natural gas-fueled generating facilities in Iowa and BHE Renewables operates natural gas-fueled generating facilities in Texas, Illinois and New York, which are subject to the CSAPR. MidAmerican Energy has installed emissions controls at its coal-fueled generating facilities to comply with the CSAPR and may purchase emissions allowances to meet a portion of its compliance obligations. The cost of these allowances is subject to market conditions at the time of purchase and historically has not been material. MidAmerican Energy believes that the controls installed to date are consistent with the reductions to be achieved from implementation of the rule. None of PacifiCorp's, Nevada Power's or Sierra Pacific's generating facilities are subject to the CSAPR. However, in a Notice of Data Availability published in the January 6, 2017, Federal Register, the EPA provided preliminary estimates of which upwind states may have linkages to downwind states experiencing ozone levels at or exceeding the 2015 ozone national ambient air quality standard of 70 parts per billion, and, using similar methodology to that in the CSAPR, indicated that Utah and Wyoming could have an obligation under the "good neighbor" provisions of the Clean Air Act to reduce nitrogen oxides emissions. Until such time as a rule is finalized, the relevant Registrants cannot determine whether additional action may be required.


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Regional Haze

The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and implement plans to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming, Arizona and Colorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit SIPs that address emissions from sources subject to best available retrofit technology ("BART") requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.

The state of Utah issued a regional haze SIP requiring the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the sulfur dioxide portion of the Utah regional haze SIP and disapproved the nitrogen oxides and particulate matter portions. Subsequently, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to nitrogen oxides controls and require the installation of selective catalytic reduction ("SCR") controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a federal implementation plan ("FIP") requiring the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions ("CAMX") dispersion model. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. On June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze state implementation plan revision, which incorporates a best available retrofit technology alternative into Utah's regional haze state implementation plan. The best available retrofit technology alternative makes the shutdown of PacifiCorp's carbon plant enforceable under the state implementation plan and removes the requirement to install selective catalytic reduction technology on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of Air Quality submitted the state implementation plan revision to the EPA for approval by the end of 2019.
 

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The state of Wyoming issued two regional haze SIPs requiring the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the sulfur dioxide SIP in December 2012 and the EPA's approval was upheld on appeal by the Tenth Circuit in October 2014. In addition, the EPA initially proposed in June 2012 to disapprove portions of the nitrogen oxides and particulate matter SIP and instead issue a FIP. The EPA withdrew its initial proposed actions on the nitrogen oxides and particulate matter SIP and the proposed FIP, published a re-proposed rule in June 2013, and finalized its determination in January 2014, which aligns more closely with the SIP proposed by the state of Wyoming. The EPA's final action on the Wyoming SIP approved the state's plan to have PacifiCorp install low-nitrogen oxides burners at Naughton Units 1 and 2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units 1 through 4 between 2015 and 2022, and low-nitrogen oxides burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility, requiring the installation of SCR controls within five years (i.e., by 2019). The EPA action became final on March 3, 2014. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming also filed an appeal of the EPA's final action, as did the Powder River Basin Resource Council, National Parks Conservation Association and Sierra Club. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit in the appeal. A stay remains in place and the case has not yet been set for oral argument. In June 2014, the Wyoming Department of Environmental Quality issued a revised BART permit allowing Naughton Unit 3 to operate on coal through 2017 and providing for natural gas conversion of the unit in 2018. In 2017, the department approved an extension of the compliance date for Naughton Unit 3 to align with the requirements of the Wyoming SIP extending the requirement to cease coal firing to no later than January 30, 2019. The EPA issued final approval of the Wyoming SIP, including the Naughton Unit 3 gas conversion on March 21, 2019. PacifiCorp removed the unit from coal-fueled service on January 30, 2019, and its 2019 IRP Action Plan incorporates completion of the gas conversion, including all required regulatory notices and filings, by the end of 2020. On February 5, 2019, PacifiCorp submitted a reasonable progress reassessment permit application and reasonable progress determination for Jim Bridger Units 1 and 2, seeking a rescission of the December 2017 permit requiring the installation of selective catalytic reduction, to be replaced with permit imposing plant-wide emission limits to achieve better modeled visibility, fewer overall environmental impacts and lower costs of compliance. The proposal was issued for public comment in August 2019, and the state of Wyoming held a public hearing August 23, 2019 to consider the proposal and public input. The state of Wyoming is developing responses to public comment and is anticipated to submit the proposal to EPA in the first quarter 2020.

The state of Arizona issued a regional haze SIP requiring, among other things, the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Cholla Unit 4. The EPA approved in part, and disapproved in part, the Arizona SIP and issued a FIP for the disapproved portions requiring SCR controls on Cholla Unit 4. PacifiCorp filed an appeal in the United States Court of Appeals for the Ninth Circuit ("Ninth Circuit") regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP as it relates to their interests. The Ninth Circuit issued an order in February 2015, holding the matter in abeyance while the parties pursued an alternate compliance approach for Cholla Unit 4. The Arizona Department of Environmental Quality's revision of the draft permit and revision to the Arizona regional haze SIP were approved by the EPA through final action published in the Federal Register on March 27, 2017, with an effective date of April 26, 2017. The final action allows Cholla Unit 4 to utilize coal until April 30, 2025 and convert to gas or otherwise cease burning coal by June 30, 2025. In December 2019, PacifiCorp initiated steps towards the early retirement of Unit 4 by December 31, 2020.

The state of Colorado regional haze SIP requires SCR controls at Craig Unit 2 and Hayden Units 1 and 2, in which PacifiCorp has ownership interests. Each of those regional haze compliance projects are either already in service or currently being constructed. In addition, in February 2015, the state of Colorado finalized an amendment to its regional haze SIP relating to Craig Unit 1, in which PacifiCorp has an ownership interest, to require the installation of SCR controls by 2021. In September 2016, the owners of Craig Units 1 and 2 reached an agreement with state and federal agencies and certain environmental groups that were parties to the previous settlement requiring SCR to retire Unit 1 by December 31, 2025, in lieu of SCR installation, or alternatively to remove the unit from coal-fueled service by August 31, 2021 with an option to convert the unit to natural gas by August 31, 2023, in lieu of SCR installation. The terms of the agreement were approved by the Colorado Air Quality Board in December 2016, incorporated into an amended Colorado regional haze SIP in 2017 and approved by the EPA in August 2018. PacifiCorp identified a December 31, 2025, retirement date for Craig Unit 1 in its 2017 and 2019 IRPs.

Until the EPA takes final action in each state and decisions have been made in the pending appeals, PacifiCorp cannot fully determine the impacts of the Regional Haze Rule on its respective generating facilities.


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The Navajo Generating Station, in which Nevada Power is a joint owner with an 11.3% ownership share, is also a source that is subject to the regional haze BART requirements. In January 2013, the EPA announced a proposed FIP addressing BART and an alternative for the Navajo Generating Station that includes a flexible timeline for reducing nitrogen oxides emissions. The EPA issued a final FIP on August 8, 2014 adopting, with limited changes, the Navajo Generating Station proposal as a "better than BART" determination. Nevada Power filed the ERCR Plan in May 2014 that proposed to eliminate its ownership participation in the Navajo Generating Station in 2019, which was approved by the PUCN. In February 2017, the non-federal owners of the Navajo Generating Station announced the facility will shut down on or before December 23, 2019, unless new owners can be found. All current owners have since approved a lease extension with the Navajo Nation to allow operations to continue through 2019. On March 21, 2019, the Navajo Nation Council voted to end efforts to transition ownership and extend facility operations. The plant ceased operations at the end of 2019. Ownership transfer negotiations and closure preparations are ongoing and, until concluded, the relevant Registrant cannot determine whether additional action may be required.

Water Quality Standards

The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. After significant litigation, the EPA released a proposed rule under §316(b) of the Clean Water Act to regulate cooling water intakes at existing facilities. The final rule was released in May 2014, and became effective in October 2014. Under the final rule, existing facilities that withdraw at least 25% of their water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day are required to reduce fish impingement (i.e., when fish and other aquatic organisms are trapped against screens when water is drawn into a facility's cooling system) by choosing one of seven options. Facilities that withdraw at least 125 million gallons of water per day from waters of the United States must also conduct studies to help their permitting authority determine what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms (i.e., when organisms are drawn into the facility). PacifiCorp and MidAmerican Energy are assessing the options for compliance at their generating facilities impacted by the final rule and will complete impingement and entrainment studies. PacifiCorp's Dave Johnston generating facility and all of MidAmerican Energy's coal-fueled generating facilities, except Louisa, Ottumwa and Walter Scott, Jr. Unit 4, which have water cooling towers, withdraw more than 125 million gallons per day of water from waters of the United States for once-through cooling applications. PacifiCorp's Jim Bridger, Naughton, Gadsby, Hunter and Huntington generating facilities currently utilize closed cycle cooling towers but are designed to withdraw more than two million gallons of water per day. The standards are required to be met as soon as possible after the effective date of the final rule, but no later than eight years thereafter. The costs of compliance with the cooling water intake structure rule cannot be fully determined until the prescribed studies are conducted and the respective state environmental agencies review the studies to determine whether additional mitigation technologies should be applied. In the event that PacifiCorp's or MidAmerican Energy's existing intake structures require modification, the costs are not anticipated to be significant to the consolidated financial statements. Nevada Power and Sierra Pacific do not utilize once-through cooling water intake or discharge structures at any of their generating facilities. All of the Nevada Power and Sierra Pacific generating stations are designed to have either minimal or zero discharge; therefore, they are not impacted by the §316(b) final rule.


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In November 2015, the EPA published final effluent limitation guidelines and standards for the steam electric power generating sector which, among other things, regulate the discharge of bottom ash transport water, fly ash transport water, combustion residual leachate and non-chemical metal cleaning wastes. These guidelines, which had not been revised since 1982, were revised in response to the EPA's concerns that the addition of controls for air emissions has changed the effluent discharged from coal- and natural gas-fueled generating facilities. Under the originally-promulgated guidelines, permitting authorities were required to include the new limits in each impacted facility's discharge permit upon renewal with the new limits to be met as soon as possible, beginning November 1, 2018 and fully implemented by December 31, 2023. On April 5, 2017, a request for reconsideration and administrative stay of the guidelines was filed with the EPA. The EPA granted the request for reconsideration on April 12, 2017, imposed an immediate administrative stay of compliance dates in the rule that had not passed judicial review and requested the court stay the pending litigation over the rule until September 12, 2017. On June 6, 2017, the EPA proposed to extend many of the compliance deadlines that would otherwise occur in 2018 and on September 18, 2017, the EPA issued a final rule extending certain compliance dates for flue gas desulfurization wastewater and bottom ash transport water limits until November 1, 2020. In a separate action, on April 12, 2019, the Fifth Circuit Court of Appeals vacated two aspects of the final effluent limitation guidelines, concerning discharge limits for (1) legacy wastewater from ash transport or treatment systems and (2) combustion residual leachate from landfills or settling ponds. The Fifth Circuit found that EPA's own data did not support the agency's conclusion that impoundments were the best technology available for these two waste streams. EPA must now complete a new effluent limitation guideline for these discharge limits. On November 22, 2019, the EPA proposed updates to the 2015 rule, specifically addressing flue gas desulfurization wastewater and bottom ash transport water. EPA proposes to ease selenium limits on flue gas desulfurization wastewater, ease the zero-discharge requirements on bottom ash transport water associated with blowdown of ash handling systems, allow a two-year extension to meet flue gas desulfurization wastewater requirements, and include additional subcategories to both wastewater categories. The proposal does not address the wastestreams at issue in the Fifth Circuit Court of Appeal's April 2019 decision. Comments on the proposed rule were accepted through January 21, 2020. While most of the issues raised by this rule are already being addressed through the coal combustion residuals rule and are not expected to impose significant additional requirements on the facilities, the impact of the rule cannot be fully determined until the reconsideration action is complete and any judicial review is conducted.

In April 2014, the EPA and the United States Army Corps of Engineers issued a joint proposal to address "waters of the United States" to clarify protection under the Clean Water Act for streams and wetlands. The proposed rule comes as a result of United States Supreme Court decisions in 2001 and 2006 that created confusion regarding jurisdictional waters that were subject to permitting under either nationwide or individual permitting requirements. The final rule was released in May 2015 but is currently under appeal in multiple courts and a nationwide stay on the implementation of the rule was issued in October 2015. On January 13, 2017, the United States Supreme Court granted a petition to address jurisdictional challenges to the rule. The EPA plans to undertake a two-step process, with the first step to repeal the 2015 rule and the second step to carry out a notice-and-comment rulemaking in which a substantive re-evaluation of the definition of the "waters of the United States" will be undertaken. On July 27, 2017, the EPA and the Corps of Engineers issued a proposal to repeal the final rule and recodify the pre-existing rules pending issuance of a new rule, which was finalized September 12, 2019. On January 22, 2018, the United States Supreme Court issued its decision related to the jurisdictional challenges to the rule, holding that federal district courts, rather than federal appeals courts, have proper jurisdiction to hear challenges to the rule and instructed the Sixth Circuit Court of Appeals to dismiss the petitions for review for lack of jurisdiction, clearing the way for imposition of the rule in certain states barring final action by the EPA to formalize the extension of the compliance deadline. On December 11, 2018, the EPA and the Corps of Engineers proposed a revised definition of "waters of the United States" that is intended to further clarify jurisdictional questions, eliminate case-by-case determinations and narrow Clean Water Act jurisdiction to align with Justice Scalia's 2006 opinion in Rapanos v. United States. On January 23, 2020, the EPA and the Army Corps of Engineers signed the final rule narrowing the federal government's permitting authority under the Clean Water Act. The new Navigable Waters Protection Rule, which will take effect 60 days after it is published in the Federal Register, redefines what waters qualify as navigable waters of the U.S. and are under Clean Water Act jurisdiction. Under the new rule, the Clean Water Act will be considered to cover territorial seas and traditional navigable waters; tributaries that flow into jurisdictional waters; wetlands that are directly adjacent to jurisdictional waters; and lakes, ponds and impoundments of jurisdictional waters. The agency and corps originally proposed six categories, but in the final version they collapsed ditches and impoundments into other categories. There are also 12 categories of waters that the agencies highlighted as being excluded from coverage, including groundwater, ephemeral streams and pools, prior converted cropland and waste treatment systems. Until the rule is fully litigated and finalized, the Registrants cannot predict the impact on overall compliance obligations.


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Coal Combustion Byproduct Disposal

In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts under the RCRA. The final rule was released by the EPA on December 19, 2014, was published in the Federal Register on April 17, 2015 and was effective on October 19, 2015. The final rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the disposal of coal combustion residuals. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts may need to be closed unless they can meet the more stringent regulatory requirements. The final rule requires regulated entities to post annual groundwater monitoring and corrective action reports. The first of these reports was posted to the respective Registrant's coal combustion rule compliance data and information websites in March 2018. Based on the results in those reports, additional action may be required under the rule.

At the time the rule was published in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, nine surface impoundments and three landfills were either closed or repurposed to no longer receive coal combustion byproducts and hence are not subject to the final rule. As PacifiCorp proceeded to implement the final coal combustion rule, it was determined that two surface impoundments located at the Dave Johnston generating facility were hydraulically connected and effectively constitute a single impoundment. In November 2017, a new surface impoundment was placed into service at the Naughton Generating Station. At the time the rule was published in April 2015, MidAmerican Energy owned or operated nine surface impoundments and four landfills that contain coal combustion byproducts. Prior to the effective date of the rule in October 2015, MidAmerican Energy closed or repurposed six surface impoundments to no longer receive coal combustion byproducts. Five of these surface impoundments were closed on or before December 21, 2017 and the sixth is undergoing closure. At the time the rule was published in April 2015, the Nevada Utilities operated ten evaporative surface impoundments and two landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, the Nevada Utilities closed four of the surface impoundments, four impoundments discontinued receipt of coal combustion byproducts making them inactive and two surface impoundments remain active and subject to the final rule. The two landfills remain active and subject to the final rule.


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Multiple parties filed challenges over various aspects of the final rule in the D.C. Circuit in 2015, resulting in settlement of some of the issues and subsequent regulatory action by the EPA, including subjecting inactive surface impoundments to regulation. Oral argument was held by the D.C. Circuit on November 20, 2017 over certain portions of the 2015 rule that had not been settled or otherwise remanded. On August 21, 2018, the D.C. Circuit issued its opinion in Utility Solid Waste Activities Group v. EPA, finding it was arbitrary and capricious for EPA to allow unlined ash ponds to continue operating until some unknown point in the future when groundwater contamination could be detected. The D.C. Circuit vacated the closure section of the CCR rule and remanded the issue of unlined ponds to EPA for reconsideration with specific instructions to consider harm to the environment, not just to human health. The D.C. Circuit also held EPA's decision to not regulate legacy ponds was arbitrary and capricious. While the D.C. Circuit's decision was pending, the EPA, on March 15, 2018, issued a proposal to address provisions of the final coal combustion residuals rule that were remanded back to the agency on June 14, 2016, by the D.C. Circuit. The proposal included provisions that establish alternative performance standards for owners and operators of coal combustion residuals units located in states that have approved permit programs or are otherwise subject to oversight through a permit program administered by the EPA. The EPA finalized the first phase of the coal combustion residuals rule amendments on July 30, 2018, with an effective date of August 28, 2018 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater performance standards for certain constituents, EPA extended the deadline by which facilities must initiate closure of unlined ash ponds exceeding a groundwater protection standard and impoundments that do not meet the rule's aquifer location restrictions to October 31, 2020. Following submittal of competing motions from environmental groups and the EPA to stay or remand this deadline extension, on March 13, 2019, the D.C. Circuit granted EPA's request to remand the rule and left the October 31, 2020 deadline in place while the agency undertakes a new rulemaking establishing a new deadline for initiating closure. On August 14, 2019, the EPA released its "Phase 2" proposal, which contains targeted amendments to the coal combustion residuals rule in response to court remands and EPA settlement agreements, as well as issues raised in a rulemaking petition. The Phase 2 proposal modifies the definition of "beneficial use" by replacing a mass-based threshold with new location-based criteria for triggering the need to conduct an environmental demonstration; establishes a definition of "CCR storage pile" to address the temporary storage of coal combustion residuals on the ground, depending on whether the material is destined for disposal or beneficial use; makes certain changes to the rule's annual groundwater monitoring and corrective action reports to make it easier for the public to see and understand the data contained within the reports; modifies the requirements related to facilities' publicly available coal combustion residual rule websites to make the information more readily available; and establishes a risk-based groundwater monitoring protection standard for boron in the event the EPA decides to add boron to Appendix IV in the coal combustion residuals rule. The EPA accepted comments on the Phase 2 proposal through October 15, 2019. On December 2, 2019, the EPA proposed additional changes to the CCR rule in its Holistic Approach to Closure: Part A rule. This proposal addressed the D.C. Circuit's revocation of the provisions that allow unlined impoundments to continue receiving ash and establishes a new deadline of August 31, 2020, by which all unlined surface impoundments (including clay lined impoundments that do not otherwise meet the definition of “lined”) must initiate closure. The proposal also identifies and clarifies several opportunities to extend the closure deadlines for lack of alternative capacity or closure of the coal-fueled operating unit by a date certain. Comments on the proposal were accepted through January 31, 2020. In addition, it is anticipated that EPA will issue several more proposals over the coming months that further modify the CCR rule, including a federal permit program as directed under the WIIN Act; closure Part B, which may address liner equivalency demonstrations, the use of CCR in impoundment closure, and deadlines to complete closure by removal; and legacy impoundments. Until the proposals are finalized and fully litigated, the Registrants cannot determine whether additional action may be required.

Separately, on August 10, 2017, the EPA issued proposed permitting guidance on how states' coal combustion residuals permit programs should comply with the requirements of the final rule as authorized under the December 2016 Water Infrastructure Improvements for the Nation Act. Utilizing that guidance, the state of Oklahoma submitted an application to the EPA for approval of its state program and, on June 28, 2018, the EPA's approval of the application was published in the Federal Register. Environmental groups, including Waterkeeper Alliance and the Sierra Club, filed suit in the United States District Court for the District of Columbia on September 26, 2018, alleging that the EPA unlawfully approved Oklahoma's permit program. This suit also incorporates claims first identified in a July 26, 2018 notice of intent to sue that alleged the EPA failed to perform nondiscretionary duties related to the development and publication of minimum guidelines for public participation in the approval of state permit programs for coal combustion residuals. To date, none of the states in which the Registrants operate has submitted an application to the EPA for approval of state permitting authority. The state of Utah adopted the federal final rule in September 2016, which required PacifiCorp to submit permit applications for two of its landfills by March 2017. It is anticipated that the state of Utah will submit an application to EPA for approval of its coal combustion residuals permit program prior to the end of 2021. In 2019, the state of Wyoming proposed to adopt state rules which incorporate the final federal rule by reference. It is anticipated that Wyoming will finalize its rule in late 2020 and submit an application to the EPA to implement a state permit program in early 2021.


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Notwithstanding the status of the final coal combustion residuals rule, citizens' suits have been filed against regulated entities seeking judicial relief for contamination alleged to have been caused by releases of coal combustion byproducts. Some of these cases have been successful in imposing liability upon companies if coal combustion byproducts contaminate groundwater that is ultimately released or connected to surface water. In addition, actions have been filed against regulated entities seeking to require that surface impoundments containing coal combustion residuals be subject to closure by removal rather than being allowed to effectuate closure in place as provided under the final rule. The Registrants are not a party to these lawsuits and until they are resolved, the Registrants cannot predict the impact on overall compliance obligations.

Other

Other laws, regulations and agencies to which the relevant Registrants are subject include, but are not limited to:
The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental remediation costs. Certain Registrants have been identified as potentially responsible parties in connection with certain disposal sites. The relevant Registrants have completed several cleanup actions and are participating in ongoing investigations and remedial actions. Costs associated with these actions are not expected to be material and are expected to be found prudent and included in rates.
The Nuclear Waste Policy Act of 1982, under which the United States Department of Energy is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Refer to Note 14 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 11 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K for additional information regarding MidAmerican Energy's nuclear decommissioning obligations.
The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of PacifiCorp's mining activities.
The FERC evaluates hydroelectric systems to ensure environmental impacts are minimized, including the issuance of environmental impact statements for licensed projects both initially and upon relicensing. The FERC monitors the hydroelectric facilities for compliance with the license terms and conditions, which include environmental provisions. Refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for information regarding the relicensing of PacifiCorp's Klamath River hydroelectric system.

The Registrants expect they will be allowed to recover their respective prudently incurred costs to comply with the environmental laws and regulations discussed above. The Registrants' planning efforts take into consideration the complexity of balancing factors such as: (a) pending environmental regulations and requirements to reduce emissions, address waste disposal, ensure water quality and protect wildlife; (b) avoidance of excessive reliance on any one generation technology; (c) costs and trade-offs of various resource options including energy efficiency, demand response programs and renewable generation; (d) state-specific energy policies, resource preferences and economic development efforts; (e) additional transmission investment to reduce power costs and increase efficiency and reliability of the integrated transmission system; and (f) keeping rates affordable. Due to the number of generating units impacted by environmental regulations, deferring installation of compliance-related projects is often not feasible or cost effective and places the Registrants at risk of not having access to necessary capital, material, and labor while attempting to perform major equipment installations in a compressed timeframe concurrent with other utilities across the country. Therefore, the Registrants have established installation schedules with permitting agencies that coordinate compliance timeframes with construction and tie-in of major environmental compliance projects as units are scheduled off-line for planned maintenance outages; these coordinated efforts help reduce costs associated with replacement power and maintain system reliability.


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Item 1A.    Risk Factors

Each Registrant is subject to numerous risks and uncertainties, including, but not limited to, those described below. Careful consideration of these risks, together with all of the other information included in this Form 10-K and the other public information filed by the relevant Registrant, should be made before making an investment decision. Additional risks and uncertainties not presently known or which each Registrant currently deems immaterial may also impair its business operations. Unless stated otherwise, the risks described below generally relate to each Registrant.

Corporate and Financial Structure Risks

BHE is a holding company and depends on distributions from subsidiaries, including joint ventures, to meet its obligations.

BHE is a holding company with no material assets other than the ownership interests in its subsidiaries and joint ventures, collectively referred to as its subsidiaries. Accordingly, cash flows and the ability to meet BHE's obligations are largely dependent upon the earnings of its subsidiaries and the payment of such earnings to BHE in the form of dividends or other distributions. BHE's subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay amounts due pursuant to BHE's senior debt, junior subordinated debt or its other obligations, or to make funds available, whether by dividends or other payments, for the payment of amounts due pursuant to BHE's senior debt, junior subordinated debt or its other obligations, and do not guarantee the payment of any of its obligations. Distributions from subsidiaries may also be limited by:
their respective earnings, capital requirements, and required debt and preferred stock payments;
the satisfaction of certain terms contained in financing, ring-fencing or organizational documents; and
regulatory restrictions that limit the ability of BHE's regulated utility subsidiaries to distribute profits.

BHE is substantially leveraged, the terms of its existing senior and junior subordinated debt do not restrict the incurrence of additional debt by BHE or its subsidiaries, and BHE's senior debt is structurally subordinated to the debt of its subsidiaries, and each of such factors could adversely affect BHE's consolidated financial results.

A significant portion of BHE's capital structure is comprised of debt, and BHE expects to incur additional debt in the future to fund items such as, among others, acquisitions, capital investments and the development and construction of new or expanded facilities. As of December 31, 2019, BHE had the following outstanding obligations:
senior unsecured debt of $8.6 billion;
junior subordinated debentures of $100 million;
short-term borrowings of $1,590 million;
guarantees and letters of credit in respect of subsidiary and equity method investments aggregating $277 million; and
commitments, subject to satisfaction of certain specified conditions, to provide equity contributions in support of renewable tax equity investments totaling $2.4 billion.

BHE's consolidated subsidiaries also have significant amounts of outstanding debt, which totaled $32.3 billion as of December 31, 2019. These amounts exclude (a) trade debt, (b) preferred stock obligations, (c) letters of credit in respect of subsidiary debt, and (d) BHE's share of the outstanding debt of its own or its subsidiaries' equity method investments.

Given BHE's substantial leverage, it may not have sufficient cash to service its debt, which could limit its ability to finance future acquisitions, develop and construct additional projects, or operate successfully under difficult conditions, including those brought on by adverse national and global economies, unfavorable financial markets or growth conditions where its capital needs may exceed its ability to fund them. BHE's leverage could also impair its credit quality or the credit quality of its subsidiaries, making it more difficult to finance operations or issue future debt on favorable terms, and could result in a downgrade in debt ratings by credit rating agencies.


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The terms of BHE's and its subsidiaries' debt do not limit BHE's ability or the ability of its subsidiaries to incur additional debt or issue preferred stock. Accordingly, BHE or its subsidiaries could enter into acquisitions, new financings, refinancings, recapitalizations, leases or other highly leveraged transactions that could significantly increase BHE's or its subsidiaries' total amount of outstanding debt. The interest payments needed to service this increased level of debt could adversely affect BHE's or its subsidiaries' financial results. Many of BHE's subsidiaries' debt agreements contain covenants, or may in the future contain covenants, that restrict or limit, among other things, such subsidiaries' ability to create liens, sell assets, make certain distributions, incur additional debt or miss contractual deadlines or requirements, and BHE's ability to comply with these covenants may be affected by events beyond its control. Further, if an event of default accelerates a repayment obligation and such acceleration results in an event of default under some or all of BHE's other debt, BHE may not have sufficient funds to repay all of the accelerated debt simultaneously, and the other risks described under "Corporate and Financial Structure Risks" may be magnified as well.

Because BHE is a holding company, the claims of its senior debt holders are structurally subordinated with respect to the assets and earnings of its subsidiaries. Therefore, the rights of its creditors to participate in the assets of any subsidiary in the event of a liquidation or reorganization are subject to the prior claims of the subsidiary's creditors and preferred shareholders, if any. In addition, pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties in the state of Nevada, AltaLink's transmission properties, the equity interest of MidAmerican Funding's subsidiary and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of solar and wind generation projects, are directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of BHE's debt.

A downgrade in BHE's credit ratings or the credit ratings of its subsidiaries, including the Subsidiary Registrants, could negatively affect BHE's or its subsidiaries' access to capital, increase the cost of borrowing or raise energy transaction credit support requirements.

BHE's senior unsecured debt and its subsidiaries' long-term debt, including the Subsidiary Registrants, are rated by various rating agencies. BHE cannot give assurance that its senior unsecured debt rating or any of its subsidiaries' long-term debt ratings will not be reduced in the future. Although none of the Registrants' outstanding debt has rating-downgrade triggers that would accelerate a repayment obligation, a credit rating downgrade would increase any such Registrant's borrowing costs and commitment fees on its revolving credit agreements and other financing arrangements, perhaps significantly. In addition, such Registrant would likely be required to pay a higher interest rate in future financings, and the potential pool of investors and funding sources would likely decrease. Further, access to the commercial paper market could be significantly limited, resulting in higher interest costs.

Similarly, any downgrade or other event negatively affecting the credit ratings of BHE's subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could cause BHE to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing its and its subsidiaries' liquidity and borrowing capacity.

Most of the Registrants' large wholesale customers, suppliers and counterparties require such Registrant to have sufficient creditworthiness in order to enter into transactions, particularly in the wholesale energy markets. If the credit ratings of a Registrant were to decline, especially below investment grade, the relevant Registrant's financing costs and borrowings would likely increase because certain counterparties may require collateral in the form of cash, a letter of credit or some other form of security for existing transactions and as a condition to entering into future transactions with such Registrant. Amounts could be material and could adversely affect such Registrant's liquidity and cash flows.

BHE's majority shareholder, Berkshire Hathaway, could exercise control over BHE in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors and BHE could exercise control over the Subsidiary Registrants in a manner that would benefit BHE to the detriment of the Subsidiary Registrants' creditors and PacifiCorp's preferred stockholders.

Berkshire Hathaway is majority owner of BHE and has control over all decisions requiring shareholder approval. In circumstances involving a conflict of interest between Berkshire Hathaway and BHE's creditors, Berkshire Hathaway could exercise its control in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors.

BHE indirectly owns all of the common stock of PacifiCorp, Nevada Power and Sierra Pacific and is the sole member of MidAmerican Funding and, accordingly, indirectly owns all of MidAmerican Energy's common stock. As a result, BHE has control over all decisions requiring shareholder approval, including the election of directors. In circumstances involving a conflict of interest between BHE and the creditors of the Subsidiary Registrants, BHE could exercise its control in a manner that would benefit BHE to the detriment of the Subsidiary Registrants' creditors.


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Business Risks

Much of BHE's growth has been achieved through acquisitions, and any such acquisition may not be successful.

Much of BHE's growth has been achieved through acquisitions. Future acquisitions may range from buying individual assets to the purchase of entire businesses. BHE will continue to investigate and pursue opportunities for future acquisitions that it believes, but cannot assure, may increase value and expand or complement existing businesses. BHE may participate in bidding or other negotiations at any time for such acquisition opportunities which may or may not be successful.

Any acquisition entails numerous risks, including, among others:
the failure to complete the transaction for various reasons, such as the inability to obtain the required regulatory approvals, materially adverse developments in the potential acquiree's business or financial condition or successful intervening offers by third parties;
the failure of the combined business to realize the expected benefits;
the risk that federal, state or foreign regulators or courts could require regulatory commitments or other actions in respect of acquired assets, potentially including programs, contributions, investments, divestitures and market mitigation measures;
the risk of unexpected or unidentified issues not discovered in the diligence process; and
the need for substantial additional capital and financial investments.

An acquisition could cause an interruption of, or a loss of momentum in, the activities of one or more of BHE's subsidiaries. In addition, the final orders of regulatory authorities approving acquisitions may be subject to appeal by third parties. The diversion of BHE management's attention and any delays or difficulties encountered in connection with the approval and integration of the acquired operations could adversely affect BHE's combined businesses and financial results and could impair its ability to realize the anticipated benefits of the acquisition.

BHE cannot assure that future acquisitions, if any, or any integration efforts will be successful, or that BHE's ability to repay its obligations will not be adversely affected by any future acquisitions.

The Registrants are subject to operating uncertainties and events beyond each respective Registrant's control that impact the costs to operate, maintain, repair and replace utility and interstate natural gas pipeline systems, which could adversely affect each respective Registrant's financial results.

The operation of complex utility systems or interstate natural gas pipeline and storage systems that are spread over large geographic areas involves many operating uncertainties and events beyond each respective Registrant's control. These potential events include the breakdown or failure of the Registrants' thermal, nuclear, hydroelectric, solar, wind and other electricity generating facilities and related equipment, compressors, pipelines, transmission and distribution lines or other equipment or processes, which could lead to catastrophic events; unscheduled outages; strikes, lockouts or other labor-related actions; shortages of qualified labor; transmission and distribution system constraints; failure to obtain, renew or maintain rights-of-way, easements and leases on United States federal, Native American, First Nations or tribal lands; terrorist activities or military or other actions, including cyber attacks; fuel shortages or interruptions; unavailability of critical equipment, materials and supplies; low water flows and other weather-related impacts; performance below expected levels of output, capacity or efficiency; operator error; third-party excavation errors; unexpected degradation of pipeline systems; design, construction or manufacturing defects; and catastrophic events such as severe storms, floods, fires, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, litigation, wars, terrorism and embargoes. A catastrophic event might result in injury or loss of life, extensive property damage or environmental or natural resource damages. For example, in the event of an uncontrolled release of water at one of PacifiCorp's high hazard potential hydroelectric dams, it is probable that loss of human life, disruption of lifeline facilities and property damage could occur in the downstream population and civil or other penalties could be imposed by the FERC. Similarly, in the event of a fire caused by a Registrant's operation of its businesses, including transmission or distribution systems, the relevant Registrant could be exposed to significant liability for personal and property damages that result. The extent of that liability would be determined by the applicable state law where any such damage occurred. In California, for example, where PacifiCorp operates, state law currently exposes utilities to "inverse condemnation" liability for damages resulting from events such as fires caused by the utility's operations regardless of fault. Any of these events or other operational events could significantly reduce or eliminate the relevant Registrant's revenue or significantly increase its expenses, thereby reducing the availability of distributions to BHE. For example, if the relevant Registrant cannot operate its electricity or natural gas facilities at full capacity due to damage caused by a catastrophic event, its revenue could decrease and its expenses could increase due to the need to obtain energy from more expensive sources.

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Further, the Registrants self-insure many risks, and current and future insurance coverage may not be sufficient to replace lost revenue or cover repair and replacement costs or other damages. The scope, cost and availability of each Registrant's insurance coverage may change, including the portion that is self-insured. Any reduction of each Registrant's revenue or increase in its expenses resulting from the risks described above, could adversely affect the relevant Registrant's financial results.

Each Registrant is subject to extensive federal, state, local and foreign legislation and regulation, including numerous environmental, health, safety, reliability, data privacy and other laws and regulations that affect its operations and costs. These laws and regulations are complex, dynamic and subject to new interpretations or change. In addition, new laws and regulations, including initiatives regarding deregulation and restructuring of the utility industry, are continually being proposed and enacted that impose new or revised requirements or standards on each Registrant.

Each Registrant is required to comply with numerous federal, state, local and foreign laws and regulations as described in "General Regulation" and "Environmental Laws and Regulations" in Item 1 of this Form 10-K that have broad application to each Registrant and limits the respective Registrant's ability to independently make and implement management decisions regarding, among other items, acquiring businesses; constructing, acquiring, disposing or retiring of operating assets; operating and maintaining generating facilities and transmission and distribution system assets; complying with pipeline safety and integrity and environmental requirements; setting rates charged to customers; establishing capital structures and issuing debt or equity securities; transacting between subsidiaries and affiliates; and paying dividends or similar distributions. These laws and regulations, which are followed in developing the Registrants' safety and compliance programs and procedures, are implemented and enforced by federal, state and local regulatory agencies, such as the Occupational Safety and Health Administration, the FERC, the EPA, the DOT, the NRC, the Federal Mine Safety and Health Administration and various state regulatory commissions in the United States, and foreign regulatory agencies, such as GEMA, which discharges certain of its powers through its staff within Ofgem, in Great Britain and the AUC in Alberta, Canada.

Compliance with applicable laws and regulations generally requires each Registrant to obtain and comply with a wide variety of licenses, permits, inspections, audits and other approvals. Further, compliance with laws and regulations can require significant capital and operating expenditures, including expenditures for new equipment, inspection, cleanup costs, removal and remediation costs and damages arising out of contaminated properties. Compliance activities pursuant to existing or new laws and regulations could be prohibitively expensive or otherwise uneconomical. As a result, each Registrant could be required to shut down some facilities or materially alter its operations. Further, each Registrant may not be able to obtain or maintain all required environmental or other regulatory approvals and permits for its operating assets or development projects. Delays in, or active opposition by third parties to, obtaining any required environmental or regulatory authorizations or failure to comply with the terms and conditions of the authorizations may increase costs or prevent or delay each Registrant from operating its facilities, developing or favorably locating new facilities or expanding existing facilities. If any Registrant fails to comply with any environmental or other regulatory requirements, such Registrant may be subject to penalties and fines or other sanctions, including changes to the way its electricity generating facilities are operated that may adversely impact generation or how the Pipeline Companies are permitted to operate their systems that may adversely impact throughput. The costs of complying with laws and regulations could adversely affect each Registrant's financial results. Not being able to operate existing facilities or develop new generating facilities to meet customer electricity needs could require such Registrant to increase its purchases of electricity on the wholesale market, which could increase market and price risks and adversely affect such Registrant's financial results.

Existing laws and regulations, while comprehensive, are subject to changes and revisions from ongoing policy initiatives by legislators and regulators and to interpretations that may ultimately be resolved by the courts. For example, changes in laws and regulations could result in, but are not limited to, increased competition and decreased revenues within each Registrant's service territories, such as the recently defeated Nevada Energy Choice Initiative; new environmental requirements, including the implementation of or changes to the Affordable Clean Energy rule, RPS and GHG emissions reduction goals; the issuance of new or stricter air quality standards; the implementation of energy efficiency mandates; the issuance of regulations governing the management and disposal of coal combustion byproducts; changes in forecasting requirements; changes to each Registrant's service territories as a result of condemnation or takeover by municipalities or other governmental entities, particularly where it lacks the exclusive right to serve its customers; the inability of each Registrant to recover its costs on a timely basis, if at all; new pipeline safety requirements; or a negative impact on each Registrant's current cost recovery arrangements. In addition to changes in existing legislation and regulation, new laws and regulations are likely to be enacted from time to time that impose additional or new requirements or standards on each Registrant. Recent efforts by the EPA to repeal the Clean Power Plan could increase the filing of common law nuisance lawsuits against emitters of GHG. Adverse rulings in GHG-related cases could result in increased or changed regulations and could increase costs for GHG emitters, including the Registrants' generating facilities. The GHG rules, changes to those rules, and the Registrants' compliance requirements are subject to potential outcomes from proceedings and litigation challenging the rules.

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New federal, regional, state and international accords, legislation, regulation, or judicial proceedings limiting GHG emissions could have a material adverse impact on the Registrants, the United States and the global economy. Companies and industries with higher GHG emissions, such as utilities with significant coal-fueled generating facilities, will be subject to more direct impacts and greater financial and regulatory risks. The impact is dependent on numerous factors, none of which can be meaningfully quantified at this time. These factors include, but are not limited to, the magnitude and timing of GHG emissions reduction requirements; the design of the requirements; the cost, availability and effectiveness of emissions control technology; the price, distribution method and availability of offsets and allowances used for compliance; government-imposed compliance costs; and the existence and nature of incremental cost recovery mechanisms. Examples of how new requirements may impact the Registrants include:
Additional costs may be incurred to purchase required emissions allowances under any market-based cap-and-trade system in excess of allocations that are received at no cost. These purchases would be necessary until new technologies could be developed and deployed to reduce emissions or lower carbon generation is available;
Acquiring and renewing construction and operating permits for new and existing generating facilities may be costly and difficult;
Additional costs may be incurred to purchase and deploy new generating technologies;
Costs may be incurred to retire existing coal-fueled generating facilities before the end of their otherwise useful lives or to convert them to burn fuels, such as natural gas or biomass, that result in lower emissions;
Operating costs may be higher and generating unit outputs may be lower;
Higher interest and financing costs and reduced access to capital markets may result to the extent that financial markets view climate change and GHG emissions as a greater business risk; and
The relevant Registrant's natural gas pipeline operations, electric transmission and retail sales may be impacted in response to changes in customer demand and requirements to reduce GHG emissions.

The impact of events or conditions caused by climate change, whether from natural processes or human activities, are uncertain and could vary widely, from highly localized to worldwide, and the extent to which a utility's operations may be affected is uncertain. Climate change may cause physical and financial risk through, among other things, sea level rise, changes in precipitation and extreme weather events. Consumer demand for energy may increase or decrease, based on overall changes in weather and as customers promote lower energy consumption through the continued use of energy efficiency programs or other means. Availability of resources to generate electricity, such as water for hydroelectric production and cooling purposes, may also be impacted by climate change and could influence the Registrants' existing and future electricity generating portfolio. These issues may have a direct impact on the costs of electricity production and increase the price customers pay or their demand for electricity.

Implementing actions required under, and otherwise complying with, new federal and state laws and regulations and changes in existing ones are among the most challenging aspects of managing utility operations. The Registrants cannot accurately predict the type or scope of future laws and regulations that may be enacted, changes in existing ones or new interpretations by agency orders or court decisions, nor can each Registrant determine their impact on it at this time; however, any one of these could adversely affect each Registrant's financial results through higher capital expenditures and operating costs, early closure of generating facilities or lower tax benefits or restrict or otherwise cause an adverse change in how each Registrant operates its business. To the extent that each Registrant is not allowed by its regulators to recover or cannot otherwise recover the costs to comply with new laws and regulations or changes in existing ones, the costs of complying with such additional requirements could have a material adverse effect on the relevant Registrant's financial results. Additionally, even if such costs are recoverable in rates, if they are substantial and result in rates increasing to levels that substantially reduce customer demand, this could have a material adverse effect on the relevant Registrant's financial results.

Recovery of costs and certain activities by each Registrant is subject to regulatory review and approval, and the inability to recover costs or undertake certain activities may adversely affect each Registrant's financial results.

State Regulatory Rate Review Proceedings

The Utilities establish rates for their regulated retail service through state regulatory proceedings. These proceedings typically involve multiple parties, including government bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but generally have the common objective of limiting rate increases or requesting rate decreases while also requiring the Utilities to ensure system reliability. Decisions are subject to judicial appeal, potentially leading to further uncertainty associated with the approval proceedings.


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States set retail rates based in part upon the state regulatory commission's acceptance of an allocated share of total utility costs. When states adopt different methods to calculate interjurisdictional cost allocations, some costs may not be incorporated into rates of any state or other jurisdiction. Ratemaking is also generally done on the basis of estimates of normalized costs, so if a given year's realized costs are higher than normalized costs, rates may not be sufficient to cover those costs. In some cases, actual costs are lower than the normalized or estimated costs recovered through rates and from time-to-time may result in a state regulator requiring refunds to customers. Each state regulatory commission generally sets rates based on a test year established in accordance with that commission's policies. The test year data adopted by each state regulatory commission may create a lag between the incurrence of a cost and its recovery in rates. Each state regulatory commission also decides the allowed levels of expense, investment and capital structure that it deems are prudently incurred in providing the service and may disallow recovery in rates for any costs that it believes do not meet such standard. Additionally, each state regulatory commission establishes the allowed rate of return the Utilities will be given an opportunity to earn on their sources of capital. While rate regulation is premised on providing a fair opportunity to earn a reasonable rate of return on invested capital, the state regulatory commissions do not guarantee that each Registrant will be able to realize the allowed rate of return or recover all of its costs even if it believes such costs to be prudently incurred.

Some state regulatory commissions have authorized recovery of certain costs above the level assumed in establishing base rates through adjustment mechanisms, which may be subject to customer sharing. Any significant increase in fuel costs for electricity generation or purchased electricity costs could have a negative impact on the Utilities, despite efforts to minimize this impact through the use of hedging contracts and adjustment mechanisms or through future general regulatory rate reviews. Any of these consequences could adversely affect each Registrant's financial results.

FERC Jurisdiction

The FERC authorizes cost-based rates associated with transmission services provided by the Utilities' transmission facilities. Under the Federal Power Act, the Utilities, or MISO as it relates to MidAmerican Energy, may voluntarily file, or may be obligated to file, for changes, including general rate changes, to their system-wide transmission service rates. General rate changes implemented may be subject to refund. The FERC also has responsibility for approving both cost- and market-based rates under which the Utilities sell electricity in the wholesale market, has jurisdiction over most of PacifiCorp's hydroelectric generating facilities and has broad jurisdiction over energy markets. The FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or could revoke or restrict the ability of the Utilities to sell electricity at market-based rates, which could adversely affect each Registrant's financial results. The FERC also maintains rules concerning standards of conduct, affiliate restrictions, interlocking directorates and cross-subsidization. As a transmission owning member of MISO, MidAmerican Energy is also subject to MISO-directed modifications of market rules, which are subject to FERC approval and operational procedures. As participants in EIM, PacifiCorp, Nevada Power and Sierra Pacific are also subject to applicable California ISO rules, which are subject to FERC approval and operational procedures. The FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act and the FERC's rules and orders.

The NERC has standards in place to ensure the reliability of the electric generation system and transmission grid. The Utilities are subject to the NERC's regulations and periodic audits to ensure compliance with those regulations. The NERC may carry out enforcement actions for non-compliance and administer significant financial penalties, subject to the FERC's review.

The FERC has jurisdiction over, among other things, the construction, abandonment, modification and operation of natural gas pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including all rates, charges and terms and conditions of service. The FERC also has market transparency authority and has adopted additional reporting and internet posting requirements for natural gas pipelines and buyers and sellers of natural gas.

Rates for the interstate natural gas transmission and storage operations at the Pipeline Companies, which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for charges, are authorized by the FERC. In accordance with the FERC's rate-making principles, the Pipeline Companies' current maximum tariff rates are designed to recover prudently incurred costs included in their pipeline system's regulatory cost of service that are associated with the construction, operation and maintenance of their pipeline system and to afford the Pipeline Companies an opportunity to earn a reasonable rate of return. Nevertheless, the rates the FERC authorizes the Pipeline Companies to charge their customers may not be sufficient to recover the costs incurred to provide services in any given period. Moreover, from time to time, the FERC may change, alter or refine its policies or methodologies for establishing pipeline rates and terms and conditions of service. In addition, the FERC has the authority under Section 5 of the Natural Gas Act of 1938 ("NGA") to investigate whether a pipeline may be earning more than its allowed rate of return and, when appropriate, to institute proceedings against such pipeline to prospectively reduce rates. Any such proceedings, if instituted, could result in significantly adverse rate decreases.


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Under FERC policy, interstate pipelines and their customers may execute contracts at negotiated rates, which may be above or below the maximum tariff rate for that service or the pipeline may agree to provide a discounted rate, which would be a rate between the maximum and minimum tariff rates. In a rate proceeding, rates in these contracts are generally not subject to adjustment. It is possible that the cost to perform services under negotiated or discounted rate contracts will exceed the cost used in the determination of the negotiated or discounted rates, which could result either in losses or lower rates of return for providing such services. Under certain circumstances, FERC policy allows interstate natural gas pipelines to design new maximum tariff rates to recover such costs in regulatory rate reviews. However, with respect to discounts granted to affiliates, the interstate natural gas pipeline must demonstrate that the discounted rate was necessary in order to meet competition.

GEMA Jurisdiction

The Northern Powergrid Distribution Companies, as Distribution Network Operators ("DNOs") and holders of electricity distribution licenses, are subject to regulation by GEMA. Most of the revenue of a DNO is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not directly constrain profits from year-to-year, but is a control on revenue that operates independent of a significant portion of the DNO's actual costs. A resetting of the formula does not require the consent of the DNO, but if a licensee disagrees with a change to its license it can appeal the matter to the United Kingdom's Competition and Markets Authority. GEMA is able to impose financial penalties on DNOs that contravene any of their electricity distribution license duties or certain of their duties under British law, or fail to achieve satisfactory performance of individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the DNO's revenue. During the term of any price control, additional costs have a direct impact on the financial results of the Northern Powergrid Distribution Companies.

AUC Jurisdiction

The AUC is an independent, quasi-judicial agency established by the province of Alberta, Canada, which is responsible for, among other things, approving the tariffs of transmission facility owners, including AltaLink, and distribution utilities, acquisitions of such transmission facility owners or utilities, and construction and operation of new transmission projects in Alberta. The AUC also investigates and rules on regulated rate disputes and system access problems.

The AUC regulates and oversees Alberta's electricity transmission sector with broad authority that may impact many of AltaLink's activities, including its tariffs, rates, construction, operations and financing. The AUC has various core functions in regulating the Alberta electricity transmission sector, including the following:
regulating and adjudicating issues related to the operation of electric utilities within Alberta;
processing and approving general tariff applications relating to revenue requirements and rates of return including deemed capital structure for regulated utilities while ensuring that utility rates are just and reasonable and approval of the transmission tariff rates of regulated transmission providers by the AESO, which is the independent transmission system operator in Alberta that controls the operation of AltaLink's transmission system;
approving the need for new electricity transmission facilities and permits to build and licenses to operate electricity transmission facilities;
reviewing operations and accounts from electric utilities and conducting on-site inspections to ensure compliance with industry regulations and standards;
adjudicating enforcement issues including the imposition of administrative penalties that arise when market participants violate the rules of the AESO; and
collecting, storing, analyzing, appraising and disseminating information to effectively fulfill its duties as an industry regulator.

In addition, AUC approval is required in connection with new energy and regulated utility initiatives in Alberta, amendments to existing approvals and financing proposals by designated utilities.


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Physical or cyber attacks, both threatened and actual, could impact each Registrant's operations and could adversely affect its financial results.

Each Registrant relies on technology in virtually all aspects of its business. Like those of many large businesses, certain of the Registrant's technology systems have been subject to computer viruses, malicious codes, unauthorized access, phishing efforts, denial-of-service attacks and other cyber attacks and each Registrant expects to be subject to similar attacks in the future as such attacks become more sophisticated and frequent. A significant disruption or failure of its technology systems by physical or cyber attack could result in service interruptions, safety failures, security events, regulatory compliance failures, an inability to protect information and assets against unauthorized users, and other operational difficulties. Attacks perpetrated against each Registrant's systems could result in loss of assets and critical information and expose it to remediation costs and reputational damage.

Although the Registrants have taken steps intended to mitigate these risks, a significant disruption or cyber intrusion could adversely affect each Registrant's financial results. Cyber attacks could further adversely affect each Registrant's ability to operate facilities, information technology and business systems, or compromise sensitive customer and employee information. In addition, physical or cyber attacks against key suppliers or service providers could have a similar effect on each Registrant. Additionally, if each Registrant is unable to acquire, develop, implement, adopt or protect rights around new technology, it may suffer a competitive disadvantage.

Each Registrant is actively pursuing, developing and constructing new or expanded facilities, the completion and expected costs of which are subject to significant risk, and each Registrant has significant funding needs related to its planned capital expenditures.

Each Registrant actively pursues, develops and constructs new or expanded facilities. Each Registrant expects to incur significant annual capital expenditures over the next several years. Such expenditures may include construction and other costs for new electricity generating facilities, electric transmission or distribution projects, environmental control and compliance systems, natural gas storage facilities, new or expanded pipeline systems, and continued maintenance and upgrades of existing assets.

Development and construction of major facilities are subject to substantial risks, including fluctuations in the price and availability of commodities, manufactured goods, equipment, and the imposition of tariffs thereon when sourced by foreign providers, labor, siting and permitting and changes in environmental and operational compliance matters, load forecasts and other items over a multi-year construction period, as well as counterparty risk and the economic viability of the Registrants' suppliers, customers and contractors. Certain of the Registrants' construction projects are substantially dependent upon a single supplier or contractor and replacement of such supplier or contractor may be difficult and cannot be assured. These risks may result in the inability to timely complete a project or higher than expected costs to complete an asset and place it in-service and, in extreme cases, the loss of the power purchase agreements or other long-term off-take contracts underlying such projects. Such costs may not be recoverable in the regulated rates or market or contract prices each Registrant is able to charge its customers. Delays in construction of renewable projects may result in delayed in-service dates which may result in the loss of anticipated revenue or income tax benefits. It is also possible that additional generation needs may be obtained through power purchase agreements, which could increase long-term purchase obligations and force reliance on the operating performance of a third party. The inability to successfully and timely complete a project, avoid unexpected costs or recover any such costs could adversely affect such Registrant's financial results.

Furthermore, each Registrant depends upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. If BHE does not provide needed funding to its subsidiaries and the subsidiaries are unable to obtain funding from external sources, they may need to postpone or cancel planned capital expenditures.

A significant sustained decrease in demand for electricity or natural gas in the markets served by each Registrant would decrease its operating revenue, could impact its planned capital expenditures and could adversely affect its financial results.

A significant sustained decrease in demand for electricity or natural gas in the markets served by each Registrant would decrease its operating revenue, could impact its planned capital expenditures and could adversely affect its financial results. Factors that could lead to a decrease in market demand include, among others:
a depression, recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on electricity or natural gas;
an increase in the market price of electricity or natural gas or a decrease in the price of other competing forms of energy;
shifts in competitively priced natural gas supply sources away from the sources connected to the Pipeline Companies' systems, including shale gas sources;

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efforts by customers, legislators and regulators to reduce the consumption of electricity generated or distributed by each Registrant through various existing laws and regulations, as well as, deregulation, conservation, energy efficiency and private generation measures and programs;
laws mandating or encouraging renewable energy sources, which may decrease the demand for electricity and natural gas or change the market prices of these commodities;
higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or other fuel sources for electricity generation or that limit the use of natural gas or the generation of electricity from fossil fuels;
a shift to more energy-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, legislation mandating higher fuel economy or lower emissions, price differentials, incentives or otherwise;
a reduction in the state or federal subsidies or tax incentives that are provided to agricultural, industrial or other customers, or a significant sustained change in prices for commodities such as ethanol or corn for ethanol manufacturers; and
sustained mild weather that reduces heating or cooling needs.

Each Registrant's operating results may fluctuate on a seasonal and quarterly basis and may be adversely affected by weather.

In most parts of the United States and other markets in which each Registrant operates, demand for electricity peaks during the summer months when irrigation and cooling needs are higher. Market prices for electricity also generally peak at that time. In other areas, including the western portion of PacifiCorp's service territory, demand for electricity peaks during the winter when heating needs are higher. In addition, demand for natural gas and other fuels generally peaks during the winter. This is especially true in MidAmerican Energy's and Sierra Pacific's retail natural gas businesses. Further, extreme weather conditions, such as heat waves, winter storms or floods could cause these seasonal fluctuations to be more pronounced. Periods of low rainfall or snowpack may negatively impact electricity generation at PacifiCorp's hydroelectric generating facilities, which may result in greater purchases of electricity from the wholesale market or from other sources at market prices. Additionally, PacifiCorp and MidAmerican Energy have added substantial wind-powered generating capacity, and BHE's unregulated subsidiaries are adding solar and wind-powered generating capacity, each of which is also a climate-dependent resource.

As a result, the overall financial results of each Registrant may fluctuate substantially on a seasonal and quarterly basis. Each Registrant has historically provided less service, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect each Registrant's financial results through lower revenue or margins. Conversely, unusually extreme weather conditions could increase each Registrant's costs to provide services and could adversely affect its financial results. The extent of fluctuation in each Registrant's financial results may change depending on a number of factors related to its regulatory environment and contractual agreements, including its ability to recover energy costs, the existence of revenue sharing provisions as it relates to MidAmerican Energy and Nevada Power, and terms of its wholesale sale contracts.

Each Registrant is subject to market risk associated with the wholesale energy markets, which could adversely affect its financial results.

In general, each Registrant's primary market risk is adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas, coal and fuel oil, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. The market price of wholesale electricity may be influenced by several factors, such as the adequacy or type of generating capacity, scheduled and unscheduled outages of generating facilities, prices and availability of fuel sources for generation, disruptions or constraints to transmission and distribution facilities, weather conditions, demand for electricity, economic growth and changes in technology. Volumetric changes are caused by fluctuations in generation or changes in customer needs that can be due to the weather, electricity and fuel prices, the economy, regulations or customer behavior. For example, the Utilities purchase electricity and fuel in the open market as part of their normal operating businesses. If market prices rise, especially in a time when larger than expected volumes must be purchased at market prices, the Utilities may incur significantly greater expense than anticipated. Likewise, if electricity market prices decline in a period when the Utilities are a net seller of electricity in the wholesale market, the Utilities could earn less revenue. Although the Utilities have energy cost adjustment mechanisms, the risks associated with changes in market prices may not be fully mitigated due to customer sharing bands as it relates to PacifiCorp and other factors.


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Potential terrorist activities and the impact of military or other actions, could adversely affect each Registrant's financial results.

The ongoing threat of terrorism and the impact of military or other actions by nations or politically, ethnically or religiously motivated organizations regionally or globally may create increased political, economic, social and financial market instability, which could subject each Registrant's operations to increased risks. Additionally, the United States government has issued warnings that energy assets, specifically pipeline, nuclear generation, transmission and other electric utility infrastructure, are potential targets for terrorist attacks. Political, economic, social or financial market instability or damage to or interference with the operating assets of the Registrants, customers or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to electricity and natural gas, and increased security, repair or other costs, any of which may materially adversely affect each Registrant in ways that cannot be predicted at this time. Any of these risks could materially affect its consolidated financial results. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect each Registrant's ability to raise capital.

Certain Registrants are subject to the unique risks associated with nuclear generation.

The ownership and operation of nuclear power plants, such as MidAmerican Energy's 25% ownership interest in Quad Cities Station, involves certain risks. These risks include, among other items, mechanical or structural problems, inadequacy or lapses in maintenance protocols, the impairment of reactor operation and safety systems due to human error, the costs of storage, handling and disposal of nuclear materials, compliance with and changes in regulation of nuclear power plants, limitations on the amounts and types of insurance coverage commercially available, and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. Additionally, Exelon Generation, the 75% owner and operator of the facility, may respond to the occurrence of any of these or other risks in a manner that negatively impacts MidAmerican Energy, including closure of Quad Cities Station prior to the expiration of its operating license. The prolonged unavailability, or early closure, of Quad Cities Station due to operational or economic factors could have a materially adverse effect on the relevant Registrant's financial results, particularly when the cost to produce power at the plant is significantly less than market wholesale prices. The following are among the more significant of these risks:
Operational Risk - Operations at any nuclear power plant could degrade to the point where the plant would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the plant to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased electricity costs to meet supply commitments. Rather than incurring substantial costs to restart the plant, the plant could be shut down. Furthermore, a shut-down or failure at any other nuclear power plant could cause regulators to require a shut-down or reduced availability at Quad Cities Station.
In addition, issues relating to the disposal of nuclear waste material, including the availability, unavailability and expense of a permanent repository for spent nuclear fuel could adversely impact operations as well as the cost and ability to decommission nuclear power plants, including Quad Cities Station, in the future.

Regulatory Risk - The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with applicable Atomic Energy Act regulations or the terms of the licenses of nuclear facilities. Unless extended, the NRC operating licenses for Quad Cities Station will expire in 2032. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.

Nuclear Accident and Catastrophic Risks - Accidents and other unforeseen catastrophic events have occurred at nuclear facilities other than Quad Cities Station, both in the United States and elsewhere, such as at the Fukushima Daiichi nuclear power plant in Japan as a result of the earthquake and tsunami in March 2011. The consequences of an accident or catastrophic event can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident or catastrophic event could exceed the relevant Registrant's resources, including insurance coverage.


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Certain of BHE's subsidiaries are subject to the risk that customers will not renew their contracts or that BHE's subsidiaries will be unable to obtain new customers for expanded capacity, each of which could adversely affect its financial results.

If BHE's subsidiaries are unable to renew, remarket, or find replacements for their customer agreements on favorable terms, BHE's subsidiaries' sales volumes and operating revenue would be exposed to reduction and increased volatility. For example, without the benefit of long-term transportation agreements, BHE cannot assure that the Pipeline Companies will be able to transport natural gas at efficient capacity levels. Substantially all of the Pipeline Companies' revenues are generated under transportation and storage contracts that periodically must be renegotiated and extended or replaced, and the Pipeline Companies are dependent upon relatively few customers for a substantial portion of their revenue. Similarly, without long-term power purchase agreements, BHE cannot assure that its unregulated power generators will be able to operate profitably. Failure to maintain existing long-term agreements or secure new long-term agreements, or being required to discount rates significantly upon renewal or replacement, could adversely affect BHE's consolidated financial results. The replacement of any existing long-term agreements depends on market conditions and other factors that may be beyond BHE's subsidiaries' control.

Each Registrant is subject to counterparty risk, which could adversely affect its financial results.

Each Registrant is subject to counterparty credit risk related to contractual payment obligations with wholesale suppliers and customers. Adverse economic conditions or other events affecting counterparties with whom each Registrant conducts business could impair the ability of these counterparties to meet their payment obligations. Each Registrant depends on these counterparties to remit payments on a timely basis. Each Registrant continues to monitor the creditworthiness of its wholesale suppliers and customers in an attempt to reduce the impact of any potential counterparty default. If strategies used to minimize these risk exposures are ineffective or if any Registrant's wholesale suppliers' or customers' financial condition deteriorates or they otherwise become unable to pay, it could have a significant adverse impact on each Registrant's liquidity and its financial results.

Each Registrant is subject to counterparty performance risk related to performance of contractual obligations by wholesale suppliers, customers and contractors. Each Registrant relies on wholesale suppliers to deliver commodities, primarily natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide these commodities pursuant to existing contracts could disrupt the delivery of electricity and require the Utilities to incur additional expenses to meet customer needs. In addition, when these contracts terminate, the Utilities may be unable to purchase the commodities on terms equivalent to the terms of current contracts.

Each Registrant relies on wholesale customers to take delivery of the energy they have committed to purchase. Failure of customers to take delivery may require the relevant Registrant to find other customers to take the energy at lower prices than the original customers committed to pay. If each Registrant's wholesale customers are unable to fulfill their obligations, there may be a significant adverse impact on its financial results.

The Northern Powergrid Distribution Companies' customers are concentrated in a small number of electricity supply businesses with RWE Npower PLC and British Gas Trading Limited accounting for approximately 17% and 12%, respectively, of distribution revenue in 2019. AltaLink's primary source of operating revenue is the AESO. Generally, a single customer purchases the energy from BHE's independent power projects in the United States and the Philippines pursuant to long-term power purchase agreements. For example, certain of BHE Renewables' solar and wind independent power projects sell all of their electrical production to either Pacific Gas and Electric Company or Southern California Edison Company, respectively. Any material payment or other performance failure by the counterparties in these arrangements could have a significant adverse impact on BHE's consolidated financial results.

BHE owns investments and projects in foreign countries that are exposed to risks related to fluctuations in foreign currency exchange rates and increased economic, regulatory and political risks.

BHE's business operations and investments outside the United States increase its risk related to fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar. BHE's principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from its foreign operations changes with the fluctuations of the currency in which they transact. BHE indirectly owns a hydroelectric power plant in the Philippines and may acquire significant energy-related investments and projects outside of the United States. BHE may selectively reduce some foreign currency exchange rate risk by, among other things, requiring contracted amounts be settled in, or indexed to, United States dollars or a currency freely convertible into United States dollars, or hedging through foreign currency derivatives. These efforts, however, may not be effective and could negatively affect BHE's consolidated financial results.


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In addition to any disruption in the global financial markets, the economic, regulatory and political conditions in some of the countries where BHE has operations or is pursuing investment opportunities may present increased risks related to, among others, inflation, foreign currency exchange rate fluctuations, currency repatriation restrictions, nationalization, renegotiation, privatization, availability of financing on suitable terms, customer creditworthiness, construction delays, business interruption, political instability, civil unrest, guerilla activity, terrorism, expropriation, trade sanctions, contract nullification and changes in law, regulations or tax policy. BHE may not choose to or be capable of either fully insuring against or effectively hedging these risks.

Poor performance of plan and fund investments and other factors impacting the pension and other postretirement benefit plans and nuclear decommissioning and mine reclamation trust funds could unfavorably impact each Registrant's cash flows, liquidity and financial results.

Costs of providing each Registrant's defined benefit pension and other postretirement benefit plans and costs associated with the joint trustee plan to which PacifiCorp contributes depend upon a number of factors, including the rates of return on plan assets, the level and nature of benefits provided, discount rates, mortality assumptions, the interest rates used to measure required minimum funding levels, the funded status of the plans, changes in benefit design, tax deductibility and funding limits, changes in laws and government regulation and each Registrant's required or voluntary contributions made to the plans. Furthermore, the timing of recognition of unrecognized gains and losses associated with the Registrants’ defined benefit pension plans is subject to volatility due to events that may give rise to settlement accounting. Settlement events resulting from lump sum distributions offered by certain of the Registrants' defined benefit pension plans are influenced by the interest rates used to discount a participant’s lump sum distribution. When the applicable interest rates are low, lump sum distributions in a given year tend to increase resulting in a higher likelihood of triggering settlement accounting.

Certain of the Registrant's pension and other postretirement benefit plans are in underfunded positions. Each Registrant may be required to make cash contributions to fund these plans in the future. Additionally, each Registrant's plans have investments in domestic and foreign equity and debt securities and other investments that are subject to loss. Losses from investments could add to the volatility, size and timing of future contributions.

Furthermore, the funded status of the UMWA 1974 Pension Plan multiemployer plan to which PacifiCorp's subsidiary previously contributed is considered critical and declining. PacifiCorp's subsidiary involuntarily withdrew from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceased performing work for the subsidiary. PacifiCorp has recorded its best estimate of the withdrawal obligation.

In addition, MidAmerican Energy is required to fund over time the projected costs of decommissioning Quad Cities Station, a nuclear power plant, and Bridger Coal Company, a joint venture of PacifiCorp's subsidiary, Pacific Minerals, Inc., is required to fund projected mine reclamation costs. Funds that MidAmerican Energy has invested in a nuclear decommissioning trust and a subsidiary of PacifiCorp has invested in a mine reclamation trust are invested in debt and equity securities and poor performance of these investments will reduce the amount of funds available for their intended purpose, which could require MidAmerican Energy or PacifiCorp's subsidiary to make additional cash contributions. Such cash funding obligations, which are also impacted by the other factors described above, could have a material impact on MidAmerican Energy's or PacifiCorp's liquidity by reducing their available cash.

Inflation and changes in commodity prices and fuel transportation costs may adversely affect each Registrant's financial results.

Inflation and increases in commodity prices and fuel transportation costs may affect each Registrant by increasing both operating and capital costs. As a result of existing rate agreements, contractual arrangements or competitive price pressures, each Registrant may not be able to pass the costs of inflation on to its customers. If each Registrant is unable to manage cost increases or pass them on to its customers, its financial results could be adversely affected.


83


Cyclical fluctuations and competition in the residential real estate brokerage and mortgage businesses could adversely affect HomeServices.

The residential real estate brokerage and mortgage industries tend to experience cycles of greater and lesser activity and profitability and are typically affected by changes in economic conditions, which are beyond HomeServices' control. Any of the following, among others, are examples of items that could have a material adverse effect on HomeServices' businesses by causing a general decline in the number of home sales, sale prices or the number of home financings which, in turn, would adversely affect its financial results:
rising interest rates or unemployment rates, including a sustained high unemployment rate in the United States;
periods of economic slowdown or recession in the markets served;
decreasing home affordability;
lack of available mortgage credit for potential homebuyers, such as the reduced availability of credit, which may continue into future periods;
inadequate home inventory levels;
sources of new competition; and
changes in applicable tax law.

Disruptions in the financial markets could affect each Registrant's ability to obtain debt financing or to draw upon or renew existing credit facilities and have other adverse effects on each Registrant.

Disruptions in the financial markets could affect each Registrant's ability to obtain debt financing or to draw upon or renew existing credit facilities and have other adverse effects on each Registrant. Significant dislocations and liquidity disruptions in the United States, Great Britain, Canada and global credit markets, such as those that occurred in 2008 and 2009, may materially impact liquidity in the bank and debt capital markets, making financing terms less attractive for borrowers that are able to find financing and, in other cases, may cause certain types of debt financing, or any financing, to be unavailable. Additionally, economic uncertainty in the United States or globally may adversely affect the United States' credit markets and could negatively impact each Registrant's ability to access funds on favorable terms or at all. If a Registrant is unable to access the bank and debt markets to meet liquidity and capital expenditure needs, it may adversely affect the timing and amount of its capital expenditures, acquisition financing and its financial results.

Potential changes in accounting standards may impact each Registrant's financial results and disclosures in the future, which may change the way analysts measure each Registrant's business or financial performance.

The Financial Accounting Standards Board ("FASB") and the SEC continuously make changes to accounting standards and disclosure and other financial reporting requirements. New or revised accounting standards and requirements issued by the FASB or the SEC or new accounting orders issued by the FERC could significantly impact each Registrant's financial results and disclosures. For example, beginning in 2018 all changes in the fair values of equity securities (whether realized or unrealized) are recognized as gains or losses in the relevant Registrant's financial statements. Accordingly, periodic changes in such Registrant's reported net income will likely be subject to significant variability.

Each Registrant is involved in a variety of legal proceedings, the outcomes of which are uncertain and could adversely affect its financial results.

Each Registrant is, and in the future may become, a party to a variety of legal proceedings. Litigation is subject to many uncertainties, and the Registrants cannot predict the outcome of individual matters with certainty. It is possible that the final resolution of some of the matters in which each Registrant is involved could result in additional material payments substantially in excess of established reserves or in terms that could require each Registrant to change business practices and procedures or divest ownership of assets. Further, litigation could result in the imposition of financial penalties or injunctions and adverse regulatory consequences, any of which could limit each Registrant's ability to take certain desired actions or the denial of needed permits, licenses or regulatory authority to conduct its business, including the siting or permitting of facilities. Any of these outcomes could have a material adverse effect on such Registrant's financial results.

Item 1B.
Unresolved Staff Comments

Not applicable.

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Item 2.    Properties

Each Registrant's energy properties consist of the physical assets necessary to support its electricity and natural gas businesses. Properties of the relevant Registrant's electricity businesses include electric generation, transmission and distribution facilities, as well as coal mining assets that support certain of PacifiCorp's electric generating facilities. Properties of the relevant Registrant's natural gas businesses include natural gas distribution facilities, interstate pipelines, storage facilities, compressor stations and meter stations. The transmission and distribution assets are primarily within each Registrant's service territories. In addition to these physical assets, the Registrants have rights-of-way, mineral rights and water rights that enable each Registrant to utilize its facilities. It is the opinion of each Registrant's management that the principal depreciable properties owned by it are in good operating condition and are well maintained. Pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties in the state of Nevada, AltaLink's transmission properties and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of generation projects are pledged or encumbered to support or otherwise provide the security for the related subsidiary debt. For additional information regarding each Registrant's energy properties, refer to Item 1 of this Form 10-K and Notes 4, 5 and 22 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of Nevada Power in Item 8 of this Form 10-K and Notes 3 and 4 of the Notes to Consolidated Financial Statements of Sierra Pacific in Item 8 of this Form 10-K.

The following table summarizes Berkshire Hathaway Energy's operating electric generating facilities as of December 31, 2019:
 
 
 
 
 
 
Facility Net
 
Net Owned
Energy
 
 
 
 
 
Capacity
 
Capacity
Source
 
Entity
 
Location by Significance
 
(MWs)
 
(MWs)
 
 
 
 
 
 
 
 
 
Natural gas
 
PacifiCorp, MidAmerican Energy, NV Energy and BHE Renewables
 
Nevada, Utah, Iowa, Illinois, Washington, Oregon, Texas, New York, Arizona and Wyoming
 
10,938
 
10,659
Coal
 
PacifiCorp, MidAmerican Energy and NV Energy
 
Wyoming, Iowa, Utah, Arizona, Nevada, Colorado and Montana
 
13,641
 
8,593
Wind
 
PacifiCorp, MidAmerican Energy and BHE Renewables
 
Iowa, Wyoming, Texas, Nebraska, Washington, California, Illinois, Oregon and Kansas
 
8,883
 
8,883
Solar
 
BHE Renewables and NV Energy
 
California, Texas, Arizona, Minnesota and Nevada
 
1,699
 
1,551
Hydroelectric
 
PacifiCorp, MidAmerican Energy and BHE Renewables
 
Washington, Oregon, The Philippines, Idaho, California, Utah, Hawaii, Montana, Illinois and Wyoming
 
1,299
 
1,277
Nuclear
 
MidAmerican Energy
 
Illinois
 
1,821
 
455
Geothermal
 
PacifiCorp and BHE Renewables
 
California and Utah
 
377
 
377
 
 
 
 
Total
 
38,658
 
31,795

Additionally, as of December 31, 2019 the Company has electric generating facilities that are under construction in Iowa, Wyoming and Montana having total Facility Net Capacity and Net Owned Capacity of 1,816 MWs.

The right to construct and operate each Registrant's electric transmission and distribution facilities and interstate natural gas pipelines across certain property was obtained in most circumstances through negotiations and, where necessary, through prescription, eminent domain or similar rights. PacifiCorp, MidAmerican Energy, Nevada Power, Sierra Pacific, Northern Natural Gas and Kern River in the United States; Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc in Great Britain; and AltaLink in Alberta, Canada continue to have the power of eminent domain or similar rights in each of the jurisdictions in which they operate their respective facilities, but the United States and Canadian utilities do not have the power of eminent domain with respect to governmental, Native American or Canadian First Nations' tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities in the Moapa Indian Reservation are located within a utility corridor that is reserved to the United States Department of Interior, Bureau of Land Management.

85



With respect to real property, each of the electric transmission and distribution facilities and interstate natural gas pipelines fall into two basic categories: (1) parcels that are owned in fee, such as certain of the electric generating facilities, electric substations, natural gas compressor stations, natural gas meter stations and office sites; and (2) parcels where the interest derives from leases, easements (including prescriptive easements), rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the electric transmission and distribution facilities and interstate natural gas pipelines. Each Registrant believes it has satisfactory title or interest to all of the real property making up their respective facilities in all material respects.

Item 3.    Legal Proceedings

Each Registrant is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Each Registrant does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. Each Registrant is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts.

Item 4.
Mine Safety Disclosures

Information regarding Berkshire Hathaway Energy's and PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Reform Act is included in Exhibit 95 to this Form 10-K.


86


PART II

Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

BERKSHIRE HATHAWAY ENERGY

BHE's common stock is beneficially owned by Berkshire Hathaway, Mr. Walter Scott, Jr., a member of BHE's Board of Directors (along with his family members and related or affiliated entities) and Mr. Gregory E. Abel, BHE's Chairman, and has not been registered with the SEC pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly held or traded. BHE has not declared or paid any cash dividends to its common shareholders since Berkshire Hathaway acquired an equity ownership interest in BHE in March 2000, and does not presently anticipate that it will declare any dividends on its common stock in the foreseeable future.

PACIFICORP

All common stock of PacifiCorp is held by its parent company, PPW Holdings LLC, which is a direct, wholly owned subsidiary of BHE. PacifiCorp declared and paid dividends to PPW Holdings LLC of $175 million in 2019 and $450 million in 2018.

MIDAMERICAN FUNDING AND MIDAMERICAN ENERGY

All common stock of MidAmerican Energy is held by its parent company, MHC, which is a direct, wholly owned subsidiary of MidAmerican Funding. MidAmerican Funding is an Iowa limited liability company whose membership interest is held solely by BHE. Neither MidAmerican Funding nor MidAmerican Energy declared or paid any cash distributions or dividends to its sole member or shareholder in 2019 and 2018.

NEVADA POWER

All common stock of Nevada Power is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE. Nevada Power declared and paid dividends to NV Energy of $371 million in 2019. Nevada Power did not declare or pay dividends to NV Energy in 2018.

SIERRA PACIFIC

All common stock of Sierra Pacific is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE. Sierra Pacific declared and paid dividends to NV Energy of $46 million in 2019. Sierra Pacific did not declare or pay dividends to NV Energy in 2018.


87


Item 6.
Selected Financial Data
Berkshire Hathaway Energy Company and its subsidiaries
 
PacifiCorp and its subsidiaries
 
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
 
Nevada Power Company and its subsidiaries
 
Sierra Pacific Power Company
 

Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Berkshire Hathaway Energy Company and its subsidiaries
 
PacifiCorp and its subsidiaries
 
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
 
Nevada Power Company and its subsidiaries
 
Sierra Pacific Power Company
 

Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Berkshire Hathaway Energy Company and its subsidiaries
 
PacifiCorp and its subsidiaries
 
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
 
Nevada Power Company and its subsidiaries
 
Sierra Pacific Power Company
 


88


Item 8.
Financial Statements and Supplementary Data
Berkshire Hathaway Energy Company and its subsidiaries
 
 
Report of Independent Registered Public Accounting Firm
 
Consolidated Balance Sheets
 
Consolidated Statements of Operations
 
Consolidated Statements of Comprehensive Income
 
Consolidated Statements of Changes in Equity
 
Consolidated Statements of Cash Flows
 
Notes to Consolidated Financial Statements
 
PacifiCorp and its subsidiaries
 
 
Report of Independent Registered Public Accounting Firm
 
Consolidated Balance Sheets
 
Consolidated Statements of Operations
 
Consolidated Statements of Comprehensive Income
 
Consolidated Statements of Changes in Shareholders' Equity
 
Consolidated Statements of Cash Flows
 
Notes to Consolidated Financial Statements
 
MidAmerican Energy Company
 
 
Report of Independent Registered Public Accounting Firm
 
Balance Sheets
 
Statements of Operations
 
Statements of Changes in Shareholder's Equity
 
Statements of Cash Flows
 
Notes to Financial Statements
 
MidAmerican Funding, LLC and its subsidiaries
 
 
Report of Independent Registered Public Accounting Firm
 
Consolidated Balance Sheets
 
Consolidated Statements of Operations
 
Consolidated Statements of Changes in Member's Equity
 
Consolidated Statements of Cash Flows
 
Notes to Consolidated Financial Statements
 
Nevada Power Company and its subsidiaries
 
 
Report of Independent Registered Public Accounting Firm
 
Consolidated Balance Sheets
 
Consolidated Statements of Operations
 
Consolidated Statements of Changes in Shareholder's Equity
 
Consolidated Statements of Cash Flows
 
Notes to Consolidated Financial Statements
 
Sierra Pacific Power Company
 
 
Report of Independent Registered Public Accounting Firm
 
Balance Sheets
 
Statements of Operations
 
Statements of Changes in Shareholder's Equity
 
Statements of Cash Flows
 
Notes to Financial Statements
 


89


Berkshire Hathaway Energy Company and its subsidiaries
Consolidated Financial Section

90


Item 6.
Selected Financial Data

Information required by Item 6 is omitted pursuant to General Instruction I(2)(a) to Form 10-K.

Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of the Company during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with the Company's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. The Company's actual results in the future could differ significantly from the historical results.

The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, corporate functions and intersegment eliminations.

Results of Operations

Overview

Net income for the Company's reportable segments for the years ended December 31 is summarized as follows (in millions):
 
2019
 
2018
 
Change
 
2018
 
2017
 
Change
Net income attributable to BHE shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PacifiCorp
$
773

 
$
739

 
$
34

 
5
%
 
$
739

 
$
769

 
$
(30
)
 
(4
)%
MidAmerican Funding
781

 
669

 
112

 
17

 
669

 
574

 
95

 
17

NV Energy
365

 
317

 
48

 
15

 
317

 
346

 
(29
)
 
(8
)
Northern Powergrid
256

 
239

 
17

 
7

 
239

 
251

 
(12
)
 
(5
)
BHE Pipeline Group
422

 
387

 
35

 
9

 
387

 
277

 
110

 
40

BHE Transmission
229

 
210

 
19

 
9

 
210

 
224

 
(14
)
 
(6)
BHE Renewables(1)
431

 
329

 
102

 
31

 
329

 
864

 
(535
)
 
(62
)
HomeServices
160

 
145

 
15

 
10

 
145

 
149

 
(4
)
 
(3
)
BHE and Other
(467
)
 
(467
)
 

 

 
(467
)
 
(584
)
 
117

 
(20
)
Total net income attributable to BHE shareholders
$
2,950

 
$
2,568

 
$
382

 
15
%
 
$
2,568

 
$
2,870

 
$
(302
)
 
(11
)%

(1)
Includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.

Net income attributable to BHE shareholders increased $382 million for 2019 compared to 2018. Included in these results were pre-tax unrealized losses on the Company's investment in BYD Company Limited ($313 million, $227 million after-tax, in 2019 and $526 million, $383 million after-tax, in 2018) and a $134 million income tax benefit in 2018 related to the accrued repatriation tax on undistributed foreign earnings as a result of 2017 Tax Reform. Excluding the impacts of these items, adjusted net income attributable to BHE shareholders in 2019 was $3,177 million, an increase of $360 million, or 13%, compared to adjusted net income attributable to BHE shareholders in 2018 of $2,817 million.

Net income attributable to BHE shareholders decreased $302 million for 2018 compared to 2017. 2018 included a pre-tax unrealized loss of $526 million ($383 million after-tax) on the Company's investment in BYD Company Limited, partially offset by a $134 million income tax benefit related to the accrued repatriation tax on undistributed foreign earnings as a result of 2017 Tax Reform. 2017 included a $516 million income tax benefit as a result of 2017 Tax Reform, partially offset by $439 million of pre-tax charges ($263 million after-tax) from tender offers for certain long-term debt completed in December 2017. Excluding the impacts of these items, adjusted net income attributable to BHE shareholders in 2018 was $2,817 million, an increase of $200 million, or 8%, compared to adjusted net income attributable to BHE shareholders in 2017 of $2,617 million.


91


In 2018, the Domestic Regulated Businesses began passing the benefits of lower income tax expense related to the 2017 Tax Reform to customers through various regulatory mechanisms, including lower retail rates, higher depreciation expense and reductions to rate base, which generally produced lower revenue, operating income and income tax expense in 2018 compared to 2017.

The increase in net income attributable to BHE shareholders for 2019 compared to 2018 was due to the following:

PacifiCorp's net income increased $34 million primarily due to higher allowances for equity and borrowed funds used during construction of $55 million, lower pension and post retirement expense of $11 million and higher utility margin of $4 million, partially offset by higher depreciation and amortization expense of $25 million from additional plant placed in-service, lower PTCs of $21 million from expirations, higher interest expense of $17 million and higher operations and maintenance expense of $10 million, primarily due to costs associated with the early retirement of a coal-fueled generation unit totaling $24 million offset by a decrease in wildfire suppression costs of $9 million. Utility margin increased primarily due to lower coal-fueled generation costs, higher wholesale average market prices, higher retail revenue primarily due to favorable customer volumes and higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms, partially offset by lower wholesale volumes, higher purchased electricity costs, higher natural gas-fueled generation costs and lower net wheeling revenue. Retail customer volumes increased 0.4% primarily due to an increase in the average number of customers and the favorable impact of weather, partially offset by lower customer usage.
MidAmerican Funding's net income increased $112 million primarily due to higher income tax benefit of $115 million, largely due to higher PTCs of $70 million and the favorable impacts of ratemaking, higher electric utility margin, higher allowances for equity and borrowed funds of $32 million and higher investment earnings, partially offset by higher interest expense of $55 million and higher depreciation and amortization expense of $30 million due to additional assets placed in-service offset by $46 million of lower Iowa revenue sharing accruals. Electric utility margin increased due to higher wind generation, higher recoveries through bill riders (substantially offset in cost of fuel and energy, operations and maintenance expense and income tax expense) and higher retail customer volumes. Electric retail customer volumes increased 1.4% as an increase in industrial volumes of 4.0% was largely offset by lower residential volumes from the unfavorable impact of weather and lower customer usage.
NV Energy's net income increased $48 million primarily due to lower operations and maintenance expense, largely due to lower political activity expenses and lower earnings sharing accruals of $23 million at Nevada Power, partially offset by lower electric utility margin of $58 million and higher depreciation and amortization expense. Electric utility margin decreased due to lower retail customer volumes and lower average retail rates from a tax rate reduction rider effective April 1, 2018, partially offset by an increase in the average number of customers and higher wholesale and transmission revenue. Electric retail customer volumes decreased 1.4% primarily due to the impacts of weather, net of increased distribution only service customer volumes.
Northern Powergrid's net income increased $17 million primarily due to lower overall pension expense of $23 million, largely resulting from lower pension settlement losses recognized in 2019 compared to 2018, and higher distribution tariff rates of $39 million, partially offset by lower distributed units of $21 million, higher distribution-related operating and depreciation expenses of $13 million and the stronger United States dollar of $10 million.
BHE Pipeline Group's net income increased $35 million primarily due to higher transportation revenue of $45 million, lower property and other tax expense of $9 million due to a non-recurring property tax refund in 2019 and favorable margin of $9 million on system balancing activities, partially offset by higher depreciation and amortization expense, net of the impact of lower depreciation rates at Kern River, due to increased spending on capital projects.
BHE Transmission's net income increased $19 million primarily due to favorable regulatory decisions received in 2019 and the unfavorable impacts of a regulatory rate order received in 2018 at AltaLink and higher equity earnings at Electric Transmission Texas, LLC, partially offset by the stronger United States dollar impact of $5 million.

92


BHE Renewables' net income increased $102 million primarily due to higher wind earnings of $74 million and higher geothermal earnings of $53 million largely due to higher generation and margins from market opportunities and lower operations and maintenance expense, partially offset by lower hydro earnings of $20 million, primarily due to lower rainfall and a declining financial asset balance, and lower solar earnings of $5 million primarily due to lower insolation. Wind earnings were favorable primarily due to improved tax equity investment earnings of $49 million, earnings from new projects of $35 million and a favorable change in the valuation of a power purchase agreement of $11 million, partially offset by lower revenues on existing projects of $12 million primarily from lower generation and $8 million of unfavorable changes in the valuation of interest rate swap derivatives. Tax equity investment earnings were favorable due to $57 million of earnings from projects reaching commercial operation and $7 million of higher commitment fees, partially offset by $13 million of lower earnings from existing projects mainly due to derates caused by turbine blade repairs.
HomeServices' net income increased $15 million primarily due to higher earnings at existing mortgage businesses of $33 million due to increased refinance activity and net income from acquired businesses of $9 million, partially offset by $36 million of lower earnings at existing brokerage businesses primarily from lower closed units and margins.
BHE and Other net loss remained the same as the change in the after-tax unrealized position of the Company's investment in BYD Company Limited of $156 million was offset by a $134 million income tax benefit recognized in 2018 related to the accrued repatriation tax on undistributed foreign earnings as a result of 2017 Tax Reform, higher interest expense and lower net income of $14 million at MidAmerican Energy Services, LLC driven by unrealized mark-to-market losses on contracts.
The decrease in net income attributable to BHE shareholders for 2018 compared to 2017 was due to the following:
PacifiCorp's net income decreased $30 million, primarily due to lower utility margin of $198 million and higher pension and post retirement expense of $13 million primarily due to a pension settlement charge, partially offset by a decrease in income tax expense of $181 million, primarily from a lower tax rate partially offset by $6 million of income in 2017 from 2017 Tax Reform, and higher allowance for funds used during construction of $22 million. Utility margin decreased due to lower average retail rates, including the impact of a lower federal tax rate due to the 2017 Tax Reform of $152 million, higher natural gas costs, lower wholesale revenue, higher purchased electricity costs and lower retail customer volumes, partially offset by higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms and lower coal costs. Retail customer volumes decreased by 0.2% due to impacts of weather, partially offset by an increase in the average number of customers.
MidAmerican Funding's net income increased $95 million, primarily due to higher electric utility margin of $122 million, a higher income tax benefit of $60 million, primarily due to a $21 million increase in PTCs, a lower federal tax rate and a 2017 charge of $10 million from 2017 Tax Reform, after-tax charges of $17 million in 2017 related to the tender offer of a portion of MidAmerican Funding's 6.927% Senior Bonds due 2029 and higher allowance for borrowed and equity funds of $17 million, partially offset by higher depreciation and amortization of $109 million due to wind-powered generation and other plant placed in-service and increases for Iowa revenue sharing, higher operations and maintenance expense of $11 million and higher interest expense of $10 million. Electric utility margin increased due to higher recoveries through bill riders of $127 million (substantially offset in cost of fuel and energy, operations and maintenance expense and income tax expense), higher retail customer volumes of 5.6%, largely due to industrial growth and the favorable impact of weather, and higher wholesale revenue, partially offset by lower average retail rates of $126 million, predominantly from the impact of a lower federal tax rate due to 2017 Tax Reform, and higher generation and purchased power costs.
NV Energy's net income decreased $29 million, primarily due to an increase in operations and maintenance expense of $71 million from higher political activity expenses and $38 million of earnings sharing established in 2018 as part of the Nevada Power 2017 regulatory rate review, a decrease in electric utility margin of $52 million and an increase in depreciation and amortization of $34 million as a result of various regulatory-directed amortizations established in the Nevada Power 2017 regulatory rate review. These decreases to net income were partially offset by a decrease in income tax expense of $122 million, primarily from a lower federal tax rate and a 2017 charge of $19 million from 2017 Tax Reform. Electric utility margin decreased due to lower average retail rates, including the impact of a lower federal tax rate due to 2017 Tax Reform of $71 million, partially offset by higher retail customer volumes of 3.0%, mainly due to the favorable impact of weather.

93


Northern Powergrid's net income decreased $12 million due to higher distribution-related operating and depreciation expenses of $32 million from additional distribution network investment and higher pension expense of $13 million, largely resulting from pension settlement losses recognized in 2018 due to higher lump sum payments, partially offset by higher distribution revenue of $13 million, higher smart meter operating income of $9 million and the weaker United States dollar of $9 million. Distribution revenue increased due to higher tariff rates of $24 million, partially offset by unfavorable movements in regulatory provisions.
BHE Pipeline Group's net income increased $110 million, due to higher transportation revenue of $113 million at Northern Natural Gas and Kern River from higher volumes and rates due to unique market opportunities and colder temperatures, a decrease in income tax expense of $50 million, primarily from a lower federal tax rate offset by $7 million of income in 2017 from 2017 Tax Reform, and lower depreciation and amortization of $33 million, largely due to lower depreciation rates at Kern River, partially offset by higher operations and maintenance expense of $88 million, primarily due to increased pipeline integrity projects at Northern Natural Gas.
BHE Transmission's net income decreased $14 million from lower earnings at AltaLink of $10 million, primarily due to the impacts of a regulatory rate order in December 2018 and benefits from the release of contingent liabilities in 2017, partially offset by higher net income from the nonregulated natural gas generation business, and lower earnings at BHE U.S. Transmission of $4 million from lower equity earnings at Electric Transmission Texas, LLC due to the impacts of a regulatory rate order in March 2017.
BHE Renewables' net income decreased $535 million primarily due to $628 million of income in 2017 from 2017 Tax Reform primarily resulting from reductions in deferred income tax liabilities, $45 million of higher operations and maintenance expense, mainly due to losses on asset disposals in the Imperial Valley and transformer remediation costs, and an unfavorable change in the valuation of a power purchase agreement of $13 million. These decreases were partially offset by $50 million of increased revenue from overall higher generation and pricing at existing projects, favorable earnings of $34 million from tax equity investments due largely to earnings from additional tax equity investments of $41 million offset by $7 million of higher equity losses from existing tax equity investments, $29 million of net income from additional wind and solar capacity placed in-service, $15 million of make-whole premiums paid in 2017 due to early debt retirements and a settlement of $7 million received in 2018 related to transformer issues in 2016.
HomeServices' net income decreased $4 million, primarily due to lower margin and higher operating expenses at existing businesses, $31 million of income in 2017 from 2017 Tax Reform and $16 million of higher interest expense from increased borrowings primarily related to acquisitions, partially offset by net income of $58 million contributed from acquired businesses and a decrease in income tax expense of $28 million from a lower federal tax rate due to the impact of 2017 Tax Reform.
BHE and Other net loss improved $117 million, primarily due to the 2017 after-tax charge of $246 million related to the tender offer of a portion of BHE's senior bonds, a 2017 charge of $127 million from 2017 Tax Reform, a $134 million income tax benefit in 2018 related to the accrued repatriation tax on undistributed foreign earnings as a result of 2017 Tax Reform and lower consolidated state and foreign income tax expense, partially offset by the after-tax unrealized loss on the investment in BYD Company Limited totaling $383 million and $58 million of lower tax benefits from a lower federal tax rate due to the impact of 2017 Tax Reform.


94


Reportable Segment Results

Operating revenue and operating income for the Company's reportable segments for the years ended December 31 are summarized as follows (in millions):
 
2019
 
2018
 
Change
 
2018
 
2017
 
Change
Operating revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PacifiCorp
$
5,068

 
$
5,026

 
$
42

 
1
 %
 
$
5,026

 
$
5,237

 
$
(211
)
 
(4
)%
MidAmerican Funding
2,927

 
3,053

 
(126
)
 
(4
)
 
3,053

 
2,846

 
207

 
7

NV Energy
3,037

 
3,039

 
(2
)
 

 
3,039

 
3,015

 
24

 
1

Northern Powergrid
1,013

 
1,020

 
(7
)
 
(1
)
 
1,020

 
949

 
71

 
7

BHE Pipeline Group
1,131

 
1,203

 
(72
)
 
(6
)
 
1,203

 
993

 
210

 
21

BHE Transmission
707

 
710

 
(3
)
 

 
710

 
699

 
11

 
2

BHE Renewables
932

 
908

 
24

 
3

 
908

 
838

 
70

 
8

HomeServices
4,473

 
4,214

 
259

 
6

 
4,214

 
3,443

 
771

 
22

BHE and Other
556

 
614

 
(58
)
 
(9
)
 
614

 
594

 
20

 
3

Total operating revenue
$
19,844

 
$
19,787

 
$
57

 
 %
 
$
19,787

 
$
18,614

 
$
1,173

 
6
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PacifiCorp
$
1,072

 
$
1,051

 
$
21

 
2
 %
 
$
1,051

 
$
1,440

 
$
(389
)
 
(27
)%
MidAmerican Funding
549

 
550

 
(1
)
 

 
550

 
544

 
6

 
1

NV Energy
655

 
607

 
48

 
8

 
607

 
766

 
(159
)
 
(21
)
Northern Powergrid
472

 
486

 
(14
)
 
(3
)
 
486

 
488

 
(2
)
 

BHE Pipeline Group
572

 
525

 
47

 
9

 
525

 
473

 
52

 
11

BHE Transmission
323

 
313

 
10

 
3

 
313

 
322

 
(9
)
 
(3
)
BHE Renewables
336

 
325

 
11

 
3

 
325

 
316

 
9

 
3

HomeServices
222

 
214

 
8

 
4

 
214

 
214

 

 

BHE and Other
(51
)
 
1

 
(52
)
 
*

 
1

 
(41
)
 
42

 
*

Total operating income
$
4,150

 
$
4,072

 
$
78

 
2
 %
 
$
4,072

 
$
4,522

 
$
(450
)
 
(10
)%

* Not meaningful

PacifiCorp

Operating revenue increased $42 million for 2019 compared to 2018 due to higher retail revenue of $40 million and higher wholesale and other revenue of $2 million. Retail revenue increased primarily due to higher customer volumes of $31 million and higher average retail rates of $9 million. Retail customer volumes increased 0.4% primarily due to an increase in the average number of residential and commercial customers and the favorable impact of weather, partially offset by lower customer usage. Wholesale and other revenue increased primarily due to higher wholesale average market prices, largely offset by lower wholesale volumes.

Operating income increased $21 million for 2019 compared to 2018 primarily due to lower depreciation and amortization expense of $25 million and higher utility margin of $4 million, partially offset by higher operations and maintenance expense of $10 million, primarily due to costs associated with the early retirement of a coal-fueled generation unit totaling $24 million offset by a decrease in wildfire suppression costs of $9 million. The decrease in depreciation and amortization expense reflects prior year accelerated depreciation of Utah’s share of certain thermal plant units of $174 million (offset in income tax expense) as ordered by the Utah Public Utilities Commission, partially offset by current year accelerated depreciation of Oregon’s share of certain retired wind equipment due to repowering projects that were placed into service in 2019 of $120 million (offset in income tax expense) as ordered by the Oregon Public Utilities Commission and additional plant placed in-service. Utility margin increased primarily due to lower coal-fueled generation costs, higher wholesale average market prices, higher retail revenue primarily due to favorable customer volumes and higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms, partially offset by lower wholesale volumes, higher purchased electricity costs, higher natural gas-fueled generation costs and lower net wheeling revenue.


95


Operating revenue decreased $211 million for 2018 compared to 2017 due to lower retail revenue of $197 million and lower wholesale and other revenue of $14 million. Retail revenue decreased $180 million due to lower average retail rates, including the impact of lower federal tax rate due to 2017 Tax Reform of $152 million, and lower customer volumes of $17 million. Retail customer volumes decreased by 0.2% due to impacts of weather on the residential and commercial customer volumes and lower residential usage in all states except Utah and lower industrial usage in Oregon, Washington and Utah, partially offset by an increase in the average number of residential and commercial customers across the service territory, higher residential and commercial usage in Utah, higher irrigation usage and higher industrial usage in Wyoming and Idaho.

Operating income decreased $389 million for 2018 compared to 2017 primarily due to lower utility margin of $198 million, higher depreciation and amortization expense of $183 million, primarily due to accelerated depreciation of Utah's share of certain thermal plant units of $174 million as ordered by the Utah Public Utilities Commission. Utility margin decreased due to lower average retail rates, including the impact of a lower federal tax rate due to the 2017 Tax Reform of $151 million, higher natural gas costs, lower wholesale revenue, higher purchased electricity costs and lower retail customer volumes, partially offset by higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms and lower coal costs.

MidAmerican Funding

Operating revenue decreased $126 million for 2019 compared to 2018 primarily due to lower electric and natural gas energy efficiency program revenue of $76 million (offset in operations and maintenance expense) and lower natural gas operating revenue of $66 million, partially offset by higher other operating revenue of $13 million, primarily from nonregulated utility construction services, and higher electric operating revenue of $3 million. Electric operating revenue increased due to higher retail revenue of $77 million, partially offset by lower wholesale and other revenue of $74 million. Electric retail revenue increased due to higher customer usage of $76 million and higher recoveries through bill riders (substantially offset in cost of fuel and energy, operations and maintenance expense and income tax expense), primarily the energy adjustment clause, partially offset by lower average rates of $54 million due to sales mix and $19 million from the unfavorable impact of weather. Electric retail customer volumes increased 1.4% as an increase in industrial volumes of 4.0% was largely offset by lower residential volumes from the unfavorable impact of weather and lower customer usage. Electric wholesale and other revenue decreased due to 10.6% lower sales volumes and $35 million from lower average per-unit prices. Natural gas operating revenue decreased from lower recoveries through the purchased gas adjustment clause due to a lower average per-unit cost of natural gas sold totaling $69 million (offset in cost of sales), partially offset by an increase in retail sales volumes of 2.0% from the favorable impact of weather in 2019.

Operating income decreased $1 million for 2019 compared to 2018 primarily due to higher electric utility margin, largely offset by higher operations and maintenance expense not recovered through bill riders and higher depreciation and amortization of $30 million. Electric utility margin increased due to higher wind generation, higher recoveries through bill riders and higher retail customer volumes. Operations and maintenance expense increased mainly due to higher wind-powered generation costs of $37 million, primarily due to the new and repowered wind-powered generating facilities, and higher electric and natural gas distribution costs of $12 million, partially offset by lower fossil-fueled generation maintenance costs. The increase in depreciation and amortization expense reflects $78 million related to new and repowered wind-powered generation and other additional plant placed in-service, partially offset by lower Iowa revenue sharing accruals of $46 million.

Operating revenue increased $207 million for 2018 compared to 2017 primarily due to higher electric operating revenue of $175 million and higher natural gas operating revenue of $35 million. Electric operating revenue increased due to higher retail revenue of $102 million and higher wholesale and other revenue of $73 million. Electric retail revenue increased $127 million from higher recoveries through bill riders (substantially offset in cost of fuel and energy, operations and maintenance expense and income tax expense), primarily the energy adjustment clause, $65 million from higher customer usage, including higher industrial sales volumes, and $36 million from the impact of weather in 2018, partially offset by lower average rates of $126 million, predominantly from the impact of a lower federal tax rate due to 2017 Tax Reform. Electric retail customer volumes increased 5.6%, largely due to industrial growth and the favorable impact of weather. Electric wholesale and other revenue increased due to 22.0% higher sales volumes and higher average per-unit prices of $18 million. Natural gas operating revenue increased due to 16.7% higher retail sales volumes from the impact of weather in 2018 and industrial growth, partially offset by a lower average per-unit price of $21 million (offset in cost of sales) and other usage and rate factors, including the impact of a lower federal tax rate due to 2017 Tax Reform.


96


Operating income increased $6 million for 2018 compared to 2017 primarily due to higher electric utility margin of $122 million and higher natural gas utility margin of $11 million, partially offset by higher depreciation and amortization of $109 million, higher operations and maintenance expense of $11 million and higher property and other taxes of $6 million. Wind-powered generation maintenance increased $23 million primarily due to the additional wind generation facilities but was offset by lower maintenance costs for transmission, distribution and fossil-fueled generation. The increase in depreciation and amortization reflects $65 million related to additional wind generation and other plant placed in-service and increases for Iowa revenue sharing of $44 million. Electric utility margin increased due to higher recoveries through bill riders, higher retail customer volumes and higher wholesale revenue, partially offset by lower average retail rates, predominately from the impact of a lower federal tax rate due to 2017 Tax Reform, and higher generation and purchased power costs. Natural gas utility margin increased due to higher retail sales volumes from colder temperatures in 2018, partially offset by lower average rates, including the impact of a lower federal tax rate due to 2017 Tax Reform.

NV Energy

Operating revenue decreased $2 million for 2019 compared to 2018 primarily due to lower electric operating revenue of $17 million, partially offset by higher natural gas operating revenue of $15 million. Electric operating revenue decreased due to lower retail revenue of $32 million, partially offset by higher wholesale and other revenue of $15 million. Electric retail revenue decreased primarily due to lower retail customer volumes of $50 million and a decrease from a tax rate reduction rider effective April 1, 2018 of $17 million, partially offset by higher fully-bundled energy rates (offset in cost of sales) of $31 million and an increase in the average number of customers of $9 million. Electric retail customer volumes decreased 1.4% primarily due to the impacts of weather, net of increased distribution only service customer volumes. Natural gas operating revenue increased due to a higher average per-unit price (offset in cost of sales) of $13 million and higher volumes from the impacts of weather.

Operating income increased $48 million for 2019 compared to 2018 due to lower operations and maintenance expense primarily due to lower political activity expenses and lower earnings sharing accruals at Nevada Power, partially offset by lower electric utility margin of $58 million and higher depreciation and amortization expense of $26 million. Electric utility margin decreased due to higher energy costs of $41 million and lower electric operating revenue of $17 million. Energy costs increased due to higher net deferred power costs of $109 million, partially offset by lower purchased power costs of $57 million and a lower average cost of fuel for generation of $11 million.

Operating revenue increased $24 million for 2018 compared to 2017 primarily due to higher electric operating revenue of $17 million and higher natural gas operating revenue of $5 million. Electric operating revenue increased due to higher electric retail revenue of $17 million primarily due to higher fully-bundled energy rates (offset in cost of fuel and energy) of $84 million, higher customer volumes of $19 million, primarily due to the impacts of weather, and customer growth of $11 million, partially offset by a decrease from the impact of a lower federal tax rate due to 2017 Tax Reform of $71 million and lower rates from the Nevada Power 2017 regulatory rate review of $30 million. Electric retail customer volumes, including distribution only service customers, increased 3.0% compared to 2017. Natural gas operating revenue increased due to a higher average per-unit price (offset in cost of sales) of $7 million, partially offset by lower volumes from the impacts of weather.

Operating income decreased $159 million for 2018 compared to 2017 due to an increase in operations and maintenance expense of $71 million, primarily due to higher political activity expenses and $38 million of earnings sharing established in 2018 as part of the Nevada Power 2017 regulatory rate review, a decrease in electric utility margin of $52 million and higher depreciation and amortization of $34 million as a result of various regulatory-directed amortizations established in the Nevada Power 2017 regulatory rate review. Electric utility margin decreased as higher energy costs of $69 million were offset by higher electric operating revenue of $17 million. Energy costs increased due to higher net deferred power costs of $57 million and higher purchased power costs of $33 million, partially offset by a lower average cost of fuel for generation of $21 million.

Northern Powergrid

Operating revenue decreased $7 million for 2019 compared to 2018 primarily due to the stronger United States dollar of $45 million and lower distributed units of $21 million, partially offset by higher distribution tariff rates of $39 million and higher smart meter revenue of $15 million due to a larger number of units installed. Operating income decreased $14 million for 2019 compared to 2018 mainly due to the stronger United States dollar of $21 million, higher distribution-related operations and maintenance expense and higher depreciation expense related to additional distribution network and smart meter investments, partially offset by the higher distribution and smart meter revenues.


97


Operating revenue increased $71 million for 2018 compared to 2017 due to the weaker United States dollar of $36 million, higher smart metering revenues of $27 million and higher distribution revenues of $13 million, partially offset by lower contracting revenue of $6 million. Smart metering revenue increased due to a larger number of units installed. Distribution revenue increased primarily due to higher tariff rates of $24 million, partially offset by unfavorable movements on regulatory provisions of $6 million. Operating income decreased $2 million for 2018 compared to 2017 mainly due to higher distribution-related operating and depreciation expenses of $32 million from additional distribution network investment, partially offset by the weaker United States dollar of $18 million, higher distribution revenue of $13 million and higher smart meter operating income of $9 million.

BHE Pipeline Group

Operating revenue decreased $72 million for 2019 compared to 2018 due to lower gas sales of $89 million at Northern Natural Gas related to system balancing activities (largely offset in cost of sales), partially offset by higher transportation revenue of $19 million. Transportation revenue increased from generally higher volumes and rates, partially offset by the impact of period two rates of $26 million (largely offset in depreciation and amortization expense) and $11 million from refunds related to 2017 Tax Reform at Kern River. Operating income increased $47 million for 2019 compared to 2018 primarily due to higher transportation revenue of $45 million, lower property and other tax expense of $9 million due to a non-recurring property tax refund in 2019 and favorable margins of $9 million on system balancing activities, partially offset by higher depreciation and amortization expense, net of the impact of lower depreciation rates at Kern River, due to increased spending on capital projects.

Operating revenue increased $210 million for 2018 compared to 2017 due to higher transportation revenues of $113 million at Northern Natural Gas and Kern River from higher volumes and rates due to unique market opportunities and colder temperatures and higher gas sales of $99 million related to system balancing activities at Northern Natural Gas (largely offset in cost of sales). Operating income increased $52 million for 2018 compared to 2017 primarily due to higher transportation revenues at Northern Natural Gas and Kern River and lower depreciation and amortization of $33 million, largely due to lower depreciation rates at Kern River, partially offset by higher operations and maintenance expense, primarily due to increased pipeline integrity projects at Northern Natural Gas.

BHE Transmission

Operating revenue decreased $3 million for 2019 compared to 2018 mainly due to the stronger United States dollar of $17 million, largely offset by favorable regulatory decisions received in 2019 at AltaLink. Operating income increased $10 million for 2019 compared to 2018 primarily due to favorable regulatory decision received in 2019 and the unfavorable impacts of a regulatory rate order received in 2018 at AltaLink, partially offset by the stronger United States dollar of $8 million.

Operating revenue increased $11 million for 2018 compared to 2017 due to higher operating revenue at AltaLink, primarily from higher revenue from the nonregulated natural gas generation business and additional assets placed in-service, partially offset by the release of contingent liabilities in 2017. Operating income decreased $9 million for 2018 compared to 2017 primarily due to the impacts of a regulatory rate order received by AltaLink in December 2018 and the release of contingent liabilities in 2017, partially offset by the weaker United States dollar and higher operating income from the nonregulated natural gas generation business.

BHE Renewables

Operating revenue increased $24 million for 2019 compared to 2018 primarily due to higher wind revenues of $32 million and higher natural gas and geothermal revenues of $32 million due to higher generation and pricing from market opportunities, partially offset by lower hydro revenues of $28 million due to lower rainfall and lower solar revenues of $11 million due to lower insolation. Wind revenues increased primarily due to $33 million from new projects and a favorable change in the valuation of a power purchase agreement of $11 million, partially offset by lower generation of $12 million at existing projects. Operating income increased $11 million for 2019 compared to 2018 primarily due to the higher operating revenue and lower operations and maintenance expense of $18 million at the geothermal and hydro projects, partially offset by higher expenses related to new wind-powered generation of $30 million.

Operating revenue increased $70 million for 2018 compared to 2017 due to overall higher generation and pricing of $50 million at existing projects and $33 million from additional wind and solar capacity placed in-service, partially offset by an unfavorable change in the valuation of a power purchase agreement of $13 million. Operating income increased $9 million for 2018 compared to 2017 due to the increase in operating revenue, partially offset by higher operations and maintenance expense of $45 million related to losses on asset disposals in the Imperial Valley, transformer remediation costs and higher depreciation expense of $17 million, primarily related to additional solar and wind capacity placed in-service.


98


HomeServices

Operating revenue increased $259 million for 2019 compared to 2018 primarily due to an increase from acquired businesses of $221 million and higher mortgage revenue at existing businesses of $103 million due to increased refinance activity, partially offset by lower brokerage revenue at existing businesses of $74 million mainly due to a 4% decrease in closed units. Operating income increased $8 million for 2019 compared to 2018 due to an increase at existing mortgage businesses of $47 million and an increase from acquired businesses of $15 million, partially offset by a decrease at existing brokerage companies of $54 million primarily from lower closed units and margins.

Operating revenue increased $771 million for 2018 compared to 2017 due to an increase from acquired businesses totaling $838 million and a 4% increase in average home sales prices for existing brokerage businesses, offset by a 5% decrease in closed brokerage units at existing brokerage businesses. Operating income was unchanged for 2018 compared to 2017 primarily due to higher earnings from acquired businesses of $65 million offset by lower earnings from existing businesses.

BHE and Other

Operating revenue decreased $58 million for 2019 compared to 2018 primarily due to lower electricity and natural gas volumes at MidAmerican Energy Services, LLC. BHE and Other had an operating loss of $51 million in 2019 compared to operating income of $1 million in 2018 primarily due to lower margin of $25 million driven by unrealized mark-to-market losses on contracts at MidAmerican Energy Services, LLC and higher other operating costs.

Operating revenue increased $20 million for 2018 compared to 2017 primarily due to higher electricity and natural gas volumes and favorable unrealized mark-to-market gains on contracts at MidAmerican Energy Services, LLC. BHE and Other had operating income of $1 million in 2018 compared to an operating loss of $41 million in 2017 primarily due to lower other operating costs and higher margins at MidAmerican Energy Services, LLC.

Consolidated Other Income and Expense Items

Interest expense

Interest expense for the years ended December 31 is summarized as follows (in millions):
 
2019
 
2018
 
Change
 
2018
 
2017
 
Change
 
 
 
 
 
 
 
 
 
 
 
 
Subsidiary debt
$
1,477

 
$
1,412

 
$
65

 
5
%
 
$
1,412

 
$
1,399

 
$
13

 
1
 %
BHE senior debt and other
430

 
421

 
9

 
2

 
421

 
423

 
(2
)
 

BHE junior subordinated debentures
5

 
5

 

 

 
5

 
19

 
(14
)
 
(74
)
Total interest expense
$
1,912

 
$
1,838

 
$
74

 
4
%
 
$
1,838

 
$
1,841

 
$
(3
)
 
 %

Interest expense increased $74 million for 2019 compared to 2018 primarily due to debt issuances at BHE, PacifiCorp, MidAmerican Energy and BHE Pipeline Group, partially offset by scheduled maturities, principal payments and the impact of foreign currency exchange rate movements.

Interest expense decreased $3 million for 2018 compared to 2017 primarily due to repayments of BHE junior subordinated debentures of $944 million in 2017, scheduled maturities and principal payments and early redemptions of subsidiary debt, partially offset by debt issuances at BHE, MidAmerican Funding, BHE Renewables and HomeServices.

Capitalized interest

Capitalized interest increased $16 million for 2019 compared to 2018 primarily due to higher construction work-in-progress balances at PacifiCorp and MidAmerican Energy, partially offset by a lower construction work-in-progress balance at BHE Renewables.

Capitalized interest increased $16 million for 2018 compared to 2017 primarily due to higher construction work-in-progress balances at PacifiCorp, MidAmerican Energy and BHE Renewables.


99


Allowance for equity funds
Allowance for equity funds increased $69 million for 2019 compared to 2018 and $28 million for 2018 compared to 2017 primarily due to higher construction work-in-progress balances at PacifiCorp and MidAmerican Energy.

Interest and dividend income
Interest and dividend income increased $4 million for 2019 compared to 2018 and $2 million for 2018 compared to 2017 primarily due to higher cash balances at PacifiCorp and MidAmerican Energy, partially offset by a lower financial asset balance at the Casecnan project.

(Losses) gains on marketable securities, net

(Losses) gains on marketable securities, net was favorable $250 million for 2019 compared to 2018 and unfavorable $552 million for 2018 compared to 2017 primarily due to the change in the unrealized position on the Company's investment in BYD Company Limited of $213 million and $(526) million, respectively.

Other, net

Other, net improved $106 million for 2019 compared to 2018 primarily due to higher investment earnings and lower non-service pension expense of $20 million, largely resulting from lower settlement losses recognized in 2019 compared to 2018 at PacifiCorp and Northern Powergrid.

Other, net improved $411 million primarily due to charges of $439 million in 2017 from tender offers related to certain long-term debt completed in December 2017.

Income tax benefit

Income tax benefit increased $15 million for 2019 compared to 2018 and the effective tax rate was (25)% for 2019 and (30)% for 2018. The effective tax rate increased primarily due to higher pre-tax income and a $134 million income tax benefit recognized in 2018 related to the accrued repatriation tax on undistributed foreign earnings as a result of 2017 Tax Reform, partially offset by higher PTCs of $188 million, the favorable impacts of ratemaking and lower consolidated state income taxes in 2019.

Income tax benefit increased $29 million for 2018 compared to 2017 and the effective tax rate was (30)% for 2018 and (22)% for 2017. The effective tax rate decreased primarily due to the reduction in the United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, the favorable impacts of ratemaking of $140 million, including amortization of Utah's share of non-protected excess deferred income taxes used to accelerate depreciation of certain thermal plant units as ordered by the Utah Public Utilities Commission, a $134 million income tax benefit recognized in 2018 related to the accrued repatriation tax on undistributed foreign earnings as a result of 2017 Tax Reform, higher PTCs of $76 million and lower United States income taxes on foreign earnings of $40 million, partially offset by net impacts of $731 million in 2017 as a result of 2017 Tax Reform.

The 2017 Tax Reform most notably lowered the United States federal corporate income tax rate from 35% to 21% effective January 1, 2018, and created a one-time repatriation tax on undistributed foreign earnings and profits. The $731 million of lower income tax expense was comprised of benefits from reductions in deferred income tax liabilities of $1,150 million, partially offset by an accrual for the deemed repatriation of undistributed foreign earnings and profits totaling $419 million.

Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold based on a per kilowatt rate as prescribed pursuant to the applicable federal income tax law and are eligible for the credit for 10 years from the date the qualifying generating facilities are placed in-service. A credit of $0.025 per kilowatt hour was applied to 2019 production and a credit of $0.024 per kilowatt hour was applied to 2018 and 2017 production, which resulted in PTCs of $759 million in 2019, $571 million in 2018 and $495 million in 2017.


100


Equity (loss) income

Equity (loss) income for the years ended December 31 is summarized as follows (in millions):
 
2019
 
2018
 
Change
 
2018
 
2017
 
Change
Equity income (loss):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ETT
$
65

 
$
62

 
$
3

 
5%
 
$
62

 
$
(62
)
 
$
124

 
*
Tax equity investments
(148
)
 
(61
)
 
(87
)
 
*
 
(61
)
 
(120
)
 
59

 
(49)%
Agua Caliente
28

 
27

 
1

 
4
 
27

 
24

 
3

 
13
HomeServices
7

 
8

 
(1
)
 
(13)
 
8

 
6

 
2

 
33
Other
4

 
7

 
(3
)
 
(43)
 
7

 
1

 
6

 
*
Total equity (loss) income
$
(44
)
 
$
43

 
$
(87
)
 
*
 
$
43

 
$
(151
)
 
$
194

 
*

* Not meaningful

Equity income decreased $87 million for 2019 compared to 2018 primarily due higher pre-tax equity losses from tax equity investments at BHE Renewables. PTCs and other income tax benefits from these projects are recognized in income tax expense.

Equity income increased $194 million for 2018 compared to 2017 primarily due to the impacts of 2017 Tax Reform, which decreased equity income in 2017 by $228 million mainly due to equity earnings charges recognized totaling $154 million for amounts to be returned to the customers of equity investments in regulated entities. These investments include pass-through entities for income tax purposes and the lower equity income is entirely offset by lower income tax expense as a result of benefits from reductions in deferred income tax liabilities. Additionally, 2018 pre-tax equity earnings were lower at Electric Transmission Texas, LLC primarily due to the impacts of new retail rates effective March 2017.

Net income attributable to noncontrolling interests

Net income attributable to noncontrolling interests decreased $5 million for 2019 compared to 2018 mainly due to lower earnings at the Casecnan project.

Net income attributable to noncontrolling interests decreased $17 million for 2018 compared to 2017 mainly due to the April 2018 purchase of a redeemable noncontrolling interest at HomeServices.

Liquidity and Capital Resources

Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The Company's long-term debt may include provisions that allow BHE or its subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 18 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the limitation of distributions from BHE's subsidiaries.


101


As of December 31, 2019, the Company's total net liquidity was as follows (in millions):
 
 
 
 
 
MidAmerican
 
NV
 
Northern
 
BHE
 
 
 
 
 
BHE
 
PacifiCorp
 
Funding
 
Energy
 
Powergrid
 
Canada
 
Other
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
13

 
$
30

 
$
288

 
$
49

 
$
334

 
$
69

 
$
257

 
$
1,040

 
 

 
 
 
 
 
 
 
 
 
 
 
 
 
 

Credit facilities
3,500

 
1,200

 
1,309

 
650

 
199

 
674

 
1,880

 
9,412

Less:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

Short-term debt
(1,590
)
 
(130
)
 

 

 

 
(211
)
 
(1,283
)
 
(3,214
)
Tax-exempt bond support and letters of credit

 
(256
)
 
(370
)
 

 

 
(3
)
 

 
(629
)
Net credit facilities
1,910

 
814

 
939

 
650

 
199

 
460

 
597

 
5,569

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total net liquidity
$
1,923

 
$
844

 
$
1,227

 
$
699

 
$
533

 
$
529

 
$
854

 
$
6,609

Credit facilities:
 

 
 

 
 

 
 
 
 

 
 
 
 

 
 

Maturity dates
2022

 
2022

 
2020, 2022

 
2022

 
2022

 
2023

 
2020, 2022

 
 


Refer to Note 9 of the Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the Company's credit facilities, letters of credit, equity commitments and other related items.

On January 29, 2019, PG&E Corporation and Pacific Gas and Electric Company filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Northern District of California. As a result, the Company does not expect to receive distributions from Topaz or Agua Caliente in the near term.

Operating Activities

Net cash flows from operating activities for the years ended December 31, 2019 and 2018 were $6.2 billion and $6.8 billion, respectively. The decrease was primarily due to changes in working capital, partially offset by an increase in income tax receipts.

Net cash flows from operating activities for the years ended December 31, 2018 and 2017 were $6.8 billion and $6.1 billion, respectively. The increase was primarily due to changes in working capital and an increase in income tax receipts.

The timing of the Company's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.

Investing Activities

Net cash flows from investing activities for the years ended December 31, 2019 and 2018 were $(9.0) billion and $(7.0) billion, respectively. The change was primarily due to higher capital expenditures of $1.1 billion and higher funding of tax equity investments. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Net cash flows from investing activities for the years ended December 31, 2018 and 2017 were $(7.0) billion and $(6.1) billion, respectively. The change was primarily due to higher capital expenditures of $1.7 billion and higher funding of tax equity investments, partially offset by higher cash paid for acquisitions in 2017 of $1.0 billion. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Acquisitions

In 2017, the Company completed various acquisitions totaling $1.1 billion, net of cash acquired. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which primarily related to residential real estate brokerage businesses, development and construction costs for a 110-MW solar project and a 50-MW solar project, and the remaining 25% interest in a natural gas-fueled generation facility at Nevada Power. As a result of the various acquisitions, the Company acquired assets of $1.1 billion, assumed liabilities of $487 million and recognized goodwill of $508 million.

102



Financing Activities

Net cash flows from financing activities for the year ended December 31, 2019 were $3,124 million. Sources of cash totaled $5.4 billion and consisted of proceeds from subsidiary debt issuances totaling $4.7 billion and net proceeds from short-term debt of $684 million. Uses of cash totaled $2.3 billion and consisted mainly of $1.9 billion for repayments of subsidiary debt and repurchases of common stock of $293 million.

Net cash flows from financing activities for the year ended December 31, 2018 were $(174) million. Sources of cash totaled $5.6 billion and consisted of proceeds from BHE senior debt issuances of $3.2 billion and proceeds from subsidiary debt issuances totaling $2.4 billion. Uses of cash totaled $5.8 billion and consisted mainly of $2.4 billion for repayments of subsidiary debt, net repayments of short term debt of $1.9 billion, $1.0 billion for repayments of BHE senior debt and the purchase of redeemable noncontrolling interest of $131 million.

Net cash flows from financing activities for the year ended December 31, 2017 were $274 million. Sources of cash totaled $4.1 billion and consisted of net proceeds from short-term debt of $2.4 billion and proceeds from subsidiary debt issuances totaling $1.7 billion. Uses of cash totaled $3.9 billion and consisted mainly of $2.3 billion for repayments of BHE senior debt and junior subordinated debentures, $1.0 billion for repayments of subsidiary debt and tender offer premiums paid of $435 million.

Debt Repurchases

The Company may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Common Stock Transactions

For the years ended December 31, 2019, 2018 and 2017, BHE repurchased 447,712 shares of its common stock for $293 million, 177,381 shares of its common stock for $107 million and 35,000 shares of its common stock for $19 million, respectively.

Future Uses of Cash

The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which BHE and each subsidiary has access to external financing depends on a variety of factors, including its credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry and project finance markets, among other items.

Capital Expenditures

The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Expenditures for certain assets may ultimately include acquisitions of existing assets.


103


The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, by reportable segment for the years ended December 31 are as follows (in millions):
 
Historical
 
Forecast
 
2017
 
2018
 
2019
 
2020
 
2021
 
2022
 
 
 
 
 
 
 
 
 
 
 
 
PacifiCorp
$
769

 
$
1,257

 
$
2,175

 
$
2,788

 
$
1,374

 
$
2,392

MidAmerican Funding
1,776

 
2,332

 
2,810

 
1,861

 
1,027

 
877

NV Energy
456

 
503

 
657

 
675

 
468

 
526

Northern Powergrid
579

 
566

 
602

 
732

 
660

 
471

BHE Pipeline Group
286

 
427

 
687

 
489

 
470

 
421

BHE Transmission
334

 
270

 
247

 
522

 
321

 
260

BHE Renewables
323

 
817

 
122

 
106

 
65

 
71

HomeServices
37

 
47

 
54

 
44

 
38

 
35

BHE and Other
11

 
22

 
10

 
18

 
9

 
6

Total
$
4,571

 
$
6,241

 
$
7,364

 
$
7,235

 
$
4,432

 
$
5,059


 
Historical
 
Forecast
 
2017
 
2018
 
2019
 
2020
 
2021
 
2022
 
 
 
 
 
 
 
 
 
 
 
 
Wind generation
$
1,291

 
$
2,740

 
$
2,784

 
$
2,355

 
$
627

 
$
717

Electric transmission
343

 
219

 
640

 
685

 
289

 
1,410

Other growth
689

 
715

 
828

 
845

 
682

 
431

Operating
2,248

 
2,567

 
3,112

 
3,350

 
2,834

 
2,501

Total
$
4,571

 
$
6,241

 
$
7,364

 
$
7,235

 
$
4,432

 
$
5,059


The Company's historical and forecast capital expenditures consisted mainly of the following:
Wind generation includes the following:
Construction of wind-powered generating facilities at MidAmerican Energy totaling $1,486 million for 2019, $1,261 million for 2018 and $657 million for 2017. MidAmerican Energy placed in-service 1,019 MWs (nominal ratings) during 2019, 817 MWs (nominal ratings) during 2018 and 334 MWs (nominal ratings) during 2017. Wind XI, a 2,000-MW project, was completed in January 2020. Wind XII is a 591-MW project, including 201 MWs placed in-service in 2019 and facilities expected to be placed in-service by the end of 2020. MidAmerican Energy expects all of these wind-powered generating facilities to qualify for 100% of PTCs available. PTCs from these projects are excluded from MidAmerican Energy's Iowa energy adjustment clause until these generation assets are reflected in base rates. Additionally, MidAmerican Energy continues to evaluate wind-powered and other renewable generating facilities that would not be subject to pre-approved ratemaking principles.
Repowering certain existing wind-powered generating facilities at MidAmerican Energy totaling $369 million for 2019, $422 million for 2018 and $514 million for 2017. The repowering projects entail the replacement of significant components of older turbines. Planned spending for the repowered generating facilities totals $136 million in 2020, $436 million in 2021 and $329 million in 2022. Of the 1,056 MWs of current repowering projects not in-service as of December 31, 2019, 649 MWs are currently expected to qualify for 80% of the federal PTCs available for ten years following each facility's return to service and 407 MWs are expected to qualify for 60% of such credits.
Construction of wind-powered generating facilities at PacifiCorp totaling $338 million for 2019, $9 million for 2018, and $5 million for 2017. A total of 1,190 MWs of new wind-powered generating facilities are expected to be placed in-service in 2020. Planned spending for the new wind-powered generating facilities totals $1,303 million in 2020, $79 million in 2021 and $388 million in 2022. The energy production from the new wind-powered generating facilities is expected to qualify for 100% of the federal PTCs available for ten years once the equipment is placed in service.


104


Repowering certain existing wind-powered generating facilities at PacifiCorp totaling $585 million for 2019, $332 million for 2018 and $6 million for 2017. The repowering projects entail the replacement of significant components of older turbines. Certain repowering projects were placed in service in 2019 and the remaining repowering projects are expected to be placed in-service at various dates in 2020. Planned spending for the repowered generating facilities totals $87 million in 2020. The energy production from such repowered facilities is expected to qualify for 100% of the federal PTCs available for ten years following each facility's return to service.
Construction of wind-powered generating facilities at BHE Renewables totaling $15 million for 2019, $717 million for 2018 and $109 million for 2017. BHE Renewables placed in-service 512 MWs during 2018.
Electric transmission includes PacifiCorp's costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, which is a major segment of PacifiCorp's Energy Gateway Transmission expansion program expected to be placed in service in 2020 and AltaLink's directly assigned projects from the AESO.
Other growth includes projects to deliver power and services to new markets, new customer connections, enhancements to existing customer connections and investments in solar generation.
Operating includes ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, investments in routine expenditures for generation, transmission, distribution and other infrastructure needed to serve existing and expected demand and environmental spending relating to emissions control equipment and the management of coal combustion residuals.

Contractual Obligations
The Company has contractual cash obligations that may affect its consolidated financial condition. The following table summarizes the Company's material contractual cash obligations as of December 31, 2019 (in millions):
 
 
Payments Due By Periods
 
 
 
 
2021-
 
2023-
 
2025 and
 
 
 
 
2020
 
2022
 
2024
 
After
 
Total
 
 
 
 
 
 
 
 
 
 
 
BHE senior debt
 
$
350

 
$
450

 
$
900

 
$
6,951

 
$
8,651

BHE junior subordinated debentures
 

 

 

 
100

 
100

Subsidiary debt
 
2,189

 
2,650

 
3,223

 
22,821

 
30,883

Interest payments on long-term debt(1)
 
1,758

 
3,260

 
2,972

 
19,824

 
27,814

Short-term debt
 
3,214

 

 

 

 
3,214

Operating and finance lease liabilities

 
149

 
260

 
155

 
532

 
1,096

Interest payments on operating and finance lease liabilities(1)
 
69

 
115

 
86

 
395

 
665

Fuel, capacity and transmission contract commitments(1)
 
2,218

 
2,720

 
2,181

 
13,584

 
20,703

Construction commitments(1)
 
1,682

 
548

 
10

 

 
2,240

Easements(1)
 
62

 
138

 
142

 
2,259

 
2,601

Other(1)
 
718

 
753

 
586

 
1,655

 
3,712

Total contractual cash obligations
 
$
12,409

 
$
10,894

 
$
10,255

 
$
68,121

 
$
101,679


(1)
Not reflected on the Consolidated Balance Sheets.

The Company has other types of commitments that arise primarily from unused lines of credit, letters of credit or relate to construction and other development costs (Liquidity and Capital Resources included within this Item 7 and Note 9), uncertain tax positions (Note 12) and asset retirement obligations (Note 14), which have not been included in the above table because the amount and timing of the cash payments are not certain. Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.


105


Additionally, the Company has invested in projects sponsored by third parties, commonly referred to as tax equity investments. Under the terms of these tax equity investments, the Company has entered into equity capital contribution agreements with the project sponsors that require contributions. The Company has made contributions of $1,619 million, $698 million and $403 million in 2019, 2018 and 2017, respectively, and has commitments as of December 31, 2019, subject to satisfaction of certain specified conditions, to provide equity contributions of $2.4 billion in 2020 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.

Regulatory Matters

The Company is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further discussion regarding the Company's general regulatory framework and current regulatory matters.

BHE Renewables' Counterparty Risk

On January 29, 2019, PG&E Corporation and Pacific Gas and Electric Company (the "PG&E Utility") (together "PG&E") filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Northern District of California ("PG&E Bankruptcy Filing"). The Company owns 100% of Topaz and owns a 49% interest in Agua Caliente. Topaz is a 550-MW solar photovoltaic electric power generating facility located in California. Topaz sells 100% of its energy, capacity and RECs generated from the facility to PG&E Utility under a 25-year wholesale power purchase agreement ("PPA") that is in effect until October 2039. As of December 31, 2019, the Company's consolidated balance sheet includes $1.0 billion of property, plant and equipment, net and $0.9 billion of non-recourse project debt related to Topaz. Agua Caliente is a 290-MW solar photovoltaic electric power generating facility located in Arizona. Agua Caliente sells 100% of its energy, capacity and RECs generated from the facility to PG&E Utility under a 25-year wholesale PPA that is in effect until June 2039. As of December 31, 2019, the Company's equity investment in Agua Caliente totals $73 million and the project has $0.8 billion of non-recourse project debt owed to the United States Department of Energy. The PG&E Bankruptcy Filing is an event of default under the Topaz PPA ("PPA Default"). PG&E paid in full the invoices for December 2018 deliveries and all amounts invoiced to date for post-petition energy deliveries for both Topaz and Agua Caliente. PG&E has not paid for the power delivered from January 1 through January 28, 2019. The Company continues to perform on its obligations and deliver renewable energy to the PG&E Utility, and PG&E has publicly stated it will pay suppliers in full under normal terms for post-petition goods and services received. The Company maintains that, in light of the current facts and circumstances, the PPA Default could not reasonably be expected to result in a material adverse effect under the Topaz indenture and, therefore, no default has occurred under the Topaz indenture. In July 2019, the California Governor signed AB 1054 into law. AB 1054 is comprehensive legislation addressing wildfire risk in the state of California that, among other items, authorizes a wildfire fund which would operate as an insurance fund to support the creditworthiness of electrical utilities, if certain utilities, including PG&E, participate by making the required contributions, among other things. In July 2019, PG&E notified the CPUC of its intent to participate in the insurance fund and such participation requires, among other items, PG&E to exit bankruptcy by June 30, 2020. The Company believes it is more likely than not that no impairment exists and current debt obligations will be met, as post-petition contractual revenue payments are expected to be paid by PG&E Utility to the Topaz and Agua Caliente projects. The Company will continue to monitor the situation, including continued receipt of future PG&E payments and the future risk of the PPAs being rejected or modified through the bankruptcy process.

Quad Cities Generating Station Operating Status

Exelon Generation Company, LLC ("Exelon Generation"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the zero emission credits will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will not receive additional revenue from the subsidy.

On February 14, 2017, two lawsuits were filed with the United States District Court for the Northern District of Illinois ("Northern District of Illinois") against the Illinois Power Agency alleging that the state's zero emission credit program violates certain provisions of the United States Constitution. Both lawsuits were dismissed at the Northern District of Illinois, and the United States Court of Appeals for the Seventh Circuit affirmed the dismissals. On April 15, 2019, plaintiffs' petition seeking United States Supreme Court review of the case was denied.


106


On January 9, 2017, the Electric Power Supply Association ("EPSA") filed two requests with the FERC seeking to expand Minimum Offer Price Rule ("MOPR") provisions to apply to existing resources receiving zero emission credit compensation. When a resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a government-provided financial support program, resulting in a higher offer that may not clear the capacity market. If the EPSA's requests are successful, an expanded MOPR could result in an increased risk of Quad Cities Station not clearing in future capacity auctions and Exelon Generation no longer receiving capacity revenues for the facility. As majority owner and operator of Quad Cities Station, Exelon Generation filed protests at the FERC in response to each filing.

On December 19, 2019, the FERC issued an order in the PJM Interconnection, L.L.C. ("PJM") MOPR proceeding that broadly applies the MOPR to all new and existing resources, including nuclear, greatly expanding the breadth and scope of PJM's MOPR, effective as of PJM's next capacity auction. The FERC directed PJM to make a compliance filing within 90 days. The FERC has no deadline for acting on PJM's compliance filing. While the FERC included some limited exemptions in its order, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. In addition, the FERC provided no new mechanism for accommodating state-supported resources other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. Unless Illinois can implement an FRR program in their PJM zones, the MOPR will apply to Exelon Generation's nuclear plants in those states receiving a benefit under the Illinois zero emissions program, including Quad Cities Station, resulting in higher offers for those units that may not clear the capacity market.

On January 21, 2020, Exelon Generation, PJM and a number of other entities submitted individual requests for rehearing of the FERC's December 19, 2019 order on the PJM MOPR. Exelon Generation is currently working with PJM and other stakeholders to pursue the FRR option prior to the next capacity auction in PJM. If Illinois implements the FRR option, Quad Cities Station could be removed from PJM's capacity auction and instead supply capacity and be compensated under the FRR program. Implementing the FRR program in Illinois will require both legislative and regulatory changes. MidAmerican Energy cannot predict whether such legislative and regulatory changes can be implemented prior to the next capacity auction in PJM or their potential impact on the continued operation of Quad Cities Station.

Environmental Laws and Regulations

The Company is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. The Company believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion regarding environmental laws and regulations.

Collateral and Contingent Features

Debt of BHE and debt and preferred securities of certain of its subsidiaries are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of the rated company's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.

BHE and its subsidiaries have no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. The Company's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.


107


In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2019, the applicable entities' credit ratings from the three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2019, the Company would have been required to post $390 million of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.

Inflation

Historically, overall inflation and changing prices in the economies where BHE's subsidiaries operate have not had a significant impact on the Company's consolidated financial results. In the United States and Canada, the Regulated Businesses operate under cost-of-service based rate structures administered by various state and provincial commissions and the FERC. Under these rate structures, the Regulated Businesses are allowed to include prudent costs in their rates, including the impact of inflation. The price control formula used by the Northern Powergrid Distribution Companies incorporates the rate of inflation in determining rates charged to customers. BHE's subsidiaries attempt to minimize the potential impact of inflation on their operations through the use of fuel, energy and other cost adjustment clauses and bill riders, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.

Off-Balance Sheet Arrangements

The Company has certain investments that are accounted for under the equity method in accordance with GAAP. Accordingly, an amount is recorded on the Company's Consolidated Balance Sheets as an equity investment and is increased or decreased for the Company's pro-rata share of earnings or losses, respectively, less any dividends from such investments. Certain equity investments are presented on the Consolidated Balance Sheets net of investment tax credits.


108


As of December 31, 2019, the Company's investments that are accounted for under the equity method had short- and long-term debt of $2.4 billion, unused revolving credit facilities of $119 million and letters of credit outstanding of $88 million. As of December 31, 2019, the Company's pro-rata share of such short- and long-term debt was $1.2 billion, unused revolving credit facilities was $60 million and outstanding letters of credit was $43 million. The entire amount of the Company's pro-rata share of the outstanding short- and long-term debt and unused revolving credit facilities is non-recourse to the Company. The entire amount of the Company's pro-rata share of the outstanding letters of credit is recourse to the Company. Although the Company is generally not required to support debt service obligations of its equity investees, default with respect to this non-recourse short- and long-term debt could result in a loss of invested equity.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by the Company's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with the Company's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

Accounting for the Effects of Certain Types of Regulation

The Regulated Businesses prepare their financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Regulated Businesses defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.

The Company continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit the Regulated Businesses' ability to recover their costs. The Company believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at the federal, state and provincial levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI"). Total regulatory assets were $2.9 billion and total regulatory liabilities were $7.3 billion as of December 31, 2019. Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Regulated Businesses' regulatory assets and liabilities.

Classification and Recognition Methodology

The majority of the Company's commodity derivative contracts are probable of inclusion in the rates of its rate-regulated subsidiaries, and changes in the estimated fair value of derivative contracts are generally recorded as net regulatory assets or liabilities. Accordingly, amounts are generally not recognized in earnings until the contracts are settled and the forecasted transaction has occurred. As of December 31, 2019, the Company had $77 million recorded as net regulatory assets related to derivative contracts on the Consolidated Balance Sheets.


109


Impairment of Goodwill and Long-Lived Assets

The Company's Consolidated Balance Sheet as of December 31, 2019 includes goodwill of acquired businesses of $9.7 billion. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31. Additionally, no indicators of impairment were identified as of December 31, 2019. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The Company uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating future cash flows, the Company incorporates current market information, as well as historical factors. Refer to Note 22 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's goodwill.

The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2019, the impacts of regulation are considered when evaluating the carrying value of regulated assets.

The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what the Company would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect the Company's results of operations.

Pension and Other Postretirement Benefits

Certain of the Company's subsidiaries sponsor defined benefit pension and other postretirement benefit plans that cover the majority of employees. The Company recognizes the funded status of the defined benefit pension and other postretirement benefit plans on the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2019, the Company recognized a net liability totaling $21 million for the funded status of the defined benefit pension and other postretirement benefit plans. As of December 31, 2019, amounts not yet recognized as a component of net periodic benefit cost that were included in net regulatory assets totaled $600 million and in AOCI totaled $570 million.

The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected long-term rate of return on plan assets and healthcare cost trend rates. These key assumptions are reviewed annually and modified as appropriate. The Company believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about the defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2019.

The Company chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.

In establishing its assumption as to the expected long-term rate of return on plan assets, the Company utilizes the expected asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. The Company regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.


110


The Company chooses a healthcare cost trend rate that reflects the near and long-term expectations of increases in medical costs and corresponds to the expected benefit payment periods. The healthcare cost trend rate is assumed to gradually decline to 5.00% by 2025, at which point the rate of increase is assumed to remain constant. Refer to Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for healthcare cost trend rate sensitivity disclosures.

The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and the funded status. If changes were to occur for the following key assumptions, the approximate effect on the Consolidated Financial Statements would be as follows (dollars in millions):
 
Domestic Plans
 
 
 
 
 
 
 
Other Postretirement
 
United Kingdom
 
Pension Plans
 
Benefit Plans
 
Pension Plan
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
 
 
 
 
 
 
 
 
 
 
Effect on December 31, 2019
 
 
 
 
 
 
 
 
 
 
 
Benefit Obligations:
 
 
 
 
 
 
 
 
 
 
 
Discount rate
$
(143
)
 
$
158

 
$
(27
)
 
$
30

 
$
(190
)
 
$
171

 
 
 
 
 
 
 
 
 
 
 
 
Effect on 2019 Periodic Cost:
 
 
 
 
 
 
 
 
 
 
 
Discount rate
$
(1
)
 
$
2

 
$
1

 
$
(1
)
 
$
(19
)
 
$
19

Expected rate of return on plan assets
(12
)
 
12

 
(4
)
 
2

 
(10
)
 
10


A variety of factors affect the funded status of the plans, including asset returns, discount rates, mortality assumptions, plan changes and the Company's funding policy for each plan.

Income Taxes

In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory commissions. The Company's income tax returns are subject to continuous examinations by federal, state, local and foreign income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on the Company's consolidated financial results. Refer to Note 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's income taxes.

It is probable the Company's regulated businesses will pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property-related basis differences and other various differences on to their customers in certain state and provincial jurisdictions. As of December 31, 2019, these amounts were recognized as a net regulatory liability of $3.4 billion and will be included in regulated rates when the temporary differences reverse.
The Company has not established deferred income taxes on its undistributed foreign earnings that have been determined by management to be reinvested indefinitely; however, the Company periodically evaluates its capital requirements. If circumstances change in the future and a portion of the Company's undistributed foreign earnings were repatriated, the dividends may be subject to taxation in the United States but the tax is not expected to be material.


111


Revenue Recognition - Unbilled Revenue

Revenue recognized is equal to what the Company has the right to invoice as it corresponds directly with the value to the customer of the Company's performance to date and includes billed and unbilled amounts. The determination of customer invoices is based on a systematic reading of meters, fixed reservation charges based on contractual quantities and rates or, in the case of the Great Britain distribution businesses, when information is received from the national settlement system. At the end of each month, energy provided to customers since the date of the last meter reading is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $638 million as of December 31, 2019. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Unbilled revenue is reversed in the following month and billed revenue is recorded based on the subsequent meter readings.


112


Item 7A.
Quantitative and Qualitative Disclosures About Market Risk

The Company's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. The Company's significant market risks are primarily associated with commodity prices, interest rates, equity prices, foreign currency exchange rates and the extension of credit to counterparties with which the Company transacts. The following discussion addresses the significant market risks associated with the Company's business activities. Each of the Company's business platforms has established guidelines for credit risk management.

Commodity Price Risk

The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through BHE's ownership of the Utilities as they have an obligation to serve retail customer load in their regulated service territories. The Company also provides nonregulated retail electricity and natural gas services in competitive markets. The Utilities' load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold and natural gas supply for retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage and transmission and transportation constraints. The Company does not engage in a material amount of proprietary trading activities. To manage a portion of its commodity price risk, the Company uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. The Company does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. The Company's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates, which is subject to regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.

The table that follows summarizes the Company's price risk on commodity contracts accounted for as derivatives, excluding collateral netting of $79 million and $59 million, respectively, as of December 31, 2019 and 2018, and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices with the contracted or expected volumes. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).

 
Fair Value -
 
Estimated Fair Value after
 
Net Asset
 
Hypothetical Change in Price
 
(Liability)
 
10% increase
 
10% decrease
As of December 31, 2019:
 
 
 
 
 
Not designated as hedging contracts
$
16

 
$
57

 
$
(24
)
Designated as hedging contracts
(21
)
 
(1
)
 
(41
)
Total commodity derivative contracts
$
(5
)
 
$
56

 
$
(65
)
 
 
 
 
 
 
As of December 31, 2018:
 
 
 
 
 
Not designated as hedging contracts
$
5

 
$
34

 
$
(12
)
Designated as hedging contracts
5

 
37

 
(21
)
Total commodity derivative contracts
$
10

 
$
71

 
$
(33
)

The settled cost of certain of the Company's commodity derivative contracts not designated as hedging contracts is included in regulated rates and, therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose the Company to earnings volatility. Consolidated financial results would be negatively impacted if the costs of wholesale electricity, wholesale natural gas or fuel are higher than what is included in regulated rates, including the impacts of adjustment mechanisms. As of December 31, 2019 and 2018, a net regulatory asset of $77 million and $110 million, respectively, was recorded related to the net derivative asset of $16 million and $5 million, respectively. The difference between the net regulatory asset and the net derivative asset relates primarily to a power purchase agreement derivative at BHE Renewables. For the Company's commodity derivative contracts designated as hedging contracts, net unrealized gains and losses associated with interim price movements on commodity derivative contracts, to the extent the hedge is considered effective, generally do not expose the Company to earnings volatility.


113


Interest Rate Risk

The Company is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt, future debt issuances and mortgage commitments. The Company manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, the Company's fixed-rate long-term debt does not expose the Company to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of the Company's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 9, 10, 11, and 15 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of the Company's short and long-term debt.

As of December 31, 2019 and 2018, the Company had short- and long-term variable-rate obligations totaling $4.8 billion and $4.3 billion, respectively, that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on the Company's consolidated annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2019 and 2018.

The Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, forward sale commitments or mortgage interest rate lock commitments, to mitigate the Company's exposure to interest rate risk. Changes in fair value of agreements designated as cash flow hedges are reported in accumulated other comprehensive income to the extent the hedge is effective until the forecasted transaction occurs. Changes in fair value of agreements not designated as hedging contracts are recognized in earnings. As of December 31, 2019 and 2018, the Company had variable-to-fixed interest rate swaps with notional amounts of $380 million and $637 million, respectively, and £141 million and £161 million, respectively, to protect the Company against an increase in interest rates. Additionally, as of December 31, 2019 and 2018, the Company had mortgage commitments, net, with notional amounts of $913 million and $326 million, respectively, to protect the Company against an increase in interest rates. The fair value of the Company's interest rate derivative contracts was a net derivative liability of $5 million as of December 31, 2019 and a net derivative liability of $8 million as of December 31, 2018. A hypothetical 20 basis point increase and a 20 basis point decrease in interest rates would not have a material impact on the Company.

Equity Price Risk

Market prices for equity securities are subject to fluctuation and consequently the amount realized in the subsequent sale of an investment may significantly differ from the reported market value. Fluctuation in the market price of a security may result from perceived changes in the underlying economic characteristics of the investee, the relative price of alternative investments and general market conditions.

As of December 31, 2019 and 2018, the Company's investment in BYD Company Limited common stock represented approximately 69% and 79%, respectively, of the total fair value of the Company's equity securities. The majority of the Company's remaining equity securities are held in a trust related to the decommissioning of nuclear generation assets and the realized and unrealized gains and losses are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates. The following table summarizes the Company's investment in BYD Company Limited as of December 31, 2019 and 2018 and the effects of a hypothetical 30% increase and a 30% decrease in market price as of those dates. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).

 
 
 
 
 
Estimated
 
Hypothetical
 
 
 
Hypothetical
 
Fair Value after
 
Percentage Increase
 
Fair
 
Price
 
Hypothetical
 
(Decrease) in BHE
 
Value
 
Change
 
Change in Prices
 
Shareholders' Equity
 
 
 
 
 
 
 
 
As of December 31, 2019
$
1,122

 
30% increase
 
$
1,459

 
1
 %
 
 
 
30% decrease
 
785

 
(1
)
 
 
 
 
 
 
 
 
As of December 31, 2018
$
1,435

 
30% increase
 
$
1,866

 
1
 %
 
 
 
30% decrease
 
1,005

 
(1
)

114



Foreign Currency Exchange Rate Risk

BHE's business operations and investments outside of the United States increase its risk related to fluctuations in foreign currency exchange rates primarily in relation to the British pound and the Canadian dollar. BHE's reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from BHE's foreign operations changes with the fluctuations of the currency in which they transact.

Northern Powergrid's functional currency is the British pound. As of December 31, 2019, a 10% devaluation in the British pound to the United States dollar would result in the Company's Consolidated Balance Sheet being negatively impacted by a $452 million cumulative translation adjustment in AOCI. A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for Northern Powergrid of $26 million in 2019.

BHE Canada's functional currency is the Canadian dollar. As of December 31, 2019, a 10% devaluation in the Canadian dollar to the United States dollar would result in the Company's Consolidated Balance Sheet being negatively impacted by a $336 million cumulative translation adjustment in AOCI. A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for BHE Canada of $17 million in 2019.

Credit Risk

Domestic Regulated Operations

The Utilities are exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent the Utilities' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, the Utilities analyze the financial condition of each significant wholesale counterparty, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, the Utilities enter into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, the Utilities exercise rights under these arrangements, including calling on the counterparty's credit support arrangement.

As of December 31, 2019, PacifiCorp's aggregate credit exposure with wholesale energy supply and marketing counterparties included counterparties having non-investment grade, internally rated credit ratings. Substantially all of these non-investment grade, internally rated counterparties are associated with long-duration solar and wind power purchase agreements from facilities that have not yet achieved commercial operation and for which PacifiCorp has no obligation should the facilities not achieve commercial operation.

Substantially all of MidAmerican Energy's electric wholesale sales revenue results from participation in RTOs, including the MISO and the PJM. MidAmerican Energy's share of historical losses from defaults by other RTO market participants has not been material. Additionally, as of December 31, 2019, MidAmerican Energy's aggregate direct credit exposure from electric wholesale marketing counterparties was not material.

As of December 31, 2019, NV Energy's aggregate credit exposure from energy related transactions, based on settlement and mark-to-market exposures, net of collateral, was not material.

Northern Natural Gas' primary customers include utilities in the upper Midwest. Kern River's primary customers are electric and natural gas distribution utilities, major oil and natural gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies and financial institutions. As a general policy, collateral is not required for receivables from creditworthy customers. Customers' financial condition and creditworthiness, as defined by the tariff, are regularly evaluated and historical losses have been minimal. In order to provide protection against credit risk, and as permitted by the separate terms of each of Northern Natural Gas' and Kern River's tariffs, the companies have required customers that lack creditworthiness to provide cash deposits, letters of credit or other security until they meet the creditworthiness requirements of the respective tariff.


115


Northern Powergrid

The Northern Powergrid Distribution Companies charge fees for the use of their distribution systems to supply companies. The supply companies purchase electricity from generators and traders, sell the electricity to end-use customers and use the Northern Powergrid Distribution Companies' distribution networks pursuant to the multilateral "Distribution Connection and Use of System Agreement." The Northern Powergrid Distribution Companies' customers are concentrated in a small number of electricity supply businesses. During 2019, RWE Npower PLC and certain of its affiliates and British Gas Trading Limited represented approximately 17% and 12%, respectively, of the total combined distribution revenue of the Northern Powergrid Distribution Companies. The industry operates in accordance with a framework which sets credit limits for each supply business based on its credit rating or payment history and requires them to provide credit cover if their value at risk (measured as being equivalent to 45 days usage) exceeds the credit limit. Acceptable credit typically is provided in the form of a parent company guarantee, letter of credit or an escrow account. Ofgem has indicated that, provided the Northern Powergrid Distribution Companies have implemented credit control, billing and collection in line with best practice guidelines and can demonstrate compliance with the guidelines or are able to satisfactorily explain departure from the guidelines, any bad debt losses arising from supplier default will be recovered through an increase in future allowed income. Losses incurred to date have not been material.

BHE Canada

AltaLink's primary source of operating revenue is the AESO, an entity rated AA- by Standard and Poor's. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligations would significantly impair AltaLink's ability to meet its existing and future obligations. Total operating revenue for AltaLink was $706 million for the year ended December 31, 2019.

BHE Renewables

BHE Renewables owns independent power projects in the United States and the Philippines that generally have separate project financing agreements. These projects source of operating revenue is derived primarily from long-term power purchase agreements with single customers, primarily utilities, which expire between 2019 and 2043. Because of the dependence generally from a single customer at each project, any material failure of the customer to fulfill its obligations would significantly impair that project's ability to meet its existing and future obligations. On January 29, 2019, a customer of certain BHE Renewables' solar projects filed for chapter 11 bankruptcy protection. See BHE Renewables' Counterparty Risk in Item 7 of this Form 10-K for additional information. Total operating revenue for BHE Renewables was $932 million for the year ended December 31, 2019.

Other Energy Business

MidAmerican Energy Services, LLC ("MES") is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with financial institutions and other market participants. Credit risk may be concentrated to the extent that MES' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, MES analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, MES enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, MES exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

As of December 31, 2019, MES' aggregate credit exposure from energy related transactions, based on settlement and mark-to-market exposures, net of collateral, was not material.


116


Item 8.
Financial Statements and Supplementary Data



117




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and the Shareholders of
Berkshire Hathaway Energy Company
Des Moines, Iowa

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes and the schedules listed in the Index at Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Change in Accounting Principle

As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting for leases in 2019 due to the adoption of ASU 2016-02 "Leases". In 2018, the Company changed its method of accounting for investments in equity securities (excluding equity method investments) due to the adoption of ASU 2016-01 "Financial Instruments - Recognition and Measurement of Financial Assets and Financial Liabilities".

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.




/s/
Deloitte & Touche LLP

Des Moines, Iowa
February 21, 2020

We have served as the Company's auditor since 1991.



118


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)

 
As of December 31,
 
2019
 
2018
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
1,040

 
$
627

Restricted cash and cash equivalents
212

 
227

Trade receivables, net
1,910

 
2,038

Inventories
873

 
844

Mortgage loans held for sale
1,039

 
468

Other current assets
839

 
943

Total current assets
5,913

 
5,147

 
 
 
 
Property, plant and equipment, net
73,305

 
68,087

Goodwill
9,722

 
9,595

Regulatory assets
2,766

 
2,896

Investments and restricted cash and cash equivalents and investments
6,255

 
4,903

Other assets
2,090

 
1,561

 
 
 
 
Total assets
$
100,051

 
$
92,189


The accompanying notes are an integral part of these consolidated financial statements.

119


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)

 
As of December 31,
 
2019
 
2018
LIABILITIES AND EQUITY
Current liabilities:
 
 
 
Accounts payable
$
1,839

 
$
1,809

Accrued interest
493

 
469

Accrued property, income and other taxes
537

 
599

Accrued employee expenses
285

 
275

Short-term debt
3,214

 
2,516

Current portion of long-term debt
2,539

 
2,081

Other current liabilities
1,350

 
1,021

Total current liabilities
10,257

 
8,770

 
 
 
 
BHE senior debt
8,231

 
8,577

BHE junior subordinated debentures
100

 
100

Subsidiary debt
28,483

 
25,492

Regulatory liabilities
7,100

 
7,346

Deferred income taxes
9,653

 
9,047

Other long-term liabilities
3,649

 
3,134

Total liabilities
67,473

 
62,466

 
 
 
 
Commitments and contingencies (Note 16)

 

 
 
 
 
Equity:
 
 
 
BHE shareholders' equity:
 
 
 
Common stock - 115 shares authorized, no par value, 77 shares issued and outstanding

 

Additional paid-in capital
6,389

 
6,371

Long-term income tax receivable
(530
)
 
(457
)
Retained earnings
28,296

 
25,624

Accumulated other comprehensive loss, net
(1,706
)
 
(1,945
)
Total BHE shareholders' equity
32,449

 
29,593

Noncontrolling interests
129

 
130

Total equity
32,578

 
29,723

 
 
 
 

Total liabilities and equity
$
100,051

 
$
92,189


The accompanying notes are an integral part of these consolidated financial statements.

120


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
Operating revenue:
 
 
 
 
 
Energy
$
15,371

 
$
15,573

 
$
15,171

Real estate
4,473

 
4,214

 
3,443

Total operating revenue
19,844

 
19,787

 
18,614

 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
Energy:
 
 
 
 
 
Cost of sales
4,586

 
4,769

 
4,518

Operations and maintenance
3,318

 
3,440

 
3,210

Depreciation and amortization
2,965

 
2,933

 
2,580

Property and other taxes
574

 
573

 
555

Real estate
4,251

 
4,000

 
3,229

Total operating expenses
15,694

 
15,715

 
14,092

 
 
 
 

 
 
Operating income
4,150

 
4,072

 
4,522

 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
Interest expense
(1,912
)
 
(1,838
)
 
(1,841
)
Capitalized interest
77

 
61

 
45

Allowance for equity funds
173

 
104

 
76

Interest and dividend income
117

 
113

 
111

(Losses) gains on marketable securities, net
(288
)
 
(538
)
 
14

Other, net
97

 
(9
)
 
(420
)
Total other income (expense)
(1,736
)
 
(2,107
)
 
(2,015
)
 
 
 
 
 
 
Income before income tax benefit and equity (loss) income
2,414

 
1,965

 
2,507

Income tax benefit
(598
)
 
(583
)
 
(554
)
Equity (loss) income
(44
)
 
43

 
(151
)
Net income
2,968

 
2,591

 
2,910

Net income attributable to noncontrolling interests
18

 
23

 
40

Net income attributable to BHE shareholders
$
2,950

 
$
2,568

 
$
2,870


The accompanying notes are an integral part of these consolidated financial statements.


121


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Net income
$
2,968

 
$
2,591

 
$
2,910

 
 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
 
Unrecognized amounts on retirement benefits, net of tax of
$15, $8 and $9
(59
)
 
25

 
64

Foreign currency translation adjustment
327

 
(494
)
 
546

Unrealized gains on marketable securities, net of tax of
 $-, $- and $270

 

 
500

Unrealized (losses) gains on cash flow hedges, net of tax of
 $8, $1 and $(7)
(29
)
 
7

 
3

Total other comprehensive income (loss), net of tax
239

 
(462
)
 
1,113

 
 
 
 
 
 

Comprehensive income
3,207

 
2,129

 
4,023

Comprehensive income attributable to noncontrolling interests
18

 
23

 
40

Comprehensive income attributable to BHE shareholders
$
3,189

 
$
2,106

 
$
3,983


The accompanying notes are an integral part of these consolidated financial statements.


122


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Amounts in millions)

 
BHE Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
Long-term
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
Additional
 
Income
 
 
 
Other
 
 
 
 
 
Common
 
Paid-in
 
Tax
 
Retained
 
Comprehensive
 
Noncontrolling
 
Total
 
Shares
 
Stock
 
Capital
 
Receivable
 
Earnings
 
Loss, Net
 
Interests
 
Equity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2016
77

 
$

 
$
6,390

 
$

 
$
19,448

 
$
(1,511
)
 
$
136

 
$
24,463

Net income

 

 

 

 
2,870

 

 
22

 
2,892

Other comprehensive loss

 

 

 

 

 
1,113

 

 
1,113

Distributions

 

 

 

 

 

 
(22
)
 
(22
)
Common stock purchases

 

 
(1
)
 

 
(18
)
 

 

 
(19
)
Common stock exchange

 

 
(6
)
 

 
(94
)
 

 

 
(100
)
Other equity transactions

 

 
(15
)
 

 

 

 
(4
)
 
(19
)
Balance, December 31, 2017
77

 

 
6,368

 

 
22,206

 
(398
)
 
132

 
28,308

Adoption of ASU 2016-01

 

 

 

 
1,085

 
(1,085
)
 

 

Net income

 

 

 

 
2,568

 

 
20

 
2,588

Other comprehensive income

 

 

 

 

 
(462
)
 

 
(462
)
Reclassification of long-term
income tax receivable

 

 

 
(609
)
 

 

 

 
(609
)
Long-term income tax
receivable adjustments

 

 

 
152

 
(135
)
 

 

 
17

Common stock purchases

 

 
(6
)
 

 
(101
)
 

 

 
(107
)
Distributions

 

 

 

 

 

 
(23
)
 
(23
)
Other equity transactions

 

 
9

 

 
1

 

 
1

 
11

Balance, December 31, 2018
77

 

 
6,371

 
(457
)
 
25,624

 
(1,945
)
 
130

 
29,723

Net income

 

 

 

 
2,950

 

 
18

 
2,968

Other comprehensive income

 

 

 

 

 
239

 

 
239

Long-term income tax
receivable adjustments

 

 
33

 
(73
)
 

 

 

 
(40
)
Common stock purchases

 

 
(15
)
 

 
(278
)
 

 

 
(293
)
Distributions

 

 


 

 

 

 
(22
)
 
(22
)
Other equity transactions

 

 


 

 

 

 
3

 
3

Balance, December 31, 2019
77

 
$

 
$
6,389

 
$
(530
)
 
$
28,296

 
$
(1,706
)
 
$
129

 
$
32,578


The accompanying notes are an integral part of these consolidated financial statements.


123


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
 
Years Ended December 31,
 
2019
 
2018
 
2017
Cash flows from operating activities:
 
 
 
 
 
Net income
$
2,968

 
$
2,591

 
$
2,910

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
 
 
Losses (gains) on marketable securities, net
288

 
538

 
(14
)
Losses (gains) on other items, net
43

 
56

 
455

Depreciation and amortization
3,011

 
2,984

 
2,646

Allowance for equity funds
(173
)
 
(104
)
 
(76
)
Equity loss (income), net of distributions
93

 
45

 
260

Changes in regulatory assets and liabilities
153

 
196

 
31

Deferred income taxes and amortization of investment tax credits
290

 
8

 
19

Other, net
23

 
67

 
12

Changes in other operating assets and liabilities, net of effects from acquisitions:
 
 
 
 
 
Trade receivables and other assets
(372
)
 
72

 
(74
)
Derivative collateral, net
(25
)
 
27

 
(22
)
Pension and other postretirement benefit plans
(51
)
 
(54
)
 
(91
)
Accrued property, income and other taxes
(16
)
 
199

 
(28
)
Accounts payable and other liabilities
(26
)
 
145

 
50

Net cash flows from operating activities
6,206

 
6,770

 
6,078

 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
Capital expenditures
(7,364
)
 
(6,241
)
 
(4,571
)
Acquisitions, net of cash acquired
(27
)
 
(106
)
 
(1,113
)
Purchases of marketable securities
(262
)
 
(329
)
 
(190
)
Proceeds from sales of marketable securities
238

 
287

 
202

Equity method investments
(1,617
)
 
(683
)
 
(395
)
Other, net
69

 
83

 
(12
)
Net cash flows from investing activities
(8,963
)
 
(6,989
)
 
(6,079
)
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
Proceeds from BHE senior debt

 
3,166

 

Repayments of BHE senior debt and junior subordinated debentures

 
(1,045
)
 
(2,323
)
Common stock purchases
(293
)
 
(107
)
 
(19
)
Proceeds from subsidiary debt
4,699

 
2,352

 
1,763

Repayments of subsidiary debt
(1,914
)
 
(2,422
)
 
(1,000
)
Net proceeds from (repayments of) short-term debt
684

 
(1,946
)
 
2,361

Tender offer premium paid

 

 
(435
)
Purchase of redeemable noncontrolling interest

 
(131
)
 

Other, net
(52
)
 
(41
)
 
(73
)
Net cash flows from financing activities
3,124

 
(174
)
 
274

 
 
 
 
 
 
Effect of exchange rate changes
18

 
(7
)
 
7

 
 
 
 
 
 
Net change in cash and cash equivalents and restricted cash and cash equivalents
385

 
(400
)
 
280

Cash and cash equivalents and restricted cash and cash equivalents at beginning of period
883

 
1,283

 
1,003

Cash and cash equivalents and restricted cash and cash equivalents at end of period
$
1,268

 
$
883

 
$
1,283


The accompanying notes are an integral part of these consolidated financial statements.

124


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)
Organization and Operations

Berkshire Hathaway Energy Company ("BHE") is a holding company that owns a highly diversified portfolio of locally managed businesses principally engaged in the energy industry (collectively with its subsidiaries, the "Company") and is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The Company's operations are organized as eight business segments: PacifiCorp, MidAmerican Funding, LLC ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. ("NV Energy") (which primarily consists of Nevada Power Company ("Nevada Power") and Sierra Pacific Power Company ("Sierra Pacific")), Northern Powergrid Holdings Company ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which consists of Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation ("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, LLC), BHE Renewables and HomeServices of America, Inc. (collectively with its subsidiaries, "HomeServices"). The Company, through these locally managed and operated businesses, owns four utility companies in the United States serving customers in 11 states, two electricity distribution companies in Great Britain, two interstate natural gas pipeline companies in the United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States.

(2)    Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

The Consolidated Financial Statements include the accounts of BHE and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. The Consolidated Statements of Operations include the revenue and expenses of any acquired entities from the date of acquisition. Intercompany accounts and transactions have been eliminated.

Use of Estimates in Preparation of Financial Statements

The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; impairment of goodwill; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; fair value of assets acquired and liabilities assumed in business combinations; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.

Accounting for the Effects of Certain Types of Regulation

PacifiCorp, MidAmerican Energy, Nevada Power, Sierra Pacific, Northern Natural Gas, Kern River and AltaLink (the "Regulated Businesses") prepare their financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Regulated Businesses defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.


125


The Company continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit the Regulated Businesses' ability to recover their costs. The Company believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at the federal, state and provincial levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").

Fair Value Measurements

As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Alternative valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.

Cash Equivalents and Restricted Cash and Cash Equivalents and Investments

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements and debt service obligations for certain of the Company's nonregulated renewable energy projects. Restricted amounts are included in restricted cash and cash equivalents and investments and restricted cash and cash equivalents and investments on the Consolidated Balance Sheets.

Investments

Fixed Maturity Securities

The Company's management determines the appropriate classification of investments in fixed maturity securities at the acquisition date and reevaluates the classification at each balance sheet date. Investments and restricted cash and cash equivalents and investments that management does not intend to use or is restricted from using in current operations are presented as noncurrent on the Consolidated Balance Sheets.

Available-for-sale investments are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. Realized and unrealized gains and losses on fixed maturity securities in a trust related to the decommissioning of nuclear generation assets are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates. Trading investments are carried at fair value with changes in fair value recognized in earnings. Held-to-maturity investments are carried at amortized cost, reflecting the ability and intent to hold the securities to maturity. The difference between the original cost and maturity value of a fixed maturity security is amortized to earnings using the interest method.

Investment gains and losses arise when investments are sold (as determined on a specific identification basis) or are other-than-temporarily impaired with respect to securities classified as available-for-sale. If the value of a fixed maturity investment declines to below amortized cost and the decline is deemed other than temporary, the amortized cost of the investment is reduced to fair value, with a corresponding charge to earnings. Any resulting impairment loss is recognized in earnings if the Company intends to sell, or expects to be required to sell, the debt security before its amortized cost is recovered. If the Company does not expect to ultimately recover the amortized cost basis even if it does not intend to sell the security, the credit loss component is recognized in earnings and any difference between fair value and the amortized cost basis, net of the credit loss, is reflected in other comprehensive income (loss) ("OCI"). For regulated fixed maturity investments, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in regulated rates is probable.


126


Equity Securities

Investments in equity securities are carried at fair value with changes in fair value recognized in earnings as a component of gains (losses) on marketable securities, net. Prior to January 1, 2018, substantially all of the Company's equity security investments were classified as available-for-sale with changes in fair value recognized in OCI, net of income taxes. All changes in fair value of equity securities in a trust related to the decommissioning of nuclear generation assets are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates.

Equity Method Investments

The Company utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when the investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate the ability to exercise significant influence is restricted. In applying the equity method, the Company records the investment at cost and subsequently increases or decreases the carrying value of the investment by the Company's share of the net earnings or losses and OCI of the investee. The Company records dividends or other equity distributions as reductions in the carrying value of the investment. Certain equity investments are presented on the Consolidated Balance Sheets net of related investment tax credits.

Allowance for Doubtful Accounts

Trade receivables are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts. The allowance for doubtful accounts is based on the Company's assessment of the collectability of amounts owed to the Company by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. As of December 31, 2019 and 2018, the allowance for doubtful accounts totaled $44 million and $42 million, respectively, and is included in trade receivables, net on the Consolidated Balance Sheets.

Derivatives

The Company employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price, interest rate, and foreign currency exchange rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets on the Consolidated Balance Sheets.

Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or cost of sales on the Consolidated Statements of Operations.

For the Company's derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For the Company's derivatives not designated as hedging contracts and for which changes in fair value are not recorded as regulatory assets and liabilities, unrealized gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for sales contracts; cost of sales and operating expense for purchase contracts and electricity, natural gas and fuel swap contracts; and other, net for interest rate swap derivatives.

For the Company's derivatives designated as hedging contracts, the Company formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. The Company formally documents hedging activity by transaction type and risk management strategy.


127


Changes in the estimated fair value of a derivative contract designated and qualified as a cash flow hedge, to the extent effective, are included on the Consolidated Statements of Changes in Equity as AOCI, net of tax, until the contract settles and the hedged item is recognized in earnings. The Company discontinues hedge accounting prospectively when it has determined that a derivative contract no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative contract no longer qualifies as an effective hedge, future changes in the estimated fair value of the derivative contract are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the contract settles and the hedged item is recognized in earnings, unless it becomes probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in earnings.

Inventories

Inventories consist mainly of fuel, which includes coal stocks, stored gas and fuel oil, totaling $257 million and $273 million as of December 31, 2019 and 2018, respectively, and materials and supplies totaling $616 million and $571 million as of December 31, 2019 and 2018, respectively. The cost of materials and supplies, coal stocks and fuel oil is determined primarily using the average cost method. The cost of stored gas is determined using either the last-in-first-out ("LIFO") method or the lower of average cost or market. With respect to inventories carried at LIFO cost, the replacement cost would be $2 million and $14 million higher as of December 31, 2019 and 2018, respectively.

Property, Plant and Equipment, Net

General

Additions to property, plant and equipment are recorded at cost. The Company capitalizes all construction-related materials, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include capitalized interest, including debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable to the Regulated Businesses. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. Additionally, MidAmerican Energy has regulatory arrangements in Iowa in which the carrying cost of certain utility plant has been reduced for amounts associated with electric returns on equity exceeding specified thresholds.
 
Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by the Company's various regulatory authorities. Depreciation studies are completed by the Regulated Businesses to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.

Generally when the Company retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.

Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, is capitalized by the Regulated Businesses as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC") and the Alberta Utilities Commission ("AUC"). After construction is completed, the Company is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.


128


Asset Retirement Obligations

The Company recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. The Company's AROs are primarily related to the decommissioning of nuclear generating facilities and obligations associated with its other generating facilities and offshore natural gas pipelines. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. For the Regulated Businesses, the difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.

Impairment

The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. The impacts of regulation are considered when evaluating the carrying value of regulated assets.

Leases

The Company has non-cancelable operating leases primarily for office space, office equipment, generating facilities, land and rail cars and finance leases consisting primarily of transmission assets, generating facilities and vehicles. These leases generally require the Company to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. The Company does not include options in its lease calculations unless there is a triggering event indicating the Company is reasonably certain to exercise the option. The Company’s accounting policy is to not recognize lease obligations and corresponding right-of-use assets for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with ASC 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.

The Company's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.

The Company's operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly. The right-of-use assets and lease liabilities for finance leases as of December 31, 2018 have been reclassified from property, plant and equipment, net and current portion of long-term and subsidiary debt, respectively, to conform to the current period presentation.


129


Goodwill

Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired in business combinations. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31. When evaluating goodwill for impairment, the Company estimates the fair value of the reporting unit. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the identifiable assets, including identifiable intangible assets, and liabilities of the reporting unit are estimated at fair value as of the current testing date. The excess of the estimated fair value of the reporting unit over the current estimated fair value of net assets establishes the implied value of goodwill. The excess of the recorded goodwill over the implied goodwill value is charged to earnings as an impairment loss. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The Company uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. In estimating future cash flows, the Company incorporates current market information, as well as historical factors. As such, the determination of fair value incorporates significant unobservable inputs. During 2019, 2018 and 2017, the Company did not record any material goodwill impairments.

The Company records goodwill adjustments for (a) the tax benefit associated with the excess of tax-deductible goodwill over the reported amount of goodwill and (b) changes to the purchase price allocation prior to the end of the measurement period, which is not to exceed one year from the acquisition date.

Revenue Recognition

Customer Revenue

The Company uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The Company records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations. In the event one of the parties to a contract has performed before the other, the Company would recognize a contract asset or contract liability depending on the relationship between the Company's performance and the customer's payment.

Energy Products and Services

A majority of the Company's energy revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. The Company's energy revenue that is nonregulated primarily relates to the Company's renewable energy business.

Revenue recognized is equal to what the Company has the right to invoice as it corresponds directly with the value to the customer of the Company's performance to date and includes billed and unbilled amounts. As of December 31, 2019 and 2018, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $638 million and $554 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.

Real Estate Services

The Company's HomeServices reportable segment consists of separate brokerage, mortgage and franchise businesses. Rates charged for brokerage, mortgage and franchise real estate services are established through contractual arrangements that establish the transaction price and the allocation of the price amongst the separate performance obligations.


130


The full-service residential real estate brokerage business has performance obligations to deliver integrated real estate services including brokerage services, title and closing services, property and casualty insurance, home warranties, relocation services, and other home-related services to customers. All performance obligations related to the full-service residential real estate brokerage business are satisfied in less than one year at the point in time when a real estate transaction is closed or when services are provided. Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when a real estate transaction is closed. Title and escrow closing fee revenue from real estate transactions and related amounts due to the title insurer are recognized at closing. Payments for amounts billed are generally due from the customer at closing.

The franchise business operates a network that has performance obligations to provide the right to use certain brand names and other related service marks as well as to provide orientation programs, training and consultation services, advertising programs and other services to its franchisees. The performance obligations related to the franchise business are satisfied over time or when the services are provided. Franchise royalty fees are sales-based variable consideration and are based on a percentage of commissions earned by franchisees on real estate sales, which are recognized when the sale closes. Meetings and training revenue, referral fees, late fees, service fees and franchise termination fees are earned when services have been completed. Payments for amounts billed are generally due from the franchisee within 30 days of billing.

Other Revenue

Energy Products and Services

Other revenue consists primarily of revenue related to power purchase agreements not considered Customer Revenue as they are recognized in accordance with Accounting Standards Codification ("ASC") 815, "Derivatives and Hedging" and ASC 842, "Leases" and certain non tariff-based revenue approved by the regulator that is not considered Customer Revenue within ASC 606, "Revenue from Contracts with Customers."

Real Estate Service

Other revenue consists primarily of revenue related to the mortgage business. Mortgage fee revenue consists of amounts earned related to application and underwriting fees, and fees on canceled loans. Fees associated with the origination and acquisition of mortgage loans are recognized as earned. These amounts are not considered Customer Revenue as they are recognized in accordance with ASC 815, "Derivatives and Hedging," ASC 825, "Financial Instruments" and ASC 860, "Transfers and Servicing."

Unamortized Debt Premiums, Discounts and Debt Issuance Costs

Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.

Foreign Currency

The accounts of foreign-based subsidiaries are measured in most instances using the local currency of the subsidiary as the functional currency. Revenue and expenses of these businesses are translated into United States dollars at the average exchange rate for the period. Assets and liabilities are translated at the exchange rate as of the end of the reporting period. Gains or losses from translating the financial statements of foreign-based operations are included in equity as a component of AOCI. Gains or losses arising from transactions denominated in a currency other than the functional currency of the entity that is party to the transaction are included in earnings.

Income Taxes

The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated United States federal and Iowa state income tax returns and the majority of the Company's United States federal income tax is remitted to or received from Berkshire Hathaway. The Company records the deferred income tax assets associated with the state of Iowa net operating loss carryforward as a long-term income tax receivable from Berkshire Hathaway as a component of BHE's shareholders' equity due to the long-term related-party nature of the income tax receivable.


131


Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimated income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities associated with income tax benefits and expense for certain property-related basis differences and other various differences that the Company's regulated businesses deems probable to be passed on to their customers in most state and provincial jurisdictions are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions.

The Company has not established deferred income taxes on its undistributed foreign earnings that have been determined by management to be reinvested indefinitely; however, the Company periodically evaluates its capital requirements. If circumstances change in the future and a portion of the Company's undistributed foreign earnings were repatriated, the dividends may be subject to taxation in the United States but the tax is not expected to be material.

In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory commissions. The Company's income tax returns are subject to continuous examinations by federal, state, local and foreign income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on the Company's consolidated financial results. The Company's unrecognized tax benefits are primarily included in accrued property, income and other taxes and other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.

New Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, which creates FASB Accounting Standards Codification ("ASC") Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize on the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. The Company has elected to utilize various practical expedients available to adopt ASU No. 2016-02, including (1) the package of three not requiring a reassessment of (i) whether any expired or existing contracts are or contain leases; (ii) the lease classification for any expired or existing leases; and (iii) initial direct costs for any existing leases; (2) using hindsight in determining the lease term; and (3) not requiring a reassessment of whether existing or expired land easements that were not previously accounted for as leases under ASC Topic 840 are or contain a lease under ASC Topic 842. The Company adopted this guidance for all applicable contracts in-effect as of January 1, 2019 under a modified retrospective method and the adoption did not have a cumulative effect impact at the date of initial adoption.


132


(3)    Business Acquisitions

The Company completed various acquisitions, which primarily related to residential real estate brokerage businesses and, in 2017, development and construction costs for a110-megawatt ("MW")solar project and a 50-MW solar project and the remaining 25% interest in a natural gas-fueled generation facility at Nevada Power, totaling $27 million in 2019, $106 million in 2018 and $1.1 billion in 2017. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed and the 2017 acquisitions resulted in acquired assets of $1.1 billion, assumed liabilities of $487 million and recognized goodwill of $508 million. The acquired assets, assumed liabilities and recognized goodwill for the 2019 and 2018 acquisitions were not material. Additionally, in April 2018, HomeServices acquired the remaining 33.3% interest in a real estate brokerage franchise business from the noncontrolling interest member at a contractually determined option exercise price totaling $131 million.

(4)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following as of December 31 (in millions):
 
Depreciable
 
 
 
 
 
Life
 
2019
 
2018
Regulated assets:
 
 
 
 
 
Utility generation, transmission and distribution systems
5-80 years
 
$
81,127

 
$
76,707

Interstate natural gas pipeline assets
3-80 years
 
8,165

 
7,524

 
 
 
89,292

 
84,231

Accumulated depreciation and amortization
 
 
(26,353
)
 
(25,894
)
Regulated assets, net
 
 
62,939

 
58,337

 
 
 
 
 
 
Nonregulated assets:
 
 
 
 
 
Independent power plants
5-30 years
 
6,983

 
6,826

Other assets
3-30 years
 
1,834

 
1,424

 
 
 
8,817

 
8,250

Accumulated depreciation and amortization
 
 
(2,183
)
 
(1,610
)
Nonregulated assets, net
 
 
6,634

 
6,640

 
 
 
 
 
 
Net operating assets
 
 
69,573

 
64,977

Construction work-in-progress
 
 
3,732

 
3,110

Property, plant and equipment, net
 
 
$
73,305

 
$
68,087


Construction work-in-progress includes $3.6 billion and $2.9 billion as of December 31, 2019 and 2018, respectively, related to the construction of regulated assets.


(5)
Jointly Owned Utility Facilities

133



Under joint facility ownership agreements, the Domestic Regulated Businesses, as tenants in common, have undivided interests in jointly owned generation, transmission, distribution and pipeline common facilities. The Company accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include the Company's share of the expenses of these facilities.

The amounts shown in the table below represent the Company's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2019 (dollars in millions):
 
 
 
 
 
Accumulated
 
Construction
 
Company
 
Facility In
 
Depreciation and
 
Work-in-
 
Share
 
Service
 
Amortization
 
Progress
PacifiCorp:
 
 
 
 
 
 
 
Jim Bridger Nos. 1-4
67
%
 
$
1,476

 
$
677

 
$
9

Hunter No. 1
94

 
484

 
193

 
1

Hunter No. 2
60

 
305

 
121

 
2

Wyodak
80

 
473

 
243

 
1

Colstrip Nos. 3 and 4
10

 
254

 
137

 
2

Hermiston
50

 
181

 
92

 
5

Craig Nos. 1 and 2
19

 
368

 
252

 

Hayden No. 1
25

 
75

 
39

 

Hayden No. 2
13

 
43

 
23

 

Transmission and distribution facilities
Various
 
808

 
255

 
103

Total PacifiCorp
 
 
4,467

 
2,032

 
123

MidAmerican Energy:
 
 
 
 
 
 
 
Louisa No. 1
88
%
 
834

 
458

 
7

Quad Cities Nos. 1 and 2(1)
25

 
729

 
424

 
11

Walter Scott, Jr. No. 3
79

 
930

 
392

 
5

Walter Scott, Jr. No. 4(2)
60

 
316

 
131

 
1

George Neal No. 4
41

 
316

 
171

 
2

Ottumwa No. 1
52

 
634

 
229

 
19

George Neal No. 3
72

 
489

 
238

 
4

Transmission facilities
Various
 
258

 
95

 

Total MidAmerican Energy
 
 
4,506

 
2,138

 
49

NV Energy:
 
 
 
 
 
 
 
Navajo
11
%
 
13

 
2

 

Valmy
50

 
390

 
271

 

Transmission facilities
Various
 
70

 
29

 

On Line Transmission Line
25

 
159

 
24

 

Total NV Energy
 
 
632

 
326

 

BHE Pipeline Group - common facilities
Various
 
266

 
157

 

Total
 
 
$
9,871

 
$
4,653

 
$
172

(1)
Includes amounts related to nuclear fuel.
(2)
Facility in-service and accumulated depreciation and amortization amounts are net of credits applied under Iowa revenue sharing arrangements totaling $458 million and $94 million, respectively.


134


(6)    Leases

The following table summarizes the Company's leases recorded on the Consolidated Balance Sheet (in millions):
 
As of
 
December 31, 2019
Right-of-use assets:
 
Operating leases
$
525

Finance leases
504

Total right-of-use assets
$
1,029

 
 
Lease liabilities:
 
Operating leases
$
577

Finance leases
519

Total lease liabilities
$
1,096


The following table summarizes the Company's lease costs (in millions):
 
Year Ended
 
December 31, 2019
 
 
Variable
$
623

Operating
170

Finance:
 
Amortization
16

Interest
41

Short-term
7

Total lease costs
$
857

 
 
Weighted-average remaining lease term (years):
 
Operating leases
7.6

Finance leases
28.8

 
 
Weighted-average discount rate:
 
Operating leases
5.2
%
Finance leases
8.6
%

The following table summarizes the Company's supplemental cash flow information relating to leases (in millions):
 
Year Ended
 
December 31, 2019
 
 
Cash paid for amounts included in the measurement of lease liabilities:
 
Operating cash flows from operating leases
$
(153
)
Operating cash flows from finance leases
(42
)
Financing cash flows from finance leases
(19
)
Right-of-use assets obtained in exchange for lease liabilities:
 
Operating leases
$
82

Finance leases
14



135


The Company has the following remaining lease commitments as of (in millions):
 
December 31, 2019
 
Operating
 
Finance
 
Total
2020
$
147

 
$
71

 
$
218

2021
126

 
77

 
203

2022
102

 
70

 
172

2023
73

 
59

 
132

2024
50

 
59

 
109

Thereafter
202

 
725

 
927

Total undiscounted lease payments
700

 
1,061

 
1,761

Less - amounts representing interest
(123
)
 
(542
)
 
(665
)
Lease liabilities
$
577

 
$
519

 
$
1,096

 
December 31, 2018(1)
 
Operating
 
Capital
 
Total
2019
$
147

 
$
69

 
$
216

2020
128

 
68

 
196

2021
110

 
73

 
183

2022
87

 
67

 
154

2023
61

 
56

 
117

Thereafter
159

 
772

 
931

Total undiscounted lease payments
$
692

 
$
1,105

 
$
1,797


(1)     Amounts included for comparability and accounted for in accordance with ASC 840, "Leases".


136


(7)    Regulatory Matters

Regulatory Assets

Regulatory assets represent costs that are expected to be recovered in future regulated rates. The Company's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
 
Weighted
 
 
 
 
 
Average
 
 
 
 
 
Remaining Life
 
2019
 
2018
 
 
 
 
 
 
Employee benefit plans(1)
15 years
 
$
667

 
$
773

Asset retirement obligations
Various
 
445

 
375

Asset disposition costs
Various
 
391

 
358

Deferred income taxes(2)
Various
 
223

 
196

Deferred operating costs
11 years
 
134

 
141

Deferred net power costs
2 years
 
110

 
103

Unrealized loss on regulated derivative contracts
3 years
 
78

 
120

Unamortized contract values
4 years
 
60

 
79

Abandoned projects
3 years
 
58

 
134

Other
Various
 
715

 
788

Total regulatory assets
 
 
$
2,881

 
$
3,067

 
 
 
 
 
 
Reflected as:
 
 
 
 
 
Current assets
 
 
$
115

 
$
171

Noncurrent assets
 
 
2,766

 
2,896

Total regulatory assets
 
 
$
2,881

 
$
3,067

(1)
Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
(2)
Amounts primarily represent income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.

The Company had regulatory assets not earning a return on investment of $1.4 billion and $1.3 billion as of December 31, 2019 and 2018, respectively.


137


Regulatory Liabilities

Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. The Company's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
 
Weighted
 
 
 
 
 
Average
 
 
 
 
 
Remaining Life
 
2019
 
2018
 
 
 
 
 
 
Deferred income taxes(1)
Various
 
$
3,611

 
$
3,923

Cost of removal(2)
27 years
 
2,370

 
2,426

Levelized depreciation
29 years
 
304

 
329

Asset retirement obligations
33 years
 
241

 
163

Impact fees
2 years
 
72

 
88

Other
Various
 
713

 
577

Total regulatory liabilities
 
 
$
7,311

 
$
7,506

 
 
 
 
 
 
Reflected as:
 
 
 
 
 
Current liabilities
 
 
$
211

 
$
160

Noncurrent liabilities
 
 
7,100

 
7,346

Total regulatory liabilities
 
 
$
7,311

 
$
7,506


(1)
Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse. See Note 12 for further discussion of 2017 Tax Reform impacts.
(2)
Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.

138


(8)    Investments and Restricted Cash and Cash Equivalents and Investments

Investments and restricted cash and cash equivalents and investments consists of the following as of December 31 (in millions):
 
2019
 
2018
Investments:
 
 
 
BYD Company Limited common stock
$
1,122

 
$
1,435

Rabbi trusts
410

 
371

Other
187

 
168

Total investments
1,719

 
1,974

 
 
 
 
Equity method investments:
 
 
 
BHE Renewables tax equity investments
3,130

 
1,661

Electric Transmission Texas, LLC
555

 
527

Bridger Coal Company
81

 
99

Other
181

 
153

Total equity method investments
3,947

 
2,440

 
 
 
 
Restricted cash and cash equivalents and investments:
 
 
 
Quad Cities Station nuclear decommissioning trust funds
599

 
504

Other restricted cash and cash equivalents
230

 
256

Total restricted cash and cash equivalents and investments
829

 
760

 
 
 
 
Total investments and restricted cash and cash equivalents and investments
$
6,495

 
$
5,174

 
 
 
 
Reflected as:
 
 
 
Other current assets
$
240

 
$
271

Noncurrent assets
6,255

 
4,903

Total investments and restricted cash and cash equivalents and investments
$
6,495

 
$
5,174


Investments

BHE's investment in BYD Company Limited common stock is accounted for as a marketable security with changes in fair value recognized in net income.

Rabbi trusts primarily hold corporate-owned life insurance on certain current and former key executives and directors. The Rabbi trusts were established to hold investments used to fund the obligations of various nonqualified executive and director compensation plans and to pay the costs of the trusts. The amount represents the cash surrender value of all of the policies included in the Rabbi trusts, net of amounts borrowed against the cash surrender value.

(Losses) gains on marketable securities, net recognized during the period consists of the following (in millions):
 
Years Ended December 31,
 
2019
 
2018
Unrealized losses recognized on marketable securities still held at the reporting date
$
(290
)
 
$
(540
)
Net gains recognized on marketable securities sold during the period
2

 
2

Losses on marketable securities, net
$
(288
)
 
$
(538
)


139


Equity Method Investments

The Company has invested in projects sponsored by third parties, commonly referred to as tax equity investments. Under the terms of these tax equity investments, the Company has entered into equity capital contribution agreements with the project sponsors that require contributions. The Company has made contributions of $1,619 million, $698 million and $403 million in 2019, 2018 and 2017, respectively, and has commitments as of December 31, 2019, subject to satisfaction of certain specified conditions, to provide equity contributions of $2.4 billion in 2020 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.

BHE, through a subsidiary, owns 50% of Electric Transmission Texas, LLC, which owns and operates electric transmission assets in the Electric Reliability Council of Texas footprint. BHE, through a subsidiary, owns 66.67% of Bridger Coal Company ("Bridger Coal"), which is a coal mining joint venture that supplies coal to the Jim Bridger Nos. 1-4 generating facility. Bridger Coal is being accounted for under the equity method of accounting as the power to direct the activities that most significantly impact Bridger Coal's economic performance are shared with the joint venture partner. See Note 12 for discussion of 2017 Tax Reform impacts to equity earnings recorded for the year ended December 31, 2017.

Restricted Investments

MidAmerican Energy has established a trust for the investment of funds for decommissioning the Quad Cities Nuclear Station Units 1 and 2 ("Quad Cities Station"). These investments in debt and equity securities are reported at fair value. Funds are invested in the trust in accordance with applicable federal and state investment guidelines and are restricted for use as reimbursement for costs of decommissioning the Quad Cities Station, which are currently licensed for operation until December 2032.

(9)    Short-Term Debt and Credit Facilities

The following table summarizes BHE's and its subsidiaries' availability under their credit facilities as of December 31 (in millions):
 
 
 
 
 
MidAmerican
 
NV
 
Northern
 
BHE
 
 
 
 
 
BHE
 
PacifiCorp
 
Funding
 
Energy
 
Powergrid
 
Canada
 
Other
 
Total(1)
2019:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Credit facilities
$
3,500

 
$
1,200

 
$
1,309

 
$
650

 
$
199

 
$
674

 
$
1,880

 
$
9,412

Less:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-term debt
(1,590
)
 
(130
)
 

 

 

 
(211
)
 
(1,283
)
 
(3,214
)
Tax-exempt bond support and letters of credit

 
(256
)
 
(370
)
 

 

 
(3
)
 

 
(629
)
Net credit facilities
$
1,910

 
$
814

 
$
939

 
$
650

 
$
199

 
$
460

 
$
597

 
$
5,569

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2018:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Credit facilities(2)
$
3,500

 
$
1,200

 
$
1,309

 
$
650

 
$
231

 
$
639

 
$
1,585

 
$
9,114

Less:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-term debt
(983
)
 
(30
)
 
(240
)
 

 
(77
)
 
(345
)
 
(841
)
 
(2,516
)
Tax-exempt bond support and letters of credit

 
(89
)
 
(370
)
 
(80
)
 

 
(4
)
 

 
(543
)
Net credit facilities
$
2,517

 
$
1,081

 
$
699

 
$
570

 
$
154

 
$
290

 
$
744

 
$
6,055

(1)
The table does not include unused credit facilities and letters of credit for investments that are accounted for under the equity method.
(2)    Includes the drawn uncommitted credit facilities totaling $39 million at Northern Powergrid.

As of December 31, 2019, the Company was in compliance with the covenants of its credit facilities and letter of credit arrangements.

BHE

BHE has a $3.5 billion unsecured credit facility expiring in June 2022 with one remaining one-year extension option subject to lender consent. This credit facility, which is for general corporate purposes, supports BHE's commercial paper program and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at BHE's option, plus a spread that varies based on BHE's credit ratings for its senior unsecured long-term debt securities.

140



As of December 31, 2019 and 2018, the weighted average interest rate on commercial paper borrowings outstanding was 1.91% and 2.76%, respectively. This credit facility requires that BHE's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.70 to 1.0 as of the last day of each quarter.

As of December 31, 2019 and 2018, BHE had $107 million and $115 million, respectively, of letters of credit outstanding. These letters of credit primarily support power purchase agreements and debt service requirements at certain subsidiaries of BHE Renewables, LLC expiring through April 2021 and have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.

PacifiCorp

PacifiCorp has a $600 million unsecured credit facility expiring in June 2022 and a $600 million unsecured credit facility expiring in June 2022 with one remaining one-year extension option subject to lender consent. These credit facilities, which support PacifiCorp's commercial paper program, certain series of its tax-exempt bond obligations and provide for the issuance of letters of credit, have variable interest rates based on the Eurodollar rate or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities.

As of December 31, 2019 and 2018, the weighted average interest rate on commercial paper borrowings outstanding was 2.05% and 2.85%, respectively. These credit facilities require that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.

As of December 31, 2019 and 2018, PacifiCorp had $13 million and $184 million, respectively, of fully available letters of credit issued under committed arrangements. As of December 31, 2019 and 2018, $13 million and $14 million, respectively, support certain transactions required by third parties and generally have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.

MidAmerican Funding

MidAmerican Energy has a $900 million unsecured credit facility expiring in June 2022. The credit facility supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations, provides for the issuance of letters of credit and has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. MidAmerican Energy has a $400 million unsecured credit facility that expires in August 2020 and has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread. As of December 31, 2018, MidAmerican Energy had a $400 million unsecured credit facility expiring November 2019, which it terminated in January 2019.

MidAmerican Energy had commercial paper borrowings outstanding of $- million as of December 31, 2019, and $240 million with a weighted average interest rate of 2.49% as of December 31, 2018. The credit facility requires that MidAmerican Energy's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.

NV Energy

Nevada Power has a $400 million secured credit facility expiring in June 2022 and Sierra Pacific has a $250 million secured credit facility expiring in June 2022. These credit facilities, which are for general corporate purposes and provide for the issuance of letters of credit, have a variable interest rate based on the Eurodollar rate or a base rate, at each of the Nevada Utilities' option, plus a spread that varies based on each of the Nevada Utilities' credit ratings for its senior secured long‑term debt securities. Amounts due under each credit facility are collateralized by each of the Nevada Utilities' general and refunding mortgage bonds. These credit facilities require that each of the Nevada Utilities' ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.

Northern Powergrid

Northern Powergrid has a £150 million unsecured credit facility expiring in October 2022. The credit facility has a variable interest rate based on sterling London Interbank Offered Rate ("LIBOR") plus a spread that varies based on its credit ratings. The credit facility requires that the ratio of consolidated senior total net debt, including current maturities, to regulated asset value not exceed 0.8 to 1.0 at Northern Powergrid and 0.65 to 1.0 at Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc as of June 30 and December 31. Northern Powergrid's interest coverage ratio shall not be less than 2.5 to 1.0.

141



AltaLink

AltaLink has a C$500 million secured revolving term credit facility expiring in December 2023 with a recurring one-year extension option subject to lender consent. The credit facility, which provides support for borrowings under the unsecured commercial paper program and may also be used for general corporate purposes, has a variable interest rate based on the Canadian bank prime lending rate or a spread above the Bankers' Acceptance rate, at AltaLink's option, based on AltaLink's credit ratings for its senior secured long-term debt securities. In addition, AltaLink has a C$75 million secured revolving term credit facility expiring in December 2023 with a recurring one-year extension option subject to lender consent. The credit facility, which may be used for general corporate purposes and letters of credit, has a variable interest rate based on the Canadian bank prime lending rate, United States base rate, a spread above the United States LIBOR loan rate or a spread above the Bankers' Acceptance rate, at AltaLink's option, based on AltaLink's credit ratings for its senior secured long-term debt securities.

As of December 31, 2019 and 2018, AltaLink had $192 million and $281 million outstanding under these facilities at a weighted average interest rate of 2.16% and 2.26%, respectively. The credit facilities require the consolidated indebtedness to total capitalization not exceed 0.75 to 1.0 measured as of the last day of each quarter.

AltaLink Investments, L.P. has a C$300 million unsecured revolving term credit facility expiring in December 2023 with a recurring one-year extension option subject to lender consent. The credit facility, which may be used for general corporate purposes and letters of credit to a maximum of C$10 million, has a variable interest rate based on the Canadian bank prime lending rate, United States base rate, a spread above the United States LIBOR loan rate or a spread above the Bankers' Acceptance rate, at AltaLink Investments, L.P.'s option, based on AltaLink Investments, L.P.'s credit ratings for its senior unsecured long-term debt securities. 

As of December 31, 2019 and 2018, AltaLink Investments, L.P. had $19 million and $64 million outstanding under this facility at a weighted average interest rate of 3.08% and 3.25%, respectively. The credit facility requires the consolidated total debt to capitalization to not exceed 0.8 to 1.0 and earnings before interest, taxes, depreciation and amortization to interest expense for the four fiscal quarters ended to not be less than 2.25 to 1.0 measured as of the last day of each quarter.

In January 2020, AltaLink and AltaLink Investments, L.P. extended, with lender consent, the expiration dates for the existing credit facilities to December 2024.

HomeServices

HomeServices has a $600 million unsecured credit facility expiring in September 2022. The credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the LIBOR or a base rate, at HomeServices' option, plus a spread that varies based on HomeServices' total net leverage ratio as of the last day of each quarter. As of December 31, 2019 and 2018, HomeServices had $318 million and $404 million, respectively, outstanding under its credit facility with a weighted average interest rate of 3.29% and 3.94%, respectively.

Through its subsidiaries, HomeServices maintains mortgage lines of credit totaling $1.3 billion and $985 million as of December 31, 2019 and 2018, respectively, used for mortgage banking activities that expire beginning in January 2020 through December 2020. The mortgage lines of credit have variable rates based on LIBOR plus a spread. Collateral for these credit facilities is comprised of residential property being financed and is equal to the loans funded with the facilities. As of December 31, 2019 and 2018, HomeServices had $965 million and $436 million, respectively, outstanding under these mortgage lines of credit at a weighted average interest rate of 3.51% and 4.42%, respectively.

BHE Renewables Letters of Credit

As of December 31, 2019 and 2018, certain renewable projects collectively have letters of credit outstanding of $373 million and $322 million, respectively, primarily in support of the power purchase agreements and large generator interconnection agreements associated with the projects.


142


(10)
BHE Debt

Senior Debt

BHE senior debt represents unsecured senior obligations of BHE that are redeemable in whole or in part at any time generally with make-whole premiums. BHE senior debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (in millions):
 
Par Value
 
2019
 
2018
 
 
 
 
 
 
2.40% Senior Notes, due 2020
$
350

 
$
349

 
$
349

2.375% Senior Notes, due 2021
450

 
448

 
448

2.80% Senior Notes, due 2023
400

 
398

 
398

3.75% Senior Notes, due 2023
500

 
498

 
498

3.50% Senior Notes, due 2025
400

 
398

 
398

3.25% Senior Notes, due 2028
600

 
594

 
594

8.48% Senior Notes, due 2028
256

 
259

 
257

6.125% Senior Bonds, due 2036
1,670

 
1,661

 
1,661

5.95% Senior Bonds, due 2037
550

 
548

 
547

6.50% Senior Bonds, due 2037
225

 
223

 
222

5.15% Senior Notes, due 2043
750

 
740

 
740

4.50% Senior Notes, due 2045
750

 
738

 
738

3.80% Senior Notes, due 2048
750

 
737

 
737

4.45% Senior Notes, due 2049
1,000

 
990

 
990

Total BHE Senior Debt
$
8,651

 
$
8,581

 
$
8,577

 
 
 
 
 
 
Reflected as:
 
 
 
 
 
Current liabilities
 
 
$
350

 
$

Noncurrent liabilities
 
 
8,231

 
8,577

Total BHE Senior Debt
 
 
$
8,581

 
$
8,577


Junior Subordinated Debentures

BHE junior subordinated debentures consists of the following as of December 31 (in millions):
 
Par Value
 
2019
 
2018
 
 
 
 
 
 
Junior subordinated debentures, due 2057
100

 
100

 
100

Total BHE junior subordinated debentures - noncurrent
$
100

 
$
100

 
$
100


In June 2017, BHE issued $100 million of its 5.00% junior subordinated debentures due June 2057 in exchange for 181,819 shares of BHE no par value common stock held by a minority shareholder. The junior subordinated debentures are redeemable at BHE's option at any time from and after June 15, 2037, at par plus accrued and unpaid interest. Interest expense to the minority shareholder was $5 million for each of the years ended December 31, 2019 and 2018.


143


(11)    Subsidiary Debt

BHE's direct and indirect subsidiaries are organized as legal entities separate and apart from BHE and its other subsidiaries. Pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties; the equity interest of MidAmerican Funding's subsidiary; MidAmerican Energy's electric utility properties in the state of Iowa; substantially all of Nevada Power's and Sierra Pacific's properties in the state of Nevada; AltaLink's transmission properties; and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of solar and wind generation projects are pledged or encumbered to support or otherwise provide the security for their related subsidiary debt. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The long-term debt of BHE's subsidiaries may include provisions that allow BHE's subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums.

Distributions at these separate legal entities are limited by various covenants including, among others, leverage ratios, interest coverage ratios and debt service coverage ratios. As of December 31, 2019, all subsidiaries were in compliance with their long-term debt covenants. On January 29, 2019, PG&E Corporation and Pacific Gas and Electric Company (the "PG&E Utility") (together "PG&E") filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Northern District of California. As a result, the Company does not expect to receive distributions from Topaz Solar Farms LLC ("Topaz") or Agua Caliente Solar, LLC ("Agua Caliente") in the near term.

Long-term debt of subsidiaries consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (in millions):
 
Par Value
 
2019
 
2018
 
 
 
 
 
 
PacifiCorp
$
7,705

 
$
7,658

 
$
7,015

MidAmerican Funding
7,515

 
7,427

 
5,597

NV Energy
3,836

 
3,821

 
3,817

Northern Powergrid
3,234

 
3,221

 
2,626

BHE Pipeline Group
1,250

 
1,247

 
1,042

BHE Transmission
3,891

 
3,879

 
3,842

BHE Renewables
3,239

 
3,206

 
3,401

HomeServices
213

 
213

 
233

Total subsidiary debt
$
30,883

 
$
30,672

 
$
27,573

 
 
 
 
 
 
Reflected as:
 
 
 
 
 
Current liabilities
 
 
$
2,189

 
$
2,081

Noncurrent liabilities
 
 
28,483

 
25,492

Total subsidiary debt
 
 
$
30,672

 
$
27,573



144


PacifiCorp

PacifiCorp's long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs as of December 31 (dollars in millions):
 
Par Value
 
2019
 
2018
First mortgage bonds:
 
 
 
 
 
2.95% to 8.53%, due through 2024
$
1,899

 
$
1,895

 
$
2,244

3.35% to 6.71%, due 2025 to 2026
350

 
349

 
348

3.50% to 7.70%, due 2029 to 2031
700

 
696

 
298

5.25% to 6.35%, due 2034 to 2038
2,350

 
2,338

 
2,338

4.10% to 6.00%, due 2039 to 2042
950

 
939

 
939

4.13% to 4.15%, due 2049 to 2050
1,200

 
1,186

 
593

Variable-rate series, tax-exempt bond obligations (2019-1.60% to 1.80%; 2018-1.67% to 1.85%):
 
 
 
 
 
Due 2020
38

 
38

 
38

Due 2024(1)(2)
143

 
143

 
142

Due 2025(1)
25

 
24

 
25

Due 2024 to 2025(2)
50

 
50

 
50

Total PacifiCorp
$
7,705

 
$
7,658

 
$
7,015


(1)
Supported by $170 million of fully available letters of credit issued under committed bank arrangements as of December 31, 2018. These arrangements were canceled in 2019.
(2)
Secured by pledged first mortgage bonds registered to and held by the tax-exempt bond trustee generally with the same interest rates, maturity dates and redemption provisions as the tax-exempt bond obligations.

The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's mortgage. Approximately $29 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage as of December 31, 2019.


145


MidAmerican Funding

MidAmerican Funding's long-term debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
 
Par Value
 
2019
 
2018
MidAmerican Funding:
 
 
 
 
 
6.927% Senior Bonds, due 2029
$
239

 
$
219

 
$
217

 
 
 
 
 
 
MidAmerican Energy:
 
 
 
 
 
Tax-exempt bond obligations -
 
 
 
 
 
Variable-rate tax-exempt bond obligation series: (weighted average interest rate- 2019-1.66%, 2018-1.74%), due 2023-2047
$
370

 
$
368

 
$
368

First Mortgage Bonds:
 
 
 
 
 
2.40%, due 2019

 

 
500

3.70%, due 2023
250

 
249

 
249

3.50%, due 2024
500

 
501

 
501

3.10%, due 2027
375

 
373

 
372

3.65%, due 2029
850

 
864

 

4.80%, due 2043
350

 
346

 
346

4.40%, due 2044
400

 
395

 
394

4.25%, due 2046
450

 
445

 
445

3.95%, due 2047
475

 
470

 
470

3.65%, due 2048
700

 
688

 
688

4.25%, due 2049
900

 
872

 

3.15%, due 2050
600

 
591

 

Notes:
 
 
 
 
 
6.75% Series, due 2031
400

 
396

 
396

5.75% Series, due 2035
300

 
298

 
298

5.80% Series, due 2036
350

 
348

 
348

Transmission upgrade obligation, 4.45% and 3.42% due through 2035 and 2036, respectively
6

 
4

 
5

Total MidAmerican Energy
7,276

 
7,208

 
5,380

Total MidAmerican Funding
$
7,515

 
$
7,427

 
$
5,597


Pursuant to MidAmerican Energy's mortgage dated September 9, 2013, as amended by the First Supplemental Indenture dated as of September 19, 2013, MidAmerican Energy's first mortgage bonds, currently and from time to time outstanding, are secured by a first mortgage lien on substantially all of its electric generating, transmission and distribution property within the state of Iowa, subject to certain exceptions and permitted encumbrances. As of December 31, 2019, MidAmerican Energy's eligible property subject to the lien of the mortgage totaled approximately $20 billion based on original cost. Additionally, MidAmerican Energy's senior notes outstanding are equally and ratably secured with the first mortgage bonds as required by the indentures under which the senior notes were issued.

MidAmerican Energy's variable-rate tax-exempt obligations bear interest at rates that are periodically established through remarketing of the bonds in the short-term tax-exempt market. MidAmerican Energy, at its option, may change the mode of interest calculation for these bonds by selecting from among several floating or fixed rate alternatives. The interest rates shown in the table above are the weighted average interest rates as of December 31, 2019 and 2018. MidAmerican Energy maintains revolving credit facility agreements to provide liquidity for holders of these issues and $180 million of the variable rate, tax-exempt bonds are secured by an equal amount of first mortgage bonds pursuant to MidAmerican Energy's mortgage dated September 9, 2013, as supplemented and amended.


146


NV Energy

NV Energy's long-term debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
 
Par Value
 
2019
 
2018
NV Energy:
 
 
 
 
 
6.250% Senior Notes, due 2020
$
315

 
$
321

 
$
330

 
 
 
 
 
 
Nevada Power:
 
 
 
 
 
General and refunding mortgage securities:
 
 
 
 
 
7.125% Series V, due 2019

 

 
500

2.750%, Series BB, due 2020
575

 
575

 
574

3.700%, Series CC, due 2029
500

 
496

 

6.650% Series N, due 2036
367

 
360

 
360

6.750% Series R, due 2037
349

 
348

 
348

5.375% Series X, due 2040
250

 
249

 
248

5.450% Series Y, due 2041
250

 
245

 
244

Tax-exempt refunding revenue bond obligations:
 
 
 
 
 
Fixed-rate series:
 
 
 
 
 
1.800% Pollution Control Bonds Series 2017A, due 2032(1)
40

 
39

 
40

1.600% Pollution Control Bonds Series 2017, due 2036(1)
40

 
39

 
39

1.600% Pollution Control Bonds Series 2017B, due 2039(1)
13

 
13

 
13

Total Nevada Power
2,384

 
2,364

 
2,366

 
 
 
 
 
 
Sierra Pacific:
 
 
 
 
 
General and refunding mortgage securities:
 
 
 
 
 
3.375% Series T, due 2023
250

 
249

 
249

2.600% Series U, due 2026
400

 
396

 
396

6.750% Series P, due 2037
252

 
256

 
256

Tax-exempt refunding revenue bond obligations:
 
 
 
 
 
Fixed-rate series:
 
 
 
 
 
1.250% Pollution Control Series 2016A, due 2029

 

 
20

1.850% Pollution Control Series 2016B, due 2029(2)
30

 
29

 

1.500% Gas Facilities Series 2016A, due 2031

 

 
58

3.000% Gas and Water Series 2016B, due 2036(3)
60

 
62

 
62

1.850% Water Facilities Series 2016C, due 2036(4)

 

 
30

2.050% Water Facilities Series 2016D, due 2036(2)(5)
25

 
25

 
25

2.050% Water Facilities Series 2016E, due 2036(2)(5)
25

 
25

 
25

2.050% Water Facilities Series 2016F, due 2036(2)
75

 
74

 

1.850% Water Facilities Series 2016G, due 2036(2) 
20

 
20

 

Total Sierra Pacific
1,137

 
1,136

 
1,121

Total NV Energy
$
3,836

 
$
3,821

 
$
3,817


(1)    Subject to mandatory purchase by Nevada Power in May 2020 at which date the interest rate may be adjusted from time to time.
(2)    Subject to mandatory purchase by Sierra Pacific in April 2022 at which date the interest rate may be adjusted from time to time.
(3)    Subject to mandatory purchase by Sierra Pacific in June 2022 at which date the interest rate may be adjusted from time to time.
(4)    Bond was purchased by Sierra Pacific during 2019. As of December 31, 2018 the bond variable interest rate was 1.750% to 1.820%.
(5)    Bonds were purchased by Sierra Pacific during 2019 and re-offered at a fixed interest rate. As of December 31, 2018 the bonds variable interest rate
was 1.750% to 1.820%.

147


In January 2020, Nevada Power issued $425 million of its 2.400% General and Refunding Mortgage Notes, Series DD, due May 2030 and issued $300 million of its 3.125% General and Refunding Mortgage Notes, Series EE, due August 2050. Nevada Power intends to use the net proceeds from the sale of the Notes to repay $575 million aggregate principal amount of its 2.750% General and Refunding Mortgage Notes, Series BB, maturing in April 2020 and for general corporate purposes.

In January 2020, Nevada Power issued a 30-day notice of early redemption to repay $575 million of its 2.750% General and Refunding Mortgage Notes, Series BB.

The issuance of General and Refunding Mortgage Securities by the Nevada Utilities are subject to PUCN approval and are limited by available property and other provisions of the mortgage indentures for each of Nevada Power and Sierra Pacific. As of December 31, 2019, approximately $8.7 billion of Nevada Power's and $4.2 billion of Sierra Pacific's (based on original cost) property was subject to the liens of the mortgages.

Northern Powergrid

Northern Powergrid and its subsidiaries' long-term debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
 
Par Value(1)
 
2019
 
2018
 
 
 
 
 
 
8.875% Bonds, due 2020
$
133

 
$
135

 
$
133

9.25% Bonds, due 2020
265

 
265

 
260

4.133% to 4.586% European Investment Bank loans, due 2019 to 2022
251

 
252

 
293

7.25% Bonds, due 2022
265

 
270

 
262

2.50% Bonds, due 2025
199

 
197

 
189

2.073% European Investment Bank loan, due 2025
66

 
68

 
65

2.564% European Investment Bank loans, due 2027
332

 
330

 
318

7.25% Bonds, due 2028
246

 
250

 
241

4.375% Bonds, due 2032
199

 
196

 
188

5.125% Bonds, due 2035
265

 
262

 
252

5.125% Bonds, due 2035
199

 
197

 
189

2.750% Bonds, due 2049
199

 
196

 

2.250% Bonds, due 2059
398

 
389

 

Variable-rate bond, due 2026(2)
217

 
214

 
236

Total Northern Powergrid
$
3,234

 
$
3,221

 
$
2,626


(1)
The par values for these debt instruments are denominated in sterling.
(2)
Amortizes semiannually and the Company has entered into an interest rate swap that fixes the interest rate on 86% of the outstanding debt. The variable interest rate as of December 31, 2019 was 2.54% while the fixed interest rate was 2.82%.

BHE Pipeline Group

BHE Pipeline Group's long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
 
Par Value
 
2019
 
2018
Northern Natural Gas:
 
 
 
 
 
4.25% Senior Notes, due 2021
$
200

 
$
200

 
$
199

5.80% Senior Bonds, due 2037
150

 
149

 
149

4.10% Senior Bonds, due 2042
250

 
248

 
248

4.30% Senior Bonds, due 2049
650

 
650

 
446

Total BHE Pipeline Group
$
1,250

 
$
1,247

 
$
1,042



148


BHE Transmission

BHE Transmission's long-term debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
 
Par Value(1)
 
2019
 
2018
AltaLink Investments, L.P.:
 
 
 
 
 
Series 12-1 Senior Bonds, 3.674%, due 2019
$

 
$

 
$
148

Series 13-1 Senior Bonds, 3.265%, due 2020
154

 
154

 
148

Series 15-1 Senior Bonds, 2.244%, due 2022
154

 
154

 
146

Total AltaLink Investments, L.P.
308

 
308

 
442

 
 
 
 
 
 
AltaLink, L.P.:
 
 
 
 
 
Series 2013-2 Notes, 3.621%, due 2020
96

 
96

 
92

Series 2012-2 Notes, 2.978%, due 2022
212

 
212

 
201

Series 2013-4 Notes, 3.668%, due 2023
385

 
384

 
366

Series 2014-1 Notes, 3.399%, due 2024
269

 
269

 
256

Series 2016-1 Notes, 2.747%, due 2026
269

 
269

 
255

Series 2006-1 Notes, 5.249%, due 2036
115

 
115

 
109

Series 2010-1 Notes, 5.381%, due 2040
96

 
96

 
91

Series 2010-2 Notes, 4.872%, due 2040
115

 
115

 
109

Series 2011-1 Notes, 4.462%, due 2041
212

 
211

 
201

Series 2012-1 Notes, 3.990%, due 2042
404

 
398

 
380

Series 2013-3 Notes, 4.922%, due 2043
269

 
268

 
256

Series 2014-3 Notes, 4.054%, due 2044
227

 
226

 
215

Series 2015-1 Notes, 4.090%, due 2045
269

 
268

 
255

Series 2016-2 Notes, 3.717%, due 2046
346

 
345

 
328

Series 2013-1 Notes, 4.446%, due 2053
192

 
192

 
183

Series 2014-2 Notes, 4.274%, due 2064
100

 
100

 
95

Total AltaLink, L.P.
3,576

 
3,564

 
3,392

 
 
 
 
 
 
Other:
 
 
 
 
 
Construction Loan, 5.620%, due 2020
7

 
7

 
8

 
 
 
 
 
 
Total BHE Transmission
$
3,891

 
$
3,879

 
$
3,842


(1)
The par values for these debt instruments are denominated in Canadian dollars.


149


BHE Renewables

BHE Renewables' long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
 
Par Value
 
2019
 
2018
Fixed-rate(1):
 
 
 
 
 
Bishop Hill Holdings Senior Notes, 5.125%, due 2032
$
78

 
$
77

 
$
84

Solar Star Funding Senior Notes, 3.950%, due 2035
283

 
280

 
292

Solar Star Funding Senior Notes, 5.375%, due 2035
894

 
886

 
915

Grande Prairie Wind Senior Notes, 3.860%, due 2037
358

 
355

 
392

Topaz Solar Farms Senior Notes, 5.750%, due 2039
680

 
672

 
709

Topaz Solar Farms Senior Notes, 4.875%, due 2039
195

 
193

 
205

Alamo 6 Senior Notes, 4.170%, due 2042
216

 
213

 
221

Other
13

 
13

 
16

Variable-rate(1):
 
 
 
 
 
Pinyon Pines I and II Term Loans, due 2020(2)
284

 
284

 
310

TX Jumbo Road Term Loan, due 2025(2)
161

 
158

 
176

Marshall Wind Term Loan, due 2026(2)
77

 
75

 
81

Total BHE Renewables
$
3,239

 
$
3,206

 
$
3,401


(1)
Amortizes quarterly or semiannually.
(2)
The term loans have variable interest rates based on LIBOR plus a margin that varies during the terms of the agreements. The Company has entered into interest rate swaps that fix the interest rate on 75% of the Pinyon Pines outstanding debt through December 31, 2019 and 50% of the Pinyon Pines outstanding debt thereafter, and 100% of the TX Jumbo Road and Marshall Wind outstanding debt. The variable interest rate as of December 31, 2019 and 2018 was 3.69% and 4.55%, respectively, while the fixed interest rates as of December 31, 2019 and 2018 ranged from 3.21% to 5.41%.

In January 2020, Pinyon Pines I and II repaid $284 million of its variable-rate term loans. This debt was refinanced with $382 million of fifteen year variable-rate term loans due December 2034. The new term loans amortize semiannually and have variable interest rates based on LIBOR plus a margin that varies during the terms of the agreements. The Company has entered into interest rate swaps that fix the interest rate on 100% of the new term loans.

HomeServices

HomeServices' long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
 
Par Value
 
2019
 
2018
Variable-rate:
 
 
 
 
 
Variable-rate term loan (2019 - 3.299%, 2018 - 4.022%), due 2022(1)
$
213

 
$
213

 
$
233


(1)
Term loan amortizes quarterly and variable-rate resets monthly.


150


Annual Repayments of Long-Term Debt

The annual repayments of BHE and subsidiary debt for the years beginning January 1, 2020 and thereafter, excluding fair value adjustments and unamortized premiums, discounts and debt issuance costs, are as follows (in millions):
 
 
 
 
 
 
 
 
 
 
 
2025 and
 
 
 
2020
 
2021
 
2022
 
2023
 
2024
 
Thereafter
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
BHE senior notes
$
350

 
$
450

 
$

 
$
900

 
$

 
$
6,951

 
$
8,651

BHE junior subordinated debentures

 

 

 

 

 
100

 
100

PacifiCorp
38

 
420

 
605

 
449

 
591

 
5,602

 
7,705

MidAmerican Funding

 

 

 
315

 
535

 
6,665

 
7,515

NV Energy
890

 

 

 
250

 

 
2,696

 
3,836

Northern Powergrid
480

 
32

 
498

 
34

 
35

 
2,155

 
3,234

BHE Pipeline Group

 
200

 

 

 

 
1,050

 
1,250

BHE Transmission
251

 
1

 
366

 
386

 
270

 
2,617

 
3,891

BHE Renewables
503

 
172

 
170

 
174

 
184

 
2,036

 
3,239

HomeServices
27

 
33

 
153

 

 

 

 
213

Totals
$
2,539

 
$
1,308

 
$
1,792

 
$
2,508

 
$
1,615

 
$
29,872

 
$
39,634


(12)    Income Taxes

Tax Cuts and Jobs Act

The 2017 Tax Reform impacted many areas of income tax law. The most material items include the reduction of the federal corporate tax rate from 35% to 21% effective January 1, 2018, the one-time repatriation tax of foreign earnings and profits and limitations on bonus depreciation for utility property. GAAP requires the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change was enacted. As a result of the 2017 Tax Reform, in December 2017, the Company reduced deferred income tax liabilities $7,115 million. As it is probable the change in deferred taxes for the Company's regulated businesses will be passed back to customers through regulatory mechanisms, the Company increased net regulatory liabilities by $5,950 million. The reduction in deferred income tax liabilities also resulted in a decrease in deferred income tax expense of $1,150 million, mostly driven by the Company's non-regulated businesses, primarily BHE Renewables, BHE's investment in BYD Company Limited and HomeServices.

As a result of the 2017 Tax Reform, BHE's consolidated net income in 2017 increased by $516 million primarily due to benefits from reductions in deferred income tax liabilities of $1,150 million, partially offset by an accrual for the deemed repatriation of undistributed foreign earnings and profits totaling $419 million and equity earnings charges totaling $228 million mainly for amounts to be returned to the customers of equity investments in regulated entities.

In December 2017, the Securities and Exchange Commission issued Staff Accounting Bulletin ("SAB") 118 to assist in the implementation process of the 2017 Tax Reform by allowing for calculations to be classified as provisional and subject to remeasurement. There are three different classifications for the accounting: (1) completed, (2) not complete but reasonably estimable or (3) not complete and amounts are not reasonably estimable. The Company recorded the impacts of the 2017 Tax Reform in December 2017 and believed all the impacts to be complete with the exception of the repatriation tax on foreign earnings and interpretations of the bonus depreciation rules. The Company determined the amounts recorded and the interpretations relating to these two items to be provisional and subject to remeasurement during the measurement period upon obtaining the necessary additional information to complete the accounting. The Company believed the estimates for the repatriation tax to be reasonable, however, additional time was required to validate the inputs to the foreign earnings and profits calculation, the basis on which the repatriation tax is determined and additional guidance was required to determine state income tax implications. The Company also believed its interpretations for bonus depreciation to be reasonable, however, clarifying guidance was needed. During 2018, the Company finalized its provisional amounts resulting in a $134 million reduction to the repatriation tax liability estimate, based on further analysis of the earnings and profits completed during 2018 and additional guidance from certain states. In addition, the Company recorded a current tax benefit and deferred tax expense of $68 million following clarifying bonus depreciation guidance. As a result of 2017 Tax Reform and the nature of the Company's regulated businesses, the Company reduced the associated deferred income tax liabilities $27 million and increased regulatory liabilities by the same amount.


151


Iowa Senate File 2417

In May 2018, Iowa Senate File 2417 was signed into law, which, among other items, reduces the state of Iowa corporate tax rate from 12% to 9.8% and eliminates corporate federal deductibility, both for tax years starting in 2021. GAAP requires the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change was enacted.

As a result of Iowa Senate File 2417, the Company reduced deferred income tax liabilities $61 million and decreased deferred income tax expense by $2 million. As it is probable the change in deferred taxes for the Company's regulated businesses will be passed back to customers through regulatory mechanisms, the Company increased net regulatory liabilities by $59 million. In connection with Iowa Senate File 2417, the Company determined it was more appropriate to present the deferred income tax assets of $609 million associated with the state of Iowa net operating loss carryforward as a long-term income tax receivable from Berkshire Hathaway as a component of BHE's shareholders' equity. As the Company does not currently expect to receive the majority of the income tax amounts from Berkshire Hathaway related to the state of Iowa prior to the 2021 effective date, the Company remeasured the long-term income tax receivable with Berkshire Hathaway at the enactment date and recorded a decrease to the long-term income tax receivable from Berkshire Hathaway of $115 million. Subsequent to the remeasurement date, the Company amended the tax sharing agreement with Berkshire Hathaway and received $90 million in 2019 related to previously used state of Iowa net operating loss carryforwards.

Income tax (benefit) expense consists of the following for the years ended December 31 (in millions):
 
2019
 
2018
 
2017
Current:
 
 
 
 
 
Federal
$
(956
)
 
$
(686
)
 
$
(653
)
State
(13
)
 
(9
)
 
(3
)
Foreign
81

 
104

 
83

 
(888
)
 
(591
)
 
(573
)
Deferred:
 
 
 
 
 
Federal
431

 
165

 
(76
)
State
(127
)
 
(131
)
 
100

Foreign
(8
)
 
(20
)
 
2

 
296

 
14

 
26

 
 
 
 
 
 
Investment tax credits
(6
)
 
(6
)
 
(7
)
Total
$
(598
)
 
$
(583
)
 
$
(554
)

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax (benefit) expense is as follows for the years ended December 31:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Federal statutory income tax rate
21
 %
 
21
 %
 
35
 %
Income tax credits
(32
)
 
(30
)
 
(20
)
Effects of ratemaking
(6
)
 
(8
)
 
(1
)
State income tax, net of federal income tax benefit
(5
)
 
(6
)
 
3

Effects of tax rate change and repatriation tax

 
(4
)
 
(31
)
Income tax effect of foreign income
(2
)
 
(3
)
 
(5
)
Equity income

 
1

 
(2
)
Other, net
(1
)
 
(1
)
 
(1
)
Effective income tax rate
(25
)%
 
(30
)%
 
(22
)%

Effects of 2017 Tax Reform have been included in state income tax, net of federal income tax benefit, effects of tax rate change and repatriation tax and equity income.


152


Income tax credits relate primarily to production tax credits ("PTC") from wind-powered generating facilities owned by MidAmerican Energy, PacifiCorp and BHE Renewables. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.

The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated United States federal and Iowa state income tax returns and the majority of the Company's United States federal income tax is remitted to or received from Berkshire Hathaway. As of December 31, 2019, the Company had a current income tax payable to Berkshire Hathaway for federal income tax of $76 million and a long-term income tax receivable from Berkshire Hathaway, reflected as a component of BHE's shareholders' equity, of $530 million for Iowa state income tax. As of December 31, 2018, the Company had a current income tax payable to Berkshire Hathaway for federal income tax of $172 million, a current income tax receivable from Berkshire Hathaway for Iowa state income tax of $90 million and a long-term income tax receivable from Berkshire Hathaway, reflected as a component of BHE's shareholders' equity, of $457 million for Iowa state income tax. Additionally, for the years ended December 31, 2019 and 2018 the Company generated $79 million and $53 million, respectively, of state of Iowa net operating losses which were carried forward and increased the long-term income tax receivable from Berkshire Hathaway.

The net deferred income tax liability consists of the following as of December 31 (in millions):
 
2019
 
2018
Deferred income tax assets:
 
 
 
Regulatory liabilities
$
1,610

 
$
1,674

Federal, state and foreign carryforwards
575

 
596

AROs
306

 
232

Other
590

 
527

Total deferred income tax assets
3,081

 
3,029

Valuation allowances
(143
)
 
(137
)
Total deferred income tax assets, net
2,938

 
2,892

 
 
 
 
Deferred income tax liabilities:
 
 
 
Property-related items
(10,439
)
 
(10,185
)
Investments
(1,137
)
 
(876
)
Regulatory assets
(631
)
 
(656
)
Other
(384
)
 
(222
)
Total deferred income tax liabilities
(12,591
)
 
(11,939
)
Net deferred income tax liability
$
(9,653
)
 
$
(9,047
)

The following table provides the Company's net operating loss and tax credit carryforwards and expiration dates as of December 31, 2019 (in millions):
 
Federal
 
State
 
Foreign
 
Total
Net operating loss carryforwards(1)
$
292

 
$
5,819

 
$
523

 
$
6,634

Deferred income taxes on net operating loss carryforwards
61

 
323

 
141

 
525

Expiration dates
2020 - indefinite
 
2020 - 2039
 
2035 - 2038
 


 
 
 
 
 
 
 
 
Tax credits
$
23

 
$
27

 
$

 
$
50

Expiration dates
2023 - indefinite
 
2020 - indefinite
 

 


(1)
The federal net operating loss carryforwards relate principally to net operating loss carryforwards of subsidiaries that are tax residents in both the United States and the United Kingdom. The federal net operating loss carryforwards were generated prior to Berkshire Hathaway Inc.'s ownership and will begin to expire in 2020.


153


The United States Internal Revenue Service has closed its examination of the Company's income tax returns through December 31, 2011. The statute of limitations for the Company's income tax returns have expired through December 31, 2009, for California, Nebraska, Oregon and Utah, through December 31, 2011 for Minnesota and Montana, and through December 31, 2015, except for the impact of any federal audit adjustments, for Idaho, Illinois, Iowa and Kansas. The closure of examinations, or the expiration of the statute of limitations, for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.

A reconciliation of the beginning and ending balances of the Company's net unrecognized tax benefits is as follows for the years ended December 31 (in millions):
 
2019
 
2018
 
 
 
 
Beginning balance
$
185

 
$
181

Additions based on tax positions related to the current year
3

 
4

Additions for tax positions of prior years
13

 
38

Reductions for tax positions of prior years
(37
)
 
(38
)
Statute of limitations
(9
)
 
2

Settlements
(5
)
 
(2
)
Interest and penalties
(5
)
 

Ending balance
$
145

 
$
185


As of December 31, 2019 and 2018, the Company had unrecognized tax benefits totaling $139 million and $154 million, respectively, that if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect the Company's effective income tax rate.

(13)    Employee Benefit Plans

Defined Benefit Plans

Domestic Operations

PacifiCorp, MidAmerican Energy and NV Energy sponsor defined benefit pension plans that cover a majority of all employees of BHE and its domestic energy subsidiaries. These pension plans include noncontributory defined benefit pension plans, supplemental executive retirement plans ("SERP") and a restoration plan for certain executives of NV Energy. PacifiCorp, MidAmerican Energy and NV Energy also provide certain postretirement healthcare and life insurance benefits through various plans to eligible retirees.

Net Periodic Benefit Cost

For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets is generally calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the first year in which they occur.


154


Net periodic benefit cost for the plans included the following components for the years ended December 31 (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2017
 
2019
 
2018
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
Service cost
$
16

 
$
21

 
$
24

 
$
8

 
$
9

 
$
9

Interest cost
111

 
105

 
116

 
27

 
24

 
29

Expected return on plan assets
(154
)
 
(164
)
 
(160
)
 
(40
)
 
(41
)
 
(40
)
Settlement

 
21

 

 

 

 

Net amortization
31

 
28

 
25

 
(6
)
 
(13
)
 
(14
)
Net periodic benefit cost (credit)
$
4

 
$
11

 
$
5

 
$
(11
)
 
$
(21
)
 
$
(16
)

Funded Status

The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Plan assets at fair value, beginning of year
$
2,396

 
$
2,761

 
$
664

 
$
736

Employer contributions
12

 
38

 
2

 
8

Participant contributions

 

 
9

 
8

Actual return on plan assets
456

 
(147
)
 
122

 
(38
)
Settlement
(22
)
 
(119
)
 

 

Benefits paid
(186
)
 
(137
)
 
(55
)
 
(50
)
Plan assets at fair value, end of year
$
2,656

 
$
2,396

 
$
742

 
$
664


The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Benefit obligation, beginning of year
$
2,718

 
$
3,006

 
$
672

 
$
721

Service cost
16

 
21

 
8

 
9

Interest cost
111

 
105

 
27

 
24

Participant contributions

 

 
9

 
8

Actuarial loss (gain)
242

 
(160
)
 
12

 
(40
)
Amendment
(1
)
 
2

 

 

Settlement
(22
)
 
(119
)
 

 

Benefits paid
(186
)
 
(137
)
 
(55
)
 
(50
)
Benefit obligation, end of year
$
2,878

 
$
2,718

 
$
673

 
$
672

Accumulated benefit obligation, end of year
$
2,867

 
$
2,709

 
 
 
 


155


The funded status of the plans and the amounts recognized on the Consolidated Balance Sheets as of December 31 are as follows (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Plan assets at fair value, end of year
$
2,656

 
$
2,396

 
$
742

 
$
664

Benefit obligation, end of year
2,878

 
2,718

 
673

 
672

Funded status
$
(222
)
 
$
(322
)
 
$
69

 
$
(8
)
 
 
 
 
 
 
 
 
Amounts recognized on the Consolidated Balance Sheets:
 
 
 
 
 
 
 
Other assets
$
73

 
$
20

 
$
76

 
$
5

Other current liabilities
(13
)
 
(13
)
 

 

Other long-term liabilities
(282
)
 
(329
)
 
(7
)
 
(13
)
Amounts recognized
$
(222
)
 
$
(322
)
 
$
69

 
$
(8
)

The SERPs and restoration plan have no plan assets; however, the Company has Rabbi trusts that hold corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERPs and restoration plan. The cash surrender value of all of the policies included in the Rabbi trusts, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $252 million and $256 million as of December 31, 2019 and 2018, respectively. These assets are not included in the plan assets in the above table, but are reflected in noncurrent investments and restricted cash and investments on the Consolidated Balance Sheets.

The fair value of plan assets, projected benefit obligation and accumulated benefit obligation for (1) pension and other postretirement benefit plans with a projected benefit obligation in excess of the fair value of plan assets and (2) pension plans with an accumulated benefit obligation in excess of the fair value of plan assets as of December 31 are as follows (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Fair value of plan assets
$
1,939

 
$
1,752

 
$
439

 
$
417

 
 
 
 
 
 
 
 
Projected benefit obligation
$
2,227

 
$
2,091

 
$
446

 
$
429

 
 
 
 
 
 
 
 
Accumulated benefit obligation
$
2,222

 
$
2,085

 
 
 
 

Unrecognized Amounts

The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Net loss
$
653

 
$
747

 
$
(23
)
 
$
50

Prior service credit
(2
)
 

 
(14
)
 
(22
)
Regulatory deferrals
1

 
(1
)
 
6

 
7

Total
$
652

 
$
746

 
$
(31
)
 
$
35



156


A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2019 and 2018 is as follows (in millions):
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
Other
 
 
 
Regulatory
 
Regulatory
 
Comprehensive
 
 
 
Asset
 
Liability
 
Loss
 
Total
Pension
 
 
 
 
 
 
 
Balance, December 31, 2017
$
665

 
$
(43
)
 
$
20

 
$
642

Net loss (gain) arising during the year
114

 
43

 
(6
)
 
151

Net prior service cost arising during the year

 

 
2

 
2

Settlement
(21
)
 

 

 
(21
)
Net amortization
(28
)
 

 

 
(28
)
Total
65

 
43

 
(4
)
 
104

Balance, December 31, 2018
730

 

 
16

 
746

Net (gain) loss arising during the year
(38
)
 
(33
)
 
10

 
(61
)
Net prior service credit arising during the year

 

 
(2
)
 
(2
)
Net amortization
(31
)
 

 

 
(31
)
Total
(69
)
 
(33
)
 
8

 
(94
)
Balance, December 31, 2019
$
661

 
$
(33
)
 
$
24

 
$
652


 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
Other
 
 
 
Regulatory
 
Regulatory
 
Comprehensive
 
 
 
Asset
 
Liability
 
Loss
 
Total
Other Postretirement
 
 
 
 
 
 
 
Balance, December 31, 2017
$
10

 
$
(26
)
 
$

 
$
(16
)
Net loss arising during the year
23

 
14

 
1

 
38

Net amortization
11

 
2

 

 
13

Total
34

 
16

 
1

 
51

Balance, December 31, 2018
44

 
(10
)
 
1

 
35

Net gain arising during the year
(45
)
 
(23
)
 
(4
)
 
(72
)
Net amortization
5

 
1

 

 
6

Total
(40
)
 
(22
)
 
(4
)
 
(66
)
Balance, December 31, 2019
$
4

 
$
(32
)
 
$
(3
)
 
$
(31
)

157


Plan Assumptions

Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost were as follows:

Pension
 
Other Postretirement
 
2019
 
2018
 
2017
 
2019
 
2018
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
Benefit obligations as of December 31:
 
 
 
 
 
 
 
 
 
 
 
Discount rate
3.32
%
 
4.25
%
 
3.60
%
 
3.24
%
 
4.21
%
 
3.57
%
Rate of compensation increase
2.75
%
 
2.75
%
 
2.75
%
 
NA

 
NA

 
NA

Interest crediting rates for cash balance plan
 
 
 
 
 
 


 


 


2017
NA

 
NA

 
2.49
%
 
NA

 
NA

 
NA

2018
NA

 
3.38
%
 
3.06
%
 
NA

 
NA

 
NA

2019
3.22
%
 
3.54
%
 
3.06
%
 
NA

 
NA

 
NA

2020
2.94
%
 
3.54
%
 
2.72
%
 
NA

 
NA

 
NA

2021
2.94
%
 
3.56
%
 
2.72
%
 
NA

 
NA

 
NA

2022
3.02
%
 
3.56
%
 
2.72
%
 
NA

 
NA

 
NA

 
 
 
 
 
 
 
 
 
 
 
 
Net periodic benefit cost for the years ended December 31:
 
 
 
 
 
 
 
 
 
 
 
Discount rate
4.25
%
 
3.60
%
 
4.06
%
 
4.21
%
 
3.57
%
 
4.01
%
Expected return on plan assets
6.48
%
 
6.36
%
 
6.55
%
 
6.39
%
 
6.44
%
 
6.73
%
Rate of compensation increase
2.75
%
 
2.75
%
 
2.75
%
 
NA

 
NA

 
NA

Interest crediting rate for cash balance plan
3.22
%
 
3.38
%
 
2.49
%
 
NA

 
NA

 
NA


In establishing its assumption as to the expected return on plan assets, the Company utilizes the asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets.
 
2019
 
2018
Assumed healthcare cost trend rates as of December 31:
 
 
 
Healthcare cost trend rate assumed for next year
6.50
%
 
6.80
%
Rate that the cost trend rate gradually declines to
5.00
%
 
5.00
%
Year that the rate reaches the rate it is assumed to remain at
2025
 
2025

Contributions and Benefit Payments

Employer contributions to the pension and other postretirement benefit plans are expected to be $13 million and $- million, respectively, during 2020. Funding to the established pension trusts is based upon the actuarially determined costs of the plans and the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 and the Pension Protection Act of 2006, as amended. The Company considers contributing additional amounts from time to time in order to achieve certain funding levels specified under the Pension Protection Act of 2006, as amended. The Company evaluates a variety of factors, including funded status, income tax laws and regulatory requirements, in determining contributions to its other postretirement benefit plans.


158


The expected benefit payments to participants in the Company's pension and other postretirement benefit plans for 2020 through 2024 and for the five years thereafter are summarized below (in millions):
 
Projected Benefit
 
Payments
 
 
 
Other
 
Pension
 
Postretirement
 
 
 
 
2020
$
233

 
$
57

2021
218

 
56

2022
213

 
55

2023
212

 
54

2024
205

 
51

2025-2029
927

 
224


Plan Assets

Investment Policy and Asset Allocations

The Company's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The plans retain outside investment advisors to manage plan investments within the parameters outlined by each plan's Pension and Employee Benefits Plans Administrative Committee. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments.

The target allocations (percentage of plan assets) for the Company's pension and other postretirement benefit plan assets are as follows as of December 31, 2019:
 
 
 
Other
 
Pension
 
Postretirement
 
%
 
%
PacifiCorp:
 
 
 
Debt securities(1)
30-43
 
33-37
Equity securities(1)
48-65
 
62-66
Limited partnership interests
6-12
 
1-3
 
 
 
 
MidAmerican Energy:
 
 
 
Debt securities(1)
20-50
 
25-45
Equity securities(1)
60-80
 
45-80
Real estate funds
2-8
 
Other
0-3
 
0-5
 
 
 
 
NV Energy:
 
 
 
Debt securities(1)
53-77
 
40
Equity securities(1)
23-47
 
60

(1)
For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities.


159


Fair Value Measurements

The following table presents the fair value of plan assets, by major category, for the Company's defined benefit pension plans (in millions):
 
Input Levels for Fair Value Measurements(1)
 
 
 
Level 1
 
Level 2
 
Total
As of December 31, 2019:
 
 
 
 
 
Cash equivalents
$
27

 
$
36

 
$
63

Debt securities:
 
 
 
 
 
United States government obligations
210

 

 
210

International government obligations

 
5

 
5

Corporate obligations

 
376

 
376

Municipal obligations

 
28

 
28

Agency, asset and mortgage-backed obligations

 
115

 
115

Equity securities:
 
 
 
 
 
United States companies
547

 
1

 
548

International companies
136

 

 
136

Investment funds(2)
125

 

 
125

Total assets in the fair value hierarchy
$
1,045

 
$
561

 
1,606

Investment funds(2) measured at net asset value
 
 
 
 
915

Limited partnership interests(3) measured at net asset value
 
 
 
 
93

Real estate funds measured at net asset value
 
 
 
 
42

Total assets measured at fair value
 
 
 
 
$
2,656

 
 
 
 
 
 
As of December 31, 2018:
 
 
 
 
 
Cash equivalents
$
8

 
$
41

 
$
49

Debt securities:
 
 
 
 
 
United States government obligations
160

 

 
160

International government obligations

 
5

 
5

Corporate obligations

 
373

 
373

Municipal obligations

 
29

 
29

Agency, asset and mortgage-backed obligations

 
123

 
123

Equity securities:
 
 
 
 
 
United States companies
492

 
1

 
493

International companies
108

 

 
108

Investment funds(2)
119

 

 
119

Total assets in the fair value hierarchy
$
887

 
$
572

 
1,459

Investment funds(2) measured at net asset value
 
 
 
 
792

Limited partnership interests(3) measured at net asset value
 
 
 
 
104

Real estate funds measured at net asset value
 
 
 
 
41

Total assets measured at fair value
 
 
 
 
$
2,396


(1)
Refer to Note 15 for additional discussion regarding the three levels of the fair value hierarchy.
(2)
Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 62% and 38%, respectively, for 2019 and 59% and 41%, respectively, for 2018. Additionally, these funds are invested in United States and international securities of approximately 66% and 34%, respectively, for 2019 and 73% and 27%, respectively, for 2018.
(3)
Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.

160


The following table presents the fair value of plan assets, by major category, for the Company's defined benefit other postretirement plans (in millions):
 
Input Levels for Fair Value Measurements(1)
 
 
 
Level 1
 
Level 2
 
Total
As of December 31, 2019:
 
 
 
 
 
Cash equivalents
$
17

 
$
1

 
$
18

Debt securities:
 
 
 
 
 
United States government obligations
23

 

 
23

Corporate obligations

 
44

 
44

Municipal obligations

 
57

 
57

Agency, asset and mortgage-backed obligations

 
33

 
33

Equity securities:
 
 
 
 
 
United States companies
151

 

 
151

International companies
6

 

 
6

Investment funds
236

 

 
236

Total assets in the fair value hierarchy
$
433

 
$
135

 
568

Investment funds measured at net asset value
 
 
 
 
169

Limited partnership interests measured at net asset value
 
 
 
 
5

Total assets measured at fair value
 
 
 
 
$
742

 
 
 
 
 
 
As of December 31, 2018:
 
 
 
 
 
Cash equivalents
$
10

 
$
2

 
$
12

Debt securities:
 
 
 
 
 
United States government obligations
13

 

 
13

Corporate obligations

 
42

 
42

Municipal obligations

 
45

 
45

Agency, asset and mortgage-backed obligations

 
30

 
30

Equity securities:
 
 
 
 
 
United States companies
158

 

 
158

International companies
6

 

 
6

Investment funds(2)
202

 
1

 
203

Total assets in the fair value hierarchy
$
389

 
$
120

 
509

Investment funds(2) measured at net asset value
 
 
 
 
149

Limited partnership interests(3) measured at net asset value
 
 
 
 
6

Total assets measured at fair value
 
 
 
 
$
664


(1)
Refer to Note 15 for additional discussion regarding the three levels of the fair value hierarchy.
(2)
Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 58% and 42%, respectively, for 2019 and 65% and 35%, respectively, for 2018. Additionally, these funds are invested in United States and international securities of approximately 75% and 25%, respectively, for 2019 and 79% and 21%, respectively, for 2018.
(3)
Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.

For level 1 investments, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. For level 2 investments, the fair value is determined using pricing models based on observable market inputs. Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.


161


Foreign Operations

Certain wholly-owned subsidiaries of Northern Powergrid participate in the Northern Powergrid group of the United Kingdom industry-wide Electricity Supply Pension Scheme (the "UK Plan"), which provides pension and other related defined benefits, based on final pensionable pay, to the employees of Northern Powergrid. The UK Plan is closed to employees hired after July 23, 1997. Employees hired after that date are covered by a defined contribution plan sponsored by a wholly-owned subsidiary of Northern Powergrid.

Net Periodic Benefit Cost

For purposes of calculating the expected return on pension plan assets, a market-related value is used. The market-related value of plan assets is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the first year in which they occur.

Net periodic benefit cost for the UK Plan included the following components for the years ended December 31 (in millions):
 
2019
 
2018
 
2017
 
 
 
 
 
 
Service cost
$
16

 
$
19

 
$
23

Interest cost
49

 
56

 
58

Expected return on plan assets
(100
)
 
(101
)
 
(100
)
Settlement
26

 
44

 
31

Net amortization
46

 
45

 
63

Net periodic benefit cost
$
37

 
$
63

 
$
75

    
Funded Status

The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
 
2019
 
2018
 
 
 
 
Plan assets at fair value, beginning of year
$
1,989

 
$
2,368

Employer contributions
56

 
60

Participant contributions
1

 
1

Actual return on plan assets
194

 
(44
)
Settlement
(99
)
 
(205
)
Benefits paid
(71
)
 
(71
)
Foreign currency exchange rate changes
81

 
(120
)
Plan assets at fair value, end of year
$
2,151

 
$
1,989



162


The following table is a reconciliation of the benefit obligation for the years ended December 31 (in millions):
 
2019
 
2018
 
 
 
 
Benefit obligation, beginning of year
$
1,833

 
$
2,201

Service cost
16

 
19

Interest cost
49

 
56

Participant contributions
1

 
1

Actuarial loss (gain)
175

 
(87
)
Settlement
(99
)
 
(182
)
Amendment

 
8

Benefits paid
(71
)
 
(71
)
Foreign currency exchange rate changes
115

 
(112
)
Benefit obligation, end of year
$
2,019

 
$
1,833

Accumulated benefit obligation, end of year
$
1,786

 
$
1,637


The funded status of the UK Plan and the amounts recognized on the Consolidated Balance Sheets as of December 31 are as follows (in millions):
 
2019
 
2018
 
 
 
 
Plan assets at fair value, end of year
$
2,151

 
$
1,989

Benefit obligation, end of year
2,019

 
1,833

Funded status
$
132

 
$
156

 
 
 
 
Amounts recognized on the Consolidated Balance Sheets:
 
 
 
Other assets
$
132

 
$
156


Unrecognized Amounts

The portion of the funded status of the UK Plan not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
 
2019
 
2018
 
 
 
 
Net loss
$
543

 
$
472

Prior service cost
6

 
8

Total
$
549

 
$
480



163


A reconciliation of the amounts not yet recognized as components of net periodic benefit cost, which are included in accumulated other comprehensive loss on the Consolidated Balance Sheets, for the years ended December 31 is as follows (in millions):
 
2019
 
2018
 
 
 
 
Balance, beginning of year
$
480

 
$
510

Net loss arising during the year
81

 
59

Net prior service cost arising during the year

 
8

Settlement
(26
)
 
(22
)
Net amortization
(46
)
 
(45
)
Foreign currency exchange rate changes
60

 
(30
)
Total
69

 
(30
)
Balance, end of year
$
549

 
$
480


Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Benefit obligations as of December 31:
 
 
 
 
 
Discount rate
2.10
%
 
2.90
%
 
2.60
%
Rate of compensation increase
3.30
%
 
3.55
%
 
3.45
%
Rate of future price inflation
2.80
%
 
3.05
%
 
2.95
%
 
 
 
 
 
 
Net periodic benefit cost for the years ended December 31:
 
 
 
 
 
Discount rate
2.90
%
 
2.60
%
 
2.70
%
Expected return on plan assets
5.10
%
 
4.90
%
 
5.00
%
Rate of compensation increase
3.55
%
 
3.45
%
 
3.00
%
Rate of future price inflation
3.05
%
 
2.95
%
 
3.00
%
    
Contributions and Benefit Payments

Employer contributions to the UK Plan are expected to be £43 million during 2020. The expected benefit payments to participants in the UK Plan for 2020 through 2024 and for the five years thereafter excluding lump sum settlement elections, using the foreign currency exchange rate as of December 31, 2019, are summarized below (in millions):
2020
$
74

2021
75

2022
77

2023
79

2024
81

2025-2029
436

    

164


Plan Assets

Investment Policy and Asset Allocations

The investment policy for the UK Plan is to balance risk and return through a diversified portfolio of debt securities, equity securities, real estate and other asset classes. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The UK Plan retains outside investment advisors to manage plan investments within the parameters set by the trustees of the UK Plan in consultation with Northern Powergrid. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments. The return on assets assumption is based on a weighted-average of the expected historical performance for the types of assets in which the UK Plan invests.

The target allocations (percentage of plan assets) for the UK Plan assets are as follows as of December 31, 2019:
 
%
Debt securities(1)
50-55
Equity securities(1)
35-40
Real estate funds and other
5-15

(1)
For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds have been allocated based on the underlying investments in debt and equity securities.

Fair Value Measurements

The following table presents the fair value of the UK Plan assets, by major category (in millions):
 
Input Levels for Fair Value Measurements(1)
 
 
 
Level 1
 
Level 2
 
Level 3
 
Total
As of December 31, 2019:
 
 
 
 
 
 
 
Cash equivalents
$
3

 
$
24

 
$

 
$
27

Debt securities:
 
 
 
 
 
 
 
United Kingdom government obligations
960

 

 

 
960

Equity securities:
 
 
 
 
 
 
 
Investment funds(2)

 
818

 

 
818

Real estate funds

 

 
243

 
243

Total
$
963

 
$
842

 
$
243

 
2,048

Investment funds(2) measured at net asset value
 
 
 
 
 
 
103

Total assets measured at fair value
 
 
 
 
 
 
$
2,151

 
 
 
 
 
 
 
 
As of December 31, 2018:
 
 
 
 
 
 
 
Cash equivalents
$
3

 
$
59

 
$

 
$
62

Debt securities:
 
 
 
 
 
 
 
United Kingdom government obligations
891

 

 

 
891

Equity securities:
 
 
 
 
 
 
 
Investment funds(2)

 
697

 

 
697

Real estate funds

 

 
239

 
239

Total
$
894

 
$
756

 
$
239

 
1,889

Investment funds(2) measured at net asset value
 
 
 
 
 
 
100

Total assets measured at fair value
 
 
 
 
 
 
$
1,989


(1)
Refer to Note 15 for additional discussion regarding the three levels of the fair value hierarchy.
(2)
Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 38% and 62%, respectively, for 2019 and 36% and 64%, respectively, for 2018.


165


The fair value of the UK Plan's assets are determined similar to the plan assets of the domestic plans as previously discussed.

The following table reconciles the beginning and ending balances of the UK Plan assets measured at fair value using significant Level 3 inputs for the years ended December 31 (in millions):
 
Real Estate Funds
 
2019
 
2018
 
2017
 
 
 
 
 

Beginning balance
$
239

 
$
230

 
$
105

Actual return on plan assets still held at period end
(5
)
 
23

 
6

Purchases

 

 
104

Foreign currency exchange rate changes
9

 
(14
)
 
15

Ending balance
$
243

 
$
239

 
$
230


Defined Contribution Plans

The Company sponsors various defined contribution plans covering substantially all employees. The Company's contributions vary depending on the plan, but matching contributions are based on each participant's level of contribution, and certain participants receive contributions based on eligible pre-tax annual compensation. Contributions cannot exceed the maximum allowable for tax purposes. The Company's contributions to these plans were $115 million, $112 million and $103 million for the years ended December 31, 2019, 2018 and 2017, respectively.

(14)
Asset Retirement Obligations

The Company estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.

The Company does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $2.4 billion as of December 31, 2019 and 2018.

The following table presents the Company's ARO liabilities by asset type as of December 31 (in millions):
 
2019
 
2018
 
 
 
 
Fossil fuel facilities
$
623

 
$
371

Quad Cities Station
358

 
345

Wind generating facilities
211

 
174

Offshore pipeline facilities
15

 
33

Solar generating facilities
21

 
20

Other
44

 
42

Total asset retirement obligations
$
1,272

 
$
985

 
 
 
 
Quad Cities Station nuclear decommissioning trust funds
$
599

 
$
504



166


The following table reconciles the beginning and ending balances of the Company's ARO liabilities for the years ended December 31 (in millions):
 
2019
 
2018
 
 
 
 
Beginning balance
$
985

 
$
954

Change in estimated costs
257

 
10

Additions
43

 
28

Retirements
(61
)
 
(45
)
Accretion
48

 
38

Ending balance
$
1,272

 
$
985

 
 
 
 
Reflected as:
 
 
 
Other current liabilities
$
167

 
$
43

Other long-term liabilities
1,105

 
942

Total ARO liability
$
1,272

 
$
985


The Nuclear Regulatory Commission regulates the decommissioning of nuclear power plants, which includes the planning and funding for the decommissioning. In accordance with these regulations, MidAmerican Energy submits a biennial report to the Nuclear Regulatory Commission providing reasonable assurance that funds will be available to pay for its share of the Quad Cities Station decommissioning.

Certain of the Company's decommissioning and reclamation obligations relate to jointly owned facilities and mine sites, and as such, each subsidiary is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. The Company's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities.

In January 2018, MidAmerican Energy completed groundwater testing at its coal combustion residuals ("CCR") surface impoundments. Based on this information, MidAmerican Energy discontinued sending CCR to surface impoundments effective April 2018 and initiated analysis of additional actions to be taken. As a result of that analysis, MidAmerican Energy will remove all CCR material located below the water table and cap the material in such facilities, which is a more extensive closure activity than previously assumed. In the first quarter of 2019, MidAmerican Energy increased the asset retirement obligations for its fossil-fueled generating facilities by $237 million related to the cost of this closure activity. Closure activity on the six existing surface impoundments is estimated to extend through 2023.

(15)    Fair Value Measurements

The carrying value of the Company's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. The Company has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
Level 3 - Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.

The following table presents the Company's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
 
Input Levels for Fair Value Measurements
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other(1)
 
Total
As of December 31, 2019:
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
Commodity derivatives
$

 
$
45

 
$
108

 
$
(24
)
 
$
129

Interest rate derivatives

 
2

 
14

 

 
16

Mortgage loans held for sale

 
1,039

 

 

 
1,039

Money market mutual funds(2)
824

 

 

 

 
824

Debt securities:
 
 
 
 
 
 
 
 
 
United States government obligations
189

 

 

 

 
189

International government obligations

 
4

 

 

 
4

Corporate obligations

 
58

 

 

 
58

Municipal obligations

 
1

 

 

 
1

Agency, asset and mortgage-backed obligations

 
1

 

 

 
1

Equity securities:
 
 
 
 
 
 
 
 
 
United States companies
336

 

 

 

 
336

International companies
1,131

 

 

 

 
1,131

Investment funds
169

 

 

 

 
169

 
$
2,649

 
$
1,150

 
$
122

 
$
(24
)
 
$
3,897

Liabilities:
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
(4
)
 
$
(143
)
 
$
(11
)
 
$
103

 
$
(55
)
Interest rate derivatives
(2
)
 
(19
)
 

 

 
(21
)
 
$
(6
)
 
$
(162
)
 
$
(11
)
 
$
103

 
$
(76
)

As of December 31, 2018:
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
1

 
$
91

 
$
108

 
$
(52
)
 
$
148

Interest rate derivatives
1

 
13

 
10

 

 
24

Mortgage loans held for sale

 
468

 

 

 
468

Money market mutual funds(2)
409

 

 

 

 
409

Debt securities:
 
 
 
 
 
 
 
 
 
United States government obligations
187

 

 

 

 
187

International government obligations

 
4

 

 

 
4

Corporate obligations

 
46

 

 

 
46

Municipal obligations

 
2

 

 

 
2

Agency, asset and mortgage-backed obligations

 
1

 

 

 
1

Equity securities:
 
 
 
 
 
 
 
 
 
United States companies
256

 

 

 

 
256

International companies
1,441

 

 

 

 
1,441

Investment funds
128

 

 

 

 
128

 
$
2,423

 
$
625

 
$
118

 
$
(52
)
 
$
3,114

Liabilities:
 
 
 
 
 
 
 
 
 
Commodity derivatives
$
(1
)
 
$
(180
)
 
$
(9
)
 
$
111

 
$
(79
)
Interest rate derivatives

 
(32
)
 

 

 
(32
)
 
$
(1
)
 
$
(212
)
 
$
(9
)
 
$
111

 
$
(111
)

(1)
Represents netting under master netting arrangements and a net cash collateral receivable of $79 million and $59 million as of December 31, 2019 and 2018, respectively.

167


(2)
Amounts are included in cash and cash equivalents; other current assets; and noncurrent investments and restricted cash and investments on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.

The Company's mortgage loans held for sale are valued based on independent quoted market prices, where available, or the prices of other mortgage whole loans with similar characteristics. As necessary, these prices are adjusted for typical securitization activities, including servicing value, portfolio composition, market conditions and liquidity.

The Company's investments in money market mutual funds and debt and equity securities are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.

The following table reconciles the beginning and ending balances of the Company's assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions):
 
Commodity
Derivatives
 
Interest Rate Derivatives
 
2019
 
2018
 
2017
 
2019
 
2018
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
Beginning balance
$
99

 
$
94

 
$
60

 
$
10

 
$
9

 
$
6

Changes included in earnings
10

 
1

 
23

 
479

 
181

 
147

Changes in fair value recognized in OCI
(1
)
 
2

 
(3
)
 

 

 

Changes in fair value recognized in net regulatory assets
(26
)
 
3

 
(1
)
 

 

 

Purchases
6

 
3

 
1

 

 

 
4

Settlements
9

 
(4
)
 
14

 
(475
)
 
(180
)
 
(148
)
Ending balance
$
97

 
$
99

 
$
94

 
$
14

 
$
10

 
$
9


The Company's long-term debt is carried at cost, including fair value adjustments and unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Financial Statements. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt as of December 31 (in millions):
 
2019
 
2018
 
Carrying
 
Fair
 
Carrying
 
Fair
 
Value
 
Value
 
Value
 
Value
 
 
 
 
 
 
 
 
Long-term debt
$
39,353

 
$
46,004

 
$
36,774

 
$
39,398



168


(16)    Commitments and Contingencies

Commitments

The Company has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2019 are as follows (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
2025 and
 
 
 
 
2020
 
2021
 
2022
 
2023
 
2024
 
Thereafter
 
Total
Contract type:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel, capacity and transmission contract commitments
 
$
2,218

 
$
1,527

 
$
1,193

 
$
1,093

 
$
1,088

 
$
13,584

 
$
20,703

Construction commitments
 
1,682

 
521

 
27

 
2

 
8

 

 
2,240

Easements
 
62

 
68

 
70

 
72

 
70

 
2,259

 
2,601

Maintenance, service and other contracts
 
669

 
342

 
324

 
300

 
255

 
1,624

 
3,514

 
 
$
4,631

 
$
2,458

 
$
1,614

 
$
1,467

 
$
1,421

 
$
17,467

 
$
29,058


Fuel, Capacity and Transmission Contract Commitments

The Utilities have fuel supply and related transportation and lime contracts for their coal- and natural gas-fueled generating facilities. The Utilities expect to supplement these contracts with additional contracts and spot market purchases to fulfill their future fossil fuel needs. The Utilities acquire a portion of their electricity through long-term purchases and exchange agreements. The Utilities have several power purchase agreements with renewable generating facilities that are not included in the table above as the payments are based on the amount of energy generated and there are no minimum payments. The Utilities also have contracts for the right to transmit electricity over other entities' transmission lines to facilitate delivery to their customers.

MidAmerican Energy has long-term rail transportation contracts with BNSF Railway Company ("BNSF"), an affiliate company, and Union Pacific Railroad Company for the transportation of coal to all of the MidAmerican Energy-operated coal-fueled generating facilities. For the years ended December 31, 2019, 2018 and 2017, $123 million, $111 million and $109 million, respectively, were incurred for coal transportation services, the majority of which was related to the BNSF agreement.

Construction Commitments

The Company's firm construction commitments reflected in the table above include the following major construction projects:
PacifiCorp's costs associated with certain generating plant, transmission and distribution projects.
MidAmerican Energy's firm construction commitments primarily consisting of contracts for the construction and repowering of wind-powered generating facilities in 2020 and 2021.
AltaLink's investments in directly assigned transmission projects from the AESO.

Easements

The Company has non-cancelable easements for land on which certain of its assets, primarily wind-powered generating facilities, are located.

Maintenance, Service and Other Contracts

The Company has entered into service agreements related to its nonregulated solar and wind-powered projects with third parties to operate and maintain the projects under fixed-fee operating and maintenance agreements. Additionally, the Company has various non-cancelable maintenance, service and other contracts primarily related to turbine and equipment maintenance and various other service agreements.


169


BHE Renewables' Counterparty Risk

On January 29, 2019, PG&E Corporation and Pacific Gas and Electric Company (the "PG&E Utility") (together "PG&E") filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Northern District of California ("PG&E Bankruptcy Filing"). The Company owns 100% of Topaz and owns a 49% interest in Agua Caliente. Topaz is a 550-MW solar photovoltaic electric power generating facility located in California. Topaz sells 100% of its energy, capacity and renewable energy credits generated from the facility to PG&E Utility under a 25-year wholesale power purchase agreement ("PPA") that is in effect until October 2039. As of December 31, 2019, the Company's consolidated balance sheet includes $1.0 billion of property, plant and equipment, net and $0.9 billion of non-recourse project debt related to Topaz. Agua Caliente is a 290-MW solar photovoltaic electric power generating facility located in Arizona. Agua Caliente sells 100% of its energy, capacity and renewable energy credits generated from the facility to PG&E Utility under a 25-year wholesale PPA that is in effect until June 2039. As of December 31, 2019, the Company's equity investment in Agua Caliente totals $73 million and the project has $0.8 billion of non-recourse project debt owed to the United States Department of Energy. The PG&E Bankruptcy Filing is an event of default under the Topaz PPA ("PPA Default"). PG&E paid in full the invoices for December 2018 deliveries and all amounts invoiced to date for post-petition energy deliveries for both Topaz and Agua Caliente. PG&E has not paid for the power delivered from January 1 through January 28, 2019. The Company continues to perform on its obligations and deliver renewable energy to the PG&E Utility, and PG&E has publicly stated it will pay suppliers in full under normal terms for post-petition goods and services received. The Company maintains that, in light of the current facts and circumstances, the PPA Default could not reasonably be expected to result in a material adverse effect under the Topaz indenture and, therefore, no default has occurred under the Topaz indenture. In July 2019, the California Governor signed AB 1054 into law. AB 1054 is comprehensive legislation addressing wildfire risk in the state of California that, among other items, authorizes a wildfire fund which would operate as an insurance fund to support the creditworthiness of electrical utilities, if certain utilities, including PG&E, participate by making the required contributions, among other things. In July 2019, PG&E notified the CPUC of its intent to participate in the insurance fund and such participation requires, among other items, PG&E to exit bankruptcy by June 30, 2020. The Company believes it is more likely than not that no impairment exists and current debt obligations will be met, as post-petition contractual revenue payments are expected to be paid by PG&E Utility to the Topaz and Agua Caliente projects. The Company will continue to monitor the situation, including continued receipt of future PG&E payments and the future risk of the PPAs being rejected or modified through the bankruptcy process.

Legal Matters

The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

Environmental Laws and Regulations

The Company is subject to federal, state, local and foreign laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.

Hydroelectric Relicensing

PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA does not guarantee dam removal. Instead, it establishes a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the Federal Energy Regulatory Commission ("FERC") license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.


170


In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four main-stem Klamath dams from PacifiCorp to the KRRC. Over the past two years, the KRRC has been supplementing the application with additional information about its financial, technical, and legal capacity to become the licensee. In July 2019, the KRRC provided the FERC with additional information about its financial capacity to become a licensee, including updated cost estimates, and its insurance, bonding and liability transfer package. The FERC is evaluating the KRRC's information and the proposed license transfer. The KRRC will continue to refine its insurance, bonding and liability transfer package, and PacifiCorp will review the KRRC's capacity to fulfill its indemnity obligation under the KHSA. If certain conditions in the amended KHSA are not satisfied (e.g., inadequate funding or inability of KRRC to satisfy its indemnification obligation) and the license does not transfer to the KRRC, PacifiCorp will resume relicensing with the FERC.

The United States Court of Appeals for the District of Columbia Circuit issued a decision in the Hoopa Valley Tribe v. FERC litigation, in January 2019, finding that the states of California and Oregon have waived their Clean Water Act, Section 401, water quality certification authority over the Klamath hydroelectric project relicensing. This decision has the potential to limit the ability of the States to impose water quality conditions on new and relicensed projects. Environmental interests, supported by California, Oregon and other states, asked the court to rehear the case, which was denied. Subsequently, environmental groups, supported by numerous states, filed a petition for certiorari before the United States Supreme Court, which was denied on December 9, 2019, thereby allowing the circuit court opinion to stand as a final and unappealable decision.

As of December 31, 2019, PacifiCorp's assets included $29 million of costs associated with the Klamath hydroelectric system's mainstem dams and the associated relicensing and settlement costs, which are being depreciated and amortized in accordance with state regulatory approvals in Utah, Wyoming and Idaho through December 31, 2022.

Hydroelectric Commitments

Certain of PacifiCorp's hydroelectric licenses contain requirements for PacifiCorp to make certain capital and operating expenditures related to its hydroelectric facilities. PacifiCorp estimates it is obligated to make capital expenditures of approximately $168 million over the next 10 years related to these licenses.

Guarantees

The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company's consolidated financial results.


171


(17)    Revenue from Contracts with Customers

The Company uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The following table summarizes the Company's energy products and services revenue by regulated energy and nonregulated energy, with further disaggregation of regulated energy by customer class and line of business, including a reconciliation to the Company's reportable segment information included in Note 22 (in millions):
 
 
For the Year Ended December 31, 2019
 
 
PacifiCorp
 
MidAmerican Funding
 
NV Energy
 
Northern Powergrid
 
BHE Pipeline Group
 
BHE Transmission
 
BHE Renewables
 
BHE and
Other(1)
 
Total
Customer Revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail Electric
 
$
4,789

 
$
1,938

 
$
2,740

 
$

 
$

 
$

 
$

 
$
(2
)
 
$
9,465

Retail Gas
 

 
570

 
116

 

 

 

 

 

 
686

Wholesale
 
99

 
309

 
51

 

 

 

 

 
(2
)
 
457

Transmission and
distribution
 
98

 
57

 
98

 
876

 

 
690

 

 

 
1,819

Interstate pipeline
 

 

 

 

 
1,122

 

 

 
(118
)
 
1,004

Other
 

 

 
2

 

 

 

 

 

 
2

Total Regulated
 
4,986

 
2,874

 
3,007

 
876

 
1,122

 
690

 

 
(122
)
 
13,433

Nonregulated
 

 
30

 

 
36

 

 
17

 
744

 
577

 
1,404

Total Customer Revenue
 
4,986

 
2,904

 
3,007

 
912

 
1,122

 
707

 
744

 
455

 
14,837

Other revenue
 
82

 
23

 
30

 
101

 
9

 

 
188

 
101

 
534

Total
 
$
5,068

 
$
2,927

 
$
3,037

 
$
1,013

 
$
1,131

 
$
707

 
$
932

 
$
556

 
$
15,371


 
 
For the Year Ended December 31, 2018
 
 
PacifiCorp
 
MidAmerican Funding
 
NV Energy
 
Northern Powergrid
 
BHE Pipeline Group
 
BHE Transmission
 
BHE Renewables
 
BHE and
Other(1)
 
Total
Customer Revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail Electric
 
$
4,732

 
$
1,915

 
$
2,773

 
$

 
$

 
$

 
$

 
$
(1
)
 
$
9,419

Retail Gas
 

 
636

 
101

 

 

 

 

 

 
737

Wholesale
 
55

 
411

 
39

 

 

 

 

 
(4
)
 
501

Transmission and
distribution
 
103

 
56

 
96

 
892

 

 
700

 

 
(1
)
 
1,846

Interstate pipeline
 

 

 

 

 
1,232

 

 

 
(125
)
 
1,107

Other
 

 

 
2

 

 

 

 

 

 
2

Total Regulated
 
4,890

 
3,018

 
3,011

 
892

 
1,232

 
700

 

 
(131
)
 
13,612

Nonregulated
 

 
14

 

 
39

 

 
10

 
673

 
624

 
1,360

Total Customer Revenue
 
4,890

 
3,032

 
3,011

 
931

 
1,232

 
710

 
673

 
493

 
14,972

Other revenue(1)
 
136

 
21

 
28

 
89

 
(29
)
 

 
235

 
121

 
601

Total
 
$
5,026

 
$
3,053

 
$
3,039

 
$
1,020

 
$
1,203

 
$
710

 
$
908

 
$
614

 
$
15,573


(1)
Includes net payments to counterparties for the financial settlement of certain derivative contracts at BHE Pipeline Group.


172


Real Estate Services

The following table summarizes the Company's real estate services revenue by line of business (in millions):
 
HomeServices
 
Years Ended December 31,
 
2019
 
2018
Customer Revenue:
 
 
 
Brokerage
$
4,028

 
$
3,882

Franchise
68

 
67

Total Customer Revenue
4,096

 
3,949

Other revenue
377

 
265

Total
$
4,473

 
$
4,214

    
Remaining Performance Obligations

The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of December 31, 2019, by reportable segment (in millions):
 
Performance obligations expected to be satisfied
 
 
 
Less than 12 months
 
More than 12 months
 
Total
BHE Pipeline Group
$
871

 
$
5,136

 
$
6,007


(18)
BHE Shareholders' Equity

Common Stock

On March 14, 2000, and as amended on December 7, 2005, BHE's shareholders entered into a Shareholder Agreement that provides specific rights to certain shareholders. One of these rights allows certain shareholders the ability to put their common shares to BHE at the then-current fair value dependent on certain circumstances controlled by BHE.

For the year ended December 31, 2017, BHE issued $100 million of its 5.00% junior subordinated debentures due June 2057 in exchange for 181,819 shares of its common stock.

Restricted Net Assets

BHE has maximum debt-to-total capitalization percentage restrictions imposed by its senior unsecured credit facilities expiring in June 2022 which, in certain circumstances, limit BHE's ability to make cash dividends or distributions. As a result of this restriction, BHE has restricted net assets of $18.1 billion as of December 31, 2019.

Certain of BHE's subsidiaries have restrictions on their ability to dividend, loan or advance funds to BHE due to specific legal or regulatory restrictions, including, but not limited to, maximum debt-to-total capitalization percentages and commitments made to state commissions. As a result of these restrictions, BHE's subsidiaries had restricted net assets of $17.5 billion as of December 31, 2019.


173


(19)    Components of Accumulated Other Comprehensive Loss, Net

The following table shows the change in accumulated other comprehensive loss attributable to BHE shareholders by each component of other comprehensive income (loss), net of applicable income taxes, for the year ended December 31 (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized
 
Foreign
 
Unrealized
 
Unrealized
 
AOCI
 
 
Amounts on
 
Currency
 
Gains on
 
Gains (Losses)
 
Attributable
 
 
Retirement
 
Translation
 
Marketable
 
on Cash Flow
 
To BHE
 
 
Benefits
 
Adjustment
 
Securities
 
Hedges
 
Shareholders, Net
 
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2016
 
$
(447
)
 
$
(1,675
)
 
$
585

 
$
26

 
$
(1,511
)
Other comprehensive income (loss)
 
64

 
546

 
500

 
3

 
1,113

Balance, December 31, 2017
 
(383
)
 
(1,129
)
 
1,085

 
29

 
(398
)
Adoption of ASU 2016-01
 

 

 
(1,085
)
 

 
(1,085
)
Other comprehensive income (loss)
 
25

 
(494
)
 

 
7

 
(462
)
Balance, December 31, 2018
 
(358
)
 
(1,623
)
 

 
36

 
(1,945
)
Other comprehensive (loss) income
 
(59
)
 
327

 

 
(29
)
 
239

Balance, December 31, 2019
 
$
(417
)
 
$
(1,296
)
 
$

 
$
7

 
$
(1,706
)

Reclassifications from AOCI to net income for the years ended December 31, 2019, 2018 and 2017 were insignificant. Additionally, refer to the "Foreign Operations" discussion in Note 13 for information about unrecognized amounts on retirement benefits reclassifications from AOCI that do not impact net income in their entirety.

(20)
Noncontrolling Interests

Included in noncontrolling interests on the Consolidated Balance Sheets are preferred securities of subsidiaries of $58 million as of December 31, 2019 and 2018, consisting of $56 million of 8.061% cumulative preferred securities of Northern Electric plc., a subsidiary of Northern Powergrid, which are redeemable in the event of the revocation of Northern Electric plc.'s electricity distribution license by the Secretary of State, and $2 million of nonredeemable preferred stock of PacifiCorp.

(21)    Supplemental Cash Flow Disclosures

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 2019 and December 31, 2018, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements and debt service obligations for certain of the Company's nonregulated renewable energy projects. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2019 and December 31, 2018, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
 
As of December 31,
 
2019
 
2018
Cash and cash equivalents
$
1,040

 
$
627

Restricted cash and cash equivalents
212

 
227

Investments and restricted cash and cash equivalents and investments
16

 
29

Total cash and cash equivalents and restricted cash and cash equivalents
$
1,268

 
$
883


174



The summary of supplemental cash flow disclosures as of and for the years ending December 31 is as follows (in millions):
 
2019
 
2018
 
2017
Supplemental disclosure of cash flow information:
 
 
 
 
 
Interest paid, net of amounts capitalized
$
1,723

 
$
1,713

 
$
1,715

Income taxes received, net(1)
$
850

 
$
780

 
$
540

 
 
 
 
 
 
Supplemental disclosure of non-cash investing and financing transactions:
 
 
 
 
 
Accruals related to property, plant and equipment additions
$
888

 
$
823

 
$
653

Common stock exchanged for junior subordinated debentures
$

 
$

 
$
100


(1)
Includes $942 million, $884 million and $636 million of income taxes received from Berkshire Hathaway in 2019, 2018 and 2017, respectively.


175


(22)    Segment Information

The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, BHE Transmission, whose business includes operations in Canada, and BHE Renewables, whose business includes operations in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):
 
Years Ended December 31,
 
2019
 
2018
 
2017
Operating revenue:
 
 
 
 
 
PacifiCorp
$
5,068

 
$
5,026

 
$
5,237

MidAmerican Funding
2,927

 
3,053

 
2,846

NV Energy
3,037

 
3,039

 
3,015

Northern Powergrid
1,013

 
1,020

 
949

BHE Pipeline Group
1,131

 
1,203

 
993

BHE Transmission
707

 
710

 
699

BHE Renewables
932

 
908

 
838

HomeServices
4,473

 
4,214

 
3,443

BHE and Other(1)
556

 
614

 
594

Total operating revenue
$
19,844

 
$
19,787

 
$
18,614

 
 
 
 
 
 
Depreciation and amortization:
 
 
 
 
 
PacifiCorp
$
954

 
$
979

 
$
796

MidAmerican Funding
638

 
609

 
500

NV Energy
482

 
456

 
422

Northern Powergrid
254

 
250

 
214

BHE Pipeline Group
115

 
126

 
159

BHE Transmission
240

 
247

 
239

BHE Renewables
282

 
268

 
251

HomeServices
47

 
51

 
66

BHE and Other(1)
(1
)
 
(2
)
 
(1
)
Total depreciation and amortization
$
3,011

 
$
2,984

 
$
2,646

 
 
 
 
 
 
Operating income:
 
 
 
 
 
PacifiCorp
$
1,072

 
$
1,051

 
$
1,440

MidAmerican Funding
549

 
550

 
544

NV Energy
655

 
607

 
766

Northern Powergrid
472

 
486

 
488

BHE Pipeline Group
572

 
525

 
473

BHE Transmission
323

 
313

 
322

BHE Renewables
336

 
325

 
316

HomeServices
222

 
214

 
214

BHE and Other(1)
(51
)
 
1

 
(41
)
Total operating income
4,150

 
4,072

 
4,522

Interest expense
(1,912
)
 
(1,838
)
 
(1,841
)
Capitalized interest
77

 
61

 
45

Allowance for equity funds
173

 
104

 
76

Interest and dividend income
117

 
113

 
111

(Losses) gains on marketable securities, net
(288
)
 
(538
)
 
14

Other, net
97

 
(9
)
 
(420
)
Total income before income tax (benefit) expense and equity income (loss)
$
2,414

 
$
1,965

 
$
2,507


176



 
Years Ended December 31,
 
2019
 
2018
 
2017
Interest expense:
 
 
 
 
 
PacifiCorp
$
401

 
$
384

 
$
381

MidAmerican Funding
302

 
247

 
237

NV Energy
229

 
224

 
233

Northern Powergrid
139

 
141

 
133

BHE Pipeline Group
52

 
43

 
43

BHE Transmission
157

 
167

 
169

BHE Renewables
174

 
201

 
204

HomeServices
25

 
23

 
7

BHE and Other(1)
433

 
408

 
434

Total interest expense
$
1,912

 
$
1,838

 
$
1,841

 
 
 
 
 
 
Income tax (benefit) expense:
 
 
 
 
 
PacifiCorp
$
61

 
$
5

 
$
362

MidAmerican Funding
(377
)
 
(262
)
 
(202
)
NV Energy
98

 
100

 
221

Northern Powergrid
59

 
61

 
57

BHE Pipeline Group
138

 
119

 
170

BHE Transmission
11

 
7

 
(124
)
BHE Renewables(2)
(325
)
 
(158
)
 
(795
)
HomeServices
51

 
52

 
49

BHE and Other(1)
(314
)
 
(507
)
 
(292
)
Total income tax (benefit) expense
$
(598
)
 
$
(583
)
 
$
(554
)
 
 
 
 
 
 
Capital expenditures:
 
 
 
 
 
PacifiCorp
$
2,175

 
$
1,257

 
$
769

MidAmerican Funding
2,810

 
2,332

 
1,776

NV Energy
657

 
503

 
456

Northern Powergrid
602

 
566

 
579

BHE Pipeline Group
687

 
427

 
286

BHE Transmission
247

 
270

 
334

BHE Renewables
122

 
817

 
323

HomeServices
54

 
47

 
37

BHE and Other
10

 
22

 
11

Total capital expenditures
$
7,364

 
$
6,241

 
$
4,571



177


 
As of December 31,
 
2019
 
2018
 
2017
Property, plant and equipment, net:
 
 
 
 
 
PacifiCorp
$
20,973

 
$
19,570

 
$
19,183

MidAmerican Funding
18,377

 
16,169

 
14,221

NV Energy
9,613

 
9,367

 
9,276

Northern Powergrid
6,606

 
6,007

 
6,075

BHE Pipeline Group
5,482

 
4,904

 
4,587

BHE Transmission
6,157

 
5,824

 
6,330

BHE Renewables
5,976

 
6,155

 
5,637

HomeServices
161

 
141

 
117

BHE and Other
(40
)
 
(50
)
 
(69
)
Total property, plant and equipment, net
$
73,305

 
$
68,087

 
$
65,357

 
 
 
 
 
 
Total assets:
 
 
 
 
 
PacifiCorp
$
24,861

 
$
23,478

 
$
23,086

MidAmerican Funding
22,664

 
20,029

 
18,444

NV Energy
14,128

 
14,119

 
13,903

Northern Powergrid
8,385

 
7,427

 
7,565

BHE Pipeline Group
6,100

 
5,511

 
5,134

BHE Transmission
8,776

 
8,424

 
9,009

BHE Renewables
9,961

 
8,666

 
7,687

HomeServices
3,846

 
2,797

 
2,722

BHE and Other
1,330

 
1,738

 
2,658

Total assets
$
100,051

 
$
92,189

 
$
90,208

 
 
 
 
 
 
 
Years Ended December 31,
 
2019
 
2018
 
2017
Operating revenue by country:
 
 
 
 
 
United States
$
18,108

 
$
18,014

 
$
16,916

United Kingdom
1,011

 
1,017

 
948

Canada
706

 
710

 
699

Philippines and other
19

 
46

 
51

Total operating revenue by country
$
19,844

 
$
19,787

 
$
18,614

 
 
 
 
 
 
Income before income tax (benefit) expense and equity income (loss) by country:
 
 
 
 
United States
$
1,866

 
$
1,425

 
$
1,927

United Kingdom
326

 
307

 
313

Canada
178

 
155

 
167

Philippines and other
44

 
78

 
100

Total income before income tax (benefit) expense and equity (loss) income by country:
$
2,414

 
$
1,965

 
$
2,507


178


 
As of December 31,
 
2019
 
2018
 
2017
Property, plant and equipment, net by country:
 
 
 
 
 
United States
$
60,634

 
$
56,362

 
$
53,065

United Kingdom
6,504

 
5,895

 
5,953

Canada
6,157

 
5,817

 
6,323

Philippines and other
10

 
13

 
16

Total property, plant and equipment, net by country
$
73,305

 
$
68,087

 
$
65,357


(1)
The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate to other corporate entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.

(2)
Income tax (benefit) expense includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.

The following table shows the change in the carrying amount of goodwill by reportable segment for the years ended December 31, 2019 and 2018 (in millions):
 
 
 
 
 
 
 
 
 
BHE
 
 
 
 
 
 
 
BHE
 
 
 
 
 
MidAmerican
 
NV
 
Northern
 
Pipeline
 
BHE
 
BHE
 
Home-
 
and
 
 
 
PacifiCorp
 
Funding
 
Energy
 
Powergrid
 
Group
 
Transmission
 
Renewables
 
Services
 
Other
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2017
$
1,129

 
$
2,102

 
$
2,369

 
$
991

 
$
73

 
$
1,571

 
$
95

 
$
1,348

 
$

 
$
9,678

Acquisitions

 

 

 

 

 

 

 
79

 

 
79

Foreign currency translation

 

 

 
(39
)
 

 
(123
)
 

 

 

 
(162
)
December 31, 2018
1,129

 
2,102

 
2,369

 
952

 
73

 
1,448

 
95

 
1,427

 

 
9,595

Acquisitions

 

 

 

 

 

 

 
29

 

 
29

Foreign currency translation

 

 

 
26

 

 
72

 

 

 

 
98

December 31, 2019
$
1,129

 
$
2,102

 
$
2,369

 
$
978

 
$
73

 
$
1,520

 
$
95

 
$
1,456

 
$

 
$
9,722



179


PacifiCorp and its subsidiaries
Consolidated Financial Section


180


Item 6.
Selected Financial Data

The following table sets forth PacifiCorp's selected consolidated historical financial data, which should be read in conjunction with the information in Item 7 of this Form 10-K and with PacifiCorp's historical Consolidated Financial Statements and notes thereto in Item 8 of this Form 10-K. The selected consolidated historical financial data has been derived from PacifiCorp's audited historical Consolidated Financial Statements and notes thereto (in millions).

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
2016
 
2015
 
 
 
 
 
 
 
 
 
 
Consolidated Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Operating revenue
$
5,068

 
$
5,026

 
$
5,237

 
$
5,201

 
$
5,232

Operating income(2)
1,072

 
1,051

 
1,440

 
1,428

 
1,347

Net income
771

 
738

 
768

 
763

 
695


 
As of December 31,
 
2019
 
2018
 
2017
 
2016
 
2015
 
 
 
 
 
 
 
 
 
 
Consolidated Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Total assets
$
23,697

 
$
22,313

 
$
21,920

 
$
22,394

 
$
22,637

Short-term debt
130

 
30

 
80

 
270

 
20

Current portion of long-term debt obligations(1)
38

 
350

 
586

 
52

 
66

Long-term debt obligations, excluding current portion(1)
7,620

 
6,665

 
6,419

 
7,000

 
7,048

Total shareholders' equity
8,437

 
7,845

 
7,555

 
7,390

 
7,503


(1)
On January 1 2019, PacifiCorp adopted Accounting Standards Update No. 2016-02 under a modified retrospective method, which resulted in the reclassification of current capital lease obligation amounts of $2 million at December 31, 2018 and 2017, $6 million at December 31, 2016, and $2 million as of December 31, 2015 to Other current liabilities. The adoption also resulted in the reclassification of the non-current capital lease obligation amounts of $19 million at December 31, 2018, $18 million at December 31, 2017, $21 million at December 31, 2016 and $30 million at December 31, 2015 to Other long-term liabilities.

(2)
In January 2018, PacifiCorp retrospectively adopted Accounting Standards Update No. 2017-07, which resulted in the reclassification of amounts other than the service cost for pension and other postretirement benefit plans to Other, net on the Consolidated Statements of Operations of a $22 million benefit for the year ended December 31, 2017, a $2 million cost for the year ended December 31, 2016, and a $7 million cost for the year ended December 31, 2015, with a corresponding increase or reduction to operating expenses.





181


Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of PacifiCorp during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Item 6 of this Form 10-K and with PacifiCorp's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. PacifiCorp's actual results in the future could differ significantly from the historical results.

Results of Operations

Overview

Net income for the year ended December 31, 2019, was $771 million, an increase of $33 million, or 4%, compared to 2018, primarily due to higher allowances for funds used during construction of $55 million, lower pension and post retirement expense of $11 million primarily due to a prior year pension settlement charge of $22 million, partially offset by higher non-service cost components of pension and other postretirement expenses of $11 million, and higher utility margin of $4 million, partially offset by higher depreciation and amortization expense of $25 million from additional plant placed in-service, excluding a $49 million decrease in accelerated depreciation expense (offset in income tax expense) associated with Oregon’s share of certain retired wind equipment in the current year and Utah’s share of certain thermal plant units in the prior year, lower PTCs of $21 million from expirations, higher interest expense of $17 million, and higher operations and maintenance expense of $10 million, primarily due to costs associated with the early retirement of Cholla Unit 4 of $24 million, increase in vegetation management costs of $11 million, partially offset by a decrease in expenses primarily due to wildfire suppression costs of $9 million. Utility margin increased primarily due to lower coal-fueled generation volumes, higher retail revenue, and higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms, partially offset by higher purchased electricity costs, and higher natural gas-fueled generation costs. Retail volumes increased 0.4% primarily due to the increase in the average number of residential and commercial customers and the favorable impact of weather on residential customer volumes in all states except Utah, partially offset by lower commercial usage primarily in Utah and Washington. Energy generated decreased 3% for 2019 compared to 2018 primarily due to lower coal-fueled, wind and hydroelectric-powered generation, partially offset by higher natural gas-fueled generation. Wholesale electricity sales volumes decreased 34% and purchased electricity volumes decreased 5%.

Net income for the year ended December 31, 2018, was $738 million, a decrease of $30 million, or 4%, compared to 2017, primarily due to lower utility margin of $198 million, higher depreciation and amortization expense of $183 million, due to accelerated depreciation for Utah's share of certain thermal plant units of $174 million ($170 million offset in income tax expense and $4 million offset in revenue), higher plant in-service, and higher pension and other postretirement expense of $13 million, primarily due to a pension settlement charge, partially offset by a decrease in income tax expense of $355 million and higher allowance for funds used during construction of $22 million. Utility margin decreased due to lower average retail rates, including the impact of the lower federal tax rate due to the 2017 Tax Reform of $152 million, higher natural gas-fueled generation volumes, lower average wholesale prices, higher purchased electricity from higher prices, and lower retail customer volumes, partially offset by higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms, lower natural gas prices, higher wholesale volumes and lower coal-fueled generation volumes. Income tax expense decreased primarily due to lower federal tax rate due to the impact of 2017 Tax Reform, and amortization of a portion of Utah's allocated excess deferred income taxes used to accelerate depreciation of certain thermal plant units as ordered by the UPSC. Retail customer volumes decreased by 0.2% due to impacts of weather on the residential and commercial customer volumes, lower residential usage in all states except Utah and lower industrial usage in Oregon, Washington and Utah, partially offset by an increase in the average number of commercial and residential customers across the service territory, higher commercial and residential usage in Utah, higher irrigation usage, and higher industrial usage in Wyoming and Idaho. Energy generated increased 2% for 2018 compared to 2017 primarily due to higher natural gas-fueled and wind-power generation, partially offset by lower hydroelectric and coal-fueled generation. Wholesale electricity sales volumes increased 15% and purchased electricity volumes decreased 4%.


182


Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operations. Utility margin is calculated as operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.

PacifiCorp's cost of fuel and energy is generally recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in PacifiCorp's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of fuel and energy separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):
 
2019
 
2018
 
Change
 
2018
 
2017
 
Change
Utility margin:
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenue
$
5,068

 
$
5,026

 
$
42

1
 %
 
$
5,026

 
$
5,237

 
$
(211
)
(4
)%
Cost of fuel and energy
1,795

 
1,757

 
38

2

 
1,757

 
1,770

 
(13
)
(1
)
Utility margin
3,273

 
3,269

 
4


 
3,269

 
3,467

 
(198
)
(6
)
Operations and maintenance
1,048

 
1,038

 
10

1

 
1,038

 
1,034

 
4


Depreciation and amortization
954

 
979

 
(25
)
(3
)
 
979

 
796

 
183

23

Property and other taxes
199

 
201

 
(2
)
(1
)
 
201

 
197

 
4

2

Operating income
$
1,072

 
$
1,051

 
$
21

2
 %
 
$
1,051

 
$
1,440

 
$
(389
)
(27
)%


183



A comparison of key operating results related to utility margin is as follows for the years ended December 31:

 
 
2019
 
2018
 
Change
 
2018
 
2017
 
Change
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility margin (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenue
 
$
5,068

 
$
5,026

 
$
42

 
1
 %
 
$
5,026

 
$
5,237

 
$
(211
)
 
(4
)%
Cost of fuel and energy
 
1,795

 
1,757

 
38

 
2

 
1,757

 
1,770

 
(13
)
 
(1
)
Utility margin
 
$
3,273

 
$
3,269

 
$
4

 
 %
 
$
3,269

 
$
3,467

 
$
(198
)
 
(6
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales (GWhs):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
16,668

 
16,227

 
441

 
3
 %
 
16,227

 
16,625

 
(398
)
 
(2
)%
Commercial(1)
 
18,151

 
18,078

 
73

 

 
18,078

 
17,726

 
352

 
2

Industrial, irrigation and other(1)
 
20,524

 
20,810

 
(286
)
 
(1
)
 
20,810

 
20,899

 
(89
)
 

Total retail
 
55,343

 
55,115

 
228

 

 
55,115

 
55,250

 
(135
)
 

Wholesale
 
5,480

 
8,309

 
(2,829
)
 
(34
)
 
8,309

 
7,218

 
1,091

 
15

Total sales
 
60,823

 
63,424

 
(2,601
)
 
(4
)%
 
63,424

 
62,468

 
956

 
2
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
 
1,933

 
1,900

 
33

 
2
 %
 
1,900

 
1,867

 
33

 
2
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average revenue per MWh:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail
 
$
84.80

 
$
84.43

 
$
0.37

 
 %
 
$
84.43

 
$
87.78

 
$
(3.35
)
 
(4
)%
Wholesale
 
$
35.21

 
$
22.56

 
$
12.65

 
56
 %
 
$
22.56

 
$
28.56

 
$
(6.00
)
 
(21
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sources of energy (GWhs)(1):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Coal
 
34,510

 
36,481

 
(1,971
)
 
(5
)%
 
36,481

 
37,362

 
(881
)
 
(2
)%
Natural gas
 
12,058

 
10,555

 
1,503

 
14

 
10,555

 
7,447

 
3,108

 
42

Hydroelectric(2)
 
2,842

 
3,263

 
(421
)
 
(13
)
 
3,263

 
4,731

 
(1,468
)
 
(31
)
Wind and other(2)
 
2,385

 
3,205

 
(820
)
 
(26
)
 
3,205

 
2,890

 
315

 
11

Total energy generated
 
51,795

 
53,504

 
(1,709
)
 
(3
)
 
53,504

 
52,430

 
1,074

 
2

Energy purchased
 
12,906

 
13,579

 
(673
)
 
(5
)
 
13,579

 
14,076

 
(497
)
 
(4
)
Total
 
64,701

 
67,083

 
(2,382
)
 
(4
)%
 
67,083

 
66,506

 
577

 
1
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average cost of energy per MWh:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Energy generated(3)
 
$
19.36

 
$
18.91

 
$
0.45

 
2
 %
 
$
18.91

 
$
19.14

 
$
(0.23
)
 
(1
)%
Energy purchased
 
$
54.20

 
$
48.23

 
$
5.97

 
12
 %
 
$
48.23

 
$
43.25

 
$
4.98

 
12
 %

(1)
GWh amounts are net of energy used by the related generating facilities.
(2)
All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities.
(3)
The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.



184


Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

Utility margin increased $4 million for 2019 compared to 2018 primarily due to:
$54 million of lower coal-fueled generation costs primarily due to lower average volumes;
$40 million of higher retail revenue primarily from higher retail customer volumes. Retail volumes increased 0.4% primarily due to an increase in the average number of residential and commercial customers and the favorable impact of weather on residential customer volumes in all states except Utah, partially offset by lower commercial usage primarily in Utah and Washington;
$11 million of higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms; and
$5 million of higher wholesale revenue from higher average market prices, offset by lower volumes.
The increases above were partially offset by:
$45 million of higher purchased electricity costs due to higher average market prices, offset by lower volumes;
$45 million of higher natural gas-fueled generation costs due to higher average volumes and prices; and
$11 million of higher wheeling costs and lower wheeling revenues.
Operations and maintenance increased $10 million, or 1%, for 2019 compared to 2018 primarily due to costs associated with the early retirement of Cholla Unit 4 in December 2020 of $24 million and an $11 million increase in vegetation management costs, partially offset by a $9 million decrease in fire suppression costs, a $7 million decrease in materials and supply expense primarily due to usage, and reduced labor and benefits expense primarily due to higher capitalized labor related to construction projects.
 
Depreciation and amortization decreased $25 million, or 3%, for 2019 compared to 2018 primarily due to a decrease in accelerated depreciation (offset in income tax expense) resulting from $174 million of accelerated depreciation in the prior year for Utah's share of certain thermal plant units pursuant to a 2017 Tax Reform settlement approved by the UPSC compared to $120 million of accelerated depreciation in the current year for Oregon's share of certain retired wind equipment due to repowering as ordered in the Oregon RAC proceeding, partially offset by higher plant-in-service.

Interest expense increased $17 million, or 4%, for 2019 compared to 2018 primarily due to higher average long-term debt balances.

Allowance for borrowed and equity funds increased $55 million, or 104%, for 2019 compared to 2018 primarily due to higher qualified construction work-in-progress balances.

Interest and dividend income increased $6 million, or 40%, for 2019 compared to 2018 primarily due to higher average cash and cash equivalents balances.

Other, net increased $24 million, or 300% for 2019 compared to 2018 primarily due to the prior year pension settlement charge of $22 million and higher cash surrender value of company owned life insurance policies of $5 million, partially offset by higher non-service cost components of pension and other postretirement expense of $11 million.

Income tax expense increased $56 million for 2019 compared to 2018 and the effective tax rate was 7% and 1% for 2019 and 2018, respectively. The effective tax rate increased primarily as a result of lower amortization of excess deferred income taxes in 2019 and expiring PTCs, slightly offset by the effects of ratemaking. In 2019, $91 million of Oregon’s allocated excess deferred income taxes was amortized pursuant to the Oregon RAC proceeding, whereby a portion of Oregon’s allocated excess deferred income taxes was used to accelerate depreciation for Oregon’s share of certain retired wind equipment due to repowering. In 2018, $127 million of Utah's allocated excess deferred income taxes was amortized pursuant to a 2017 Tax Reform settlement approved by the UPSC, whereby a portion of Utah's allocated excess deferred incomes taxes was used to accelerate depreciation on Utah's share of certain thermal plant units.



185


Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

Utility margin decreased $198 million for 2018 compared to 2017 primarily due to:
$180 million of lower retail revenue primarily due to lower average retail rates, including the impact of a lower federal tax rate due to 2017 Tax Reform of $152 million;
$59 million of higher natural gas-fueled generation volumes;
$42 million of lower average wholesale prices;
$41 million of higher purchased electricity costs due to higher prices; and
$17 million of lower retail revenue from lower retail customer volumes. Retail volumes decreased 0.2% due to the unfavorable impacts of weather on the residential and commercial customer volumes, lower residential usage in all states except Utah, and lower industrial usage in Oregon, Washington and Utah, partially offset by an increase in the average number of commercial and residential customers across the service territory, higher commercial and residential usage in Utah, higher irrigation usage, and higher industrial usage in Wyoming and Idaho.
The decreases above were partially offset by:
$70 million of higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms;
$33 million of lower natural gas costs from lower average prices;
$23 million of higher wholesale revenue due to higher volumes; and
$20 million of lower coal costs due to lower volumes.

Operations and maintenance increased $4 million for 2018 compared to 2017 primarily due to reserves accrued for 2018 insurance deductibles for third-party property damage and expenses of $7 million and increased maintenance costs partially offset by favorable labor costs.

Depreciation and amortization increased $183 million, or 23%, for 2018 compared to 2017 primarily due to $174 million of accelerated depreciation for Utah's share of certain thermal plant units as ordered by the UPSC in the tax reform docket to offset excess deferred income taxes benefits owed to customers, and higher plant-in-service.

Allowance for borrowed and equity funds increased $22 million, or 71%, for 2018 compared to 2017 primarily due to a prior year true-up that reduced AFUDC rates by $13 million and higher qualified construction work-in-progress balances.

Other, net decreased $19 million, or 70% for 2018 compared to 2017 primarily due to a pension settlement charge of $22 million, lower cash surrender value of company owned life insurance policies of $5 million, partially offset by lower non-service cost components of pension and other postretirement expenses of $9 million.

Income tax expense decreased $355 million, or 99%, for 2018 compared to 2017 and the effective tax rate was 1% and 32% for 2018 and 2017, respectively. The effective tax rate decreased primarily as a result of the reduction in the United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, and the amortization of $127 million of Utah's allocated excess deferred income taxes pursuant to a 2017 Tax Reform settlement approved by the UPSC, whereby a portion of Utah's allocated excess deferred incomes taxes was used to accelerate depreciation on Utah's share of certain thermal plant units.


186


Liquidity and Capital Resources

As of December 31, 2019, PacifiCorp's total net liquidity was as follows (in millions):

Cash and cash equivalents
 
$
30

 
 
 
Credit facilities(1)
 
1,200

Less:
 
 
Short-term debt
 
(130
)
Tax-exempt bond support
 
(256
)
Net credit facilities
 
814

 
 
 
Total net liquidity
 
$
844

 
 
 
Credit facilities:
 
 
Maturity dates
 
2022


(1)
Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding PacifiCorp's credit facilities.
Operating Activities

Net cash flows from operating activities for the years ended December 31, 2019 and 2018 were $1.5 billion and $1.8 billion, respectively. The decrease is primarily due to higher payments for purchased power, timing of payments for operating expenses and lower receipts from retail customers.

Net cash flows from operating activities for the years ended December 31, 2018 and 2017 were $1.8 billion and $1.6 billion, respectively. The increase is primarily due to current year lower payments for income taxes, a prior year pension contribution and higher current year receipts from wholesale customers, partially offset by lower current year receipts from retail customers and higher payments for purchased power.

The timing of PacifiCorp's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.

Investing Activities

Net cash flows from investing activities for the years ended December 31, 2019 and 2018 were $(2.2) billion and $(1.3) billion, respectively. The increase in net cash outflows from investing activities is mainly due to an increase in capital expenditures of $918 million.

Net cash flows from investing activities for the years ended December 31, 2018 and 2017 were $(1.3) billion and $(757) million. The increase in net cash outflows from investing activities is mainly due to an increase in capital expenditures of $488 million.

Financing Activities

Short-term Debt

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of December 31, 2019, PacifiCorp had $130 million of short-term debt outstanding at a weighted average interest rate of 2.05%. As of December 31, 2018, PacifiCorp had $30 million of short-term debt outstanding at a weighted average interest rate of 2.85%. For further discussion, refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.


187


Long-term Debt

In March 2019, PacifiCorp issued $400 million of its 3.50% First Mortgage Bonds due June 2029 and $600 million of its 4.15% First Mortgage Bonds due February 2050. PacifiCorp used a portion of the net proceeds to repay the short-term debt that was partially incurred in January 2019 to repay all of PacifiCorp's $350 million 5.50% First Mortgage Bonds due January 2019. PacifiCorp intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.

PacifiCorp made repayments on long-term debt totaling $350 million and $586 million during the years ended December 31, 2019 and 2018, respectively.

PacifiCorp's Mortgage and Deed of Trust creates a lien on most of PacifiCorp's electric utility property, allowing the issuance of bonds based on a percentage of utility property additions, bond credits arising from retirement of previously outstanding bonds or deposits of cash. The amount of bonds that PacifiCorp may issue generally is also subject to a net earnings test. As of December 31, 2019, PacifiCorp estimated it would be able to issue up to $10.8 billion of new first mortgage bonds under the most restrictive issuance test in the mortgage. Any issuances are subject to market conditions and amounts may be further limited by regulatory authorizations or commitments or by covenants and tests contained in other financing agreements. PacifiCorp also has the ability to release property from the lien of the mortgage on the basis of property additions, bond credits or deposits of cash.

Credit Facilities

In 2019, PacifiCorp completed a re-offering of variable rate tax-exempt bond obligations totaling $168 million, involving the cancellation, at PacifiCorp's request, of $170 million of letters of credit support by the issuing banks. As a result, PacifiCorp's credit facility support for outstanding variable rate tax-exempt bond obligations increased by $168 million.

Debt Authorizations

PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $1 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement with the SEC to issue up to $1 billion additional first mortgage bonds through October 2021.

Preferred Stock

As of December 31, 2019 and 2018, PacifiCorp had non-redeemable preferred stock outstanding with an aggregate stated value of $2 million.

Common Shareholder's Equity

In 2019 and 2018, PacifiCorp declared and paid dividends of $175 million and $450 million, respectively, to PPW Holdings LLC.

Capitalization

PacifiCorp manages its capitalization and liquidity position to maintain a prudent capital structure with an objective of retaining strong investment grade credit ratings, which is expected to facilitate continuing access to flexible borrowing arrangements at favorable costs and rates. This objective, subject to periodic review and revision, attempts to balance the interests of all shareholders, customers and creditors and provide a competitive cost of capital and predictable capital market access.

Under existing or prospective authoritative accounting guidance, such as guidance pertaining to consolidations and leases, it is possible that new purchase power and gas agreements, transmission arrangements or amendments to existing arrangements may be accounted for as lease obligations on PacifiCorp's financial statements. While PacifiCorp has successfully amended covenants in financing arrangements that may be impacted, it may be more difficult for PacifiCorp to comply with its capitalization targets or regulatory commitments concerning minimum levels of common equity as a percentage of capitalization. This may lead PacifiCorp to seek amendments or waivers under financing agreements and from regulators, delay or reduce dividends or spending programs, seek additional new equity contributions from its indirect parent company, BHE, or take other actions.


188


Future Uses of Cash

PacifiCorp has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depends on a variety of factors, including PacifiCorp's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ended December 31 are as follows (in millions):

 
Historical
 
Forecast
 
2017
 
2018
 
2019
 
2020
 
2021
 
2022
 
 
 
 
 
 
 
 
 
 
 
 
Transmission system investment
$
115

 
$
75

 
$
478

 
$
301

 
$
218

 
$
1,273

Wind investment
11

 
341

 
923

 
1,390

 
79

 
388

Operating and other
643

 
841

 
774

 
1,097

 
1,077

 
731

Total
$
769

 
$
1,257

 
$
2,175

 
$
2,788

 
$
1,374

 
$
2,392


PacifiCorp’s 2019 IRP identified a significant increase in renewable resource generation and associated transmission. PacifiCorp has included an estimate of the 2019 IRP resources in its forecast capital expenditures for 2020 through 2022. These estimates are likely to change as a result of the RFP process. PacifiCorp's historical and forecast capital expenditures include the following:

Transmission system investment primarily reflects initial costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, a major segment of PacifiCorp's Energy Gateway Transmission expansion program expected to be placed in-service in 2020 and investment in additional Energy Gateway Transmission segments expected to be placed in service in 2023. Planned spending for the Aeolus-Bridger/Anticline line totals $139 million in 2020 and $1 million in 2021.
Wind investment includes the following:
Construction of wind-powered generating facilities at PacifiCorp totaled $338 million for 2019 and includes the 1,190 MWs of new wind-powered generating facilities that are expected to be placed in-service in 2020 and the energy production is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. PacifiCorp's 2019 IRP identified 1,920 MWs of new-wind powered generating resources that are expected to come online in 2023. PacifiCorp anticipates that the additional new wind powered generation will be a mixture of owned and contracted resources. Planned spending for the wind-powered generating facilities totals $1,303 million in 2020, $79 million in 2021 and $388 million in 2022.
Repowering existing wind-powered generating facilities at PacifiCorp totaled $585 million in 2019 and $332 million in 2018. Certain repowering projects were placed in service in 2019 and the remaining repowering projects are expected to be placed in-service at various dates in 2020. The energy production from such repowered facilities is expected to qualify for 100% of the federal renewable electricity PTCs available for 10 years following each facility's return to service. Planned spending for certain existing wind-powered generating facilities totals $87 million in 2020.
Remaining investments relate to operating projects that consist of advanced meter infrastructure costs, routine expenditures for generation, transmission, distribution, planned spend for wildfire mitigation and other infrastructure needed to serve existing and expected demand.

189



Contractual Obligations

PacifiCorp has contractual cash obligations that may affect its consolidated financial condition. The following table summarizes PacifiCorp's material contractual cash obligations as of December 31, 2019 (in millions):

 
Payments Due By Periods
 
 
 
2021-
 
2023-
 
2025 and
 
 
 
2020
 
2022
 
2024
 
After
 
Total
 
 
 
 
 
 
 
 
 
 
Long-term debt, including interest:
 
 
 
 
 
 
 
 
 
Fixed-rate obligations
$
371

 
$
1,736

 
$
1,497

 
$
9,540

 
$
13,144

Variable-rate obligations(1)
43

 
8

 
174

 
53

 
278

Short-term debt, including interest
130

 

 

 

 
130

Operating and finance lease liabilities
4

 
10

 
4

 
13

 
31

Interest payments on operating and finance lease liabilities
2

 
3

 
2

 
9

 
16

Easements
10

 
24

 
23

 
349

 
406

Asset retirement obligations
19

 
16

 
35

 
403

 
473

Power purchase agreements - commercially operable(2):
 
 
 
 
 
 
 
 
 
Electricity commodity contracts
229

 
263

 
230

 
1,044

 
1,766

Electricity capacity contracts
35

 
60

 
74

 
640

 
809

Electricity mixed contracts
15

 
28

 
28

 
126

 
197

Power purchase agreements - non-commercially operable(2)
7

 
104

 
106

 
987

 
1,204

Transmission
101

 
163

 
127

 
429

 
820

Fuel purchase agreements(2):
 
 
 
 
 
 
 
 
 
Natural gas supply and transportation
78

 
56

 
55

 
199

 
388

Coal supply and transportation
754

 
779

 
438

 
576

 
2,547

Other purchase obligations
1,173

 
96

 
70

 
204

 
1,543

Other long-term liabilities(3)
26

 
12

 
16

 
57

 
111

Total contractual cash obligations
$
2,997

 
$
3,358

 
$
2,879

 
$
14,629

 
$
23,863


(1)
Consists of principal and interest for tax-exempt bond obligations with interest rates scheduled to reset periodically prior to maturity. Future variable interest rates are assumed to equal December 31, 2019 rates. Refer to "Interest Rate Risk" in Item 7A of this Form 10-K for additional discussion related to variable-rate liabilities.
(2)
Commodity contracts are agreements for the delivery of energy. Capacity contracts are agreements that provide rights to energy output, generally of a specified generating facility. Forecasted or other applicable estimated prices were used to determine total dollar value of the commitments. PacifiCorp has several contracts for purchases of electricity from facilities that have not yet achieved commercial operation. To the extent any of these facilities do not achieve commercial operation, PacifiCorp has no obligation to the counterparty.
(3)
Includes environmental and hydroelectric relicensing commitments recorded in the Consolidated Balance Sheets that are contractually or legally binding. Excludes regulatory liabilities and employee benefit plan obligations that are not legally or contractually fixed as to timing and amount. Deferred income taxes are excluded since cash payments are based primarily on taxable income for each year. Uncertain tax positions are also excluded because the amounts and timing of cash payments are not certain.

Regulatory Matters

PacifiCorp is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further discussion regarding PacifiCorp's general regulatory framework and current regulatory matters.


190


Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. PacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and financial results.

Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.

Collateral and Contingent Features

Debt and preferred securities of PacifiCorp are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of PacifiCorp's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. As of December 31, 2019, PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt by Moody's Investor Service and Standard & Poor's Rating Services were investment grade.

PacifiCorp has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt and a change in ratings is not an event of default under the applicable debt instruments. PacifiCorp's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities. Certain authorizations or exemptions by regulatory commissions for the issuance of securities are valid as long as PacifiCorp maintains investment grade ratings on senior secured debt. A downgrade below that level would necessitate new regulatory applications and approvals.

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2019, PacifiCorp would have been required to post $232 million of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors. Refer to Note 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for a discussion of PacifiCorp's collateral requirements specific to PacifiCorp's derivative contracts.

Inflation

Historically, overall inflation and changing prices in the economies where PacifiCorp operates have not had a significant impact on PacifiCorp's consolidated financial results. PacifiCorp operates under a cost-of-service based rate structure administered by various state commissions and the FERC. Under this rate structure, PacifiCorp is allowed to include prudent costs in its rates, including the impact of inflation. PacifiCorp attempts to minimize the potential impact of inflation on its operations through the use of energy and other cost adjustment clauses and tariff riders, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.


191


Off-Balance Sheet Arrangements

PacifiCorp from time to time enters into arrangements in the normal course of business to facilitate commercial transactions with third parties that involve guarantees or similar arrangements. PacifiCorp currently has indemnification obligations in connection with the sale of certain assets. In addition, PacifiCorp evaluates potential obligations that arise out of variable interests in unconsolidated entities, determined in accordance with authoritative accounting guidance. PacifiCorp believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these obligations is remote. Refer to Notes 11 and 19 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for more information on these obligations and arrangements.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting PacifiCorp, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by PacifiCorp's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with PacifiCorp's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

Accounting for the Effects of Certain Types of Regulation

PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, PacifiCorp defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in rates occur.

PacifiCorp continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit PacifiCorp's ability to recover its costs. PacifiCorp believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI"). Total regulatory assets were $1.1 billion and total regulatory liabilities were $3.0 billion as of December 31, 2019. Refer to Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's regulatory assets and liabilities.

Derivatives

PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.


192


PacifiCorp has established a risk management process that is designed to identify, assess, manage, mitigate, monitor and report, each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices. As of December 31, 2019, PacifiCorp had no derivative contracts outstanding related to interest rate risk. Refer to Notes 12 and 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's derivative contracts.

Measurement Principles

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by accounting principles generally accepted in the United States of America. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. As of December 31, 2019, PacifiCorp had a net derivative liability of $63 million related to contracts valued using either quoted prices or forward price curves based upon observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. The assumptions used in these models are critical because any changes in assumptions could have a significant impact on the estimated fair value of the contracts. As of December 31, 2019, PacifiCorp had a net derivative asset of $- million related to contracts where PacifiCorp uses internal models with significant unobservable inputs.

Classification and Recognition Methodology

PacifiCorp's derivative contracts are probable of inclusion in rates and changes in the estimated fair value of derivative contracts are generally recorded as regulatory assets. Accordingly, amounts are generally not recognized in earnings until the contracts are settled and the forecasted transaction has occurred. As of December 31, 2019, PacifiCorp had $62 million recorded as a regulatory asset related to derivative contracts on the Consolidated Balance Sheets.

Pension and Other Postretirement Benefits

PacifiCorp sponsors defined benefit pension and other postretirement benefit plans that cover the majority of its employees. In addition, PacifiCorp contributes to a joint trustee pension plan for benefits offered to certain bargaining units. PacifiCorp recognizes the funded status of its defined benefit pension and other postretirement benefit plans on the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2019, PacifiCorp recognized a net liability totaling $101 million for the funded status of its defined benefit pension and other postretirement benefit plans. As of December 31, 2019, amounts not yet recognized as a component of net periodic benefit cost that were included in net regulatory assets and accumulated other comprehensive loss totaled $402 million and $21 million, respectively.

The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rate and expected long-term rate of return on plan assets. These key assumptions are reviewed annually and modified as appropriate. PacifiCorp believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 10 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about PacifiCorp's defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2019.


193


PacifiCorp chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.

In establishing its assumption as to the expected long-term rate of return on plan assets, PacifiCorp evaluates the investment allocation between return-seeking investment and fixed income securities based on the funded status of the plan and utilizes the asset allocation and return assumptions for each asset class based on forward-looking views of the financial markets and historical performance. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. PacifiCorp regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.

The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and the funded status. If changes were to occur for the following key assumptions, the approximate effect on the Consolidated Financial Statements would be as follows (in millions):

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plan
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
 
 
 
 
 
 
Effect on December 31, 2019 Benefit Obligations:
 
 
 
 
 
 
 
Discount rate
$
(59
)
 
$
65

 
$
(12
)
 
$
13

 
 
 
 
 
 
 
 
Effect on 2019 Periodic Cost:
 
 
 
 
 
 
 
Discount rate
$

 
$

 
$
1

 
$
(1
)
Expected rate of return on plan assets
(5
)
 
5

 
(2
)
 
2


A variety of factors affect the funded status of the plans, including asset returns, discount rates, mortality assumptions, plan changes and PacifiCorp's funding policy for each plan.

Income Taxes

In determining PacifiCorp's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by PacifiCorp's various regulatory commissions. PacifiCorp's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. PacifiCorp recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of PacifiCorp's federal, state and local income tax examinations is uncertain, PacifiCorp believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on PacifiCorp's consolidated financial results. PacifiCorp's unrecognized tax benefits are primarily included in other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations. Refer to Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's income taxes.

It is probable that PacifiCorp will pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property-related basis differences and other various differences on to their customers in certain state jurisdictions. As of December 31, 2019, these amounts were recognized as a net regulatory liability of $1.7 billion and will be included in regulated rates when the temporary differences reverse.


194


Revenue Recognition - Unbilled Revenue

Revenue is recognized as electricity is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since the date of the last meter reading is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $245 million as of December 31, 2019. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.

Item 7A. 
Quantitative and Qualitative Disclosures About Market Risk

PacifiCorp's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. PacifiCorp's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which PacifiCorp transacts. The following discussion addresses the significant market risks associated with PacifiCorp's business activities. PacifiCorp has established guidelines for credit risk management. Refer to Notes 2 and 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's contracts accounted for as derivatives.

Risk Management

PacifiCorp has a risk management committee that is responsible for the oversight of market and credit risk relating to the commodity transactions of PacifiCorp. To limit PacifiCorp's exposure to market and credit risk, the risk management committee recommends, and executive management establishes, policies, limits and approved products, which are reviewed frequently to respond to changing market conditions.

Risk is an inherent part of PacifiCorp's business and activities. PacifiCorp has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in PacifiCorp's business. The risk management policy governs energy transactions and is designed for hedging PacifiCorp's existing energy and asset exposures, and to a limited extent, the policy permits arbitrage and trading activities to take advantage of market inefficiencies. The policy also governs the types of transactions authorized for use and establishes guidelines for credit risk management and management information systems required to effectively monitor such transactions. PacifiCorp's risk management policy provides for the use of only those contracts that have a similar volume or price relationship to its portfolio of assets, liabilities or anticipated transactions.

Commodity Price Risk

PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as PacifiCorp has an obligation to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. PacifiCorp does not engage in a material amount of proprietary trading activities. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. PacifiCorp's exposure to commodity price risk is generally limited by its ability to include commodity costs in rates, which is subject to regulatory lag that occurs between the time the costs are incurred and when the costs are included in rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.

PacifiCorp measures the market risk in its electricity and natural gas portfolio daily, utilizing a historical Value-at-Risk ("VaR") approach and other measurements of net position. PacifiCorp also monitors its portfolio exposure to market risk in comparison to established thresholds and measures its open positions subject to price risk in terms of quantity at each delivery location for each forward time period. VaR computations for the electricity and natural gas commodity portfolio are based on a historical simulation technique, utilizing historical price changes over a specified (holding) period to simulate potential forward energy market price curve movements to estimate the potential unfavorable impact of such price changes on the portfolio positions. The quantification of market risk using VaR provides a consistent measure of risk across PacifiCorp's continually changing portfolio. VaR represents an estimate of possible changes at a given level of confidence in fair value that would be measured on its portfolio assuming hypothetical movements in forward market prices and is not necessarily indicative of actual results that may occur.


195


PacifiCorp's VaR computations utilize several key assumptions. The calculation includes short-term commodity contracts, the expected resource and demand obligations from PacifiCorp's long-term contracts, the expected generation levels from PacifiCorp's generation assets and the expected retail and wholesale load levels. The portfolio reflects flexibility contained in contracts and assets, which accommodate the normal variability in PacifiCorp's demand obligations and generation availability. These contracts and assets are valued to reflect the variability PacifiCorp experiences as a load-serving entity. Contracts or assets that contain flexible elements are often referred to as having embedded options or option characteristics. These options provide for energy volume changes that are sensitive to market price changes. Therefore, changes in the option values affect the energy position of the portfolio with respect to market prices, and this effect is calculated daily. When measuring portfolio exposure through VaR, these position changes that result from the option sensitivity are held constant through the historical simulation. PacifiCorp's VaR methodology is based on a 36-month forward position, 95% confidence interval and one-day holding period.

As of December 31, 2019, PacifiCorp's estimated potential one-day unfavorable impact on fair value of the electricity and natural gas commodity portfolio over the next 36 months was $14 million, as measured by the VaR computations described above. The minimum, average and maximum daily VaR (one-day holding periods) were as follows for the year ended December 31 (in millions):

 
2019
Minimum VaR (measured)
$
7

Average VaR (calculated)
9

Maximum VaR (measured)
16


PacifiCorp maintained compliance with its VaR limit procedures during the year ended December 31, 2019. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed estimated VaR levels.

Fair Value of Derivatives

The table that follows summarizes PacifiCorp's price risk on commodity contracts accounted for as derivatives, excluding collateral netting of $47 million and $59 million as of December 31, 2019 and 2018, respectively, and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions):

 
Fair Value -
 
Estimated Fair Value after
 
 Net Asset
 
Hypothetical Change in Price
 
(Liability)
 
10% increase
 
10% decrease
As of December 31, 2019:
 
 
 
 
 
Total commodity derivative contracts
$
(63
)
 
$
(44
)
 
$
(82
)
 
 
 
 
 
 
As of December 31, 2018
 
 
 
 
 
Total commodity derivative contracts
$
(97
)
 
$
(92
)
 
$
(102
)

PacifiCorp's commodity derivative contracts are generally recoverable from customers in rates; therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose PacifiCorp to earnings volatility. As of December 31, 2019 and 2018, a regulatory asset of $62 million and $96 million, respectively, was recorded related to the net derivative liability of $63 million and $97 million, respectively. Consolidated financial results would be negatively impacted if the costs of wholesale electricity, natural gas or fuel are higher or the level of wholesale electricity sales are lower than what is included in rates, including the impacts of adjustment mechanisms.


196


Interest Rate Risk

PacifiCorp is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, PacifiCorp's fixed-rate long-term debt does not expose PacifiCorp to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if PacifiCorp were to reacquire all or a portion of these instruments prior to their maturity. PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. The nature and amount of PacifiCorp's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7, 8 and 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of PacifiCorp's short- and long-term debt.

As of December 31, 2019 and 2018, PacifiCorp had short- and long-term variable-rate obligations totaling $385 million and $285 million, respectively that expose PacifiCorp to the risk of increased interest expense in the event of increases in short-term interest rates. The market risk related to PacifiCorp's variable-rate debt as of December 31, 2019 is not hedged. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on PacifiCorp's consolidated annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2019 and 2018.

Credit Risk

PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

As of December 31, 2019, PacifiCorp's aggregate credit exposure with wholesale energy supply and marketing counterparties included counterparties having non-investment grade, internally rated credit ratings. Substantially all of these non-investment grade, internally rated counterparties are associated with long-duration solar and wind power purchase agreements from facilities that have not yet achieved commercial operation and for which PacifiCorp has no obligation should the facilities not achieve commercial operation.


197


Item 8.
Financial Statements and Supplementary Data



198



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of PacifiCorp
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PacifiCorp and subsidiaries ("PacifiCorp") as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of PacifiCorp as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of PacifiCorp’s management. Our responsibility is to express an opinion on PacifiCorp’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to PacifiCorp in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. PacifiCorp is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of PacifiCorp’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.


/s/ Deloitte & Touche LLP

Portland, Oregon
February 21, 2020

We have served as PacifiCorp's auditor since 2006.


199


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)

 
As of December 31,
 
2019
 
2018
 
 
 
 
ASSETS
 
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
30

 
$
77

Trade receivables, net
644

 
640

Other receivables, net
70

 
92

Inventories
394

 
417

Other current assets
152

 
133

Total current assets
1,290

 
1,359

 
 
 
 
Property, plant and equipment, net
20,973

 
19,570

Regulatory assets
1,060

 
1,076

Other assets
374

 
308

 
 
 
 
Total assets
$
23,697

 
$
22,313


The accompanying notes are an integral part of these consolidated financial statements.



200



PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)

 
As of December 31,
 
2019
 
2018
 
 
 
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
679

 
$
597

Accrued interest
116

 
114

Accrued property, income and other taxes
96

 
75

Accrued employee expenses
75

 
79

Short-term debt
130

 
30

Current portion of long-term debt
38

 
350

Regulatory liabilities
56

 
77

Other current liabilities
170

 
193

Total current liabilities
1,360

 
1,515

 
 
 
 
Long-term debt
7,620

 
6,665

Regulatory liabilities
2,913

 
2,978

Deferred income taxes
2,563

 
2,543

Other long-term liabilities
804

 
767

Total liabilities
15,260

 
14,468

 
 
 
 
Commitments and contingencies (Note 14)

 

 
 
 
 
Shareholders' equity:
 
 
 
Preferred stock
2

 
2

Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding

 

Additional paid-in capital
4,479

 
4,479

Retained earnings
3,972

 
3,377

Accumulated other comprehensive loss, net
(16
)
 
(13
)
Total shareholders' equity
8,437

 
7,845

 
 
 
 
Total liabilities and shareholders' equity
$
23,697

 
$
22,313


The accompanying notes are an integral part of these consolidated financial statements.


201


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Operating revenue
$
5,068

 
$
5,026

 
$
5,237

 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
Cost of fuel and energy
1,795

 
1,757

 
1,770

Operations and maintenance
1,048

 
1,038

 
1,034

Depreciation and amortization
954

 
979

 
796

Property and other taxes
199

 
201

 
197

Total operating expenses
3,996

 
3,975

 
3,797

 
 
 
 
 
 
Operating income
1,072

 
1,051

 
1,440

 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
Interest expense
(401
)
 
(384
)
 
(381
)
Allowance for borrowed funds
36

 
18

 
11

Allowance for equity funds
72

 
35

 
20

Interest and dividend income
21

 
15

 
11

Other, net
32

 
8

 
27

Total other expense
(240
)
 
(308
)
 
(312
)
 
 
 
 
 
 
Income before income tax expense
832

 
743

 
1,128

Income tax expense
61

 
5

 
360

Net income
$
771

 
$
738

 
$
768


The accompanying notes are an integral part of these consolidated financial statements.


202


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Net income
$
771

 
$
738

 
$
768

 
 
 
 
 
 
Other comprehensive (loss) income, net of tax —
 
 
 
 
 
Unrecognized amounts on retirement benefits, net of tax of ($1), $1 and $3
(3
)
 
2

 
(3
)
 
 
 
 
 
 
Comprehensive income
$
768

 
$
740

 
$
765


The accompanying notes are an integral part of these consolidated financial statements.


203


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(Amounts in millions)

 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
Additional
 
 
 
Other
 
Total
 
Preferred
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
Shareholders'
 
Stock
 
Stock
 
Capital
 
Earnings
 
Loss, Net
 
Equity
Balance, December 31, 2016
$
2

 
$

 
$
4,479

 
$
2,921

 
$
(12
)
 
$
7,390

Net income

 

 

 
768

 

 
768

Other comprehensive loss

 

 

 

 
(3
)
 
(3
)
Common stock dividends declared

 

 

 
(600
)
 

 
(600
)
Balance, December 31, 2017
2

 

 
4,479

 
3,089

 
(15
)
 
7,555

Net income

 

 

 
738

 

 
738

Other comprehensive income

 

 

 

 
2

 
2

Common stock dividends declared

 

 

 
(450
)
 

 
(450
)
Balance, December 31, 2018
2

 

 
4,479

 
3,377

 
(13
)
 
7,845

Net income

 

 

 
771

 

 
771

Other comprehensive loss

 

 

 
(1
)
 
(3
)
 
(4
)
Common stock dividends declared

 

 

 
(175
)
 

 
(175
)
Balance, December 31, 2019
$
2

 
$

 
$
4,479

 
$
3,972

 
$
(16
)
 
$
8,437


The accompanying notes are an integral part of these consolidated financial statements.


204


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
Cash flows from operating activities:
 
 
 
 
 
Net income
$
771

 
$
738

 
$
768

Adjustments to reconcile net income to net cash flows from operating
 
 
 
 
 
activities:

 

 

Depreciation and amortization
954

 
979

 
796

Allowance for equity funds
(72
)
 
(35
)
 
(20
)
Changes in regulatory assets and liabilities
(55
)
 
87

 
18

Deferred income taxes and amortization of investment tax credits
(131
)
 
(199
)
 
70

Other, net
20

 
5

 
9

Changes in other operating assets and liabilities:
 
 
 
 
 
Trade receivables, other receivables and other assets
14

 
62

 
67

Inventories
23

 
16

 
10

Derivative collateral, net
12

 
15

 
(6
)
Accrued property, income and other taxes, net
22

 
60

 
(48
)
Accounts payable and other liabilities
(11
)
 
83

 
(62
)
Net cash flows from operating activities
1,547

 
1,811

 
1,602

 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
Capital expenditures
(2,175
)
 
(1,257
)
 
(769
)
Other, net
11

 
5

 
12

Net cash flows from investing activities
(2,164
)
 
(1,252
)
 
(757
)
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
Proceeds from long-term debt
989

 
593

 

Repayments of long-term debt
(350
)
 
(586
)
 
(52
)
Net proceeds from (repayments of) short-term debt
100

 
(50
)
 
(190
)
Dividends paid
(175
)
 
(450
)
 
(600
)
Other, net
(3
)
 
(3
)
 
(7
)
Net cash flows from financing activities
561

 
(496
)
 
(849
)
 
 
 
 
 
 
Net change in cash and cash equivalents and restricted cash and cash equivalents
(56
)
 
63

 
(4
)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period
92

 
29

 
33

Cash and cash equivalents and restricted cash and cash equivalents at end of period
$
36

 
$
92

 
$
29


The accompanying notes are an integral part of these consolidated financial statements.


205


PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)    Organization and Operations

PacifiCorp, which includes PacifiCorp and its subsidiaries, is a United States regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining services. PacifiCorp is an indirect subsidiary of Berkshire Hathaway Energy Company ("BHE"), a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

(2)    Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

The Consolidated Financial Statements include the accounts of PacifiCorp and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated.

Use of Estimates in Preparation of Financial Statements

The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.

Accounting for the Effects of Certain Types of Regulation

PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, PacifiCorp defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in rates occur.

PacifiCorp continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit PacifiCorp's ability to recover its costs. PacifiCorp believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").

Fair Value Measurements

As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.

206



Cash Equivalents and Restricted Cash and Cash Equivalents and Investments

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds representing escrow accounts for disputes, vendor retention, custodial and nuclear decommissioning funds. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets.

Investments

Available-for-sale securities are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. As of December 31, 2019 and 2018, PacifiCorp had no unrealized gains and losses on available-for-sale securities. Trading securities are carried at fair value with realized and unrealized gains and losses recognized in earnings.

Equity Method Investments

PacifiCorp utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when an investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate the ability to exercise significant influence is restricted. In applying the equity method, PacifiCorp records the investment at cost and subsequently increases or decreases the carrying value of the investment by PacifiCorp's proportionate share of the net earnings or losses and other comprehensive income (loss) ("OCI") of the investee. PacifiCorp records dividends or other equity distributions as reductions in the carrying value of the investment.

Allowance for Doubtful Accounts

Accounts receivable are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts. The allowance for doubtful accounts is based on PacifiCorp's assessment of the collectability of amounts owed to PacifiCorp by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. As of December 31, 2019 and 2018, the allowance for doubtful accounts totaled $8 million and is included in trade receivables, net on the Consolidated Balance Sheets.

Derivatives

PacifiCorp employs a number of different derivative contracts, which may include forwards, options, swaps and other agreements, to manage price risk for electricity, natural gas and other commodities and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.

Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or energy costs on the Consolidated Statements of Operations.

For PacifiCorp's derivative contracts, the settled amount is generally included in rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in rates are recorded as regulatory liabilities or assets. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.

Inventories

Inventories consist mainly of materials, supplies and fuel stocks and are stated at the lower of average cost or net realizable value.


207


Property, Plant and Equipment, Net

General

Additions to property, plant and equipment are recorded at cost. PacifiCorp capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs, which include debt and equity allowance for funds used during construction ("AFUDC"). The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed.

Depreciation and amortization are generally computed on the straight-line method based on composite asset class lives prescribed by PacifiCorp's various regulatory authorities or over the assets' estimated useful lives. Depreciation studies are completed periodically to determine the appropriate composite asset class lives, net salvage and depreciation rates. These studies are reviewed and rates are ultimately approved by the various regulatory authorities. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.

Generally when PacifiCorp retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.

Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of property, plant and equipment, is capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, PacifiCorp is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.

Asset Retirement Obligations

PacifiCorp recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. PacifiCorp's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.

Impairment

PacifiCorp evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment supports PacifiCorp's regulated businesses the impacts of regulation are considered when evaluating the carrying value of regulated assets.


208


Leases

PacifiCorp has non-cancelable operating leases primarily for land, office space, office equipment, and generating facilities and finance leases consisting primarily of office buildings, natural gas pipeline facilities, and generating facilities. These leases generally require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. PacifiCorp does not include options in its lease calculations unless there is a triggering event indicating PacifiCorp is reasonably certain to exercise the option. PacifiCorp's accounting policy is to not recognize lease obligations and corresponding right-of-use assets for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Right-of-use assets will be evaluated for impairment in line with ASC 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.

PacifiCorp's leases of generating facilities generally are in the form of long-term purchases of electricity, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.

PacifiCorp's operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly.

Revenue Recognition

PacifiCorp uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which PacifiCorp expects to be entitled in exchange for those goods or services. PacifiCorp records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.

Substantially all of PacifiCorp's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission and distribution and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of revenue recognized in accordance with ASC 815, "Derivatives and Hedging."

Revenue recognized is equal to what PacifiCorp has the right to invoice as it corresponds directly with the value to the customer of PacifiCorp's performance to date and includes billed and unbilled amounts. As of December 31, 2019 and 2018, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $245 million and $229 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.

Income Taxes

Berkshire Hathaway includes PacifiCorp in its consolidated United States federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for income taxes has been computed on a stand-alone basis.


209


Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimated income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain property-related basis differences and other various differences that PacifiCorp deems probable to be passed on to its customers in most state jurisdictions are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse or as otherwise approved by PacifiCorp's various regulatory commissions. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.

Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions. Investment tax credits are included in other long-term liabilities on the Consolidated Balance Sheets and were $11 million and $13 million as of December 31, 2019 and 2018, respectively.

In determining PacifiCorp's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by PacifiCorp's various regulatory commissions. PacifiCorp's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. PacifiCorp recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of PacifiCorp's federal, state and local income tax examinations is uncertain, PacifiCorp believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on PacifiCorp's consolidated financial results. PacifiCorp's unrecognized tax benefits are primarily included in other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.

Unamortized Debt Premiums, Discounts and Debt Issuance Costs

Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.

Segment Information

PacifiCorp currently has one segment, which includes its regulated electric utility operations.

New Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, which creates FASB Accounting Standards Codification ("ASC") Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize on the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. PacifiCorp has elected to utilize various practical expedients available to adopt ASU No. 2016-02, including (1) the package of three not requiring a reassessment of (i) whether any expired or existing contracts are or contain leases; (ii) the lease classification for any expired or existing leases; and (iii) initial direct costs for any existing leases; (2) using hindsight in determining the lease term; and (3) not requiring a reassessment of whether existing or expired land easements that were not previously accounted for as leases under ASC Topic 840 are or contain a lease under ASC Topic 842. PacifiCorp adopted this guidance for all applicable contracts in effect as of January 1, 2019 under a modified retrospective method and the adoption did not have a cumulative effect impact at the date of initial adoption.



210


(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following as of December 31 (in millions):

 
Depreciable Life
 
2019
 
2018
Utility Plant:
 
 
 
 
 
Generation
14 - 67 years
 
$
12,509

 
$
12,606

Transmission
58 - 75 years
 
6,482

 
6,357

Distribution
20 - 70 years
 
7,307

 
7,030

Intangible plant(1)
5 - 75 years
 
1,016

 
970

Other
5 - 60 years
 
1,449

 
1,436

Utility plant in service
 
 
28,763

 
28,399

Accumulated depreciation and amortization
 
 
(9,803
)
 
(10,034
)
Utility plant in service, net
 
 
18,960

 
18,365

Other non-regulated, net of accumulated depreciation and amortization
46 years
 
10

 
10

Plant, net
 
 
18,970

 
18,375

Construction work-in-progress
 
 
2,003

 
1,195

Property, plant and equipment, net
 
 
$
20,973

 
$
19,570


(1)
Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years.

The average depreciation and amortization rate applied to depreciable property, plant and equipment was 3.3%, 3.5% and 2.9% for the years ended December 31, 2019, 2018 and 2017, respectively, including the impacts of accelerated depreciation for Oregon’s share of certain wind equipment retired as a result of wind repowering projects placed into service in 2019 and accelerated depreciation for Utah’s share of certain thermal plant units in 2018.

PacifiCorp filed a depreciation study in 2018 with all of its state public utility commissions, except the California Public Utilities Commission. PacifiCorp is currently working with the commissions and interested parties and anticipates revised depreciation rates to be effective January 1, 2021.

Unallocated Acquisition Adjustments

PacifiCorp has unallocated acquisition adjustments that represent the excess of costs of the acquired interests in property, plant and equipment purchased from the entity that first dedicated the assets to utility service over their net book value in those assets. These unallocated acquisition adjustments included in other property, plant and equipment had an original cost of $156 million as of December 31, 2019 and 2018, and accumulated depreciation of $132 million and $127 million as of December 31, 2019 and 2018, respectively.



211


(4)    Jointly Owned Utility Facilities

Under joint facility ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly owned generation, transmission and distribution facilities. PacifiCorp accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include PacifiCorp's share of the expenses of these facilities.

The amounts shown in the table below represent PacifiCorp's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2019 (dollars in millions):
 
 
 
Facility
 
Accumulated
 
Construction
 
PacifiCorp
 
in
 
Depreciation and
 
Work-in-
 
Share
 
Service
 
Amortization
 
Progress
 
 
 
 
 
 
 
 
Jim Bridger Nos. 1 - 4
67
%
 
$
1,476

 
$
677

 
$
9

Hunter No. 1
94

 
484

 
193

 
1

Hunter No. 2
60

 
305

 
121

 
2

Wyodak
80

 
473

 
243

 
1

Colstrip Nos. 3 and 4
10

 
254

 
137

 
2

Hermiston
50

 
181

 
92

 
5

Craig Nos. 1 and 2
19

 
368

 
252

 

Hayden No. 1
25

 
75

 
39

 

Hayden No. 2
13

 
43

 
23

 

Transmission and distribution facilities
Various
 
808

 
255

 
103

Total
 
 
$
4,467

 
$
2,032

 
$
123



212


(5)    Leases

The following table summarizes PacifiCorp's leases recorded on the Consolidated Balance Sheet (in millions):
 
As of
 
December 31, 2019
Right-of-use assets:
 
Operating leases
$
12

Finance leases
19

Total right-of-use assets
$
31

 
 
Lease liabilities:
 
Operating leases
$
12

Finance leases
19

Total lease liabilities
$
31


The following table summarizes PacifiCorp's lease costs (in millions):
 
Year Ended
 
December 31, 2019
 
 
Variable
$
77

Operating
3

Finance:
 
Amortization
1

Interest
2

Short-term
2

Total lease costs
$
85

 
 
Weighted-average remaining lease term (years):
 
Operating leases
14.0

Finance leases
9.1

 
 
Weighted-average discount rate:
 
Operating leases
3.7
%
Finance leases
10.6
%

Cash payments associated with operating and finance lease liabilities approximated lease cost for the year ended December 31, 2019.


213


PacifiCorp has the following remaining lease commitments as of (in millions):
 
December 31, 2019
 
Operating
 
Finance
 
Total
2020
$
2

 
$
3

 
$
5

2021
2

 
7

 
9

2022
2

 
3

 
5

2023
2

 
2

 
4

2024
1

 
2

 
3

Thereafter
7

 
14

 
21

Total undiscounted lease payments
16

 
31

 
47

Less - amounts representing interest
(4
)
 
(12
)
 
(16
)
Lease liabilities
$
12

 
$
19

 
$
31

 
December 31, 2018(1)
 
Operating
 
Capital
 
Total
2019
$
3

 
$
4

 
$
7

2020
3

 
4

 
7

2021
3

 
7

 
10

2022
2

 
3

 
5

2023
2

 
2

 
4

Thereafter
7

 
16

 
23

Total undiscounted lease payments
$
20

 
$
36

 
$
56


(1)     Amounts included for comparability and accounted for in accordance with ASC 840, "Leases".  


214


(6)    Regulatory Matters

Regulatory Assets

Regulatory assets represent costs that are expected to be recovered in future rates. PacifiCorp's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
 
Weighted
 
 
 
 
 
Average
 
 
 
 
 
Remaining
 
 
 
 
 
Life
 
2019
 
2018
 
 
 
 
 
 
Employee benefit plans(1)
19 years
 
$
422

 
$
448

Utah mine disposition(2)
Various
 
125

 
136

Unamortized contract values
4 years
 
60

 
79

Deferred net power costs
2 years
 
106

 
62

Unrealized loss on derivative contracts
3 years
 
62

 
96

Asset retirement obligation
28 years
 
140

 
119

Other
Various
 
208

 
172

Total regulatory assets
 
 
$
1,123

 
$
1,112

 
 
 
 
 
 
Reflected as:
 
 
 
 
 
Current assets
 
 
$
63

 
$
36

Noncurrent assets
 
 
1,060

 
1,076

Total regulatory assets
 
 
$
1,123

 
$
1,112


(1)
Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in rates when recognized.

(2)
Amounts represent regulatory assets established as a result of the Utah mine disposition in 2015 for the net property, plant and equipment not considered probable of disallowance and for the portion of losses associated with the assets held for sale, UMWA 1974 Pension Plan withdrawal and closure costs incurred to date considered probable of recovery.

PacifiCorp had regulatory assets not earning a return on investment of $609 million and $636 million as of December 31, 2019 and 2018, respectively.


215


Regulatory Liabilities

Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. PacifiCorp's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
 
Weighted
 
 
 
 
 
Average
 
 
 
 
 
Remaining
 
 
 
 
 
Life
 
2019
 
2018
 
 
 
 
 
 
Cost of removal(1)
26 years
 
$
1,019

 
$
994

Deferred income taxes(2)
Various
 
1,653

 
1,803

Other
Various
 
297

 
258

Total regulatory liabilities
 
 
$
2,969

 
$
3,055

 
 
 
 
 
 
Reflected as:
 
 
 
 
 
Current liabilities
 
 
$
56

 
$
77

Noncurrent liabilities
 
 
2,913

 
2,978

Total regulatory liabilities
 
 
$
2,969

 
$
3,055


(1)
Amounts represent estimated costs, as accrued through depreciation rates, of removing property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.

(2)
Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable of being passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.



216


(7)    Short-term Debt and Credit Facilities

The following table summarizes PacifiCorp's availability under its credit facilities as of December 31 (in millions):
2019:
 
 
Credit facilities
 
$
1,200

Less:
 
 
Short-term debt
 
(130
)
Tax-exempt bond support
 
(256
)
Net credit facilities
 
$
814

 
 
 
2018:
 
 
Credit facilities
 
$
1,200

Less:
 
 
Short-term debt
 
(30
)
Tax-exempt bond support
 
(89
)
Net credit facilities
 
$
1,081


As of December 31, 2019, PacifiCorp was in compliance with the covenants of its credit facilities and letter of credit arrangements.

PacifiCorp has a $600 million unsecured credit facility expiring in June 2022 and a $600 million unsecured credit facility expiring in June 2022 with one remaining one-year extension option subject to lender consent. These credit facilities, which support PacifiCorp's commercial paper program, certain series of its tax-exempt bond obligations and provide for the issuance of letters of credit, have variable interest rates based on the Eurodollar rate or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities.

As of December 31, 2019 and 2018, the weighted average interest rate on commercial paper borrowings outstanding was 2.05% and 2.85%, respectively. These credit facilities require that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.

As of December 31, 2019 and 2018, PacifiCorp had $13 million and $184 million, respectively, of fully available letters of credit issued under committed arrangements. As of December 31, 2019 and 2018, $13 million and $14 million, respectively, support certain transactions required by third parties and generally have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.


217


(8)    Long-term Debt

PacifiCorp's long-term debt was as follows as of December 31 (dollars in millions):
 
2019
 
2018
 
 
 
 
 
Average
 
 
 
Average
 
Principal
 
Carrying
 
Interest
 
Carrying
 
Interest
 
Amount
 
Value
 
Rate
 
Value
 
Rate
 
 
 
 
 
 
 
 
 
 
First mortgage bonds:
 
 
 
 
 
 
 
 
 
2.95% to 8.53%, due through 2024
$
1,899

 
$
1,895

 
4.09
%
 
$
2,244

 
4.31
%
3.35% to 6.71%, due 2025 to 2026
350

 
349

 
4.31

 
348

 
4.31

3.50% to 7.70%, due 2029 to 2031
700

 
696

 
5.30

 
298

 
7.70

5.25% to 6.35%, due 2034 to 2038
2,350

 
2,338

 
5.96

 
2,338

 
5.96

4.10% to 6.00%, due 2039 to 2042
950

 
939

 
5.40

 
939

 
5.40

4.13% to 4.15%, due 2049 to 2050
1,200

 
1,186

 
4.14

 
593

 
4.13

Variable-rate series, tax-exempt bond obligations (2019-1.60% to 1.80%; 2018-1.67% to 1.85%):
 
 
 
 
 
 
 
 
 
Due 2020
38

 
38

 
1.78

 
38

 
1.85

Due 2024(1)(2)
143

 
143

 
1.73

 
142

 
1.68

Due 2025(1)
25

 
24

 
1.75

 
25

 
1.75

Due 2024 to 2025(2)
50

 
50

 
1.63

 
50

 
1.75

Total long-term debt
$
7,705

 
$
7,658

 
 
 
$
7,015

 
 
Reflected as:
 
 
 
 
2019
 
2018
 
 
 
 
Current portion of long-term debt
$
38

 
$
350

Long-term debt
7,620

 
6,665

Total long-term debt
$
7,658

 
$
7,015


1)
Supported by $170 million of fully available letters of credit issued under committed bank arrangements as of December 31, 2018. These arrangements were canceled in 2019.
2)
Secured by pledged first mortgage bonds registered to and held by the tax-exempt bond trustee generally with the same interest rates, maturity dates and redemption provisions as the tax-exempt bond obligations.
PacifiCorp's long-term debt generally includes provisions that allow PacifiCorp to redeem the first mortgage bonds in whole or in part at any time through the payment of a make-whole premium. Variable-rate tax-exempt bond obligations are generally redeemable at par value.

PacifiCorp currently has regulatory authority from the Oregon Public Utility Commission and the Idaho Public Utilities Commission to issue an additional $1.0 billion of long-term debt. PacifiCorp must make a notice filing with the Washington Utilities and Transportation Commission prior to any future issuance. PacifiCorp currently has an effective shelf registration statement filed with the United States Securities and Exchange Commission (SEC) to issue up to $1.0 billion additional first mortgage bonds through October 2021.

The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's mortgage. Approximately $29 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage as of December 31, 2019.







218


As of December 31, 2019, the annual principal maturities of long-term debt for 2020 and thereafter are as follows (in millions):

 
Long-term
 
Debt
 
 
2020
$
38

2021
420

2022
605

2023
449

2024
591

Thereafter
5,602

Total
7,705

Unamortized discount and debt issuance costs
(47
)
Total
$
7,658


(9)    Income Taxes

Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
 
2019
 
2018
 
2017
 
 
 
 
 
 
Current:
 
 
 
 
 
Federal
$
158

 
$
164

 
$
249

State
34

 
40

 
41

Total
192

 
204

 
290

 
 
 
 
 
 
Deferred:
 
 
 
 
 
Federal
(132
)
 
(187
)
 
59

State
4

 
(9
)
 
15

Total
(128
)
 
(196
)
 
74

 
 
 
 
 
 
Investment tax credits
(3
)
 
(3
)
 
(4
)
Total income tax expense
$
61

 
$
5

 
$
360


A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Federal statutory income tax rate
21
 %
 
21
 %
 
35
 %
State income taxes, net of federal income tax benefit
3

 
4

 
3

Amortization of excess deferred income taxes
(11
)
 
(17
)
 

Effects of ratemaking
(2
)
 

 
1

Federal income tax credits
(3
)
 
(7
)
 
(5
)
Other
(1
)
 

 
(2
)
Effective income tax rate
7
 %
 
1
 %
 
32
 %


219


Income tax credits relate primarily to production tax credits ("PTC") earned by PacifiCorp's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. Amortization of excess deferred income taxes is primarily attributable to the amortization of $91 million of Oregon allocated excess deferred income taxes pursuant to the Oregon Renewable Adjustment Clause settlement, whereby a portion of Oregon allocated excess deferred income taxes was used to accelerate depreciation on Oregon's share of certain repowered wind facilities. Amortization of excess deferred income taxes in 2018 is primarily attributable to the amortization of $127 million of Utah allocated excess deferred income taxes pursuant to a 2017 Tax Reform settlement approved by the UPSC, whereby a portion of Utah allocated excess deferred income taxes was used to accelerate depreciation on Utah's share of certain thermal plant units.

The net deferred income tax liability consists of the following as of December 31 (in millions):
 
2019
 
2018
 
 
 
 
Deferred income tax assets:
 
 
 
Regulatory liabilities
$
731

 
$
752

Employee benefits
83

 
91

Derivative contracts and unamortized contract values
33

 
45

State carryforwards
70

 
77

Asset retirement obligations
61

 
53

Other
68

 
56

 
1,046

 
1,074

Deferred income tax liabilities:
 
 
 
Property, plant and equipment
(3,312
)
 
(3,335
)
Regulatory assets
(276
)
 
(273
)
Other
(21
)
 
(9
)
 
(3,609
)
 
(3,617
)
Net deferred income tax liability
$
(2,563
)
 
$
(2,543
)

The following table provides PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December 31, 2019 (in millions):
 
 
State
 
 
 
Net operating loss carryforwards
 
$
1,140

Deferred income taxes on net operating loss carryforwards
 
$
51

Expiration dates
 
2023 - 2032

 
 
 
Tax credit carryforwards
 
$
19

Expiration dates
 
2020 - indefinite


The United States Internal Revenue Service has closed its examination of PacifiCorp's income tax returns through December 31, 2011. The statute of limitations for PacifiCorp's state income tax returns have expired through December 31, 2011, with the exception of California, Utah and Oregon, for which the statutes have expired through December 31, 2009. In addition, Idaho's statute of limitations has expired through December 31, 2015, except for the impact of any federal audit adjustments. The statute of limitations expiring for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
 
(10)    Employee Benefit Plans

PacifiCorp sponsors defined benefit pension and other postretirement benefit plans that cover the majority of its employees, as well as a defined contribution 401(k) employee savings plan ("401(k) Plan"). In addition, PacifiCorp contributes to a joint trustee pension plan and a subsidiary previously contributed to a multiemployer pension plan for benefits offered to certain bargaining units.

Defined Benefit Plans

PacifiCorp's pension plans include non-contributory defined benefit pension plans, collectively the PacifiCorp Retirement Plan ("Retirement Plan"), and the Supplemental Executive Retirement Plan ("SERP"). The Retirement Plan is closed to all non-union employees hired after January 1, 2008. All non-union Retirement Plan participants hired prior to January 1, 2008 that did not elect to receive equivalent fixed contributions to the 401(k) Plan effective January 1, 2009 earned benefits based on a cash balance formula through December 31, 2016. Effective January 1, 2017, non-union employee participants with a cash balance benefit in the Retirement Plan are no longer eligible to receive pay credits in their cash balance formula. In general for union employees, benefits under the Retirement Plan were frozen at various dates from December 31, 2007 through December 31, 2011 as they are now being provided with enhanced 401(k) Plan benefits. However, certain limited union Retirement Plan participants continue to earn benefits under the Retirement Plan based on the employee's years of service and a final average pay formula. The SERP was closed to new participants as of March 21, 2006 and froze future accruals for active participants as of December 31, 2014.

During 2018, the Retirement Plan incurred a settlement charge of $22 million as a result of excess lump sum distributions over the defined threshold for the year ended December 31, 2018.

PacifiCorp's other postretirement benefit plan provides healthcare and life insurance benefits to eligible retirees.

Net Periodic Benefit Cost

For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the first year in which they occur.

Net periodic benefit cost for the plans included the following components for the years ended December 31 (in millions):

 
Pension
 
Other Postretirement
 
2019
 
2018
 
2017
 
2019
 
2018
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
Service cost
$

 
$

 
$

 
$
2

 
$
2

 
$
2

Interest cost
44

 
43

 
49

 
12

 
11

 
14

Expected return on plan assets
(67
)
 
(72
)
 
(72
)
 
(21
)
 
(21
)
 
(21
)
Settlement

 
22

 

 

 

 

Net amortization
11

 
13

 
14

 

 
(6
)
 
(6
)
Net periodic benefit (credit) cost
$
(12
)
 
$
6

 
$
(9
)
 
$
(7
)
 
$
(14
)
 
$
(11
)

Funded Status

The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Plan assets at fair value, beginning of year
$
942

 
$
1,111

 
$
297

 
$
332

Employer contributions
4

 
4

 
1

 
1

Participant contributions

 

 
5

 
5

Actual return on plan assets
181

 
(52
)
 
55

 
(16
)
Settlement

 
(52
)
 

 

Benefits paid
(91
)
 
(69
)
 
(24
)
 
(25
)
Plan assets at fair value, end of year
$
1,036

 
$
942

 
$
334

 
$
297



220


The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Benefit obligation, beginning of year
$
1,105

 
$
1,251

 
$
298

 
$
331

Service cost

 

 
2

 
2

Interest cost
44

 
43

 
12

 
11

Participant contributions

 

 
5

 
5

Actuarial loss (gain)
109

 
(68
)
 
11

 
(26
)
Settlement

 
(52
)
 

 

Benefits paid
(91
)
 
(69
)
 
(24
)
 
(25
)
Benefit obligation, end of year
$
1,167

 
$
1,105

 
$
304

 
$
298

Accumulated benefit obligation, end of year
$
1,167

 
$
1,105

 
 
 
 
The funded status of the plans and the amounts recognized on the Consolidated Balance Sheets as of December 31 are as follows (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Plan assets at fair value, end of year
$
1,036

 
$
942

 
$
334

 
$
297

Less - Benefit obligation, end of year
1,167

 
1,105

 
304

 
298

Funded status
$
(131
)
 
$
(163
)
 
$
30

 
$
(1
)
 
 
 
 
 
 
 
 
Amounts recognized on the Consolidated Balance Sheets:
 
 
 
 
 
 
 
Other assets
$
7

 
$
3

 
$
30

 
$

Other current liabilities
(4
)
 
(4
)
 

 

Other long-term liabilities
(134
)
 
(162
)
 

 
(1
)
Amounts recognized
$
(131
)
 
$
(163
)
 
$
30

 
$
(1
)

The SERP has no plan assets; however, PacifiCorp has a Rabbi trust that holds corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERP. The cash surrender value of all of the policies included in the Rabbi trust, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $57 million and $52 million as of December 31, 2019 and 2018, respectively. These assets are not included in the plan assets in the above table, but are reflected in cash and cash equivalents, totaling $- million and $1 million as of December 31, 2019 and 2018, respectively, and noncurrent other assets, totaling $57 million and $51 million as of December 31, 2019 and 2018, respectively, on the Consolidated Balance Sheets.

The projected benefit obligation and the accumulated benefit obligation for the pension plan were both in excess of the fair value of the plan assets as of December 31, 2019.

Unrecognized Amounts

The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Net loss (gain)
$
442

 
$
461

 
$
(26
)
 
$
(2
)
Regulatory deferrals
1

 
(1
)
 
6

 
7

Total
$
443

 
$
460

 
$
(20
)
 
$
5



221


A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2019 and 2018 is as follows (in millions):
 
 
 
Accumulated
 
 
 
 
 
Other
 
 
 
Regulatory
 
Comprehensive
 
 
 
Asset
 
Loss
 
Total
Pension
 
 
 
 
 
Balance, December 31, 2017
$
418

 
$
20

 
$
438

Net loss (gain) arising during the year
59

 
(2
)
 
57

Net amortization
(12
)
 
(1
)
 
(13
)
Settlement
(22
)
 

 
(22
)
Total
25

 
(3
)
 
22

Balance, December 31, 2018
443

 
17

 
460

Net (gain) loss arising during the year
(11
)
 
5

 
(6
)
Net amortization
(10
)
 
(1
)
 
(11
)
Total
(21
)
 
4

 
(17
)
Balance, December 31, 2019
$
422

 
$
21

 
$
443


 
Regulatory
 
Asset (Liability)
Other Postretirement
 
Balance, December 31, 2017
$
(11
)
Net loss arising during the year
10

Net amortization
6

Total
16

Balance, December 31, 2018
5

Net gain arising during the year
(25
)
Net amortization

Total
(25
)
Balance, December 31, 2019
$
(20
)


222


Plan Assumptions

Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2017
 
2019
 
2018
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
Benefit obligations as of December 31:
 
 
 
 
 
 
 
 
 
 
 
Discount rate
3.25
%
 
4.25
%
 
3.60
%
 
3.20
%
 
4.25
%
 
3.60
%
Rate of compensation increase
N/A

 
N/A

 
N/A

 
N/A

 
N/A

 
N/A

 
 
 
 
 
 
 
 
 
 
 
 
Interest crediting rates for cash balance plan (1)(2)(3)
2.27
%
 
3.40
%
 
1.61
%
 
N/A

 
N/A

 
N/A

 
 
 
 
 
 
 
 
 
 
 
 
Net periodic benefit cost for the years ended December 31:
 
 
 
 
 
 
 
 
 
 
Discount rate
4.25
%
 
3.60
%
 
4.05
%
 
4.25
%
 
3.60
%
 
4.05
%
Expected return on plan assets
7.00

 
7.00

 
7.25

 
6.86

 
6.86

 
7.25

Rate of compensation increase
N/A

 
N/A

 
N/A

 
N/A

 
N/A

 
N/A


(1)
2019 Cash Balance Interest Crediting Rate assumption is 2.27% for 2020-2021 and 2.10% for 2022 and all future years for nonunion participants and 2.16% for 2020-2021 and 2.70% for 2022+ for union participants.
(2)
2018 Cash Balance Interest Crediting Rate assumption was 3.40% for 2019 and all future years for nonunion participants and 3.15% for 2019-2020 and 3.25% for 2021+ for union participants.
(3)
2017 Cash Balance Interest Crediting Rate assumption was 2.26% for 2018-2019 and 1.60% for 2020+ for nonunion participants and 2.78% for 2018-2019 and 2.60% for 2020+ for union participants.
In establishing its assumption as to the expected return on plan assets, PacifiCorp utilizes the asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets.

As a result of a plan amendment effective on January 1, 2017, the benefit obligation for the Retirement Plan is no longer affected by future increases in compensation. As a result of a labor settlement reached with UMWA in December 2014, the benefit obligation for the other postretirement plan is no longer affected by healthcare cost trends.

Contributions and Benefit Payments

Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $- million, respectively, during 2020. Funding to PacifiCorp's Retirement Plan trust is based upon the actuarially determined costs of the plan and the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 ("ERISA") and the Pension Protection Act of 2006, as amended ("PPA"). PacifiCorp considers contributing additional amounts from time to time in order to achieve certain funding levels specified under the PPA. PacifiCorp evaluates a variety of factors, including funded status, income tax laws and regulatory requirements, in determining contributions to its other postretirement benefit plan.

The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2020 through 2024 and for the five years thereafter are summarized below (in millions):
 
Projected Benefit Payments
 
Pension
 
Other Postretirement
 
 
 
 
2020
$
112

 
$
27

2021
98

 
24

2022
94

 
23

2023
89

 
23

2024
83

 
21

2025-2029
350

 
94



223


Plan Assets

Investment Policy and Asset Allocations

PacifiCorp's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The plans retain outside investment advisors to manage plan investments within the parameters outlined by the PacifiCorp Pension Committee. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments.

The target allocations (percentage of plan assets) for PacifiCorp's pension and other postretirement benefit plan assets are as follows as of December 31, 2019:
 
Pension(1)
 
Other Postretirement(1)
 
%
 
%
Debt securities(2)
30 - 43
 
33 - 37
Equity securities(2)
48 - 65
 
62 - 66
Limited partnership interests
6 - 12
 
1 - 3

(1)
PacifiCorp's Retirement Plan trust includes a separate account that is used to fund benefits for the other postretirement benefit plan. In addition to this separate account, the assets for the other postretirement benefit plan are held in Voluntary Employees' Beneficiary Association ("VEBA") trusts, each of which has its own investment allocation strategies. Target allocations for the other postretirement benefit plan include the separate account of the Retirement Plan trust and the VEBA trusts.
(2)
For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities.

224


Fair Value Measurements
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit pension plan (in millions):
 
 
Input Levels for Fair Value Measurements
 
 
 
 
Level 1(1)
 
Level 2(1)
 
Level 3(1)
 
Total
As of December 31, 2019:
 
 
 
 
 
 
 
 
Cash equivalents
 
$

 
$
24

 
$

 
$
24

Debt securities:
 
 
 
 
 
 
 
 
United States government obligations
 
21

 

 

 
21

Corporate obligations
 

 
94

 

 
94

Municipal obligations
 

 
10

 

 
10

Agency, asset and mortgage-backed obligations
 

 
42

 

 
42

Equity securities:
 
 
 
 
 
 
 
 
United States companies
 
355

 

 

 
355

International companies
 
15

 

 

 
15

Investment funds(2)
 
55

 

 

 
55

Total assets in the fair value hierarchy
 
$
446

 
$
170

 
$

 
616

Investment funds(2) measured at net asset value
 
 
 
 
 
 
 
327

Limited partnership interests(3) measured at net asset value
 
 
 
 
 
 
 
93

Investments at fair value
 
 
 
 
 
 
 
$
1,036

 
 
 
 
 
 
 
 
 
As of December 31, 2018:
 
 
 
 
 
 
 
 
Cash equivalents
 
$

 
$
11

 
$

 
$
11

Debt securities:
 
 
 
 
 
 
 
 
United States government obligations
 
4

 

 

 
4

International government obligations
 

 
1

 

 
1

Corporate obligations
 

 
88

 

 
88

Municipal obligations
 

 
10

 

 
10

Agency, asset and mortgage-backed obligations
 

 
43

 

 
43

Equity securities:
 
 
 
 
 
 
 
 
United States companies
 
327

 

 

 
327

International companies
 
15

 

 

 
15

Investment funds(2)
 
54

 

 

 
54

Total assets in the fair value hierarchy
 
$
400

 
$
153

 
$

 
553

Investment funds(2) measured at net asset value
 
 
 
 
 
 
 
285

Limited partnership interests(3) measured at net asset value
 
 
 
 
 
 
 
104

Investments at fair value
 
 
 
 
 
 
 
$
942


(1)
Refer to Note 13 for additional discussion regarding the three levels of the fair value hierarchy.
(2)
Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 55% and 45% respectively, for both 2019 and 2018, and are invested in United States and international securities of approximately 51% and 49%, respectively, for 2019 and 68% and 32%, respectively, for 2018.
(3)
Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.

225


The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit other postretirement plan (in millions):
 
 
Input Levels for Fair Value Measurements
 
 
 
 
Level 1(1)
 
Level 2(1)
 
Level 3(1)
 
Total
As of December 31, 2019:
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
8

 
$
1

 
$

 
$
9

Debt securities:
 
 
 
 
 
 
 
 
United States government obligations
 
12

 

 

 
12

Corporate obligations
 

 
26

 

 
26

Municipal obligations
 

 
2

 

 
2

Agency, asset and mortgage-backed obligations
 

 
22

 

 
22

Equity securities:
 
 
 
 
 
 
 
 
United States companies
 
74

 

 

 
74

International companies
 
4

 

 

 
4

Investment funds(2)
 
44

 

 

 
44

Total assets in the fair value hierarchy
 
142

 
51

 

 
193

Investment funds(2) measured at net asset value
 
 
 
 
 
 
 
136

Limited partnership interests(3) measured at net asset value
 
 
 
 
 
 
 
5

Investments at fair value
 
 
 
 
 
 
 
$
334

 
 
 
 
 
 
 
 
 
As of December 31, 2018:
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
4

 
$
1

 
$

 
$
5

Debt securities:
 
 
 
 
 
 
 
 
United States government obligations
 
3

 

 

 
3

Corporate obligations
 

 
23

 

 
23

Municipal obligations
 

 
2

 

 
2

Agency, asset and mortgage-backed obligations
 

 
17

 

 
17

Equity securities:
 
 
 
 
 
 
 
 
United States companies
 
83

 

 

 
83

International companies
 
4

 

 

 
4

Investment funds(2)
 
38

 

 

 
38

Total assets in the fair value hierarchy
 
132

 
43

 

 
175

Investment funds(2) measured at net asset value
 
 
 
 
 
 
 
116

Limited partnership interests(3) measured at net asset value
 
 
 
 
 
 
 
6

Investments at fair value
 
 
 
 
 
 
 
$
297


(1)
Refer to Note 13 for additional discussion regarding the three levels of the fair value hierarchy.
(2)
Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 56% and 44%, respectively, for 2019 and 59% and 41%, respectively, for 2018, and are invested in United States and international securities of approximately 79% and 21%, respectively, for 2019 and 90% and 10%, respectively, for 2018.
(3)
Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.
For level 1 investments, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. For level 2 investments, the fair value is determined using pricing models based on observable market inputs. Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.


226


Multiemployer and Joint Trustee Pension Plans

PacifiCorp contributes to the PacifiCorp/IBEW Local 57 Retirement Trust Fund ("Local 57 Trust Fund") (plan number 001) and its subsidiary, Energy West Mining Company, previously contributed to the UMWA 1974 Pension Plan (plan number 002). Contributions to these pension plans are based on the terms of collective bargaining agreements.

As a result of the Utah Mine Disposition and United Mine Workers of America ("UMWA") labor settlement, PacifiCorp's subsidiary, Energy West Mining Company, triggered involuntary withdrawal from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceased performing work for the subsidiary. PacifiCorp recorded its estimate of the withdrawal obligation in December 2014 when withdrawal was considered probable and deferred the portion of the obligation considered probable of recovery to a regulatory asset. PacifiCorp has subsequently revised its estimate due to changes in facts and circumstances for a withdrawal occurring by July 2015. As communicated in a letter received in August 2016, the plan trustees determined a withdrawal liability of $115 million. Energy West Mining Company began making installment payments in November 2016 and has the option to elect a lump sum payment to settle the withdrawal obligation. The ultimate amount paid by Energy West Mining Company to settle the obligation is dependent on a variety of factors, including the results of ongoing negotiations with the plan trustees.

The Local 57 Trust Fund is a joint trustee plan such that the board of trustees is represented by an equal number of trustees from PacifiCorp and the union. The Local 57 Trust Fund was established pursuant to the provisions of the Taft-Hartley Act and although formed with the ability for other employers to participate in the plan, there are no other employers that participate in this plan.

The risk of participating in multiemployer pension plans generally differs from single-employer plans in that assets are pooled such that contributions by one employer may be used to provide benefits to employees of other participating employers and plan assets cannot revert back to employers. If an employer ceases participation in the plan, the employer may be obligated to pay a withdrawal liability based on the participants' unfunded, vested benefits in the plan. This occurred as a result of Energy West Mining Company's withdrawal from the UMWA 1974 Pension Plan. If participating employers withdraw from a multiemployer plan, the unfunded obligations of the plan may be borne by the remaining participating employers.

The following table presents PacifiCorp's participation in individually significant joint trustee and multiemployer pension plans for the years ended December 31 (dollars in millions):

 
 
 
 
PPA zone status or
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
plan funded status percentage for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
plan years beginning July 1,
 
 
 
 
 
Contributions(1)
 
 
Plan name
 
Employer Identification Number
 
2019
 
2018
 
2017
 
Funding improvement plan
 
Surcharge imposed under PPA(1)
 
2019
 
2018
 
2017
 
Year contributions to plan exceeded more than 5% of total contributions(2)
Local 57 Trust Fund
 
87-0640888
 
At least 80%
 
At least 80%
 
At least 80%
 
None
 
None
 
$
7

 
$
7

 
$
7

 
2017, 2016, 2015

(1)
PacifiCorp's minimum contributions to the plan are based on the amount of wages paid to employees covered by the Local 57 Trust Fund collective bargaining agreements, subject to ERISA minimum funding requirements.

(2)
For the Local 57 Trust Fund, information is for plan years beginning July 1, 2017, 2016 and 2015. Information for the plan year beginning July 1, 2018 is not yet available.

The current collective bargaining agreements governing the Local 57 Trust Fund expire in 2023.

Defined Contribution Plan

PacifiCorp's 401(k) plan covers substantially all employees. PacifiCorp's matching contributions are based on each participant's level of contribution and, as of January 1, 2019, all participants receive contributions based on eligible pre-tax annual compensation. Contributions cannot exceed the maximum allowable for tax purposes. PacifiCorp's contributions to the 401(k) plan were $40 million, $39 million and $39 million for the years ended December 31, 2019, 2018 and 2017, respectively.


227


(11)    Asset Retirement Obligations

PacifiCorp estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.

PacifiCorp does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. Cost of removal regulatory liabilities totaled $1,019 million and $994 million as of December 31, 2019 and 2018, respectively.

The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 31 (in millions):
 
2019
 
2018
 
 
 
 
Beginning balance
$
227

 
$
215

Change in estimated costs
27

 
9

Additions
9

 

Retirements
(15
)
 
(5
)
Accretion
9

 
8

Ending balance
$
257

 
$
227

 
 
 
 
Reflected as:
 
 
 
Other current liabilities
$
19

 
$
21

Other long-term liabilities
238

 
206

 
$
257

 
$
227


Certain of PacifiCorp's decommissioning and reclamation obligations relate to jointly owned facilities and mine sites. PacifiCorp is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, PacifiCorp may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. PacifiCorp's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities.

(12)    Risk Management and Hedging Activities

PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.

PacifiCorp has established a risk management process that is designed to identify, assess, manage, mitigate, monitor and report, each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

228



There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.

The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):

 
Other
 
 
 
Other
 
Other
 
 
 
Current
 
Other
 
Current
 
Long-term
 
 
 
Assets
 
Assets
 
Liabilities
 
Liabilities
 
Total
 
 
 
 
 
 
 
 
 
 
As of December 31, 2019:
 
 
 
 
 
 
 
 
 
Not designated as hedging contracts(1):
 
 
 
 
 
 
 
 
 
Commodity assets
$
15

 
$
2

 
$
4

 
$

 
$
21

Commodity liabilities
(3
)
 

 
(31
)
 
(50
)
 
(84
)
Total
12

 
2

 
(27
)
 
(50
)
 
(63
)
 
 
 
 
 
 
 
 
 
 
Total derivatives
12

 
2

 
(27
)
 
(50
)
 
(63
)
Cash collateral receivable

 

 
20

 
27

 
47

Total derivatives - net basis
$
12

 
$
2

 
$
(7
)
 
$
(23
)
 
$
(16
)
 
 
 
 
 
 
 
 
 
 
As of December 31, 2018:
 
 
 
 
 
 
 
 
 
Not designated as hedging contracts(1):
 
 
 
 
 
 
 
 
 
Commodity assets
$
36

 
$
4

 
$
10

 
$
1

 
$
51

Commodity liabilities
(9
)
 
(1
)
 
(67
)
 
(71
)
 
(148
)
Total
27

 
3

 
(57
)
 
(70
)
 
(97
)
 
 
 
 
 
 
 
 
 
 
Total derivatives
27

 
3

 
(57
)
 
(70
)
 
(97
)
Cash collateral (payable) receivable
(2
)
 

 
16

 
45

 
59

Total derivatives - net basis
$
25

 
$
3

 
$
(41
)
 
$
(25
)
 
$
(38
)
(1)
PacifiCorp's commodity derivatives are generally included in rates and as of December 31, 2019 and 2018, a regulatory asset of $62 million and $96 million, respectively, was recorded related to the net derivative liability of $63 million and $97 million, respectively.

229


The following table reconciles the beginning and ending balances of PacifiCorp's regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in regulatory assets, as well as amounts reclassified to earnings for the years ended December 31 (in millions):
 
2019
 
2018
 
2017
 
 
 
 
 
 
Beginning balance
$
96

 
$
101

 
$
73

Changes in fair value recognized in regulatory assets
(37
)
 
12

 
47

Net (losses) gains reclassified to operating revenue
(34
)
 
(68
)
 
9

Net gains (losses) reclassified to energy costs
37

 
51

 
(28
)
Ending balance
$
62

 
$
96

 
$
101


Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of December 31 (in millions):
 
Unit of
 
 
 
 
 
Measure
 
2019
 
2018
 
 
 
 
 
 
Electricity sales
Megawatt hours
 
(2
)
 
(6
)
Natural gas purchases
Decatherms
 
129

 
117


Credit Risk

PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

Collateral and Contingent Features

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2019, PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt by Moody's Investor Service and Standard & Poor's Rating Services were investment grade.

The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $80 million and $113 million as of December 31, 2019 and 2018, respectively, for which PacifiCorp had posted collateral of $47 million and $61 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of December 31, 2019 and 2018, PacifiCorp would have been required to post $27 million and $35 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.


230


(13)
Fair Value Measurements

The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the ability to access at the measurement date.

Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

Level 3 - Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including its own data.

The following table presents PacifiCorp's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
 
Input Levels for Fair Value Measurements
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other(1)
 
Total
As of December 31, 2019:
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
Commodity derivatives
$

 
$
21

 
$

 
$
(7
)
 
$
14

Money market mutual funds(2)
23

 

 

 

 
23

Investment funds
25

 

 

 

 
25

 
$
48

 
$
21

 
$

 
$
(7
)
 
$
62

 
 
 
 
 
 
 
 
 
 
Liabilities - Commodity derivatives
$

 
$
(84
)
 
$

 
$
54

 
$
(30
)
 
 
 
 
 
 
 
 
 
 
As of December 31, 2018:
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
Commodity derivatives
$

 
$
51

 
$

 
$
(23
)
 
$
28

Money market mutual funds (2)
69

 

 

 

 
69

Investment funds
24

 

 

 

 
24

 
$
93

 
$
51

 
$

 
$
(23
)
 
$
121

 
 
 
 
 
 
 
 
 
 
Liabilities - Commodity derivatives
$

 
$
(148
)
 
$

 
$
82

 
$
(66
)

(1)
Represents netting under master netting arrangements and a net cash collateral receivable of $47 million and $59 million as of December 31, 2019 and 2018, respectively.
(2)
Amounts are included in cash and cash equivalents, other current assets and other assets on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.

231


Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. Refer to Note 12 for further discussion regarding PacifiCorp's risk management and hedging activities.

PacifiCorp's investments in money market mutual funds and investment funds are stated at fair value and are primarily accounted for as available-for-sale securities. When available, PacifiCorp uses a readily observable quoted market price or net asset value of an identical security in an active market to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.

PacifiCorp's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of PacifiCorp's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt as of December 31 (in millions):
 
2019
 
2018
 
Carrying
 
Fair
 
Carrying
 
Fair
 
Value
 
Value
 
Value
 
Value
 
 
 
 
 
 
 
 
Long-term debt
$
7,658

 
$
9,280

 
$
7,015

 
$
7,833


(14)    Commitments and Contingencies

Legal Matters

PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
    
Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.

232



Hydroelectric Relicensing

PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA does not guarantee dam removal. Instead, it establishes a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the Federal Energy Regulatory Commission ("FERC") license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.

In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four main-stem Klamath dams from PacifiCorp to the KRRC. Over the past two years, the KRRC has been supplementing the application with additional information about its financial, technical, and legal capacity to become the licensee. In July 2019, the KRRC provided the FERC with additional information about its financial capacity to become a licensee, including updated cost estimates, and its insurance, bonding and liability transfer package. The FERC is evaluating the KRRC's information and the proposed license transfer. The KRRC will continue to refine its insurance, bonding and liability transfer package, and PacifiCorp will review the KRRC's capacity to fulfill its indemnity obligation under the KHSA. If certain conditions in the amended KHSA are not satisfied (e.g., inadequate funding or inability of KRRC to satisfy its indemnification obligation) and the license does not transfer to the KRRC, PacifiCorp will resume relicensing with the FERC.

The United States Court of Appeals for the District of Columbia Circuit issued a decision in the Hoopa Valley Tribe v. FERC litigation, in January 2019, finding that the states of California and Oregon have waived their Clean Water Act, Section 401, water quality certification authority over the Klamath hydroelectric project relicensing. This decision has the potential to limit the ability of the States to impose water quality conditions on new and relicensed projects. Environmental interests, supported by California, Oregon and other states, asked the court to rehear the case, which was denied. Subsequently, environmental groups, supported by numerous states, filed a petition for certiorari before the United States Supreme Court, which was denied on December 9, 2019, thereby allowing the circuit court opinion to stand as a final and unappealable decision.

As of December 31, 2019, PacifiCorp's assets included $29 million of costs associated with the Klamath hydroelectric system's mainstem dams and the associated relicensing and settlement costs, which are being depreciated and amortized in accordance with state regulatory approvals in Utah, Wyoming and Idaho through December 31, 2022.

Hydroelectric Commitments

Certain of PacifiCorp's hydroelectric licenses contain requirements for PacifiCorp to make certain capital and operating expenditures related to its hydroelectric facilities. PacifiCorp estimates it is obligated to make capital expenditures of approximately $168 million over the next 10 years related to these licenses.


233


Commitments

PacifiCorp has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2019 are as follows (in millions):

 
2020
 
2021
 
2022
 
2023
 
2024
 
2025 and Thereafter
 
Total
Contract type:
 
 
 
 
 
 
 
 
 
 
 
 
 
Purchased electricity contracts -
 
 
 
 
 
 
 
 
 
 
 
 
 
commercially operable
$
279

 
$
177

 
$
174

 
$
168

 
$
164

 
$
1,810

 
$
2,772

Purchased electricity contracts -
 
 
 
 
 
 
 
 
 
 
 
 
 
non-commercially operable
7

 
52

 
52

 
53

 
53

 
987

 
1,204

Fuel contracts
832

 
519

 
316

 
245

 
248

 
775

 
2,935

Construction commitments
844

 
6

 

 

 
4

 

 
854

Transmission
101

 
86

 
77

 
71

 
56

 
429

 
820

Easements
10

 
12

 
12

 
12

 
11

 
349

 
406

Maintenance, service and
 
 
 
 
 
 
 
 
 
 
 
 
 
other contracts
329

 
49

 
41

 
34

 
32

 
204

 
689

Total commitments
$
2,402

 
$
901

 
$
672

 
$
583

 
$
568

 
$
4,554

 
$
9,680

    
Purchased Electricity Contracts - Commercially Operable

As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-term purchases and exchange agreements. PacifiCorp has several power purchase agreements with solar or wind-powered generating facilities that are not included in the table above as the payments are based on the amount of energy generated and there are no minimum payments. Refer to Note 5 for information on lease commitments.

Included in the minimum fixed annual payments for purchased electricity above are commitments to purchase electricity from several hydroelectric systems under long-term arrangements with public utility districts. These purchases are made on a "cost-of-service" basis for a stated percentage of system output and for a like percentage of system operating expenses and debt service. These costs are included in energy costs on the Consolidated Statements of Operations. PacifiCorp is required to pay its portion of operating costs and its portion of the debt service, whether or not any electricity is produced. These arrangements accounted for less than 5% of PacifiCorp's 2019, 2018 and 2017 energy sources.

Purchased Electricity Contracts - Non-commercially Operable

PacifiCorp has several contracts for purchases of electricity from facilities that have not yet achieved commercial operation. To the extent any of these facilities do not achieve commercial operation, PacifiCorp has no obligation to the counterparty.

Fuel Contracts

PacifiCorp has "take or pay" coal and natural gas contracts that require minimum payments.

Construction Commitments

PacifiCorp's construction commitments included in the table above relate to firm commitments and include costs associated with certain generating plant, transmission, and distribution projects.

Transmission

PacifiCorp has contracts for the right to transmit electricity over other entities' transmission lines to facilitate delivery to PacifiCorp's customers.
    

234


Easements

PacifiCorp has non-cancelable easements for land on which certain of its assets, primarily wind-powered generating facilities, are located.

Guarantees

PacifiCorp has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on PacifiCorp's consolidated financial results.

(15)    Revenue from Contracts with Customers

The following table summarizes PacifiCorp's revenue by regulated energy, with further disaggregation of regulated energy by customer class, for the years ended December 31 (in millions):
 
2019
 
2018
Customer Revenue:
 
 
 
Retail:
 
 
 
Residential
$
1,783

 
$
1,737

Commercial
1,522

 
1,513

Industrial
1,176

 
1,172

Other retail
230

 
234

Total retail
4,711

 
4,656

Wholesale
99

 
55

Transmission
98

 
103

Other Customer Revenue
78

 
76

Total Customer Revenue
4,986

 
4,890

Other revenue
82

 
136

Total operating revenue
$
5,068

 
$
5,026


(16)    Preferred Stock

PacifiCorp has 3,500 thousand shares of Serial Preferred Stock authorized at the stated value of $100 per share. PacifiCorp had 24 thousand shares of Serial Preferred Stock issued and outstanding as of December 31, 2019 and 2018. The outstanding preferred stock series are non-redeemable and have annual dividend rates of 6.00% and 7.00%.

In the event of voluntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends. Upon involuntary liquidation, all preferred stock is entitled to stated value plus accrued dividends. Dividends on all preferred stock are cumulative. Holders also have the right to elect members to the PacifiCorp Board of Directors in the event dividends payable are in default in an amount equal to four full quarterly payments.

PacifiCorp also has 16 million shares of No Par Serial Preferred Stock and 127 thousand shares of 5% Preferred Stock authorized, but no shares were issued or outstanding as of December 31, 2019 and 2018.

(17)    Common Shareholder's Equity

Through PPW Holdings, BHE is the sole shareholder of PacifiCorp's common stock. The state regulatory orders that authorized BHE's acquisition of PacifiCorp contain restrictions on PacifiCorp's ability to pay dividends to the extent that they would reduce PacifiCorp's common equity below specified percentages of defined capitalization. As of December 31, 2019, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to PPW Holdings or BHE without prior state regulatory approval to the extent that it would reduce PacifiCorp's common equity below 44% of its total capitalization, excluding short-term debt and current maturities of long-term debt. As of December 31, 2019, PacifiCorp's actual common equity percentage, as calculated under this measure, was 53%, and PacifiCorp would have been permitted to dividend $2.4 billion under this commitment.


235


These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings or BHE if PacifiCorp's senior unsecured debt rating is BBB- or lower by Standard & Poor's Rating Services or Fitch Ratings, or Baa3 or lower by Moody's Investor Service, as indicated by two of the three rating services. As of December 31, 2019, PacifiCorp met the minimum required senior unsecured debt ratings for making distributions.

PacifiCorp is also subject to a maximum debt-to-total capitalization percentage under various financing agreements as further discussed in Note 7.

(18)    Components of Accumulated Other Comprehensive Loss, Net

Accumulated other comprehensive loss, net consists of unrecognized amounts on retirement benefits, net of tax, of $16 million and $13 million as of December 31, 2019 and 2018, respectively.

(19)    Variable-Interest Entities

PacifiCorp holds a two-thirds interest in Bridger Coal Company ("Bridger Coal"), which supplies coal to the Jim Bridger generating facility that is owned two-thirds by PacifiCorp and one-third by PacifiCorp's joint venture partner in Bridger Coal. PacifiCorp purchases two-thirds of the coal produced by Bridger Coal, while the remaining coal is purchased by the joint venture partner. The power to direct the activities that most significantly impact Bridger Coal's economic performance are shared with the joint venture partner. Each joint venture partner is jointly and severally liable for the obligations of Bridger Coal. Bridger Coal's necessary working capital to carry out its mining operations is financed by contributions from PacifiCorp and its joint venture partner. PacifiCorp's equity investment in Bridger Coal was $81 million and $100 million as of December 31, 2019 and 2018, respectively. Refer to Note 21 for information regarding related-party transactions with Bridger Coal.

(20)    Supplemental Cash Flow Disclosures

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2019 and 2018, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
 
2019
 
2018
Cash and cash equivalents
$
30

 
$
77

Restricted cash included in other current assets
4

 
13

Restricted cash included in other assets
2

 
2

Total cash and cash equivalents and restricted cash and cash equivalents
$
36

 
$
92


The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
 
 
2019
 
2018
 
2017
 
 
 
 
 
 
 
Interest paid, net of amounts capitalized
 
$
340

 
$
347

 
$
350

Income taxes paid, net
 
$
171

 
$
144

 
$
340

Supplemental disclosure of non-cash investing and financing activities:
Accounts payable related to property, plant and equipment additions
 
$
293

 
$
184

 
$
147


236



(21)    Related-Party Transactions

PacifiCorp has an intercompany administrative services agreement with BHE and its subsidiaries. Amounts charged to PacifiCorp by BHE and its subsidiaries under this agreement totaled $10 million, $12 million and $11 million during the years ended December 31, 2019, 2018 and 2017, respectively. Payables associated with these administrative services were immaterial as of December 31, 2019 and 2018, respectively. Amounts charged by PacifiCorp to BHE and its subsidiaries under this agreement, as well as receivables associated with these administrative services, were immaterial during the years ended December 31, 2019, 2018 and 2017, respectively.

PacifiCorp also engages in various transactions with several subsidiaries of BHE in the ordinary course of business. Services provided by these subsidiaries in the ordinary course of business and charged to PacifiCorp primarily relate to wholesale electricity purchases and transmission of electricity, transportation of natural gas and employee relocation services. These expenses totaled $7 million, $8 million and $6 million during the years ended December 31, 2019, 2018 and 2017, respectively. Payables associated with these services were immaterial as of December 31, 2019 and 2018, respectively. Amounts charged by PacifiCorp to subsidiaries of BHE for wholesale electricity sales in the ordinary course of business were immaterial during the years ended December 31, 2019, 2018 and 2017, respectively.

PacifiCorp has long-term transportation contracts with BNSF Railway Company ("BNSF"), an indirect wholly owned subsidiary of Berkshire Hathaway, PacifiCorp's ultimate parent company. Transportation costs under these contracts were $35 million, $33 million and $35 million during the years ended December 31, 2019, 2018 and 2017, respectively. As of December 31, 2019 and 2018, PacifiCorp had immaterial amounts of accounts payable to BNSF outstanding under these contracts, including indirect payables related to a jointly owned facility.

PacifiCorp is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated United States federal income tax return. Federal and state income taxes payable to BHE were $31 million and $10 million as of December 31, 2019 and 2018, respectively. For the years ended December 31, 2019, 2018 and 2017, cash paid for federal and state income taxes to BHE totaled $171 million, $144 million and $340 million, respectively.

PacifiCorp transacts with its equity investees, Bridger Coal and Trapper Mining Inc. During the years ended December 31, 2019, 2018 and 2017, PacifiCorp charged Bridger Coal immaterial amounts, primarily for administrative support and management services provided by PacifiCorp to Bridger Coal. Receivables for these services, as well as for certain expenses paid by PacifiCorp and reimbursed by Bridger Coal, were immaterial as of December 31, 2019 and 2018, respectively. Services provided by equity investees to PacifiCorp primarily relate to coal purchases. During the years ended December 31, 2019, 2018 and 2017, coal purchases from PacifiCorp's equity investees totaled $155 million, $163 million and $170 million, respectively. Payables to PacifiCorp's equity investees were $12 million and $13 million as of December 31, 2019 and 2018, respectively.


237


MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
Consolidated Financial Section

238


Item 6.
Selected Financial Data

Information required by Item 6 is omitted pursuant to General Instruction I(2)(a) to Form 10-K.

Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of MidAmerican Funding and its subsidiaries and MidAmerican Energy during the periods included herein. Information in Management's Discussion and Analysis related to MidAmerican Energy, whether or not segregated, also relates to MidAmerican Funding. Information related to other subsidiaries of MidAmerican Funding pertains only to the discussion of the financial condition and results of operations of MidAmerican Funding. Where necessary, discussions have been segregated under the heading "MidAmerican Funding" to allow the reader to identify information applicable only to MidAmerican Funding. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with MidAmerican Funding's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements and MidAmerican Energy's historical Financial Statements and Notes to Financial Statements each in Item 8 of this Form 10-K. MidAmerican Funding's and MidAmerican Energy's actual results in the future could differ significantly from the historical results.


239


Results of Operations

Overview

MidAmerican Energy -

MidAmerican Energy's net income for 2019 was $793 million, an increase of $111 million, or 16%, compared to 2018 primarily due to a higher income tax benefit of $116 million from higher PTCs of $70 million and the effects of ratemaking, higher electric utility margin of $42 million, higher allowances for equity and borrowed funds of $32 million and higher investment earnings of $20 million, partially offset by higher interest expense of $54 million and higher depreciation and amortization expense of $30 million due to wind-powered generation and other plant placed in-service offset by $46 million of lower Iowa revenue sharing. Electric utility margin increased due to lower fuel costs from higher wind generation, higher recoveries through bill riders (substantially offset in cost of fuel and energy, operations and maintenance expense and income tax benefit) and higher retail customer volumes. Electric retail customer volumes increased 1.4% as an increase in industrial volumes of 4.0% was largely offset by lower residential volumes from the less favorable impact of weather and lower overall customer usage.

MidAmerican Energy's net income for 2018 was $682 million, an increase of $77 million, or 13%, compared to 2017 primarily due to higher electric utility margin of $122 million, a higher income tax benefit of $72 million, primarily due to a $21 million increase in PTCs, a lower federal tax rate and a 2017 charge of $7 million from the Tax Cuts and Jobs Act enacted on December 22, 2017 (the "2017 Tax Reform"), and higher allowance for borrowed and equity funds of $17 million, partially offset by higher depreciation and amortization of $109 million due to wind-powered generation and other plant placed in-service and $44 million of higher Iowa revenue sharing, higher operations and maintenance expense of $12 million and higher interest expense of $13 million. Electric utility margin increased due to higher recoveries through bill riders of $127 million (substantially offset in cost of fuel and energy, operations and maintenance expense and income tax benefit), higher retail customer volumes of 5.6%, largely due to industrial growth and the favorable impact of weather and higher wholesale revenue, partially offset by lower average retail rates of $126 million, predominantly from the impact of a lower federal tax rate due to 2017 Tax Reform, and higher generation and purchased power costs.

MidAmerican Funding -

MidAmerican Funding's net income for 2019 was $781 million, an increase of $112 million, or 17%, compared to 2018. The increase was primarily due to the changes in MidAmerican Energy's earnings discussed above. MidAmerican Funding's net income for 2018 was $669 million, an increase of $95 million, or 17%, compared to 2017. In addition to the MidAmerican Energy impacts, MidAmerican Funding's net income for 2017 reflects after-tax charges of $17 million related to the tender offer of a portion of its 6.927% Senior Bonds due 2029.

Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as regulated electric operating revenue less cost of fuel and energy, which are captions presented on the Statements of Operations. Natural gas utility margin is calculated as regulated natural gas operating revenue less regulated cost of natural gas purchased for resale, which are included in regulated natural gas and other and cost of natural gas purchased for resale and other, respectively, on the Statements of Operations.

MidAmerican Energy's cost of fuel and energy and regulated cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in MidAmerican Energy's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.


240


Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):
 
 
2019
 
2018
 
Change
 
2018
 
2017
 
Change
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric utility margin:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated electric operating revenue
 
$
2,237

 
$
2,283

 
$
(46
)
(2
)%
 
$
2,283

 
$
2,108

 
$
175

8
%
Cost of fuel and energy
 
399

 
487

 
(88
)
(18
)
 
487

 
434

 
53

12

Electric utility margin
 
1,838

 
1,796

 
42

2
 %
 
1,796

 
1,674

 
122

7
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas utility margin:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated natural gas operating revenue
 
660

 
754

 
(94
)
(12
)%
 
754

 
719

 
35

5
%
Cost of natural gas purchased for resale
 
395

 
465

 
(70
)
(15
)
 
465

 
441

 
24

5

Natural gas utility margin
 
265

 
289

 
(24
)
(8
)%
 
289

 
278

 
11

4
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility margin
 
$
2,103

 
$
2,085

 
$
18

1
 %
 
$
2,085

 
$
1,952

 
$
133

7
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other operating revenue
 
28

 
12

 
16

*
 
12

 
10

 
2

20
%
Other cost of sales
 
18

 
1

 
17

*
 
1

 
1

 


Operations and maintenance
 
800

 
811

 
(11
)
(1
)
 
811

 
799

 
12

2

Depreciation and amortization
 
639

 
609

 
30

5

 
609

 
500

 
109

22

Property and other taxes
 
126

 
125

 
1

1

 
125

 
119

 
6

5

Operating income
 
$
548

 
$
551

 
$
(3
)
(1
)%
 
$
551

 
$
543

 
$
8

1
%

*
Not meaningful.


241


Regulated Electric Utility Margin

A comparison of key operating results related to regulated electric utility margin is as follows for the years ended December 31:
 
2019
 
2018
 
Change
 
2018
 
2017
 
Change
Electric utility margin (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenue
$
2,237

 
$
2,283

 
$
(46
)
 
(2
)%
 
$
2,283

 
$
2,108

 
$
175

 
8
%
Cost of fuel and energy
399

 
487

 
(88
)
 
(18
)
 
487

 
434

 
53

 
12

Electric utility margin
$
1,838

 
$
1,796

 
$
42

 
2
 %
 
$
1,796

 
$
1,674

 
$
122

 
7
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electricity sales (GWhs):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
6,575

 
6,763

 
(188
)
 
(3
)%
 
6,763

 
6,207

 
556

 
9
%
Commercial
3,921

 
3,897

 
24

 
1

 
3,897

 
3,761

 
136

 
4

Industrial
14,127

 
13,587

 
540

 
4

 
13,587

 
12,957

 
630

 
5

Other
1,578

 
1,604

 
(26
)
 
(2
)
 
1,604

 
1,567

 
37

 
2

Total retail
26,201

 
25,851

 
350

 
1

 
25,851

 
24,492

 
1,359

 
6

Wholesale
10,000

 
11,181

 
(1,181
)
 
(11
)
 
11,181

 
9,165

 
2,016

 
22

Total sales
36,201

 
37,032

 
(831
)
 
(2
)%
 
37,032

 
33,657

 
3,375

 
10
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands)
786

 
780

 
6

 
1
 %
 
780

 
770

 
10

 
1
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average revenue per MWh:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail
$
74.01

 
$
74.12

 
$
(0.11
)
 
 %
 
$
74.12

 
$
73.88

 
$
0.24

 
%
Wholesale
$
21.84

 
$
25.63

 
$
(3.79
)
 
(15
)%
 
$
25.63

 
$
23.42

 
$
2.21

 
9
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Heating degree days
6,661

 
6,627

 
34

 
1
 %
 
6,627

 
5,492

 
1,135

 
21
%
Cooling degree days
1,152

 
1,307

 
(155
)
 
(12
)%
 
1,307

 
1,117

 
190

 
17
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sources of energy (GWhs)(1):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Coal
12,182

 
15,811

 
(3,629
)
 
(23
)%
 
15,811

 
13,598

 
2,213

 
16
%
Wind and other(2)
16,136

 
13,627

 
2,509

 
18

 
13,627

 
12,932

 
695

 
5

Nuclear
3,849

 
3,869

 
(20
)
 
(1
)
 
3,869

 
3,850

 
19

 

Natural gas
441

 
661

 
(220
)
 
(33
)
 
661

 
360

 
301

 
84

Total energy generated
32,608

 
33,968

 
(1,360
)
 
(4
)
 
33,968

 
30,740

 
3,228

 
11

Energy purchased
4,292

 
3,837

 
455

 
12

 
3,837

 
3,603

 
234

 
6

Total
36,900

 
37,805

 
(905
)
 
(2
)%
 
37,805

 
34,343

 
3,462

 
10
%


(1)
GWh amounts are net of energy used by the related generating facilities.

(2)
All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities.


242


For 2019 compared to 2018, regulated electric utility margin increased $42 million primarily due to:
(1)
Higher retail utility margin of $36 million due to -
an increase of $73 million from non-weather-related sales growth due to higher industrial usage, partially offset by lower residential usage;
an increase of $38 million, net of energy costs, from higher recoveries through bill riders, primarily related to the PTC component of the energy adjustment clause and ratemaking treatment for the impact of 2017 Tax Reform (both offset in income tax benefit), partially offset by a decrease of $49 million in electric energy efficiency program revenue (offset in operations and maintenance expense);
a decrease of $3 million from various other revenue;
a decrease of $18 million from the impact of weather; and
a decrease of $54 million in averages revenue rates due to sales mix;
(2)
Higher wholesale utility margin of $5 million due to higher margin per unit reflecting lower energy costs, partially offset by lower sales volumes; and
(3)
Higher Multi-Value Projects ("MVP") transmission revenue of $1 million.

For 2018 compared to 2017, regulated electric utility margin increased $122 million primarily due to:
(1)
Higher retail utility margin of $73 million due to -
an increase of $104 million, net of energy costs, from higher recoveries through bill riders, primarily related to the PTC component of the energy adjustment clause (offset in income tax benefit);
an increase of $58 million from non-weather-related sales growth due to higher industrial usage;
an increase of $33 million from the impact of weather;
an increase of $4 million from various other revenue; and
a decrease of $126 million in averages rates, predominantly from the impact of a lower federal tax rate due to 2017 Tax Reform;
(2)
Higher wholesale utility margin of $52 million due to higher margins per unit from higher market prices and lower fuel costs on higher sales volumes; and
(3)
Lower MVP transmission revenue of $3 million due to refund accruals.



243


Regulated Natural Gas Utility Margin

A comparison of key operating results related to regulated natural gas utility margin is as follows for the years ended December 31:

 
2019
 
2018
 
Change
 
2018
 
2017
 
Change
Natural gas utility margin (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenue
$
660

 
$
754

 
$
(94
)
 
(12
)%
 
$
754

 
$
719

 
$
35

 
5
 %
Cost of natural gas purchased for resale
395

 
465

 
(70
)
 
(15
)
 
465

 
441

 
24

 
5

Natural gas utility margin
$
265

 
$
289

 
$
(24
)
 
(8
)%
 
$
289

 
$
278

 
$
11

 
4
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas throughput (000's Dths):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
56,101

 
54,798

 
1,303

 
2
 %
 
54,798

 
46,366

 
8,432

 
18
 %
Commercial
27,333

 
26,382

 
951

 
4

 
26,382

 
23,434

 
2,948

 
13

Industrial
5,258

 
5,777

 
(519
)
 
(9
)
 
5,777

 
4,725

 
1,052

 
22

Other
77

 
48

 
29

 
60

 
48

 
38

 
10

 
26

Total retail sales
88,769

 
87,005

 
1,764

 
2

 
87,005

 
74,563

 
12,442

 
17

Wholesale sales
36,886

 
39,267

 
(2,381
)
 
(6
)
 
39,267

 
39,735

 
(468
)
 
(1
)
Total sales
125,655

 
126,272

 
(617
)
 

 
126,272

 
114,298

 
11,974

 
10

Gas transportation service
112,143

 
102,198

 
9,945

 
10

 
102,198

 
92,136

 
10,062

 
11

Total natural gas throughput
237,798

 
228,470

 
9,328

 
4
 %
 
228,470

 
206,434

 
22,036

 
11
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands)
766

 
759

 
7

 
1
 %
 
759

 
751

 
8

 
1
 %
Average revenue per retail Dth sold
$
6.03

 
$
6.89

 
$
(0.86
)
 
(12
)%
 
$
6.89

 
$
7.64

 
$
(0.75
)
 
(10
)%
Average cost of natural gas per retail Dth sold
$
3.47

 
$
4.02

 
$
(0.55
)
 
(14
)%
 
$
4.02

 
$
4.41

 
$
(0.39
)
 
(9
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Combined retail and wholesale average cost of natural gas per Dth sold
$
3.14

 
$
3.69

 
$
(0.55
)
 
(15
)%
 
$
3.69

 
$
3.86

 
$
(0.17
)
 
(4
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Heating degree days
6,980

 
6,843

 
137

 
2
 %
 
6,843

 
5,788

 
1,055

 
18
 %

For 2019 compared to 2018, regulated natural gas utility margin decreased $24 million primarily due to:
(1)
A decrease of $27 million in natural gas energy efficiency program revenue (offset in operations and maintenance expense); and
(2)
An increase of $2 million from higher retail sales volumes due primarily to the impact of colder winter temperatures.

For 2018 compared to 2017, regulated natural gas utility margin increased $11 million primarily due to:
(1)
An increase of $16 million from higher retail sales volumes due primarily to the impact of colder winter temperatures;
(2)
An increase of $2 million from higher natural gas transportation services; and
(3)
A decrease of $9 million from rate and non-weather-related usage factors, including the impact of a lower federal tax rate due to 2017 Tax Reform.

Operating Expenses

MidAmerican Energy -

Operations and maintenance decreased $11 million for 2019 compared to 2018 due to lower energy efficiency program expense of $76 million (offset in operating revenue) and $9 million from lower fossil-fueled generation maintenance, partially offset by higher wind-powered generation costs of $37 million primarily due to new and repowered wind-powered generating facilities, higher natural gas and electric distribution operations costs of $11 million, higher transmission operations costs from MISO of $7 million (offset in operating revenue), and higher healthcare and other operations costs.

244



Operations and maintenance increased $12 million for 2018 compared to 2017 primarily due to higher wind-powered generation maintenance of $23 million from additional wind turbines, higher energy efficiency program expense of $6 million and higher transmission operations costs from MISO of $4 million, both of which are recoverable in bill riders and offset in operating revenue, partially offset by lower electric distribution and transmission maintenance of $13 million primarily from tree-trimming and emergency outage work and lower fossil-fueled and nuclear generation maintenance expense of $8 million.

Depreciation and amortization increased $30 million for 2019 compared to 2018 due to $78 million related to new and repowered wind-powered generating facilities and other plant placed in-service, partially offset by lower Iowa revenue sharing accruals of $46 million.

Depreciation and amortization increased $109 million for 2018 compared to 2017 primarily due to $67 million related to wind-powered generating facilities and other plant placed in-service and higher Iowa revenue sharing accruals of $44 million.

Property and other taxes increased $6 million for 2018 compared to 2017 due to higher wind turbine property taxes and other real estate taxes.

Other Income and (Expense)

MidAmerican Energy -

Interest expense increased $54 million for 2019 compared to 2018 primarily due to the issuance of first mortgage bonds totaling $1.5 billion in January 2019 and $850 million in October 2019, partially offset by the redemption of $500 million of first mortgage bonds in February 2019.

Interest expense increased $13 million for 2018 compared to 2017 primarily due to the issuance of $700 million of first mortgage bonds in February 2018 and $150 million of variable rate, tax-exempt bonds in December 2017, partially offset by the redemption of $350 million of senior notes in March 2018.

Allowance for borrowed and equity funds increased $32 million for 2019 compared to 2018 and $17 million for 2018 compared to 2017 primarily due to higher construction work-in-progress balances related to new and repowering wind-powered generation projects.

Other, net increased $20 million for 2019 compared to 2018 primarily due to higher returns on corporate-owned life insurance policies and higher interest income due to a favorable cash position.

Other, net decreased $7 million for 2018 compared to 2017 primarily due to lower returns on corporate-owned life insurance policies.

MidAmerican Funding -

In addition to the fluctuations discussed above for MidAmerican Energy, MidAmerican Funding's other, net for 2017 reflects a pre-tax charge of $29 million from the early redemption of a portion of MidAmerican Funding's 6.927% Senior Bonds due 2029.

Income Tax Benefit

MidAmerican Energy -

MidAmerican Energy's income tax benefit increased $116 million for 2019 compared to 2018, and the effective tax rate was (88)% for 2019 and (60)% for 2018. The change in the effective tax rate was substantially due to an increase of $70 million in PTCs and the effects of ratemaking.

MidAmerican Energy's income tax benefit increased $72 million for 2018 compared to 2017, and the effective tax rate was (60)% for 2018 and (43)% for 2017. The change in the effective tax rate was substantially due to the reduction in the United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, an increase of $21 million in PTCs and the effects of ratemaking.


245


Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold based on a prescribed per-kilowatt rate pursuant to the applicable federal income tax law and are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in service. Beginning in late 2014, some of MidAmerican Energy's wind-powered generating facilities surpassed the 10-year eligibility period for earning the credits. Most of those facilities have since been repowered, and under Internal Revenue Service rules, qualifying repowered facilities are eligible for the credits, or a portion thereof, for 10 years from the date they are returned to service. Refer to "Capital Expenditures" in Liquidity and Capital Resources for additional information about repowering and new wind-powered generation placed in-service. A credit per kilowatt hour of $0.025 for 2019 and $0.024 for 2018 and 2017 was applied to the annual production of eligible facilities, which resulted in $378 million, $308 million and $287 million, respectively, in PTCs.

MidAmerican Funding -

MidAmerican Funding's income tax benefit increased $115 million for 2019 compared to 2018, and the effective tax rate was (93)% for 2019 and (64)% for 2018. MidAmerican Funding's income tax benefit increased $60 million for 2018 compared to 2017, and the effective tax rate was (64)% for 2018 and (54)% for 2017. The change in effective tax rates was due principally to the factors discussed for MidAmerican Energy. Additionally, 2017 reflects an income tax benefit from a charge of $29 million for the early redemption of a portion of MidAmerican Funding's 6.927% Senior Bonds due 2029.

Liquidity and Capital Resources

As of December 31, 2019, MidAmerican Energy's and MidAmerican Funding's total net liquidity were as follows (in millions):
MidAmerican Energy:
 
 
Cash and cash equivalents
 
$
287

 
 
 
Credit facilities, maturing 2020 and 2022
 
1,305

Less:
 
 
Tax-exempt bond support
 
(370
)
Net credit facilities
 
935

MidAmerican Energy total net liquidity
 
$
1,222

 
 
 
MidAmerican Funding:
 
 
MidAmerican Energy total net liquidity
 
$
1,222

Cash and cash equivalents
 
1

MHC, Inc. credit facility, maturing 2020
 
4

MidAmerican Funding total net liquidity
 
$
1,227


Operating Activities

MidAmerican Energy's net cash flows from operating activities were $1,490 million, $1,508 million and $1,396 million for 2019, 2018 and 2017, respectively. MidAmerican Funding's net cash flows from operating activities were $1,475 million, $1,516 million and $1,380 million for 2019, 2018 and 2017, respectively. Cash flows from operating activities decreased for 2019 compared to 2018 primarily due to lower income tax receipts and higher interest payments, partially offset by lower payments to vendors and lower payments for the settlement of asset retirement obligations. Cash flows from operating activities increased for 2018 compared to 2017 primarily due to higher cash margins for MidAmerican Energy's regulated electric and natural gas businesses, higher income tax receipts and higher energy efficiency cost recovery cash inflows.

The timing of MidAmerican Energy's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.


246


Investing Activities

MidAmerican Energy's net cash flows from investing activities were $(2,801) million, $(2,310) million and $(1,776) million for 2019, 2018 and 2017, respectively. MidAmerican Funding's net cash flows from investing activities were $(2,801) million, $(2,310) million and $(1,779) million for 2019, 2018 and 2017, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures. Purchases and proceeds related to marketable securities primarily consist of activity within the Quad Cities Generating Station nuclear decommissioning trust, and other investment proceeds relates primarily to company-owned life insurance policies. In 2018, proceeds from sales of other investments includes $15 million for the transfer of corporate aircraft to BHE.

Financing Activities

MidAmerican Energy's net cash flows from financing activities were $1.585 billion, $576 million and $636 million for 2019, 2018 and 2017, respectively. MidAmerican Funding's net cash flows from financing activities were $1.6 billion, $569 million and $654 million for 2019, 2018 and 2017, respectively. In January 2019, MidAmerican Energy issued $600 million of its 3.65% First Mortgage Bonds due April 2029 and $900 million of its 4.25% First Mortgage Bonds due July 2049, and in October 2019, issued an additional $250 million of its 3.65% First Mortgage Bonds due April 2029 and $600 million of its 3.15% First Mortgage Bonds due April 2050. In February 2019, MidAmerican Energy redeemed $500 million of its 2.40% First Mortgage Bonds due in March 2019 at a redemption price of 100% of the principal amount plus accrued interest. In February 2018, MidAmerican Energy issued $700 million of its 3.65% First Mortgage Bonds due August 2048 and, in March 2018, repaid $350 million of its 5.30% Senior Notes due March 2018. In December 2017, the Iowa Finance Authority issued $150 million of its variable-rate, tax-exempt Solid Waste Facilities Revenue Bonds due December 2047, the restricted proceeds of which were loaned to MidAmerican Energy for the purpose of constructing solid waste facilities. In February 2017, MidAmerican Energy issued $375 million of its 3.10% First Mortgage Bonds due May 2027 and $475 million of its 3.95% First Mortgage Bonds due August 2047. In February 2017, MidAmerican Energy redeemed in full through optional redemption its $250 million of 5.95% Senior Notes due July 2017. Net (repayments of) proceeds from short-term debt relate to MidAmerican Energy's use of short-term borrowings through its commercial paper program.

In December 2017, MidAmerican Funding redeemed through a tender offer a portion of its 6.927% Senior Bonds. MidAmerican Funding received $15 million and $133 million in 2019 and 2017, respectively, and made payments totaling $8 million in 2018 through its note payable with BHE.

Debt Authorizations and Related Matters

MidAmerican Energy has authority from the FERC to issue through July 31, 2020, commercial paper and bank notes aggregating $1.3 billion at interest rates not to exceed the applicable London Interbank Offered Rate ("LIBOR") plus a spread of 400 basis points. MidAmerican Energy has a $900 million unsecured credit facility expiring in June 2022. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. MidAmerican Energy has a $400 million unsecured credit facility, which expires in August 2020 and has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.

MidAmerican Energy currently has an effective automatic registration statement with the SEC to issue an indeterminate amount of long-term debt securities through June 26, 2021. Additionally, MidAmerican Energy has authorization from the FERC to issue, through June 30, 2021, long-term debt securities up to an aggregate of $850 million at interest rates not to exceed the applicable United States Treasury rate plus a spread of 175 basis points and preferred stock up to an aggregate of $500 million and from the ICC to issue long-term debt securities up to an aggregate of $850 million through August 20, 2022, and preferred stock up to an aggregate of $500 million through November 1, 2020.

MidAmerican Funding or one of its subsidiaries, including MidAmerican Energy, may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by MidAmerican Funding or one of its subsidiaries may be reissued or resold by MidAmerican Funding or one of its subsidiaries from time to time and will depend on prevailing market conditions, the issuing company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.


247


Future Uses of Cash

MidAmerican Energy and MidAmerican Funding have available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which MidAmerican Energy and MidAmerican Funding have access to external financing depends on a variety of factors, including their credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

MidAmerican Energy has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

MidAmerican Energy's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ended December 31 are as follows (in millions):
 
Historical
 
Forecast
 
2017
 
2018
 
2019
 
2020
 
2021
 
2022
 
 
 
 
 
 
 
 
 
 
 
 
Wind-powered generation under ratemaking principles
$
657

 
$
1,261

 
$
1,486

 
$
371

 
$

 
$

Renewable generation not under ratemaking principles

 

 

 
420

 

 

Wind-powered generation repowering
514

 
422

 
369

 
136

 
436

 
329

Other
602

 
649

 
955

 
934

 
591

 
548

Total
$
1,773

 
$
2,332

 
$
2,810

 
$
1,861

 
$
1,027

 
$
877


MidAmerican Energy's historical and forecast capital expenditures include the following:
The construction of wind-powered generating facilities in Iowa. MidAmerican Energy placed in-service 1,019 MWs (nominal ratings) during 2019, 817 MWs (nominal ratings) during 2018 and 334 MWs (nominal ratings) during 2017. Wind XI, a 2,000-MW project, was completed in January 2020. Wind XII is a 591-MW project, including 201 MWs placed in-service in 2019 and facilities expected to be placed in-service by the end of 2020. MidAmerican Energy expects all of these wind-powered generating facilities to qualify for 100% of PTCs available. PTCs from these projects are excluded from MidAmerican Energy's Iowa energy adjustment clause until these generation assets are reflected in base rates.
Additionally, MidAmerican Energy continues to evaluate wind-powered and other renewable generating facilities that would not be subject to pre-approved ratemaking principles.
The repowering of the oldest of MidAmerican Energy's wind-powered generating facilities in Iowa. IRS rules provide for re-establishment of the PTC for an existing wind-powered generating facility upon the replacement of a significant portion of its components. If the degree of component replacement meets IRS guidelines, PTCs are re-established for ten years at rates that depend upon the date in which construction begins. Under MidAmerican Energy's Iowa electric tariff, federal PTCs related to facilities that were in-service prior to 2013 must be included in its Iowa energy adjustment clause. In August 2017, the IUB approved a tariff change that excludes from MidAmerican Energy's Iowa energy adjustment clause any future federal PTCs related to these repowered facilities. Below is a summary of historical and forecast wind-powered generation repowering projects:

248


 
Capacity
 
% of Federal Production
Year Placed In-Service
(MWs)(1)
 
Tax Credit Rate
 
 
 
 
Historical:
 
 
 
2017
414
 
100%
2018
222
 
100%
2019
466
 
100%
2019
120
 
80%
Forecast:
 
 
 
2020
55
 
80%
2021
594
 
80%
2022
407
 
60%
(1)
Capacity values for historical repowered facilities reflect new nominal ratings and for forecast projects reflect existing nominal ratings.
Remaining expenditures primarily relate to routine operating projects for distribution, generation, transmission and other infrastructure needed to serve existing and expected demand.

249


Contractual Obligations

MidAmerican Energy and MidAmerican Funding have contractual cash obligations that may affect their financial condition. The following table summarizes the material contractual cash obligations of MidAmerican Energy and MidAmerican Funding as of December 31, 2019 (in millions):
 
Payments Due By Periods
 
 
 
 
 
2021-
 
2023-
 
2025 and
 
 
 
2020
 
2022
 
2024
 
After
 
Total
MidAmerican Energy:
 
 
 
 
 
 
 
 
 
Long-term debt
$

 
$
1

 
$
850

 
$
6,425

 
$
7,276

Interest payments on long-term debt(1)(2)
294

 
590

 
580

 
4,447

 
5,911

Coal, electricity and natural gas contracts commitments(1)
244

 
246

 
86

 
52

 
628

Construction commitments(1)
670

 
542

 
6

 

 
1,218

Easements(1)
32

 
73

 
77

 
1,492

 
1,674

Other commitments(1)
198

 
310

 
275

 
432

 
1,215

 
1,438

 
1,762

 
1,874

 
12,848

 
17,922

 
 
 
 
 
 
 
 
 
 
MidAmerican Funding parent:
 
 
 
 
 
 
 
 
 
Long-term debt

 

 

 
239

 
239

Interest payments on long-term debt(1)
17

 
33

 
33

 
75

 
158

 
17

 
33

 
33

 
314

 
397

Total contractual cash obligations
$
1,455

 
$
1,795

 
$
1,907

 
$
13,162

 
$
18,319

(1)
Not reflected on the Consolidated Balance Sheets.
(2)
Includes interest payments for tax-exempt bond obligations with interest rates scheduled to reset periodically prior to maturity. Future variable interest rates are assumed to equal December 31, 2019 rates.

MidAmerican Energy has other types of commitments that relate primarily to construction expenditures (in "Capital Expenditures" section above) and asset retirement obligations beyond 2019 (Note 11), which have not been included in the above table because the amount or timing of the cash payments is not certain. Refer to Notes 8, 11 and 13 in Notes to Financial Statements in Item 8 of this Form 10-K for additional information.

Regulatory Matters

MidAmerican Energy is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further discussion regarding MidAmerican Energy's general regulatory framework and current regulatory matters.

Quad Cities Generating Station Operating Status

Exelon Generation Company, LLC ("Exelon Generation"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the zero emission credits will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will not receive additional revenue from the subsidy.

On February 14, 2017, two lawsuits were filed with the United States District Court for the Northern District of Illinois ("Northern District of Illinois") against the Illinois Power Agency alleging that the state's zero emission credit program violates certain provisions of the United States Constitution. Both lawsuits were dismissed at the Northern District of Illinois, and the United States Court of Appeals for the Seventh Circuit affirmed the dismissals. On April 15, 2019, plaintiffs' petition seeking United States Supreme Court review of the case was denied.


250


On January 9, 2017, the Electric Power Supply Association ("EPSA") filed two requests with the FERC seeking to expand Minimum Offer Price Rule ("MOPR") provisions to apply to existing resources receiving zero emission credit compensation. When a resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a government-provided financial support program, resulting in a higher offer that may not clear the capacity market. If the EPSA's requests are successful, an expanded MOPR could result in an increased risk of Quad Cities Station not clearing in future capacity auctions and Exelon Generation no longer receiving capacity revenues for the facility. As majority owner and operator of Quad Cities Station, Exelon Generation filed protests at the FERC in response to each filing.

On December 19, 2019, the FERC issued an order in the PJM Interconnection, L.L.C. ("PJM") MOPR proceeding that broadly applies the MOPR to all new and existing resources, including nuclear, greatly expanding the breadth and scope of PJM's MOPR, effective as of PJM's next capacity auction. The FERC directed PJM to make a compliance filing within 90 days. The FERC has no deadline for acting on PJM's compliance filing. While the FERC included some limited exemptions in its order, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. In addition, the FERC provided no new mechanism for accommodating state-supported resources other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. Unless Illinois can implement an FRR program in their PJM zones, the MOPR will apply to Exelon Generation's nuclear plants in those states receiving a benefit under the Illinois zero emissions program, including Quad Cities Station, resulting in higher offers for those units that may not clear the capacity market.

On January 21, 2020, Exelon Generation, PJM and a number of other entities submitted individual requests for rehearing of the FERC's December 19, 2019 order on the PJM MOPR. Exelon Generation is currently working with PJM and other stakeholders to pursue the FRR option prior to the next capacity auction in PJM. If Illinois implements the FRR option, Quad Cities Station could be removed from PJM's capacity auction and instead supply capacity and be compensated under the FRR program. Implementing the FRR program in Illinois will require both legislative and regulatory changes. MidAmerican Energy cannot predict whether such legislative and regulatory changes can be implemented prior to the next capacity auction in PJM or their potential impact on the continued operation of Quad Cities Station.

Environmental Laws and Regulations

MidAmerican Energy is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and MidAmerican Energy is unable to predict the impact of the changing laws and regulations on its operations and financial results. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.

Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.

Collateral and Contingent Features

Debt securities of MidAmerican Energy are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of MidAmerican Energy's ability to, in general, meet the obligations of its issued debt securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. As of December 31, 2019, MidAmerican Energy's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the three recognized credit rating agencies were investment grade. As a result of the issuance of first mortgage bonds by MidAmerican Energy in September 2013, its then outstanding senior unsecured debt was equally and ratably secured with such first mortgage bonds. Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K for a discussion of MidAmerican Energy's first mortgage bonds.

MidAmerican Funding and MidAmerican Energy have no credit rating downgrade triggers that would accelerate the maturity dates of its outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. MidAmerican Energy's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.

251



In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base MidAmerican Energy's collateral requirements on its credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in MidAmerican Energy's creditworthiness. These rights can vary by contract and by counterparty. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2019, MidAmerican Energy would have been required to post $84 million of additional collateral. MidAmerican Energy's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.

Inflation

Historically, overall inflation and changing prices in the economies where MidAmerican Energy operates have not had a significant impact on its financial results. MidAmerican Energy operates under cost-of-service based rate structures administered by various state commissions and the FERC. Under these rate structures, MidAmerican Energy is allowed to include prudent costs in its rates, including the impact of inflation. MidAmerican Energy attempts to minimize the potential impact of inflation on its operations through the use of fuel, energy and other cost adjustment clauses and bill riders, by employing prudent risk management and hedging strategies and by considering, among other areas, inflation's impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs, and long-term debt issuances. There can be no assurance that such actions will be successful.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting MidAmerican Energy and MidAmerican Funding, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by MidAmerican Energy's methods, judgments and assumptions used in the preparation of the Financial Statements and should be read in conjunction with MidAmerican Energy's Summary of Significant Accounting Policies included in Note 2 of Notes to Financial Statements in Item 8 of this Form 10-K.

Accounting for the Effects of Certain Types of Regulation

MidAmerican Energy prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, MidAmerican Energy defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.

MidAmerican Energy continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition, that could limit MidAmerican Energy's ability to recover its costs. MidAmerican Energy believes the application of the guidance for regulated operations is appropriate, and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI"). Total regulatory assets were $289 million and total regulatory liabilities were $1,406 million as of December 31, 2019. Refer to Note 5 of Notes to Financial Statements in Item 8 of this Form 10-K for additional information regarding regulatory assets and liabilities.


252


Income Taxes

In determining MidAmerican Funding's and MidAmerican Energy's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by MidAmerican Energy's various regulatory commissions. MidAmerican Funding's and MidAmerican Energy's income tax returns are subject to continuous examinations by federal, state and local tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. MidAmerican Funding and MidAmerican Energy recognize the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of their federal, state and local tax examinations is uncertain, each company believes it has made adequate provisions for its income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on its consolidated financial results. Refer to Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding income taxes.

Impairment of Goodwill

MidAmerican Funding's Consolidated Balance Sheet as of December 31, 2019, includes goodwill from the acquisition of MHC totaling $1.3 billion. Goodwill is allocated to each reporting unit. MidAmerican Funding evaluates goodwill for impairment at least annually and completed its annual review as of October 31. Additionally, no indicators of impairment were identified as of December 31, 2019. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. MidAmerican Funding uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating future cash flows, MidAmerican Funding incorporates current market information, as well as historical factors.

Pension and Other Postretirement Benefits

MidAmerican Energy sponsors defined benefit pension and other postretirement benefit plans that cover the majority of the employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy Inc. MidAmerican Energy recognizes the funded status of its defined benefit pension and other postretirement benefit plans on the Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2019, MidAmerican Energy recognized a net liability totaling $- million for the funded status of its defined benefit pension and other postretirement benefit plans. As of December 31, 2019, amounts not yet recognized as a component of net periodic benefit cost that were included in regulatory assets and regulatory liabilities totaled $26 million and $32 million, respectively.

The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected long-term rate of return on plan assets and healthcare cost trend rates. These key assumptions are reviewed annually and modified as appropriate. MidAmerican Energy believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 10 of Notes to Financial Statements in Item 8 of this Form 10-K for disclosures about MidAmerican Energy's defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2019.

MidAmerican Energy chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.

In establishing its assumption as to the expected long-term rate of return on plan assets, MidAmerican Energy utilizes the expected asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. MidAmerican Energy regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.


253


MidAmerican Energy chooses a healthcare cost trend rate that reflects the near and long-term expectations of increases in medical costs and corresponds to the expected benefit payment periods. The healthcare cost trend rate is assumed to gradually decline to 5% by 2025 at which point the rate of increase is assumed to remain constant. Refer to Note 10 of Notes to Financial Statements in Item 8 of this Form 10-K for healthcare cost trend rate sensitivity disclosures.

The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and the funded status. If changes were to occur for the following key assumptions, the approximate effect on the Financial Statements of the total plan before allocations to affiliates would be as follows (in millions):
 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
Effect on December 31, 2019 Benefit Obligations:
 
 
 
 
 
 
 
Discount rate
$
(34
)
 
$
37

 
$
(8
)
 
$
9

 
 
 
 
 
 
 
 
Effect on 2019 Periodic Cost:
 
 
 
 
 
 
 
Discount rate
2

 
(2
)
 

 

Expected rate of return on plan assets
(3
)
 
3

 
(1
)
 
1


A variety of factors affect the funded status of the plans, including asset returns, discount rates, plan changes and MidAmerican Energy's funding policy for each plan.

Revenue Recognition - Unbilled Revenue

Revenue from electric and natural gas customers is recognized as electricity or natural gas is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters and rates. At the end of each month, energy provided to customers since the date of the last meter reading is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $91 million as of December 31, 2019. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses and composition of sales among customer classes. Unbilled revenue is reversed in the following month, and billed revenue is recorded based on the subsequent meter readings.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

MidAmerican Energy's Balance Sheets include assets and liabilities with fair values that are subject to market risks. MidAmerican Energy's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which it transacts. The following discussion addresses the significant market risks associated with MidAmerican Energy's business activities. MidAmerican Energy has established guidelines for credit risk management. Refer to Note 2 of Notes to Financial Statements in Item 8 of this Form 10-K for additional information regarding MidAmerican Energy's contracts accounted for as derivatives.

Commodity Price Risk

MidAmerican Energy is exposed to the impact of market fluctuations in commodity prices and interest rates. MidAmerican Energy is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its regulated service territory. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather; market liquidity; generating facility availability; customer usage; storage; and transmission and transportation constraints. Commodity price risk for MidAmerican Energy's regulated retail electricity and natural gas operations is significantly mitigated by the inclusion of energy costs in energy cost rider mechanisms, which permit the current recovery of such costs from its retail customers. MidAmerican Energy uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements to mitigate price volatility on behalf of its customers. MidAmerican Energy does not engage in a material amount of proprietary trading activities.


254


Interest Rate Risk

MidAmerican Energy and MidAmerican Funding are exposed to interest rate risk on their outstanding variable-rate short- and long-term debt and future debt issuances. MidAmerican Energy and MidAmerican Funding manage interest rate risk by limiting their exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, the fixed-rate long-term debt does not expose MidAmerican Energy or MidAmerican Funding to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if MidAmerican Energy or MidAmerican Funding were to reacquire all or a portion of these instruments prior to their maturity. MidAmerican Energy or MidAmerican Funding may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate their exposure to interest rate risk. The nature and amount of their short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7, 8 and 12 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-K for additional discussion of MidAmerican Energy's and MidAmerican Funding's short- and long-term debt.

As of December 31, 2019 and 2018, MidAmerican Energy had short- and long-term variable-rate obligations totaling $370 million and $610 million, respectively, that expose MidAmerican Energy to the risk of increased interest expense in the event of increases in short-term interest rates. The market risk related to MidAmerican Energy's variable-rate debt as of December 31, 2019, is not hedged. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on MidAmerican Energy's annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2019 and 2018.

Credit Risk

MidAmerican Energy is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Additionally, MidAmerican Energy participates in the regional transmission organization ("RTO") markets and has indirect credit exposure related to other participants, although RTO credit policies are designed to limit exposure to credit losses from individual participants. Credit risk may be concentrated to the extent MidAmerican Energy's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, MidAmerican Energy analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty, and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, MidAmerican Energy enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, MidAmerican Energy exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

Substantially all of MidAmerican Energy's electric wholesale sales revenue results from participation in RTOs, including the MISO and the PJM. MidAmerican Energy's share of historical losses from defaults by other RTO market participants has not been material. Additionally, as of December 31, 2019, MidAmerican Energy's aggregate direct credit exposure from electric wholesale marketing counterparties was not material.


255


Item 8.
Financial Statements and Supplementary Data

MidAmerican Energy Company


MidAmerican Funding, LLC and Subsidiaries



256




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholder of
MidAmerican Energy Company
Des Moines, Iowa

Opinion on the Financial Statements

We have audited the accompanying balance sheets of MidAmerican Energy Company ("MidAmerican Energy") as of December 31, 2019 and 2018, the related statements of operations, changes in shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes and the schedule listed in the Index at Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of MidAmerican Energy as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of MidAmerican Energy's management. Our responsibility is to express an opinion on MidAmerican Energy's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to MidAmerican Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. MidAmerican Energy is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of MidAmerican Energy's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.


/s/ Deloitte & Touche LLP

Des Moines, Iowa
February 21, 2020

We have served as MidAmerican Energy's auditor since 1999.


257


MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS
(Amounts in millions)
 
As of December 31,
 
2019
 
2018
 
 
 
 
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
287

 
$

Trade receivables, net
291

 
367

Inventories
226

 
204

Other current assets
90

 
90

Total current assets
894

 
661

 
 
 
 
Property, plant and equipment, net
18,375

 
16,157

Regulatory assets
289

 
273

Investments and restricted investments
818

 
708

Other assets
188

 
121

 
 
 
 
Total assets
$
20,564

 
$
17,920


The accompanying notes are an integral part of these financial statements.

258


MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (continued)
(Amounts in millions)

 
As of December 31,
 
2019
 
2018
 
 
 
 
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
 
 
 
Accounts payable
$
519

 
$
575

Accrued interest
78

 
53

Accrued property, income and other taxes
225

 
300

Short-term debt

 
240

Current portion of long-term debt

 
500

Other current liabilities
219

 
122

Total current liabilities
1,041

 
1,790

 
 
 
 
Long-term debt
7,208

 
4,879

Regulatory liabilities
1,406

 
1,620

Deferred income taxes
2,626

 
2,322

Asset retirement obligations
704

 
552

Other long-term liabilities
339

 
311

Total liabilities
13,324

 
11,474

 
 
 
 
Commitments and contingencies (Note 13)

 

 
 
 
 
Shareholder's equity:
 
 
 
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding

 

Additional paid-in capital
561

 
561

Retained earnings
6,679

 
5,885

Total shareholder's equity
7,240

 
6,446

 
 
 
 
Total liabilities and shareholder's equity
$
20,564

 
$
17,920


The accompanying notes are an integral part of these financial statements.


259


MIDAMERICAN ENERGY COMPANY
STATEMENTS OF OPERATIONS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
Operating revenue:
 
 
 
 
 
Regulated electric
$
2,237

 
$
2,283

 
$
2,108

Regulated natural gas and other
688

 
766

 
729

Total operating revenue
2,925

 
3,049

 
2,837

 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
Cost of fuel and energy
399

 
487

 
434

Cost of natural gas purchased for resale and other
413

 
466

 
442

Operations and maintenance
800

 
811

 
799

Depreciation and amortization
639

 
609

 
500

Property and other taxes
126

 
125

 
119

Total operating expenses
2,377

 
2,498

 
2,294

 
 
 
 
 
 
Operating income
548

 
551

 
543

 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
Interest expense
(281
)
 
(227
)
 
(214
)
Allowance for borrowed funds
27

 
20

 
15

Allowance for equity funds
78

 
53

 
41

Other, net
50

 
30

 
37

Total other income (expense)
(126
)
 
(124
)
 
(121
)
 
 
 
 
 
 
Income before income tax benefit
422

 
427

 
422

Income tax benefit
(371
)
 
(255
)
 
(183
)
 
 
 
 
 
 
Net income
$
793

 
$
682

 
$
605


The accompanying notes are an integral part of these financial statements.


260


MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Amounts in millions)

 
 
 
Additional
 
 
 
Total
 
Common
 
Paid-in
 
Retained
 
Shareholder's
 
Stock
 
Capital
 
Earnings
 
Equity
 
 
 
 
 
 
 
 
Balance, December 31, 2016
$

 
$
561

 
$
4,599

 
$
5,160

Net income

 

 
605

 
605

Other equity transactions

 

 
(1
)
 
(1
)
Balance, December 31, 2017

 
561

 
5,203

 
5,764

Net income

 

 
682

 
682

Balance, December 31, 2018

 
561

 
5,885

 
6,446

Net income

 

 
793

 
793

Other equity transactions

 

 
1

 
1

Balance, December 31, 2019
$

 
$
561

 
$
6,679

 
$
7,240


The accompanying notes are an integral part of these financial statements.


261


MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CASH FLOWS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
Cash flows from operating activities:
 
 
 
 
 
Net income
$
793

 
$
682

 
$
605

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
 
 
Depreciation and amortization
639

 
609

 
500

Amortization of utility plant to other operating expenses
33

 
34

 
34

Allowance for equity funds
(78
)
 
(53
)
 
(41
)
Deferred income taxes and amortization of investment tax credits
154

 
33

 
332

Other, net
(9
)
 
13

 
(15
)
Changes in other operating assets and liabilities:
 
 
 
 
 
Trade receivables and other assets
60

 
(25
)
 
(60
)
Inventories
(22
)
 
41

 
19

Derivative collateral, net
(1
)
 
(1
)
 
2

Contributions to pension and other postretirement benefit plans, net
(10
)
 
(13
)
 
(11
)
Accrued property, income and other taxes, net
(76
)
 
218

 
(41
)
Accounts payable and other liabilities
7

 
(30
)
 
72

Net cash flows from operating activities
1,490

 
1,508

 
1,396

 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
Capital expenditures
(2,810
)
 
(2,332
)
 
(1,773
)
Purchases of marketable securities
(156
)
 
(263
)
 
(143
)
Proceeds from sales of marketable securities
138

 
223

 
137

Proceeds from sales of other investments
1

 
17

 
2

Other investment proceeds
13

 
15

 
1

Other, net
13

 
30

 

Net cash flows from investing activities
(2,801
)
 
(2,310
)
 
(1,776
)
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
Proceeds from long-term debt
2,326

 
687

 
990

Repayments of long-term debt
(500
)
 
(350
)
 
(255
)
Net (repayments of) proceeds from short-term debt
(240
)
 
240

 
(99
)
Other, net
(1
)
 
(1
)
 

Net cash flows from financing activities
1,585

 
576

 
636

 
 
 
 
 
 
Net change in cash and cash equivalents and restricted cash and cash equivalents
274

 
(226
)
 
256

Cash and cash equivalents and restricted cash and cash equivalents at beginning of year
56

 
282

 
26

Cash and cash equivalents and restricted cash and cash equivalents at end of year
$
330

 
$
56

 
$
282



The accompanying notes are an integral part of these financial statements.



262


MIDAMERICAN ENERGY COMPANY
NOTES TO FINANCIAL STATEMENTS

(1)
Organization and Operations

MidAmerican Energy Company ("MidAmerican Energy") is a public utility with electric and natural gas operations and is the principal subsidiary of MHC Inc. ("MHC"). MHC is a holding company that conducts no business other than the ownership of its subsidiaries and related corporate services. MHC's nonregulated subsidiary is Midwest Capital Group, Inc. MHC is the direct wholly owned subsidiary of MidAmerican Funding, LLC, ("MidAmerican Funding"), which is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

(2)
Summary of Significant Accounting Policies

Basis of Presentation

The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2019, 2018 and 2017.

Use of Estimates in Preparation of Financial Statements

The preparation of the Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Financial Statements.

Accounting for the Effects of Certain Types of Regulation

MidAmerican Energy's utility operations are subject to the regulation of the Iowa Utilities Board ("IUB"), the Illinois Commerce Commission ("ICC"), the South Dakota Public Utilities Commission, and the Federal Energy Regulatory Commission ("FERC"). MidAmerican Energy's accounting policies and the accompanying Financial Statements conform to GAAP applicable to rate-regulated enterprises and reflect the effects of the ratemaking process.

MidAmerican Energy prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, MidAmerican Energy defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.

MidAmerican Energy continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition, that could limit MidAmerican Energy's ability to recover its costs. MidAmerican Energy believes the application of the guidance for regulated operations is appropriate, and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").


263


Fair Value Measurements

As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.

Cash Equivalents and Restricted Cash and Cash Equivalents and Investments

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax exempt bond agreements. Restricted amounts are included in other current assets and investments and restricted investments on the Balance Sheets.

Investments

Fixed Maturity Securities

MidAmerican Energy's management determines the appropriate classification of investments in fixed maturity securities at the acquisition date and reevaluates the classification at each balance sheet date. Investments that management does not intend to use or is restricted from using in current operations are presented as noncurrent on the Balance Sheets.

Available-for-sale investments are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. Realized and unrealized gains and losses on fixed maturity securities in a trust related to the decommissioning of the Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") are recorded as a net regulatory liability because MidAmerican Energy expects to refund to customers any decommissioning funds in excess of costs for these activities through regulated rates. Trading investments are carried at fair value with changes in fair value recognized in earnings. Held-to-maturity securities are carried at amortized cost, reflecting the ability and intent to hold the securities to maturity. The difference between the original cost and maturity value of a fixed maturity security is amortized to earnings using the interest method.

Investments gains and losses arise when investments are sold (as determined on a specific identification basis) or are other-than-temporarily impaired with respect to securities classified as available-for-sale. If the value of a fixed maturity investment declines to below amortized cost and the decline is deemed other than temporary, the amortized cost of the investment is reduced to fair value, with a corresponding charge to earnings. Any resulting impairment loss is recognized in earnings if MidAmerican Energy intends to sell, or expects to be required to sell, the debt security before its amortized cost is recovered. If MidAmerican Energy does not expect to ultimately recover the amortized cost basis even if it does not intend to sell the security, the credit loss component is recognized in earnings and any difference between fair value and the amortized cost basis, net of the credit loss, is reflected in other comprehensive income (loss) ("OCI"). For regulated investments, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in regulated rates is probable.

Equity Securities

All changes in fair value of equity securities in a trust related to the decommissioning of nuclear generation assets are recorded as a net regulatory liability since MidAmerican Energy expects to refund to customers any decommissioning funds in excess of costs for these activities through regulated rates.

Allowance for Doubtful Accounts

Receivables are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts. The allowance for doubtful accounts is based on MidAmerican Energy's assessment of the collectability of amounts owed to it by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. As of December 31, 2019 and 2018, the allowance for doubtful accounts totaled $5 million and $7 million, respectively, and is included in receivables, net on the Balance Sheets.

264



Derivatives

MidAmerican Energy employs a number of different derivative contracts, including forwards, futures, options, swaps and other agreements, to manage price risk for electricity, natural gas and other commodities, and interest rate risk. Derivative contracts are recorded on the Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets on the Balance Sheets.

Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked to market, and settled amounts are recognized as operating revenue or cost of sales on the Statements of Operations.

For MidAmerican Energy's derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities.

Inventories

Inventories consist mainly of coal stocks, totaling $66 million and $51 million as of December 31, 2019 and 2018, respectively, materials and supplies, totaling $128 million and $124 million as of December 31, 2019 and 2018, respectively, and natural gas in storage, totaling $28 million and $24 million as of December 31, 2019 and 2018, respectively. The cost of materials and supplies, coal stocks and fuel oil is determined using the average cost method. The cost of stored natural gas is determined using the last-in-first-out method. With respect to stored natural gas, the replacement cost would be $2 million lower and $14 million higher as of December 31, 2019 and 2018, respectively.

Property, Plant and Equipment, Net

General

Additions to utility plant are recorded at cost. MidAmerican Energy capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC") and equity AFUDC. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. Additionally, MidAmerican Energy has regulatory arrangements in Iowa in which the carrying cost of certain utility plant has been reduced for amounts associated with electric returns on equity exceeding specified thresholds and retail energy benefits associated with certain wind-powered generation. Amounts expensed under this arrangement are included as a component of depreciation and amortization.

Depreciation and amortization for MidAmerican Energy's utility operations are computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by its various regulatory authorities. Depreciation studies are completed by MidAmerican Energy to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.

Generally, when MidAmerican Energy retires or sells a component of utility plant, it charges the original cost, net of any proceeds from the disposition to accumulated depreciation. Any gain or loss on disposals of nonregulated assets is recorded through earnings.

Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of its regulated facilities, is capitalized by MidAmerican Energy as a component of utility plant, with offsetting credits to the Statements of Operations. AFUDC is computed based on guidelines set forth by the FERC. After construction is completed, MidAmerican Energy is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.


265


Asset Retirement Obligations

MidAmerican Energy recognizes AROs when it has a legal obligation to perform decommissioning or removal activities upon retirement of an asset. MidAmerican Energy's AROs are primarily related to decommissioning of the Quad Cities Station and obligations associated with its other generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to utility plant) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in utility plant, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.

Impairment

MidAmerican Energy evaluates long-lived assets for impairment, including utility plant, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value. The impacts of regulation are considered when evaluating the carrying value of regulated assets. For all other assets, any resulting impairment loss is reflected on the Statements of Operations.

Revenue Recognition

MidAmerican Energy uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which MidAmerican Energy expects to be entitled in exchange for those goods and services. MidAmerican Energy records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Statements of Operations.

A majority of MidAmerican Energy's energy revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided.

Revenue from electric and natural gas customers is recognized as electricity or natural gas is delivered or services are provided. Revenue recognized includes billed and unbilled amounts. As of December 31, 2019 and 2018, unbilled revenue was $91 million and $88 million, respectively, and is included in trade receivables, net on the Balance Sheets.

The determination of customer billings is based on a systematic reading of customer meters and applicable rates. At the end of each month, amounts of energy provided to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses and composition of customer classes. Unbilled revenue is reversed in the following month and billed revenue is recorded based on the subsequent meter readings.

All of MidAmerican Energy's regulated retail electric and natural gas sales are subject to energy adjustment clauses. MidAmerican Energy also has costs that are recovered, at least in part, through bill riders, including demand-side management and certain transmission costs. The clauses and riders allow MidAmerican Energy to adjust the amounts charged for electric and natural gas service as the related costs change. The costs recovered in revenue through use of the adjustment clauses and bill riders are charged to expense in the same year the related revenue is recognized. At any given time, these costs may be over or under collected from customers. The total under collection included in receivables at December 31, 2019 and 2018, was $56 million.

Unamortized Debt Premiums, Discounts and Issuance Costs

Premiums, discounts and issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.


266


Income Taxes

Berkshire Hathaway includes MidAmerican Funding and MidAmerican Energy in its consolidated United States federal and Iowa state income tax returns. MidAmerican Funding's and MidAmerican Energy's provisions for income taxes have been computed on a stand-alone basis.

Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimated income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with certain property-related basis differences and other various differences that MidAmerican Energy deems probable to be passed on to its customers in most state jurisdictions are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions.

In determining MidAmerican Funding's and MidAmerican Energy's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by MidAmerican Energy's various regulatory commissions. MidAmerican Funding's and MidAmerican Energy's income tax returns are subject to continuous examinations by federal, state and local tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. MidAmerican Funding and MidAmerican Energy recognize the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of their federal, state and local income tax examinations is uncertain, each company believes it has made adequate provisions for its income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on its consolidated financial results. MidAmerican Funding's and MidAmerican Energy's unrecognized tax benefits are primarily included in taxes accrued and other long-term liabilities on their respective Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.

New Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, which creates FASB Accounting Standards Codification ("ASC") Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize on the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. MidAmerican Energy has elected to utilize various practical expedients available to adopt ASU No. 2016-02, including (1) the package of three not requiring a reassessment of (i) whether any expired or existing contracts are or contain leases; (ii) the lease classification for any expired or existing leases; and (iii) initial direct costs for any existing leases; (2) using hindsight in determining the lease term; and (3) not requiring a reassessment of whether existing or expired land easements that were not previously accounted for as leases under ASC Topic 840 are or contain a lease under ASC Topic 842. MidAmerican Energy adopted this guidance for all applicable contracts in effect as of January 1, 2019 under a modified retrospective method, and the adoption did not have a cumulative effect impact at the date of initial adoption nor a material impact on MidAmerican Energy's Financial Statements and disclosures included within Notes to Financial Statements.



267


(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following as of December 31 (in millions):

 
Depreciable Life
 
2019
 
2018
 
 
 
 
 
 
Utility plant in service:
 
 
 
 
 
Generation
20-70 years
 
$
15,687

 
$
13,727

Transmission
52-75 years
 
2,124

 
1,934

Electric distribution
20-75 years
 
4,095

 
3,672

Natural gas distribution
29-75 years
 
1,820

 
1,724

Utility plant in service
 
 
23,726

 
21,057

Accumulated depreciation and amortization
 
 
(6,139
)
 
(5,941
)
Utility plant in service, net
 
 
17,587

 
15,116

Nonregulated property, net:
 
 
 
 
 
Nonregulated property gross
20-50 years
 
7

 
7

Accumulated depreciation and amortization
 
 
(1
)
 
(1
)
Nonregulated property, net
 
 
6

 
6

 
 
 
17,593

 
15,122

Construction work-in-progress
 
 
782

 
1,035

Property, plant and equipment, net
 
 
$
18,375

 
$
16,157


Nonregulated property includes land, computer software and other assets not recoverable for regulated utility purposes.

The average depreciation and amortization rates applied to depreciable utility plant for the years ended December 31 were as follows:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Electric
3.1
%
 
2.9
%
 
2.6
%
Natural gas
2.8
%
 
2.8
%
 
2.7
%



268


(4)    Jointly Owned Utility Facilities

Under joint facility ownership agreements with other utilities, MidAmerican Energy, as a tenant in common, has undivided interests in jointly owned generation and transmission facilities. MidAmerican Energy accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating expenses on the Statements of Operations include MidAmerican Energy's share of the expenses of these facilities.

The amounts shown in the table below represent MidAmerican Energy's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2019 (dollars in millions):
 
 
 
 
 
Accumulated
 
Construction
 
Company
 
Plant in
 
Depreciation and
 
Work-in-
 
Share
 
Service
 
Amortization
 
Progress
 
 
 
 
 
 
 
 
Louisa Unit No. 1
88
%
 
$
834

 
$
458

 
$
7

Quad Cities Unit Nos. 1 & 2(1)
25

 
729

 
424

 
11

Walter Scott, Jr. Unit No. 3
79

 
930

 
392

 
5

Walter Scott, Jr. Unit No. 4(2)
60

 
316

 
131

 
1

George Neal Unit No. 4
41

 
316

 
171

 
2

Ottumwa Unit No. 1
52

 
634

 
229

 
19

George Neal Unit No. 3
72

 
489

 
238

 
4

Transmission facilities
Various

 
258

 
95

 

Total
 
 
$
4,506

 
$
2,138

 
$
49

(1)
Includes amounts related to nuclear fuel.
(2)
Plant in service and accumulated depreciation and amortization amounts are net of credits applied under Iowa regulatory arrangements totaling $458 million and $94 million, respectively.

(5)
Regulatory Matters

Regulatory Assets

Regulatory assets represent costs that are expected to be recovered in future regulated rates. MidAmerican Energy's regulatory assets reflected on the Balance Sheets consist of the following as of December 31 (in millions):
 
Average
 
 
 
 
 
Remaining Life
 
2019
 
2018
 
 
 
 
 
 
Asset retirement obligations(1)
6 years
 
$
223

 
$
160

Employee benefit plans(2)
12 years
 
26

 
62

Unrealized loss on regulated derivative contracts
1 year
 
7

 
19

Other
Various
 
33

 
32

Total
 
 
$
289

 
$
273

(1)
Amount predominantly relates to asset retirement obligations for fossil-fueled and wind-powered generating facilities. Refer to Note 11 for a discussion of asset retirement obligations.
(2)
Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.

MidAmerican Energy had regulatory assets not earning a return on investment of $286 million and $269 million as of December 31, 2019 and 2018, respectively.


269


Regulatory Liabilities

Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. MidAmerican Energy's regulatory liabilities reflected on the Balance Sheets consist of the following as of December 31 (in millions):
 
Average
 
 
 
 
 
Remaining Life
 
2019
 
2018
 
 
 
 
 
 
Cost of removal accrual(1)
29 years
 
$
572

 
$
708

Deferred income taxes(2)
Various
 
478

 
626

Asset retirement obligations(3)
33 years
 
241

 
160

Employee benefit plans(4)
10 years
 
32

 

Pre-funded AFUDC on transmission MVPs(5)
53 years
 
35

 
36

Iowa electric revenue sharing accrual(6)
1 year
 
22

 
70

Other
Various
 
26

 
20

Total
 
 
$
1,406

 
$
1,620

(1)
Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing utility plant in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.
(2)
Amounts primarily represent income tax liabilities primarily related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to state accelerated tax depreciation and certain property-related basis differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(3)
Amount represents the excess of nuclear decommission trust assets over the related asset retirement obligation. Refer to Note 11 for a discussion of asset retirement obligations.
(4)
Represents amounts not yet recognized as a component of net periodic benefit cost that are to be returned to customers in future periods when recognized.
(5)
Represents AFUDC accrued on transmission MVPs that is deducted from rate base as a result of the inclusion of related construction work-in-progress in rate base.
(6)
Represents current-year accruals under a regulatory arrangement in Iowa in which equity returns exceeding specified thresholds reduce utility plant upon final determination.

(6)
Investments and Restricted Investments

Investments and restricted investments consists of the following amounts as of December 31 (in millions):
 
2019
 
2018
 
 
 
 
Nuclear decommissioning trust
$
599

 
$
504

Rabbi trusts
203

 
191

Other
16

 
13

Total
$
818

 
$
708


MidAmerican Energy has established a trust for the investment of funds for decommissioning the Quad Cities Station. The debt and equity securities in the trust are reported at fair value. Funds are invested in the trust in accordance with applicable federal and state investment guidelines and are restricted for use as reimbursement for costs of decommissioning the Quad Cities Station, which is currently licensed for operation until December 2032. As of December 31, 2019 and 2018, the fair value of the trust's funds was invested as follows: 56% and 51%, respectively, in domestic common equity securities, 31% and 37%, respectively, in United States government securities, 10% and 9%, respectively, in domestic corporate debt securities and 3% and 3%, respectively, in other securities.

Rabbi trusts primarily hold corporate-owned life insurance on certain current and former key executives and directors. The Rabbi trusts were established to hold investments used to fund the obligations of various nonqualified executive and director compensation plans and to pay the costs of the trusts. The amount represents the cash surrender value of all of the policies included in the Rabbi trusts, net of amounts borrowed against the cash surrender value. Changes in the cash surrender value of the policies are reflected in other income (expense) - other, net on the Statements of Operation.


270


(7)    Short-Term Debt and Credit Facilities

Interim financing of working capital needs and the construction program is obtained from unaffiliated parties through the sale of commercial paper or short-term borrowing from banks. MidAmerican Energy has a $900 million unsecured credit facility expiring June 2022. The credit facility supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations, provides for the issuance of letters of credit and has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. MidAmerican Energy has a $400 million unsecured credit facility that expires in August 2020 and has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread. Additionally, MidAmerican Energy has a $5 million unsecured credit facility, which expires in June 2020 and has a variable interest rate based on the Eurodollar rate plus a spread. As of December 31, 2018, MidAmerican Energy had a $400 million unsecured credit facility expiring November 2019, which was terminated in January 2019. MidAmerican Energy had commercial paper borrowings outstanding of $- million as of December 31, 2019, and $240 million with a weighted average interest rate of 2.49% as of December 31, 2018. The $900 million and $400 million credit facilities each require that MidAmerican Energy's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of any quarter. As of December 31, 2019, MidAmerican Energy was in compliance with the covenants of its credit facilities. MidAmerican Energy has authority from the FERC to issue commercial paper and bank notes aggregating $1.3 billion through July 31, 2020.

The following table summarizes MidAmerican Energy's availability under its two unsecured revolving credit facilities as of December 31 (in millions):
 
2019
 
2018
 
 
 
 
Credit facilities
$
1,305

 
$
1,305

Less:
 
 
 
Short-term debt outstanding

 
(240
)
Variable-rate tax-exempt bond support
(370
)
 
(370
)
Net credit facilities
$
935

 
$
695



271


(8)
Long-Term Debt

MidAmerican Energy's long-term debt consists of the following, including amounts maturing within one year and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
 
Par Value
 
2019
 
2018
 
 
 
 
 
 
First mortgage bonds:
 
 
 
 
 
2.40%, due 2019
$

 
$

 
$
500

3.70%, due 2023
250

 
249

 
249

3.50%, due 2024
500

 
501

 
500

3.10%, due 2027
375

 
373

 
372

3.65%, due 2029
850

 
864

 

4.80%, due 2043
350

 
346

 
346

4.40%, due 2044
400

 
395

 
395

4.25%, due 2046
450

 
445

 
445

3.95%, due 2047
475

 
470

 
470

3.65%, due 2048
700

 
688

 
688

4.25%, due 2049
900

 
872

 

3.15%, due 2050
600

 
591

 

Notes:
 
 
 
 
 
6.75% Series, due 2031
400

 
396

 
396

5.75% Series, due 2035
300

 
298

 
298

5.8% Series, due 2036
350

 
348

 
347

Transmission upgrade obligation, 4.45% and 3.42% due through 2035 and 2036, respectively
6

 
4

 
5

Variable-rate tax-exempt bond obligation series: (weighted average interest rate- 2019-1.66%, 2018-1.74%):
 
 
 
 
 
Due 2023, issued in 1993
7

 
7

 
7

Due 2023, issued in 2008
57

 
57

 
57

Due 2024
35

 
35

 
35

Due 2025
13

 
13

 
13

Due 2036
33

 
33

 
33

Due 2038
45

 
45

 
45

Due 2046
30

 
29

 
29

Due 2047
150

 
149

 
149

Total
$
7,276

 
$
7,208

 
$
5,379


The annual repayments of MidAmerican Energy's long-term debt for the years beginning January 1, 2020, and thereafter, excluding unamortized premiums, discounts and debt issuance costs, are as follows (in millions):
2020
 
$

2021
 

2022
 
1

2023
 
315

2024
 
535

2025 and thereafter
 
6,425



272


Pursuant to MidAmerican Energy's mortgage dated September 9, 2013, MidAmerican Energy's first mortgage bonds, currently and from time to time outstanding, are secured by a first mortgage lien on substantially all of its electric generating, transmission and distribution property within the State of Iowa, subject to certain exceptions and permitted encumbrances. As of December 31, 2019, MidAmerican Energy's eligible property subject to the lien of the mortgage totaled approximately $20 billion based on original cost. Additionally, MidAmerican Energy's senior notes outstanding are equally and ratably secured with the first mortgage bonds as required by the indentures under which the senior notes were issued.

MidAmerican Energy's variable-rate tax-exempt bond obligations bear interest at rates that are periodically established through remarketing of the bonds in the short-term tax-exempt market. MidAmerican Energy, at its option, may change the mode of interest calculation for these bonds by selecting from among several floating or fixed rate alternatives. The interest rates shown in the table above are the weighted average interest rates as of December 31, 2019 and 2018. MidAmerican Energy maintains revolving credit facility agreements to provide liquidity for holders of these issues. Additionally, MidAmerican Energy's obligations associated with the $30 million and $150 million variable rate, tax-exempt bond obligations due 2046 and 2047, respectively, are secured by an equal amount of first mortgage bonds pursuant to MidAmerican Energy's mortgage dated September 9, 2013, as supplemented and amended. Proceeds of the $150 million of variable-rate, tax-exempt Solid Waste Facilities Revenue Bonds due December 2047 are restricted for the purpose of constructing solid waste facilities. As of December 31, 2019, $32 million of the restricted proceeds remain and are reflected in other current assets on the Balance Sheet.

As of December 31, 2019, MidAmerican Energy was in compliance with all of its applicable long-term debt covenants.

In March 1999, MidAmerican Energy committed to the IUB to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain its common equity level above 42% of total capitalization unless circumstances beyond its control result in the common equity level decreasing to below 39% of total capitalization. MidAmerican Energy must seek the approval from the IUB of a reasonable utility capital structure if MidAmerican Energy's common equity level decreases below 42% of total capitalization, unless the decrease is beyond the control of MidAmerican Energy. MidAmerican Energy is also required to seek the approval of the IUB if MidAmerican Energy's equity level decreases to below 39%, even if the decrease is due to circumstances beyond the control of MidAmerican Energy. As of December 31, 2019, MidAmerican Energy's common equity ratio was 51% computed on a basis consistent with its commitment. As a result of its regulatory commitment to maintain its common equity level above certain thresholds, MidAmerican Energy could dividend $2.0 billion as of December 31, 2019, without falling below 42%.

(9)
Income Taxes

MidAmerican Energy's income tax benefit from continuing operations consists of the following for the years ended December 31 (in millions):
 
2019
 
2018
 
2017
Current:
 
 
 
 
 
Federal
$
(478
)
 
$
(276
)
 
$
(490
)
State
(47
)
 
(12
)
 
(25
)
 
(525
)
 
(288
)
 
(515
)
Deferred:
 
 
 
 
 
Federal
166

 
42

 
335

State
(11
)
 
(8
)
 
(2
)
 
155

 
34

 
333

 
 
 
 
 
 
Investment tax credits
(1
)
 
(1
)
 
(1
)
Total
$
(371
)
 
$
(255
)
 
$
(183
)


273


A reconciliation of the federal statutory income tax rate to MidAmerican Energy's effective income tax rate applicable to income before income tax benefit from continuing operations is as follows for the years ended December 31:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Federal statutory income tax rate
21
 %
 
21
 %
 
35
 %
Income tax credits
(90
)
 
(73
)
 
(68
)
State income tax, net of federal income tax benefit
(11
)
 
(4
)
 
(4
)
Effects of ratemaking
(8
)
 
(5
)
 
(7
)
Other, net

 
1

 
1

Effective income tax rate
(88
)%
 
(60
)%
 
(43
)%

Income tax credits relate primarily to production tax credits ("PTC") earned by MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.

MidAmerican Energy's net deferred income tax liability consists of the following as of December 31 (in millions):
 
2019
 
2018
Deferred income tax assets:
 
 
 
Regulatory liabilities
$
368

 
$
405

Asset retirement obligations
234

 
164

Employee benefits
26

 
47

Other
71

 
80

Total deferred income tax assets
699

 
696

 
 
 
 
Deferred income tax liabilities:
 
 
 
Depreciable property
(3,253
)
 
(2,945
)
Regulatory assets
(68
)
 
(61
)
Other
(4
)
 
(12
)
Total deferred income tax liabilities
(3,325
)
 
(3,018
)
 
 
 
 
Net deferred income tax liability
$
(2,626
)
 
$
(2,322
)

As of December 31, 2019, MidAmerican Energy has available $51 million of state tax carryforwards, principally related to $745 million of net operating losses, that expire at various intervals between 2020 and 2038.

The United States Internal Revenue Service has closed its examination of MidAmerican Energy's income tax returns through December 31, 2011. The statute of limitations for MidAmerican Energy's state income tax returns have expired through December 31, 2009, with the exception of Iowa and Illinois, for which the statute of limitations have expired through December 31, 2015, except for the impact of any federal audit adjustments. The statute of limitations expiring for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.


274


A reconciliation of the beginning and ending balances of MidAmerican Energy's net unrecognized tax benefits is as follows for the years ended December 31 (in millions):
 
2019
 
2018
 
 
 
 
Beginning balance
$
10

 
$
12

Additions based on tax positions related to the current year
5

 
4

Additions for tax positions of prior years
10

 
47

Reductions based on tax positions related to the current year
(5
)
 
(4
)
Reductions for tax positions of prior years
(12
)
 
(48
)
Interest and penalties

 
(1
)
Ending balance
$
8

 
$
10


As of December 31, 2019, MidAmerican Energy had unrecognized tax benefits totaling $27 million that, if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect MidAmerican Energy's effective income tax rate.

(10)
Employee Benefit Plans

Defined Benefit Plan

MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering a majority of all employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. Benefit obligations under the plan are based on a cash balance arrangement for salaried employees and most union employees and final average pay formulas for other union employees. MidAmerican Energy also maintains noncontributory, nonqualified defined benefit supplemental executive retirement plans ("SERP") for certain active and retired participants. In 2018, the defined benefit pension plan recorded a settlement gain of $1 million for previously unrecognized gains as a result of excess lump sum distributions over the defined threshold for the year ended December 31, 2018.

MidAmerican Energy also sponsors certain postretirement healthcare and life insurance benefits covering substantially all retired employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. Under the plans, a majority of all employees of the participating companies may become eligible for these benefits if they reach retirement age. New employees are not eligible for benefits under the plans. MidAmerican Energy has been allowed to recover accrued pension and other postretirement benefit costs in its electric and gas service rates.

Net Periodic Benefit Cost

For purposes of calculating the expected return on pension plan assets, a market-related value is used. The market-related value of plan assets is calculated by spreading the difference between expected and actual investment returns on equity investments over a five-year period beginning after the first year in which they occur.

MidAmerican Energy bills to and is reimbursed currently for affiliates' share of the net periodic benefit costs from all plans in which such affiliates participate. In 2019, 2018 and 2017, MidAmerican Energy's share of the pension net periodic benefit (credit) cost was $(8) million, $(9) million and $(6) million, respectively. MidAmerican Energy's share of the other postretirement net periodic benefit (credit) cost in 2019, 2018 and 2017 totaled $1 million, $(2) million and $(1) million, respectively.


275


Net periodic benefit cost for the plans of MidAmerican Energy and the aforementioned affiliates included the following components for the years ended December 31 (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2017
 
2019
 
2018
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
Service cost
$
6

 
$
9

 
$
9

 
$
5

 
$
5

 
$
5

Interest cost
30

 
28

 
31

 
10

 
8

 
9

Expected return on plan assets
(41
)
 
(44
)
 
(44
)
 
(13
)
 
(13
)
 
(14
)
Settlement

 
(1
)
 

 

 

 

Net amortization
1

 
2

 
2

 
(3
)
 
(4
)
 
(4
)
Net periodic benefit (credit) cost
$
(4
)
 
$
(6
)
 
$
(2
)
 
$
(1
)
 
$
(4
)
 
$
(4
)

Funded Status

The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Plan assets at fair value, beginning of year
$
644

 
$
745

 
$
247

 
$
277

Employer contributions
7

 
7

 
1

 
1

Participant contributions

 

 
2

 
1

Actual return on plan assets
123

 
(39
)
 
42

 
(17
)
Settlement

 
(37
)
 

 

Benefits paid
(57
)
 
(32
)
 
(20
)
 
(15
)
Plan assets at fair value, end of year
$
717

 
$
644

 
$
272

 
$
247


The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Benefit obligation, beginning of year
$
736

 
$
799

 
$
242

 
$
246

Service cost
6

 
9

 
5

 
5

Interest cost
30

 
28

 
10

 
8

Participant contributions

 

 
2

 
1

Actuarial (gain) loss
48

 
(33
)
 
(13
)
 
(3
)
Plan amendments

 
2

 

 

Settlement

 
(37
)
 

 

Benefits paid
(57
)
 
(32
)
 
(20
)
 
(15
)
Benefit obligation, end of year
$
763

 
$
736

 
$
226

 
$
242

Accumulated benefit obligation, end of year
$
758

 
$
733

 
 
 
 


276


The funded status of the plans and the amounts recognized on the Balance Sheets as of December 31 are as follows (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Plan assets at fair value, end of year
$
717

 
$
644

 
$
272

 
$
247

Less - Benefit obligation, end of year
763

 
736

 
226

 
242

Funded status
$
(46
)
 
$
(92
)
 
$
46

 
$
5

 
 
 
 
 
 
 
 
Amounts recognized on the Balance Sheets:
 
 
 
 
 
 
 
Other assets
$
66

 
$
17

 
$
46

 
$
5

Other current liabilities
(7
)
 
(7
)
 

 

Other liabilities
(105
)
 
(102
)
 

 

Amounts recognized
$
(46
)
 
$
(92
)
 
$
46

 
$
5


The SERP has no plan assets; however, MidAmerican Energy and BHE have Rabbi trusts that hold corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERP. The cash surrender value of all of the policies included in MidAmerican Energy's Rabbi trusts, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $122 million and $116 million as of December 31, 2019 and 2018. These assets are not included in the plan assets in the above table, but are reflected in investments and restricted investments on the Balance Sheets. The accumulated benefit obligation and projected benefit obligation for the SERP was $112 million and $112 million for 2019 and $109 million and $109 million for 2018, respectively.

Unrecognized Amounts

The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Net loss (gain)
$
6

 
$
40

 
$
4

 
$
48

Prior service cost (credit)
(1
)
 
1

 
(14
)
 
(20
)
Total
$
5

 
$
41

 
$
(10
)
 
$
28


MidAmerican Energy sponsors pension and other postretirement benefit plans on behalf of certain of its affiliates in addition to itself, and therefore, the portion of the funded status of the respective plans that has not yet been recognized in net periodic benefit cost is attributable to multiple entities. Additionally, substantially all of MidAmerican Energy's portion of such amounts is either refundable to or recoverable from its customers and is reflected as regulatory liabilities and regulatory assets.


277


A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2019 and 2018 is as follows (in millions):
 
Regulatory
Asset
 
Regulatory
Liability
 
Receivables
(Payables)
with Affiliates
 
Total
Pension
 
 
 
 
 
 
 
Balance, December 31, 2017
$
24

 
$
(41
)
 
$
7

 
$
(10
)
Net loss arising during the year
2

 
41

 
9

 
52

Net amortization
(2
)
 

 

 
(2
)
Settlement
1

 

 

 
1

Total
1

 
41

 
9

 
51

Balance, December 31, 2018
25

 

 
16

 
41

Net (gain) loss arising during the year
(5
)
 
(32
)
 
2

 
(35
)
Net amortization
(1
)
 

 

 
(1
)
Total
(6
)
 
(32
)
 
2

 
(36
)
Balance, December 31, 2019
$
19

 
$
(32
)
 
$
18

 
$
5


 
Regulatory
Asset
 
Receivables
(Payables)
with Affiliates
 
Total
Other Postretirement
 
 
 
 
 
Balance, December 31, 2017
$
14

 
$
(16
)
 
$
(2
)
Net loss arising during the year
20

 
6

 
26

Net amortization
3

 
1

 
4

Total
23

 
7

 
30

Balance, December 31, 2018
37

 
(9
)
 
28

Net (gain) arising during the year
(33
)
 
(9
)
 
(42
)
Net amortization
3

 
1

 
4

Total
(30
)
 
(8
)
 
(38
)
Balance, December 31, 2019
$
7

 
$
(17
)
 
$
(10
)

Actuarial gains for 2019 impacting the December 31, 2019 funded status for the pension and other postretirement plans are due to higher than assumed actual return on plan assets, offset by a decrease in the discount rate assumptions from that assumed at December 31, 2018.



278


Plan Assumptions

Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
 
Pension
 
Other Postretirement
 
2019
 
2018
 
2017
 
2019
 
2018
 
2017
Benefit obligations as of December 31:
 
 
 
 
 
 
 
 
 
 
 
Discount rate
3.40
%
 
4.25
%
 
3.60
%
 
3.20
%
 
4.15
%
 
3.50
%
Rate of compensation increase
2.75
%
 
2.75
%
 
2.75
%
 
N/A

 
N/A

 
N/A

Interest crediting rates for cash balance plan
 
 
 
 
 
 
 
 
 
 
 
   2017
N/A

 
N/A

 
1.44
%
 
N/A

 
N/A

 
N/A

   2018
N/A

 
2.26
%
 
2.26
%
 
N/A

 
N/A

 
N/A

   2019
3.40
%
 
3.40
%
 
2.26
%
 
N/A

 
N/A

 
N/A

   2020
2.27
%
 
3.40
%
 
1.60
%
 
N/A

 
N/A

 
N/A

   2021
2.27
%
 
3.40
%
 
1.60
%
 
N/A

 
N/A

 
N/A

   2022 and beyond
2.27
%
 
3.40
%
 
1.60
%
 
N/A

 
N/A

 
N/A

 
 
 
 
 
 
 
 
 
 
 
 
Net periodic benefit cost for the years ended December 31:
 
 
 
 
 
 
 
 
 
 
 
Discount rate
4.25
%
 
3.60
%
 
4.10
%
 
4.15
%
 
3.50
%
 
3.90
%
Expected return on plan assets(1)
6.50
%
 
6.50
%
 
6.75
%
 
6.25
%
 
6.25
%
 
6.50
%
Rate of compensation increase
2.75
%
 
2.75
%
 
2.75
%
 
N/A

 
N/A

 
N/A

Interest crediting rates for cash balance plan
3.40
%
 
2.26
%
 
1.44
%
 
N/A

 
N/A

 
N/A

(1)
Amounts reflected are pre-tax values. Assumed after-tax returns for a taxable, non-union other postretirement plan were 4.62% for 2019, 4.13% for 2018, and 4.81% for 2017.

In establishing its assumption as to the expected return on plan assets, MidAmerican Energy utilizes the asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets.
 
2019
 
2018
Assumed healthcare cost trend rates as of December 31:
 
 
 
Healthcare cost trend rate assumed for next year
6.50
%
 
6.80
%
Rate that the cost trend rate gradually declines to
5.00
%
 
5.00
%
Year that the rate reaches the rate it is assumed to remain at
2025
 
2025

Contributions and Benefit Payments

Employer contributions to the pension and other postretirement benefit plans are expected to be $7 million and $1 million, respectively, during 2020. Funding to MidAmerican Energy's qualified pension benefit plan trust is based upon the actuarially determined costs of the plan and the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 and the Pension Protection Act of 2006, as amended. MidAmerican Energy considers contributing additional amounts from time to time in order to achieve certain funding levels specified under the Pension Protection Act of 2006, as amended. MidAmerican Energy evaluates a variety of factors, including funded status, income tax laws and regulatory requirements, in determining contributions to its other postretirement benefit plans.


279


Net periodic benefit costs assigned to MidAmerican Energy affiliates are reimbursed currently in accordance with its intercompany administrative services agreement. The expected benefit payments to participants in MidAmerican Energy's pension and other postretirement benefit plans for 2020 through 2024 and for the five years thereafter are summarized below (in millions):
 
Projected Benefit Payments
 
Pension
 
Other Postretirement
 
 
 
 
2020
$
64

 
$
20

2021
63

 
22

2022
61

 
22

2023
58

 
21

2024
56

 
20

2025-2029
244

 
84


Plan Assets

Investment Policy and Asset Allocations

MidAmerican Energy's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The plans retain outside investment advisors to manage plan investments within the parameters outlined by the MidAmerican Energy Pension and Employee Benefits Plans Administrative Committee. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments.

The target allocations (percentage of plan assets) for MidAmerican Energy's pension and other postretirement benefit plan assets are as follows as of December 31, 2019:
 
Pension
 
Other
Postretirement
 
%
 
%
Debt securities(1)
20-50
 
25-45
Equity securities(1)
60-80
 
45-80
Real estate funds
2-8
 
Other
0-3
 
0-5

(1)
For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities.


280


Fair Value Measurements

The following table presents the fair value of plan assets, by major category, for MidAmerican Energy's defined benefit pension plan (in millions):
 
Input Levels for Fair Value Measurements(1)
 
 
 
Level 1
 
Level 2
 
Level 3
 
Total
As of December 31, 2019:
 
 
 
 
 
 
 
Cash equivalents
$
21

 
$

 
$

 
$
21

Debt securities:
 
 
 
 
 
 
 
United States government obligations
16

 

 

 
16

Corporate obligations

 
61

 

 
61

Municipal obligations

 
5

 

 
5

Agency, asset and mortgage-backed obligations

 
33

 

 
33

Equity securities:
 
 
 
 
 
 
 
United States companies
129

 

 

 
129

International companies
42

 

 

 
42

Investment funds(2)
69

 

 

 
69

Total assets in the hierarchy
$
277

 
$
99

 
$

 
376

Investment funds(2) measured at net asset value
 
 
 
 
 
 
299

Real estate funds measured at net asset value
 
 
 
 
 
 
42

Total assets measured at fair value
 
 
 
 
 
 
$
717

 
 
 
 
 
 
 
 
As of December 31, 2018:
 
 
 
 
 
 
 
Cash equivalents
$

 
$
20

 
$

 
$
20

Debt securities:
 
 
 
 
 
 
 
United States government obligations
6

 

 

 
6

Corporate obligations

 
63

 

 
63

Municipal obligations

 
6

 

 
6

Agency, asset and mortgage-backed obligations

 
37

 

 
37

Equity securities:
 
 
 
 
 
 
 
United States companies
111

 

 

 
111

International companies
35

 

 

 
35

Investment funds(2)
65

 

 

 
65

Total assets in the hierarchy
$
217

 
$
126

 
$

 
343

Investment funds(2) measured at net asset value
 
 
 
 
 
 
260

Real estate funds measured at net asset value
 
 
 
 
 
 
41

Total assets measured at fair value
 
 
 
 
 
 
$
644

(1)
Refer to Note 12 for additional discussion regarding the three levels of the fair value hierarchy.
(2)
Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 69% and 31%, respectively, for 2019 and 65% and 35%, respectively, for 2018. Additionally, these funds are invested in United States and international securities of approximately 74% and 26%, respectively, for 2019 and 74% and 26%, respectively, for 2018.


281


The following table presents the fair value of plan assets, by major category, for MidAmerican Energy's defined benefit other postretirement plans (in millions):
 
Input Levels for Fair Value Measurements(1)
 
 
 
Level 1
 
Level 2
 
Level 3
 
Total
As of December 31, 2019:
 
 
 
 
 
 
 
Cash equivalents
$
6

 
$

 
$

 
$
6

Debt securities:
 
 
 
 
 
 
 
United States government obligations
6

 

 

 
6

Corporate obligations

 
12

 

 
12

Municipal obligations

 
55

 

 
55

Agency, asset and mortgage-backed obligations

 
10

 

 
10

Equity securities:
 
 
 
 
 
 
 
United States companies
75

 

 

 
75

Investment funds(2)
108

 

 

 
108

Total assets measured at fair value
$
195

 
$
77

 
$

 
$
272

 
 
 
 
 
 
 
 
As of December 31, 2018:
 
 
 
 
 
 
 
Cash equivalents
$
5

 
$

 
$

 
$
5

Debt securities:
 
 
 
 
 
 
 
United States government obligations
6

 

 

 
6

Corporate obligations

 
12

 

 
12

Municipal obligations

 
43

 

 
43

Agency, asset and mortgage-backed obligations

 
12

 

 
12

Equity securities:
 
 
 
 
 
 
 
United States companies
73

 

 

 
73

Investment funds(2)
96

 

 

 
96

Total assets measured at fair value
$
180

 
$
67

 
$

 
$
247

(1)
Refer to Note 12 for additional discussion regarding the three levels of the fair value hierarchy.
(2)
Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately 77% and 23%, respectively, for 2019 and 78% and 22%, respectively, for 2018. Additionally, these funds are invested in United States and international securities of approximately 42% and 58%, respectively, for 2019 and 41% and 59%, respectively, for 2018.

For level 1 investments, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. For level 2 investments, the fair value is determined using pricing models based on observable market inputs. Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.

Defined Contribution Plan

MidAmerican Energy sponsors a defined contribution plan ("401(k) plan") covering substantially all employees. MidAmerican Energy's matching contributions are based on each participant's level of contribution, and certain participants receive contributions based on eligible pre-tax annual compensation. Contributions cannot exceed the maximum allowable for tax purposes. Certain participants now receive enhanced benefits in the 401(k) plan and no longer accrue benefits in the noncontributory defined benefit pension plans. MidAmerican Energy's contributions to the plan were $23 million, $22 million, and $20 million for the years ended December 31, 2019, 2018 and 2017, respectively.


282


(11)
Asset Retirement Obligations

MidAmerican Energy estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.

MidAmerican Energy does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $572 million and $708 million as of December 31, 2019 and 2018, respectively.

The following table presents MidAmerican Energy's ARO liabilities by asset type as of December 31 (in millions):
 
2019
 
2018
 
 
 
 
Quad Cities Station
$
358

 
$
345

Fossil-fueled generating facilities
325

 
93

Wind-powered generating facilities
154

 
123

Other
2

 
1

Total asset retirement obligations
$
839

 
$
562

 
 
 
 
Quad Cities Station nuclear decommissioning trust funds(1)
$
599

 
$
504

(1)
Refer to Note 6 for a discussion of the Quad Cities Station nuclear decommissioning trust funds.

The following table reconciles the beginning and ending balances of MidAmerican Energy's ARO liabilities for the years ended December 31 (in millions):
 
2019
 
2018
 
 
 
 
Beginning balance
$
562

 
$
559

Change in estimated costs
234

 
(10
)
Additions
27

 
17

Retirements
(14
)
 
(28
)
Accretion
30

 
24

Ending balance
$
839

 
$
562

 
 
 
 
Reflected as:
 
 
 
Other current liabilities
$
135

 
$
10

Asset retirement obligations
704

 
552

 
$
839

 
$
562


In January 2018, MidAmerican Energy completed groundwater testing at its coal combustion residuals ("CCR") surface impoundments. Based on this information, MidAmerican Energy discontinued sending CCR to surface impoundments effective April 2018 and initiated analysis of additional actions to be taken. As a result of that analysis, MidAmerican Energy will remove all CCR material located below the water table and cap the material in such facilities, which is a more extensive closure activity than previously assumed. In the first quarter of 2019, MidAmerican Energy increased the asset retirement obligations for its fossil-fueled generating facilities by $237 million related to the cost of this closure activity. Closure activity on the six existing surface impoundments is estimated to extend through 2023.


283


(12)
Fair Value Measurements

The carrying value of MidAmerican Energy's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. MidAmerican Energy has various financial assets and liabilities that are measured at fair value on the Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that MidAmerican Energy has the ability to access at the measurement date.
Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
Level 3 - Unobservable inputs reflect MidAmerican Energy's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. MidAmerican Energy develops these inputs based on the best information available, including its own data.

284


The following table presents MidAmerican Energy's assets and liabilities recognized on the Balance Sheets and measured at fair value on a recurring basis (in millions):
 
 
Input Levels for Fair Value Measurements
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other(1)
 
Total
As of December 31, 2019:
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
$

 
$
2

 
$
1

 
$
(1
)
 
$
2

Money market mutual funds(2)
 
274

 

 

 

 
274

Debt securities:
 
 
 
 
 
 
 
 
 
 
United States government obligations
 
189

 

 

 

 
189

International government obligations
 

 
4

 

 

 
4

Corporate obligations
 

 
58

 

 

 
58

Municipal obligations
 

 
1

 

 

 
1

Agency, asset and mortgage-backed obligations
 

 
1

 

 

 
1

Equity securities:
 
 
 
 
 
 
 
 
 
 
United States companies
 
336

 

 

 

 
336

International companies
 
9

 

 

 

 
9

Investment funds
 
15

 

 

 

 
15

 
 
$
823

 
$
66

 
$
1

 
$
(1
)
 
$
889

 
 
 
 
 
 
 
 
 
 
 
Liabilities - commodity derivatives
 
$

 
$
(9
)
 
$

 
$
2

 
$
(7
)
 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2018
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
$

 
$
4

 
$
2

 
$
(3
)
 
$
3

Money market mutual funds(2)
 
2

 

 

 

 
2

Debt securities:
 
 
 
 
 
 
 
 
 
 
United States government obligations
 
187

 

 

 

 
187

International government obligations
 

 
4

 

 

 
4

Corporate obligations
 

 
46

 

 

 
46

Municipal obligations
 

 
2

 

 

 
2

Agency, asset and mortgage-backed obligations
 

 
1

 

 

 
1

Equity securities:
 
 
 
 
 
 
 
 
 
 
United States companies
 
256

 

 

 

 
256

International companies
 
6

 

 

 

 
6

Investment funds
 
10

 

 

 

 
10

 
 
$
461

 
$
57

 
$
2

 
$
(3
)
 
$
517

Liabilities:
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
$

 
$
(4
)
 
$
(2
)
 
$
3

 
$
(3
)
Interest rate derivatives(3)
 
$

 
$
(19
)
 
$

 
$

 
$
(19
)
 
 
$

 
$
(23
)
 
$
(2
)
 
$
3

 
$
(22
)

(1)
Represents netting under master netting arrangements and a net cash collateral receivable of $1 million and $- million as of December 31, 2019 and 2018, respectively.
(2)
Amounts are included in cash and cash equivalents and investments and restricted investments on the Balance Sheets. The fair value of these money market mutual funds approximates cost.
(3)
The interest rate derivatives were interest rate locks related to MidAmerican Energy's January 2019 issuance of first mortgage bonds.


285


MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value, with debt securities accounted for as available-for-sale securities. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
MidAmerican Energy's long-term debt is carried at cost on the Financial Statements. The fair value of MidAmerican Energy's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Energy's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Energy's long-term debt as of December 31 (in millions):
 
2019
 
2018
 
Carrying
Value
 
Fair Value
 
Carrying
Value
 
Fair Value
 
 
 
 
 
 
 
 
Long-term debt
$
7,208

 
$
8,283

 
$
5,379

 
$
5,644


(13)
Commitments and Contingencies    

Commitments

MidAmerican Energy had the following firm commitments that are not reflected on the Balance Sheet. Minimum payments as of December 31, 2019, are as follows (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
2025 and
 
 
 
 
2020
 
2021
 
2022
 
2023
 
2024
 
Thereafter
 
Total
Contract type:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Coal and natural gas for generation
 
$
114

 
$
52

 
$
48

 
$
39

 
$

 
$

 
$
253

Electric capacity and transmission
 
28

 
24

 
14

 
8

 
7

 
29

 
110

Natural gas contracts for gas operations
 
102

 
61

 
47

 
24

 
8

 
23

 
265

Construction commitments
 
670

 
515

 
27

 
2

 
4

 

 
1,218

Easements
 
32

 
36

 
37

 
38

 
39

 
1,492

 
1,674

Maintenance, services and other
 
198

 
156

 
154

 
155

 
120

 
432

 
1,215

 
 
$
1,144

 
$
844

 
$
327

 
$
266

 
$
178

 
$
1,976

 
$
4,735


Coal, Natural Gas, Electric Capacity and Transmission Commitments

MidAmerican Energy has coal supply and related transportation and lime contracts for its coal-fueled generating facilities. MidAmerican Energy expects to supplement the coal contracts with additional contracts and spot market purchases to fulfill its future coal supply needs. Additionally, MidAmerican Energy has a natural gas transportation contract for a natural gas-fueled generating facility. The contracts have minimum payment commitments ranging through 2023.

MidAmerican Energy has various natural gas supply and transportation contracts for its regulated natural gas operations that have minimum payment commitments ranging through 2037.

MidAmerican Energy has contracts to purchase electric capacity that have minimum payment commitments ranging through 2028. MidAmerican Energy also has contracts for the right to transmit electricity over other entities' transmission lines with minimum payment commitments ranging through 2022.

Construction Commitments

MidAmerican Energy's 2020 and 2021 firm construction commitments reflected in the table above consist primarily of contracts for the construction and repowering of wind-powered generating facilities and the settlement of asset retirement obligations.


286


Easements

MidAmerican Energy has non-cancelable easements with minimum payment commitments ranging through 2061 for land in Iowa on which certain of its assets, primarily wind-powered generating facilities, are located.

Maintenance, Services and Other Contracts

MidAmerican Energy has other non-cancelable contracts primarily related to maintenance and services for various generating facilities with minimum payment commitments ranging through 2029.

Environmental Laws and Regulations

MidAmerican Energy is subject to federal, state and local laws and regulations regarding air and water quality, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.

Transmission Rates

MidAmerican Energy's wholesale transmission rates are set annually using FERC-approved formula rates subject to true-up for actual cost of service. MidAmerican Energy is authorized by the FERC to include a 0.50% adder beyond the base ROE effective January 2015. Prior to September 2016, the rates in effect were based on a 12.38% return on equity ("ROE"). In November 2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the 12.38% ROE no longer be found just and reasonable and sought to reduce the base ROE to 9.15% and 8.67%, respectively. In September 2016, the FERC issued an order for the first complaint, which reduced the base ROE to 10.32% and required refunds, plus interest, for the period from November 2013 through February 2015. Customer refunds relative to the first complaint occurred in February 2017. In November 2019, the FERC issued an order addressing the second complaint and issues on appeal in the first complaint. The order established an ROE of 9.88% (10.38% including the 0.50% adder) for the 15-month refund period of the first complaint and prospectively from September 2016 forward. The order indicated no refunds were necessary for the period February 2015 through September 2016. The order has been appealed, and MidAmerican Energy has accrued a $16 million liability for refunds of amounts collected under the higher ROE during the periods covered by both complaints.

Legal Matters

MidAmerican Energy is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Energy does not believe that such normal and routine litigation will have a material impact on its financial results.

(14)
Revenue from Contracts with Customers

MidAmerican Energy uses a single five-step model to identify and recognizes revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. The following table summarizes MidAmerican Energy's revenue by line of business and customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 18, (in millions):

287


 
For the Year Ended December 31,
 
2019
 
2018
 
Electric
 
Natural Gas
 
Other
 
Total
 
Electric
 
Natural Gas
 
Other
 
Total
Customer Revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
672

 
$
383

 
$

 
$
1,055

 
$
696

 
$
421

 
$

 
$
1,117

Commercial
322

 
132

 

 
454

 
314

 
153

 

 
467

Industrial
799

 
17

 

 
816

 
758

 
22

 

 
780

Natural gas transportation services

 
38

 

 
38

 

 
39

 

 
39

Other retail
145

 

 

 
145

 
147

 
1

 

 
148

Total retail
1,938

 
570

 

 
2,508

 
1,915

 
636

 

 
2,551

Wholesale
221

 
88

 

 
309

 
295

 
116

 

 
411

Multi-value transmission projects
57

 

 

 
57

 
55

 

 

 
55

Other Customer Revenue

 

 
28

 
28

 

 

 
11

 
11

Total Customer Revenue
2,216

 
658

 
28

 
2,902

 
2,265

 
752

 
11

 
3,028

Other revenue
21

 
2

 

 
23

 
18

 
2

 
1

 
21

Total operating revenue
$
2,237

 
$
660

 
$
28

 
$
2,925

 
$
2,283

 
$
754

 
$
12

 
$
3,049


(15)    Other Income (Expense) - Other, Net

Other, net, as shown on the Statements of Operations, includes the following other income (expense) items for the years ended December 31 (in millions):
 
2019
 
2018
 
2017
 
 
 
 
 
 
Non-service cost components of postretirement employee benefit plans
$
17

 
$
21

 
$
18

Corporate-owned life insurance income
24

 
6

 
13

Interest income and other, net
9

 
3

 
6

Total
$
50

 
$
30

 
$
37



288


(16)    Supplemental Cash Flow Disclosures

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 2019 and 2018, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2019 and 2018 as presented in the Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Balance Sheets (in millions):
 
As of December 31,
 
2019
 
2018
 
 
 
 
Cash and cash equivalents
$
287

 
$

Restricted cash and cash equivalents in other current assets
43

 
56

Total cash and cash equivalents and restricted cash and cash equivalents
$
330

 
$
56


The summary of supplemental cash flow disclosures as of and for the years ending December 31 is as follows (in millions):
 
2019
 
2018
 
2017
Supplemental cash flow information:
 
 
 
 
 
Interest paid, net of amounts capitalized
$
224

 
$
198

 
$
193

Income taxes received, net
$
450

 
$
494

 
$
465

 
 
 
 
 
 
Supplemental disclosure of non-cash investing transactions:
 
 
 
 
 
Accounts payable related to utility plant additions
$
337

 
$
371

 
$
224


(17)
Related Party Transactions

The companies identified as affiliates of MidAmerican Energy are Berkshire Hathaway and its subsidiaries, including BHE and its subsidiaries. The basis for the following transactions is provided for in service agreements between MidAmerican Energy and the affiliates.

MidAmerican Energy is reimbursed for charges incurred on behalf of its affiliates. The majority of these reimbursed expenses are for general costs, such as insurance and building rent, and for employee wages, benefits and costs related to corporate functions such as information technology, human resources, treasury, legal and accounting. The amount of such reimbursements was $43 million, $51 million and $53 million for 2019, 2018 and 2017, respectively. Additionally, in 2018, MidAmerican Energy received $15 million from BHE for the transfer of a corporate aircraft.

MidAmerican Energy reimbursed BHE in the amount of $14 million, $11 million and $9 million in 2019, 2018 and 2017, respectively, for its share of corporate expenses.

MidAmerican Energy purchases natural gas transportation and storage capacity services from Northern Natural Gas Company, a wholly owned subsidiary of BHE, and coal transportation services from BNSF Railway Company, an indirect wholly owned subsidiary of Berkshire Hathaway, in the normal course of business at either tariffed or market prices. These purchases totaled $139 million, $127 million and $122 million in 2019, 2018 and 2017, respectively.

MidAmerican Energy had accounts receivable from affiliates of $6 million and $8 million as of December 31, 2019 and 2018, respectively, that are included in receivables on the Balance Sheets. MidAmerican Energy also had accounts payable to affiliates of $11 million and $12 million as of December 31, 2019 and 2018, respectively, that are included in accounts payable on the Balance Sheets.


289


MidAmerican Energy is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated United States federal income tax return. For current federal and state income taxes, MidAmerican Energy had a payable to BHE of $82 million and $156 million as of December 31, 2019 and 2018, respectively. MidAmerican Energy received net cash receipts for federal and state income taxes from BHE totaling $450 million, $494 million and $465 million for the years ended December 31, 2019, 2018 and 2017, respectively.

MidAmerican Energy recognizes the full amount of the funded status for its pension and postretirement plans, and amounts attributable to MidAmerican Energy's affiliates that have not previously been recognized through income are recognized as an intercompany balance with such affiliates. MidAmerican Energy adjusts these balances when changes to the funded status of the respective plans are recognized and does not intend to settle the balances currently. Amounts receivable from affiliates attributable to the funded status of employee benefit plans totaled $23 million and $20 million as of December 31, 2019 and 2018, respectively, and similar amounts payable to affiliates totaled $47 million and $36 million as of December 31, 2019 and 2018, respectively. See Note 10 for further information pertaining to pension and postretirement accounting.

(18)    Segment Information

MidAmerican Energy has identified two reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. Refer to Note 9 for a discussion of items affecting income tax (benefit) expense for the regulated electric and natural gas operating segments.

The following tables provide information on a reportable segment basis (in millions):
 
Years Ended December 31,
 
2019
 
2018
 
2017
Operating revenue:
 
 
 
 
 
Regulated electric
$
2,237

 
$
2,283

 
$
2,108

Regulated natural gas
660

 
754

 
719

Other
28

 
12

 
10

Total operating revenue
$
2,925

 
$
3,049

 
$
2,837

 
 
 
 
 
 
Depreciation and amortization:
 
 
 
 
 
Regulated electric
$
593

 
$
565

 
$
458

Regulated natural gas
46

 
44

 
42

Total depreciation and amortization
$
639

 
$
609

 
$
500

 
 
 
 
 
 
Operating income:
 
 
 
 
 
Regulated electric
$
473

 
$
469

 
$
472

Regulated natural gas
71

 
81

 
72

Other
4

 
1

 
(1
)
Total operating income
$
548

 
$
551

 
$
543

 
 
 
 
 
 
Interest expense:
 
 
 
 
 
Regulated electric
$
259

 
$
208

 
$
196

Regulated natural gas
22

 
19

 
18

Total interest expense
$
281

 
$
227

 
$
214

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

290


 
Years Ended December 31,
 
2019
 
2018
 
2017
Income tax (benefit) expense:
 
 
 
 
 
Regulated electric
$
(384
)
 
$
(273
)
 
$
(212
)
Regulated natural gas
12

 
16

 
29

Other
1

 
2

 

Total income tax (benefit) expense
$
(371
)
 
$
(255
)
 
$
(183
)
 
 
 
 
 
 
Net income:
 
 
 
 
 
Regulated electric
$
739

 
$
628

 
$
570

Regulated natural gas
52

 
54

 
35

Other
2

 

 

Net income
$
793

 
$
682

 
$
605

 
 
 
 
 
 
Capital expenditures:
 
 
 
 
 
Regulated electric
$
2,684

 
$
2,223

 
$
1,686

Regulated natural gas
126

 
109

 
87

Total capital expenditures
$
2,810

 
$
2,332

 
$
1,773


 
As of December 31,
 
2019
 
2018
 
2017
Total assets:
 
 
 
 
 
Regulated electric
$
19,093

 
$
16,511

 
$
14,914

Regulated natural gas
1,468

 
1,406

 
1,403

Other
3

 
3

 
1

Total assets
$
20,564

 
$
17,920

 
$
16,318


291





REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Managers and Member of
MidAmerican Funding, LLC
Des Moines, Iowa

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in member's equity, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes and the schedules listed in the Index at Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of MidAmerican Funding as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of MidAmerican Funding's management. Our responsibility is to express an opinion on MidAmerican Funding's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to MidAmerican Funding in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. MidAmerican Funding is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of MidAmerican Funding's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.


/s/ Deloitte & Touche LLP

Des Moines, Iowa
February 21, 2020

We have served as MidAmerican Funding's auditor since 1999.


292


MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)

 
As of December 31,
 
2019
 
2018
 
 
 
 
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
288

 
$
1

Trade receivables, net
291

 
365

Inventories
226

 
204

Other current assets
91

 
89

Total current assets
896

 
659

 
 
 
 
Property, plant and equipment, net
18,377

 
16,169

Goodwill
1,270

 
1,270

Regulatory assets
289

 
273

Investments and restricted investments
820

 
710

Other assets
188

 
121

 
 
 
 
Total assets
$
21,840

 
$
19,202


The accompanying notes are an integral part of these consolidated financial statements.

293


MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)

 
As of December 31,
 
2019
 
2018
 
 
 
 
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
 
 
 
Accounts payable
$
520

 
$
575

Accrued interest
84

 
58

Accrued property, income and other taxes
226

 
300

Note payable to affiliate
171

 
156

Short-term debt

 
240

Current portion of long-term debt

 
500

Other current liabilities
219

 
122

Total current liabilities
1,220

 
1,951

 
 
 
 
Long-term debt
7,448

 
5,119

Regulatory liabilities
1,406

 
1,620

Deferred income taxes
2,621

 
2,319

Asset retirement obligations
704

 
552

Other long-term liabilities
340

 
312

Total liabilities
13,739

 
11,873

 
 
 
 
Commitments and contingencies (Note 13)

 

 
 
 
 
Member's equity:
 
 
 
Paid-in capital
1,679

 
1,679

Retained earnings
6,422

 
5,650

Total member's equity
8,101

 
7,329

 
 
 
 
Total liabilities and member's equity
$
21,840

 
$
19,202


The accompanying notes are an integral part of these consolidated financial statements.


294


MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
Operating revenue:
 
 
 
 
 
Regulated electric
$
2,237

 
$
2,283

 
$
2,108

Regulated natural gas and other
690

 
770

 
738

Total operating revenue
2,927

 
3,053

 
2,846

 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
Cost of fuel and energy
399

 
487

 
434

Cost of natural gas purchased for resale and other
412

 
469

 
447

Operations and maintenance
801

 
813

 
802

Depreciation and amortization
639

 
609

 
500

Property and other taxes
127

 
125

 
119

Total operating expenses
2,378

 
2,503

 
2,302

 
 
 
 
 
 
Operating income
549

 
550

 
544

 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
Interest expense
(302
)
 
(247
)
 
(237
)
Allowance for borrowed funds
27

 
20

 
15

Allowance for equity funds
78

 
53

 
41

Other, net
52

 
31

 
9

Total other income (expense)
(145
)
 
(143
)
 
(172
)
 
 
 
 
 
 
Income before income tax benefit
404

 
407

 
372

Income tax benefit
(377
)
 
(262
)
 
(202
)
 
 
 
 
 
 
Net income
$
781

 
$
669

 
$
574


The accompanying notes are an integral part of these consolidated financial statements.

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY
(Amounts in millions)

 
Paid-in
Capital
 
Retained
Earnings
 
Total Member's Equity
 
 
 
 
 
 
Balance, December 31, 2016
$
1,679

 
$
4,407

 
$
6,086

Net income

 
574

 
574

Balance, December 31, 2017
1,679

 
4,981

 
6,660

Net income

 
669

 
669

Balance, December 31, 2018
1,679

 
5,650

 
7,329

Net income

 
781

 
781

Distribution to member

 
(8
)
 
(8
)
Other equity transactions

 
(1
)
 
(1
)
Balance, December 31, 2019
$
1,679

 
$
6,422

 
$
8,101


The accompanying notes are an integral part of these consolidated financial statements.


295


MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
 
Years Ended December 31,
 
2019
 
2018
 
2017
Cash flows from operating activities:
 
 
 
 
 
Net income
$
781

 
$
669

 
$
574

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
 
 
Loss on other items

 

 
29

Depreciation and amortization
639

 
609

 
500

Amortization of utility plant to other operating expenses
33

 
34

 
34

Allowance for equity funds
(78
)
 
(53
)
 
(41
)
Deferred income taxes and amortization of investment tax credits
152

 
32

 
334

Other, net
(8
)
 
16

 
(14
)
Changes in other operating assets and liabilities:
 
 
 
 
 
Trade receivables and other assets
56

 
(19
)
 
(62
)
Inventories
(22
)
 
41

 
19

Derivative collateral, net
(1
)
 
(1
)
 
2

Contributions to pension and other postretirement benefit plans, net
(10
)
 
(13
)
 
(11
)
Accrued property, income and other taxes, net
(74
)
 
230

 
(54
)
Accounts payable and other liabilities
7

 
(29
)
 
70

Net cash flows from operating activities
1,475

 
1,516

 
1,380

 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
Capital expenditures
(2,810
)
 
(2,332
)
 
(1,773
)
Purchases of marketable securities
(156
)
 
(263
)
 
(143
)
Proceeds from sales of marketable securities
138

 
223

 
137

Proceeds from sales of other investments
1

 
17

 
2

Other investment proceeds
13

 
15

 
1

Other, net
13

 
30

 
(3
)
Net cash flows from investing activities
(2,801
)
 
(2,310
)
 
(1,779
)
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
Proceeds from long-term debt
2,326

 
687

 
990

Repayments of long-term debt
(500
)
 
(350
)
 
(341
)
Net change in note payable to affiliate
15

 
(8
)
 
133

Net (repayments of) proceeds from short-term debt
(240
)
 
240

 
(99
)
Tender offer premium paid

 

 
(29
)
Other, net
(1
)
 

 

Net cash flows from financing activities
1,600

 
569

 
654

 
 
 
 
 
 
Net change in cash and cash equivalents and restricted cash and cash equivalents
274

 
(225
)
 
255

Cash and cash equivalents and restricted cash and cash equivalents at beginning of year
57

 
282

 
27

Cash and cash equivalents and restricted cash and cash equivalents at end of year
$
331

 
$
57

 
$
282


The accompanying notes are an integral part of these consolidated financial statements.


296


MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)
Organization and Operations

MidAmerican Funding, LLC ("MidAmerican Funding") is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). MidAmerican Funding's direct wholly owned subsidiary is MHC Inc. ("MHC"), which constitutes substantially all of MidAmerican Funding's assets, liabilities and business activities except those related to MidAmerican Funding's long-term debt securities. MHC conducts no business other than the ownership of its subsidiaries and related corporate services. MHC's principal subsidiary is MidAmerican Energy Company ("MidAmerican Energy"), a public utility with electric and natural gas operations, and its direct, wholly owned nonregulated subsidiary is Midwest Capital Group, Inc. ("Midwest Capital Group").

(2)
Summary of Significant Accounting Policies

In addition to the following significant accounting policies, refer to Note 2 of MidAmerican Energy's Notes to Financial Statements for significant accounting policies of MidAmerican Funding.

Basis of Consolidation and Presentation

The Consolidated Financial Statements include the accounts of MidAmerican Funding and its subsidiaries in which it held a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated, other than those between rate-regulated operations. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2019, 2018 and 2017.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired when MidAmerican Funding purchased MHC. MidAmerican Funding evaluates goodwill for impairment at least annually and completed its annual review as of October 31. When evaluating goodwill for impairment, MidAmerican Funding estimates the fair value of the reporting unit. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the identifiable assets, including identifiable intangible assets, and liabilities of the reporting unit are estimated at fair value as of the current testing date. The excess of the estimated fair value of the reporting unit over the current estimated fair value of net assets establishes the implied value of goodwill. The excess of the recorded goodwill over the implied goodwill value is charged to earnings as an impairment loss. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. MidAmerican Funding uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. In estimating future cash flows, MidAmerican Funding incorporates current market information, as well as historical factors. As such, the determination of fair value incorporates significant unobservable inputs. During 2019, 2018 and 2017, MidAmerican Funding did not record any goodwill impairments.

(3)    Property, Plant and Equipment, Net

Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements. In addition to MidAmerican Energy's property, plant and equipment, net, MidAmerican Funding had nonregulated property gross of $3 million and $24 million as of December 31, 2019 and 2018, respectively, and related accumulated depreciation and amortization of $1 million and $12 million as of December 31, 2019 and 2018, respectively, which, as of December 31, 2018, consisted primarily of a corporate aircraft owned by MHC. In 2019, MHC transferred the aircraft by dividend to MidAmerican Funding, which transferred it to BHE.

(4)
Jointly Owned Utility Facilities

Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.

(5)
Regulatory Matters

Refer to Note 5 of MidAmerican Energy's Notes to Financial Statements.

(6)
Investments and Restricted Investments

Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K. In addition to MidAmerican Energy's investments and restricted investments, MHC had corporate-owned life insurance policies in a Rabbi trust owned by MHC with a total cash surrender value of $2 million as of December 31, 2019 and 2018.

(7)
Short-Term Debt and Credit Facilities

Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements. In addition to MidAmerican Energy's credit facilities, MHC has a $4 million unsecured credit facility, which expires in June 2020 and has a variable interest rate based on the Eurodollar rate plus a spread. As of December 31, 2019 and 2018, there were no borrowings outstanding under this credit facility. As of December 31, 2019, MHC was in compliance with the covenants of its credit facility.

(8)    Long-Term Debt

Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements for detail and a discussion of its long-term debt. In addition to MidAmerican Energy's annual repayments of long-term debt, MidAmerican Funding has $239 million of 6.927% Senior Bonds due in 2029, with a carrying value of $240 million as of December 31, 2019 and 2018. In December 2017, MidAmerican Funding redeemed through a tender offer a portion of its 6.927% Senior Bonds. A charge of $29 million for the total premium is included in other income (expense) on the Consolidated Statement of Operations.

MidAmerican Funding parent company long-term debt is secured by a pledge of the common stock of MHC. See Item 15(c) for the Consolidated Financial Statements of MHC Inc. and subsidiaries. The bonds are the direct senior secured obligations of MidAmerican Funding and effectively rank junior to all indebtedness and other liabilities of the direct and indirect subsidiaries of MidAmerican Funding, to the extent of the assets of these subsidiaries. MidAmerican Funding may redeem the bonds in whole or in part at any time at a redemption price equal to the sum of any accrued and unpaid interest to the date of redemption and the greater of (1) 100% of the principal amount of the bonds or (2) the sum of the present values of the remaining scheduled payments of principal and interest on the bonds, discounted to the date of redemption on a semiannual basis at the treasury yield plus 25 basis points.

Subsidiaries of MidAmerican Funding must make payments on their own indebtedness before making distributions to MidAmerican Funding. Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements for a discussion of utility regulatory restrictions affecting distributions from MidAmerican Energy. As a result of the utility regulatory restrictions agreed to by MidAmerican Energy in March 1999, MidAmerican Funding had restricted net assets of $5.2 billion as of December 31, 2019.

As of December 31, 2019, MidAmerican Funding was in compliance with all of its applicable long-term debt covenants.

Each of MidAmerican Funding's direct or indirect subsidiaries is organized as a legal entity separate and apart from MidAmerican Funding and its other subsidiaries. It should not be assumed that any asset of any subsidiary of MidAmerican Funding will be available to satisfy the obligations of MidAmerican Funding or any of its other subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MidAmerican Funding, one of its subsidiaries or affiliates thereof.


297


(9)    Income Taxes

MidAmerican Funding's income tax benefit from continuing operations consists of the following for the years ended December 31 (in millions):
 
2019
 
2018
 
2017
Current:
 
 
 
 
 
Federal
$
(480
)
 
$
(280
)
 
$
(505
)
State
(49
)
 
(14
)
 
(31
)
 
(529
)
 
(294
)
 
(536
)
Deferred:
 
 
 
 
 
Federal
164

 
42

 
338

State
(11
)
 
(9
)
 
(3
)
 
153

 
33

 
335

 
 
 
 
 
 
Investment tax credits
(1
)
 
(1
)
 
(1
)
Total
$
(377
)
 
$
(262
)
 
$
(202
)

A reconciliation of the federal statutory income tax rate to MidAmerican Funding's effective income tax rate applicable to income before income tax benefit from continuing operations is as follows for the years ended December 31:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Federal statutory income tax rate
21
 %
 
21
 %
 
35
 %
Income tax credits
(94
)
 
(76
)
 
(77
)
State income tax, net of federal income tax benefit
(12
)
 
(4
)
 
(6
)
Effects of ratemaking
(8
)
 
(6
)
 
(8
)
Other, net

 
1

 
2

Effective income tax rate
(93
)%
 
(64
)%
 
(54
)%

Income tax credits relate primarily to production tax credits ("PTC") earned by MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.


298


MidAmerican Funding's net deferred income tax liability consists of the following as of December 31 (in millions):
 
2019
 
2018
Deferred income tax assets:
 
 
 
Regulatory liabilities
$
368

 
$
405

Asset retirement obligations
234

 
164

Employee benefits
26

 
47

Other
76

 
85

Total deferred income tax assets
704

 
701

 
 
 
 
Deferred income tax liabilities:
 
 
 
Depreciable property
(3,253
)
 
(2,947
)
Regulatory assets
(68
)
 
(62
)
Other
(4
)
 
(11
)
Total deferred income tax liabilities
(3,325
)
 
(3,020
)
 
 
 
 
Net deferred income tax liability
$
(2,621
)
 
$
(2,319
)

As of December 31, 2019, MidAmerican Funding has available $51 million of state tax carryforwards, principally related to $745 million of net operating losses, that expire at various intervals between 2020 and 2038.

The United States Internal Revenue Service has closed its examination MidAmerican Funding’s income tax returns through December 31, 2011. The statute of limitations for MidAmerican Funding’s state income tax returns have expired through December 31, 2009, with the exception of Iowa and Illinois, for which the statute of limitations have expired through December 31, 2015, except for the impact of any federal audit adjustments. The statute of limitations expiring for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.

A reconciliation of the beginning and ending balances of MidAmerican Funding's net unrecognized tax benefits is as follows for the years ended December 31 (in millions):
 
2019
 
2018
 
 
 
 
Beginning balance
$
10

 
$
12

Additions based on tax positions related to the current year
5

 
4

Additions for tax positions of prior years
10

 
47

Reductions based on tax positions related to the current year
(5
)
 
(4
)
Reductions for tax positions of prior years
(12
)
 
(48
)
Interest and penalties

 
(1
)
Ending balance
$
8

 
$
10


As of December 31, 2019, MidAmerican Funding had unrecognized tax benefits totaling $27 million that, if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect MidAmerican Funding's effective income tax rate.


299


(10)    Employee Benefit Plans

Refer to Note 10 of MidAmerican Energy's Notes to Financial Statements for additional information regarding MidAmerican Funding's pension, supplemental retirement and postretirement benefit plans.

Pension and postretirement costs allocated by MidAmerican Funding to its parent and other affiliates in each of the years ended December 31, were as follows (in millions):
 
2019
 
2018
 
2017
 
 
 
 
 
 
Pension costs
$
4

 
$
3

 
$
4

Other postretirement costs
(2
)
 
(2
)
 
(3
)

(11)
Asset Retirement Obligations

Refer to Note 11 of MidAmerican Energy's Notes to Financial Statements.

(12)    Fair Value Measurements

Refer to Note 12 of MidAmerican Energy's Notes to Financial Statements.

MidAmerican Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Funding's long-term debt as of December 31 (in millions):
 
2019
 
2018
 
Carrying
Value
 
Fair Value
 
Carrying
Value
 
Fair Value
 
 
 
 
 
 
 
 
Long-term debt
$
7,448

 
$
8,599

 
$
5,619

 
$
5,941


(13)    Commitments and Contingencies

Refer to Note 13 of MidAmerican Energy's Notes to Financial Statements.

Legal Matters

MidAmerican Funding is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Funding does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

(14)    Revenue from Contracts with Customers

Refer to Note 14 of MidAmerican Energy's Notes to Financial Statements. Additionally, MidAmerican Funding had $2 million and $4 million of other revenue from contracts with customers for the year ended December 31, 2019 and 2018, respectively.
 

300


(15)    Other Income (Expense) - Other, Net

Other, net, as shown on the Consolidated Statements of Operations, includes the following other income (expense) items for the years ended December 31 (in millions):
 
2019
 
2018
 
2017
 
 
 
 
 
 
Non-service cost components of postretirement employee benefit plans
$
17

 
$
21

 
$
18

Corporate-owned life insurance income
24

 
6

 
13

Loss on debt tender offer

 

 
(29
)
Interest income and other, net
11

 
4

 
7

Total
$
52

 
$
31

 
$
9


Refer to Note 8 for information regarding the debt tender offer.

(16)    Supplemental Cash Flow Information

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 2019 and 2018, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2019 and 2018 as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
 
As of December 31,
 
2019
 
2018
 
 
 
 
Cash and cash equivalents
$
288

 
$
1

Restricted cash and cash equivalents in other current assets
43

 
56

Total cash and cash equivalents and restricted cash and cash equivalents
$
331

 
$
57


The summary of supplemental cash flow information as of and for the years ending December 31 is as follows (in millions):
 
2019
 
2018
 
2017
Supplemental cash flow information:
 
 
 
 
 
Interest paid, net of amounts capitalized
$
245

 
$
218

 
$
218

Income taxes received, net
$
456

 
$
511

 
$
472

 
 
 
 
 
 
Supplemental disclosure of non-cash investing and financing transactions:
 
 
 
 
 
Accounts payable related to utility plant additions
$
337

 
$
371

 
$
224

Distribution of corporate aircraft to parent
$
8

 
$

 
$


(17)
Related Party Transactions

The companies identified as affiliates of MidAmerican Funding are Berkshire Hathaway and its subsidiaries, including BHE and its subsidiaries. The basis for the following transactions is provided for in service agreements between MidAmerican Funding and the affiliates.


301


MidAmerican Funding is reimbursed for charges incurred on behalf of its affiliates. The majority of these reimbursed expenses are for allocated general costs, such as insurance and building rent, and for employee wages, benefits and costs for corporate functions, such as information technology, human resources, treasury, legal and accounting. The amount of such reimbursements was $41 million, $44 million and $46 million for 2019, 2018 and 2017, respectively. Additionally, in 2018, MidAmerican Funding received $15 million from BHE for the transfer of corporate aircraft owned by MidAmerican Energy and, in 2019, recorded a noncash dividend of $8 million for the transfer to BHE of corporate aircraft owned by MHC.

MidAmerican Funding reimbursed BHE in the amount of $14 million, $11 million and $9 million in 2019, 2018 and 2017, respectively, for its share of corporate expenses.

MidAmerican Energy purchases natural gas transportation and storage capacity services from Northern Natural Gas Company, a wholly owned subsidiary of BHE, and coal transportation services from BNSF Railway Company, a wholly-owned subsidiary of Berkshire Hathaway, in the normal course of business at either tariffed or market prices. These purchases totaled $139 million, $127 million and $122 million in 2019, 2018 and 2017, respectively.

MHC has a $300 million revolving credit arrangement carrying interest at the 30-day LIBOR rate plus a spread to borrow from BHE. Outstanding balances are unsecured and due on demand. The outstanding balance was $171 million at an interest rate of 1.944% as of December 31, 2019, and $156 million at an interest rate of 2.629% as of December 31, 2018, and is reflected as note payable to affiliate on the Consolidated Balance Sheet.

BHE has a $100 million revolving credit arrangement, carrying interest at the 30-day LIBOR rate plus a spread to borrow from MHC. Outstanding balances are unsecured and due on demand. There were no borrowings outstanding throughout 2019 and 2018.

MidAmerican Funding had accounts receivable from affiliates of $7 million and $5 million as of December 31, 2019 and 2018, respectively, that are included in receivables, net on the Consolidated Balance Sheets. MidAmerican Funding also had accounts payable to affiliates of $11 million and $12 million as of December 31, 2019 and 2018, respectively, that are included in accounts payable on the Consolidated Balance Sheets.

MidAmerican Funding is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated United States federal income tax return. For current federal and state income taxes, MidAmerican Funding had a payable to BHE of $83 million and $156 million as of December 31, 2019 and 2018, respectively. MidAmerican Funding received net cash receipts for federal and state income taxes from BHE totaling $456 million, $511 million and $472 million for the years ended December 31, 2019, 2018 and 2017, respectively.

MidAmerican Funding recognizes the full amount of the funded status for its pension and postretirement plans, and amounts attributable to MidAmerican Funding's affiliates that have not previously been recognized through income are recognized as an intercompany balance with such affiliates. MidAmerican Funding adjusts these balances when changes to the funded status of the respective plans are recognized and does not intend to settle the balances currently. Amounts receivable from affiliates attributable to the funded status of employee benefit plans totaled $23 million and $20 million as of December 31, 2019 and 2018, respectively, and similar amounts payable to affiliates totaled $47 million and $36 million as of December 31, 2019 and 2018, respectively. See Note 10 for further information pertaining to pension and postretirement accounting.

The indenture pertaining to MidAmerican Funding's long-term debt restricts MidAmerican Funding from paying a distribution on its equity securities, unless after making such distribution either its debt to total capital ratio does not exceed 0.67:1 and its interest coverage ratio is not less than 2.2:1 or its senior secured long-term debt rating is at least BBB or its equivalent. MidAmerican Funding may seek a release from this restriction upon delivery to the indenture trustee of written confirmation from the ratings agencies that without this restriction MidAmerican Funding's senior secured long-term debt would be rated at least BBB+.


302


(18)
Segment Information

MidAmerican Funding has identified two reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. "Other" in the tables below consists of the nonregulated subsidiaries of MidAmerican Funding not engaged in the energy business and parent company interest expense. Refer to Note 9 for a discussion of items affecting income tax (benefit) expense for the regulated electric and natural gas operating segments.

The following tables provide information on a reportable segment basis (in millions):
 
Years Ended December 31,
 
2019
 
2018
 
2017
Operating revenue:
 
 
 
 
 
Regulated electric
$
2,237

 
$
2,283

 
$
2,108

Regulated natural gas
660

 
754

 
719

Other
30

 
16

 
19

Total operating revenue
$
2,927

 
$
3,053

 
$
2,846

 
 
 
 
 
 
Depreciation and amortization:
 
 
 
 
 
Regulated electric
$
593

 
$
565

 
$
458

Regulated natural gas
46

 
44

 
42

Total depreciation and amortization
$
639

 
$
609

 
$
500

 
 
 
 
 
 
Operating income:
 
 
 
 
 
Regulated electric
$
473

 
$
469

 
$
472

Regulated natural gas
71

 
81

 
72

Other
5

 

 

Total operating income
$
549

 
$
550

 
$
544

 
 
 
 
 
 
Interest expense:
 
 
 
 
 
Regulated electric
$
259

 
$
208

 
$
196

Regulated natural gas
22

 
19

 
18

Other
21

 
20

 
23

Total interest expense
$
302

 
$
247

 
$
237

 
 
 
 
 
 
Income tax (benefit) expense:
 
 
 
 
 
Regulated electric
$
(384
)
 
$
(273
)
 
$
(212
)
Regulated natural gas
12

 
16

 
29

Other
(5
)
 
(5
)
 
(19
)
Total income tax (benefit) expense
$
(377
)
 
$
(262
)
 
$
(202
)
 
 
 
 
 
 
Net income:
 
 
 
 
 
Regulated electric
$
739

 
$
628

 
$
570

Regulated natural gas
52

 
54

 
35

Other
(10
)
 
(13
)
 
(31
)
Net income
$
781

 
$
669

 
$
574

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

303


 
Years Ended December 31,
 
2019
 
2018
 
2017
Capital expenditures:
 
 
 
 
 
Regulated electric
$
2,684

 
$
2,223

 
$
1,686

Regulated natural gas
126

 
109

 
87

Total capital expenditures
$
2,810

 
$
2,332

 
$
1,773


 
As of December 31,
 
2019
 
2018
 
2017
Total assets:
 
 
 
 
 
Regulated electric
$
20,284

 
$
17,702

 
$
16,105

Regulated natural gas
1,547

 
1,485

 
1,482

Other
9

 
15

 
34

Total assets
$
21,840

 
$
19,202

 
$
17,621


Goodwill by reportable segment as of December 31, 2019 and 2018, was as follows (in millions):
Regulated electric
$
1,191

Regulated natural gas
79

Total
$
1,270



304



Nevada Power Company and its subsidiaries
Consolidated Financial Section


305


Item 6.        Selected Financial Data

Information required by Item 6 is omitted pursuant to General Instruction I(2)(a) to Form 10-K.

Item 7.        Management's Discussion and Analysis of Financial Condition and Results of Operations 

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Nevada Power during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Nevada Power's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K. Nevada Power's actual results in the future could differ significantly from the historical results.

Results of Operations

Overview

Net income for the year ended December 31, 2019 was $264 million, an increase of $38 million, or 17%, compared to 2018, primarily due to $119 million of lower operations and maintenance, mainly due to lower political activity expenses, a lower accrual for earnings sharing and lower settlement costs associated with a personal injury claim in 2018. The increase is partially offset by $62 million of lower utility margin, mainly due to lower customer volumes from the unfavorable impacts of weather and lower average retail rates related to the tax rate reduction rider effective April 2018, and $20 million of higher depreciation and amortization expense, primarily due to higher plant placed in service.

Net income for the year ended December 31, 2018 was $226 million, a decrease of $29 million, or 11%, compared to 2017, primarily due to $52 million of higher operations and maintenance expense, mainly due to an accrual for earnings sharing established in 2018 as part of the Nevada Power 2017 regulatory rate review and increased political activity expenses, $37 million of lower utility margin and higher depreciation and amortization, primarily due to various regulatory-directed amortizations established in the Nevada Power 2017 regulatory rate review. These decreases were partially offset by lower income tax expense of $84 million, primarily from a lower federal tax rate due to the impact of the Tax Cuts and Jobs Act (the "2017 Tax Reform") and $9 million of lower interest expense on long-term debt. Utility margins decreased due to lower average retail rates including rate impacts related to the tax rate reduction rider as a result of 2017 Tax Reform and lower margins from customers purchasing energy from alternative providers and becoming distribution only service customers, partially offset by higher residential, commercial and industrial volumes.



306


Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operations. Utility margin is calculated as operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.
Nevada Power's cost of fuel and energy is generally recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in Nevada Power's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of fuel and energy separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):
 
 
2019
 
2018
 
Change
 
2018
 
2017
 
Change
Utility margin:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenue
 
$
2,148

 
$
2,184

 
$
(36
)
(2
)%
 
$
2,184

 
$
2,206

 
$
(22
)
(1
)%
Cost of fuel and energy
 
943

 
917

 
26

3

 
917

 
902

 
15

2

Utility margin
 
1,205

 
1,267

 
(62
)
(5
)
 
1,267

 
1,304

 
(37
)
(3
)
Operations and maintenance
 
324

 
443

 
(119
)
(27
)
 
443

 
391

 
52

13

Depreciation and amortization
 
357

 
337

 
20

6

 
337

 
308

 
29

9

Property and other taxes
 
45

 
41

 
4

10

 
41

 
40

 
1

3

Operating income
 
$
479

 
$
446

 
$
33

7
 %
 
$
446

 
$
565

 
$
(119
)
(21
)%































307


A comparison of key operating results related to utility margin is as follows for the years ended December 31:

 
 
2019
 
2018
 
Change
 
2018
 
2017
 
Change
Utility margin (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenue
 
$
2,148

 
$
2,184

 
$
(36
)
(2
)%
 
$
2,184

 
$
2,206

 
$
(22
)
(1
)%
Cost of fuel and energy
 
943

 
917

 
26

3

 
917

 
902

 
15

2

Utility margin
 
$
1,205

 
$
1,267

 
$
(62
)
(5
)%
 
$
1,267

 
$
1,304

 
$
(37
)
(3
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
GWhs sold:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
9,311

 
9,970

 
(659
)
(7
)%
 
9,970

 
9,501

 
469

5
 %
Commercial
 
4,657

 
4,778

 
(121
)
(3
)
 
4,778

 
4,656

 
122

3

Industrial
 
5,344

 
5,534

 
(190
)
(3
)
 
5,534

 
6,201

 
(667
)
(11
)
Other
 
193

 
214

 
(21
)
(10
)
 
214

 
212

 
2

1

Total fully bundled(1)
 
19,505

 
20,496

 
(991
)
(5
)
 
20,496

 
20,570

 
(74
)

Distribution only service
 
2,613

 
2,521

 
92

4

 
2,521

 
1,830

 
691

38

Total retail
 
22,118

 
23,017

 
(899
)
(4
)
 
23,017

 
22,400

 
617

3

Wholesale
 
527

 
274

 
253

92

 
274

 
314

 
(40
)
(13
)
Total GWhs sold
 
22,645

 
23,291

 
(646
)
(3
)%
 
23,291

 
22,714

 
577

3
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
840

 
825

 
15

2
 %
 
825

 
810

 
15

2
 %
Commercial
 
109

 
108

 
1

1

 
108

 
106

 
2

2

Industrial
 
2

 
2

 


 
2

 
2

 


Total
 
951

 
935

 
16

2
 %
 
935

 
918

 
17

2
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average per MWh:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenue - fully bundled(1)
 
$
105.88

 
$
102.82

 
$
3.06

3
 %
 
$
102.82

 
$
104.57

 
$
(1.75
)
(2
)%
Revenue - wholesale
 
$
35.87

 
$
40.31

 
$
(4.44
)
(11
)%
 
$
40.31

 
$
37.26

 
$
3.05

8
 %
Cost of energy(2)(3)
 
$
46.06

 
$
42.17

 
$
3.89

9
 %
 
$
42.17

 
$
41.84

 
$
0.33

1
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Heating degree days
 
1,875

 
1,527

 
348

23
 %
 
1,527

 
1,265

 
262

21
 %
Cooling degree days
 
3,648

 
4,255

 
(607
)
(14
)%
 
4,255

 
4,044

 
211

5
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sources of energy (GWhs)(3)(4):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas
 
13,161

 
13,848

 
(687
)
(5
)%
 
13,848

 
13,172

 
676

5
 %
Coal
 
1,059

 
1,231

 
(172
)
(14
)
 
1,231

 
1,449

 
(218
)
(15
)
Renewables
 
61

 
69

 
(8
)
(12
)
 
69

 
73

 
(4
)
(5
)
Total energy generated
 
14,281

 
15,148

 
(867
)
(6
)
 
15,148

 
14,694

 
454

3

Energy purchased
 
6,167

 
6,587

 
(420
)
(6
)
 
6,587

 
6,858

 
(271
)
(4
)
Total
 
20,448

 
21,735

 
(1,287
)
(6
)%
 
21,735

 
21,552

 
183

1
 %

(1)
Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2)
The average cost per MWh of energy includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.
(3)
The average cost per MWh of energy and sources of energy excludes 153, 153 and 296 GWhs of coal and 1,756, 1,483 and 2,373 GWhs of natural gas generated energy that is purchased at cost by related parties for the years ended December 31, 2019, 2018 and 2017, respectively.
(4)
GWh amounts are net of energy used by the related generating facilities.

308


Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

Utility margin decreased $62 million for 2019 compared to 2018 primarily due to:
$51 million in lower customer volumes primarily from the unfavorable impacts of weather;
$11 million in lower retail rates due to the tax rate reduction rider effective April 2018;
$4 million from lower transmission revenue; and
$3 million due to lower retail rates as a result of the 2017 regulatory rate review with rates effective February 2018.
The decrease in utility margin was offset by:
$7 million due to residential and commercial customer growth.

Operations and maintenance decreased $119 million, or 27%, for 2019 compared to 2018 primarily due to the impacts of adopting ASC 842 of $50 million, lower political activity expenses, a lower accrual for earnings sharing of $19 million and settlement costs associated with a personal injury claim in 2018 of $8 million.

Depreciation and amortization increased $20 million, or 6%, for 2019 compared to 2018 primarily due to the impacts of adopting ASC 842 of $13 million and higher plant placed in service.

Property and other taxes increased $4 million, or 10%, for 2019 compared to 2018 primarily due to a decrease in available abatements.

Other income (expense) is favorable $6 million, or 4%, for 2019 compared to 2018 primarily due to lower interest expense on long-term debt and regulatory liabilities of $36 million, higher dividend and interest income of $7 million and higher other income due to a licensing agreement with a third party of $2 million, partially offset by the impacts of adopting ASC 842 of $37 million and higher non-service pension expense of $5 million.

Income tax expense increased $1 million, or 1%, for 2019 compared to 2018. The effective tax rate was 22% in 2019 and 24% in 2018 and decreased due to lower nondeductible expenses.

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

Utility margin decreased $37 million for 2018 compared to 2017 due to:
$51 million in lower retail rates due to the tax rate reduction rider as a result of 2017 Tax Reform;
$30 million due to lower retail rates as a result of the 2017 regulatory rate review with rates effective February 2018; and
$20 million in lower commercial and industrial retail revenue from customers purchasing energy from alternative providers and becoming distribution-only service customers.
The decrease in utility margin was partially offset by:
$20 million in higher residential volumes primarily from the impacts of weather;
$20 million in higher commercial and industrial volumes;
$11 million in higher other revenue primarily from impact fees and revenue relating to customers becoming distribution-only service customers;
$9 million due to residential customer growth; and
$4 million in higher energy efficiency program rate revenue, which is offset in operations and maintenance expense.

Operations and maintenance increased $52 million, or 13%, for 2018 compared to 2017 primarily due to an accrual for earnings sharing established in 2018 as part of the Nevada Power 2017 regulatory rate review and increased political activity expenses, partially offset by disallowances in 2017 resulting from regulatory rate reviews.

Depreciation and amortization increased $29 million, or 9%, for 2018 compared to 2017 primarily due to various regulatory-directed amortizations and increased depreciation expense as a result of the Nevada Power 2017 regulatory rate review.



309




Other income (expense) is favorable $6 million, or 4%, for 2018 compared to 2017 primarily due to lower interest expense on long-term debt, partially offset by an unfavorable clarification order from the 2017 regulatory rate review to record carrying charges on impact fees received from customers that elected to become distribution only service customers and losses on investments.

Income tax expense decreased $84 million, or 54%, for 2018 compared to 2017. The effective tax rate was 24% in 2018 and 38% in 2017. The decrease in the effective tax rate is primarily due to 2017 Tax Reform, which reduced the United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, partially offset by an increase in nondeductible expenses.

Liquidity and Capital Resources

As of December 31, 2019, Nevada Power's total net liquidity was $415 million as follows (in millions):
Cash and cash equivalents
 
$
15

Credit facilities(1)
 
400

Total net liquidity
 
$
415

Credit facilities:
 
 
Maturity dates
 
2022


(1)
Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding Nevada Power's credit facility.

Operating Activities

Net cash flows from operating activities for the years ended December 31, 2019 and 2018 were $701 million and $619 million, respectively. The change was primarily due to lower interest payments for long-term debt, lower payments for operating costs, mainly due to lower political activity expenses, a decrease in fuel costs, lower contributions to the pension plan and proceeds from a licensing agreement with a third party, partially offset by lower collections from customers due to the unfavorable impacts of weather and decreased collections of customer advances.

Net cash flows from operating activities for the years ended December 31, 2018 and 2017 were $619 million and $665 million, respectively. The change was due to impact fees received in 2017, higher contributions to the pension plan and higher payments for operating costs, partially offset by increased collections from customers due to higher deferred energy rates.

The timing of Nevada Power's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.

Investing Activities

Net cash flows from investing activities for the years ended December 31, 2019 and 2018 were $(407) million and $(297) million, respectively. The change was primarily due to increased capital expenditures. Refer to “Future Uses of Cash” for further discussion of capital expenditures.

Net cash flows from investing activities for the years ended December 31, 2018 and 2017 were $(297) million and $(343) million, respectively. The change was primarily due to the acquisition of the remaining 25% ownership in the Silverhawk generating station in 2017, partially offset by increased capital expenditures.

Financing Activities

Net cash flows from financing activities for the years ended December 31, 2019 and 2018 were $(390) million and $(267) million, respectively. The change was primarily due to lower proceeds from issuance of long-term debt and higher dividends paid to NV Energy, Inc. of $447 million in 2019, partially offset by lower repayments of long-term debt.

Net cash flows from financing activities for the years ended December 31, 2018 and 2017 were $(267) million and $(546) million, respectively. The change was due to greater proceeds from issuance of long-term debt and higher dividends paid to NV Energy, Inc. in 2017, partially offset by higher repayments of long-term debt.

310



Ability to Issue Debt

Nevada Power currently has an effective automatic registration statement with the SEC to issue an indeterminate amount of long-term debt securities through October 15, 2022. Additionally, Nevada Power's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of December 31, 2019, Nevada Power has financing authority from the PUCN consisting of the ability to issue long-term and short-term debt securities so long as the total amount of debt outstanding (excluding borrowings under Nevada Power’s $400 million secured credit facility) does not exceed $3.2 billion as measured at the end of each calendar quarter. Nevada Power's revolving credit facility contains a financial maintenance covenant which Nevada Power was in compliance with as of December 31, 2019. In addition, certain financing agreements contain covenants which are currently suspended as Nevada Power's senior secured debt is rated investment grade. However, if Nevada Power's senior secured debt ratings fall below investment grade by either Moody's Investor Service or Standard & Poor's, Nevada Power would be subject to limitations under these covenants.

Ability to Issue General and Refunding Mortgage Securities

To the extent Nevada Power has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, Nevada Power's ability to issue secured debt is limited by the amount of bondable property or retired bonds that can be used to issue debt under Nevada Power's indenture.

Nevada Power's indenture creates a lien on substantially all of Nevada Power's properties in Nevada. As of December 31, 2019, $8.7 billion of Nevada Power's assets were pledged. Nevada Power had the capacity to issue $3.3 billion of additional general and refunding mortgage securities as of December 31, 2019 determined on the basis of 70% of net utility property additions. Property additions include plant-in-service and specific assets in construction work-in-progress. The amount of bond capacity listed above does not include eligible property in construction work-in-progress. Nevada Power also has the ability to release property from the lien of Nevada Power's indenture on the basis of net property additions, cash or retired bonds. To the extent Nevada Power releases property from the lien of Nevada Power's indenture, it will reduce the amount of securities issuable under the indenture.

Long-Term Debt

In January 2019, Nevada Power issued $500 million of its 3.700% General and Refunding Mortgage Notes, Series CC, due May 2029. Nevada Power used the net proceeds to repay all of Nevada Power's $500 million 7.125% General and Refunding Mortgage Notes, Series V, maturing in March 2019.

In January 2020, Nevada Power issued $425 million of its 2.400% General and Refunding Mortgage Notes, Series DD, due May 2030 and issued $300 million of its 3.125% General and Refunding Mortgage Notes, Series EE, due August 2050. Nevada Power intends to use the net proceeds from the sale of the Notes to repay $575 million aggregate principal amount of its 2.750% General and Refunding Mortgage Notes, Series BB, maturing in April 2020 and for general corporate purposes.

In January 2020, Nevada Power issued a 30-day notice of early redemption to repay $575 million of its 2.750% General and Refunding Mortgage Notes, Series BB.

Future Uses of Cash

Capital Expenditures

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution control technologies, replacement generation and associated operating costs are generally incorporated into Nevada Power's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.

311



Historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ending December 31 are as follows (in millions):
 
Historical
 
Forecasted
 
2017
 
2018
 
2019
 
2020
 
2021
 
2022
 
 
 
 
 
 
 
 
 
 
 
 
Generation development
$

 
$

 
$

 
$
84

 
$
47

 
$
30

Distribution
110

 
137

 
209

 
242

 
88

 
142

Transmission system investment
9

 
9

 
10

 
21

 
6

 
23

Operating and other
151

 
150

 
185

 
149

 
140

 
78

Total
$
270

 
$
296

 
$
404

 
$
496

 
$
281

 
$
273


Nevada Power's forecast capital expenditures include investments that relate to operating projects that consist of routine expenditures for transmission, distribution, generation and other infrastructure needed to serve existing and expected demand.

Contractual Obligations

Nevada Power has contractual cash obligations that may affect its consolidated financial condition. The following table summarizes Nevada Power's material contractual cash obligations as of December 31, 2019 (in millions):
 
 
Payments Due by Periods
 
 
2020
 
2021 - 2022
 
2023 - 2024
 
2025 and Thereafter
 
Total
 
 
 
 
 
 
 
 
 
 
 
Long-term debt
 
$
575

 
$

 
$

 
$
1,809

 
$
2,384

Interest payments on long-term debt(1)
 
103

 
190

 
190

 
1,126

 
1,609

ON Line finance lease liability
 
12

 
26

 
31

 
316

 
385

Interest payments on ON Line finance lease liability(1)
 
32

 
62

 
57

 
325

 
476

Operating and finance lease liabilities(2)
 
11

 
34

 
14

 
26

 
85

Interest payments on operating and finance lease liabilities(1)
 
7

 
10

 
5

 
4

 
26

Fuel and capacity contract commitments(1)(3)
 
539

 
709

 
645

 
3,432

 
5,325

Fuel and capacity contract commitments (not commercially operable)(1)(3)
 
1

 
47

 
249

 
4,677

 
4,974

Non-construction commitments(1)
 
23

 

 

 

 
23

Easements(1)
 
4

 
9

 
8

 
43

 
64

Asset retirement obligations
 
14

 
22

 
14

 
32

 
82

Maintenance, service and other contracts(1)
 
51

 
91

 
59

 
18

 
219

Total contractual cash obligations
 
$
1,372

 
$
1,200

 
$
1,272

 
$
11,808

 
$
15,652


(1)
Not reflected on the Consolidated Balance Sheets.
(2)
Includes fuel and capacity contracts designated as a finance lease.
(3)
Purchased power includes estimated payments for contracts which meet the definition of a lease and payments are based on the amount of energy expected to be generated.

Nevada Power has other types of commitments that arise primarily from unused lines of credit, letters of credit or relate to construction and other development costs (Liquidity and Capital Resources included within this Item 7 and Note 7) and asset retirement obligations (Note 11), which have not been included in the above table because the amount and timing of the cash payments are not certain. Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.


312


Regulatory Matters

Nevada Power is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further discussion regarding Nevada Power's general regulatory framework and current regulatory matters.

Environmental Laws and Regulations

Nevada Power is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Nevada Power believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and financial results. Refer to "Liquidity and Capital Resources" for discussion of Nevada Power's forecasted environmental-related capital expenditures.

Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.

313



Collateral and Contingent Features

Debt of Nevada Power is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of Nevada Power's ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.

Nevada Power has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. Nevada Power's secured revolving credit facility does not require the maintenance of a minimum credit rating level in order to draw upon its availability. However, commitment fees and interest rates under the credit facility are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2019, the applicable credit ratings obtained from recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2019, Nevada Power would have been required to post $22 million of additional collateral. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.

Inflation

Historically, overall inflation and changing prices in the economies where Nevada Power operates has not had a significant impact on Nevada Power's consolidated financial results. Nevada Power operates under a cost-of-service based rate structure administered by the PUCN and the FERC. Under this rate structure, Nevada Power is allowed to include prudent costs in its rates, including the impact of inflation after Nevada Power experiences cost increases. Fuel and purchase power costs are recovered through a balancing account, minimizing the impact of inflation related to these costs. Nevada Power attempts to minimize the potential impact of inflation on its operations through the use of periodic rate adjustments for fuel and energy costs, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting Nevada Power, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by Nevada Power's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with Nevada Power's Summary of Significant Accounting Policies included in Nevada Power's Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

Accounting for the Effects of Certain Types of Regulation

Nevada Power prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Nevada Power defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.


314


Nevada Power continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Nevada Power's ability to recover its costs. Nevada Power believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss). Total regulatory assets were $0.8 billion and total regulatory liabilities were $1.3 billion as of December 31, 2019. Refer to Nevada Power's Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's regulatory assets and liabilities.

Impairment of Long-Lived Assets

Nevada Power evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2019, the impacts of regulation are considered when evaluating the carrying value of regulated assets.

The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what Nevada Power would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect Nevada Power's results of operations.


315


Income Taxes

In determining Nevada Power's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by Nevada Power's various regulatory commissions. Nevada Power's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Nevada Power recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Nevada Power's federal, state and local income tax examinations is uncertain, Nevada Power believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on Nevada Power's consolidated financial results. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations. Refer to Nevada Power's Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's income taxes.

Revenue Recognition - Unbilled Revenue

Revenue is recognized as electricity is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since their last billing is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $109 million as of December 31, 2019. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month when actual revenue is recorded.


316


Item 7A.     Quantitative and Qualitative Disclosures About Market Risk

Nevada Power's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. Nevada Power's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which Nevada Power transacts. The following discussion addresses the significant market risks associated with Nevada Power's business activities. Nevada Power has established guidelines for credit risk management. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's contracts accounted for as derivatives.

Commodity Price Risk

Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity, natural gas and coal market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. Nevada Power's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates through its deferred energy mechanism, which is subject to disallowance and regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.

Interest Rate Risk

Nevada Power is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. Nevada Power manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, Nevada Power's fixed-rate long-term debt does not expose Nevada Power to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if Nevada Power were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of Nevada Power's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7 and 8 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of Nevada Power's short- and long-term debt.

As of December 31, 2019 and 2018, Nevada Power had no short- and long-term variable-rate obligations that expose Nevada Power to the risk of increased interest expense in the event of increases in short-term interest rates.

Credit Risk

Nevada Power is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Nevada Power analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Nevada Power enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Nevada Power exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
 
As of December 31, 2019, Nevada Power's aggregate credit exposure from energy related transactions were not material, based on settlement and mark-to-market exposures, net of collateral.


317


Item 8.        Financial Statements and Supplementary Data

 
 
 
 
 
 
Consolidated Balance Sheets
 
 
 
 
 
 
Consolidated Statements of Operations
 
 
 
 
 
 
Consolidated Statements of Changes in Shareholder's Equity
 
 
 
 
 
 
Consolidated Statements of Cash Flows
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
 


318



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholder of
Nevada Power Company


Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Nevada Power Company and subsidiaries ("Nevada Power") as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Nevada Power as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of Nevada Power's management. Our responsibility is to express an opinion on Nevada Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Nevada Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Nevada Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Nevada Power's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/
Deloitte & Touche LLP

Las Vegas, Nevada
February 21, 2020
We have served as Nevada Power's auditor since 1987.


319


NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions, except share data)

 
As of December 31,
 
2019
 
2018
ASSETS
 
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
15

 
$
111

Trade receivables, net
215

 
233

Inventories
62

 
61

Regulatory assets
1

 
39

Prepayments
42

 
51

Other current assets
29

 
24

Total current assets
364

 
519

 
 
 
 
Property, plant and equipment, net
6,538

 
6,418

Finance lease right of use assets, net
441

 
450

Regulatory assets
800

 
878

Other assets
59

 
37

 
 
 
 
Total assets
$
8,202

 
$
8,302

 
 
 
 
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
 
 
 
Accounts payable
$
194

 
$
187

Accrued interest
30

 
38

Accrued property, income and other taxes
25

 
30

Current portion of long-term debt
575

 
500

Current portion of finance lease obligations
24

 
20

Regulatory liabilities
93

 
49

Customer deposits
62

 
67

Other current liabilities
34

 
29

Total current liabilities
1,037

 
920

 
 
 
 
Long-term debt
1,776

 
1,853

Finance lease obligations
430

 
443

Regulatory liabilities
1,163

 
1,137

Deferred income taxes
714

 
749

Other long-term liabilities
285

 
296

Total liabilities
5,405

 
5,398

 
 
 
 
Commitments and contingencies (Note 13)
 
 
 
 
 
 
 
Shareholder's equity:
 
 
 
Common stock - $1.00 stated value, 1,000 shares authorized, issued and outstanding

 

Additional paid-in capital
2,308

 
2,308

Retained earnings
493

 
600

Accumulated other comprehensive loss, net
(4
)
 
(4
)
Total shareholder's equity
2,797

 
2,904

 
 
 
 
Total liabilities and shareholder's equity
$
8,202

 
$
8,302

 
 
 
 
The accompanying notes are an integral part of the consolidated financial statements.


320


NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Operating revenue
$
2,148

 
$
2,184

 
$
2,206

 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
Cost of fuel and energy
943

 
917

 
902

Operations and maintenance
324

 
443

 
391

Depreciation and amortization
357

 
337

 
308

Property and other taxes
45

 
41

 
40

Total operating expenses
1,669

 
1,738

 
1,641

 
 
 
 
 
 
Operating income
479

 
446

 
565

 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
Interest expense
(171
)
 
(170
)
 
(179
)
Allowance for borrowed funds
3

 
2

 
1

Allowance for equity funds
5

 
3

 
1

Other, net
21

 
17

 
23

Total other income (expense)
(142
)
 
(148
)
 
(154
)
 
 
 
 
 
 
Income before income tax expense
337

 
298

 
411

Income tax expense
73

 
72

 
156

Net income
$
264

 
$
226

 
$
255

 
 
 
 
 
 
The accompanying notes are an integral part of these consolidated financial statements.


321


NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Amounts in millions, except shares)

 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
Other
 
 
 
Other
 
Total
 
 
Common Stock
 
Paid-in
 
Retained
 
Comprehensive
 
Shareholder's
 
 
Shares
 
Amount
 
Capital
 
Earnings
 
Loss, Net
 
Equity
Balance, December 31, 2016
 
1,000

 
$

 
$
2,308

 
$
667

 
$
(3
)
 
$
2,972

Net income
 

 

 

 
255

 

 
255

Dividends declared
 

 

 

 
(548
)
 

 
(548
)
Other equity transactions
 

 

 

 

 
(1
)
 
(1
)
Balance, December 31, 2017
 
1,000

 

 
2,308

 
374

 
(4
)
 
2,678

Net income
 

 

 

 
226

 

 
226

Balance, December 31, 2018
 
1,000

 

 
2,308

 
600

 
(4
)
 
2,904

Net income
 

 

 

 
264

 

 
264

Dividends declared
 

 

 

 
(371
)
 

 
(371
)
Balance, December 31, 2019
 
1,000

 
$

 
$
2,308

 
$
493

 
$
(4
)
 
$
2,797

 
 
 
 
 
 
 
 
 
 
 
 
 
The accompanying notes are an integral part of these consolidated financial statements.


322


NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Cash flows from operating activities:
 
 
 
 
 
Net income
$
264

 
$
226

 
$
255

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
 
 
Loss (gain) on nonrecurring items
1

 

 
(1
)
Depreciation and amortization
357

 
337

 
308

Allowance for equity funds
(5
)
 
(3
)
 
(1
)
Changes in regulatory assets and liabilities
27

 
83

 
50

Deferred income taxes and amortization of investment tax credits
(32
)
 
(13
)
 
94

Deferred energy
51

 
(11
)
 
(16
)
Amortization of deferred energy
43

 
16

 
16

Other, net
(6
)
 
14

 
(3
)
Changes in other operating assets and liabilities:
 
 
 
 
 
Trade receivables and other assets
19

 
5

 
6

Inventories
1

 
(1
)
 
6

Accrued property, income and other taxes
(13
)
 
(35
)
 
(26
)
Accounts payable and other liabilities
(6
)
 
1

 
(23
)
Net cash flows from operating activities
701

 
619

 
665

 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
Capital expenditures
(409
)
 
(298
)
 
(270
)
Acquisitions

 

 
(77
)
Proceeds from sale of assets
2

 
1

 
4

Net cash flows from investing activities
(407
)
 
(297
)
 
(343
)
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
Proceeds from long-term debt
495

 
573

 
91

Repayments of long-term debt
(500
)
 
(824
)
 
(75
)
Dividends paid
(371
)
 

 
(548
)
Other, net
(14
)
 
(16
)
 
(14
)
Net cash flows from financing activities
(390
)
 
(267
)
 
(546
)
 
 
 
 
 
 
Net change in cash and cash equivalents and restricted cash and cash equivalents
(96
)
 
55

 
(224
)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period
121

 
66

 
290

Cash and cash equivalents and restricted cash and cash equivalents at end of period
$
25

 
$
121

 
$
66

 
 
 
 
 
 
The accompanying notes are an integral part of these consolidated financial statements.


323


NEVADA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)    Organization and Operations

Nevada Power Company, together with its subsidiaries ("Nevada Power"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company ("Sierra Pacific") and certain other subsidiaries. Nevada Power is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers primarily in Las Vegas, North Las Vegas, Henderson and adjoining areas. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

(2)    Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

The Consolidated Financial Statements include the accounts of Nevada Power and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2019, 2018 and 2017.

Use of Estimates in Preparation of Financial Statements

The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.

Accounting for the Effects of Certain Types of Regulation

Nevada Power prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Nevada Power defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.

Nevada Power continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Nevada Power's ability to recover its costs. Nevada Power believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss).

Fair Value Measurements

As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.

324



Cash Equivalents and Restricted Cash and Investments

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets.

Allowance for Doubtful Accounts

Accounts receivable are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts. The allowance for doubtful accounts is based on Nevada Power's assessment of the collectability of amounts owed to Nevada Power by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. Nevada Power also has the ability to assess deposits on customers who have delayed payments or who are deemed to be a credit risk. As of December 31, 2019 and 2018, the allowance for doubtful accounts totaled $15 million and $16 million, respectively, and is included in trade receivables, net on the Consolidated Balance Sheets.

Derivatives

Nevada Power employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.

Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked‑to‑market and settled amounts are recognized as cost of fuel, energy and capacity on the Consolidated Statements of Operations.

For Nevada Power's derivative contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.

Inventories

Inventories consist mainly of materials and supplies totaling $62 million and $56 million as of December 31, 2019 and 2018, and fuel, which includes coal stock, stored natural gas and fuel oil, totaling $- million and $5 million as of December 31, 2019 and 2018, respectively. The cost is determined using the average cost method. Materials are charged to inventory when purchased and are expensed or capitalized to construction work in process, as appropriate, when used. Fuel costs are recovered from retail customers through the base tariff energy rates and deferred energy accounting adjustment charges approved by the Public Utilities Commission of Nevada ("PUCN").

Property, Plant and Equipment, Net

General

Additions to property, plant and equipment are recorded at cost. Nevada Power capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. The cost of repairs and minor replacements are charged to expense when incurred with the exception of costs for generation plant maintenance under certain long-term service agreements. Costs under these agreements are expensed straight-line over the term of the agreements as approved by the PUCN.


325


Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by Nevada Power's various regulatory authorities. Depreciation studies are completed by Nevada Power to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as a non-current regulatory liability on the Consolidated Balance Sheets. As actual removal costs are incurred, the associated liability is reduced.

Generally when Nevada Power retires or sells a component of regulated property, plant and equipment depreciated using the composite method, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings with the exception of material gains or losses on regulated property, plant and equipment depreciated on a straight-line basis, which is then recorded to a regulatory asset or liability.

Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, are capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. The rate applied to construction costs is the lower of the PUCN allowed rate of return and rates computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, Nevada Power is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets. Nevada Power's AFUDC rate used during 2019 and 2018 was 7.83% and 7.95%, respectively.

Asset Retirement Obligations

Nevada Power recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. Nevada Power's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability on the Consolidated Balance Sheets. The costs are not recovered in rates until the work has been completed.

Impairment of Long-Lived Assets

Nevada Power evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2019, the impacts of regulation are considered when evaluating the carrying value of regulated assets.


326


Leases

Lessee

Nevada Power has non-cancelable operating leases primarily for land, generating facilities, vehicles and office equipment and finance leases consisting primarily of transmission assets, generating facilities, office space and vehicles. These leases generally require Nevada Power to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Nevada Power does not include options in its lease calculations unless there is a triggering event indicating Nevada Power is reasonably certain to exercise the option. Nevada Power's accounting policy is to not recognize lease obligations and corresponding right-of-use assets for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with ASC Topic 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.

Nevada Power's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.

Nevada Power's operating right-of-use assets are recorded in other assets and the operating lease liabilities are recorded in current and long-term other liabilities accordingly. The right-of-use assets and lease liabilities for finance leases as of December 31, 2018 have been reclassified from property, plant and equipment, net and current portion of long-term and long-term debt, respectively, to conform to the current period presentation.

Income Taxes

Berkshire Hathaway includes Nevada Power in its consolidated United States federal income tax return. Consistent with established regulatory practice, Nevada Power's provision for income taxes has been computed on a separate return basis.

Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimated income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain property‑related basis differences and other various differences that Nevada Power deems probable to be passed on to its customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties.

In determining Nevada Power's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by Nevada Power's various regulatory commissions. Nevada Power's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Nevada Power recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Nevada Power's federal, state and local income tax examinations is uncertain, Nevada Power believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on Nevada Power's consolidated financial results. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.


327


Revenue Recognition

Nevada Power uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which Nevada Power expects to be entitled in exchange for those goods or services. Nevada Power records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.

Substantially all of Nevada Power's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission and distribution and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of amounts not considered Customer Revenue within Accounting Standards Codification ("ASC") 606, "Revenue from Contracts with Customers" and revenue recognized in accordance with ASC 842, "Leases."

Revenue recognized is equal to what Nevada Power has the right to invoice as it corresponds directly with the value to the customer of Nevada Power's performance to date and includes billed and unbilled amounts. As of December 31, 2019 and 2018, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $109 million and $106 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued. In addition, Nevada Power has recognized contract assets of $9 million and $- million as of December 31, 2019 and 2018, respectively, due to Nevada Power's performance on certain contracts.

Unamortized Debt Premiums, Discounts and Issuance Costs

Premiums, discounts and financing costs incurred for the issuance of long-term debt are amortized over the term of the related financing on a straight-line basis.

Segment Information

Nevada Power currently has one segment, which includes its regulated electric utility operations.

New Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, which creates FASB Accounting Standards Codification ("ASC") Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize on the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. Nevada Power has elected to utilize various practical expedients available to adopt ASU No. 2016-02, including (1) the package of three not requiring a reassessment of (i) whether any expired or existing contracts are or contain leases; (ii) the lease classification for any expired or existing leases; and (iii) initial direct costs for any existing leases; (2) using hindsight in determining the lease term; and (3) not requiring a reassessment of whether existing or expired land easements that were not previously accounted for as leases under ASC Topic 840 are or contain a lease under ASC Topic 842. Nevada Power adopted this guidance for all applicable contracts in-effect as of January 1, 2019 under a modified retrospective method and the adoption did not have a cumulative effect impact at the date of initial adoption.


328


(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following as of December 31 (in millions):
 
Depreciable Life
 
2019
 
2018
Utility plant:
 
 
 
 
 
Generation
30 - 55 years
 
$
3,541

 
$
3,720

Distribution
20 - 65 years
 
3,567

 
3,411

Transmission
45 - 70 years
 
1,444

 
1,439

General and intangible plant
5 - 65 years
 
741

 
716

Utility plant
 
 
9,293

 
9,286

Accumulated depreciation and amortization
 
 
(2,951
)
 
(2,966
)
Utility plant, net
 
 
6,342

 
6,320

Other non-regulated, net of accumulated depreciation and amortization
45 years
 
1

 
1

Plant, net
 
 
6,343

 
6,321

Construction work-in-progress
 
 
195

 
97

Property, plant and equipment, net
 
 
$
6,538

 
$
6,418


Almost all of Nevada Power's plant is subject to the ratemaking jurisdiction of the PUCN and the FERC. Nevada Power's depreciation and amortization expense, as authorized by the PUCN, stated as a percentage of the depreciable property balances as of December 31, 2019, 2018 and 2017 was 3.3%, 3.2%, and 3.2%, respectively. Nevada Power is required to file a utility plant depreciation study every six years as a companion filing with the triennial general rate review filings.

Construction work-in-progress is related to the construction of regulated assets.

In January 2018, Nevada Power revised its electric depreciation rates based on the results of a new depreciation study performed in 2017, the most significant impact of which was shorter estimated useful lives at the Navajo Generating Station and longer average service lives for various other utility plant groups. The net effect of these changes approximately increased depreciation and amortization expense by $7 million annually, based on depreciable plant balances at the time of the change.

(4)    Jointly Owned Utility Facilities

Under joint facility ownership agreements, Nevada Power, as tenants in common, has undivided interests in jointly owned generation and transmission facilities. Nevada Power accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include Nevada Power's share of the expenses of these facilities.

The amounts shown in the table below represent Nevada Power's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2019 (dollars in millions):

 
Nevada
 
 
 
 
 
Construction
 
Power's
 
Utility
 
Accumulated
 
Work-in-
 
Share
 
Plant
 
Depreciation
 
Progress
 
 
 
 
 
 
 
 
Navajo Generating Station(1)
11
%
 
$
13

 
$
2

 
$

ON Line Transmission Line
24

 
151

 
23

 

Other transmission facilities
Various

 
66

 
27

 

Total
 
 
$
230

 
$
52

 
$


(1)
Represents Nevada Power's proportionate share of capitalized asset retirement costs to retire the Navajo Generating Station, which was shut down in November 2019.


329


(5)
Leases

The following table summarizes Nevada Power's leases recorded on the Consolidated Balance Sheet (in millions):
 
As of
 
December 31, 2019
Right-of-use assets:
 
Operating leases
$
13

Finance leases
441

Total right-of-use assets
$
454

 
 
Lease liabilities:
 
Operating leases
$
17

Finance leases
454

Total lease liabilities
$
471


The following table summarizes Nevada Power's lease costs (in millions):
 
Year Ended
 
December 31, 2019
 
 
Variable
$
434

Operating
3

Finance:
 
Amortization
13

Interest
37

Total lease costs
$
487

 
 
Weighted-average remaining lease term (years):
 
Operating leases
7.5

Finance leases
30.6

 
 
Weighted-average discount rate:
 
Operating leases
4.5
%
Finance leases
8.7
%

The following table summarizes Nevada Power's supplemental cash flow information relating to leases (in millions):
 
Year Ended
 
December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
 
Operating cash flows from operating leases
$
(3
)
Operating cash flows from finance leases
(37
)
Financing cash flows from finance leases
(14
)
Right-of-use assets obtained in exchange for lease liabilities:
 
Finance leases
$
9



330


Nevada Power has the following remaining lease commitments as of (in millions):
 
December 31, 2019
 
Operating
 
Finance
 
Total
2020
$
3

 
$
60

 
$
63

2021
3

 
64

 
67

2022
3

 
62

 
65

2023
2

 
51

 
53

2024
2

 
52

 
54

Thereafter
7

 
664

 
671

Total undiscounted lease payments
20

 
953

 
973

Less - amounts representing interest
(3
)
 
(499
)
 
(502
)
Lease liabilities
$
17

 
$
454

 
$
471

 
December 31, 2018(1)
 
Operating
 
Capital
 
Total
2019
$
3

 
$
59

 
$
62

2020
3

 
59

 
62

2021
3

 
61

 
64

2022
3

 
60

 
63

2023
2

 
50

 
52

Thereafter
10

 
709

 
719

Total undiscounted lease payments
$
24

 
$
998

 
$
1,022


(1)     Amounts included for comparability and accounted for in accordance with ASC Topic 840, "Leases".

Operating and Finance Lease Obligations

Nevada Power's lease obligation primarily consists of a transmission line One Nevada Transmission Line ("ON Line"), which was placed in-service on December 31, 2013. Nevada Power and Sierra Pacific, collectively the ("Nevada Utilities"), entered into a long-term transmission use agreement, in which the Nevada Utilities have a 25% interest and Great Basin Transmission South, LLC has a 75% interest. The Nevada Utilities' share of the long-term transmission use agreement and ownership interest is split at 95% for Nevada Power and 5% for Sierra Pacific. In December 2019, the PUCN ordered the Nevada Utilities to complete the procedures changing the ownership split to 75% for Nevada Power and 25% for Sierra Pacific, effective January 1, 2020. The term of the lease is 41 years with the agreement ending December 31, 2054. Total ON Line finance lease obligations of $385 million and $395 million were included on the Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively. See Note 2 for further discussion of Nevada Power's other lease obligations.


331


(6)    Regulatory Matters

Regulatory Assets

Regulatory assets represent costs that are expected to be recovered in future rates. Nevada Power's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
 
Weighted
 
 
 
 
 
Average
 
 
 
 
 
Remaining Life
 
2019
 
2018
 
 
 
 
 
 
Decommissioning costs(2)
3 years
 
$
241

 
$
222

Deferred operating costs
9 years
 
136

 
152

Merger costs from 1999 merger
25 years
 
120

 
125

Employee benefit plans(1)
8 years
 
87

 
105

Asset retirement obligations
6 years
 
67

 
68

Legacy meters
13 years
 
49

 
53

ON Line deferrals
34 years
 
45

 
46

Abandoned projects
1 year
 
12

 
46

Deferred energy costs
1 year
 

 
47

Other
Various
 
44

 
53

Total regulatory assets
 
 
$
801

 
$
917

 
 
 
 
 
 
Reflected as:
 
 
 
 
 
Current assets
 
 
$
1

 
$
39

Noncurrent assets
 
 
800

 
878

Total regulatory assets
 
 
$
801

 
$
917


(1)
Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.

(2)
Amount includes regulatory assets with an indeterminate life of $104 million and $81 million as of December 31, 2019 and 2018, respectively.

Nevada Power had regulatory assets not earning a return on investment of $303 million and $334 million as of December 31, 2019 and 2018, respectively. The regulatory assets not earning a return on investment primarily consist of merger costs from the 1999 merger, asset retirement obligations, deferred operating costs, a portion of the employee benefit plans, losses on reacquired debt and deferred energy costs.


332


Regulatory Liabilities

Regulatory liabilities represent amounts that are expected to be returned to customers in future periods. Nevada Power's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
 
Weighted
 
 
 
 
 
Average
 
 
 
 
 
Remaining Life
 
2019
 
2018
 
 
 
 
 
 
Deferred income taxes(1)
Various
 
$
681

 
$
677

Cost of removal(2)
33 years
 
332

 
320

Impact fees(3)
2 years
 
72

 
86

Other
Various
 
171

 
103

Total regulatory liabilities
 
 
$
1,256

 
$
1,186

 
 
 
 
 
 
Reflected as:
 
 
 
 
 
Current liabilities
 
 
$
93

 
$
49

Noncurrent liabilities
 
 
1,163

 
1,137

Total regulatory liabilities
 
 
$
1,256

 
$
1,186


(1)
Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to accelerated tax depreciation and certain property-related basis differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.

(2)
Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices.

(3)
Amounts reduce rate base or otherwise accrue a carrying cost.

Deferred Energy

Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets and would be included in the table above as deferred energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.

2017 Tax Reform

In February 2018, Nevada Power made filings with the PUCN proposing a tax rate reduction rider for the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. In March 2018, the PUCN issued an order approving the rate reduction proposed by Nevada Power. The new rates were effective April 1, 2018. The order extended the procedural schedule to allow parties additional discovery relevant to 2017 Tax Reform and a hearing was held in July 2018. In September 2018, the PUCN issued an order directing Nevada Power to record the amortization of any excess protected accumulated deferred income tax arising from the 2017 Tax Reform as a regulatory liability effective January 1, 2018. Subsequently, Nevada Power filed a petition for reconsideration relating to the amortization of protected excess accumulated deferred income tax balances resulting from the 2017 Tax Reform. In November 2018, the PUCN issued an order granting reconsideration and reaffirming the September 2018 order. In December 2018, Nevada Power filed a petition for judicial review. In January 2019, intervening parties filed statements of intent to participate in the petition for judicial review. Nevada Power has filed opening briefs and the intervening parties have filed answering briefs. The hearing occurred in January 2020 and a ruling is expected in the first half of 2020.


333


Energy Efficiency Program Rates ("EEPR") and Energy Efficiency Implementation Rates ("EEIR")

EEPR was established to allow Nevada Power to recover the costs of implementing energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by Nevada Power and approved by the PUCN in integrated resource plan proceedings. When Nevada Power's regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, it is obligated to refund energy efficiency implementation revenue previously collected for that year. In March 2019, Nevada Power filed an application to reset the EEIR and EEPR and to refund the EEIR revenue received in 2018, including carrying charges. In August 2019, the PUCN issued an order accepting a stipulation requiring Nevada Power to refund the 2018 revenue and reset the rates as filed effective October 1, 2019. The EEIR liability for Nevada Power is $8 million and $9 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively.

Emissions Reduction and Capacity Retirement Plan ("ERCR Plan")

In November 2019, the Navajo coal-fueled generating facility was retired. Nevada Power owned 11% of the facility and its net owned capacity was 255 MWs. The decommissioning was approved by the PUCN in May 2014 as a part of the filed ERCR Plan. The remaining net book value of $12 million was moved from property, plant and equipment, net to noncurrent regulatory assets on the Consolidated Balance Sheet in November 2019, in compliance with the ERCR Plan. Refer to Note 13 for additional information on the ERCR Plan.

(7)    Credit Facility

Nevada Power has a $400 million secured credit facility expiring in June 2022. The credit facility, which is for general corporate purposes and provide for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at Nevada Power's option, plus a spread that varies based on Nevada Power's credit ratings for its senior secured long‑term debt securities. As of December 31, 2019 and 2018, Nevada Power had no borrowings outstanding under the credit facility. Amounts due under Nevada Power's credit facility are collateralized by Nevada Power's general and refunding mortgage bonds. The credit facility requires Nevada Power's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.


334


(8)    Long-Term Debt

Nevada Power's long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
 
Par Value
 
2019
 
2018
General and refunding mortgage securities:
 
 
 
 
 
7.125% Series V, due 2019
$

 
$

 
$
500

2.750%, Series BB, due 2020
575

 
575

 
574

3.700%, Series CC, due 2029
500

 
496

 

6.650% Series N, due 2036
367

 
358

 
358

6.750% Series R, due 2037
349

 
346

 
346

5.375% Series X, due 2040
250

 
248

 
247

5.450% Series Y, due 2041
250

 
237

 
236

Tax-exempt refunding revenue bond obligations:
 
 
 
 
 
Fixed-rate series:
 
 
 
 
 
1.800% Pollution Control Bonds Series 2017A, due 2032(1)
40

 
39

 
40

1.600% Pollution Control Bonds Series 2017, due 2036(1)
40

 
39

 
39

1.600% Pollution Control Bonds Series 2017B, due 2039(1)
13

 
13

 
13

Total long-term debt
$
2,384

 
$
2,351

 
$
2,353

 
 
 
 
 
 
Reflected as:
 
 
 
 
 
Current portion of long-term debt
 
 
$
575

 
$
500

Long-term debt
 
 
1,776

 
1,853

Total long-term debt
 
 
$
2,351

 
$
2,353


(1)
Subject to mandatory purchase by Nevada Power in May 2020 at which date the interest rate may be adjusted from time to time.

Annual Payment on Long-Term Debt

The annual repayments of long-term debt for the years beginning January 1, 2020 and thereafter, are as follows (in millions):
2020
$
575

2025 and thereafter
1,809

Total
2,384

Unamortized premium, discount and debt issuance cost
(33
)
Total
$
2,351


In January 2020, Nevada Power issued $425 million of its 2.400% General and Refunding Mortgage Notes, Series DD, due May 2030 and issued $300 million of its 3.125% General and Refunding Mortgage Notes, Series EE, due August 2050. Nevada Power intends to use the net proceeds from the sale of the Notes to repay $575 million aggregate principal amount of its 2.750% General and Refunding Mortgage Notes, Series BB, maturing in April 2020 and for general corporate purposes.

In January 2020, Nevada Power issued a 30-day notice of early redemption to repay $575 million of its 2.750% General and Refunding Mortgage Notes, Series BB.

The issuance of General and Refunding Mortgage Securities by Nevada Power is subject to PUCN approval and is limited by available property and other provisions of the mortgage indentures. As of December 31, 2019, approximately $8.7 billion (based on original cost) of Nevada Power's property was subject to the liens of the mortgages.



335


(9)
Income Taxes

Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
 
2019
 
2018
 
2017
 
 
 
 
 
 
Current – Federal
$
105

 
$
84

 
$
62

Deferred – Federal
(31
)
 
(13
)
 
95

Uncertain tax positions

 
2

 

Investment tax credits
(1
)
 
(1
)
 
(1
)
Total income tax expense
$
73

 
$
72

 
$
156


A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Federal statutory income tax rate
21
%
 
21
%
 
35
%
Non-deductible expenses

 
3

 

Effect of ratemaking

 

 
1

Effect of tax rate change

 

 
1

Other
1

 

 
1

Effective income tax rate
22
%
 
24
%
 
38
%

The net deferred income tax liability consists of the following as of December 31 (in millions):
 
2019
 
2018
Deferred income tax assets:
 
 
 
Regulatory liabilities
$
211

 
$
209

Operating and finance leases
99

 
97

Employee benefits
14

 
15

Customer advances
19

 
18

Other
9

 
9

Total deferred income tax assets
352

 
348

 
 
 
 
Deferred income tax liabilities:
 
 
 
Property related items
(797
)
 
(799
)
Regulatory assets
(166
)
 
(196
)
Operating and finance leases
(95
)
 
(94
)
Other
(8
)
 
(8
)
Total deferred income tax liabilities
(1,066
)
 
(1,097
)
Net deferred income tax liability
$
(714
)
 
$
(749
)

The United States Internal Revenue Service has closed its examination of NV Energy’s consolidated income tax returns through December 31, 2008, and the statute of limitations has expired for NV Energy’s consolidated income tax returns through the short year ended December 19, 2013. The statute of limitations expiring may not preclude the Internal Revenue Service from adjusting the federal net operating loss carryforward utilized in a year for which the examination is not closed.


336


(10)    Employee Benefit Plans

Nevada Power is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Nevada Power did not make any contributions to the Qualified Pension Plan for the year ended December 31, 2019 and contributed $19 million and $1 million to the Qualified Pension Plan for the years ended December 31, 2018 and 2017, respectively. Nevada Power contributed $1 million to the Non-Qualified Pension Plans for the years ended December 31, 2019, 2018 and 2017. Nevada Power did not make any contributions to the Other Postretirement Plans for the years ended December 31, 2019, 2018 and 2017. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.

Amounts payable to NV Energy are included on the Consolidated Balance Sheets and consist of the following as of December 31 (in millions):
 
2019
 
2018
Qualified Pension Plan -
 
 
 
Other long-term liabilities
$
18

 
$
26

 
 
 
 
Non-Qualified Pension Plans:
 
 
 
Other current liabilities
1

 
1

Other long-term liabilities
9

 
9

 
 
 
 
Other Postretirement Plans -
 
 
 
Other long-term liabilities
2

 
1


(11)    Asset Retirement Obligations

Nevada Power estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.

Nevada Power does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $332 million and $320 million as of December 31, 2019 and 2018, respectively.

The following table presents Nevada Power's ARO liabilities by asset type as of December 31 (in millions):
 
2019
 
2018
 
 
 
 
Waste water remediation
$
37

 
$
37

Evaporative ponds and dry ash landfills
12

 
12

Asbestos

 
5

Solar
2

 
2

Other
23

 
27

Total asset retirement obligations
$
74

 
$
83


The following table reconciles the beginning and ending balances of Nevada Power's ARO liabilities for the years ended December 31 (in millions):
 
2019
 
2018
 
 
 
 
Beginning balance
$
83

 
$
80

Change in estimated costs
6

 
11

Retirements
(19
)
 
(11
)
Accretion
4

 
3

Ending balance
$
74

 
$
83

 
 
 
 
Reflected as:
 
 
 
Other current liabilities
$
14

 
$
13

Other long-term liabilities
60

 
70

 
$
74

 
$
83


In 2008, Nevada Power signed an administrative order of consent as owner and operator of Reid Gardner Generating Station Unit Nos. 1, 2 and 3 and as co-owner and operating agent of Unit No. 4. Based on the administrative order of consent, Nevada Power recorded estimated AROs and capital remediation costs. However, actual costs of work under the administrative order of consent may vary significantly once the scope of work is defined and additional site characterization has been completed. In connection with the termination of the co-ownership arrangement, effective October 22, 2013, between Nevada Power and California Department of Water Resources ("CDWR") for the Reid Gardner Generating Station Unit No. 4, Nevada Power and CDWR entered into a cost-sharing agreement that sets forth how the parties will jointly share in costs associated with all investigation, characterization and, if necessary, remedial activities as required under the administrative order of consent.

Certain of Nevada Power's decommissioning and reclamation obligations relate to jointly-owned facilities, and as such, Nevada Power is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. Management has identified legal obligations to retire generation plant assets specified in land leases for Nevada Power's jointly-owned Navajo Generating Station, retired in November 2019, and the Higgins Generating Station. Provisions of the lease require the lessees to remove the facilities upon request of the lessors at the expiration of the leases. Nevada Power's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities in other long-term liabilities on the Consolidated Balance Sheets.

(12)
Fair Value Measurements

The carrying value of Nevada Power's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Nevada Power has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Nevada Power has the ability to access at the measurement date.
Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
Level 3 - Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including its own data.


337


The following table presents Nevada Power's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
 
Input Levels for Fair Value Measurements
 
 
 
Level 1
 
Level 2
 
Level 3
 
Total
As of December 31, 2019:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity derivatives
$

 
$

 
$

 
$

Money market mutual funds(1)
10

 

 

 
10

Investment funds
2

 

 

 
2

 
$
12

 
$

 
$

 
$
12

 
 
 
 
 
 
 
 
Liabilities - commodity derivatives
$

 
$

 
$
(8
)
 
$
(8
)
 
 
 
 
 
 
 
 
As of December 31, 2018:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity derivatives
$

 
$

 
$
7

 
$
7

Money market mutual funds(1)
104

 

 

 
104

Investment funds
1

 

 

 
1

 
$
105

 
$

 
$
7

 
$
112

 
 
 
 
 
 
 
 
Liabilities - commodity derivatives
$

 
$

 
$
(4
)
 
$
(4
)

(1)
Amounts are included in cash and cash equivalents on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of December 31, 2019, had an immaterial impact to the fair value of its derivative contracts. As such, Nevada Power considers its derivative contracts to be valued using Level 3 inputs.

Nevada Power's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.


338


The following table reconciles the beginning and ending balances of Nevada Power's net commodity derivative assets or liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions):
 
 
2019
 
2018
 
2017
Beginning balance
 
$
3

 
$
(3
)
 
$
(14
)
Changes in fair value recognized in regulatory assets or liabilities
 
(21
)
 
4

 
(3
)
Settlements
 
10

 
2

 
14

Ending balance
 
$
(8
)
 
$
3

 
$
(3
)

Nevada Power's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Nevada Power's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Nevada Power's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Nevada Power's long-term debt as of December 31 (in millions):
 
2019
 
2018
 
Carrying
 
Fair
 
Carrying
 
Fair
 
Value
 
Value
 
Value
 
Value
 
 
 
 
 
 
 
 
Long-term debt
$
2,351

 
$
2,848

 
$
2,353

 
$
2,651


(13)
Commitments and Contingencies

Environmental Laws and Regulations

Nevada Power is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.

Senate Bill 123

In June 2013, the Nevada State Legislature passed Senate Bill 123 ("SB 123"), which included the retirement of coal plants and replacing the capacity with renewable facilities and other generating facilities. In May 2014, Nevada Power filed its ERCR Plan in compliance with SB 123. In July 2015, Nevada Power filed an amendment to its ERCR Plan with the PUCN which was approved in September 2015. In June 2015, the Nevada State Legislature passed Assembly Bill No. 498, which modified the capacity replacement components of SB 123.

In compliance with Senate Bill No. 123, Nevada Power retired 255 MWs of coal-fueled generation in 2019 in addition to the 557 MWs of coal-fueled generation retired in 2017.Consistent with the Emissions Reduction and Capacity Replacement Plan ("ERCR Plan"), between 2014 and 2016, Nevada Power acquired 536 MWs of natural gas generating resources, executed long-term power purchase agreements for 200 MWs of nameplate renewable energy capacity and constructed a 15-MW solar photovoltaic facility. Nevada Power has the option to acquire 35 MWs of nameplate renewable energy capacity in the future under the ERCR Plan, subject to PUCN approval.

Legal Matters

Nevada Power is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Nevada Power does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. Nevada Power is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts.


339


Commitments

Nevada Power has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2019 are as follows (in millions):
 
2020
 
2021
 
2022
 
2023
 
2024
 
2025 and Thereafter
 
Total
Contract type:
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel, capacity and transmission contract commitments
$
539

 
$
390

 
$
319

 
$
321

 
$
324

 
$
3,432

 
$
5,325

Fuel and capacity contract commitments (not commercially operable)
1

 
6

 
41

 
92

 
157

 
4,677

 
4,974

Construction commitments
23

 

 

 

 

 

 
23

Easements
4

 
4

 
5

 
5

 
3

 
43

 
64

Maintenance, service and other contracts
51

 
48

 
43

 
34

 
25

 
18

 
219

Total commitments
$
618

 
$
448

 
$
408

 
$
452

 
$
509

 
$
8,170

 
$
10,605


Fuel and Capacity Contract Commitments

Purchased Power

Nevada Power has several contracts for long-term purchase of electric energy which have been approved by the PUCN. The expiration of these contracts range from 2026 to 2067. Purchased power includes estimated payments for contracts which meet the definition of a lease and payments are based on the amount of energy expected to be generated. See Note 5 for further discussion of Nevada Power's lease commitments.

Natural Gas

Nevada Power's gas transportation contracts expire from 2022 to 2032 and the gas supply contracts expires from 2020 to 2021.

Fuel and Capacity Contract Commitments - Not Commercially Operable

Nevada Power has several contracts for long-term purchase of electric energy in which the facility remains under development. Amounts represent the estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver power.

Construction Commitments

Nevada Power's construction commitments included in the table above relate to firm commitments and include costs associated with certain generating plant projects.

Easements

Nevada Power has non-cancelable easements for land. Operations and maintenance expense on non-cancelable easements totaled $7 million, $4 million and $4 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Maintenance, Service and Other Contracts

Nevada Power has long-term service agreements for the performance of maintenance on generation units. Obligation amounts are based on estimated usage. The estimated expiration of these service agreements range from 2020 to 2027.

(14)    Revenues from Contracts with Customers

The following table summarizes Nevada Power's revenue by customer class for the years ended December 31 (in millions):
 
2019
 
2018
Customer Revenue:
 
 
 
Retail:
 
 
 
Residential
$
1,141

 
$
1,195

Commercial
441

 
433

Industrial
433

 
425

Other
20

 
24

Total fully bundled
2,035

 
2,077

Distribution only service
31

 
30

Total retail
2,066

 
2,107

Wholesale, transmission and other
57

 
53

Total Customer Revenue
2,123

 
2,160

Other revenue
25

 
24

Total revenue
$
2,148

 
$
2,184


(15)    Supplemental Cash Flow Disclosures

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 2019 and December 31, 2018, consist of funds restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2019 and December 31, 2018, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
 
As of
 
December 31,

December 31,
 
2019

2018
Cash and cash equivalents
$
15

 
$
111

Restricted cash and cash equivalents included in other current assets
10

 
10

Total cash and cash equivalents and restricted cash and cash equivalents
$
25

 
$
121


The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
 
2019
 
2018
 
2017
 
 
 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
 
 
Interest paid, net of amounts capitalized
$
126

 
$
166

 
$
167

Income taxes paid
$
113

 
$
117

 
$
89

 
 
 
 
 
 
Supplemental disclosure of non-cash investing and financing transactions:
 
 
 
 
 
Accruals related to property, plant and equipment additions
$
49

 
$
34

 
$
18



340


(16)
Related Party Transactions

Nevada Power has an intercompany administrative services agreement with BHE and its subsidiaries. Amounts charged to Nevada Power under this agreement totaled $2 million for the years ended December 31, 2019, 2018 and 2017.

Kern River Gas Transmission Company, an indirect subsidiary of BHE, provided natural gas transportation and other services to Nevada Power of $52 million, $58 million and $66 million for the years ended December 31, 2019, 2018 and 2017. As of December 312019 and 2018, Nevada Power's Consolidated Balance Sheets included amounts due to Kern River Gas Transmission Company of $4 million.

Nevada Power provided electricity and other services to PacifiCorp, an indirect subsidiary of BHE, of $2 million, $3 million and $3 million for the years ended December 312019, 2018 and 2017, respectively. Receivables associated with these services were $- million as of December 31, 2019 and 2018. PacifiCorp provided electricity and the sale of renewable energy credits to Nevada Power of $- million for the years ended December 312019, 2018 and 2017. Payables associated with these transactions were $-million as of December 31, 2019 and 2018.

Nevada Power provided electricity to Sierra Pacific of $84 million, $91 million and $104 million for the years ended December 312019, 2018 and 2017, respectively. Receivables associated with these transactions were $5 million and $6 million as of December 31, 2019 and 2018, respectively. Nevada Power purchased electricity from Sierra Pacific of $25 million, $28 million and $21 million for the years ended December 312019, 2018 and 2017, respectively. Payables associated with these transactions were $1 million as of December 31, 2019 and 2018.

Nevada Power incurs intercompany administrative and shared facility costs with NV Energy and Sierra Pacific. These transactions are governed by an intercompany service agreement and are priced at cost. Nevada Power provided services to NV Energy of $-million, $1 million and $- million for each of the years ending December 312019, 2018 and 2017, respectively. NV Energy provided services to Nevada Power of $9 million, $7 million and $10 million for the years ending December 312019, 2018 and 2017, respectively. Nevada Power provided services to Sierra Pacific of $26 million, $28 million and $27 million for the years ended December 312019, 2018 and 2017, respectively. Sierra Pacific provided services to Nevada Power of $14 million, $15 million and $17 million for the years ended December 312019, 2018 and 2017, respectively. As of December 312019 and 2018, Nevada Power's Consolidated Balance Sheets included amounts due to NV Energy of $26 million. There were no receivables due from NV Energy as of December 312019 and 2018. As of December 312019 and 2018, Nevada Power's Consolidated Balance Sheets included receivables due from Sierra Pacific of $3 million and $5 million, respectively. There were no payables due to Sierra Pacific as of December 312019 and 2018.

Nevada Power is party to a tax-sharing agreement with NV Energy and NV Energy is part of the Berkshire Hathaway consolidated United States federal income tax return. Federal income taxes receivable from NV Energy were $7 million as of December 31, 2019 and federal income taxes payable to NV Energy were $4 million as of December 31, 2018. Nevada Power made cash payments of $113 million, $117 million and $89 million for federal income taxes for the years ended December 312019, 2018 and 2017, respectively.

Certain disbursements for accounts payable and payroll are made by NV Energy on behalf of Nevada Power and reimbursed automatically when settled by the bank. These amounts are recorded as accounts payable at the time of disbursement.


341


(17)    Unaudited Quarterly Operating Results (in millions)
 
Three-Month Periods Ended
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
2019
 
2019
 
2019
 
2019
 
 
 
 
 
 
 
 
Operating revenues
$
395

 
$
527

 
$
806

 
$
420

Operating income
45

 
123

 
244

 
67

Net income
6

 
69

 
165

 
24

 
 
 
 
 
 
 
 
 
Three-Month Periods Ended
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
2018
 
2018
 
2018
 
2018
 
 
 
 
 
 
 
 
Operating revenues
$
395

 
$
562

 
$
820

 
$
407

Operating income
40

 
122

 
247

 
37

Net income

 
64

 
164

 
(2
)


342


Sierra Pacific Power Company
Financial Section


343


Item 6.        Selected Financial Data

Information required by Item 6 is omitted pursuant to General Instruction I(2)(a) to Form 10-K.

Item 7.        Management's Discussion and Analysis of Financial Condition and Results of Operations 

The following is management's discussion and analysis of certain significant factors that have affected the financial condition and results of operations of Sierra Pacific during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Sierra Pacific's historical Financial Statements and Notes to Financial Statements in Item 8 of this Form 10‑K. Sierra Pacific's actual results in the future could differ significantly from the historical results.

Results of Operations

Overview

Net income for the year ended December 31, 2019 was $103 million, an increase of $11 million, or 12%, compared to 2018, primarily due to $18 million of lower operations and maintenance expense, mainly due to lower political activity expenses, $3 million of higher electric utility margin, mainly due to $6 million of higher transmission and wholesale revenues and $3 million of customer growth, partially offset by $6 million of lower average retail rates related to the tax rate reduction rider effective April 2018, and $3 million of higher natural gas utility margin, mainly due to higher customer volumes primarily from the impacts of weather. These increases are partially offset by $10 million of unfavorable other, net, mainly due to higher non-service pension expense, and $6 million of higher depreciation and amortization expense, primarily due to higher plant placed in service.
 
Net income for the year ended December 31, 2018 was $92 million, a decrease of $17 million, or 16%, compared to 2017, primarily due to $23 million of higher operations and maintenance expense, primarily due to increased political activity expenses and $15 million of lower electric utility margin, primarily due to lower average retail rates including rate impacts related to the tax rate reduction rider as a result of the Tax Cuts and Jobs Act (the "2017 Tax Reform"). These decreases were partially offset by lower income tax expense of $25 million, primarily from a lower federal tax rate due to the impact of the 2017 Tax Reform.

344


Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as electric operating revenue less cost of fuel and energy while natural gas utility margin is calculated as natural gas operating revenue less cost of natural gas purchased for resale, which are captions presented on the Statements of Operations.
Sierra Pacific's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in Sierra Pacific's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):

 
 
2019
 
2018
 
Change
 
2018
 
2017
 
Change
Electric utility margin:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric operating revenue
 
$
770

 
$
752

 
$
18

2
 %
 
$
752

 
$
713

 
$
39

5
 %
Cost of fuel and energy
 
337

 
322

 
15

5

 
322

 
268

 
54

20

Electric utility margin
 
433

 
430

 
3

1
 %
 
430

 
445

 
(15
)
(3
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas utility margin:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas operating revenue
 
119

 
103

 
16

16
 %
 
103

 
99

 
4

4
 %
Cost of natural gas purchased for resale
 
62

 
49

 
13

27

 
49

 
42

 
7

17

Natural gas utility margin
 
57

 
54

 
3

6
 %
 
54

 
57

 
(3
)
(5
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility margin
 
490

 
484

 
6

1
 %
 
484

 
502

 
(18
)
(4
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operations and maintenance
 
172

 
190

 
(18
)
(9
)%
 
190

 
167

 
23

14
 %
Depreciation and amortization
 
125

 
119

 
6

5

 
119

 
114

 
5

4

Property and other taxes
 
22

 
23

 
(1
)
(4
)
 
23

 
24

 
(1
)
(4
)
Operating income
 
$
171

 
$
152

 
$
19

13
 %
 
$
152

 
$
197

 
$
(45
)
(23
)%


345


Electric Utility Margin

A comparison of key operating results related to electric utility margin is as follows for the years ended December 31:
 
 
2019
 
2018
 
Change
 
2018
 
2017
 
Change
Electric utility margin (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric operating revenue
 
$
770

 
$
752

 
$
18

2
 %
 
$
752

 
$
713

 
$
39

5
 %
Cost of fuel and energy
 
337

 
322

 
15

5

 
322

 
268

 
54

20

Electric utility margin
 
$
433

 
$
430

 
$
3

1
 %
 
$
430

 
$
445

 
$
(15
)
(3
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
GWhs sold:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
2,491

 
2,483

 
8

 %
 
2,483

 
2,492

 
(9
)
 %
Commercial
 
2,973

 
2,998

 
(25
)
(1
)
 
2,998

 
2,954

 
44

1

Industrial
 
3,716

 
3,387

 
329

10

 
3,387

 
3,176

 
211

7

Other
 
16

 
16

 


 
16

 
16

 


Total fully bundled(1)
 
9,196

 
8,884

 
312

4

 
8,884

 
8,638

 
246

3

Distribution only service
 
1,629

 
1,516

 
113

7

 
1,516

 
1,394

 
122

9

Total retail
 
10,825

 
10,400

 
425

4

 
10,400

 
10,032

 
368

4

Wholesale
 
662

 
558

 
104

19

 
558

 
561

 
(3
)
(1
)
Total GWhs sold
 
11,487

 
10,958

 
529

5
 %
 
10,958

 
10,593

 
365

3
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
304

 
300

 
4

1
 %
 
300

 
295

 
5

2
 %
Commercial
 
48

 
47

 
1

2

 
47

 
47

 


Total
 
352

 
347

 
5

1
 %
 
347

 
342

 
5

1
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average per MWh:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenue - retail fully bundled(1)
 
$
76.72

 
$
78.32

 
$
(1.60
)
(2
)%
 
$
78.32

 
$
76.90

 
$
1.42

2
 %
Revenue - wholesale
 
$
48.54

 
$
50.11

 
$
(1.57
)
(3
)%
 
$
50.11

 
$
50.29

 
$
(0.18
)
 %
Cost of energy(2)(3)
 
$
31.81

 
$
32.96

 
$
(1.15
)
(3
)%
 
$
32.96

 
$
27.35

 
$
5.61

21
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Heating degree days
 
4,728

 
4,450

 
278

6
 %
 
4,450

 
4,523

 
(73
)
(2
)%
Cooling degree days
 
1,107

 
1,290

 
(183
)
(14
)%
 
1,290

 
1,401

 
(111
)
(8
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sources of energy (GWhs)(3)(4):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas
 
4,891

 
4,681

 
210

4
 %
 
4,681

 
4,280

 
401

9
 %
Coal
 
1,205

 
834

 
371

44

 
834

 
457

 
377

82

Renewables(5)
 
37

 
35

 
2

6

 
35

 
36

 
(1
)

Total energy generated
 
6,133

 
5,550

 
583

11

 
5,550

 
4,773

 
777

16

Energy purchased
 
4,466

 
4,229

 
237

6

 
4,229

 
5,017

 
(788
)
(16
)
Total
 
10,599

 
9,779

 
820

8
 %
 
9,779

 
9,790

 
(11
)
 %

(1)    Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2)
The average cost per MWh of energy includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.
(3)
The average cost per MWh of energy and sources of energy excludes 54 GWhs of coal and 183 GWhs of natural gas generated energy that is purchased at cost by related parties for the year ended December 31, 2018. There were no GWhs of coal or natural gas excluded for the years ended December 31, 2019 and 2017.
(4)
GWh amounts are net of energy used by the related generating facilities.
(5)
Includes the Fort Churchill Solar Array which is under lease by Sierra Pacific.

346



Natural Gas Utility Margin

A comparison of key operating results related to natural gas utility margin is as follows for the years ended December 31:
 
 
2019
 
2018
 
Change
 
2018
 
2017
 
Change
Natural gas utility margin (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas operating revenue
 
$
119

 
$
103

 
$
16

16
%
 
$
103

 
$
99

 
$
4

4
 %
Natural gas purchased for resale
 
62

 
49

 
13

27

 
49

 
42

 
7

17

Natural gas utility margin
 
$
57

 
$
54

 
$
3

6
%
 
$
54

 
$
57

 
$
(3
)
(5
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas sold (000's Dths):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
11,311

 
10,102

 
1,209

12
%
 
10,102

 
10,291

 
(189
)
(2
)%
Commercial
 
5,783

 
5,128

 
655

13

 
5,128

 
5,153

 
(25
)

Industrial
 
1,971

 
1,927

 
44

2

 
1,927

 
1,822

 
105

6

Total retail
 
19,065

 
17,157

 
1,908

11
%
 
17,157

 
17,266

 
(109
)
(1
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands)
 
170

 
167

 
3

2
%
 
167

 
164

 
3

2
 %
Average revenue per retail Dth sold:
 
$
6.24

 
$
6.00

 
$
0.24

4
%
 
$
6.00

 
$
5.73

 
$
0.27

5
 %
Average cost of natural gas per retail Dth sold
 
$
3.25

 
$
2.86

 
$
0.39

14
%
 
$
2.86

 
$
2.43

 
$
0.43

18
 %
Heating degree days
 
4,728

 
4,450

 
278

6
%
 
4,450

 
4,523

 
(73
)
(2
)%

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

Electric utility margin increased $3 million, or 1%, for 2019 compared to 2018 primarily due to:
$6 million of higher transmission and wholesale revenues; and
$3 million of customer growth.
The increase in electric utility margin was offset by:
$6 million in lower retail rates due to the tax rate reduction rider effective April 2018.

Natural gas utility margin increased $3 million, or 6%, for 2019 compared to 2018 primarily due to higher customer volumes mainly from the impacts of weather

Operations and maintenance decreased $18 million, or 9%, for 2019 compared to 2018 primarily due to lower political activity expenses and the impacts of adopting ASC 842 of $3 million, partially offset by higher generation plant costs of $3 million.

Depreciation and amortization increased $6 million, or 5%, for 2019 compared to 2018 primarily due to higher plant placed in service of $4 million and the impacts of adopting ASC 842 of $1 million.

Other income (expense) is unfavorable $10 million, or 33%, for 2019 compared to 2018 primarily due to higher non-service pension expense of $7 million and the impacts of adopting ASC 842 of $2 million.

Income tax expense decreased $2 million, or 7%, for 2019 compared to 2018. The effective tax rate was 21% in 2019 and 25% in 2018 and decreased due to lower nondeductible expenses.

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

Electric utility margin decreased $15 million or 3% for 2018 compared to 2017 primarily due to $18 million in lower retail rates from the tax rate reduction rider as a result of 2017 Tax Reform offset by $2 million of customer growth.

Natural gas utility margin decreased $3 million, or 5%, for 2018 compared to 2017 primarily due to lower retail rates from the tax rate reduction rider as a result of 2017 Tax Reform.


347


Operations and maintenance increased $23 million, or 14%, for 2018 compared to 2017 primarily due to increased political activity expenses.
 
Depreciation and amortization increased $5 million, or 4%, for 2018 compared to 2017 primarily due to higher plant placed in service.

Other income (expense) is favorable $3 million, or 9%, for 2018 compared to 2017 primarily due to lower pension expense.

Income tax expense decreased $25 million, or 45%, for 2018 compared to 2017. The effective tax rate was 25% in 2018 and 34% in 2017. The decrease in the effective tax rate is primarily due to 2017 Tax Reform, which reduced the United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, offset by an increase in nondeductible expenses.

Liquidity and Capital Resources

As of December 31, 2019, Sierra Pacific's total net liquidity was $277 million as follows (in millions):
Cash and cash equivalents
 
$
27

Credit facilities(1)
 
250

Total net liquidity
 
$
277

Credit facilities:
 
 
Maturity dates
 
2022


(1)
Refer to Note 7 of Notes to Financial Statements in Item 8 of this Form 10-K for further discussion regarding Sierra Pacific's credit facility.
Operating Activities

Net cash flows from operating activities for the years ended December 31, 2019 and 2018 were $237 million and $275 million, respectively. The change was primarily due to higher payments for income taxes, an increase in fuel costs, higher payments for operating costs and decreased collections of customer advances, partially offset by lower contributions to the pension plan.

Net cash flows from operating activities for the years ended December 31, 2018 and 2017 were $275 million and $181 million, respectively. The change was due to a decrease in fuel costs and an increase in collections from customers from higher deferred energy rates, partially offset by higher operating costs, higher federal tax payments and higher contributions to the pension plan.

The timing of Sierra Pacific's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.

Investing Activities

Net cash flows from investing activities for the years ended December 31, 2019 and 2018 were $(247) million and $(205) million, respectively. The change was primarily due to increased capital expenditures. Refer to “Future Uses of Cash” for further discussion of capital expenditures.

Net cash flows from investing activities for the years ended December 31, 2018 and 2017 were $(205) million and $(186) million, respectively. The change was primarily due to increased capital expenditures.

Financing Activities

Net cash flows from financing activities for the years ended December 31, 2019 and 2018 were $(34) million and $(2) million, respectively. The change was due to higher payments to repurchase long-term debt and dividends paid to NV Energy, Inc. of $46 million, partially offset by higher proceeds from the re-offering of previously repurchased long-term debt.

Net cash flows from financing activities for the years ended December 31, 2018 and 2017 were $(2) million and $(47) million, respectively. The change was due to higher dividends paid to NV Energy, Inc. of $45 million in 2017.


348


Ability to Issue Debt

Sierra Pacific's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of December 31, 2019, Sierra Pacific has financing authority from the PUCN consisting of the ability to issue long-term and short-term debt securities so long as the total amount of debt outstanding (excluding borrowings under Sierra Pacific's $250 million secured credit facility) does not exceed $1.6 billion as measured at the end of each calendar quarter. Sierra Pacific's revolving credit facility contains a financial maintenance covenant which Sierra Pacific was in compliance with as of December 31, 2019. In addition, certain financing agreements contain covenants which are currently suspended as Sierra Pacific's senior secured debt is rated investment grade. However, if Sierra Pacific's senior secured debt ratings fall below investment grade by either Moody's Investor Service or Standard & Poor's, Sierra Pacific would be subject to limitations under these covenants.

Ability to Issue General and Refunding Mortgage Securities

To the extent Sierra Pacific has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, Sierra Pacific's ability to issue secured debt is limited by the amount of bondable property or retired bonds that can be used to issue debt under Sierra Pacific's indenture.

Sierra Pacific's indenture creates a lien on substantially all of Sierra Pacific's properties in Nevada. As of December 31, 2019, $4.2 billion of Sierra Pacific's assets were pledged. Sierra Pacific had the capacity to issue $1.4 billion of additional general and refunding mortgage securities as of December 31, 2019 determined on the basis of 70% of net utility property additions. Property additions include plant-in-service and specific assets in construction work-in-progress. The amount of bond capacity listed above does not include eligible property in construction work-in-progress. Sierra Pacific also has the ability to release property from the lien of Sierra Pacific's indenture on the basis of net property additions, cash or retired bonds. To the extent Sierra Pacific releases property from the lien of Sierra Pacific's indenture, it will reduce the amount of securities issuable under the indenture.

Long-Term Debt

In April 2019, Sierra Pacific purchased the following series of bonds that were held by the public: $30 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; and $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036. Sierra Pacific purchased the Series 2016C, Series 2016D and Series 2016E bonds as required by the bond indentures.

In April 2019, Sierra Pacific entered into a re-offering of the following series of bonds: $30 million of its variable-rate tax-exempt Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029; the Series 2016D bonds; the Series 2016E bonds; $75 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; and $20 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036. The Series 2016B and Series 2016G bonds were offered at a fixed rate of 1.85%. The Series 2016D, Series 2016E and Series 2016F bonds were offered at a fixed rate of 2.05%. Sierra Pacific previously purchased the Series 2016B, Series 2016F and Series 2016G bonds on their date of issuance. Sierra Pacific holds the Series 2016C bonds and the bonds could be issued at a future date if required by future regulatory proceedings. Sierra Pacific used the net proceeds of the re-offering for general corporate purposes.

In June 2019, Sierra Pacific purchased the following series of bonds that were held by the public: $59 million of its fixed-rate tax-exempt Gas Facilities Refunding Revenue Bonds, Series 2016A, due 2031 and $20 million of its fixed-rate tax-exempt Humboldt County Pollution Control Refunding Revenue Bonds, Series 2016A, due 2029. Sierra Pacific holds these bonds and the bonds could be issued at a future date if required by future regulatory proceedings.

Future Uses of Cash

Capital Expenditures

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into Sierra Pacific's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.

349



Historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ending December 31 are as follows (in millions):
 
Historical
 
Forecasted
 
2017
 
2018
 
2019
 
2020
 
2021
 
2022
 
 
 
 
 
 
 
 
 
 
 
 
Generation development
$

 
$

 
$

 
$

 
$

 
$
5

Distribution
88

 
162

 
164

 
91

 
98

 
118

Transmission system investment
12

 
5

 
13

 
18

 
18

 
35

Operating and other
86

 
34

 
68

 
70

 
60

 
29

Total
$
186

 
$
201

 
$
245

 
$
179

 
$
176

 
$
187


Sierra Pacific's forecast capital expenditures include investments that relate to operating projects that consist of routine expenditures for transmission, distribution, generation and other infrastructure needed to serve existing and expected demand.

Contractual Obligations

Sierra Pacific has contractual cash obligations that may affect its financial condition. The following table summarizes Sierra Pacific's material contractual cash obligations as of December 31, 2019 (in millions):
 
Payments Due by Periods
 
2020
 
2021 - 2022
 
2023 - 2024
 
2025 and Thereafter
 
Total
Long-term debt
$

 
$

 
$
250

 
$
887

 
$
1,137

Interest payments on long-term debt(1)
41

 
82

 
74

 
292

 
489

ON Line finance lease liability

 
1

 
2

 
17

 
20

Interest payments on ON Line finance lease liability(1)
2

 
3

 
2

 
18

 
25

Operating and finance lease liabilities
4

 
7

 
4

 
27

 
42

Interest payments on operating and finance lease liabilities(1)
2

 
4

 
4

 
11

 
21

Fuel and capacity contract commitments(1)(2)
260

 
312

 
167

 
863

 
1,602

Fuel and capacity contract commitments (not commercially operable)(1)(2)
1

 
52

 
83

 
921

 
1,057

Easements(1)
2

 
4

 
4

 
30

 
40

Asset retirement obligations

 

 

 
14

 
14

Maintenance, service and other contracts(1)
11

 
15

 
3

 
9

 
38

Total contractual cash obligations
$
323

 
$
480

 
$
593

 
$
3,089

 
$
4,485


(1)
Not reflected on the Balance Sheets.
(2)
Purchased power includes estimated payments for contracts which meet the definition of a lease and payments are based on the amount of energy expected to be generated.

Sierra Pacific has other types of commitments that arise primarily from unused lines of credit, letters of credit or relate to construction and other development costs (Liquidity and Capital Resources included within this Item 7 and Note 7) and asset retirement obligations (Note 11), which have not been included in the above table because the amount and timing of the cash payments are not certain. Refer, where applicable, to the respective referenced note in Notes to Financial Statements in Item 8 of this Form 10‑K for additional information.

Regulatory Matters

Sierra Pacific is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further discussion regarding Sierra Pacific's general regulatory framework and current regulatory matters.

Environmental Laws and Regulations

Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Sierra Pacific believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and financial results. Refer to "Liquidity and Capital Resources" for discussion of Sierra Pacific's forecasted environmental-related capital expenditures.

Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.


350


Collateral and Contingent Features

Debt of Sierra Pacific is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of Sierra Pacific's ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.

Sierra Pacific has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. Sierra Pacific's secured revolving credit facility does not require the maintenance of a minimum credit rating level in order to draw upon its availability. However, commitment fees and interest rates under the credit facility are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2019, the applicable credit ratings obtained from recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2019, Sierra Pacific would have been required to post $21 million of additional collateral. Sierra Pacific's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.

Inflation

Historically, overall inflation and changing prices in the economies where Sierra Pacific operates has not had a significant impact on Sierra Pacific's financial results. Sierra Pacific operates under a cost-of-service based rate structure administered by the PUCN and the FERC. Under this rate structure, Sierra Pacific is allowed to include prudent costs in its rates, including the impact of inflation after Sierra Pacific experiences cost increases. Fuel and purchase power costs are recovered through a balancing account, minimizing the impact of inflation related to these costs. Sierra Pacific attempts to minimize the potential impact of inflation on its operations through the use of periodic rate adjustments for fuel and energy costs, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting Sierra Pacific, refer to Note 2 of Notes to Financial Statements in Item 8 of this Form 10-K.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by Sierra Pacific's methods, judgments and assumptions used in the preparation of the Financial Statements and should be read in conjunction with Sierra Pacific's Summary of Significant Accounting Policies included in Sierra Pacific's Note 2 of Notes to Financial Statements in Item 8 of this Form 10-K.

Accounting for the Effects of Certain Types of Regulation

Sierra Pacific prepares its Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Sierra Pacific defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.


351


Sierra Pacific continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Sierra Pacific's ability to recover its costs. Sierra Pacific believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss). Total regulatory assets were $295 million and total regulatory liabilities were $538 million as of December 31, 2019. Refer to Sierra Pacific's Note 6 of Notes to Financial Statements in Item 8 of this Form 10-K for additional information regarding Sierra Pacific's regulatory assets and liabilities.

Impairment of Long-Lived Assets

Sierra Pacific evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2019, the impacts of regulation are considered when evaluating the carrying value of regulated assets.

The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what Sierra Pacific would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect Sierra Pacific's results of operations.

Income Taxes

In determining Sierra Pacific's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by Sierra Pacific's various regulatory commissions. Sierra Pacific's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Sierra Pacific recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Sierra Pacific's federal, state and local income tax examinations is uncertain, Sierra Pacific believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on Sierra Pacific's financial results. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Statements of Operations. Refer to Sierra Pacific's Note 9 of Notes to Financial Statements in Item 8 of this Form 10-K for additional information regarding Sierra Pacific's income taxes.

Revenue Recognition - Unbilled Revenue

Revenue is recognized as electricity or natural gas is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since their last billing is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $63 million as of December 31, 2019. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Estimates are reversed in the following month when actual revenue is recorded.


352


Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

Sierra Pacific's Balance Sheets include assets and liabilities with fair values that are subject to market risks. Sierra Pacific's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which Sierra Pacific transacts. The following discussion addresses the significant market risks associated with Sierra Pacific's business activities. Sierra Pacific has established guidelines for credit risk management. Refer to Note 2 of Notes to Financial Statements in Item 8 of this Form 10-K for additional information regarding Sierra Pacific's contracts accounted for as derivatives.

Commodity Price Risk

Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail customer load in its regulated service territory. Sierra Pacific's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold, and natural gas supply for retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Sierra Pacific does not engage in proprietary trading activities. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. Sierra Pacific's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates through its deferred energy mechanism, which is subject to disallowance and regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.

Interest Rate Risk

Sierra Pacific is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. Sierra Pacific manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, Sierra Pacific's fixed-rate long-term debt does not expose Sierra Pacific to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Balance Sheets, changes in fair value would impact earnings and cash flows only if Sierra Pacific were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of Sierra Pacific's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7 and 8 of Notes to Financial Statements in Item 8 of this Form 10-K for additional discussion of Sierra Pacific's short- and long-term debt.

As of December 31, 2019 and 2018, Sierra Pacific had short- and long-term variable-rate obligations totaling $- million and $80 million, respectively, that expose Sierra Pacific to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on Sierra Pacific's annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2019 and 2018.

Credit Risk

Sierra Pacific is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Sierra Pacific's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Sierra Pacific analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Sierra Pacific enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Sierra Pacific exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

As of December 31, 2019, Sierra Pacific's aggregate credit exposure from energy related transactions were not material, based on settlement and mark-to-market exposures, net of collateral.


353


Item 8.        Financial Statements and Supplementary Data

 
 
Balance Sheets
 
 
Statements of Operations
 
 
Statements of Changes in Shareholder's Equity
 
 
Statements of Cash Flows
 
 
Notes to Financial Statements


354



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholder of
Sierra Pacific Power Company


Opinion on the Financial Statements

We have audited the accompanying balance sheets of Sierra Pacific Power Company ("Sierra Pacific") as of December 31, 2019 and 2018, the related statements of operations, changes in shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Sierra Pacific as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion
These financial statements are the responsibility of Sierra Pacific's management. Our responsibility is to express an opinion on Sierra Pacific's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Sierra Pacific in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Sierra Pacific is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Sierra Pacific's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/
Deloitte & Touche LLP

Las Vegas, Nevada
February 21, 2020
We have served as Sierra Pacific's auditor since 1996.


355


SIERRA PACIFIC POWER COMPANY
BALANCE SHEETS
(Amounts in millions, except share data)

 
As of December 31,
 
2019
 
2018
ASSETS
 
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
27

 
$
71

Trade receivables, net
109

 
100

Income taxes receivable
14

 

Inventories
57

 
52

Regulatory assets
12

 
7

Other current assets
20

 
33

Total current assets
239

 
263

 
 
 
 
Property, plant and equipment, net
3,075

 
2,947

Regulatory assets
283

 
314

Other assets
74

 
45

 
 
 
 
Total assets
$
3,671

 
$
3,569

 
 
 
 
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
 
 
 
Accounts payable
$
103

 
$
116

Accrued interest
14

 
13

Accrued property, income and other taxes
12

 
14

Regulatory liabilities
49

 
18

Customer deposits
21

 
18

Other current liabilities
21

 
18

Total current liabilities
220

 
197

 
 
 
 
Long-term debt
1,135

 
1,120

Regulatory liabilities
489

 
491

Deferred income taxes
347

 
331

Other long-term liabilities
160

 
166

Total liabilities
2,351

 
2,305

 
 
 
 
Commitments and contingencies (Note 13)
 
 
 
 
 
 
 
Shareholder's equity:
 
 
 
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding

 

Additional paid-in capital
1,111

 
1,111

Retained earnings
210

 
153

Accumulated other comprehensive loss, net
(1
)
 

Total shareholder's equity
1,320

 
1,264

 
 
 
 
Total liabilities and shareholder's equity
$
3,671

 
$
3,569

 
 
 
 
The accompanying notes are an integral part of the financial statements.




356


SIERRA PACIFIC POWER COMPANY
STATEMENTS OF OPERATIONS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Operating revenue:
 
 
 
 
 
Regulated electric
$
770

 
$
752

 
$
713

Regulated natural gas
119

 
103

 
99

Total operating revenue
889

 
855

 
812

 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
Cost of fuel and energy
337

 
322

 
268

Cost of natural gas purchased for resale
62

 
49

 
42

Operations and maintenance
172

 
190

 
167

Depreciation and amortization
125

 
119

 
114

Property and other taxes
22

 
23

 
24

Total operating expenses
718

 
703

 
615

 
 
 
 
 
 
Operating income
171

 
152

 
197

 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
Interest expense
(48
)
 
(44
)
 
(43
)
Allowance for borrowed funds
1

 
1

 
2

Allowance for equity funds
3

 
4

 
3

Other, net
4

 
9

 
5

Total other income (expense)
(40
)
 
(30
)
 
(33
)
 
 
 
 
 
 
Income before income tax expense
131

 
122

 
164

Income tax expense
28

 
30

 
55

Net income
$
103

 
$
92

 
$
109

 
 
 
 
 
 
The accompanying notes are an integral part of these financial statements.


357


SIERRA PACIFIC POWER COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Amounts in millions, except shares)

 
 
 
 
 
 
 
 
Retained
 
Accumulated
 
 
 
 
 
 
 
 
Other
 
Earnings
 
Other
 
Total
 
 
Common Stock
 
Paid-in
 
(Accumulated
 
Comprehensive
 
Shareholder's
 
 
Shares
 
Amount
 
Capital
 
Deficit)
 
Loss, Net
 
Equity
Balance, December 31, 2016
 
1,000

 
$

 
$
1,111

 
$
(2
)
 
$
(1
)
 
$
1,108

Net income
 

 

 

 
109

 

 
109

Dividends declared
 

 

 

 
(45
)
 

 
(45
)
Balance, December 31, 2017
 
1,000

 

 
1,111

 
62

 
(1
)
 
1,172

Net income
 

 

 

 
92

 

 
92

Other equity transactions

 

 

 

 
(1
)
 
1

 

Balance, December 31, 2018
 
1,000

 

 
1,111

 
153

 

 
1,264

Net income
 

 

 

 
103

 

 
103

Dividends declared
 

 

 

 
(46
)
 

 
(46
)
Other equity transactions
 

 

 

 

 
(1
)
 
(1
)
Balance, December 31, 2019
 
1,000

 
$

 
$
1,111

 
$
210

 
$
(1
)
 
$
1,320

 
 
 
 
 
 
 
 
 
 
 
 
 
The accompanying notes are an integral part of these financial statements.


358


SIERRA PACIFIC POWER COMPANY
STATEMENTS OF CASH FLOWS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Cash flows from operating activities:
 
 
 
 
 
Net income
$
103

 
$
92

 
$
109

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
 
 
Loss on nonrecurring items
1

 

 

Depreciation and amortization
125

 
119

 
114

Allowance for equity funds
(3
)
 
(4
)
 
(4
)
Changes in regulatory assets and liabilities
25

 
42

 
17

Deferred income taxes and amortization of investment tax credits
9

 
7

 
55

Deferred energy
15

 
9

 
(20
)
Amortization of deferred energy
(2
)
 
(10
)
 
(47
)
Other, net
(1
)
 

 
(4
)
Changes in other operating assets and liabilities:
 
 
 
 
 
Trade receivables and other assets
(6
)
 
3

 
4

Inventories
(5
)
 
(4
)
 
(3
)
Accrued property, income and other taxes
(16
)
 
3

 
1

Accounts payable and other liabilities
(8
)
 
18

 
(41
)
Net cash flows from operating activities
237

 
275

 
181

 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
Capital expenditures
(248
)
 
(205
)
 
(186
)
Proceeds from sale of assets
1





Net cash flows from investing activities
(247
)
 
(205
)
 
(186
)
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
Proceeds from long-term debt
125

 

 

Repayments of long-term debt
(109
)
 

 

Dividends paid
(46
)
 

 
(45
)
Other, net
(4
)
 
(2
)
 
(2
)
Net cash flows from financing activities
(34
)
 
(2
)
 
(47
)
 
 
 
 
 
 
Net change in cash and cash equivalents and restricted cash and cash equivalents
(44
)
 
68

 
(52
)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period
76

 
8

 
60

Cash and cash equivalents and restricted cash and cash equivalents at end of period
$
32

 
$
76

 
$
8

 
 
 
 
 
 
The accompanying notes are an integral part of these financial statements.


359


SIERRA PACIFIC POWER COMPANY
NOTES TO FINANCIAL STATEMENTS

(1)    Organization and Operations

Sierra Pacific Power Company ("Sierra Pacific") is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company ("Nevada Power") and certain other subsidiaries. Sierra Pacific is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

(2)    Summary of Significant Accounting Policies

Basis of Presentation

The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2019, 2018 and 2017.

Use of Estimates in Preparation of Financial Statements

The preparation of the Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Financial Statements.

Accounting for the Effects of Certain Types of Regulation

Sierra Pacific prepares its Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Sierra Pacific defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.

Sierra Pacific continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Sierra Pacific's ability to recover its costs. Sierra Pacific believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss).

Fair Value Measurements

As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.


360


Cash Equivalents and Restricted Cash and Investments

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other current assets and other assets on the Balance Sheets.

Allowance for Doubtful Accounts

Accounts receivable are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts. The allowance for doubtful accounts is based on Sierra Pacific's assessment of the collectability of amounts owed to Sierra Pacific by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. Sierra Pacific also has the ability to assess deposits on customers who have delayed payments or who are deemed to be a credit risk. As of December 31, 2019 and 2018, the allowance for doubtful accounts was $2 million and is included in trade receivables, net on the Balance Sheets.

Derivatives

Sierra Pacific employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price and interest rate risk. Derivative contracts are recorded on the Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.

Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked‑to‑market and settled amounts are recognized as cost of fuel, energy and capacity or natural gas purchased for resale on the Statements of Operations.

For Sierra Pacific's derivative contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.
 
Inventories

Inventories consist mainly of materials and supplies totaling $49 million and $44 million as of December 31, 2019 and 2018, respectively, and fuel, which includes coal stock, stored natural gas and fuel oil, totaling $8 million and $8 million as of December 31, 2019 and 2018, respectively. The cost is determined using the average cost method. Materials are charged to inventory when purchased and are expensed or capitalized to construction work in process, as appropriate, when used. Fuel costs are recovered from retail customers through the base tariff energy rates and deferred energy accounting adjustment charges approved by the Public Utilities Commission of Nevada ("PUCN").

Property, Plant and Equipment, Net

General

Additions to property, plant and equipment are recorded at cost. Sierra Pacific capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. The cost of repairs and minor replacements are charged to expense when incurred with the exception of costs for generation plant maintenance under certain long-term service agreements. Costs under these agreements are expensed straight-line over the term of the agreements as approved by the PUCN.


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Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by Sierra Pacific's various regulatory authorities. Depreciation studies are completed by Sierra Pacific to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as a non-current regulatory liability on the Balance Sheets. As actual removal costs are incurred, the associated liability is reduced.

Generally when Sierra Pacific retires or sells a component of regulated property, plant and equipment depreciated using the composite method, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings with the exception of material gains or losses on regulated property, plant and equipment depreciated on a straight-line basis, which is then recorded to a regulatory asset or liability.

Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, are capitalized as a component of property, plant and equipment, with offsetting credits to the Statements of Operations. The rate applied to construction costs is the lower of the PUCN allowed rate of return and rates computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, Sierra Pacific is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets. Sierra Pacific's AFUDC rate used during 2019 and 2018 was 6.65% for electric, 5.75% and 5.74% for natural gas, respectively, and 6.55% for common facilities.

Asset Retirement Obligations

Sierra Pacific recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. Sierra Pacific's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability on the Balance Sheets. The costs are not recovered in rates until the work has been completed.

Impairment of Long-Lived Assets

Sierra Pacific evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, 2019, the impacts of regulation are considered when evaluating the carrying value of regulated assets.

Leases

Lessee

Sierra Pacific has non-cancelable operating leases primarily for transmission and delivery assets, generating facilities, vehicles and office equipment and finance leases consisting primarily of transmission assets, generating facilities and vehicles. These leases generally require Sierra Pacific to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Sierra Pacific does not include options in its lease calculations unless there is a triggering event indicating Sierra Pacific is reasonably certain to exercise the option. Sierra Pacific's accounting policy is to not recognize lease obligations and corresponding right-of-use assets for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with ASC Topic 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.

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Sierra Pacific's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.

Sierra Pacific's operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly. The right-of-use assets and lease liabilities for finance leases as of December 31, 2018 have been reclassified from property, plant and equipment, net and current portion of long-term and long-term debt, respectively, to conform to the current period presentation.

Income Taxes

Berkshire Hathaway includes Sierra Pacific in its consolidated United States federal income tax return. Consistent with established regulatory practice, Sierra Pacific's provision for income taxes has been computed on a separate return basis.

Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimated income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain property-related basis differences and other various differences that Sierra Pacific deems probable to be passed on to its customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties.

In determining Sierra Pacific's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by Sierra Pacific's various regulatory commissions. Sierra Pacific's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Sierra Pacific recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Sierra Pacific's federal, state and local income tax examinations is uncertain, Sierra Pacific believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on Sierra Pacific's financial results. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Statements of Operations.

Revenue Recognition

Sierra Pacific uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which Sierra Pacific expects to be entitled in exchange for those goods or services. Sierra Pacific records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Statements of Operations.

Substantially all of Sierra Pacific's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of revenue recognized in accordance with ASC 842, "Leases" and amounts not considered Customer Revenue within Accounting Standards Codification ("ASC") 606, "Revenue from Contracts with Customers."


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Revenue recognized is equal to what Sierra Pacific has the right to invoice as it corresponds directly with the value to the customer of Sierra Pacific's performance to date and includes billed and unbilled amounts. As of December 31, 2019 and 2018, trade receivables, net on the Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $63 million and $57 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.

Unamortized Debt Premiums, Discounts and Issuance Costs

Premiums, discounts and financing costs incurred for the issuance of long-term debt are amortized over the term of the related financing on a straight-line basis.

New Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, which creates FASB Accounting Standards Codification ("ASC") Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize on the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. Sierra Pacific has elected to utilize various practical expedients available to adopt ASU No. 2016-02, including (1) the package of three not requiring a reassessment of (i) whether any expired or existing contracts are or contain leases; (ii) the lease classification for any expired or existing leases; and (iii) initial direct costs for any existing leases; (2) using hindsight in determining the lease term; and (3) not requiring a reassessment of whether existing or expired land easements that were not previously accounted for as leases under ASC Topic 840 are or contain a lease under ASC Topic 842. Sierra Pacific adopted this guidance for all applicable contracts in-effect as of January 1, 2019 under a modified retrospective method and the adoption did not have a cumulative effect impact at the date of initial adoption.

(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following as of December 31 (in millions):
 
Depreciable Life
 
2019
 
2018
Utility plant:
 
 
 
 
 
Electric generation
25 - 60 years
 
$
1,133

 
$
1,132

Electric distribution
20 - 100 years
 
1,669

 
1,568

Electric transmission
50 - 100 years
 
840

 
812

Electric general and intangible plant
5 - 70 years
 
178

 
185

Natural gas distribution
35 - 70 years
 
417

 
403

Natural gas general and intangible plant
5 - 70 years
 
14

 
14

Common general
5 - 70 years
 
338

 
321

Utility plant
 
 
4,589

 
4,435

Accumulated depreciation and amortization
 
 
(1,629
)
 
(1,583
)
Utility plant, net
 
 
2,960

 
2,852

Other non-regulated, net of accumulated depreciation and amortization
70 years
 
2

 
5

Plant, net
 
 
2,962

 
2,857

Construction work-in-progress
 
 
113

 
90

Property, plant and equipment, net
 
 
$
3,075

 
$
2,947



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All of Sierra Pacific's plant is subject to the ratemaking jurisdiction of the PUCN and the FERC. Sierra Pacific's depreciation and amortization expense, as authorized by the PUCN, stated as a percentage of the depreciable property balances as of December 312019, 2018 and 2017 was 3.1%, 3.1% and 3.0%, respectively. Sierra Pacific is required to file a utility plant depreciation study every six years as a companion filing with the triennial general rate review filings.

Construction work-in-progress is related to the construction of regulated assets.

(4)    Jointly Owned Utility Facilities

Under joint facility ownership agreements, Sierra Pacific, as tenants in common, has undivided interests in jointly owned generation and transmission facilities. Sierra Pacific accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Statements of Operations include Sierra Pacific's share of the expenses of these facilities.

The amounts shown in the table below represent Sierra Pacific's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2019 (dollars in millions):
 
Sierra
 
 
 
 
 
Construction
 
Pacific's
 
Utility
 
Accumulated
 
Work-in-
 
Share
 
Plant
 
Depreciation
 
Progress
 
 
 
 
 
 
 
 
Valmy Generating Station
50
%
 
$
390

 
$
271

 
$

ON Line Transmission Line
1

 
8

 
1

 

Valmy Transmission
50

 
4

 
2

 

Total
 
 
$
402

 
$
274

 
$


(5)
Leases

The following table summarizes Sierra Pacific's leases recorded on the Balance Sheet (in millions):
 
As of
 
December 31, 2019
Right-of-use assets:
 
Operating leases
$
17

Finance leases
43

Total right-of-use assets
$
60

 
 
Lease liabilities:
 
Operating leases
$
17

Finance leases
45

Total lease liabilities
$
62



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The following table summarizes Sierra Pacific's lease costs (in millions):
 
Year Ended
 
December 31, 2019
 
 
Variable
$
69

Operating
1

Finance:
 
Amortization
2

Interest
2

Total lease costs
$
74

 
 
Weighted-average remaining lease term (years):
 
Operating leases
26.3

Finance leases
20.9

 
 
Weighted-average discount rate:
 
Operating leases
5.0
%
Finance leases
7.1
%

The following table summarizes Sierra Pacific's supplemental cash flow information relating to leases (in millions):
 
Year Ended
 
December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
 
Operating cash flows from operating leases
$
(3
)
Operating cash flows from finance leases
(3
)
Financing cash flows from finance leases
(3
)
Right-of-use assets obtained in exchange for lease liabilities:
 
Finance leases
$
5



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Sierra Pacific has the following remaining lease commitments as of (in millions):
 
December 31, 2019
 
Operating
 
Finance
 
Total
2020
$
2

 
$
6

 
$
8

2021
2

 
6

 
8

2022
1

 
6

 
7

2023
1

 
6

 
7

2024
1

 
5

 
6

Thereafter
26

 
46

 
72

Total undiscounted lease payments
33

 
75

 
108

Less - amounts representing interest
(16
)
 
(30
)
 
(46
)
Lease liabilities
$
17

 
$
45

 
$
62

 
December 31, 2018(1)
 
Operating
 
Capital
 
Total
2019
$
2

 
$
6

 
$
8

2020
2

 
4

 
6

2021
2

 
5

 
7

2022
1

 
4

 
5

2023
1

 
4

 
5

Thereafter
28

 
47

 
75

Total undiscounted lease payments
$
36

 
$
70

 
$
106


(1)     Amounts included for comparability and accounted for in accordance with ASC Topic 840, "Leases".

Operating and Finance Lease Obligations

Sierra Pacific's operating and finance lease obligations consist mainly of ON Line and Truckee-Carson Irrigation District ("TCID"). ON Line was placed in-service on December 31, 2013. Sierra Pacific and Nevada Power, collectively the ("Nevada Utilities"), entered into a long-term transmission use agreement, in which the Nevada Utilities have a 25% interest and Great Basin Transmission South, LLC has a 75% interest. The Nevada Utilities' share of the long-term transmission use agreement and ownership interest is split at 95% for Nevada Power and 5% for Sierra Pacific. In December 2019, the PUCN ordered the Nevada Utilities to complete the procedures changing the ownership split to 75% for Nevada Power and 25% for Sierra Pacific, effective January 1, 2020. The term of the lease is 41 years with the agreement ending December 31, 2054. In 1999, Sierra Pacific entered into a 50-year agreement with TCID to lease electric distribution facilities. Total finance lease obligations of $35 million and $21 million were included on the Consolidated Balance Sheets as of December 31, 2019 and 2018, respectively, for these leases. See Note 2 for further discussion of Sierra Pacific's remaining lease obligations.


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(6)    Regulatory Matters

Regulatory Assets

Regulatory assets represent costs that are expected to be recovered in future rates. Sierra Pacific's regulatory assets reflected on the Balance Sheets consist of the following as of December 31 (in millions):
 
Weighted
 
 
 
 
 
Average
 
 
 
 
 
Remaining Life
 
2019
 
2018
 
 
 
 
 
 
Employee benefit plans(1)
8 years
 
$
107

 
$
132

Merger costs from 1999 merger
27 years
 
71

 
74

Abandoned projects
7 years
 
24

 
29

Deferred Operating Costs
12 years
 
23

 
15

Losses on reacquired debt
15 years
 
17

 
19

Other
Various
 
53

 
52

Total regulatory assets
 
 
$
295

 
$
321

 
 
 
 
 
 
Reflected as:
 
 
 
 
 
Current assets
 
 
$
12

 
$
7

Noncurrent assets
 
 
283

 
314

Total regulatory assets
 
 
$
295

 
$
321


(1)
Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.

Sierra Pacific had regulatory assets not earning a return on investment of $168 million and $190 million as of December 31, 2019 and 2018, respectively. The regulatory assets not earning a return on investment primarily consist of merger costs from the 1999 merger, a portion of the employee benefit plans, losses on reacquired debt, asset retirement obligations and legacy meters.

Regulatory Liabilities

Regulatory liabilities represent amounts that are expected to be returned to customers in future periods. Sierra Pacific's regulatory liabilities reflected on the Balance Sheets consist of the following as of December 31 (in millions):
 
Weighted
 
 
 
 
 
Average
 
 
 
 
 
Remaining Life
 
2019
 
2018
 
 
 
 
 
 
Deferred income taxes(1)
Various
 
$
263

 
$
270

Cost of removal(2)
38 years
 
217

 
210

Other
Various
 
58

 
29

Total regulatory liabilities
 
 
$
538

 
$
509

 
 
 
 
 
 
Reflected as:
 
 
 
 
 
Current liabilities
 
 
$
49

 
$
18

Noncurrent liabilities
 
 
489

 
491

Total regulatory liabilities
 
 
$
538

 
$
509


(1)
Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to accelerated tax depreciation and certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(2)
Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices.


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Deferred Energy

Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Statements of Operations but rather is deferred and recorded as a regulatory asset on the Balance Sheets and would be included in the table above as deferred energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.

Regulatory Rate Review

In June 2019, Sierra Pacific filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue increase of $5 million but requested an annual revenue reduction of $5 million. In September 2019, Sierra Pacific filed an all-party settlement for the electric regulatory rate review. The settlement resolves all cost of capital and revenue requirement issues and provides for an annual revenue reduction of $5 million and requires Sierra Pacific to share 50% of regulatory earnings above 9.7% with its customers. The rate design portion of the regulatory rate review was not a part of the settlement and a hearing on rate design was held in November 2019. In December 2019, the PUCN issued an order approving the stipulation but made some adjustments to the methodology for the weather normalization component of historical sales in rates, which resulted in an annual revenue reduction of $3 million. The new rates were effective January 1, 2020. In January 2020, Sierra Pacific filed a petition for rehearing challenging the PUCN's adjustments to the weather normalization methodology. In February 2020, the PUCN issued an order granting the petition for rehearing.

2017 Tax Reform

In February 2018, Sierra Pacific made filings with the PUCN proposing a tax rate reduction rider for the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. In March 2018, the PUCN issued an order approving the rate reduction proposed by Sierra Pacific. The new rates were effective April 1, 2018. The order extended the procedural schedule to allow parties additional discovery relevant to 2017 Tax Reform and a hearing was held in July 2018. In September 2018, the PUCN issued an order directing Sierra Pacific to record the amortization of any excess protected accumulated deferred income tax arising from the 2017 Tax Reform as a regulatory liability effective January 1, 2018. Subsequently, Sierra Pacific filed a petition for reconsideration relating to the amortization of protected excess accumulated deferred income tax balances resulting from the 2017 Tax Reform. In November 2018, the PUCN issued an order granting reconsideration and reaffirming the September 2018 order. In December 2018, Sierra Pacific filed a petition for judicial review. In January 2019, intervening parties filed statements of intent to participate in the petition for judicial review. Sierra Pacific has filed opening briefs and the intervening parties have filed answering briefs. The hearing occurred in January 2020 and a ruling is expected in the first half of 2020.

Energy Efficiency Program Rates ("EEPR") and Energy Efficiency Implementation Rates ("EEIR")

EEPR was established to allow Sierra Pacific to recover the costs of implementing energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by Sierra Pacific. When Sierra Pacific's regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, it is obligated to refund energy efficiency implementation revenue previously collected for that year. In March 2019, Sierra Pacific filed an application to reset the EEIR and EEPR and to refund the EEIR revenue received in 2018, including carrying charges. In August 2019, the PUCN issued an order accepting a stipulation to reset the rates as filed effective October 1, 2019. The EEIR liability for Sierra Pacific is $2 million and $2 million, which is included in current regulatory liabilities on the Balance Sheets as of December 31, 2019 and 2018, respectively.


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(7)    Credit Facility

The following table summarizes Sierra Pacific's availability under its credit facilities as of December 31 (in millions):
 
 
2019
 
2018
Credit facilities
 
$
250

 
$
250

Less - Water Facilities Refunding Revenue Bond support
 

 
(80
)
Net credit facilities
 
$
250

 
$
170


Sierra Pacific has a $250 million secured credit facility expiring in June 2022 The credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at Sierra Pacific's option, plus a spread that varies based on Sierra Pacific's credit ratings for its senior secured long‑term debt securities. As of December 31, 2019 and 2018, Sierra Pacific had no borrowings outstanding under the credit facility. Amounts due under Sierra Pacific's credit facility are collateralized by Sierra Pacific's general and refunding mortgage bonds. The credit facility requires Sierra Pacific's ratio of debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.

(8)    Long-Term Debt

Sierra Pacific's long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
 
Par Value
 
2019
 
2018
General and refunding mortgage securities:
 
 
 
 
 
3.375% Series T, due 2023
$
250

 
$
249

 
$
249

2.600% Series U, due 2026
400

 
396

 
396

6.750% Series P, due 2037
252

 
255

 
255

Tax-exempt refunding revenue bond obligations:
 
 
 
 
 
Fixed-rate series:
 
 
 
 
 
1.250% Pollution Control Series 2016A, due 2029

 

 
20

1.850% Pollution Control Series 2016B, due 2029 (1)
30

 
29

 

1.500% Gas Facilities Series 2016A, due 2031

 

 
58

3.000% Gas and Water Series 2016B, due 2036 (2)
60

 
62

 
62

1.850% Water Facilities Series 2016C, due 2036 (3)

 

 
30

2.050% Water Facilities Series 2016D, due 2036 (1) (4)
25

 
25

 
25

2.050% Water Facilities Series 2016E, due 2036 (1) (4)
25

 
25

 
25

2.050% Water Facilities Series 2016F, due 2036 (1)
75

 
74

 

1.850% Water Facilities Series 2016G, due 2036 (1)
20

 
20

 

Total long-term debt
$
1,137

 
$
1,135

 
$
1,120

 
 
 
 
 
 
Reflected as -
 
 
 
 
 
Long-term debt
 
 
$
1,135

 
$
1,120


(1)
Subject to mandatory purchase by Sierra Pacific in April 2022 at which date the interest rate may be adjusted from time to time.

(2)
Subject to mandatory purchase by Sierra Pacific in June 2022 at which date the interest rate may be adjusted from time to time.

(3)
Bond was purchased by Sierra Pacific during 2019. As of December 31, 2018 the bond variable interest rate was 1.750% to 1.820%.

(4)
Bonds were purchased by Sierra Pacific during 2019 and re-offered at a fixed interest rate. As of December 31, 2018 the bonds variable interest rate was 1.750% to 1.820%.


370


Annual Payment on Long-Term Debt

The annual repayments of long-term debt for the years beginning January 1, 2020 and thereafter, are as follows (in millions):
2023
$
250

2025 and thereafter
887

Total
1,137

Unamortized premium, discount and debt issuance cost
(2
)
Total
$
1,135


The issuance of General and Refunding Mortgage Securities by Sierra Pacific is subject to PUCN approval and is limited by available property and other provisions of the mortgage indentures. As of December 31, 2019, approximately $4.2 billion (based on original cost) of Sierra Pacific's property was subject to the liens of the mortgages.

(9)
Income Taxes

Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
 
2019
 
2018
 
2017
 
 
 
 
 
 
Current – Federal
$
19

 
$
23

 
$

Deferred – Federal
10

 
7

 
56

Uncertain tax positions

 
1

 

Investment tax credits
(1
)
 
(1
)
 
(1
)
Total income tax expense
$
28

 
$
30

 
$
55


A reconciliation of the federal statutory income rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Federal statutory income tax rate
21
%
 
21
%
 
35
 %
Non-deductible expenses

 
4

 

Effect of tax rate change

 

 
(1
)
Effective income tax rate
21
%
 
25
%
 
34
 %


371


The net deferred income tax liability consists of the following as of December 31 (in millions):
 
2019
 
2018
Deferred income tax assets:
 
 
 
Regulatory liabilities
$
70

 
$
70

Employee benefit plans
6

 
10

Operating and finance leases
13

 
8

Customer Advances
9

 
8

Other
6

 
6

Total deferred income tax assets
104

 
102

 
 
 
 
Deferred income tax liabilities:
 
 
 
Property related items
(370
)
 
(346
)
Regulatory assets
(62
)
 
(73
)
Operating and finance leases
(13
)
 
(8
)
Other
(6
)
 
(6
)
Total deferred income tax liabilities
(451
)
 
(433
)
Net deferred income tax liability
$
(347
)
 
$
(331
)

The United States Internal Revenue Service has closed its examination of NV Energy’s consolidated income tax returns through December 31, 2008, and the statute of limitations has expired for NV Energy’s consolidated income tax returns through the short year ended December 19, 2013. The statute of limitations expiring may not preclude the Internal Revenue Service from adjusting the federal net operating loss carryforward utilized in a year for which the examination is not closed.

(10)    Employee Benefit Plans

Sierra Pacific is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Sierra Pacific. Sierra Pacific did not make any contributions to the Qualified Pension Plan for the year ended December 31, 2019 and contributed $6 million and $1 million to the Qualified Pension Plan for the years ended December 31, 2018 and 2017, respectively. Sierra Pacific contributed $1 million to the Non-Qualified Pension Plans for the years ended December 312019, 2018 and 2017. Sierra Pacific contributed $- million, $6 million and $4 million to the Other Postretirement Plans for the years ended December 312019, 2018 and 2017, respectively. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.

Amounts payable to NV Energy are included on the Balance Sheets and consist of the following as of December 31(in millions):
 
2019
 
2018
Qualified Pension Plan -
 
 
 
Other long-term liabilities
$
4

 
$
19

 
 
 
 
Non-Qualified Pension Plans:
 
 
 
Other current liabilities
1

 
1

Other long-term liabilities
8

 
7

 
 
 
 
Other Postretirement Plans -
 
 
 
Other long-term liabilities
7

 
13


(11)    Asset Retirement Obligations

Sierra Pacific estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.

Sierra Pacific does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $217 million and $210 million as of December 31, 2019 and 2018, respectively.

The following table presents Sierra Pacific's ARO liabilities by asset type as of December 31 (in millions):
 
2019
 
2018
 
 
 
 
Asbestos
$
5

 
$
5

Evaporative ponds and dry ash landfills
2

 
2

Other
3

 
3

Total asset retirement obligations
$
10

 
$
10



372


The following table reconciles the beginning and ending balances of Sierra Pacific's ARO liabilities for the years ended December 31 (in millions):
 
2019
 
2018
 
 
 
 
Beginning balance
$
10

 
$
10

Accretion

 

Ending balance
$
10

 
$
10

 
 
 
 
Reflected as -
 
 
 
Other long-term liabilities
$
10

 
$
10


Certain of Sierra Pacific's decommissioning and reclamation obligations relate to jointly-owned facilities, and as such, Sierra Pacific is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. Sierra Pacific's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities in other long-term liabilities on the Balance Sheets.

(12)
Fair Value Measurements

The carrying value of Sierra Pacific's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Sierra Pacific has various financial assets and liabilities that are measured at fair value on the Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Sierra Pacific has the ability to access at the measurement date.
Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
Level 3 - Unobservable inputs reflect Sierra Pacific's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Sierra Pacific develops these inputs based on the best information available, including its own data.

The following table presents Sierra Pacific's assets and liabilities recognized on the Balance Sheets and measured at fair value on a recurring basis (in millions):

 
Input Levels for Fair Value Measurements
 
 
 
Level 1
 
Level 2
 
Level 3
 
Total
As of December 31, 2019:
 
 
 
 
 
 
 
Assets - money market mutual funds(1)
$
25

 
$

 
$

 
$
25

 
 
 
 
 
 
 
 
Liabilities - commodity derivatives
$

 
$

 
$
(1
)
 
$
(1
)
 
 
 
 
 
 
 
 
As of December 31, 2018:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity derivatives
$

 
$

 
$
2

 
$
2

Money market mutual funds(1)
45

 

 

 
45

 
$
45

 
$

 
$
2

 
$
47



373


(1)
Amounts are included in cash and cash equivalents on the Balance Sheets. The fair value of these money market mutual funds approximates cost.

Sierra Pacific's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.

Sierra Pacific's long-term debt is carried at cost on the Balance Sheets. The fair value of Sierra Pacific's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Sierra Pacific's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Sierra Pacific's long-term debt as of December 31 (in millions):
 
2019
 
2018
 
Carrying
 
Fair
 
Carrying
 
Fair
 
Value
 
Value
 
Value
 
Value
 
 
 
 
 
 
 
 
Long-term debt
$
1,135

 
$
1,258

 
$
1,120

 
$
1,167


(13)
Commitments and Contingencies

Environmental Laws and Regulations

Sierra Pacific is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.

Legal Matters

Sierra Pacific is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its financial results. Sierra Pacific is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts.


374


Commitments

Sierra Pacific has the following firm commitments that are not reflected on the Balance Sheet. Minimum payments as of December 31, 2019 are as follows (in millions):
 
 
 
 
 
 
 
 
 
 
 
2025 and
 
 
 
2020
 
2021
 
2022
 
2023
 
2024
 
Thereafter
 
Total
Contract type:
 
 
 
 
 
 
 
 
 
 
 
 
 
Fuel, capacity and transmission contract commitments
$
260

 
$
198

 
$
114

 
$
84

 
$
83

 
$
863

 
$
1,602

Fuel and capacity contract commitments (not commercially operable)
1

 
11

 
41

 
41

 
42

 
921

 
1,057

Easements
2

 
2

 
2

 
2

 
2

 
30

 
40

Maintenance, service and other contracts
11

 
8

 
7

 
2

 
1

 
9

 
38

Total commitments
$
274

 
$
219

 
$
164

 
$
129

 
$
128

 
$
1,823

 
$
2,737


Fuel and Capacity Contract Commitments

Purchased Power

Sierra Pacific has several contracts for long-term purchase of electric energy which have been approved by the PUCN. The expiration of these contracts range from 2020 to 2044. Purchased power includes estimated payments for contracts which meet the definition of a lease and payments are based on the amount of energy expected to be generated. See Note 5 for further discussion of Sierra Pacific's lease commitments.

Coal and Natural Gas
    
Sierra Pacific has a long-term contract for the transport of coal that expires in 2021. Additionally, gas transportation contracts expire from 2020 to 2046 and the gas supply contracts expire from 2020 to 2021.

Fuel and Capacity Contract Commitments - Not Commercially Operable

Sierra Pacific has several contracts for long-term purchase of electric energy in which the facility remains under development. Amounts represent the estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver power.

Easements

Sierra Pacific has non-cancelable easements for land. Operating and maintenance expense on non-cancelable easements totaled $2 million for the years-ended December 31, 2019, 2018 and 2017.

Maintenance, Service and Other Contracts

Sierra Pacific has long-term service agreements for the performance of maintenance on generation units. Obligation amounts are based on estimated usage. The estimated expiration of these service agreements range from 2020 to 2039.


375


(14)
Revenues from Contracts with Customers

The following table summarizes Sierra Pacific's revenue by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 17, for the years ended December 31 (in millions):
 
2019
 
2018
 
Electric
 
Natural Gas
 
Total
 
Electric
 
Natural Gas
 
Total
Customer Revenue:
 
 
 
 
 
 
 
 
 
 
 
Retail:
 
 
 
 
 
 
 
 
 
 
 
Residential
$
268

 
$
76

 
$
344

 
$
267

 
$
67

 
$
334

Commercial
245

 
30

 
275

 
246

 
25

 
271

Industrial
186

 
10

 
196

 
177

 
8

 
185

Other
6

 
1

 
7

 
6

 
1

 
7

Total fully bundled
705

 
117

 
822

 
696

 
101

 
797

Distribution only service
4

 

 
4

 
4

 

 
4

Total retail
709

 
117

 
826

 
700

 
101

 
801

Wholesale, transmission and other
57

 

 
57

 
48

 

 
48

Total Customer Revenue
766

 
117

 
883

 
748

 
101

 
849

Other revenue
4

 
2

 
6

 
4

 
2

 
6

Total revenue
$
770

 
$
119

 
$
889

 
$
752

 
$
103

 
$
855


(15)    Supplemental Cash Flow Disclosures

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 2019 and December 31, 2018, consist of funds restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2019 and December 31, 2018, as presented in the Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Balance Sheets (in millions):
 
As of
 
December 31,
 
December 31,
 
2019
 
2018
Cash and cash equivalents
$
27

 
$
71

Restricted cash and cash equivalents included in other current assets
5

 
5

Total cash and cash equivalents and restricted cash and cash equivalents
$
32

 
$
76


The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
 
2019
 
2018
 
2017
 
 
 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
 
 
Interest paid, net of amounts capitalized
$
41

 
$
41

 
$
40

Income taxes paid
$
37

 
$
19

 
$

 
 
 
 
 
 
Supplemental disclosure of non-cash investing and financing transactions:
 
 
 
 
 
Accruals related to property, plant and equipment additions
$
18

 
$
15

 
$
10



376


(16)    Related Party Transactions

Sierra Pacific has an intercompany administrative services agreement with BHE and its subsidiaries. Amounts charged to Sierra Pacific under this agreement totaled $1 million for the years ended December 31, 2019, 2018 and 2017.

Sierra Pacific provided electricity to Nevada Power of $25 million, $28 million and $21 million for the years ended December 312019, 2018 and 2017, respectively. Receivables associated with these transactions were $1 million as of December 31, 2019 and 2018. Sierra Pacific purchased electricity from Nevada Power of $84 million, $91 million and $104 million for the years ended December 31, 2019, 2018 and 2017, respectively. Payables associated with these transactions were $5 million and $6 million as of December 31, 2019 and 2018, respectively.

Sierra Pacific incurs intercompany administrative and shared facility costs with NV Energy and Nevada Power. These transactions are governed by an intercompany service agreement and are priced at cost. NV Energy provided services to Sierra Pacific of $4 million, $4 million and $5 million for the years ending December 312019, 2018 and 2017, respectively. Sierra Pacific provided services to Nevada Power of $14 million, $15 million, and $17 million for the years ended December 312019, 2018 and 2017, respectively. Nevada Power provided services to Sierra Pacific of $26 million, $28 million, and $27 million for the years ended December 312019, 2018 and 2017, respectively. As of December 31, 2019 and 2018, Sierra Pacific's Balance Sheets included amounts due to NV Energy of $15 million. There were no receivables due from NV Energy as of December 312019 and 2018. As of December 312019 and 2018, Sierra Pacific's Balance Sheets included payables due to Nevada Power of $3 million and $5 million, respectively. There were no receivables due from Nevada Power as of December 312019 and 2018.

Sierra Pacific is party to a tax-sharing agreement with NV Energy and NV Energy is part of the Berkshire Hathaway consolidated United States federal income tax return. Federal income taxes receivable from NV Energy were $14 million as of December 31, 2019 and federal income taxes payable to NV Energy were $3 million as of December 31, 2018. Sierra Pacific made cash payments of $37 million and $19 million for federal income taxes for the year ended December 312019 and 2018, respectively. No cash payments were made for federal income taxes for the year ended December 312017.

Certain disbursements for accounts payable and payroll are made by NV Energy on behalf of Sierra Pacific and reimbursed automatically when settled by the bank. These amounts are recorded as accounts payable at the time of disbursement.


377


(17)    Segment Information

Sierra Pacific has identified two reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by the PUCN; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance.

The following tables provide information on a reportable segment basis (in millions):
 
 
Years Ended December 31,
 
 
2019

2018

2017
Operating revenue:
 
 
 
 
 
 
Regulated electric
 
$
770

 
$
752

 
$
713

Regulated natural gas
 
119

 
103

 
99

Total operating revenue
 
$
889

 
$
855

 
$
812

 
 
 
 
 
 
 
Operating income:
 
 
 
 
 
 
Regulated electric
 
$
150

 
$
136

 
$
175

Regulated natural gas
 
21

 
16

 
22

Total operating income
 
171

 
152

 
197

Interest expense
 
(48
)
 
(44
)
 
(43
)
Allowance for borrowed funds
 
1

 
1

 
2

Allowance for equity funds
 
3

 
4

 
3

Other, net
 
4

 
9

 
5

Income before income tax expense
 
$
131

 
$
122

 
$
164

 
 
As of December 31,
 
 
2019
 
2018
 
2017
Assets
 
 
 
 
 
 
Regulated electric
 
$
3,319

 
$
3,177

 
$
3,103

Regulated natural gas
 
308

 
314

 
300

Regulated common assets(1)
 
44

 
78

 
10

Total assets
 
$
3,671

 
$
3,569

 
$
3,413


(1)
Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.


378


(18)    Unaudited Quarterly Operating Results (in millions)

 
Three-Month Periods Ended
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
2019
 
2019
 
2019
 
2019
Regulated electric operating revenue
$
182

 
$
172

 
$
232

 
$
184

Regulated natural gas operating revenue
37

 
22

 
16

 
44

Operating income
37

 
27

 
67

 
40

Net income
22

 
14

 
44

 
23

 
 
 
 
 
 
 
 
 
Three-Month Periods Ended
 
March 31,
 
June 30,
 
September 30,
 
December 31,
 
2018
 
2018
 
2018
 
2018
Regulated electric operating revenue
$
181

 
$
169

 
$
225

 
$
177

Regulated natural gas operating revenue
41

 
19

 
14

 
29

Operating income
47

 
19

 
56

 
30

Net income
34

 
7

 
35

 
16



379


Item 9.    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A.
Controls and Procedures

Disclosure Controls and Procedures

At the end of the period covered by this Annual Report on Form 10-K, each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company carried out separate evaluations, under the supervision and with the participation of each such entity's management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended). Based upon these evaluations, management of each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures for such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended December 31, 2019 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

Management's Report on Internal Control over Financial Reporting

Management of each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company, respectively, is responsible for establishing and maintaining, for such entity, adequate internal control over financial reporting, as such term is defined in the Securities Exchange Act of 1934 Rule 13a-15(f). Under the supervision and with the participation of management for each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, such management conducted an evaluation for the relevant entity of the effectiveness of internal control over financial reporting as of December 31, 2019, as required by the Securities Exchange Act of 1934 Rule 13a-15(c). In making this assessment, management for each such respective entity used the criteria set forth in the framework in "Internal Control - Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the evaluation conducted under the framework in "Internal Control - Integrated Framework (2013)," management for each such respective entity concluded that internal control over financial reporting for such entity was effective as of December 31, 2019.

Berkshire Hathaway Energy Company
 
PacifiCorp
 
MidAmerican Funding, LLC
February 21, 2020
 
February 21, 2020
 
February 21, 2020
 
 
 
 
 
MidAmerican Energy Company
 
Nevada Power Company
 
Sierra Pacific Power Company
February 21, 2020
 
February 21, 2020
 
February 21, 2020

Item 9B.
Other Information

None.


380


PART III

Item 10.
Directors, Executive Officers and Corporate Governance

BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER AND SIERRA PACIFIC

Information required by Item 10 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.

PACIFICORP

PacifiCorp is an indirect subsidiary of BHE, and its directors consist of executive management from both BHE and PacifiCorp. Each director was elected based on individual responsibilities, experience in the energy industry and functional expertise. There are no family relationships among the executive officers, nor any arrangements or understandings between any executive officer and any other person pursuant to which the executive officer was appointed. Set forth below is certain information, as of January 31, 2020, with respect to the current directors and executive officers of PacifiCorp:

WILLIAM J. FEHRMAN, 59, Chairman of the Board of Directors and Chief Executive Officer since January 2018. Mr. Fehrman has also been President, Chief Executive Officer and director of BHE since January 2018. Mr. Fehrman was Chief Executive Officer of MidAmerican Energy Company from 2008 to January 2018 and President and director from 2007 to January 2018. Mr. Fehrman joined BHE in 2006 and has extensive executive management experience in the energy industry with strong regulatory and operational skills.

STEFAN A. BIRD, 53, President and Chief Executive Officer of Pacific Power and director since 2015. Mr. Bird was Senior Vice President, Commercial and Trading, of PacifiCorp from 2007 to 2014. Mr. Bird joined BHE in 1998 and has significant operational, public policy and leadership experience in the energy industry, including expertise in energy supply management, resource acquisition and federal and state regulatory matters.

GARY W. HOOGEVEEN, 51, President and Chief Executive Officer of Rocky Mountain Power since November 2018. Prior to his current position Mr. Hoogeveen served as Senior Vice President and Chief Commercial Officer of Rocky Mountain Power since November 2014 and President and CEO of Kern River Gas Transmission Company from 2010 to 2014. He joined Kern River after serving as Vice President of Customer Service and Business Development for Northern Natural Gas Company. Prior to joining Northern Natural Gas, he held various management positions at Berkshire Hathaway Energy.

NIKKI L. KOBLIHA, 47, Vice President and Chief Financial Officer since 2015 and Treasurer and director since 2017. Ms. Kobliha joined PacifiCorp in 1997 and has significant financial, accounting and leadership experience in the energy industry, including expertise in financial reporting to the SEC and FERC.

PATRICK J. GOODMAN, 53, Director since 2006. Mr. Goodman has been Executive Vice President and Chief Financial Officer of BHE since 2012 and was Senior Vice President and Chief Financial Officer of BHE from 1999 to 2012. Mr. Goodman joined BHE in 1995 and has significant financial experience, including expertise in mergers and acquisitions, accounting, treasury and tax functions. Mr. Goodman is also a manager of MidAmerican Funding, LLC.

NATALIE L. HOCKEN, 50, Director since 2007. Ms. Hocken has been Senior Vice President and General Counsel of BHE since 2015 and Corporate Secretary since 2017. Ms. Hocken was Senior Vice President, Transmission and System Operations of PacifiCorp from 2012 to 2015 and Vice President and General Counsel of Pacific Power from 2007 to 2012. Ms. Hocken joined PacifiCorp in 2002 and has significant experience in the utility industry, including expertise in transmission, legal matters and federal and state regulatory matters. Ms. Hocken is also a manager of MidAmerican Funding, LLC.

Board's Role in the Risk Oversight Process

PacifiCorp's Board of Directors is comprised of a combination of BHE senior executives and PacifiCorp senior management who have direct and indirect responsibility for the management and oversight of risk. PacifiCorp's Board of Directors has not established a separate risk management and oversight committee.


381


Audit Committee and Audit Committee Financial Expert

During the year ended December 31, 2019, and as of the date of this Annual Report on Form 10-K, PacifiCorp's Board of Directors did not have an audit committee. PacifiCorp is not required to have an audit committee as its common stock is indirectly and wholly owned by BHE. However, the audit committee of BHE acts as the audit committee for PacifiCorp.

Code of Ethics

PacifiCorp has adopted a code of ethics that applies to its principal executive officer, its principal financial and accounting officer, or persons acting in such capacities, and certain other covered officers. The code of ethics is incorporated by reference in the exhibits to this Annual Report on Form 10-K.

Item 11.
Executive Compensation

BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER AND SIERRA PACIFIC

Information required by Item 11 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.

PACIFICORP

Compensation Discussion and Analysis

Compensation Philosophy and Overall Objectives

Mr. William J. Fehrman, PacifiCorp's Chairman of the Board of Directors and Chief Executive Officer, or Chairman and CEO, received no direct compensation from PacifiCorp. PacifiCorp reimbursed its indirect parent company, BHE, for the cost of Mr. Fehrman's time spent on matters supporting PacifiCorp, including compensation paid to him by BHE, pursuant to an intercompany administrative services agreement among BHE and its subsidiaries.

PacifiCorp believes that the compensation paid to each of its Chief Financial Officer, or CFO, and its other most highly compensated executive officers, to whom PacifiCorp refers collectively as its Named Executive Officers, or NEOs, should be closely aligned with its overall performance, and each NEO's contribution to that performance, on both a short- and long-term basis, and that such compensation should be sufficient to attract and retain highly qualified leaders who can create significant value for the organization. PacifiCorp's compensation programs are designed to provide its NEOs meaningful incentives for superior corporate and individual performance. Performance is evaluated on a subjective basis within the context of both financial and non-financial objectives, among which are customer service, employee commitment, environmental respect, regulatory integrity, operational excellence and financial strength, which PacifiCorp believes contribute to its long-term success.

How is Compensation Determined

PacifiCorp's compensation committee consists solely of the Chairman and CEO. The Chairman and CEO is responsible for the establishment and oversight of PacifiCorp's compensation policy and for approving compensation decisions for its NEOs such as approving base pay increases, incentive and performance awards, off-cycle pay changes, and participation in other employee benefit plans and programs.

PacifiCorp's criteria for assessing executive performance and determining compensation in any year is inherently subjective and is not based upon specific formulas or weighting of factors. PacifiCorp does not specifically use other companies as benchmarks when establishing its NEOs' compensation.

Discussion and Analysis of Specific Compensation Elements

Base Salary

PacifiCorp determines base salaries for all of its NEOs, other than the Chairman and CEO, by reviewing its overall performance, and each NEO's performance, the value each NEO brings to PacifiCorp and general labor market conditions. While base salary provides a base level of compensation intended to be competitive with the external market, the annual base salary adjustment for each NEO, other than the Chairman and CEO, is determined on a subjective basis after consideration of these factors and is not based on target percentiles or other formal criteria. All merit increases are approved by the Chairman and CEO and take effect in the last payroll period of the year. An increase or decrease in base salary may also result from a promotion or other significant change in a NEO's responsibilities during the year. For 2019, base salaries for all NEOs, other than the Chairman and CEO, increased on average by 3.72% effective December 26, 2018, reflecting merit increases.

Short-Term Incentive Compensation

The objective of short-term incentive compensation is to reward the achievement of significant annual corporate and business unit goals while also providing NEOs with competitive total cash compensation.

Annual Incentive Plan

Under PacifiCorp's Annual Incentive Plan, or AIP, all NEOs, other than the Chairman and CEO, are eligible to earn an annual discretionary cash incentive award, which is determined on a subjective basis at the Chairman and CEO's sole discretion and is not based on a specific formula or cap. The Chairman and CEO considers a variety of factors in determining each NEO's annual incentive award including the NEO's performance, PacifiCorp's overall performance and each NEO's contribution to that overall performance. The Chairman and CEO evaluates performance using financial and non-financial objectives, including customer service, employee commitment, environmental respect, regulatory integrity, operational excellence and financial strength, as well as the NEO's response to issues and opportunities that arise during the year. No factor was individually material to the Chairman and CEO's determination regarding the amounts paid to each NEO under the AIP for 2019. Approved awards are paid prior to year-end.

Performance Awards

In addition to the annual awards under the AIP, PacifiCorp may grant cash performance awards periodically during the year to one or more NEOs, other than the Chairman and CEO, to reward the accomplishment of significant non-recurring tasks or projects. These awards are discretionary and are approved by the Chairman and CEO. No cash performance awards were granted to the NEO's in 2019.

Long-Term Incentive Compensation

The objective of long-term incentive compensation is to retain NEOs, reward their exceptional performance and motivate them to create long-term, sustainable value. PacifiCorp's current long-term incentive compensation program is cash-based. PacifiCorp does not utilize stock options or other forms of equity-based awards.

Long-Term Incentive Partnership Plan

The PacifiCorp Long-Term Incentive Partnership Plan, or LTIP, is designed to retain key employees and to align PacifiCorp's interests and the interests of the participating employees. All of PacifiCorp's NEOs, other than the Chairman and CEO, participate in the LTIP. The LTIP provides for annual discretionary awards based upon significant accomplishments by the individual participants and the achievement of the financial and non-financial objectives previously described. The goals are developed with the objective of being attainable with a sustained, focused and concerted effort and are determined and communicated by January of each plan year. The BHE Chairman and PacifiCorp's Presidents approve eligibility to participate in the LTIP and the amount of the incentive award. Awards are finalized in the first quarter of the following year. PacifiCorp's Presidents may participate in the LTIP but only the BHE Chairman shall make determinations regarding their participation and the value of their incentive award. These cash-based awards are subject to mandatory deferral and equal annual vesting over a four-year period starting in the performance year. Participants allocate the value of their deferral accounts among various investment alternatives. Gains or losses may be incurred based on investment performance. Participating NEOs may elect to defer all or a part of the award or receive payment in cash after the four-year mandatory deferral and vesting period. Vested balances (including any investment gains or losses thereon) of terminating participants are paid at the time of termination.


382


Deferred Compensation Plan

PacifiCorp's Executive Voluntary Deferred Compensation Plan, or DCP, provides a means for all NEOs, other than the Chairman and CEO, to make voluntary deferrals of up to 50% of base salary and 100% of short-term incentive compensation awards. PacifiCorp includes the DCP as part of the participating NEO's overall compensation in order to provide a comprehensive, competitive package. The deferrals and any investment returns grow on a tax-deferred basis. Amounts deferred under the DCP receive a rate of return based on the returns of any combination of various investment alternatives offered under the DCP and selected by the participant. The plan allows participants to choose from three forms of distribution. The plan permits PacifiCorp to make discretionary contributions on behalf of participants.

Potential Payments Upon Termination
PacifiCorp's NEOs, other than the Chairman and CEO, are not entitled to severance or enhanced benefits upon termination of employment or change in control. However, upon any termination of employment, PacifiCorp's other NEOs would be entitled to the vested balances in the LTIP, DCP and PacifiCorp's non-contributory defined benefit pension plan, or the Retirement Plan.

Compensation Committee Report

Mr. Fehrman, PacifiCorp's current Chairman and CEO and sole member of PacifiCorp's compensation committee, has reviewed the Compensation Discussion and Analysis and, based on this review, has recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

William J. Fehrman

Summary Compensation Table

The following table sets forth information regarding compensation earned by each of PacifiCorp's NEOs during the years indicated:
 
 
 
 
 
 
 
 
Change in
 
 
 
 
 
 
 
 
 
 
 
 
Pension
 
 
 
 
 
 
 
 
 
 
 
 
Value and
 
 
 
 
 
 
 
 
 
 
 
 
Nonqualified
 
 
 
 
 
 
 
 
 
 
 
 
Deferred
 
 
 
 
 
 
 
 
 
 
 
 
Compensation
 
All Other
 
 
Name and Principal Position
 
Year
 
Base Salary
 
Bonus (1)
 
Earnings(2)
 
Compensation (3)
 
Total (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
William J. Fehrman(5)(6)
 
2019
 
$

 
$

 
$

 
$

 
$

Chairman of the Board of Directors
 
2018
 

 

 

 

 

and Chief Executive Officer
 
2017
 

 

 

 

 

 
 
 
 
 
 
 
 
 
 
 
 
 
Stefan A. Bird
 
2019
 
365,000

 
1,286,958

 
10,152

 
31,845

 
1,693,955

President and Chief Executive
 
2018
 
355,000

 
1,058,696

 
29,549

 
31,633

 
1,474,878

Officer, Pacific Power
 
2017
 
346,000

 
1,116,105

 
9,480

 
30,965

 
1,502,550

 
 
 
 
 
 
 
 
 
 
 
 
 
Gary W. Hoogeveen(7)
 
2019
 
350,000

 
964,837

 

 
32,731

 
1,347,568

President and Chief Executive
 
2018
 
315,570

 
898,733

 

 
32,484

 
1,246,787

Officer, Rocky Mountain Power
 
2017
 

 

 

 

 

 
 
 
 
 
 
 
 
 
 
 
 
 
Nikki L. Kobliha
 
2019
 
239,571

 
243,289

 
33,825

 
31,391

 
548,076

Vice President, Chief Financial
 
2018
 
224,510

 
190,045

 

 
30,804

 
445,359

Officer and Treasurer
 
2017
 
217,079

 
122,400

 
18,304

 
30,415

 
388,198



383


(1)
Consists of annual cash incentive awards earned pursuant to the AIP for PacifiCorp's NEOs and the vesting of LTIP awards and associated vested earnings. The breakout for 2019 is as follows:
 
 
 
 
 
 
LTIP
 
 
 
 
Performance
 
Vested
 
Vested
 
 
 
 
AIP
 
Award
 
Awards
 
Earnings
 
Total
Stefan A. Bird
 
$
550,000

 
$

 
$
645,000

 
$
91,958

 
$
736,958

Gary W. Hoogeveen
 
450,000

 

 
352,410

 
162,427

 
514,837

Nikki L. Kobliha
 
115,274

 

 
102,125

 
25,890

 
128,015


The ultimate payouts of LTIP awards are undeterminable as the amounts to be paid out may increase or decrease depending on investment performance. BHE's Chairman and PacifiCorp's Presidents establish the award categories for determining LTIP awards based on net income target goals or other criteria. In 2019, the gross award was subjectively determined at the discretion of the BHE Chairman and PacifiCorp's Presidents based on the overall achievement of PacifiCorp's financial and non-financial objectives including customer service, employee commitment and safety, environmental respect, regulatory integrity, operational excellence and financial strength.
(2)
Amounts are based upon the aggregate increase in the actuarial present value of all qualified and nonqualified defined benefit plans, which includes the Retirement Plan. Refer to the Pension Benefits table below for a discussion of the assumptions used in calculating these amounts. No participant in PacifiCorp's nonqualified deferred compensation plans earned "above market" or "preferential" earnings on amounts deferred.
(3)
Amounts consist of PacifiCorp K Plus Employee Savings Plan, or 401(k) Plan, contributions PacifiCorp paid on behalf of the NEOs, except for Mr. Hoogeveen for whom PacifiCorp also includes an amount paid for a tax gross-up with respect to a personal benefit with a value less than $10,000.
(4)
Any amounts voluntarily deferred by the NEO, if applicable, are included in the appropriate column in the Summary Compensation Table.
(5)
On January 10, 2018, Mr. William J. Fehrman was elected as PacifiCorp's Chairman of the Board of Directors and Chief Executive Officer.
(6)
Mr. Fehrman receives no direct compensation from PacifiCorp. PacifiCorp reimburses BHE for the cost of Mr. Fehrman's time spent on matters supporting PacifiCorp, including compensation paid to him by BHE, pursuant to an intercompany administrative services agreement among BHE and its subsidiaries. In 2019, PacifiCorp reimbursed BHE $260,538 for the cost of Mr. Fehrman's time spent on matters supporting PacifiCorp pursuant to the intercompany administrative services agreement.
(7)
On June 1, 2018, Mr. Hoogeveen was named Rocky Mountain Power's president effective June 1, 2018 and Rocky Mountain Power's chief executive officer effective November 28, 2018.
Pension Benefits

The following table sets forth certain information regarding the defined benefit pension plan accounts held by each of PacifiCorp's NEOs as of December 31, 2019:

 
 
 
 
Number of years of
 
Present value of
Name
 
Plan name
 
credited service
 
accumulated benefits (1)
 
 
 
 
 
 
 
William J. Fehrman
 
 n/a
 
n/a
 
n/a

Stefan A. Bird
 
 Retirement
 
10 years
 
$
216,926

Gary W. Hoogeveen
 
n/a
 
n/a
 
n/a

Nikki L. Kobliha
 
 Retirement
 
12 years
 
145,974



(1)
Amounts are computed using assumptions, other than the expected retirement age, consistent with those used in preparing the related pension disclosures in the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K and are as of December 31, 2019, which is the measurement date for the plans. The expected retirement age assumption has been determined in accordance with Instruction 2 to Item 402(h)(2) of Regulation S-K. For the Retirement Plan calculations of the present value of accumulated benefits, the following assumptions were used: 60% lump sum payment; 40% joint and 100% survivor annuity if participant is married and 40% single life annuity if participant is single. The present value assumptions used in calculating the present value of accumulated benefits for the Retirement Plan were as follows: a discount rate of 3.25%; an expected retirement age of 65; postretirement mortality using the RP-2014 gender specific tables, adjusted for BHE credibility weighted experience, translated to 2011 using MP-2014. 2012, 2013, 2014 and 2015 rates were used for MP-2016, MP-2017, MP-2018 and MP-2019, respectively and generational mortality improvements from 2015 forward were based on the custom RPEC 2014 v2019 model; a lump sum interest rate of 3.25%; and lump sum mortality using the unisex tables set forth in IRC 417(e)(3) for the upcoming fiscal year with mortality improvements determined using MP-2018.

384


Historically, PacifiCorp has adopted the Retirement Plan for the majority of its employees, other than employees subject to collective bargaining agreements that do not provide for coverage under the Retirement Plan. Through May 31, 2007, participants earned benefits at retirement payable for life based on length of service through May 31, 2007 and average pay in the 60 consecutive months of highest pay out of the 120 months prior to May 31, 2007. Pay for this purpose included base salary and annual incentive plan payments up to 10% of base salary, but was limited to the amounts specified in Internal Revenue Code Section 401(a)(17). Benefits were based on 1.3% of final average pay plus 0.65% of final average pay in excess of covered compensation (as defined in Internal Revenue Code Section 401(1)(5)(E)) multiplied by years of service.

The Retirement Plan was restated effective June 1, 2007 to change from a traditional final average pay formula as described above to a cash balance formula for non-union participants. Benefits under the final average pay formula were frozen as of May 31, 2007, and no future benefits will accrue under that formula for non-union participants. Under the cash balance formula, benefits are based on pay credits to each participant's account of 6.5% (5.0% for employees hired after June 30, 2006 and before January 1, 2008) of eligible compensation. Interest is also credited to each participant's account. Employees who were age 40 or older as of May 31, 2007 received certain additional transition pay credits for five years from the effective date of the Retirement Plan restatement.

Participants in the Retirement Plan are entitled to receive full benefits upon retirement on or after age 65. Such participants are also entitled to receive reduced benefits upon early retirement after age 55 with at least five years of service or when age plus years of service equals 75.

In 2008, non-union employee participants in the Retirement Plan were offered the option to continue to receive pay credits in the Retirement Plan or receive equivalent fixed contributions to the 401(k) Plan with any such election becoming effective January 1, 2009. Ms. Kobliha and Mr. Hoogeveen elected the equivalent fixed 401(k) contribution option and, therefore, no longer receive pay credits in the Retirement Plan. In 2017, the Retirement Plan was frozen for the remainder of the non-union employees (which includes Mr. Bird) with pay credits equivalent to those received in the Retirement Plan allocated into the K Plus Employee Savings Plan. Each NEO continues to receive interest credits in the Retirement Plan.

Nonqualified Deferred Compensation

The following table sets forth certain information regarding the nonqualified deferred compensation plan accounts held by each of PacifiCorp's NEOs as of December 31, 2019:

 
 
Executive
 
Registrant
 
Aggregate
 
Aggregate
 
Aggregate
 
 
contributions
 
contributions
 
earnings/losses
 
withdrawals/
 
balance as of
Name
 
in 2019(1)
 
in 2019
 
in 2019
 
distributions
 
December 31, 2019
 
 
 
 
 
 
 
 
 
 
 
William J. Fehrman
 
$

 
$

 
$

 
$

 
$

Stefan A. Bird
 

 

 

 

 

Gary W. Hoogeveen
 
718,124

 

 
378,371

 

 
2,524,570

Nikki L. Kobliha
 

 

 
4,351

 

 
51,360


(1)
The executive contribution amount shown for Mr. Hoogeveen represents a deferral of $450,000 of his 2019 compensation and a deferral of $268,124 of his 2016 LTIP award which was deferred in 2019. $154,351 of the deferred 2016 LTIP award is included in the 2019 total compensation reported for him in the Summary Compensation Table and is not additional compensation. The remaining LTIP award was earned prior to 2019.
Eligibility for PacifiCorp's DCP is restricted to select management and highly compensated employees. The plan provides tax benefits to eligible participants by allowing them to defer compensation on a pretax basis, thus reducing their current taxable income. Deferrals and any investment returns grow on a tax-deferred basis, thus participants pay no income tax until they receive distributions. The DCP permits participants to make a voluntary deferral of up to 50% of base salary and 100% of short-term incentive compensation awards. All deferrals are net of social security taxes. Amounts deferred under the DCP receive a rate of return based on the returns of any combination of various investment alternatives offered by the plan and selected by the participant. Gains or losses are calculated daily, and returns are posted to accounts based on participants' fund allocation elections. Participants can change their fund allocations as of the end of any day on which the market is open.

385


The DCP allows participants to maintain three accounts based upon when they want to receive payments: retirement account, in-service account and education account. Both the retirement and in-service accounts can be distributed as lump sums or in up to 10 annual installments, except in the case of the four DCP transition accounts that allow for a grandfathered payout based on the previous deferred compensation plan distribution elections of lump sum, 5, 10 or 15 annual installments. Effective December 31, 2006, no new money may be deferred into the DCP transition accounts. The education account is distributed in four annual installments. If a participant leaves employment prior to retirement (age 55), all amounts in the participant's account will be paid out in a lump sum as soon as administratively practicable. Participants are 100% vested in their deferrals and any investment gains or losses recorded in their accounts.

Participants in PacifiCorp's LTIP also have the option of deferring all or a part of those awards after the four-year mandatory deferral and vesting period. The provisions governing the deferral of LTIP awards are similar to those described for the DCP above.

Potential Payments Upon Termination

PacifiCorp's NEOs, other than the Chairman and CEO, are not generally entitled to severance or enhanced benefits upon termination of employment or change in control.

The following table sets forth the estimated increase in the present value of benefits pursuant to the termination scenarios indicated for PacifiCorp's NEOs, other than Mr. Fehrman. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of long-term incentive payments that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2019 and are payable as lump sums unless otherwise noted.
Termination Scenario
 
Incentive (1)
 
Pension (2)
 
 
 
 
 
Stefan A. Bird:
 
 
 
 
Retirement, Voluntary and Involuntary With or Without Cause
 
$

 
$
24,016

Death and Disability
 
1,085,034

 
24,016

Gary W. Hoogeveen:
 
 
 
 
Retirement, Voluntary and Involuntary With or Without Cause
 

 
n/a

Death and Disability
 
649,177

 
n/a

Nikki L. Kobliha:
 
 
 
 
Retirement, Voluntary and Involuntary With or Without Cause
 

 

Death and Disability
 
237,110

 


(1)
Amounts represent the unvested portion of each NEO's LTIP account, which becomes 100% vested under certain circumstances.
(2)
Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits table.
Chief Executive Officer Pay Ratio

PacifiCorp's CEO receives no direct compensation from PacifiCorp, and no amounts are reported for the CEO in the Summary Compensation Table. Accordingly, PacifiCorp has determined that the CEO pay ratio is not calculable.

Director Compensation

PacifiCorp's directors do not receive additional compensation for service as directors of PacifiCorp. Compensation information for Messrs. Fehrman, Bird, Hoogeveen, and Ms. Kobliha for their services as executive officers of PacifiCorp is described above.

Compensation Committee Interlocks and Insider Participation

Mr. Fehrman is PacifiCorp's Chairman and CEO and also the President and Chief Executive Officer of BHE. None of PacifiCorp's executive officers serves as a member of the compensation committee of any company that has an executive officer serving as a member of PacifiCorp's Board of Directors. None of PacifiCorp's executive officers serves as a member of the board of directors of any company (other than BHE) that has an executive officer serving as a member of PacifiCorp's compensation committee. See also PacifiCorp's Item 13 in this Annual Report on Form 10-K.

386



Item 12.     Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER AND SIERRA PACIFIC

Information required by Item 12 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.

PACIFICORP

Beneficial Ownership

PacifiCorp is a consolidated subsidiary of BHE. PacifiCorp's common stock is indirectly owned by BHE, 666 Grand Avenue, Suite 500, Des Moines, Iowa 50309-2580. BHE is a consolidated subsidiary of Berkshire Hathaway that, as of January 31, 2020, owns 90.9% of BHE's common stock. The balance of BHE's common stock is beneficially owned by Walter Scott, Jr. (along with his family members and related or affiliated entities), a member of BHE's Board of Directors, and Gregory E. Abel, BHE's Chairman.

None of PacifiCorp's executive officers or directors owns shares of its preferred stock. The following table sets forth certain information regarding the beneficial ownership of BHE's common stock and the Class A and Class B shares of Berkshire Hathaway common stock held by each of PacifiCorp's directors, executive officers and all of its directors and executive officers as a group as of January 31, 2020:

 
 
BHE
 
Berkshire Hathaway
 
 
Common Stock
 
Class A Common Stock
 
Class B Common Stock
Beneficial Owner
 
Number of Shares Beneficially Owned(1)
 
Percentage of Class(1)
 
Number of Shares Beneficially Owned(1)
 
Percentage of Class(1)
 
Number of Shares Beneficially Owned(1)
 
Percentage of Class(1)
 
 
 
 
 
 
 
 
 
 
 
 
 
William J. Fehrman
 

 

 

 

 

 

Stefan A. Bird
 

 

 

 

 

 

Patrick J. Goodman
 

 

 
5

 
*

 
786

 
*

Natalie L. Hocken
 

 

 

 

 

 

Nikki L. Kobliha
 

 

 

 

 

 

Gary W. Hoogeveen
 

 

 

 

 
1,073

 
*

All executive officers and directors as a group (6 persons)
 

 

 
5

 
*

 
1,859

 
*


*    Indicates beneficial ownership of less than one percent of all outstanding shares.
(1)
Includes shares of which the listed beneficial owner is deemed to have the right to acquire beneficial ownership under Rule 13d-3(d) under the Securities Exchange Act, including, among other things, shares which the listed beneficial owner has the right to acquire within 60 days.


387


Item 13.
Certain Relationships and Related Transactions, and Director Independence

BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER AND SIERRA PACIFIC

Information required by Item 13 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.

PACIFICORP

Certain Relationships and Related Transactions

The Berkshire Hathaway Inc. Code of Business Conduct and Ethics and the BHE Code of Business Conduct, or the Codes, which apply to all of PacifiCorp's directors, officers and employees and those of its subsidiaries, generally govern the review, approval or ratification of any related-person transaction. A related-person transaction is one in which PacifiCorp or any of its subsidiaries participate and in which one or more of PacifiCorp's directors, executive officers, holders of more than five percent of its voting securities or any of such persons' immediate family members have a direct or indirect material interest.

Under the Codes, all of PacifiCorp's directors and executive officers (including those of its subsidiaries) must disclose to PacifiCorp's legal department any material transaction or relationship that reasonably could be expected to give rise to a conflict with its interests. No action may be taken with respect to such transaction or relationship until approved by the legal department. For PacifiCorp's chief executive officer and chief financial officer, prior approval for any such transaction or relationship must be given by Berkshire Hathaway's audit committee. In addition, prior legal department approval must be obtained before a director or executive officer can accept employment, offices or board positions in other for-profit businesses, or engage in his or her own business that raises a potential conflict or appearance of conflict with PacifiCorp's interests.

Under an intercompany administrative services agreement PacifiCorp has entered into with BHE and its other subsidiaries, the costs of certain administrative services provided by BHE to PacifiCorp or by PacifiCorp to BHE, or shared with BHE and other subsidiaries, are directly charged or allocated to the entity receiving such services. This agreement has been filed with the regulatory commissions in the states where PacifiCorp serves retail customers. PacifiCorp also provides an annual report of all transactions with its affiliates to its state regulatory commissions, who have the authority to refuse recovery in rates for payments PacifiCorp makes to its affiliates deemed to have the effect of subsidizing the separate business activities of BHE or its other subsidiaries.

Refer to Note 21 of the Notes to the Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for additional information regarding related-party transactions.

Director Independence

Because PacifiCorp's common stock is indirectly, wholly owned by BHE and its Board of Directors consists of BHE and PacifiCorp employees, PacifiCorp is not required to have independent directors or audit, nominating or compensation committees consisting of independent directors.

Based on the standards of the New York Stock Exchange LLC, on which the common stock of PacifiCorp's ultimate parent company, Berkshire Hathaway, is listed, PacifiCorp's Board of Directors has determined that none of its directors are considered independent because of their employment by BHE or PacifiCorp.


388


Item 14.
Principal Accountant Fees and Services

The following table shows the fees paid or accrued by each Registrant for audit and audit-related services and fees paid for tax and all other services rendered by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu Limited, and their respective affiliates (collectively, the "Deloitte Entities") for each of the last two years (in millions):

 
Berkshire
 
 
 
 
 
 
 
 
 
 
 
Hathaway
 
 
 
MidAmerican
 
MidAmerican
 
Nevada
 
Sierra
 
Energy(1)
 
PacifiCorp
 
Funding(1)
 
Energy
 
Power
 
Pacific
2019
 
 
 
 
 
 
 
 
 
 
 
Audit fees(2)
$
9.7

 
$
1.5

 
$
1.4

 
$
1.2

 
$
0.9

 
$
0.9

Audit-related fees(3)
0.9

 
0.4

 
0.2

 
0.2

 

 

Tax fees(4)
0.1

 

 

 

 

 

Total
$
10.7

 
$
1.9

 
$
1.6

 
$
1.4

 
$
0.9

 
$
0.9

 
 
 
 
 
 
 
 
 
 
 
 
2018
 
 
 
 
 
 
 
 
 
 
 
Audit fees(2)
$
9.6

 
$
1.6

 
$
1.2

 
$
1.1

 
$
0.9

 
$
0.9

Audit-related fees(3)
0.8

 
0.3

 
0.2

 
0.2

 

 

Tax fees(4)
0.1

 

 

 

 

 

Total
$
10.5

 
$
1.9

 
$
1.4

 
$
1.3

 
$
0.9

 
$
0.9


(1)
The reported fees for Berkshire Hathaway Energy include those fees reported for PacifiCorp, MidAmerican Funding, Nevada Power and Sierra Pacific while the reported fees for MidAmerican Funding include those fees reported for MidAmerican Energy.
(2)
Audit fees include fees for the audit of the consolidated financial statements and interim reviews of the quarterly financial statements for each Registrant, audit services provided in connection with required statutory audits of certain of BHE's subsidiaries and comfort letters, consents and other services related to SEC matters for each Registrant.
(3)
Audit-related fees primarily include fees for assurance and related services for any other statutory or regulatory requirements, audits of certain employee benefit plans and consultations on various accounting and reporting matters.
(4)
Tax fees include fees for services relating to tax compliance, tax planning and tax advice. These services include assistance regarding federal, state and international tax compliance, tax return preparation and tax audits.

The audit committee has considered whether the non-audit services provided to the Registrants by the Deloitte Entities impaired the independence of the Deloitte Entities and concluded that they did not. All of the services performed by the Deloitte Entities were pre-approved in accordance with the pre-approval policy adopted by the audit committee. The policy provides guidelines for the audit, audit-related, tax and other non-audit services that may be provided by the Deloitte Entities to the Registrants. The policy (a) identifies the guiding principles that must be considered by the audit committee in approving services to ensure that the Deloitte Entities' independence is not impaired; (b) describes the audit, audit-related and tax services that may be provided and the non-audit services that are prohibited; and (c) sets forth pre-approval requirements for all permitted services. Under the policy, requests to provide services that require specific approval by the audit committee will be submitted to the audit committee by both the Registrants' independent auditor and BHE's Chief Financial Officer. All requests for services to be provided by the independent auditor that do not require specific approval by the audit committee will be submitted to BHE's Chief Financial Officer and must include a detailed description of the services to be rendered. BHE's Chief Financial Officer will determine whether such services are included within the list of services that have received the general pre-approval of the audit committee. The audit committee will be informed on a timely basis of any such services rendered by the independent auditor.

389


PART IV

Item 15.
Exhibits and Financial Statement Schedules

(a)
Financial Statements and Schedules
 
 
 
 
 
 
 
 
(1)
Financial Statements
 
 
 
 
 
 
 
 
 
The financial statements of all Registrants are included in their respective Item 8 of this Form 10-K.
 
 
 
 
 
 
 
 
 
 
(2)
Financial Statement Schedules
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Schedules not listed above have been omitted because they are either not applicable, not required or the information required to be set forth therein is included on the Consolidated Financial Statements or notes thereto.
 
 
 
 
 
 
 
 
(3)
 
 
 
 
 
 
 
 
 
(b)
Exhibits
 
 
 
 
 
 
 
 
 
 
 
 
 
(c)
Financial statements required by Regulation S-X, which are excluded from the Annual Report by Rule 14a-3(b).
 
 
 
 
 
 
 
 


Item 16.
Form 10-K Summary

None.


390


Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
CONDENSED BALANCE SHEETS
(Amounts in millions)

 
As of December 31,
 
2019
 
2018
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
13

 
$
9

Accounts receivable - affiliate
87

 
100

Notes receivable - affiliate
181

 
156

Income tax receivable
3

 
103

Other current assets
8

 
15

Total current assets
292

 
383

 
 
 
 
Investments in subsidiaries
40,204

 
36,602

Other investments
1,300

 
1,579

Goodwill
1,221

 
1,221

Other assets
695

 
546

 
 
 
 
Total assets
$
43,712

 
$
40,331

LIABILITIES AND EQUITY
Current liabilities:
 
 
 
Accounts payable and other current liabilities
$
194

 
$
183

Notes payable - affiliate
240

 
328

Short-term debt
1,590

 
983

Current portion of BHE senior debt
350

 

Total current liabilities
2,374

 
1,494

 
 
 
 
BHE senior debt
8,231

 
8,577

BHE junior subordinated debentures
100

 
100

Notes payable - affiliate
2

 
1

Other long-term liabilities
530

 
543

Total liabilities
11,237

 
10,715

 
 
 
 
Equity:
 
 
 
BHE shareholders' equity:
 
 
 
Common stock - 115 shares authorized, no par value, 77 shares issued and outstanding

 

Additional paid-in capital
6,389

 
6,371

Long-term income tax receivable
(530
)
 
(457
)
Retained earnings
28,296

 
25,624

Accumulated other comprehensive loss, net
(1,706
)
 
(1,945
)
Total BHE shareholders' equity
32,449

 
29,593

Noncontrolling interest
26

 
23

Total equity
32,475

 
29,616

 
 
 
 
Total liabilities and equity
$
43,712

 
$
40,331


The accompanying notes are an integral part of this financial statement schedule.

391


Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF OPERATIONS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
General and administration
$
49

 
$
21

 
$
55

Depreciation and amortization
5

 
4

 
4

Total operating expenses
54

 
25

 
59

 
 
 
 
 
 
Operating loss
(54
)
 
(25
)
 
(59
)
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
Interest expense
(452
)
 
(438
)
 
(475
)
Other, net
(271
)
 
(537
)
 
(369
)
Total other income (expense)
(723
)
 
(975
)
 
(844
)
 
 
 
 
 
 
Loss before income tax benefit and equity income
(777
)
 
(1,000
)
 
(903
)
Income tax benefit
(312
)
 
(513
)
 
(335
)
Equity income
3,419

 
3,058

 
3,441

Net income
2,954

 
2,571

 
2,873

Net income attributable to noncontrolling interest
3

 
3

 
3

Net income attributable to BHE shareholders
$
2,951

 
$
2,568

 
$
2,870


The accompanying notes are an integral part of this financial statement schedule.


392


Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Net income
$
2,954

 
$
2,571

 
$
2,873

Other comprehensive income (loss), net of tax
239

 
(462
)
 
1,113

Comprehensive income
3,193

 
2,109

 
3,986

Comprehensive income attributable to noncontrolling interests
3

 
3

 
3

Comprehensive income attributable to BHE shareholders
$
3,190

 
$
2,106

 
$
3,983


The accompanying notes are an integral part of this financial statement schedule.



393


Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF CASH FLOWS
(In millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Cash flows from operating activities
$
1,780

 
$
1,885

 
$
2,450

 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
Investments in subsidiaries
(1,972
)
 
(1,791
)
 
(1,566
)
Purchases of investments
(42
)
 
(44
)
 
(71
)
Proceeds from sale of investments
42

 
45

 
68

Notes receivable from affiliate, net
(112
)
 
(72
)
 
(305
)
Other, net
(5
)
 
(22
)
 
(8
)
Net cash flows from investing activities
(2,089
)
 
(1,884
)
 
(1,882
)
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
Proceeds from BHE senior debt

 
3,166

 

Repayments of BHE senior debt

 
(1,045
)
 
(1,379
)
Repayments of BHE subordinated debt

 

 
(944
)
Common stock purchases
(293
)
 
(107
)
 
(19
)
Net proceeds from (repayments of) short-term debt
607

 
(2,348
)
 
2,498

Tender offer premium paid

 

 
(406
)
Other, net
(1
)
 
(4
)
 
(5
)
Net cash flows from financing activities
313

 
(338
)
 
(255
)
 
 
 
 
 
 
Net change in cash and cash equivalents
4

 
(337
)
 
313

Cash and cash equivalents at beginning of year
9

 
346

 
33

Cash and cash equivalents at end of year
$
13

 
$
9

 
$
346


The accompanying notes are an integral part of this financial statement schedule.



394


Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
NOTES TO CONDENSED FINANCIAL STATEMENTS

Basis of Presentation - The condensed financial information of BHE investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in subsidiaries are recorded in the Condensed Balance Sheets. The income from operations of subsidiaries is reported on a net basis as equity income in the Condensed Statements of Operations.

Other investments - BHE's investment in BYD Company Limited ("BYD") common stock is accounted for as a marketable security with changes in fair value recognized in net income. As of December 31, 2019 and 2018, the fair value of BHE's investment in BYD common stock was $1,122 million and $1,435 million

Dividends and distributions from subsidiaries - Cash dividends paid to BHE by its subsidiaries for the years ended December 31, 2019, 2018 and 2017 were $2.0 billion, $2.3 billion and $3.0 billion, respectively. In January 2020, BHE received cash dividends from its subsidiaries totaling $118 million.

Guarantees and commitments - BHE has issued guarantees and letters of credit in respect of subsidiary and equity method investments aggregating $277 million and commitments, subject to satisfaction of certain specified conditions, to provide equity contributions in support of renewable tax equity investments totaling $2.4 billion.

See the notes to the consolidated BHE financial statements in Part II, Item 8 for other disclosures regarding long-term obligations (Notes 9, 10 and 11) and shareholders' equity (Note 18).


395


Schedule II
BERKSHIRE HATHAWAY ENERGY COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2019
(Amounts in millions)

 
 
Column B
 
Column C
 
 
Column E
 
 
Balance at
 
Charged
 
 
 
 
 
Balance
Column A
 
Beginning
 
to
 
Acquisition
 
Column D
 
at End
Description
 
of Year
 
Income
 
Reserves
 
Deductions
 
of Year
 
 
 
 
 
 
 
 
 
 
 
Reserves Deducted From Assets To Which They Apply:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reserve for uncollectible accounts receivable:
 
 
 
 
 
 
 
 
 
 
Year ended 2019
 
$
42

 
$
47

 
$

 
$
(45
)
 
$
44

Year ended 2018
 
40

 
43

 

 
(41
)
 
42

Year ended 2017
 
33

 
42

 

 
(35
)
 
40

 
 
 
 
 
 
 
 
 
 
 
Reserves Not Deducted From Assets(1):
 
 
 
 
 
 
 
 
 
 
Year ended 2019
 
$
13

 
$
4

 
$

 
$
(5
)
 
$
12

Year ended 2018
 
13

 
6

 

 
(6
)
 
13

Year ended 2017
 
13

 
7

 

 
(7
)
 
13


The notes to the consolidated BHE financial statements are an integral part of this financial statement schedule.

(1)
Reserves not deducted from assets relate primarily to estimated liabilities for losses retained by BHE for workers compensation, public liability and property damage claims.


396


Schedule I
MIDAMERICAN FUNDING, LLC
PARENT COMPANY ONLY
CONDENSED BALANCE SHEETS
(Amounts in millions)

 
As of December 31,
 
2019
 
2018
ASSETS
Current assets:
 
 
 
Receivables from affiliates
$
2

 
$
2

Total current assets
2

 
2

 
 
 
 
Investments in and advances to subsidiaries
8,346

 
8,002

 
 
 
 
Total assets
$
8,348

 
$
8,004

 
 
 
 
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
 
 
 
Interest accrued and other current liabilities
$
6

 
$
6

 
 
 
 
Payable to affiliate
1

 
429

Long-term debt
240

 
240

Total liabilities
247

 
675

 
 
 
 
Member's equity:
 
 
 
Paid-in capital
1,679

 
1,679

Retained earnings
6,422

 
5,650

Total member's equity
8,101

 
7,329

 
 
 
 
Total liabilities and member's equity
$
8,348

 
$
8,004


The accompanying notes are an integral part of this financial statement schedule.

397


Schedule I
MIDAMERICAN FUNDING, LLC
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF OPERATIONS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Other income and (expense):
 
 
 
 
 
Interest expense
$
(16
)
 
$
(16
)
 
$
(22
)
Other, net

 

 
(30
)
Loss before income taxes
(16
)
 
(16
)
 
(52
)
Income tax benefit
(5
)
 
(5
)
 
(22
)
Equity in undistributed earnings of subsidiaries
792

 
680

 
604

Net income
$
781

 
$
669

 
$
574


The accompanying notes are an integral part of this financial statement schedule.



MIDAMERICAN FUNDING, LLC
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF CASH FLOWS
(In millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Net cash flows from operating activities
$
(12
)
 
$
2

 
$
(15
)
 
 
 
 
 
 
Net cash flows from investing activities

 

 

 
 
 
 
 
 
Net cash flows from financing activities:
 
 
 
 
 
Repayment of long-term debt

 

 
(86
)
Tender offer premium paid

 

 
(29
)
Net change in amounts payable to subsidiary
12

 
(2
)
 
130

Net cash flows from financing activities
12

 
(2
)
 
15

 
 
 
 
 
 
Net change in cash and cash equivalents

 

 

Cash and cash equivalents at beginning of year

 

 

Cash and cash equivalents at end of year
$

 
$

 
$


The accompanying notes are an integral part of this financial statement schedule.

398


Schedule I
MIDAMERICAN FUNDING, LLC
PARENT COMPANY ONLY
NOTES TO CONDENSED FINANCIAL STATEMENTS

Incorporated by reference are MidAmerican Funding, LLC and Subsidiaries Consolidated Statements of Changes in Equity for the three years ended December 31, 2019 in Part II, Item 8.

Basis of Presentation - The condensed financial information of MidAmerican Funding, LLC's ("MidAmerican Funding's") investments in subsidiaries is presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in and advances to subsidiaries are recorded on the Condensed Balance Sheets. The income from operations of the subsidiaries is reported on a net basis as equity in undistributed earnings of subsidiary companies on the Condensed Statements of Operations. The Condensed Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2019, 2018 and 2017.

Payable to Affiliate - MHC, Inc. ("MHC") settles all obligations of MidAmerican Funding including primarily interest costs on, and repayments of, MidAmerican Funding's long-term debt and income taxes. MHC paid $12 million and $130 million in 2019 and 2017, respectively, and received $2 million in 2018 on behalf of MidAmerican Funding. In 2019, MHC transferred to MidAmerican Funding $440 million of its receivable from MidAmerican Funding in the form of a dividend.

Distribution to Parent - In 2019, MidAmerican Funding recorded a noncash dividend of $8 million for the transfer to BHE of corporate aircraft owned by MHC.

See the notes to the consolidated MidAmerican Funding financial statements in Part II, Item 8 for other disclosures.



399


Schedule I
MHC INC.
PARENT COMPANY ONLY
CONDENSED BALANCE SHEETS
(Amounts in millions)

 
As of December 31,
 
2019
 
2018
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
1

 
$
1

 
 
 
 
Receivable from parent
1

 
429

Investments and nonregulated property, net
2

 
12

Goodwill
1,270

 
1,270

Investments in and advances to subsidiaries
7,260

 
6,465

 
 
 
 
Total assets
$
8,534

 
$
8,177

 
 
 
 
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
 
 
 
Payables to affiliates
$
186

 
$
172

Accrued income taxes
2

 

 
 
 
 
Deferred income taxes

 
3

Total liabilities
188

 
175

 
 
 
 
Shareholder's equity:
 
 
 
Paid-in capital
2,430

 
2,430

Retained earnings
5,916

 
5,572

Total shareholder's equity
8,346

 
8,002

 
 
 
 
Total liabilities and shareholder's equity
$
8,534

 
$
8,177


The accompanying notes are an integral part of this financial statement schedule.

400



Schedule I
MHC INC.
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF OPERATIONS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Other income
$
1

 
$
1

 
$
1

Other interest expense
5

 
4

 

(Loss) income before income taxes
(4
)
 
(3
)
 
1

Income tax benefit
(1
)
 
(1
)
 

Equity in undistributed earnings of subsidiaries
795

 
682

 
603

Net income
$
792

 
$
680

 
$
604


The accompanying notes are an integral part of this financial statement schedule.




MHC INC.
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF CASH FLOWS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Net cash flows from operating activities
$
(4
)
 
$
5

 
$
(1
)
 
 
 
 
 
 
Net cash flows from investing activities:
 
 
 
 
 
Capital expenditures

 

 
(2
)
Net change in amounts receivable from parent
(12
)
 
2

 
(130
)
Net cash flows from investing activities
(12
)
 
2

 
(132
)
 
 
 
 
 
 
Net cash flows from financing activities:
 
 
 
 
 
Net change in amounts payable to subsidiaries
1

 
2

 
(1
)
Net change in note payable to Berkshire Hathaway Energy Company
15

 
(8
)
 
133

Net cash flows from financing activities
16

 
(6
)
 
132

 
 
 
 
 
 
Net change in cash and cash equivalents

 
1

 
(1
)
Cash and cash equivalents at beginning of year
1

 

 
1

Cash and cash equivalents at end of year
$
1

 
$
1

 
$


The accompanying notes are an integral part of this financial statement schedule.

401



Schedule I
MHC INC.
PARENT COMPANY ONLY
NOTES TO CONDENSED FINANCIAL STATEMENTS

Incorporated by reference are MHC Inc. and Subsidiaries Consolidated Statements of Changes in Equity for the three years ended December 31, 2019, in Part IV, Item 15(c).

Basis of Presentation - The condensed financial information of MHC Inc.'s ("MHC's") investments in subsidiaries is presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in and advances to subsidiaries are recorded on the Condensed Balance Sheets. The income from operations of the subsidiaries is reported on a net basis as equity in undistributed earnings of subsidiary companies on the Condensed Statements of Operations. The Condensed Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2019, 2018 and 2017.

Receivable from Parent - MHC settles all obligations of MidAmerican Funding, LLC ("MidAmerican Funding") including primarily interest costs on, and repayments of, MidAmerican Funding's long-term debt and income taxes. MHC paid $12 million and $130 million in 2019 and 2017, respectively, and received $2 million in 2018 on behalf of MidAmerican Funding.

Dividends Paid- In 2019, MHC recorded noncash dividends of $440 million for the transfer to MidAmerican Funding of MHC's receivable from MidAmerican Funding and $8 million for the transfer to BHE of corporate aircraft owned by MHC.

See the notes to the consolidated MHC financial statements in Part IV, Item 15(c) for other disclosures.


402


Schedule II
MIDAMERICAN ENERGY COMPANY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2019
(Amounts in millions)

 
 
Column B
 
Column C
 
 
 
Column E
 
 
Balance at
 
Additions
 
 
 
Balance
Column A
 
Beginning
 
Charged
 
Column D
 
at End
Description
 
of Year
 
to Income
 
Deductions
 
of Year
 
 
 
 
 
 
 
 
 
Reserves Deducted From Assets To Which They Apply:
 
 
 
 
 
 
 
 
Reserve for uncollectible accounts receivable:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year ended 2019
 
$
7

 
$
9

 
$
(11
)
 
$
5

 
 
 
 
 
 
 
 
 
Year ended 2018
 
$
7

 
$
8

 
$
(8
)
 
$
7

 
 
 
 
 
 
 
 
 
Year ended 2017
 
$
7

 
$
8

 
$
(8
)
 
$
7

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reserves Not Deducted From Assets(1):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year ended 2019
 
$
13

 
$
4

 
$
(5
)
 
$
12

 
 
 
 
 
 
 
 
 
Year ended 2018
 
$
13

 
$
6

 
$
(6
)
 
$
13

 
 
 
 
 
 
 
 
 
Year ended 2017
 
$
13

 
$
7

 
$
(7
)
 
$
13

(1)
Reserves not deducted from assets include estimated liabilities for losses retained by MidAmerican Energy for workers compensation, public liability and property damage claims.


403


Schedule II
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
MHC INC. AND SUBSIDIARIES
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2019
(Amounts in millions)

 
 
Column B
 
Column C
 
 
 
Column E
 
 
Balance at
 
Additions
 
 
 
Balance
Column A
 
Beginning
 
Charged
 
Column D
 
at End
Description
 
of Year
 
to Income
 
Deductions
 
of Year
 
 
 
 
 
 
 
 
 
Reserves Deducted From Assets To Which They Apply:
 
 
 
 
 
 
 
 
Reserve for uncollectible accounts receivable:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year ended 2019
 
$
7

 
$
9

 
$
(11
)
 
$
5

 
 
 
 
 
 
 
 
 
Year ended 2018
 
$
7

 
$
8

 
$
(8
)
 
$
7

 
 
 
 
 
 
 
 
 
Year ended 2017
 
$
7

 
$
8

 
$
(8
)
 
$
7

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reserves Not Deducted From Assets (1):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year ended 2019
 
$
13

 
$
4

 
$
(5
)
 
$
12

 
 
 
 
 
 
 
 
 
Year ended 2018
 
$
13

 
$
6

 
$
(6
)
 
$
13

 
 
 
 
 
 
 
 
 
Year ended 2017
 
$
13

 
$
7

 
$
(7
)
 
$
13

(1)
Reserves not deducted from assets include primarily estimated liabilities for losses retained by MidAmerican Funding and MHC for workers compensation, public liability and property damage claims.


404


The accompanying Consolidated Financial Statements of MHC Inc., the direct wholly owned subsidiary of MidAmerican Funding, are being provided pursuant to Rule 3-16 of the U. S. Securities and Exchange Commission's Regulation S-X. The purpose of these financial statements is to provide information about the assets and equity interests that collateralize MidAmerican Funding's long-term debt and that, upon the occurrence of any triggering event under the collateral agreement, would be available to satisfy the applicable debt obligations.

MHC Inc. and its subsidiaries
 


405



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholder of
MHC Inc.
Des Moines, Iowa

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of MHC Inc. and subsidiaries ("MHC") as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes and the schedules listed in the Index at Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of MHC as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of MHC's management. Our responsibility is to express an opinion on MHC's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to MHC in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. MHC is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of MHC's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.


/s/ Deloitte & Touche LLP

Des Moines, Iowa
February 21, 2020

We have served as MHC's auditor since 1999.


406


MHC INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)

 
As of December 31,
 
2019
 
2018
 
 
 
 
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
288

 
$
1

Trade receivables, net
291

 
363

Inventories
226

 
204

Other current assets
90

 
90

Total current assets
895

 
658

 
 
 
 
Property, plant and equipment, net
18,377

 
16,169

Goodwill
1,270

 
1,270

Regulatory assets
289

 
273

Investments and restricted investments
820

 
710

Receivable from affiliate
1

 
429

Other assets
188

 
121

 
 
 
 
Total assets
$
21,840

 
$
19,630


The accompanying notes are an integral part of these consolidated financial statements.

407


MHC INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)

 
As of December 31,
 
2019
 
2018
 
 
 
 
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
 
 
 
Accounts payable
$
520

 
$
575

Accrued interest
78

 
53

Accrued property, income and other taxes
226

 
300

Note payable to affiliate
171

 
156

Short-term debt

 
240

Current portion of long-term debt

 
500

Other current liabilities
220

 
122

Total current liabilities
1,215

 
1,946

 
 
 
 
Long-term debt
7,208

 
4,879

Regulatory liabilities
1,406

 
1,620

Deferred income taxes
2,621

 
2,319

Asset retirement obligations
704

 
552

Other long-term liabilities
340

 
312

Total liabilities
13,494

 
11,628

 
 
 
 
Commitments and contingencies (Note 13)
 
 
 
 
 
 
 
Shareholder's equity:
 
 
 
Common stock - no par value, 1,000 shares authorized, 1,000 shares issued and outstanding

 

Additional paid-in capital
2,430

 
2,430

Retained earnings
5,916

 
5,572

Total shareholder's equity
8,346

 
8,002

 
 
 
 
Total liabilities and shareholder's equity
$
21,840

 
$
19,630


The accompanying notes are an integral part of these consolidated financial statements.


408


MHC INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
Operating revenue:
 
 
 
 
 
Regulated electric
$
2,237

 
$
2,283

 
$
2,108

Regulated natural gas and other
690

 
770

 
738

Total operating revenue
2,927

 
3,053

 
2,846

 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
Cost of fuel and energy
399

 
487

 
434

Cost of natural gas purchased for resale and other
412

 
469

 
447

Operations and maintenance
801

 
813

 
802

Depreciation and amortization
639

 
609

 
500

Property and other taxes
127

 
125

 
119

Total operating expenses
2,378

 
2,503

 
2,302

 
 
 
 
 
 
Operating income
549

 
550

 
544

 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
Interest expense
(286
)
 
(231
)
 
(215
)
Allowance for borrowed funds
27

 
20

 
15

Allowance for equity funds
78

 
53

 
41

Other, net
52

 
31

 
39

Total other income (expense)
(129
)
 
(127
)
 
(120
)
 
 
 
 
 
 
Income before income tax benefit
420

 
423

 
424

Income tax benefit
(372
)
 
(257
)
 
(180
)
 
 
 
 
 
 
Net income
$
792

 
$
680

 
$
604


The accompanying notes are an integral part of these consolidated financial statements.


409


MHC INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Amounts in millions)

 
 
 
 
 
 
 
Total
 
Common
 
Paid-in
 
Retained
 
Shareholder's
 
Stock
 
Capital
 
Earnings
 
Equity
 
 
 
 
 
 
 
 
Balance, December 31, 2016
$

 
$
2,430

 
$
4,288

 
$
6,718

Net income

 

 
604

 
604

Balance, December 31, 2017

 
2,430

 
4,892

 
7,322

Net income

 

 
680

 
680

Balance, December 31, 2018

 
2,430

 
5,572

 
8,002

Net income

 

 
792

 
792

Dividends declared

 

 
(448
)
 
(448
)
Balance, December 31, 2019
$

 
$
2,430

 
$
5,916

 
$
8,346


The accompanying notes are an integral part of these consolidated financial statements.


410


MHC INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)

 
Years Ended December 31,
 
2019
 
2018
 
2017
Cash flows from operating activities:
 
 
 
 
 
Net income
$
792

 
$
680

 
$
604

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
 
 
Depreciation and amortization
639

 
609

 
500

Amortization of utility plant to other operating expenses
33

 
34

 
34

Allowance for equity funds
(78
)
 
(53
)
 
(41
)
Deferred income taxes and amortization of investment tax credits
152

 
32

 
334

Other, net
(7
)
 
16

 
(13
)
Changes in other operating assets and liabilities:
 
 
 
 
 
Trade receivables and other assets
56

 
(19
)
 
(63
)
Inventories
(22
)
 
41

 
19

Derivative collateral, net
(1
)
 
(1
)
 
2

Contributions to pension and other postretirement benefit plans, net
(10
)
 
(13
)
 
(11
)
Accrued property, income and other taxes, net
(74
)
 
217

 
(42
)
Accounts payable and other liabilities
7

 
(29
)
 
72

Net cash flows from operating activities
1,487

 
1,514

 
1,395

 
 
 
 
 
 
Net cash flows from investing activities:
 
 
 
 
 
Capital expenditures
(2,810
)
 
(2,332
)
 
(1,773
)
Purchases of marketable securities
(156
)
 
(263
)
 
(143
)
Proceeds from sales of marketable securities
138

 
223

 
137

Proceeds from sales of other investments
1

 
17

 
2

Other investment proceeds
13

 
15

 
1

Net change in amounts receivable from parent
(12
)
 
2

 
(130
)
Other, net
13

 
30

 
(3
)
Net cash flows from investing activities
(2,813
)
 
(2,308
)
 
(1,909
)
 
 
 
 
 
 
Net cash flows from financing activities:
 
 
 
 
 
Proceeds from long-term debt
2,326

 
687

 
990

Repayments of long-term debt
(500
)
 
(350
)
 
(255
)
Net change in amounts receivable from/payable to affiliates
15

 
(8
)
 
133

Net (repayments of) proceeds from short-term debt
(240
)
 
240

 
(99
)
Other, net
(1
)
 

 

Net cash flows from financing activities
1,600

 
569

 
769

 
 
 
 
 
 
Net change in cash and cash equivalents and restricted cash and cash equivalents
274

 
(225
)
 
255

Cash and cash equivalents and restricted cash and cash equivalents at beginning of year
57

 
282

 
27

Cash and cash equivalents and restricted cash and cash equivalents at end of year
$
331

 
$
57

 
$
282


The accompanying notes are an integral part of these consolidated financial statements.


411


MHC INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)
Organization and Operations

MHC Inc. ("MHC") is an Iowa corporation with MidAmerican Funding, LLC ("MidAmerican Funding") as its sole shareholder. MidAmerican Funding is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). MHC constitutes substantially all of MidAmerican Funding's assets, liabilities and business activities except those related to MidAmerican Funding's long-term debt securities. MHC conducts no business other than the ownership of its subsidiaries and related corporate services. MHC's principal subsidiary is MidAmerican Energy Company ("MidAmerican Energy"), a public utility with electric and natural gas operations, and its direct wholly owned nonregulated subsidiary is Midwest Capital Group, Inc.

(2)
Summary of Significant Accounting Policies

In addition to the following significant accounting policies, refer to Note 2 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K for significant accounting policies of MHC.

Basis of Consolidation and Presentation

The Consolidated Financial Statements include the accounts of MHC and its subsidiaries in which it held a controlling financial interest as of the date of the financial statement. Intercompany accounts and transactions have been eliminated, other than those between rate-regulated operations. MHC has evaluated subsequent events through February 21, 2020, which is the date the Consolidated Financial Statements were issued. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2019, 2018 and 2017.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired when MidAmerican Funding purchased MHC. MHC evaluates goodwill for impairment at least annually and completed its annual review as of October 31. When evaluating goodwill for impairment, MHC estimates the fair value of the reporting unit. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the identifiable assets, including identifiable intangible assets, and liabilities of the reporting unit are estimated at fair value as of the current testing date. The excess of the estimated fair value of the reporting unit over the current estimated fair value of net assets establishes the implied value of goodwill. The excess of the recorded goodwill over the implied goodwill value is charged to earnings as an impairment loss. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. MHC uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings and regulatory asset value; and an appropriate discount rate. In estimating future cash flows, MHC incorporates current market information, as well as historical factors. As such, the determination of fair value incorporates significant unobservable inputs. During 2019, 2018 and 2017, MHC did not record any goodwill impairments.

(3)    Property, Plant and Equipment, Net

Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K. In addition to MidAmerican Energy's property, plant and equipment, net, MHC had gross nonregulated property of $3 million and $24 million as of December 31, 2019 and 2018, respectively, and related accumulated depreciation and amortization of $1 million and $12 million as of December 31, 2019 and 2018, respectively, which, as of December 31, 2018, consisted primarily of a corporate aircraft owned by MHC. In 2019, MHC transferred the aircraft by dividend to MidAmerican Funding, which transferred it to BHE.


(4)    Jointly Owned Utility Facilities

Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K.

(5)    Regulatory Matters

Refer to Note 5 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K.

412



(6)
Investments and Restricted Investments

Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K. In addition to MidAmerican Energy's investments and restricted investments, MHC had corporate-owned life insurance policies in a Rabbi trust owned by MHC with a total cash surrender value of $2 million as of December 31, 2019 and 2018.

(7)    Short-Term Debt and Credit Facilities

Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K. In addition to MidAmerican Energy's credit facilities, MHC has a $4 million unsecured credit facility, which expires in June 2019 and has a variable interest rate based on the Eurodollar rate plus a spread. As of December 31, 2019 and 2018, there were no borrowings outstanding under this credit facility. As of December 31, 2019, MHC was in compliance with the covenants of its credit facility.

(8)
Long-Term Debt

Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K.

(9)
Income Taxes

MHC's income tax benefit from continuing operations consists of the following for the years ended December 31 (in millions):
 
2019
 
2018
 
2017
Current:
 
 
 
 
 
Federal
$
(477
)
 
$
(277
)
 
$
(489
)
State
(47
)
 
(12
)
 
(25
)
 
(524
)
 
(289
)
 
(514
)
Deferred:
 
 
 
 
 
Federal
164

 
42

 
338

State
(11
)
 
(9
)
 
(3
)
 
153

 
33

 
335

 
 
 
 
 
 
Investment tax credits
(1
)
 
(1
)
 
(1
)
Total
$
(372
)
 
$
(257
)
 
$
(180
)

A reconciliation of the federal statutory income tax rate to MHC's effective income tax rate applicable to income before income tax benefit from continuing operations is as follows for the years ended December 31:
 
2019
 
2018
 
2017
 
 
 
 
 
 
Federal statutory income tax rate
21
 %
 
21
 %
 
35
 %
Income tax credits
(90
)
 
(73
)
 
(68
)
State income tax, net of federal income tax benefit
(11
)
 
(4
)
 
(4
)
Effects of ratemaking
(8
)
 
(5
)
 
(7
)
Other, net
(1
)
 

 
1

Effective income tax rate
(89
)%
 
(61
)%
 
(43
)%

Income tax credits relate primarily to production tax credits ("PTC") earned by MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.


413


MHC's net deferred income tax liability consists of the following as of December 31 (in millions):
 
2019
 
2018
Deferred income tax assets:
 
 
 
Regulatory liabilities
$
368

 
$
405

Asset retirement obligations
234

 
164

Employee benefits
26

 
47

Other
76

 
85

Total deferred income tax assets
704

 
701

 
 
 
 
Deferred income tax liabilities:
 
 
 
Depreciable property
(3,253
)
 
(2,947
)
Regulatory assets
(68
)
 
(62
)
Other
(4
)
 
(11
)
Total deferred income tax liabilities
(3,325
)
 
(3,020
)
 
 
 
 
Net deferred income tax liability
$
(2,621
)
 
$
(2,319
)

As of December 31, 2019, MHC has available $51 million of state tax carryforwards, principally related to $745 million of net operating losses, that expire at various intervals between 2020 and 2038.

The United States Internal Revenue Service has closed its examination of MHC's income tax returns through December 31, 2011. The statute of limitations for MHC's state income tax returns have expired through December 31, 2009, with the exception of Iowa and Illinois, for which the statute of limitations have expired through December 31, 2015, except for the impact of any federal audit adjustments. The statute of limitations expiring for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.

A reconciliation of the beginning and ending balances of MHC's net unrecognized tax benefits is as follows for the years ended December 31 (in millions):
 
2019
 
2018
 
 
 
 
Beginning balance
$
10

 
$
12

Additions based on tax positions related to the current year
5

 
4

Additions for tax positions of prior years
10

 
47

Reductions based on tax positions related to the current year
(5
)
 
(4
)
Reductions for tax positions of prior years
(12
)
 
(48
)
Interest and penalties

 
(1
)
Ending balance
$
8

 
$
10


As of December 31, 2019, MHC had unrecognized tax benefits totaling $27 million that, if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect MHC's effective income tax rate.


414


(10)
Employee Benefit Plans

Refer to Note 10 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K for additional information regarding MHC's pension, supplemental retirement and postretirement benefit plans.

Pension and postretirement costs allocated by MHC to its parent and other affiliates in each of the years ended December 31, were as follows (in millions):
 
2019
 
2018
 
2017
 
 
 
 
 
 
Pension costs
$
4

 
$
3

 
$
4

Other postretirement costs
(2
)
 
(2
)
 
(3
)

(11)
Asset Retirement Obligations

Refer to Note 11 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K.

(12)
Fair Value Measurements

Refer to Note 12 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K.

(13)
Commitments and Contingencies

Refer to Note 13 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K.

Legal Matters

MHC is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MHC does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

(14)    Revenue from Contracts with Customers

Refer to Note 14 of MidAmerican Energy's Notes to Financial Statements. Additionally, MHC had $2 million and $4 million of other revenue from contracts with customers for the year ended December 31, 2019 and 2018, respectively.

(15)    Other Income (Expense) - Other, Net

Other, net, as shown on the Consolidated Statements of Operations, includes the following other income (expense) items for the years ended December 31 (in millions):
 
2019
 
2018
 
2017
 
 
 
 
 
 
Non-service cost components of postretirement employee benefit plans
$
17

 
$
21

 
$
18

Corporate-owned life insurance income
24

 
6

 
13

Interest income and other, net
11

 
4

 
8

Total
$
52

 
$
31

 
$
39



415


(16)    Supplemental Cash Flow Information

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 2019 and 2018, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2019 and 2018 as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
 
As of December 31,
 
2019
 
2018
 
 
 
 
Cash and cash equivalents
$
288

 
$
1

Restricted cash and cash equivalents in other current assets
43

 
56

Total cash and cash equivalents and restricted cash and cash equivalents
$
331

 
$
57


The summary of supplemental cash flow information as of and for the years ending December 31 is as follows (in millions):
 
2019
 
2018
 
2017
Supplemental cash flow information:
 
 
 
 
 
Interest paid, net of amounts capitalized
$
228

 
$
201

 
$
193

Income taxes received, net
$
451

 
$
494

 
$
463

 
 
 
 
 
 
Supplemental disclosure of non-cash investing and financing transactions:
 
 
 
 
 
Accounts payable related to utility plant additions
$
337

 
$
371

 
$
224

Dividend of receivable from parent and corporate aircraft
$
448

 
$

 
$


(17)
Related Party Transactions

The companies identified as affiliates of MHC are Berkshire Hathaway and its subsidiaries, including BHE and its subsidiaries. The basis for the following transactions is provided for in service agreements between MHC and the affiliates.

MHC is reimbursed for charges incurred on behalf of its affiliates. The majority of these reimbursed expenses are for allocated general costs, such as insurance and building rent, and for employee wages, benefits and costs for corporate functions, such as information technology, human resources, treasury, legal and accounting. The amount of such reimbursements was $41 million, $44 million and $46 million for 2019, 2018 and 2017, respectively. Additionally, in 2018, MHC received $15 million from BHE for the transfer of corporate aircraft owned by MidAmerican Energy.

MHC reimbursed BHE in the amount of $14 million, $11 million and $7 million in 2019, 2018 and 2017, respectively, for its share of corporate expenses.

MidAmerican Energy purchases natural gas transportation and storage capacity services from Northern Natural Gas Company, a wholly owned subsidiary of BHE, and coal transportation services from BNSF Railway Company, a wholly owned subsidiary of Berkshire Hathaway, in the normal course of business at either tariffed or market prices. These purchases totaled $139 million, $127 million and $122 million in 2019, 2018 and 2017, respectively.

MHC has a $300 million revolving credit arrangement carrying interest at the 30-day LIBOR rate plus a spread to borrow from BHE. Outstanding balances are unsecured and due on demand. The outstanding balance was $171 million at an interest rate of 1.944% as of December 31, 2019, and $156 million at an interest rate of 2.629% as of December 31, 2018, and is reflected as note payable to affiliate on the Consolidated Balance Sheet.

BHE has a $100 million revolving credit arrangement carrying interest at the 30-day LIBOR rate plus a spread to borrow from MHC. Outstanding balances are unsecured and due on demand. There were no borrowings outstanding throughout 2019 and 2018.


416


MHC pays all obligations of and receives all payments to MidAmerican Funding, including primarily interest costs on MidAmerican Funding's long-term debt and income taxes. Additionally, in 2017, MHC paid for MidAmerican Funding's redemption of a portion of its long-term debt through a tender offer. On behalf of MidAmerican Funding, MHC paid net amounts of $12 million and $130 million in 2019 and 2017, respectively and received a net amount of $2 million for 2018.

MHC had accounts receivable from affiliates of $7 million and $433 million as of December 31, 2019 and 2018, respectively, that are reflected in receivables, net and receivable from affiliate on the Consolidated Balance Sheets. MHC also had accounts payable to affiliates of $11 million and $12 million as of December 31, 2019 and 2018, respectively, that are included in accounts payable on the Consolidated Balance Sheets. In 2019, MHC recorded noncash dividends of $440 million for the transfer to MidAmerican Funding of MHC's receivable from MidAmerican Funding and $8 million for the transfer to BHE of corporate aircraft owned by MHC.

MHC is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated United States federal income tax return. For current federal and state income taxes, MHC had a payable to BHE of $83 million and $156 million as of December 31, 2019 and 2018, respectively. MHC received net cash receipts for federal and state income taxes from BHE totaling $451 million, $494 million and $463 million for the years ended December 31, 2019, 2018 and 2017, respectively.

MHC recognizes the full amount of the funded status for its pension and postretirement plans, and amounts attributable to MHC's affiliates that have not previously been recognized through income are recognized as an intercompany balance with such affiliates. MHC adjusts these balances when changes to the funded status of the respective plans are recognized and does not intend to settle the balances currently. Amounts receivable from affiliates attributable to the funded status of employee benefit plans totaled $23 million and $20 million as of December 31, 2019 and 2018, respectively, and similar amounts payable to affiliates totaled $47 million and $36 million, as of December 31, 2019 and 2018, respectively. See Note 10 for further information pertaining to pension and postretirement accounting.

(18)
Segment Information

MHC has identified two reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. "Other" in the tables below consists principally of the nonregulated subsidiaries of MHC not engaged in the energy business. Refer to Note 9 for a discussion of items affecting income tax (benefit) expense for the regulated electric and natural gas operating segments.


417


The following tables provide information on a reportable segment basis (in millions):
 
Years Ended December 31,
 
2019
 
2018
 
2017
Operating revenue:
 
 
 
 
 
Regulated electric
$
2,237

 
$
2,283

 
$
2,108

Regulated natural gas
660

 
754

 
719

Other
30

 
16

 
19

Total operating revenue
$
2,927

 
$
3,053

 
$
2,846

 
 
 
 
 
 
Depreciation and amortization:
 
 
 
 
 
Regulated electric
$
593

 
$
565

 
$
458

Regulated natural gas
46

 
44

 
42

Total depreciation and amortization
$
639

 
$
609

 
$
500

 
 
 
 
 
 
Operating income:
 
 
 
 
 
Regulated electric
$
473

 
$
469

 
$
472

Regulated natural gas
71

 
81

 
72

Other
5

 

 

Total operating income
$
549

 
$
550

 
$
544

 
 
 
 
 
 
Interest expense:
 
 
 
 
 
Regulated electric
$
259

 
$
208

 
$
196

Regulated natural gas
22

 
19

 
18

Other
5

 
4

 
1

Total interest expense
$
286

 
$
231

 
$
215

 
 
 
 
 
 
Income tax (benefit) expense:
 
 
 
 
 
Regulated electric
$
(384
)
 
$
(273
)
 
$
(212
)
Regulated natural gas
12

 
16

 
29

Other

 

 
3

Total income tax (benefit) expense
$
(372
)
 
$
(257
)
 
$
(180
)
 
 
 
 
 
 
Net income:
 
 
 
 
 
Regulated electric
$
739

 
$
628

 
$
570

Regulated natural gas
52

 
54

 
35

Other
1

 
(2
)
 
(1
)
Net income
$
792

 
$
680

 
$
604

 
 
 
 
 
 
Capital expenditures:
 
 
 
 
 
Regulated electric
$
2,684

 
$
2,223

 
$
1,686

Regulated natural gas
126

 
109

 
87

Total capital expenditures
$
2,810

 
$
2,332

 
$
1,773


 
As of December 31,
 
2019
 
2018
 
2017
Total assets:
 
 
 
 
 
Regulated electric
$
20,284

 
$
17,702

 
$
16,105

Regulated natural gas
1,547

 
1,485

 
1,482

Other
9

 
443

 
451

Total assets
$
21,840

 
$
19,630

 
$
18,038



418


Goodwill by reportable segment as of December 31, 2019 and 2018 was as follows (in millions):
Regulated electric
$
1,191

Regulated natural gas
79

Total
$
1,270



419


EXHIBIT INDEX
Exhibit No.
Description

BERKSHIRE HATHAWAY ENERGY
3.1
3.2
3.3
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9

420


Exhibit No.
Description

4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22

421


Exhibit No.
Description

4.23
4.24
4.25
4.26
4.27
4.28
4.29
4.30
4.31
4.32
4.33
4.34
4.35
4.36

422


Exhibit No.
Description

4.37
4.38
4.39
4.40
4.41
4.42
4.43
4.44
4.45
4.46
4.47
4.48

423


Exhibit No.
Description

4.49
4.50
4.51
4.52
4.53
4.54
4.55
4.56
4.57
4.58
4.59
4.60
4.61

424


Exhibit No.
Description

4.62
4.63
4.64
4.65
4.66
10.1
10.2
10.3
10.4
10.5
10.6
10.7
14.1
21.1
23.1

425


Exhibit No.
Description

24.1
31.1
31.2
32.1
32.2

PACIFICORP
3.4
3.5
10.8*
10.9*
10.10*
10.11*
10.12*
10.13*
10.14*
10.15*
14.2
23.2
31.3
31.4
32.3
32.4


426


Exhibit No.
Description

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP
4.67
Mortgage and Deed of Trust dated as of January 9, 1989, between PacifiCorp and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, incorporated by reference to Exhibit 4-E to the PacifiCorp Form 8-B, as supplemented and modified by 29 Supplemental Indentures, each incorporated by reference, as follows:
Exhibit
 
PacifiCorp
 
 
Number
 
File Type
 
File Date
(4)(b)(a)
 
SE
 
November 2, 1989
(4)(a)(a)
 
8-K
 
January 9, 1990
(4)(a)(a)
 
8-K
 
September 11, 1991
(4)(a)(a)
 
8-K
 
January 7, 1992
(4)(a)(a)
 
10-Q
 
Quarter ended March 31, 1992
(4)(a)(a)
 
10-Q
 
Quarter ended September 30, 1992
(4)(a)(a)
 
8-K
 
April 1, 1993
(4)(a)(a)
 
10-Q
 
Quarter ended September 30, 1993
 
10-Q
 
Quarter ended June 30, 1994
 
10-K
 
Year ended December 31, 1994
 
10-K
 
Year ended December 31, 1995
 
10-K
 
Year ended December 31, 1996
 
10-K
 
Year ended December 31, 1998
 
8-K
 
November 21, 2001
4.1
 
10-Q
 
Quarter ended June 30, 2003
99
 
8-K
 
September 9, 2003
4
 
8-K
 
August 26, 2004
4
 
8-K
 
June 14, 2005
4.2
 
8-K
 
August 14, 2006
4
 
8-K
 
March 14, 2007
4.1
 
8-K
 
October 3, 2007
4.1
 
8-K
 
July 17, 2008
4.1
 
8-K
 
January 8, 2009
4.1
 
8-K
 
May 12, 2011
4.1
 
8-K
 
January 6, 2012
4.1
 
8-K
 
June 6, 2013
4.1
 
8-K
 
March 13, 2014
4.1
 
8-K
 
June 19, 2015
4.1
 
8-K
 
July 13, 2018
4.1
 
8-K
 
March 1, 2019
10.16
10.17
95

427


Exhibit No.
Description


MIDAMERICAN ENERGY
3.6
3.7
14.3
23.3
31.5
31.6
32.5
32.6

MIDAMERICAN FUNDING
3.8
3.9
3.10
14.4
31.7
31.8
32.7
32.8

BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN ENERGY AND MIDAMERICAN FUNDING
4.68
4.69
4.70

428


Exhibit No.
Description

4.71
4.72
4.73
4.74
4.75
4.76
4.77
4.78
4.79
4.80
4.81
4.82
4.83
4.84
4.85
4.86
4.87

429


Exhibit No.
Description

4.88
4.89
4.90
4.91
4.92
4.93
4.94
4.95
4.96
4.97
4.98
4.99
4.100
4.101
4.102

430


Exhibit No.
Description

4.103

BERKSHIRE HATHAWAY ENERGY AND MIDAMERICAN FUNDING
4.104

NEVADA POWER
3.11
3.12
4.105
4.106
10.18
14.5
23.4
31.9
31.10
32.9
32.10

BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER
4.107
4.108

431


Exhibit No.
Description

4.109
4.110
4.111
4.112
4.113
4.114
4.115
4.116
4.117
4.118
10.19

SIERRA PACIFIC
3.13
3.14
4.119

432


Exhibit No.
Description

4.120
4.121
10.20
14.6
31.11
31.12
32.11
32.12

BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC
4.122
4.123
4.124
4.125
4.126
4.127
10.21


433


Exhibit No.
Description

ALL REGISTRANTS
101
The following financial information from each respective Registrant's Annual Report on Form 10-K for the year ended December 31, 2019 is formatted in XBRL (eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail.

(a)    Not available electronically on the SEC website as it was filed in paper previous to the electronic system currently in place.

Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, each Registrant has not filed as an exhibit to this Form 10-K certain instruments with respect to long-term debt not registered in which the total amount of securities authorized thereunder does not exceed 10% of the total assets of the respective Registrant. Each Registrant hereby agrees to furnish a copy of any such instrument to the Commission upon request.



434



SIGNATURES

BERKSHIRE HATHAWAY ENERGY COMPANY

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 21st day of February 2020.

 
BERKSHIRE HATHAWAY ENERGY COMPANY
 
 
 
/s/ William J. Fehrman*
 
William J. Fehrman
 
Director, President and Chief Executive Officer
 
(principal executive officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature
 
Title
 
Date
 
 
 
 
 
/s/ William J. Fehrman*
 
Director, President and Chief Executive Officer
 
February 21, 2020
William J. Fehrman
 
(principal executive officer)
 
 
 
 
 
 
 
/s/ Patrick J. Goodman*
 
Executive Vice President and Chief Financial Officer
 
February 21, 2020
Patrick J. Goodman
 
(principal financial and accounting officer)
 
 
 
 
 
 
 
/s/ Gregory E. Abel*
 
Chairman of the Board of Directors
 
February 21, 2020
Gregory E. Abel
 
 
 
 
 
 
 
 
 
/s/ Warren E. Buffett*
 
Director
 
February 21, 2020
Warren E. Buffett
 
 
 
 
 
 
 
 
 
/s/ Marc D. Hamburg*
 
Director
 
February 21, 2020
Marc D. Hamburg
 
 
 
 
 
 
 
 
 
/s/ Walter Scott, Jr.*
 
Director
 
February 21, 2020
Walter Scott, Jr.
 
 
 
 
 
 
 
 
 
*By: /s/ Natalie L. Hocken
 
Attorney-in-Fact
 
February 21, 2020
Natalie L. Hocken
 
 
 
 



435



SIGNATURES

PACIFICORP

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 21st day of February 2020.

 
PACIFICORP
 
 
 
/s/ Nikki L. Kobliha
 
Nikki L. Kobliha
 
Director, Vice President, Chief Financial Officer and
 
Treasurer
 
(principal financial and accounting officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature
 
Title
 
Date
 
 
 
 
 
/s/ William J. Fehrman
 
Chairman of the Board of Directors and Chief
 
February 21, 2020
William J. Fehrman
 
Executive Officer
 
 
 
 
(principal executive officer)
 
 
 
 
 
 
 
/s/ Nikki L. Kobliha
 
Director, Vice President, Chief Financial Officer and
 
February 21, 2020
Nikki L. Kobliha
 
Treasurer
 
 
 
 
(principal financial and accounting officer)
 
 
 
 
 
 
 
/s/ Stefan A. Bird
 
Director
 
February 21, 2020
Stefan A. Bird
 
 
 
 
 
 
 
 
 
/s/ Patrick J. Goodman
 
Director
 
February 21, 2020
Patrick J. Goodman
 
 
 
 
 
 
 
 
 
/s/ Natalie L. Hocken
 
Director
 
February 21, 2020
Natalie L. Hocken
 
 
 
 
 
 
 
 
 
/s/ Gary W. Hoogeveen
 
Director
 
February 21, 2020
Gary W. Hoogeveen
 
 
 
 


436



SIGNATURES

MIDAMERICAN ENERGY COMPANY

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 21st day of February 2020.

 
MIDAMERICAN ENERGY COMPANY
 
 
 
/s/ Adam L. Wright
 
Adam L. Wright
 
Director, President and Chief Executive Officer
 
(principal executive officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:

Signature
 
Title
 
Date
 
 
 
 
 
/s/ Adam L. Wright
 
Director, President and Chief Executive Officer
 
February 21, 2020
Adam L. Wright
 
(principal executive officer)
 
 
 
 
 
 
 
/s/ Thomas B. Specketer
 
Director, Vice President and Chief Financial Officer
 
February 21, 2020
Thomas B. Specketer
 
(principal financial and accounting officer)
 
 
 
 

 
 
/s/ Robert B. Berntsen
 
Director
 
February 21, 2020
Robert B. Berntsen
 
 
 
 


437



SIGNATURES

MIDAMERICAN FUNDING, LLC

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 21st day of February 2020.

 
MIDAMERICAN FUNDING, LLC
 
 
 
/s/ Adam L. Wright
 
Adam L. Wright
 
Manager and President
 
(principal executive officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:

Signature
 
Title
 
Date
 
 
 
 
 
/s/ Adam L. Wright
 
Manager and President
 
February 21, 2020
Adam L. Wright
 
(principal executive officer)
 
 
 
 
 
 
 
/s/ Thomas B. Specketer
 
Vice President and Controller
 
February 21, 2020
Thomas B. Specketer
 
(principal financial and accounting officer)
 
 
 
 
 
 
 
/s/ Daniel S. Fick
 
Manager
 
February 21, 2020
Daniel S. Fick
 
 
 
 
 
 
 
 
 
/s/ Patrick J. Goodman
 
Manager
 
February 21, 2020
Patrick J. Goodman
 
 
 
 
 
 
 
 
 
/s/ Natalie L. Hocken
 
Manager
 
February 21, 2020
Natalie L. Hocken
 
 
 
 


438



SIGNATURES

NEVADA POWER COMPANY

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 21st day of February 2020.

 
NEVADA POWER COMPANY
 
 
 
/s/ Douglas A. Cannon
 
Douglas A. Cannon
 
Director, President and Chief Executive Officer
 
(principal executive officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:

Signature
 
Title
 
Date
 
 
 
 
 
/s/ Douglas A. Cannon
 
Director, President and Chief Executive Officer
 
February 21, 2020
Douglas A. Cannon
 
(principal executive officer)
 
 
 
 
 
 
 
/s/ Michael E. Cole
 
Director, Vice President and Chief Financial Officer
 
February 21, 2020
Michael E. Cole
 
(principal financial and accounting officer)
 
 
 
 
 
 
 
/s/ Brandon M. Barkhuff
 
Director
 
February 21, 2020
Brandon M. Barkhuff
 
 
 
 
 
 
 
 
 
/s/ Kevin C. Geraghty
 
Director
 
February 21, 2020
Kevin C. Geraghty
 
 
 
 
 
 
 
 
 
/s/ Jennifer L. Oswald
 
Director
 
February 21, 2020
Jennifer L. Oswald
 
 
 
 
 
 
 
 
 
/s/ Anthony F. Sanchez, III
 
Director
 
February 21, 2020
Anthony F. Sanchez, III
 
 
 
 


439



SIGNATURES

SIERRA PACIFIC POWER COMPANY

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 21st day of February 2020.

 
SIERRA PACIFIC POWER COMPANY
 
 
 
/s/ Douglas A. Cannon
 
Douglas A. Cannon
 
Director, President and Chief Executive Officer
 
(principal executive officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:

Signature
 
Title
 
Date
 
 
 
 
 
/s/ Douglas A. Cannon
 
Director, President and Chief Executive Officer
 
February 21, 2020
Douglas A. Cannon
 
(principal executive officer)
 
 
 
 
 
 
 
/s/ Michael E. Cole
 
Director, Vice President and Chief Financial Officer
 
February 21, 2020
Michael E. Cole
 
(principal financial and accounting officer)
 
 
 
 
 
 
 
/s/ Brandon M. Barkhuff
 
Director
 
February 21, 2020
Brandon M. Barkhuff
 
 
 
 
 
 
 
 
 
/s/ Kevin C. Geraghty
 
Director
 
February 21, 2020
Kevin C. Geraghty
 
 
 
 
 
 
 
 
 
/s/ Jennifer L. Oswald
 
Director
 
February 21, 2020
Jennifer L. Oswald
 
 
 
 
 
 
 
 
 
/s/ Anthony F. Sanchez, III
 
Director
 
February 21, 2020
Anthony F. Sanchez, III
 
 
 
 


440


SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

No annual report to security holders covering each respective Registrant's last fiscal year or proxy material has been sent to security holders.



441
EXHIBIT 10.3

AMENDED AND RESTATED CREDIT AGREEMENT
made as of January 24, 2020
among
ALTALINK INVESTMENT MANAGEMENT LTD.,
as general partner of
ALTALINK INVESTMENTS, L.P.,
as Borrower,
- and -
ALTALINK INVESTMENT MANAGEMENT LTD.,
as General Partner,
- and -
ROYAL BANK OF CANADA,
as Administrative Agent of the Lenders, and as Lender,
- and -
RBC CAPITAL MARKETS,
as Sole Lead Arranger and Sole Bookrunner
- and -
BANK OF MONTREAL, as Documentation Agent
- and -
ALL OTHER LENDERS WHICH BECOME
PARTIES HEREUNDER,
as Lenders



RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement

- 1 -

TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
2

 
 
 
 
 
1.1
Definitions.
2

 
1.2
References.
25

 
1.3
Headings.
25

 
1.4
Included Words.
25

 
1.5
Accounting Terms.
25

 
1.6
Time.
26

 
1.7
Currency.
26

 
1.8
Certificates and Opinions.
26

 
1.9
Amendment and Restatement; No Novation
26

 
Schedules.
27

 
 
 
 
27

 
 
 
 
 
2.1
Credit Facility.
27

 
2.2
Cancellation.
27

 
2.3
Use of Proceeds.
28

 
2.4
Particulars of Borrowings.
28

 
2.5
Borrowing Notice.
28

 
2.6
Books of Account.
29

 
2.7
Co-ordination of Prime Rate and U.S. Base Rate Loans.
30

 
2.8
Bankers’ Acceptances.
30

 
2.9
LIBOR Loans.
34

 
Safekeeping of Drafts.
36

 
Certification to Third Parties.
36

 
2.12    
Successor LIBOR and CDOR Rate.
36

 
 
 
 
37

 
 
 
 
 
3.1
Documentary Credits.
37

 
3.2
Procedure for Issue.
38

 
3.3
Form of Documentary Credits.
38

 
3.4
Reimbursements of Amounts Drawn.
38

 
3.5
Documentary Credit Participation.
39

 
3.6
Risk of Documentary Credits.
39

 
3.7
Fees.
41

 
3.8
Repayments.
41

 
3.9
Documentary Credits Outstanding Upon Default.
42

 
 
 
 

RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement

- 2 -

42

 
 
 
 
 
4.1
Interest on Loans.
42

 
4.2
LIBOR Interest Period Determination.
43

 
4.3
Interest on Overdue Amounts.
43

 
4.4
Other Interest.
43

 
4.5
Interest Act (Canada).
44

 
4.6
Deemed Reinvestment Principle.
44

 
4.7
Maximum Return.
44

 
 
 
 
44

 
 
 
 
 
5.1
Acceptance Fees.
44

 
5.2
Commitment Fee.
44

 
5.3
Basis of Calculation of Fees.
45

 
 
 
 
45

 
 
 
 
 
6.1
Voluntary Repayment of Outstanding Accommodation.
45

 
6.2
Repayment on Maturity Date and Extension.
46

 
6.3
Excess Accommodation.
47

 
6.4
Illegality.
47

 
 
 
 
48

 
 
 
 
 
7.1
Payments on Non-Business Days.
48

 
7.2
Method and Place of Payment.
48

 
7.3
Net Payments.
48

 
7.4
Agent May Debit Account.
48

 
7.5
Currency of Payment.
48

 
7.6
General Indemnity.
49

 
7.7
Early Termination of LIBOR Interest Period.
50

 
7.8
Outstanding Bankers’ Acceptances.
50

 
 
 
 
50

 
 
 
 
 
8.1
Security.
50

 
 
 
 
51

 
 
 
 
 
9.1
Representations and Warranties.
51

 
9.2
Survival of Representations and Warranties.
55

 
 
 
 
56


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement

- 3 -

 
 
 
 
 
Reporting Covenants.
56

 
Payments Under This Agreement and Loan Documents.
57

 
Proceeds.
57

 
Inspection of Property, Books and Records, Discussions.
57

 
Notices.
57

 
Disbursements under Master Trust Indenture.
58

 
Cure Defects.
58

 
Carrying on Business.
58

 
Insurance and Insurance Proceeds.
58

 
Compliance with Laws and Agreements.
59

 
Taxes.
59

 
Further Assurances.
59

 
Limitation on Indebtedness.
59

 
Negative Pledge.
59

 
Investments.
60

 
Change in Business and Ownership of AltaLink and Subsidiaries.
60

 
Mergers, Etc.
60

 
Acquisitions.
60

 
Transactions with Non-Arm’s Length Persons.
61

 
Environmental Covenants.
61

 
Hedging Agreements.
62

 
Distributions.
62

 
Fiscal Year.
62

 
Financial Covenants.
62

 
Master Trust Indenture.
62

 
 
 
 
63

 
 
 
 
 
Conditions Precedent to the Closing.
63

 
Conditions Precedent to All Borrowings, Conversions.
64

 
Waiver.
64

 
 
 
 
64

 
 
 
 
 
Events of Default.
64

 
Remedies.
67

 
Remedies Cumulative.
68

 
Appropriation of Moneys Received.
68

 
Non-Merger.
68

 
Waiver.
68

 
Set-off.
68

 
 
 
 
69


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement

- 4 -

 
 
 
 
 
Increased Costs.
69

 
Taxes.
70

 
Mitigation Obligations: Replacement of Lenders.
72

 
Illegality.
74

 
 
 
 
74

 
 
 
 
 
Right of Setoff.
74

 
 
 
 
75

 
 
 
 
 
Sharing of Payments by Lenders.
75

 
 
 
 
76

 
 
 
 
 
Agent’s Clawback.
76

 
 
 
 
76

 
 
 
 
 
Appointment and Authority.
76

 
Rights as a Lender.
77

 
Exculpatory Provisions.
77

 
Reliance by Agent.
78

 
Indemnification of Agent.
78

 
Delegation of Duties.
78

 
Replacement of Agent.
79

 
Non-Reliance on Agent and Other Lenders.
80

 
Collective Action of the Lenders.
80

 
No Other Duties, etc.
80

 
 
 
 
80

 
 
 
 
 
Notices, etc.
80

 
Notice Details
81

 
 
 
 
82

 
 
 
 
 
Expenses; Indemnity: Damage Waiver.
82

 
 
 
 
84

 
 
 
 
 
Successors and Assigns.
84

 
 
 
 

RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement

- 5 -

87

 
 
 
 
 
Amendments and Waivers.
87

 
Judgment Currency.
87

 
 
 
 
88

 
 
 
 
 
Governing Law; Jurisdiction; Etc.
88

 
 
 
 
88

 
 
 
 
 
Waiver of Jury Trial.
88

 
 
 
 
89

 
 
 
 
 
Counterparts; Integration; Effectiveness; Electronic Execution.
89

 
 
 
 
89

 
 
 
 
 
Treatment of Certain Information: Confidentiality.
89

 
 
 
 
91

 
 
 
 
 
Further Assurances
91

 
Acknowledgement
91

SCHEDULE 1
-
BORROWER’S CERTIFICATE OF COMPLIANCE
SCHEDULE 2(A)
-
BORROWING NOTICE
SCHEDULE 2(B)
-
NOTICE OF ROLL OVER
SCHEDULE 2(C)
-
CONVERSION OPTION NOTICE
SCHEDULE 3
-
NOTICE OF EXTENSION
SCHEDULE 4
-
FORM OF ISSUE NOTICE
SCHEDULE 5
-
ASSIGNMENT AND ASSUMPTION
SCHEDULE 6
-
COMMITMENTS OF THE LENDERS
SCHEDULE 6.1(a)
-
FORM OF NOTICE OF REPAYMENT
SCHEDULE 7
-
SENIOR PLEDGED BOND, SERIES 2
SCHEDULE 8
-
THIRD SUPPLEMENTAL INDENTURE
SCHEDULE 9.1(a)
-
CREDIT PARTY AND SUBSIDIARY INFORMATION
SCHEDULE 10
-
MATERIAL AGREEMENTS


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement

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THIS AMENDED AND RESTATED CREDIT AGREEMENT is made as of January 24, 2020
A M O N G:
ALTALINK INVESTMENT MANAGEMENT LTD., as general partner of ALTALINK INVESTMENTS, L.P.,
as Borrower,
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ALTALINK INVESTMENT MANAGEMENT LTD.,
as General Partner,
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ROYAL BANK OF CANADA
as Agent of the Lenders, and as a Lender,
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ALL OTHER LENDERS WHICH BECOME PARTIES HEREUNDER,
as Lenders
WHEREAS the Borrower, Royal Bank of Canada, as agent and the Lenders are party to an Amended and Restated Credit Agreement dated July 30, 2015 (such agreement, as amended by a first amending agreement dated as of November 20, 2015, a second amending agreement dated as of December 14, 2015, a third amending agreement dated as of July 8, 2016, a fourth amending agreement dated as of December 15, 2016, a fifth amending agreement dated as of December 15, 2017 and a sixth amending agreement dated as of December 14, 2018, the “Existing Credit Agreement”), which Existing Credit Agreement was an amendment and restatement of an amended and restated credit agreement dated December 14, 2011 (such agreement, as amended by a first amending agreement dated as of April 27, 2012, a second amending agreement dated as of December 14, 2012, a third amending agreement dated as of December 16, 2013, a waiver and fourth amending agreement dated as of October 24, 2014 and a fifth amending agreement dated as of December 15, 2014, the “December 14, 2011 Credit Agreement”, which December 14, 2011 Credit Agreement was an amendment and restatement of an amended and restated credit agreement dated December 15, 2010, as amended by a first amending agreement dated as of October 28, 2011, the “December 15, 2010 Credit Agreement”, which December 15, 2010 Credit Agreement was an amendment and restatement of an amended and restated credit agreement dated December 16, 2009, as amended by a first amending agreement dated as of December 23, 2009, the “December 16, 2009 Credit Agreement”), pursuant to which the Lenders agreed (subject to the terms of the Existing Credit Agreement) to make funding available to the Borrower from time to time for operating expenses, capital expenditures and working capital needs of the Borrower and AltaLink.

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AND WHEREAS the Borrower is party to a Master Trust Indenture (as defined herein) pursuant to which it may borrow money by, among other things, creating and issuing bonds and other debt securities and entering into credit facility agreements, all in the manner set forth in the Master Trust Indenture;
AND WHEREAS in conjunction with the Original Credit Agreement (as defined in the December 16, 2009 Credit Agreement), the Borrower entered into a supplemental indenture under the Master Trust Indenture and authorized the issuance of a Pledged Bond under the Master Trust Indenture, as continuing collateral security for the obligations owing under the December 16, 2009 Credit Agreement.
AND WHEREAS the Borrower has requested that the Agent and Lenders agree to amend and restate the Existing Credit Agreement in the manner and on the terms and conditions provided for in this Amended and Restated Credit Agreement.
NOW THEREFORE THIS AGREEMENT WITNESSES that, in consideration of the mutual covenants and agreements contained in this Agreement, the Borrower, the Agent and the Lenders covenant and agree as follows:

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Article 1
INTERPRETATION
1.1
Definitions.
In this Agreement, unless the context otherwise requires, the following terms shall have the following meanings:
“Accommodations” means the Loans, Documentary Credits and Bankers’ Acceptances (including BA Equivalent Loans) made under this Credit Facility and shall refer to any one or more of such types where the context requires.
“Acquisition” means, with respect to any Person, any transaction or series of related transactions for the direct or indirect (i) acquisition of the Assets of any other Person; (ii) acquisition of any shares, securities, interests, participations or other equivalents (including partnership interests or units) of any Person; or (iii) reconstruction, reorganization, consolidation, wind-up, merger, transfer, sale, lease or other combination with any other Person; and “Acquire” and “Acquired” have meanings correlative thereto.
“Administrative Questionnaire” means an administrative questionnaire in a form provided by the Agent.
“Advance” means an advance by the Lenders or any of them of any Accommodation, and shall include deemed Advances and conversions, renewals and rollovers of existing Advances, and any reference relating to the amount of Advances shall mean the Canadian Dollar Amount of all outstanding Accommodation.
“Affiliate” of any specified Person means any other Person directly or indirectly Controlling, Controlled by, or under common Control with such Person.
“Agent” or “Administrative Agent” means RBC in its capacity as administrative agent hereunder, or any successor Agent appointed under Section 17.7.
“Agent’s Account” means the account at the Branch into which Lenders’ Advances shall be deposited for payment to the Borrower.
“Agreement” means this Amended and Restated Credit Agreement and the Schedules hereto, as amended, supplemented or restated from time to time.
“AltaLink” means AltaLink, L.P., an Alberta limited partnership, together with its successors and assigns.
“Applicable Law” means, at any time, with respect to any Person, property, transaction or event, all then applicable laws, by-laws, statutes and regulations, and (to the extent that they have the force of law) all then applicable treaties, judgments, decrees, official directives, rules, consents, approvals, authorizations, guidelines, orders and policies of any Governmental Authority having authority over any of such Person, property, transaction or event.

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“Applicable Margin” means the applicable fee or margin amount set out in the following grid for the rating which corresponds to the rating received from S&P or DBRS for the Senior Bonds, Series 13-1 and the Senior Bonds, Series 15-1 and which is determined below:
Ratings
Category I
Category II
Category III
Category IV
Category V
Category VI
Category VII
S & P and DBRS
>A / A
A / A
A- / A (low)
BBB+ /
BBB (high)
BBB / BBB
BBB- /
BBB (low)
< BBB- / BBB (low) / unrated
Applicable Margin for Bankers’ Acceptances, LIBOR Loans & Documentary Credits
70 bps
80 bps
100 bps
120 bps
145 bps
170 bps
200 bps
Applicable Margin for Prime Rate Loans and US Base Rate Loans
0 bps
0 bps
0 bps
20 bps
45 bps
70 bps
100 bps
Commitment Fee
14.0 bps
16.0 bps
20.0 bps
24.0 bps
29 bps
34 bps
40 bps

For purposes of this Agreement, if at any time the ratings assigned by the Rating Agencies fall within different rating categories in accordance with the above table, (a) in the case where the lowest senior unsecured debt rating is BBB- or higher, the Applicable Margin will be the higher of the ratings and (b) in the case where the lowest senior unsecured debt rating is lower than BBB-, the Applicable Margin will be based on the average of the ratings.
Any increase or decrease in the Applicable Margin (other than with respect to Bankers’ Acceptances) resulting from a change in the rating assigned by one or more Rating Agency shall be calculated with reference to the new Applicable Margin and fee effective on and after the date on which such rating change is published, notwithstanding that any affected Advance may have been made or issued prior to such date. Any increase or decrease in the applicable Banker’s Acceptance Fee shall apply to all Bankers’ Acceptances drawn by the Borrower or on rollover or conversion pursuant to Section 2.8(f), as of the date of such drawing, rollover or conversion, as the case may be.
“Applicable Percentage” means with respect to any Lender, the percentage of the total Commitments represented by such Lender’s Commitment. If the Commitments have terminated or expired, the Applicable Percentages shall be the percentage of the total Accommodations outstanding represented by such Lender’s Accommodations outstanding.
“Applicable Utilities Legislation” means the Alberta Utilities Commission Act (Alberta), the Electric Utilities Act (Alberta), the Public Utilities Act (Alberta), the Hydro and Electric Energy Act (Alberta), and any other legislation that now or in the future regulates the operations of the Business, as each may be amended or supplemented from time to time.
“Approved Fund” means, with respect to any Lender that is an investment fund that invests in bank loans, any other investment fund that invests in bank loans and is managed by the same investment advisor as such Lender or by an Affiliate of such investment advisor.
“Assets” means, with respect to any Person, any property, assets and undertakings of such Person of every kind and wheresoever situate, whether now owned or hereafter acquired

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(and, for greater certainty, includes any equity or like interest of any Person in any other Person).
“Assignment and Assumption” means an assignment and assumption agreement substantially in the form attached as Schedule 5.
“AUC” means the Alberta Utilities Commission, or any successor or replacement board regulating the transmission of energy in the Province of Alberta.
“Auditor” means the independent national firm of Canadian chartered accountants appointed from time to time as the auditor of the Borrower.
“BA Discount Proceeds” means, in respect of any Bankers’ Acceptance, an amount calculated on the applicable Borrowing Date which is (rounded to the nearest full cent, with one-half of one cent being rounded up) equal to the Face Amount of such Bankers’ Acceptance multiplied by the price, where the price is calculated by dividing one by the sum of one plus the product of (i) the BA Discount Rate applicable thereto expressed as a decimal fraction multiplied by (ii) a fraction, the numerator of which is the term of such Bankers’ Acceptance and the denominator of which is three hundred and sixty-five (365), which calculated price will be rounded to the nearest multiple of 0.001%.
“BA Discount Rate” means:
(a)
with respect to an issue of Bankers' Acceptances accepted by a Lender that is a Schedule I Bank, the CDOR Rate;
(b)
with respect to an issue of Bankers' Acceptances accepted by a Lender that is a Schedule II Bank or a Schedule III Bank, the lesser of: (i) the rate set out in clause (a) above plus 0.10%; and (ii) the annual rate, expressed as a percentage, as being the average discount rate for bankers' acceptances having a comparable face value and a comparable issue and maturity date to the face value and issue and maturity date of such issue of Bankers' Acceptances, expressed on the basis of a year of 365 days, quoted by such Lenders for the purchase by such Lenders of Bankers' Acceptances accepted by them, at or about 10:00 a.m. (Toronto time) on the date of issue of such Bankers' Acceptances; and
(c)
with respect to a BA Equivalent Loan:
(i)
made by a Lender that is a Schedule I Bank, the CDOR Rate; and
(ii)
made by any other Lender, the rate set out in clause (a) above plus 0.10%.
“BA Equivalent Loan” shall have the meaning ascribed thereto in Section 2.8(j).
“BA Instruments” means, collectively, Bankers’ Acceptances, Drafts and BA Equivalent Loans, and, in the singular, any one of them.

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“Bankers’ Acceptance” means a Draft drawn by the Borrower denominated in Canadian Dollars, for a term of one, two or three months or such other term as is readily acceptable, which term shall mature on a Business Day and on or before the Maturity Date for an amount of Five Hundred Thousand Canadian Dollars (Cdn.$500,000) or any whole multiple of Five Hundred and Thousand Canadian Dollars (Cdn.$500,000), the minimum aggregate amount of which included in any Borrowing shall be Five Hundred and Thousand Canadian Dollars (Cdn.$500,000), and accepted by a Lender pursuant to this Agreement.
“Bankers’ Acceptance Fee” means the fee payable on the Face Amount of each Bankers’ Acceptance calculated and payable in the manner provided for in Section 5.1.
“Beneficiary” means, in respect of a Documentary Credit, the beneficiary named in the Documentary Credit or the Issue Notice with respect thereto.
“Bond Delivery Agreement” means the bond delivery agreement dated as of December 15, 2010 among the parties hereto as the same may be amended or supplemented from time to time.
“Borrower” means AltaLink Investments, L.P., a limited partnership created and existing under the Partnership Act (Alberta), and its permitted successors and permitted assigns.
“Borrower’s Certificate of Compliance” means a certificate of the Borrower in the form of Schedule 1 and signed on behalf of the Borrower by any one of (i) Managing Director, (ii) the Vice President, Finance or any other person so designated, or (iii) any Director of the General Partner or any other senior officer of the General Partner so designated by a certificate signed by the Managing Director or any two (2) Directors of the General Partner and filed with the Agent for so long as such designation shall be in effect.
“Borrowing” means the aggregate Accommodation to be obtained by the Borrower from one or more of the Lenders on any Borrowing Date.
“Borrowing Date” means the Business Day specified in a Borrowing Notice on which a Lender is or Lenders are requested to provide Accommodation.
“Borrowing Notice” has the meaning set out in Section 2.5.
“Branch” means the main branch of the Agent situated at Toronto, Ontario, or such other branch of the Agent in the City of Toronto as the Agent may from time to time designate in writing to the Borrower.
“Business” means the following businesses and services of the Borrower and its Subsidiaries:
(a)
ownership of limited partnership units in AltaLink;
(b)
direct or indirect participation in the transmission of electricity in Canada or the United States;

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(c)
the ownership or operation of electrical transmission lines and infrastructure in Canada or the United States, including the use of such infrastructure for telecommunication or other communication purposes, subject to such telecommunication or other communication purposes not exceeding 10% of Consolidated Assets;
(d)
engineering or administrative services related to the activities described in paragraphs (a) through (c) above;
(e)
the Acquisition of any Person related to the activities described in paragraphs (a) through (d) above, in compliance with Section 10.18;
(f)
such other services as determined to be ancillary to the activities described in paragraphs (a) through (d) above (whether or not such services are regulated by the AUC), with such other services not exceeding 10% of Consolidated Assets; and
(g)
provided that such activities are not prohibited by the Master Trust Indenture, business development activities related to the pursuit of potential opportunities regarding the transmission of electricity in countries other than Canada and the United States (including, without limitation, Brazil and India), provided however that (A) any costs or expenses incurred by the Borrower and its Subsidiaries in respect of such business development activities shall not exceed $20,000,000 in aggregate per calendar year and (B) nothing in this definition shall permit the Borrower or its Subsidiaries to (i) own or operate any electrical transmission lines or any other infrastructure in any such other country, (ii) to make any Acquisition of any Person carrying on business in any such other country or of any other assets located in any such other country or (iii) to make any Investment in any Person which owns or operates any electrical transmission lines or other infrastructure in any such other country, without the prior written consent of the Majority Lenders.
For greater certainty “Business” (i) shall not include the generation and/or distribution of electricity or sale of power and (ii) when used with reference to AltaLink and its Subsidiaries, shall not be interpreted to include any business, activities or services described above which are inconsistent with the business which AltaLink and its Subsidiaries now, or at any time while this Agreement is in effect, carries out in accordance with the terms of the amended and restated master trust indenture dated April 28, 2003 to which AltaLink is party.
“Business Day” means any day of the year (other than a Saturday, Sunday, and any day which shall be in Calgary, Alberta a legal holiday) on which the Agent is open at the Branch for the conduct of regular banking business and, where used in the context of (i) U.S. Base Rate Loan, is also a day on which banks are not required or authorized to close in New York, New York; and (ii) a LIBOR Loan, is also a day on which banks are not required or authorized to close in New York, New York and dealings are carried on in the London interbank market.
“Canadian Dollar” or “Cdn.$” means the currency of Canada.

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“Canadian Dollar Amount” means, at any time, in relation to any outstanding Accommodation, in relation to a:
(a)
Loan denominated in Canadian Dollars, the principal amount thereof;
(b)
Bankers’ Acceptance, the Face Amount thereof;
(c)
Loan denominated in U.S. Dollars, the Equivalent Amount expressed in Canadian Dollars of the principal amount thereof; and
(d)
Documentary Credit, (i) where the Documentary Credit is denominated in Canadian Dollars, the amount of the maximum aggregate liability (contingent or actual) of the Documentary Credit Lender pursuant to such Documentary Credit expressed in Canadian Dollars and (ii) where the Documentary Credit is denominated in US Dollars, the Equivalent Amount of the maximum aggregate liability (contingent or actual) of the Documentary Credit Lender pursuant to such Documentary Credit.
“Capital Lease Obligations” of any Person means the obligations of such Person to pay rent or other amounts under any leasing or similar arrangement which in accordance with GAAP would be classified and accounted for as capital leases and the amount of such Capital Lease Obligations shall be the capitalized amount thereof determined in accordance with GAAP.
“CDOR Rate” means, on any date, the annual rate of interest which is the rate based on an average rate applicable to Canadian Dollar bankers’ acceptances for a specified term appearing on the Reuters Screen Page CDOR (or such other page as is a replacement page for such banker’s acceptances) at approximately 10:00 a.m. (Toronto time), on such date, or if such date is not a Business Day, then on the immediately preceding Business Day, provided that if such rate does not appear on the Reuters Screen Page CDOR (or such other page as is a replacement page for such banker’s acceptances) on such date as contemplated, then CDOR on such date shall be the rate for the term referred to above applicable to Canadian Dollar bankers’ acceptances quoted by the Agent as of 10:00 a.m. (Toronto time) on such date or, if such date is not a Business Day, then on the immediately preceding Business Day, provided further that if the CDOR Rate as determined herein shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement.
“Change in Law” means the occurrence, after the date of this Agreement, of any of the following: (a) the adoption or taking effect of any Applicable Law, (b) any change in any Applicable Law or in the administration, interpretation or application thereof by any Governmental Authority, or (c) the making or issuance of any Applicable Law by any Governmental Authority, provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or Canadian or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a “Change in Law”, regardless of the date enacted, adopted or issued.

RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement

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“Change of Control” means any event whereby:
(a)
AltaLink Holdings, L.P. ceases to be the sole limited partner and owner of 99.99% of the Equity Securities of the Borrower or AltaLink Investment Management Ltd. ceases to be the sole general partner and owner of .01% of the Equity Securities in the Borrower;
(b)
the Borrower ceases to be the sole limited partner and owner of 99.99% of the Equity Securities in AltaLink and/or AltaLink Management Ltd. ceases to be the sole general partner and the owner of .01% of the Equity Securities of AltaLink;
(c)
the aggregate revenues and the total Assets of non-wholly owned Subsidiaries of the Borrower exceed 10% of the revenue and net tangible total Assets of the Borrower and its Subsidiaries. The parties agree that for the purposes of this paragraph (c) (and paragraph 5 of the Certificate of Compliance and Section 10.16(a)), AltaLink shall be deemed to be a wholly owned Subsidiary of the Borrower so long as (i) the representations and warranties in Section 9.1(t)(i) and (ii) remain true and correct, and (ii) Berkshire Hathaway Energy Company continues to own (directly or indirectly) 100% of the Equity Securities of AltaLink Management Ltd;
(d)
Berkshire Hathaway Energy Company ceases to collectively own (directly or indirectly) at least 51% of voting and economic interest in the Borrower, unless at the closing of a transaction wherein Berkshire Hathaway Energy Company will own (directly or indirectly) less than 51% of the voting and economic interest in of the Borrower, the Borrower has delivered to the Lenders confirmations taking such transaction into account from S&P and DBRS that the senior unsecured debt ratings of the Borrower shall not be lower than BBB- or BBB(low).
“Claim” shall have the meaning set out in Section 7.6.
“Commercial Paper Program” shall have the meaning ascribed thereto in the Master Trust Indenture.
“Commitment” means in respect of each Lender from time to time, the covenant to make Advances to the Borrower of the Lender’s Applicable Percentage of the Committed Amount and, where the context requires, the maximum amount of Advances which such Lender has covenanted to make, as recorded on the Register maintained by the Agent referred to in Section 20.1(c) and as also set forth on Schedule 6 or in the most recent Assignment and Assumption executed by such Lender, as such amount may be reduced pursuant to this Agreement.
“Committed Amount” means three hundred million Canadian Dollars (Cdn $300,000,000), including as such amount may be cancelled pursuant to Section 2.2 or otherwise reduced pursuant to this Agreement.
“Consolidated Assets” means, at any time, the total Assets of the Borrower and its Subsidiaries at such time, determined on a consolidated basis in accordance with GAAP.

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“Consolidated Total Capitalization” means at any time, the sum of (i) Consolidated Unitholder Equity at such time, plus (ii) Consolidated Total Debt at such time, plus (iii) the principal amount of all outstanding Preferred Securities in each case determined on a consolidated basis for the Borrower in accordance with GAAP.
“Consolidated Total Debt” means, the following, as at any date calculated on a consolidated basis for the Borrower and its Subsidiaries, without duplication:
(a)
the aggregate principal amount of all obligations of the Borrower and its Subsidiaries for borrowed money (other than obligations arising out of the issuance of any Refunding Bonds (as such term is defined in the Master Trust Indenture) during such period of time as the Indebtedness to be repaid by the Refunding Bonds continues to be outstanding), including obligations with respect to bankers’ acceptances and contingent reimbursement obligations in respect of Documentary Credits and other instruments, and including all capitalized interest and other similar amounts required to be paid at maturity on obligations for borrowed money, but excluding Preferred Securities issued by the Borrower and its Subsidiaries;
(b)
the aggregate principal amount of all obligations issued or assumed by the Borrower and its Subsidiaries in connection with their acquisition of property in respect of the deferred purchase price of that property;
(c)
all Capital Lease Obligations and Purchase Money Obligations;
(d)
all Indebtedness outstanding under any Commercial Paper Program; and
(e)
all Guarantees of any of the foregoing.
“Consolidated Unitholder Equity” means, at any time, the consolidated unitholder equity appearing on the consolidated balance sheet of the Borrower at such time.
“Contaminant” means any pollutant, dangerous, toxic or Hazardous Substance or waste of any description whatsoever, hazardous materials or contaminants, all as defined in any Environmental Law, but excludes cleaning and related products used in the operation and maintenance of the Business which are normally used by reasonable professional operators of similar businesses.
“Contract Period” means, (i) in respect of any LIBOR Loan, the applicable LIBOR Interest Period and (ii) in respect of any BA Instrument, the applicable term of such BA Instrument selected by the Borrower in the related Borrowing Notice.
“Control”, when used with respect to any specified Person, means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms “Controlling” and “Controlled” have corresponding meanings.
“Credit Facility” means the credit facility established by the Lenders in favour of the Borrower pursuant to Section 2.1.

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“Credit Parties” means the Borrower and the General Partner.
“DBRS” means Dominion Bond Rating Service Limited and its successors for so long as it shall perform the functions of a securities rating agency.
“Default” means an event which, with the giving of notice or lapse of time, or both, would constitute an Event of Default.
“Demand Date” means any date that repayment of Accommodation or any other amount outstanding under this Agreement is demanded under ARTICLE 12.
“Depository Bill” means a depository bill, as such term is defined in the Depository Bills and Notes Act (Canada) (as such legislation may be amended, replaced or otherwise modified from time to time).
“Depreciation and Amortization Expense” means with respect to the Borrower, for any period, depreciation and amortization expense of the Borrower that is included as a deduction in the calculation of Net Income for such period, determined on a unconsolidated basis in accordance with GAAP.
“Distribution” means, with respect to any Person, any payment by such Person (i) of any dividends on any of its Equity Securities, (ii) on account of, or for the purpose of setting apart any property for a sinking or other analogous fund for, the purchase, redemption, retirement or other acquisition of any of its Equity Securities or any warrants, options or rights to acquire any such shares, or the making by such Person of any other distribution in respect of any of its Equity Securities, (iii) of any principal of or interest or premium on or of any amount in respect of a sinking or analogous fund or defeasance fund for any Indebtedness of such Person ranking in right of payment subordinate to any liability of such Person under the Loan Documents, (iv) of any principal of or interest or premium on or of any amount in respect of a sinking or analogous fund or defeasance fund for any indebtedness of such Person to a shareholder or partner of such Person or to an Affiliate of a shareholder or partner of such Person, or (v) of any management, consulting or similar fee or any bonus payment or comparable payment, or by way of gift or other gratuity, to any Affiliate of such Person or to any director or officer thereof, other than management fees paid in the ordinary course of business, not to exceed $5,000,000 in aggregate in any Fiscal Year.
“Documentary Credit” means a letter of credit or a letter of guarantee issued or to be issued by a Documentary Credit Lender for the account of Borrower pursuant to ARTICLE 3, as the same may be amended, supplemented, extended or restated from time to time.
“Documentary Credit Lenders” means, in the singular, Royal Bank of Canada or any other Lender selected by Borrower which is willing to issue Documentary Credits and, collectively, means all such Documentary Credit Lenders.
“Draft” means at any time a blank bill of exchange, within the meaning of the Bills of Exchange Act (Canada), drawn by the Borrower on a Lender and bearing such distinguishing

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letters and numbers as such Lender may require, but which at such time has not been completed or accepted by such Lender or a Depository Bill.
“EBITDA” means, with respect to the Borrower, on an unconsolidated basis, for any period, the Net Income of the Borrower for such period (a) increased, to the extent deducted in calculating Net Income for such period, by the sum of (i) Interest Expense for such period, (ii) Income Tax Expense for such period, (iii) Depreciation and Amortization Expense for such period and (iv) any other non-cash items decreasing Net Income for such period, and (b) decreased, to the extent included in calculating Net Income for such period, by the sum of (i) non-cash items relating to consolidated foreign exchange gains on debt and related foreign exchange contracts increasing Net Income for such period, and (ii) any other non-cash items increasing Net Income for such period, provided that any amounts which were included in Net Income and which represent the Borrower’s share of the net income of AltaLink which was available for distribution to the Borrower during the applicable period shall not be deducted for the purpose of this paragraph (b)(ii).
“Effective Date” means the date of this Agreement.
Eligible Assignees” means any Person (other than a natural person, any Credit Party or any Affiliate of a Credit Party), in respect of which any consent that is required by Section 20.1(b)has been obtained.
“Environmental Adverse Effect” means one or more of the following in connection with an Environmental Matter:
(a)
impairment or adverse alteration of the quality of the natural environment for any use that can be made of it by humans, or by any animal, fish or plant that is useful to humans;
(b)
injury or damage to property or to plant or animal life;
(c)
harm or material discomfort to any Person;
(d)
an adverse effect on the health of any Person;
(e)
impairment of the safety of any Person;
(f)
rendering any property or plant or animal life unfit for human use;
(g)
loss of enjoyment of normal use of property; and
(h)
interference with the normal conduct of business.
“Environmental Approvals” means all applicable permits, licences, authorizations, consents, directions or approvals required by Governmental Authorities pursuant to the Environmental Laws with respect to the operation of the Business.

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“Environmental Laws” means all applicable federal, provincial and local laws, by-laws, rules, regulations, orders, codes and judgments relating to the protection of the environment and public health and safety, and without restricting the generality of the foregoing, includes without limitation those Environmental Laws relating to the storage, transportation, treatment and disposal of Hazardous Substances, employee and product safety, and the Release or threatened Release of Hazardous Substances into the air, surface water, ground water, land surface, subsurface strata or any building or structure and, in each such case, as such Environmental Laws may be amended or supplemented from time to time.
“Environmental Liability” means any liability of the Borrower under any Environmental Laws or any other applicable law for any adverse impact on the environment, health or safety, including the Release of a Hazardous Substance, and any liability for the costs of any clean-up, preventative or other remedial action including costs relating to studies undertaken or arising out of security fencing, alternative water supplies, temporary evacuation and housing and other emergency assistance undertaken by any Governmental Authority to prevent or minimize any actual or threatened Release by the Borrower of any Hazardous Substance.
“Environmental Matter” means any past, present or future activity, event or circumstance in respect of the environment, health or safety including the Release of any Hazardous Substance including any substance which is hazardous to Persons, animals, plants, or which has a detrimental effect on the soil, air or water, or the generation, treatment, storage, use, manufacture, holding, collection, processing, treatment, presence, transportation or disposal of any Hazardous Substances.
“Environmental Proceeding” means any judgment, action, proceeding or investigation pending before any court or Governmental Authority, including any environmental Governmental Authority, with respect to or threatened against or affecting the Borrower or relating to the assets or liabilities of the Borrower or any of their respective operations, in connection with any Environmental Laws, Environmental Matter or Environmental Liability.
“Equity Securities” means, with respect to any Person, any and all shares, interests, participations, rights in, or other equivalents (however designated and whether voting or non-voting) of, such Person’s capital, whether outstanding on the date hereof or issued after the date hereof, including any interest in a partnership, limited partnership or other similar Person and any beneficial interest in a trust, and any and all rights, warrants, options or other rights exchangeable for or convertible into any of the foregoing.
“Equivalent Amount” means, with respect to any two currencies, the amount obtained in one such currency when an amount in the second currency is translated into the first currency using the Spot Rate between such currencies on the Business Day for which such computation is made.
“Event of Default” shall have the meaning specified in Section 12.1.

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“Excluded Taxes” means, with respect to the Agent, any Lender or any other recipient of any payment to be made by or on account of any obligation of a Credit Party hereunder or under any Loan Document, (a) taxes imposed on or measured by its net income, and franchise taxes imposed on it (in lieu of net income taxes), by the jurisdiction (or any political subdivision thereof) under the laws of which such recipient is organized or in which its principal office is located or, in the case of any Lender, in which its applicable lending office is located, (b) any branch profits taxes or any similar tax imposed by any jurisdiction in which the Lender is located and (c) in the case of a Foreign Lender (other than (i) an assignee pursuant to a request by the Borrower under Section 13.3(b), (ii) an assignee pursuant to an Assignment and Assumption made when an Event of Default has occurred and is continuing, or (iii) any other assignee to the extent that the Borrower has expressly agreed that any withholding tax shall be an Indemnified Tax), any withholding tax that (A) is imposed or assessed other than in respect of an Accommodation that was made on the premise that an exemption from such withholding tax would be available where the exemption is subsequently determined, or alleged by a taxing authority, not to be available and (B) is required by Applicable Law to be withheld or paid in respect of any amount payable hereunder or under any Loan Document to such Foreign Lender at the time such Foreign Lender becomes a party hereto (or designates a new lending office) or is attributable to such Foreign Lender’s failure or inability (other than as a result of a Change in Law) to comply with Section 13.2(e), except to the extent that such Foreign Lender (or its assignor, if any) was entitled, at the time of designation of a new lending office (or assignment), to receive additional amounts from a Credit Party with respect to such withholding tax pursuant to 13.2(a). For greater certainty, for purposes of item (c) above, a withholding tax includes any Tax that a Foreign Lender is required to pay pursuant to Part XIII of the Income Tax Act (Canada) or any successor provision thereto.
“Face Amount” means (i) in respect of a Bankers’ Acceptance, the amount payable to the holder on its maturity; and (ii) in respect of a Documentary Credit, the maximum amount which the Documentary Credit Lender is contingently liable to pay the Beneficiary.
FATCA” means Sections 1471 through 1474 of the Internal Revenue Code, as of the date of this Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future regulations or official interpretations thereof and any agreements entered into pursuant to Section 1471(b)(1) of the Internal Revenue Code, any intergovernmental agreements entered into in connection with the implementation of the foregoing, and any fiscal or regulatory legislation, rules, guidance or practices by any jurisdiction to implement the foregoing.
“Federal Funds Rate” means, for any day, the rate per annum equal to the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System arranged by federal funds brokers on such day, as published by the Federal Reserve Bank of New York on the Business Day next succeeding such day; provided, that (a), if such day is not a Business Day, the Federal Funds Rate for such day shall be such rate on such transactions on the next preceding Business Day as so published on the next succeeding Business Day and (b) if no such rate is so published on such next day succeeding Business

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Day, the Federal Funds Rate for such day shall be the average rate charged to the Agent on such day on such transactions as determined by the Agent.
“Financial Instrument Obligation” means the obligation under any transaction that is a rate swap, basis swap, forward rate transaction, commodity swap, commodity option, commodity future, equity or equity index swap or option, bond, note or bill option, interest rate option, forward foreign exchange transaction, cap, collar or floor transaction, currency swap, cross-currency rate swap, swaption, currency option or any other similar transaction, including any option to enter into any of the foregoing, or any combination of the foregoing. The amount of any Financial Instrument Obligation is the net amount due to or accruing due under the agreement governing such obligation, determined by marking the obligation to market at the time of determination in accordance with its terms.
“Fiscal Quarter” means, in respect of the Borrower, a period of three consecutive months in each Fiscal Year ending on March 31, June 30, September 30 and December 31, as the case may be, of such year, or such other fiscal quarter as the Lenders may agree to.
“Fiscal Year” shall mean with respect to the Borrower, a 12-month period commencing on the first day of January of each calendar year, or such other fiscal year as the Lenders may agree to.
“Foreign Lender” means any Lender that is not resident for income tax or withholding tax purposes under the laws of the jurisdiction in which the Borrower is resident for tax purposes on the date hereof and that is not otherwise considered or deemed in respect of any amount payable to it hereunder or under any Loan Document to be resident for income tax or withholding tax purposes in the jurisdiction in which the Borrower is resident for tax purposes by application of the laws of that jurisdiction. For purposes of this definition Canada and each Province and Territory thereof shall be deemed to constitute a single jurisdiction and the United States of America, each State thereof and the District of Columbia shall be deemed to constitute a single jurisdiction.
“GAAP” means (i) generally accepted accounting principles as approved by the Canadian Institute of Chartered Accountants or any successor institute from time to time, including those set out in the CPA Canada Handbook, or (ii) IFRS, if the Borrower has adopted IFRS, subject at all times to the application of Section 1.5.
“General Partner” means AltaLink Investment Management Ltd., a corporation incorporated under the Business Corporations Act (Alberta), in its capacity as general partner of the Borrower, and its permitted successors and permitted assigns in such capacity.
“Governmental Approvals” means any authorization, order, permit, approval, grant, licence, consent, right, privilege, certificate or the like which may be issued or granted by law or by rule, regulation, policy or directive of any Governmental Authority now or hereafter required in connection with the use, management, maintenance and operation of the Business by the Borrower and its Subsidiaries.

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“Governmental Authority” means with respect to any Person, any (i) international tribunal, agency, body, commission or other authority, any government, executive, parliament, legislature or local authority, or any governmental body, ministry, department or agency or regulatory authority, court, tribunal, commission or board of or within Canada or any foreign jurisdiction, or any political subdivision of any thereof or any authority having jurisdiction therein or (ii) quasi-governmental or private body exercising any regulatory, expropriation or taxing authority under or for the account of any of the above, which in each case, has jurisdiction over a specified Person or its property and assets under the laws of the jurisdiction in which that Person or its property and assets are located.
“Guarantee” means, with respect to a Person, any obligation (other than an endorsement in the ordinary course of business of negotiable instruments for deposit or collection) of such Person guaranteeing, or in effect guaranteeing, any Indebtedness or other obligation of any other Person (the “primary obligor”) in any manner, whether directly or indirectly, including any obligation incurred through an agreement, contingent or otherwise, by such Person:
(a)
to purchase such Indebtedness or obligation or any property or assets constituting security therefor;
(b)
to advance or supply funds (i) for the purchase or payment of such Indebtedness or obligation, (ii) to maintain working capital, net worth or other balance sheet condition of the primary obligor, or (iii) otherwise to advance or make available funds for the purchase or payment of such Indebtedness or obligation;
(c)
to lease property or to purchase securities or other property or services primarily for the purpose of assuring the owner of such Indebtedness or obligation of the ability of the primary obligor to make payment of the Indebtedness or obligation; or
(d)
otherwise to assure or indemnify the owner of the Indebtedness or obligation of the primary obligor against loss in respect thereof.
For the purposes of all computations made under this Agreement, a Guarantee in respect of any Indebtedness shall be deemed, without duplication, to be equal to the principal amount of such Indebtedness and any capitalized interest thereon (and any other amount which becomes due and owing in respect thereof) which has been guaranteed, and a Guarantee in respect of any other obligation shall be deemed to be Indebtedness equal to the maximum aggregate amount of such obligation.
“Hazardous Substance” means any contaminant, pollutant or substance that is likely to cause immediately, or at some future time, harm or degradation to the environment or risk to human health or safety, and without restricting the generality of the foregoing, includes without limitation any pollutant, contaminant, waste, hazardous waste, toxic substance or dangerous good which is defined or identified in any Environmental Law or industry standard, or which is present in the environment in such quantity or state that it contravenes any Environmental Law.

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“IFRS” means at any given date, International Financial Reporting Standards, which include standards and interpretations adopted by the International Accounting Standards Board (IASB), applied on a consistent basis.
“Income Tax Expense” shall mean, with respect to the Borrower for any fiscal period, the aggregate of all taxes on the income of the Borrower for such period, whether current or deferred, determined on an unconsolidated basis in accordance with GAAP.
“Indebtedness” of any Person means, at any time, (without duplication),
(a)
the aggregate principal amount of all obligations of that Person for borrowed money (other than Obligations arising out of the issuance of any Refunding Bonds (as such term is defined in the Master Trust Indenture) during such period of time as the Indebtedness to be repaid by the Refunding Bonds continues to be outstanding), including obligations with respect to bankers’ acceptances and contingent reimbursement obligations in respect of letters of credit and other instruments, and including all capitalized interest and other similar amounts required to be paid at maturity on obligations for borrowed money, but excluding Preferred Securities issued by that Person;
(b)
the aggregate principal amount of all obligations issued or assumed by that Person in connection with its acquisition of property in respect of the deferred purchase price of that property;
(c)
all Capital Lease Obligations and the aggregate principal amount of all Purchase Money Obligations of that Person;
(d)
the amount of any Mark-to-Market Exposure with respect to any Financial Instrument Obligations of that Person;
(e)
the principal amount of all borrowed money outstanding from time to time under any Commercial Paper Program;
(f)
the principal amount of all borrowed money outstanding from time to time which constitutes Subordinated Debt (as such term is defined in the Master Trust Indenture); and
(g)
all Guarantees of that Person in respect of any of the foregoing;
in each case expressed in Canadian Dollars and, with respect to any amount which is expressed in any other currency, the Canadian Dollar amount thereof shall be the Equivalent Amount at the time of determination. For greater certainty: (i) the capitalization of interest or other similar amounts payable at maturity on existing Indebtedness shall not be treated as the incurrence of Indebtedness, and (ii) the aggregate amount of all regulatory liabilities and asset retirement obligations shall not be treated as Indebtedness.
“Indemnified Taxes” means Taxes other than Excluded Taxes.

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“Insurance Proceeds” means insurance proceeds or other awards payable to the Borrower or any of its Subsidiaries in connection with the loss, destruction or condemnation of any property or assets of such Person, net of reasonable costs, fees and expenses for repairing or replacing any such property or assets.
“Interest Expense” shall mean, with respect to the Borrower for any fiscal period, interest expense and payments made in respect of Capital Lease Obligations, determined on an unconsolidated basis in accordance with GAAP, and which shall exclude amortization of financing fees.
“Investments” means, in respect of any Person, any advances, loans, guarantees or other extensions of credit or capital contributions (other than prepaid expenses in the ordinary course of business) to (by means of transfers of property, money or assets) any other Person, and, for greater certainty, includes any Indebtedness of any other Person guaranteed by such Person.
“Issue” means an issue of a Documentary Credit by the Documentary Credit Lender pursuant to Article 3.
“Issue Notice” has the meaning given to it in Section 3.2(a).
“Lenders” means RBC and all other financial institutions from time to time that have become a Lender in accordance with this Agreement and the Documentary Credit Lender and “Lender” means any one of them.
“LIBOR Interest Period” means, from time to time with respect to a LIBOR Loan, the applicable interest period of one, two, three or six months ending on a Business Day and on or before the applicable Maturity Date, as selected in accordance with Section 4.2.
“LIBOR Loan” means any Loan in U.S. Dollars with respect to which interest is calculated under this Agreement for the time being on the basis of the LIBOR Rate, the minimum aggregate principal amount of which included in any Borrowing shall be Two Hundred and Fifty Thousand U.S. Dollars (U.S.$250,000) or any greater amount which is a whole multiple of Two Hundred and Fifty Thousand U.S. Dollars (U.S.$250,000).
“LIBOR Rate” means, for any LIBOR Interest Period with respect to any LIBOR Loan:
(a)
the rate of interest per annum, expressed on the basis of a year of 360 days, determined by the Agent, which is equal to the offered rate that appears on the page of the Reuters LIBOR01 screen (or any successor thereto as may be selected by the Agent) that displays an average British Bankers Association Interest Settlement Rate for deposits in U.S. Dollars with a term equivalent to such LIBOR Interest Period, determined as of approximately 11:00 a.m. (London time) two (2) Business Days prior to the first day of such LIBOR Interest Period, or
(b)
if the rates referenced in the preceding subsection (a) are not available, the rate per annum determined by the Agent as the rate of interest, expressed on a basis of 360

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days at which deposits in U.S. Dollars for delivery on the first day of such LIBOR Interest Period in same day funds in the approximate amount of the LIBOR Loan being made, continued or converted by the Agent and with a term and amount comparable to such LIBOR Interest Period and principal amount of such LIBOR Loan as would be offered by the Agent’s London Branch to major banks in the offshore U.S. Dollar market at their request at approximately 11:00 a.m. (London time) two (2) Business Days prior to the first day of such LIBOR Interest Period;
provided that if any such rate is less than zero, the LIBOR Rate will be deemed to be zero.
“Lien” means any mortgage, lien, pledge, assignment, charge (whether floating or fixed), security, title retention agreement intended as security, hypothec, execution, seizure, attachment, garnishment or other similar encumbrance and any other arrangement which has the effect of creating an interest in property to secure payment or performance of an obligation including, without limitation, any Lien granted by the Borrower in favour of the Agent and Lenders designated as being secured, pursuant to the Master Trust Indenture and/or a Supplemental Indenture.
“Loan” means the amount of Canadian Dollars or U.S. Dollars advanced by a Lender or Lenders to the Borrower on any Borrowing Date pursuant to a Borrowing Notice or as otherwise provided herein and includes a Prime Rate Loan, a LIBOR Loan and a U.S. Base Rate Loan.
“Loan Documents” means this Agreement, any Documentary Credit documents, forms of Drafts, or agreements relating to Bankers’ Acceptances required by any Lender and, when executed and delivered by or on behalf of the Borrower, the Master Trust Indenture and the Third Supplemental Indenture, the Senior Pledged Bond, Series 2, the Bond Delivery Agreement and all other documents, certificates, fee letters, instruments and agreements to be executed and delivered to the Agent or the Lenders by any Credit Party as contemplated hereunder and thereunder or any one or more of such documents.
“Majority Lenders” means, (i) where there are less than three Lenders, all Lenders and (ii) at any other time, Lenders having, in the aggregate, Applicable Percentages of a minimum of 66.7% of the Committed Amount.
“Mark-to-Market Exposure” means, at any time, the negative net marked to market amount, if any, that would be carried in the accounts of the Borrower at such time as a liability in accordance with GAAP.
“Master Trust Indenture” means the trust indenture dated as of the 21st day of November, 2005 among the Borrower, the General Partner and BNY Trust Company of Canada, as trustee, as such agreement may be amended and supplemented from time to time.
“Material Adverse Change” means a change in the business, operations, results of operations, Assets, liabilities or financial condition of the Borrower and its Subsidiaries, taken as a whole, that would reasonably be expected to have a Material Adverse Effect.

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“Material Adverse Effect” means a material adverse effect on the ability of the Borrower to perform its obligations under this Agreement or any of the other Loan Documents or on the validity or priority of any Lien held by the Agent, or an event which results in an Event of Default and includes an Environmental Adverse Effect which constitutes or results in any of the foregoing effects.
“Material Agreement” means, collectively (i) the agreements specified by the Borrower in Schedule 10; and (ii) any other agreement of the Borrower or any of its Subsidiaries the breach, non-performance or cancellation of which or the failure of which to renew could reasonably be expected to have a Material Adverse Effect.
“Maturity Date” means, in respect of each Lender, unless otherwise accelerated as provided in this Agreement, December 14, 2024, as such date may be extended by such Lender in its sole discretion pursuant to Section 6.2(b), in which case, the Maturity Date in respect of such Lender shall be the date agreed to by such Lender pursuant to Section 6.2(b).
“Net Income” means, with respect to the Borrower for any period, the net income (loss) of the Borrower for such period, determined on an unconsolidated basis in accordance with GAAP, provided there shall be excluded therefrom (i) after-tax gains or losses from assets sales or abandonments or reserves relating thereto; (ii) after-tax items classified as extraordinary or non-recurring gains or losses; (iii) gains or losses from write-ups or write-downs of Assets; and (iv) net income (loss) from discontinued operations or the sale of discontinued operations.
“Non-AltaLink Subsidiary” means, individually, any Subsidiary of the Borrower other than AltaLink and its Subsidiaries, and “Non-AltaLink Subsidiaries” means all such Subsidiaries of the Borrower.
“Notice of Extension” shall have the meaning specified in Section 6.2(b).
“Notice of Repayment” has the meaning given to it in Section 6.1(a).
“Other Taxes” means all present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies arising from any payment made hereunder or under any other Loan Document or from the execution, delivery or enforcement of, or otherwise with respect to, this Agreement or any other Loan Document.
“Participant” has the meaning specified in Section 20.1(d).
“Permitted Lien” means, in connection with the Borrower and any Non-AltaLink Subsidiary:
(a)
any Purchase Money Mortgage or Lien granted with respect to a Capital Lease Obligation, provided that the total Indebtedness secured by such Purchase Money Mortgages and Liens shall not exceed ten million dollars ($10,000,000) at any time;

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(b)
any Lien for taxes, assessments, government charges or claims not yet due or that are being contested in good faith and in respect of which appropriate provision is made in the Borrower’s consolidated financial statements in accordance with GAAP;
(c)
any Lien securing appeal bonds or other similar liens arising in connection with court proceedings or contracts, bids or tenders entered into in the ordinary course of business, including, without limitation, surety bonds, security for costs of litigation where required by law, Documentary Credits, or any other instruments serving a similar purpose;
(d)
any Lien or deposit under workers’ compensation, social security or similar legislation or good faith deposits in connection with bids, tenders, leases and contracts entered into in the ordinary course of business or expropriation proceedings, or deposits to secure public or statutory obligations or deposits of cash or obligations to secure surety and appeal bonds;
(e)
any Lien or privilege imposed by law, such as builders’, carriers’, warehousemen’s, landlords’, mechanics’ and materialmen’s liens and privileges arising in the ordinary course of business which relate to Indebtedness not yet due or delinquent or the validity or amount of which are being contested in good faith and in respect of which adequate provision for payment has been made; any lien or privilege arising out of judgments or awards with respect to which the Borrower is prosecuting an appeal or proceedings for review and with respect to which it has secured a stay of execution pending that appeal or proceedings for review (provided no Event of Default has resulted therefrom); or undetermined or inchoate Liens and privileges incidental to current operations which have not at such time been filed pursuant to law against the Borrower or the applicable Non-AltaLink Subsidiary or which relate to obligations not due or delinquent; or the deposit of cash or securities in connection with any Lien or privilege referred to in this paragraph (e);
(f)
a Lien in cash or marketable debt securities in a sinking fund account established by the Borrower in support of a particular series of bonds under the Master Trust Indenture;
(g)
any encumbrance, such as easements, rights-of-way, servitudes or other similar rights in land granted to or reserved by other Persons, rights-of-way for access, sewers, electric lines, telegraph and telephone lines, oil and natural gas pipe lines and other similar purposes, or zoning or other restrictions as to the Borrower’s use of real property or interests therein, which do not in the aggregate materially impair its use in the operation of the Business;
(h)
any right reserved to or vested in any municipality or governmental or other public authority (whether by statutory provision or otherwise) to terminate, purchase assets used in connection with, or require annual or other periodic payments as a condition to the continuance of, any lease, licence, franchise, grant or permit;

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(i)
any lien or right of distress reserved in or exercisable under any lease for rent and for compliance with the terms of that lease;
(j)
any Lien granted by the Borrower or the applicable Non-AltaLink Subsidiary to a public utility or any municipality or governmental or other public authority when required by that utility, municipality or other authority in connection with the operations of the Borrower;
(k)
any reservation, limitation, proviso or condition, if any, expressed in any original grants to the Borrower or the applicable Non-AltaLink Subsidiary from the Crown; and
(l)
any extension, renewal, alteration, substitution or replacement, in whole or in part, of any Lien referred to in any of the foregoing paragraphs, provided that the Lien is limited to all or part of the same property that secured the Lien and the principal amount of the secured Indebtedness is not increased by that action.
“Person” means any individual, corporation, company, voluntary association, partnership, limited liability company, unlimited liability company, joint venture, trust, unincorporated organization or Governmental Authority or other entity of whatever nature.
“Preferred Securities” means any securities which on the date of issue by a Person (a) have a term to maturity of more than thirty (30) years; (b) are unsecured and rank subordinate to the unsecured and unsubordinated Indebtedness of that Person outstanding on that date; (c) entitle that Person to satisfy the obligation to pay the principal or face amount by issuing partnership units, limited partnership units or other securities evidencing an ownership interest, (d) entitle that Person to defer the payment of interest for more than four (4) years without causing an event of default to occur, and (e) entitle that Person to satisfy the obligation to make payments of interest by issuing partnership units, limited partnership units or other securities evidencing an ownership interest.
“Prime Rate” means for any day, the rate of interest per annum equal to the greater of (i) the per annum rate of interest quoted or established as the “prime rate” of the Agent which it quotes or establishes for such day as its reference rate of interest in order to determine interest rates for commercial loans in Canadian Dollars in Canada to its Canadian borrowers; and (ii) the average rate for Canadian Dollar banker’s acceptances having a term of one month that appears on Reuters Screen page CDOR (or such other page as is a replacement page for such banker’s acceptances) at approximately 10:00 a.m. (Toronto time) on such day plus 75 basis points per annum, adjusted automatically with each quoted or established change in such rate, all without the necessity of any notice to the Borrower or any other Person.
“Prime Rate Loan” means any Loan in Canadian Dollars with respect to which interest is calculated under this Agreement for the time being on the basis of the Prime Rate.
“Principal Property” means any of the Borrower’s fixed assets from time to time.

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“Purchase Money Mortgage” means any Lien created, issued or assumed by a Person to secure a Purchase Money Obligation of such Person; provided that the Lien is limited only to the assets acquired or constructed (together with all improvements and accessions thereto and proceeds thereof) using the funds advanced to such Person in connection with that Purchase Money Obligation.
“Purchase Money Obligation” means, with respect to any Person, Indebtedness of that Person incurred or assumed to finance the cost, in whole or in part, of the acquisition or construction of any equipment, real property or fixtures, and the cost of installation and any improvements thereto, so long as the Indebtedness is incurred or assumed within twenty-four (24) months after the purchase of that equipment, real property or fixture or the completion of that construction, installation or improvement, as the case may be, and includes any extension, renewal or refunding of any of that Indebtedness, so long as the principal amount thereof outstanding on the date of the extension, renewal or refunding is not increased.
Rating Agency” means DBRS or Standard & Poor’s and any other nationally recognized credit rating agency approved by the Majority Lenders.
“RBC” means Royal Bank of Canada, its successors and permitted assigns.
“Register” has the meaning specified in Section 20.1(c).
“Related Parties” means, with respect to any Person, such Person’s Affiliates and the directors, officers, employees and agents of such Person and of such Person’s Affiliates.
“Release” means the method by which a Contaminant comes to be in the environment at large and includes discharging, spraying, injection, abandonment, depositing, spilling, leaking, seeping, pouring, emitting, emptying, throwing, dumping, placing and exhausting, and when used as a noun has a correlative meaning.
“Remedial Order” means any administrative complaint, direction, order or sanction issued, filed or imposed by any Governmental Authority pursuant to any Environmental Laws and includes any order requiring investigation, assessment or remediation or any site or Hazardous Substance, or requiring that any Release or any other activity be reduced, modified or eliminated or requiring any form of payment or co-operation be provided to any Governmental Authority.
“Schedule I Bank” means a bank listed on Schedule I under the Bank Act (Canada).
“Schedule II Bank” means a bank listed on Schedule II under the Bank Act (Canada).
“Schedule III Bank” means a bank listed on Schedule III under the Bank Act (Canada).
“Scheduled Unavailability Date” has the meaning specified in Section 2.12.
“Screen Rate” has the meaning specified in Section 2.12.

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“Senior Bonds, Series 13-1” means the 3.265% Series 13-1 senior bonds issued by the Borrower under the Master Trust Indenture and the Series 13-1 Supplemental Indenture.
“Senior Bonds, Series 15-1” means the 2.244% Series 15-1 senior bonds issued by the Borrower under the Master Trust Indenture and the Series 15-1 Supplemental Indenture.
Senior Pledged Bond, Series 2 means the Three Hundred and Fifty Million Canadian Dollars (Cdn.$350,000,000) Senior Pledged Bond, Series 2 of the Borrower, issued and certified on December 15, 2010 under the Master Trust Indenture.
“Series 13-1 Supplemental Indenture” means the Series 13-1 Supplemental Indenture between the Borrower, the General Partner and the Trustee dated as of the 9th day of April, 2013 pursuant to which the Borrower issued the Senior Bonds, Series 13-1, as such indenture may be amended, supplemented or modified from time to time.
“Series 15-1 Supplemental Indenture” means the Series 15-1 Supplemental Indenture between the Borrower, the General Partner and the Trustee dated as of the 6th day of March, 2015 pursuant to which the Borrower issued the Senior Bonds, Series 15-1, as such indenture may be amended, supplemented or modified from time to time.
Spot Rate” means, in relation to the conversion of one currency into another currency, the spot rate of exchange for such conversion as quoted by the Bank of Canada at the close of business on the Business Day that such conversion is to be made (or, if such conversion is to be made before close of business on such Business Day, then at approximately close of business on the immediately preceding Business Day,), and, in either case, if no such rate is quoted, the spot rate of exchange quoted for wholesale transactions by the Agent on the Business Day such conversion is to be made in accordance with its normal practice.
“Standard & Poor’s” means Standard & Poor’s Ratings Service and its successors for so long as it shall perform the functions of a securities rating agency.
“Subsidiary” means (a) any corporation of which there is owned, directly or indirectly, by the Borrower and/or by or for any corporation in like relation to the Borrower, voting shares which, in the aggregate, entitle the holders thereof to cast more than fifty per cent (50%) of the votes which may be cast by the holders of the outstanding voting shares of such first mentioned corporation for the election of its directors and includes any corporation in like relation to a Subsidiary; or (b) any other Person of which at least a majority of voting ownership interest is at the time, directly or indirectly, owned by the Borrower and/or by any Person in like relation to the Borrower.
“Successor Rate” has the meaning specified in Section 2.12.
“Taxes” means all present or future taxes, levies, imposts, duties, deductions, withholdings, assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

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“Third Supplemental Indenture” means the Third Supplemental Indenture between the Borrower, the General Partner and the Trustee dated as of December 15, 2010 and attached hereto as Schedule 8, pursuant to which the Borrower shall issue the Senior Pledged Bond, Series 2, as such indenture may be amended, supplemented or modified from time to time.
“Trustee” means BNY Trust Company of Canada, as trustee under the Master Trust Indenture or any successor thereof.
“Type” means the type of Documentary Credit, being a letter of credit or a letter of guarantee.
“Undisbursed Credit” means, at any time, the excess, if any, of the Committed Amount then in effect over the Canadian Dollar Amount of all Accommodations then outstanding under the Credit Facility.
“U.S. Base Rate” means, for any day, the rate of interest per annum equal to the greater of (i) the per annum rate of interest which the Agent (or such other Person as agreed to by the Borrower and the Agent) quotes or establishes for such day as its reference rate of interest for loans in U.S. Dollars to borrowers in Canada; and (ii) the Federal Funds Rate plus 50 basis points per annum, adjusted automatically with each quoted or established change in such rate, all without the necessity of any notice to Borrower or any other Person.
“U.S. Base Rate Loan” means any Loan in U.S. Dollars with respect to which interest is calculated under this Agreement for the time being on the basis of the U.S. Base Rate.
“U.S. Dollars” or “U.S.$” means lawful money of the United States of America.
1.2
References.
The terms “ARTICLE”, “Section”, “subsection” or “paragraph” followed by a number refer to the specified ARTICLE, Section, subsection or paragraph of this Agreement unless otherwise expressly stated or the context otherwise requires. References to contracts, agreements or instruments, unless otherwise specified, are deemed to include all present and future amendments, supplements, restatements or replacements to or of such contracts, agreements or instruments, provided that such amendments, supplements, restatements or replacements to or of such contracts, agreements or instruments have been, if applicable, approved or consented to and otherwise made in accordance with the provisions of this Agreement.
1.3
Headings.
The Article or Section or other headings contained in this Agreement are inserted for convenience only and shall not affect the meaning or construction of any of the provisions of this Agreement.
1.4
Included Words.
Words importing the singular number only shall include the plural and vice versa where the context requires. The word “include” and derivatives thereof means “include without limitation”.
1.5
Accounting Terms.

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Subject to this Section 1.5, all accounting terms not otherwise defined in this Agreement shall have the meanings assigned to them by GAAP. The Borrower may adopt new accounting policies from time to time (including with respect to IFRS) whether such adoption is compelled by accounting or regulatory bodies having jurisdiction or at its own discretion. In the event that any changes to accounting policies result in a material change in the calculation of the financial covenants or financial covenant thresholds or terms used in this Agreement or any other Loan Document, the Borrower, the Agent and the Lenders agree to enter into negotiations in order to amend such provisions of this Agreement or such Loan Document, as applicable, so as to equitably reflect such accounting changes with the desired result that the criteria for evaluating the Borrower’s or any of its Subsidiary’s financial condition, financial covenants, financial covenant thresholds or terms used in this Agreement or any other Loan Document shall be the same after such accounting changes as if such accounting changes had not been made; provided, however, that the agreement of the Majority Lenders to any required amendments of such provisions shall be sufficient to bind all Lenders. If the Borrower and the Majority Lenders cannot agree upon the required amendments immediately prior to the date of implementation of any accounting policy change, then all calculations of financial covenant, financial covenant thresholds or terms used in this Agreement or any other Loan Document shall be prepared and delivered on the basis of accounting policies of the Borrower as at the date hereof without reflecting such accounting policy change.
1.6
Time.
Unless otherwise expressly stated, any reference herein to a time shall mean local time in Calgary, Alberta.
1.7
Currency.
Unless otherwise specified herein, or the context otherwise requires, all statements of or references to dollar amounts in this Agreement and the Loan Documents shall mean Canadian Dollars.
1.8
Certificates and Opinions.
(a)
Unless otherwise provided in a particular Schedule to this Agreement, each certificate and each opinion furnished pursuant to any provision of this Agreement shall specify the Section or Sections under which such certificate or opinion is furnished, shall include a statement that the Person making such certificate or giving such opinion has read the provisions of this Agreement relevant thereto and shall include a statement that, in the opinion of such Person, such Person has made such examination and investigation as is necessary to enable such Person to express an informed opinion on the matters set out in the certificate or opinion.
(b)
Whenever the delivery of a certificate or opinion is a condition precedent to the taking of any action by the Agent or a Lender or Lenders under this Agreement, the truth and accuracy of the facts and opinions stated in such certificate or opinion shall in each case be conditions precedent to the right of the Borrower to have such action taken, and each statement of fact contained therein shall be deemed to be a representation and warranty of the Borrower for the purposes of this Agreement.

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1.9
Amendment and Restatement; No Novation
The parties hereto acknowledge and confirm that this Amended and Restated Credit Agreement does not constitute a novation of the Existing Credit Agreement and that all debts, liabilities and obligations (including without limitation any issued and outstanding Documentary Credits) of the Borrower under the Existing Credit Agreement (i) shall be debts, liabilities and obligations of the Borrower under this Amended and Restated Credit Agreement, (ii) shall remain unaffected, except as amended hereby and (iii) shall constitute “Obligations” for the purposes of the Third Supplemental Indenture and the Senior Pledged Bond, Series 2.
1.10
Schedules.
The following are the Schedules attached to and forming part of this Agreement:
Schedule 1
Borrower’s Certificate of Compliance
Schedule 2(A)
Borrowing Notice
Schedule 2(B)
Notice of Rollover
Schedule 2(C)
Conversion Option Notice
Schedule 3
Notice of Extension
Schedule 4
Form of Issue Notice
Schedule 5
Assignment and Assumption
Schedule 6
Commitments of the Lenders
Schedule 6.1(a)
Form of Notice of Repayment
Schedule 7
Senior Pledged Bond, Series 2
Schedule 8
Third Supplemental Indenture
Schedule 9.1(a)
Credit Party and Subsidiary Information
Schedule 10
Material Agreements

ARTICLE 2    
AMOUNT AND TERMS OF THE CREDIT FACILITY
2.1
Credit Facility.
(a)
Subject to and upon the terms and conditions set forth in this Agreement, effective upon the Effective Date, the existing revolving credit facility under the Existing Credit Agreement shall be amended and restated as a revolving term credit facility in the maximum aggregate principal amount equal to three hundred million ($300,000,000.00) and the Lenders hereby agree to establish in favour of the Borrower such revolving term credit facility by way of Prime Rate Loans, U.S. Base Rate Loans, Bankers’ Acceptances and LIBOR Loans. The Credit Facility shall also include a sub-facility, to the maximum aggregate Canadian Dollar Amount of Ten Million Canadian Dollars (Cdn.$10,000,000), to be provided by the Documentary Credit Lender only by way of Documentary Credits on such terms as are agreed upon between the Borrower and the Documentary Credit Lender. The aggregate

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Canadian Dollar Amount of all Accommodations outstanding at any time under this Credit Facility shall not exceed the Committed Amount.
2.2
Cancellation.
Subject to the provisions of ARTICLE 6, the Borrower may, at any time, by giving not less than two (2) Business Days’ prior written notice of cancellation to the Agent, cancel all or any part of the Undisbursed Credit as designated by the Borrower without penalty, provided that, if it is a part only, the minimum amount cancelled is One Million Canadian Dollars (Cdn.$1,000,000) or any multiples of One Million Canadian Dollars (Cdn.$1,000,000) in excess thereof. Effective on the date of cancellation set out in the applicable notice of cancellation, the Credit Facility and the Committed Amount shall be permanently reduced by the amount of Canadian Dollars stated in the notice of cancellation.
2.3
Use of Proceeds.
The proceeds of the Credit Facility shall be used by the Borrower for operating expenses, capital expenditures and working capital needs of the Borrower and AltaLink and their Subsidiaries, and for general corporate purposes including the payment of dividends by the Borrower on its Equity Securities.
2.4
Particulars of Borrowings.
(a)
Notwithstanding any contrary provision contained in the Loan Documents, in the event of any conflict or inconsistency between any of the provisions in this Agreement and any of the provisions in the Loan Documents, as against the parties hereto, the provisions of this Agreement shall prevail.
(b)
No Borrowing from any Lender shall be obtained at any time for any period which would extend beyond the earlier of (i) the date which is 364 days following the Borrowing Date in respect of such Borrowing, and (ii) the Maturity Date of such Lender.
(c)
Subject to the provisions hereof, any Accommodation which is repaid at any time prior to the expiry of the Maturity Date may be subsequently re-drawn.
2.5
Borrowing Notice.
Whenever the Borrower desires to obtain a Borrowing (other than in the case of a Documentary Credit) it shall give to the Agent prior written notice in the form attached as Schedule 2(A), (B) or (C), as applicable (each, a “Borrowing Notice”), specifying, as applicable:
(i)
the amount, currency and type or types of Accommodation desired;
(ii)
the details of the account of the Borrower to which payment of the Borrowing is to be wired or otherwise made, if applicable;
(iii)
the requested Borrowing Date;

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(iv)
the term thereof;
(v)
if applicable, the Accommodation to be renewed or converted and, where such Accommodation includes any Loan, the currency thereof and the interest rate applicable thereto;
(vi)
if such Borrowing includes a Loan, whether it is to be a Prime Rate Loan, U.S. Base Rate Loan or a LIBOR Loan; and
(vii)
if such Borrowing includes a LIBOR Loan, the LIBOR Interest Period to be applicable to such Loan.
The Borrowing Notice shall be given to the Agent not later than 12:00 p.m. (Toronto, Ontario time):
(viii)
on the applicable Borrowing Date, if the new Accommodation or any Accommodation to be renewed or converted is by way of Prime Rate Loans or U.S. Base Rate Loans. In the event such Accommodation causes a Lender to incur costs relating solely to the providing of same day notice, the Borrower shall pay such costs to such Lender immediately upon request therefor;
(ix)
on the Business Day preceding the applicable Borrowing Date, if the new Accommodation or any Accommodation to be renewed or converted is by way of Bankers’ Acceptances; and
(x)
on the third Business Day preceding the applicable Borrowing Date, if any new Accommodation or any Accommodation to be renewed or converted is a LIBOR Loan.
In all other cases, the Borrowing Notice shall be given to the party entitled thereto on the applicable Borrowing Date.
Any Borrowing Notice received by the Agent on any Business Day after 12:00 p.m. (Toronto, Ontario time) shall be deemed to have been given to such party on the next succeeding Business Day, unless otherwise agreed by the Lenders.
2.6
Books of Account.
The Agent is hereby authorized to open and maintain books of account and other books and records evidencing all Bankers’ Acceptances accepted and cancelled and all Loans advanced and repaid and all other amounts from time to time owing by the Borrower to the Lenders under this Agreement including interest, acceptance, Documentary Credits and standby and other fees, and to enter into such books and records details of all amounts from time to time owing, paid or repaid by the Borrower under this Agreement. The Borrower acknowledges, confirms and agrees with the Agent that all such books and records kept by the Agent will constitute prima facie evidence of the balance owing by the Borrower under this Agreement; provided, however, that the failure to make any entry or recording in such books and records shall not limit or otherwise affect the obligations of the Borrower under this Agreement. Notwithstanding the foregoing, each Lender is responsible for maintaining

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its own records as to Advances made by it, and in the event of any inconsistency between such Lender’s and the Agent’s records, the Agent’s records shall govern, absent manifest error.
2.7
Co-ordination of Prime Rate and U.S. Base Rate Loans.
Each Lender shall advance its Applicable Percentage of each Prime Rate and U.S. Base Rate Loan in accordance with the following provisions:
(a)
the Agent shall advise each Lender of its receipt of a notice from the Borrower pursuant to Section 2.5, on the day such notice is received and shall, as soon as possible, advise each Lender of such Lender’s Applicable Percentage of any Prime Rate or U.S. Base Rate Loan requested by the notice;
(b)
each Lender shall deliver its Applicable Percentage of such Loan to the Agent’s Account at the Branch not later than 11:00 a.m. on the Borrowing Date; and
(c)
when the Agent determines that all the conditions precedent to a Borrowing specified in this Agreement have been met or waived, it shall advance to the Borrower the amount delivered by each Lender by wiring such amount to relevant account of the Borrower before 12:00 noon on the Borrowing Date, but if the conditions precedent to the Borrowing are not met or waived by such time, the Agent shall return the funds to the Lenders or invest them in an overnight investment as orally instructed by each Lender until such time as the Loan is advanced.
2.8
Bankers’ Acceptances.
(a)
Power of Attorney for the Execution of Bankers’ Acceptances. To facilitate acceptance of the Borrowings by way of Bankers’ Acceptances, the Borrower hereby appoints each Lender as its attorney to sign and endorse on its behalf, in handwriting or by facsimile or mechanical signature as and when deemed necessary by such Lender, blank forms of Drafts. In this respect, it is each Lender’s responsibility to maintain an adequate supply of blank forms of Drafts for acceptance under this Agreement. The Borrower recognizes and agrees that all Drafts signed and/or endorsed on its behalf by a Lender shall bind the Borrower fully and effectively as if signed in the handwriting of and duly issued by the proper signing officers of the Borrower. Each Lender is hereby authorized to issue such Drafts endorsed in blank in such Face Amounts as may be determined by such Lenders; provided that the aggregate amount thereof is equal to the aggregate amount of Bankers’ Acceptances required to be accepted and purchased by such Lender. No Lender shall be liable for any damage, loss or other claim arising by reason of any loss or improper use of any such instrument, except the gross negligence or wilful misconduct of the Lender or its officers, employees, agents or representatives. Each Lender shall maintain a record with respect to Bankers’ Acceptances held by it in blank hereunder, voided by it for any reason, accepted and purchased by it hereunder, and cancelled at the respective maturities. Each Lender agrees to provide such records to the Borrower at the Borrower’s expense upon request.

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Drafts drawn by the Borrower to be accepted as Bankers’ Acceptances shall be signed by a duly authorized officer or officers of the Borrower or by its attorneys. Notwithstanding that any Person whose signature appears on any Bankers’ Acceptance may no longer be an authorized signatory for the Borrower at the time of issuance of a Bankers’ Acceptance; that signature shall nevertheless be valid and sufficient for all purposes as if the authority had remained in force at the time of issuance and any Bankers’ Acceptance so signed shall be binding on the Borrower. Upon tender of each Draft the Borrower shall pay to the Lender the fee specified in Section 5.1 with respect to such Draft.
(b)
Sale of Bankers’ Acceptances. It shall be the responsibility of each Lender unless otherwise requested by the Borrower, to purchase its Bankers’ Acceptances at a discount rate equal to the BA Discount Rate.
In accordance with the procedures set forth in Sections 2.8(c)(i) and 2.8(c)(iii), unless the Borrower requests the Lenders not to purchase the subject Bankers’ Acceptances, the Agent will make BA Discount Proceeds received by it from the Lenders available to the Borrower on the Borrowing Date by wiring such amount to the bank account of the Borrower identified to the Agent.
Notwithstanding the foregoing, if in the determination of the Majority Lenders acting reasonably a market for Bankers’ Acceptances does not exist at any time, or the Lenders collectively cannot for other reasons readily sell Bankers’ Acceptances or perform their other obligations under this Agreement with respect to Bankers’ Acceptances, then upon at least two Business Days’ written notice by the Agent to the Borrower, the Borrower’s right to request Accommodation by way of Bankers’ Acceptances shall be and remain suspended until the Agent notifies the Borrower that any condition causing such determination no longer exists.
(c)
Coordination of BA Borrowings. Each Lender shall advance its Applicable Percentage of each Borrowing by way of Bankers’ Acceptances in accordance with the following:
(i)
the Agent, promptly following receipt of a notice from the Borrower pursuant to Section 2.5 requesting a Borrowing by way of Bankers’ Acceptances, shall advise each Lender of the aggregate Face Amount and term(s) of the Bankers’ Acceptances to be accepted by it, which term(s) shall be identical for all Lenders. The aggregate Face Amount of Bankers’ Acceptances to be accepted by a Lender shall be determined by the Agent by reference to the respective Commitments of the Lenders, except that, if the Face Amount of a Bankers’ Acceptance would not be One Hundred Thousand Canadian Dollars (Cdn.$100,000) or a whole multiple thereof, the Face Amount shall be increased or reduced by the Agent in its sole discretion to the nearest whole multiple of One Hundred Thousand Canadian Dollars (Cdn.$100,000);
(ii)
unless requested by the Borrower not to purchase the subject Bankers’ Acceptances, each Lender shall transfer to the Agent at the Branch for value

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on each Borrowing Date immediately available Canadian Dollars in an aggregate amount equal to the BA Discount Proceeds of all Bankers’ Acceptances accepted and sold or purchased by the Lender on such Borrowing Date, net of the applicable Bankers’ Acceptance Fees in respect of such Bankers’ Acceptances. Each Lender shall also advise the Agent (which shall promptly give the relevant particulars to the Borrower) as soon as possible of the discount rate at which it has sold or purchased its Bankers’ Acceptances;
(iii)
if the Borrower requests the Lenders not to purchase the subject Bankers’ Acceptances, each Lender will forward the subject Bankers’ Acceptances to the Agent for delivery against payment of the applicable Bankers’ Acceptance Fees; and
(iv)
if the Agent determines that all the conditions precedent to a Borrowing specified in this Agreement have been met or waived, it shall advance to the Borrower the amount delivered by each Lender by wiring such amount to the account of the Borrower prior to 12:00 noon on the Borrowing Date, or, if applicable shall deliver the Bankers’ Acceptances as directed by the Borrower, but if the conditions precedent to the Borrowing are not met or waived by 2:30 p.m. on the Borrowing Date, the Agent shall return the funds to the Lenders or invest them in an overnight investment as orally instructed by each Lender until such time as the Advance is made.
(d)
Payment. The Borrower shall provide for the payment to the Agent for the account of the Lenders of the Face Amount of each Bankers’ Acceptance at its maturity, either by payment of the amount thereof or through utilization of the Credit Facility in accordance with this Agreement (by rolling over the Bankers’ Acceptance or converting it into other Accommodation or a combination thereof). The Borrower will continue to be required to provide as aforesaid for each Bankers’ Acceptance at maturity notwithstanding the fact that a Lender may be the holder of the Bankers’ Acceptance which has been accepted by such Lender.
(e)
Collateralization.
(i)
If any Bankers’ Acceptance is outstanding on the Demand Date or the Maturity Date, the Borrower shall on such date pay to the Agent for the account of the Lenders at the Branch in Canadian Dollars an amount equal to the Face Amount of such Bankers’ Acceptance.
(ii)
All funds received by the Agent pursuant to Section 2.8(e)(i) shall be held by the Agent for set-off on the maturity date of the Bankers’ Acceptance against the liability of the Borrower to the Lender in respect of such Bankers’ Acceptance and, until then, shall be invested from time to time in such form of investment at the Branch designated by the Borrower and approved by the Agent, for a term corresponding to the maturity date of the applicable Bankers’ Acceptance and shall bear interest at the rate payable by the Agent

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on deposits of similar currency, amount and maturity. The balance of all such funds (together with interest thereon) held by the Agent will be applied to repayment of all debts and liabilities of the Borrower to the Lender under this Agreement and the Loan Documents and following repayment of all such debts and liabilities any amount remaining shall be paid to the Borrower or as otherwise required by law.
(f)
Notice of Rollover or Conversion. The Borrower shall give the Agent notice in the form attached as Schedule 2(B) or Schedule 2(C) hereto, as applicable, not later than 11:00 a.m. on the Business Day prior to the maturity date of Bankers’ Acceptances, specifying the Accommodation into which the Bankers’ Acceptances will be renewed or converted on maturity.
(g)
Obligations Absolute. The obligations of the Borrower with respect to Bankers’ Acceptances under this Agreement shall be unconditional and irrevocable, and shall be paid strictly in accordance with the terms of this Agreement under all circumstances, including, without limitation, the following circumstances:
(i)
any lack of validity or enforceability of any Draft accepted by a Lender as a Bankers’ Acceptance; or
(ii)
the existence of any claim, set-off, defence or other right which the Borrower may have at any time against the holder of a Bankers’ Acceptance, a Lender or any other person or entity, whether in connection with this Agreement or otherwise.
(h)
Shortfall on Drawdowns, Rollovers and Conversions. The Borrower agrees that the difference between the:
(i)
amount of a Borrowing requested by the Borrower by way of Bankers’ Acceptances and the actual proceeds of the Bankers’ Acceptances;
(ii)
actual proceeds of a Bankers’ Acceptance and the amount required to pay a maturing Bankers’ Acceptance if a Bankers’ Acceptance is being rolled over; and
(iii)
actual proceeds of a Bankers’ Acceptance and the amount required to repay any Borrowing which is being converted to a Bankers’ Acceptance,
shall be funded and paid by the Borrower from its own resources, by 11:00 a.m. (Calgary time) on the day of the Borrowing or may be advanced as a Prime Rate Loan if the Borrower is otherwise entitled to such Accommodation and the Agent will apply such Prime Rate Loan to discharge the obligations of the Borrower under such Bankers’ Acceptance. Any such Prime Rate Loan so made shall be subject to the terms and provisions of this Agreement, including payment of interest at the rates specified in Section 4.1.

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(i)
Depository Bills and Notes Act.  At the option of any Lender (and notwithstanding Section 2.8 (a)), Bankers’ Acceptances under this Agreement to be accepted by that Lender may be issued in the form of Depository Bills for a deposit with the Canadian Depository for Securities Limited pursuant to the Depository Bills and Notes Act (Canada). All Depository Bills so issued shall be governed by the provisions of this Section 2.8, as applicable.
(j)
BA Equivalent Loans. Whenever the Borrower requests an Advance that includes Banker’s Acceptances, each Lender that is not permitted by Applicable Law or by customary market practice to accept a Banker’s Acceptance (a "Non BA Lender") shall, in lieu of accepting its pro rata amount of such Banker’s Acceptances, make available to the Borrower on the Borrowing Date a non‑interest bearing loan (a "BA Equivalent Loan") in Canadian Dollars in an amount equal to the BA Discount Proceeds of its pro rata amount of the Banker’s Acceptances, based on the BA Discount Rate applicable to such Lender. Each Non BA Lender shall also be entitled to deduct from the BA Equivalent Loan an amount equal to the Banker’s Acceptance Fee that would have been applicable had it been able to accept Banker’s Acceptances. The BA Equivalent Loan shall have a term equal to the term of the Banker’s Acceptances that the Non BA Lender would otherwise have accepted and the Borrower shall, at the end of that term, be obligated to pay the Non BA Lender an amount equal to the aggregate Face Amount of the Banker’s Acceptances that it would otherwise have accepted. All provisions of this Agreement applicable to Banker’s Acceptances and Lenders that accept Banker’s Acceptances shall apply mutatis mutandis to BA Equivalent Loans and Non BA Lenders and, without limiting the foregoing, Accommodations shall include BA Equivalent Loans.
2.9
LIBOR Loans.
(a)
If the Agent determines in (which determination shall be made in good faith and shall be conclusive and binding) in connection with any request for a LIBOR Loan or a conversion or continuation thereof that (a) U.S. Dollar deposits are not being offered to banks in the applicable offshore U.S. Dollar market for the applicable amount and LIBOR Interest Period of such LIBOR Loan, or adequate and reasonable means do not exist for determining the LIBOR Rate for such LIBOR Loan, or (b) if the Majority Lenders determine and notify the Agent that the LIBOR Rate for such LIBOR Loan does not adequately and fairly reflect the cost to such Lenders of funding such LIBOR Loan, then the Agent shall promptly notify the Borrower and all Lenders. Thereafter, the obligation of the Lenders to make or maintain LIBOR Loans shall be suspended until the Agent revokes such notice. Upon receipt of such notice of suspension, the Borrower may revoke any pending request for a LIBOR Loan, or conversion or continuation of a LIBOR Loan, or, failing that, will be deemed to have converted such request into a request for a U.S. Base Rate Loan in the amount specified therein.
(b)
The Borrower shall give the Agent notice in writing not later than 10:00 a.m. on the third Business Day prior to the expiry of the LIBOR Interest Period in respect of a

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LIBOR Loan specifying the new LIBOR Interest Period (if the LIBOR Loan is to be renewed) or the Accommodation into which the LIBOR Loan will be converted on such expiry.
(c)
If no notice is given by the Borrower as provided in clause (a) or (b) above, the LIBOR Loan will be automatically converted on the expiration of the then applicable LIBOR Interest Period to a U.S. Base Rate Loan, without prejudice to the Lenders’ rights in respect of the failure to give the notice and whether or not a Default or Event of Default has occurred, in the principal amount of the funds required to be provided to the Agent for the account of the Lenders pursuant to this Section.
(d)
If any LIBOR Loan is outstanding on the Demand Date or the Maturity Date, the Borrower shall on such date pay to the Agent for the account of the Lenders at the Branch in U.S. Dollars an amount equal to the principal amount of such LIBOR Loan.
(e)
All funds received by the Agent pursuant to clause (d) shall be held by the Agent for set-off on the maturity date of the LIBOR Loan against the liability of the Borrower to the Lenders in respect of such LIBOR Loan and, until then, shall be invested from time to time in such form of investment at the Branch designated by the Borrower and approved by the Agent, for a term corresponding to the maturity date of the applicable LIBOR Loan and shall bear interest at the rate payable by the Agent on deposits of similar currency, amount and maturity. The balance of all such funds (together with interest thereon) held by the Agent will be applied to repayment of all debts and liabilities of the Borrower to the Lenders under this Agreement and the Loan Documents and following repayment of all such debts and liabilities any amount remaining shall be paid to the Borrower or as otherwise required by law.
(f)
Each Lender shall advance its Applicable Percentage of each LIBOR Loan in accordance with the following provisions:
(i)
the Agent shall advise each Lender of its receipt of a notice from a Borrower pursuant to Section 2.5 on the day such notice is received and shall, as soon as possible, advise each Lender of the amount of its Applicable Percentage of any Borrowing by way of LIBOR Loan requested by the notice;
(ii)
each Lender shall deliver its share of the Borrowing to the Agent’s Account at the Branch not later than 11:00 a.m. on the Borrowing Date; and
(iii)
when the Agent determines that all the conditions precedent to a Borrowing specified in this Agreement have been met, it shall advance to the Borrower the amount delivered by each Lender by wiring such amount to the account of the Borrower, but if the conditions precedent to the Borrowing are not met by 2:30 p.m. on the Borrowing Date, the Agent shall return the funds to the Lenders or invest them in an overnight investment as orally instructed by each Lender until such time as the LIBOR Loan is advanced.

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2.10
Safekeeping of Drafts.
The responsibility of the Agent and the Lenders in respect of the safekeeping of Drafts, Bankers’ Acceptances and other bills of exchange which are delivered to any of them hereunder shall be limited to the exercise of the same degree of care which such party gives to its own property, provided that such party shall not be deemed to be an insurer thereof.
2.11
Certification to Third Parties.
The Agent will promptly provide to the Borrower and third parties at the request of the Borrower a certificate as to the Canadian Dollar Amount of Accommodations outstanding from time to time under this Agreement, and giving such other particulars in respect of the Indebtedness as the Borrower may reasonably request.
2.12
Successor LIBOR and CDOR Rate.
(a)
Notwithstanding anything to the contrary in this Agreement, if the Agent determines (which determination shall be final, conclusive and binding upon the Borrower absent manifest error), or the Borrower or the Majority Lenders notify the Agent (with, in the case of the Majority Lenders, a copy to Borrower) that the Borrower or the Majority Lenders (as applicable) have determined, that:
(i)
adequate and reasonable means do not exist for ascertaining LIBOR or the CDOR Rate for any requested Contract Period, including because the Reuters Screen LIBOR01 Page or the “CDOR Page” (or any display substitutes therefor) of Reuters (or any successor thereof or Affiliate thereof) (collectively, the “Screen Rate”) is not available or published on a current basis and such circumstances are unlikely to be temporary; or
(ii)
the administrator of the applicable Screen Rate or a Governmental Authority having jurisdiction over the Agent has made a public statement identifying a specific date after which the applicable Screen Rate shall no longer be made available, or used for determining the interest rate of loans (such specific date, the “Scheduled Unavailability Date”); or
(iii)
syndicated loans currently being executed, or that include language similar to that contained in this Section 2.12, are being executed or amended (as applicable) to incorporate or adopt a new benchmark interest rate to replace (x) LIBOR or the Reuters Screen LIBOR01 Page or (y) the CDOR Rate or the “CDOR Page” (or any display substitutes therefor) of Reuters (or any successor thereof or Affiliate thereof), as applicable,
then, reasonably promptly after such determination by the Agent or receipt by the Agent of such notice, as applicable, the Agent and the Borrower may amend this Agreement to replace LIBOR or the CDOR Rate, as applicable, with an alternate benchmark rate selected by the Agent and the Borrower (including any mathematical or other adjustments to the benchmark (if any) incorporated therein), giving due consideration to any evolving or then existing convention for similar multi-

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currency syndicated credit facilities for such alternative benchmarks (any such proposed rate, a “Successor Rate”), together with any proposed Successor Rate Conforming Changes, and any such amendment shall become effective at 5:00 p.m., Toronto time, on the fifth Business Day after the Agent shall have posted such proposed amendment to all Lenders and the Borrower unless, prior to such time, the Lenders comprising the Majority Lenders have delivered to the Agent written notice that the Majority Lenders do not accept such amendment.
(b)
If no Successor Rate has been determined and the circumstances under Section 2.12(a) exist or the Scheduled Unavailability Date has occurred (as applicable), the Agent will promptly so notify the Borrower and each Lender. Thereafter, the Lenders shall not be required to honour any Advance or Borrowing Notice, as applicable, requesting a Borrowing by way of a LIBOR Loan or BA Instrument, as applicable, under this Agreement. Upon receipt of such notice, (A) the Borrower may revoke any pending request for a conversion to or rollover of such LIBOR Loan or BA Instrument, as applicable (to the extent of the affected LIBOR Loan, BA Instrument or Contract Period, as applicable) or, failing that, will be deemed to have converted such request into a request for conversion or rollover to a U.S. Base Rate Loan or Prime Rate Loan, as applicable, in the amount specified therein, and (B) the Borrower hereby instructs the Agent to repay each affected (x) LIBOR Loan with the proceeds of a U.S. Base Rate Loan in the amount of such affected LIBOR Loan, and (y) BA Instrument with the proceeds of a Prime Rate Loan, as applicable, in each case to be drawn down on the last day of the then current Contract Period.
(c)
Notwithstanding anything else herein, any definition of “Successor Rate” shall provide that in no event shall such Successor Rate be less than zero for purposes of this Agreement.
(d)
For purposes of this Section 2.12, “Successor Rate Conforming Changes” means, with respect to any proposed Successor Rate, any conforming changes to the definitions of U.S. Base Rate, Federal Funds Rate, Prime Rate, LIBOR Interest Period, Contract Period, timing and frequency of determining rates and making payments of interest and other administrative matters as may be appropriate, in the discretion of the Agent, to reflect the adoption of such Successor Rate and to permit the administration thereof by the Agent in a manner substantially consistent with market practice (or, if the Agent determines that adoption of any portion of such market practice is not administratively feasible or that no market practice for the administration of such Successor Rate exists, in such other manner of administration as the Agent determines in consultation with the Borrower).
ARTICLE 3    
DOCUMENTARY CREDITS
3.1
Documentary Credits.
The Documentary Credit Lender agrees, on the terms and conditions of this Agreement, to issue Documentary Credits under the Credit Facility only for the account of the Borrower from time to time on any Business Day prior to the Maturity Date in respect of the Documentary Credit Lender.

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3.2
Procedure for Issue.
(a)
Each Issue shall be made on notice substantially in the form of Schedule 4 (an “Issue Notice”) given by the Borrower to the Agent not later than 1:00 p.m. (Toronto time) on three (3) Business Day’s notice. The Issue Notice shall be in substantially the form of Schedule 4 shall be irrevocable and binding on the Borrower and shall specify (i) the requested date of Issue (the “Issue Date”), (ii) the Type of Documentary Credit, (iii) the Face Amount of the Documentary Credit, (iv) the expiration date, and (v) the name and address of the Beneficiary. The Agent shall, upon receipt of an Issue Notice, provide a copy of the Issue Notice to the Documentary Credit Lender and to each other Lender.
(b)
Not later than 1:00 p.m. (Toronto time) on the Issue Date, the Documentary Credit Lender shall issue a Documentary Credit completed in accordance with the Issue Notice in the appropriate form. Upon receipt of the Documentary Credits and upon fulfilment of the conditions set forth in ARTICLE 11, the Agent shall deliver the Documentary Credits to or to the order of the Borrower.
(c)
No Documentary Credit shall require that payment against a conforming draft be made on the same Business Day upon which the draft was presented, unless such presentation is made before 1:00 p.m. (Toronto time) on such Business Day.
(d)
Prior to the Issue Date, the Borrower shall provide a precise description of the documents and the verbatim text of any certificates to be presented by the Beneficiary which, if presented by the Beneficiary, would require the Documentary Credit Lender, to make payment under the Documentary Credit. The Documentary Credit Lender may require reasonable changes in any such document or certificate.
3.3
Form of Documentary Credits.
Each Documentary Credit (i) shall be in Canadian Dollars or United States Dollars, (ii) shall be dated the Issue Date (iii) shall have an expiration date on a Business Day which occurs no more than 364 days after the Issue Date (provided, however, no expiration date shall be a date after the Maturity Date), and (iv) shall comply with the definition of Documentary Credit. Without limiting Section 2.1(a), the aggregate of the Canadian Dollar Amount of the Face Amounts of all issued Documentary Credits shall not exceed $10,000,000 at any time.
3.4
Reimbursements of Amounts Drawn.
(a)
At or before 11:00 a.m. (Toronto time) on the date specified by a Beneficiary as a drawing date under a Documentary Credit, the Borrower shall pay to the Documentary Credit Lender an amount in same day funds equal to the amount to be drawn by the Beneficiary under the Documentary Credit.
(b)
If the Borrower fails to pay to the Documentary Credit Lender the amount drawn under any Documentary Credit, the unpaid amount due and payable shall be converted automatically as of such date, and without the necessity for the Borrower

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to give any Borrowing Notice pursuant to Section 2.5, to a Prime Rate Loan, where the Documentary Credit is denominated in Canadian Dollars and a U.S. Base Rate Loan is denominated in U.S. Dollars, made by the Lenders rateably under the Credit Facility.
3.5
Documentary Credit Participation.
(a)
Each Lender shall acquire from the Documentary Credit Lender for the Lender’s own account and risk, an undivided interest equal to the Lender’s pro rata share of the Documentary Credit Lender’s obligations and rights under each Documentary Credit together with any amount paid by the Documentary Credit Lender under a Documentary Credit. If an amount is drawn under any Documentary Credit and the Documentary Credit Lender is not reimbursed in full by the Borrower in accordance with the terms of this Agreement or if the amount is converted to an Advance pursuant to Section 3.4(b), each of the Lenders shall pay to the Documentary Credit Lender, upon demand, an amount equal to such Lender’s pro rata share of the amount which is not so reimbursed or shall acquire its pro rata share of the Advance into which the amount is converted, as the case may be.
(b)
If any amount required to be paid by a Lender to the Documentary Credit Lender pursuant to Section (a) is not paid to the Documentary Credit Lender within two Business Days after the date the payment is due, the Lender shall pay to the Documentary Credit Lender, on demand, such amount together with interest, from the date the payment was to be made until the date it is actually made, at the prevailing interbank rate. A certificate of the Documentary Credit Lender, submitted to the relevant Lender with respect to any amounts owing under this Section shall be conclusive, absent manifest error.
(c)
If, at any time after the Documentary Credit Lender has made a payment under any Documentary Credit and has received from the Lenders their pro rata share of such payment, the Documentary Credit Lender receives a payment in respect of the Documentary Credit (whether directly from the Borrower or otherwise), the Documentary Credit Lender will distribute to the Lenders their pro rata share of such payment; provided, however, if any payment so received by the Documentary Credit Lender shall be required to be returned by the Documentary Credit Lender, each Lender shall return to the Documentary Credit Lender the portion thereof previously distributed to it.
3.6
Risk of Documentary Credits.
(a)
In determining whether to pay under a Documentary Credit, the Documentary Credit Lender shall be responsible only to determine that the documents and certificates required to be delivered under the Documentary Credit have been delivered and that they comply on their face with the requirements of the Documentary Credit.
(b)
The reimbursement obligation of the Borrower under any Documentary Credit shall be unconditional and irrevocable and shall be paid strictly in accordance with the

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terms of this Agreement under all circumstances, including (i) any lack of validity or enforceability of a Documentary Credit, (ii) the existence of any claim, set-off, defence or other right which the Borrower may have at any time against a Beneficiary, the Documentary Credit Lender or any other Person, whether in connection with the Loan Documents and the transactions contemplated therein or any other transaction (including any underlying transaction between the Borrower and the Beneficiary), (iii) any certificate or other document presented with a Documentary Credit proving to be forged, fraudulent or invalid or any statement in it being untrue or inaccurate, (iv) the existence of any act or omission or any misuse of, a Documentary Credit or misapplication of proceeds by the Beneficiary, including any fraud in any certificate or other document presented with a Documentary Credit in each case unless, before payment of a Documentary Credit, (x) the Borrower has delivered to the Documentary Credit Lender a written notice of the fraud together with a written request that it refuse to honour such drawing, (y) the fraud by the Beneficiary has been established to the knowledge of the Documentary Credit Lender so as to make the fraud clear or obvious to the Documentary Credit Lender, and (z) in the case of fraud in the underlying transaction between the Borrower and the Beneficiary, the fraud is of such character as to make the demand for payment by the Beneficiary under the Documentary Credit a fraudulent one, (v) payment by the Documentary Credit Lender under the Documentary Credit against presentation of a certificate or other document which does not comply with the terms of the Documentary Credit, unless such payment is inconsistent with the standards of reasonable care specified in the Uniform Customs and Practice for Documentary Credits (1993 Revision), ICC Publication 500 (or any replacement publication), or (vi) the existence of a Default or Event of Default.
(c)
The Documentary Credit Lender shall not be responsible for (i) the validity or sufficiency of any instrument transferring or assigning or purporting to transfer or assign a Documentary Credit or the rights or benefits under it or proceeds of it, in whole or in part, which may prove to be invalid or ineffective for any reason, (ii) errors, omissions, interruptions or delays in transmission or delivery of any messages by mail, facsimile or otherwise, (iii) errors in interpretation of technical terms, (iv) any loss or delay in the transmission of any document required in order to make a drawing, and (v) any consequences arising from causes beyond the control of the Documentary Credit Lender, including the acts or omissions, whether rightful or wrongful, of any Governmental Authority. None of the above shall affect, impair, or prevent the vesting of any of the Documentary Credit Lender’s rights or powers under this Agreement. Any action taken or omitted by the Documentary Credit Lender under or in connection with any Documentary Credit or the related certificates, if taken or omitted in good faith, shall not put the Documentary Credit Lender under any resulting liability to the Borrower provided that the Documentary Credit Lender acts in accordance with the standards of reasonable care specified in the Uniform Customs and Practice for Documentary Credits (1993 Revision), ICC Publication 500 (or any replacement publication).
3.7
Fees.

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(a)
The Borrower shall pay to the Agent, (i) on behalf of the Documentary Credit Lender, a non-refundable fronting fee in respect of each Documentary Credit equal to 0.25% of its Face Amount (the “L/C Fronting Fee”), and (ii) on behalf of each Lender, a fee equal to the Applicable Margin for Documentary Credits of the Face Amount of each Documentary Credit for the period during which the Documentary Credit is outstanding (the “L/C Maintenance Fee”). The L/C Fronting Fee and the L/C Maintenance Fee shall be calculated and payable quarterly in arrears on the first Business Day following the end of each Fiscal Quarter.
(b)
The Borrower shall pay to the Documentary Credit Lender, upon the issuance, amendment or transfer of each Documentary Credit issued by the Documentary Credit Lender and each drawing made under it, the Documentary Credit Lender’s standard and prevailing documentary and administrative charges for issuing, amending, transferring or drawing under, as the case may be, Documentary Credits of similar amount, term and risk.
3.8
Repayments.
(a)
If the Borrower is required to repay the Loans pursuant to ARTICLE 2 or ARTICLE 12, then the Borrower shall pay to the Agent an amount equal to each Lender’s contingent liability in respect of (i) any outstanding Documentary Credit, and (ii) any Documentary Credit which is the subject matter of any order, judgment, injunction or other such determination (a “Judicial Order”) restricting payment under and in accordance with such Documentary Credit or extending the Lender’s liability under such Documentary Credit beyond its stated expiration date. Payment in respect of each Documentary Credit shall be due in the currency in which the Documentary Credit is denominated.
(b)
The Documentary Credit Lender shall, with respect to any Documentary Credit, upon the later of:
(i)
the date on which any final and non-appealable order, judgment or other such determination has been rendered or issued either terminating the applicable Judicial Order or permanently enjoining the Lender from paying under such Documentary Credit; and
(ii)
the earlier of (i) the date on which either (x) the original counterpart of the Documentary Credit is returned to the Documentary Credit Lender for cancellation, or (y) the Documentary Credit Lender is released by the Beneficiary from any further obligations, and (ii) the expiry (to the extent permitted by any applicable law) of the Documentary Credit,
pay to the Borrower an amount equal to the difference between the amount paid to the Documentary Credit Lender pursuant to Section 3.8(a) and the amounts paid by the Documentary Credit Lender under the Documentary Credit.
3.9
Documentary Credits Outstanding Upon Default.

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If any Documentary Credits are outstanding upon the occurrence of an Event of Default, the Borrower shall immediately pay to the Agent for the account of the Documentary Credit Lender an amount (the “Documentary Credit Deposit Amount”) equal to the undrawn principal amount of the Documentary Credits. The Documentary Credit Deposit Amount shall be held by the Agent in an interest bearing account to be applied on any drawing by a Beneficiary and shall constitute “Obligations” under the Third Supplemental Indenture. If no drawing is made in respect of a Documentary Credit prior to its expiry date, the Documentary Credit Deposit Amount applicable thereto and any accrued interest thereon, or such part thereof as has not been paid out, shall be returned to the Borrower promptly following the expiry or cancellation of the Documentary Credit.
ARTICLE 4    
INTEREST
4.1
Interest on Loans.
(a)
Prime Rate Loan. Each Prime Rate Loan shall bear interest (both before and after demand, maturity, default and, to the extent permitted by law, judgment, with interest on overdue interest at the same rate) from and including the Borrowing Date for such Loan to, but not including, the date of repayment of such Loan on the unpaid principal amount of such Loan at a nominal rate per annum equal to the Prime Rate, plus the Applicable Margin then in effect, which shall, in each case, change automatically without notice to the Borrower as and when the Prime Rate shall change so that at all times the rates set forth above shall be the Prime Rate then in effect. Interest on each Prime Rate Loan shall be computed on the basis of the actual number of days elapsed divided by 365 or 366, as applicable. Interest in respect of outstanding Prime Rate Loans shall be payable monthly in arrears on the first Business Day of each month; provided, however, that interest on overdue interest shall be payable on demand.
(b)
U.S. Base Rate Loan. Each U.S. Base Rate Loan shall bear interest (both before and after demand, maturity, default and, to the extent permitted by law, judgment, with interest on overdue interest at the same rate) from and including the Borrowing Date for such Loan to, but not including, the date of repayment of such Loan on the unpaid principal amount of such Loan at a nominal rate per annum equal to the U.S. Base Rate, plus the Applicable Margin then in effect, which shall, in each case, change automatically without notice to the Borrower as and when the U.S. Base Rate shall change so that at all times the rates set forth above shall be the U.S. Base Rate then in effect. Interest on each U.S. Base Rate Loan shall be computed on the basis of the actual number of days elapsed divided by 365 or 366, as applicable. Interest in respect of outstanding U.S. Base Rate Loans shall be payable monthly in arrears on the first Business Day of each month; provided, however, that interest on overdue interest shall be payable on demand.
(c)
LIBOR Loans. Each LIBOR Loan shall bear interest (both before and after demand, maturity, default and, to the extent permitted by law, judgment, with interest on overdue interest at the same rate) from and including the Borrowing Date for such LIBOR Loan to, but not including, the date of repayment thereof on the unpaid

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principal amount thereof at a nominal rate per annum equal to the LIBOR Rate determined by the Agent for each LIBOR Interest Period applicable to such LIBOR Loan plus the Applicable Margin in effect on the first day of such LIBOR Interest Period. Interest on each LIBOR Loan shall be computed on the basis of the actual number of days elapsed divided by three hundred and sixty (360). Interest in respect of each LIBOR Loan shall be payable on the last day of each LIBOR Interest Period applicable thereto and also, with respect to each LIBOR Interest Period which is longer than ninety (90) days, the last day of such LIBOR Interest Period and each date within such LIBOR Interest Period which is the first Business Day following the expiration of each ninety (90) day interval after the first day of such LIBOR Interest Period; provided, however, that interest on overdue interest shall be payable on demand.
4.2
LIBOR Interest Period Determination.
The Borrower shall select the duration of each LIBOR Interest Period by facsimile or telephone notice (to be confirmed the same day in writing) received by the Agent not later than 10:00 a.m. on the third Business Day preceding the applicable Borrowing Date. The first LIBOR Interest Period for any LIBOR Loan shall commence on (and include) the Borrowing Date for such LIBOR Loan, and each LIBOR Interest Period occurring thereafter for such LIBOR Loan shall commence on (and include) the day following the expiration of the next preceding LIBOR Interest Period. Notwithstanding the foregoing, if any LIBOR Interest Period would otherwise expire on a day which is not a Business Day, such LIBOR Interest Period shall expire on the next succeeding Business Day provided it is in the same calendar month, and otherwise shall expire on the preceding Business Day.
4.3
Interest on Overdue Amounts.
The Borrower will on demand pay interest to the Agent on all amounts (other than as provided in Section 4.1) payable by the Borrower pursuant to this Agreement that are not paid when due at the Prime Rate plus 2% per annum, in the case of amounts payable in Canadian Dollars, or the U.S. Base Rate plus 2% per annum, in the case of amounts payable in U.S. Dollars, in each case calculated daily and compounded monthly from the date of payment until paid in full (both before and after demand, maturity, default and, to the extent permitted by law, judgment), with interest on overdue interest at the same rate.
4.4
Other Interest.
The Borrower shall pay interest on all amounts payable hereunder at the rate specified herein or, if no rate is specified, at the U.S. Base Rate if the amount payable is in U.S. Dollars and otherwise at the Prime Rate calculated daily and compounded monthly, from the date due until paid in full (both before and after demand, maturity, default and, to the extent permitted by law, judgment).
4.5
Interest Act (Canada).

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For the purpose of the Interest Act (Canada), the yearly rate of interest to which interest calculated on the basis of a year of 360 or 365 days is equivalent is the rate of interest as so determined multiplied by the actual number of days in such year divided by 360 or 365, respectively.
The Borrower and the General Partner acknowledge and confirm that this Section 4.5 satisfies the requirements of Section 4 of the Interest Act (Canada) to the extent it applies to the expression or statement of any interest payable under this Agreement and that each of the Borrower and the General Partner is able to calculate the yearly rate or percentage of interest payable under this Agreement based upon the methodology set out in this Section 4.5. The Borrower and the General Partner each agree not to plead or assert, whether by way of defence or otherwise, in any proceeding relating to this Agreement, that the interest payable hereunder and the calculation of interest herein have not been adequately disclosed to them, whether pursuant to Section 4 of the Interest Act (Canada) or any other Applicable Law or legal principle.
4.6
Deemed Reinvestment Principle.
For the purpose of the Interest Act (Canada), the principle of deemed reinvestment of interest shall not apply to any interest calculation under this Agreement and the rates of interest stipulated in this Agreement are intended to be nominal rates and not effective rates or yields.
4.7
Maximum Return.
It is the intent of the parties hereto that the return to the Lenders pursuant to this Agreement shall not exceed the maximum return permitted under the laws of Canada and if the return to the Lenders would, but for this provision, exceed the maximum return permitted under the laws of Canada, the return to the Lenders shall be limited to the maximum return permitted under the laws of Canada and this Agreement shall automatically be modified without the necessity of any further act or deed to give effect to the restriction on return set forth above.
ARTICLE 5    
FEES
5.1
Acceptance Fees.
Upon the acceptance of any Draft pursuant to this Agreement, the Borrower will pay to the Agent for the account of the relevant Lenders an acceptance fee in Canadian Dollars calculated on the Face Amount and the term of such Draft, in accordance with the Applicable Margin in effect on the date of acceptance. The acceptance fees payable by the Borrower shall be calculated on the Face Amount of the Bankers’ Acceptance and shall be calculated on the basis of the number of days in the term of such Bankers’ Acceptance.
5.2
Commitment Fee.
The Borrower shall pay to the Agent a commitment fee in Canadian Dollars so long as the Agent has not demanded or the Lenders have not ceased to make advances under Section 12.2, calculated in accordance with the Applicable Margin on the amount of the Undisbursed Credit in existence during the period of calculation and as adjusted automatically upon any change thereof. Accrued

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commitment fees shall be calculated quarterly and be due and payable quarterly in arrears on the first Business Day after the end of each quarter of each Fiscal Year of the Borrower.
5.3
Basis of Calculation of Fees.
The fees payable under Sections 3.7, 5.1 and 5.2 with respect to any period shall be calculated on the basis of the actual number of days in such period divided by 365 or 366 days, as the case may be.
ARTICLE 6    
PAYMENT
6.1
Voluntary Repayment of Outstanding Accommodation.
(a)
Repayments. The Borrower shall have the right to voluntarily repay outstanding Accommodations from time to time on any Business Day without premium on the terms and conditions set forth in this Section:
(i)
With respect to any voluntary repayment of an Accommodation, unless the Agent with the consent of the Lenders otherwise approves, the Canadian Dollar Amount of Accommodation included in such repayment shall be Two Million Five Hundred Thousand Canadian Dollars (Cdn.$2,500,000) or whole multiples of One Hundred Thousand Canadian Dollars (Cdn.$100,000) or the entire amount of that type of Accommodation outstanding, the U.S. Dollar amount of Accommodation included in such repayment shall be Two Million Five Hundred Thousand U.S. Dollars (U.S.$2,500,000) or whole multiples of One Hundred Thousand U.S. Dollars (U.S.$100,000) or the entire amount of that type of Accommodation outstanding, and the Borrower shall give the Agent a written notice of repayment substantially in the form of Schedule 6.1(a) (a “Notice of Repayment”), specifying the amount, the type or types of Accommodation to be included in the repayment (and where such Accommodation includes any Loan, the currency thereof and the interest rate applicable thereto) and the applicable voluntary repayment date, which notice shall be irrevocable by the Borrower. The Notice of Repayment shall be given to the Agent not later than 10:00 a.m.:
(A)
on the second Business Day preceding the applicable repayment date in the case of Loans with a Canadian Dollar Amount in the aggregate equal to or greater than Two Million Five Hundred Thousand Canadian Dollars (Cdn.$2,500,000);
(B)
on the second Business Day preceding the applicable repayment date in the case of Bankers’ Acceptances in an aggregate Face Amount equal to or greater than Two Million Five Hundred Thousand Canadian Dollars (Cdn.$2,500,000); and

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(C)
on the third Business Day preceding the applicable repayment date in the case of LIBOR Loans.
(ii)
In all other cases, Notice of Repayment shall be given on the applicable repayment date.
(iii)
Any Notice of Repayment received by the Agent on any Business Day after 11:00 a.m. shall be deemed to have been given to the Agent on the next succeeding Business Day.
(iv)
On the applicable voluntary repayment date, the Borrower shall pay to the Agent for the account of the Lenders, the amount of any Accommodation that is subject to the repayment, together with all interest and other fees and amounts accrued, unpaid and due in respect of such repayment; provided, however, that accrued interest will not be repayable prior to the applicable interest payment date in Section 4.1 in respect of Prime Rate Loans or U.S. Base Rate Loans unless the full balance outstanding thereunder is voluntarily repaid.
(b)
Repayment of Certain Types of Accommodation. The following provisions shall also apply to the voluntary repayment by the Borrower of the following types of Accommodation:
(i)
Subject to Section 6.1(c), no repayment of any LIBOR Loan shall be made otherwise than upon the expiration of any applicable LIBOR Interest Period; and
(ii)
No repayment of outstanding Accommodation in the form of Bankers’ Acceptance shall be made otherwise than upon the expiration or maturity date or, in the case of a Documentary Credit, on the date of surrender thereof to the Documentary Credit Lender.
(c)
Repayment of LIBOR Loans. Notwithstanding Sections 6.1(a) and 6.1(b), a LIBOR Loan may be repaid at any time within the thirty (30) day period after the Borrower receives notice that it is required to pay any amount under Section 7.6 in respect of such Accommodation, provided that in addition to the other amounts required to be paid pursuant to this Section at the time of such repayment, the Borrower pays to the Agent for the account of the Lenders at such time all reasonable breakage costs incurred by the Lenders with respect to, and all other amounts payable by the Borrower under Sections 7.6 and 7.7 in connection with, such repayment. A certificate of a Lender or Lenders as to such costs, providing details of the calculation of such costs, shall be prima facia evidence.
6.2
Repayment on Maturity Date and Extension.
(a)
Subject to the provisions of this Agreement and to this Section, the Borrower shall repay in full all outstanding Accommodations to each Lender on the Maturity Date

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of such Lender, together with all interest, fees and other amounts payable hereunder on the Maturity Date of such Lender, in each case, to the Agent for the account of the applicable Lender(s), and the Commitment of such Lender shall be permanently cancelled and the aggregate Committed Amount shall be permanently cancelled by a corresponding amount.
(b)
By notice in writing to the Agent in the form of Schedule 3 (a “Notice of Extension”) given not more than 90 and not less than 45 days prior to each anniversary date of the date of this Agreement, the Borrower may request each Lender to extend the Maturity Date of such Lender for an additional period of 365 days. The Lenders agree that they shall give or withhold their consent in a timely manner so that the Agent may provide a response to the Borrower to the Notice of Extension within thirty (30) days from the date of such receipt, provided that the decision of any Lender to extend the Maturity Date in respect of such Lender shall be at the sole discretion of such Lender. The Borrower shall be entitled to replace any Lender which dissents in response to the Notice of Extension (a “Dissenting Lender”) with another existing Lender or Lenders without the consent of any of the remaining Lenders; or to replace a Dissenting Lender with any financial institution which is not an existing Lender with the consent of the Agent and the Documentary Credit Lender, such consent not to be unreasonably withheld. The Borrower shall be entitled, with the unanimous consent of the Lenders who have agreed to extend, to permanently cancel the Commitment of any Dissenting Lender and repay such Dissenting Lender, at which time the Committed Amount shall be permanently reduced by the amount of such Commitment.
6.3
Excess Accommodation.
In addition to the other repayment rights, obligations or options set forth in this Article, if the aggregate Canadian Dollar Amount of all Accommodations outstanding under the Credit Facility at any time exceeds the Committed Amount, the Borrower shall immediately upon request of the Agent:
(a)
to the extent any of the Accommodations are Prime Rate Loans, U.S. Base Rate Loans, repay such excess; and
(b)
in the case of Banker’s Acceptances or LIBOR Loans, pay to the Agent for the account of the Lenders an amount in Canadian Dollars or U.S. Dollars, as applicable, equivalent to the amount by which the Committed Amount is exceeded.
Funds paid under clause (b) shall be invested from time to time in such form of investment at the Branch designated by the Borrower and approved by the Agent, for terms corresponding to the applicable term of the Banker’s Acceptance or the LIBOR Interest Period, as the case may be, and shall bear interest at the rate payable by the Agent on deposits of similar currency, amount and maturity.
6.4
Illegality.

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Notwithstanding any other provision of this Agreement, if the making or continuation of any Accommodation shall have been made unlawful or prohibited due to compliance by any of the Agent and the Lenders in good faith with any change made after the date hereof in any law or governmental rule, regulation, guideline or order, or in any interpretation or application of any law or governmental rule, regulation, guideline or order by any competent authority, or with any request or directive (whether or not having the force of law) by any central bank, reserve board, superintendent of financial institutions or other comparable authority made after the date hereof, then the Agent will give notice thereof to the Borrower which shall repay such Accommodation within a reasonable period or such shorter period as may be required by law. During the continuation of any such event the Lenders will have no obligation under this Agreement to make or continue any Accommodation affected thereby.
ARTICLE 7    
PAYMENTS AND INDEMNITIES
7.1
Payments on Non-Business Days.
Unless otherwise provided herein, whenever any payment to be made under this Agreement shall be stated to be due on a day which is not a Business Day, the due date thereof shall be extended to the next succeeding Business Day, and interest or fees shall be payable at the appropriate rate during such extension.
7.2
Method and Place of Payment.
Unless otherwise provided herein, all payments made by the Borrower to the Agent under this Agreement will be made not later than 2:00 p.m. on the date when due, and all such payments will be made in immediately available funds. Any amounts received after that time shall be deemed to have been received by the Agent on the next Business Day.
7.3
Net Payments.
All payments by the Borrower under this Agreement shall be made without set-off or counterclaim or other deduction and without regard to any equities between the Borrower and the Agent or any of the Lenders or any other Person and free and clear of, and without reduction for or on account of, any present or future levies, imposts, duties, charges, fees, deductions or other withholdings, and if the Borrower is required by law to withhold any amount, then the Borrower will increase the amount of such payment to an amount which will ensure that the Agent receives the full amount of the original payment.
7.4
Agent May Debit Account.
The Agent may debit accounts of the Borrower with the Agent (if any) for any payment or amount due and payable by the Borrower pursuant to this Agreement without further direction from the Borrower to the Agent.
7.5
Currency of Payment.

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Accommodation shall be repaid by the Borrower to the Agent or a Lender as required under this Agreement in the currency in which such Accommodation was obtained. Any payment on account of an amount payable under this Agreement in a particular currency (the “Proper Currency”) required by any authority having jurisdiction to be made (or which a Lender elects to accept) in a currency (the “Other Currency”) other than the Proper Currency, whether pursuant to a judgment or order of any court or tribunal or otherwise, shall constitute a discharge of the Borrower’s obligations under this Agreement only to the extent of the amount of the Proper Currency which each applicable Lender is able, as soon as practicable after receipt by it of such payment, to purchase with the amount of the Other Currency so received. If the amount of the Proper Currency which a Lender is so able to purchase is less than the amount of the Proper Currency originally due to it, the Borrower shall indemnify and hold such Lender harmless from and against all losses, costs, damages or expenses which such Lender may sustain, pay or incur as a result of such deficiency. This indemnity shall constitute an obligation separate and independent from any other obligation contained in this Agreement, shall give rise to a separate and independent cause of action, shall apply irrespective of any indulgence granted by the Lenders from time to time, shall continue in full force and effect notwithstanding any judgment or order for a liquidated sum in respect of an amount due under this Agreement or under any judgment or order and shall not merge in any order of foreclosure made in respect of any of the security given by the Borrower to or for the benefit of any Lender.
7.6
General Indemnity.
The Borrower shall indemnify the Agent and the Lenders and their directors, officers, employees, attorneys and agents against and hold each of them harmless from any loss, liabilities, damages, claims, costs and expenses (including fees and expenses of counsel to the Agent and the Lenders on a solicitor and his own client basis and reasonable fees and expenses of all independent consultants) (each a “Claim”) suffered or incurred by any of them arising out of, resulting from or in any manner connected with or related to:
(a)
any Environmental Matter, Environmental Liability or Environmental Proceeding; and
(b)
any loss or expense incurred in liquidating or re-employing deposits from which such funds were obtained, which the Agent or Lender may sustain or incur as a consequence of:
(i)
failure by the Borrower to make payment when due of the principal amount of or interest on any LIBOR Loan;
(ii)
failure by the Borrower in proceeding with a Borrowing after the Borrower has given a Borrowing Notice;
(iii)
failure by the Borrower in repaying a Borrowing after the Borrower has given a Notice of Repayment;

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(iv)
any breach, non-observance or non-performance by the Borrower of any of its obligations, covenants, agreements, representations or warranties contained in this Agreement; and
(v)
except as otherwise provided in Section 6.1(c)the repayment of any LIBOR Loan otherwise than on the expiration of any applicable LIBOR Interest Period or the repayment of any Bankers’ Acceptance otherwise than on the maturity date thereof.
The indemnity set forth herein shall be in addition to any other obligations or liabilities of the Borrower to any of the Agent and the Lenders at common law or otherwise and this Section shall survive the repayment of the Accommodation and the termination of this Agreement. A certificate of the Lender as to any such loss or expense, providing details of the calculation of such loss or expense, shall be prima facie evidence.
7.7
Early Termination of LIBOR Interest Period.
Without limiting Section 7.6, if the Agent is required to arrange for early termination of any LIBOR Interest Period or to arrange to acquire funds for any period other than a LIBOR Interest Period to permit the Borrower to repay any LIBOR Loan, the Borrower shall reimburse the Lenders for all losses and reasonable out-of-pocket expenses incurred by them as a result of the early termination of the LIBOR Interest Period in question or as a result of entering into the new arrangement to the extent that such losses and expenses result from such payment. If any such early termination or new arrangement cannot be effected by the Agent on behalf of the Lenders, the Borrower shall continue to pay interest to the Agent in U.S. Dollars at the LIBOR Rate specified hereunder upon an amount of U.S. Dollars equal to the amount of the principal repayment for the remainder of the then current LIBOR Interest Period. The indemnity set forth herein shall be in addition to any other obligations or liabilities of the Borrower to any of the Agent and the Lenders at common law or otherwise and this Section shall survive the repayment of the Accommodation and the termination of this Agreement. A certificate of a Lender or Lenders as to any such loss or expense, providing details of the calculation of such loss or expense, shall be prima facie evidence.
7.8
Outstanding Bankers’ Acceptances.
If the Credit Facility is terminated at any time prior to the maturity date of any Bankers’ Acceptance issued hereunder, the Borrower shall pay to the Lenders, on demand, an amount with respect to each such Bankers’ Acceptance equal to the total amounts which would be required to purchase in the Canadian Dollars market, as of 10:00 a.m. on the date of payment of such demand, Government of Canada treasury bills in an aggregate amount equal to the Face Amount of such Bankers’ Acceptance having a term to maturity similar to the period from such demand to maturity of such Bankers’ Acceptance. Upon payment by the Borrower as required under this paragraph, the Borrower shall have no further liability in respect of each such Bankers’ Acceptance and the Lenders shall be entitled to all of the benefits of, and be responsible for all payments to third parties under, such Bankers’ Acceptance and the Lenders shall indemnify and hold harmless the Borrower in respect of all amounts which the Borrower may be required to pay under each such Bankers’ Acceptance to any party other than the Lenders.

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ARTICLE 8    
SECURITY
8.1
Security.
As general and continuing security for the due payment and performance of all present and future indebtedness, liabilities and obligations of the Borrower to the Agent and to the Lenders under the Existing Credit Agreement, the Borrower provided to the Agent on behalf of the Lenders a pledge of the Senior Pledged Bond, Series 2, such pledge being pursuant to the Bond Delivery Agreement. The parties hereby confirm that all present and future indebtedness, liabilities and obligations of the Borrower to the Agent and the Lenders under this Agreement shall constitute “Obligations” for the purposes of the Third Supplemental Indenture and shall be subject to the Senior Pledged Bond, Series 2.
ARTICLE 9    
REPRESENTATIONS AND WARRANTIES
9.1
Representations and Warranties.
To induce the Lenders to make Accommodations available to the Borrower, each of the Borrower and the General Partner, in its personal capacity, represents and warrants to the Agent and the Lenders that the following are true and correct in all material respects:
(a)
Existence – the Borrower and each of its Subsidiaries is a partnership, corporation or other entity, as the case may be, incorporated or organized and subsisting under the laws of its jurisdiction of incorporation or organization, specified on Schedule 9.1(a) (as such Schedule may be amended from time to time by Borrower and provided to the Lenders, provided that such amendments shall not otherwise be contrary to this Agreement) with and has all requisite partnership, corporate or other power and authority to own, hold under license or lease its property, undertaking and Assets and to carry on (i) its Business as now conducted (and as now proposed to be conducted); and (ii) the transactions contemplated by this Agreement and each other Loan Document to which it is a party. The General Partner is a corporation, duly and validly incorporated, organized and existing as a corporation under the laws of the Province of Alberta and has the legal capacity to act as the General Partner of the Borrower;
(b)
Capacity – each of the Borrower and the General Partner has the legal capacity and right to enter into the Loan Documents and do all acts and things and execute and deliver all agreements, documents and instruments as are required thereunder to be done, observed or performed by it in accordance with the terms and conditions thereof;
(c)
Authority - the execution and delivery by the Borrower and General Partner of this Agreement and each of the Loan Documents to which it is a party, and the performance by it of its obligations thereunder have been duly authorized by all necessary corporate, partnership or other action including, without limitation, the

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obtaining of all necessary shareholder, partnership or other relevant consents. No authorization, consent, approval, registration, qualification, designation, declaration or filing with any Governmental Authority or other Person, is or was necessary in connection with the execution, delivery and performance of the Borrower’s or General Partner’s obligations under this Agreement and the other Loan Documents to which it is a party, except such as are in full force and effect, unamended at the date hereof;
(d)
Execution and Delivery, Enforceability - each of the Loan Documents has been duly executed and delivered by each of the Borrower and the General Partner and constitutes a valid and legally binding obligation of the Borrower enforceable against it in accordance with its terms, subject only to bankruptcy, insolvency, reorganization, arrangement or other statutes or judicial decisions affecting the enforcement of creditors’ rights in general and to general principles of equity under which specific performance and injunctive relief may be refused by a court in its discretion;
(e)
No Litigation - there is no existing, pending or, to the knowledge of the Borrower or the General Partner, threatened litigation by or against the Borrower, its Subsidiaries or the General Partner which could reasonably be expected to be adversely determined to the rights of the Borrower, its Subsidiaries or the General Partner and which could reasonably be expected to cause a Material Adverse Effect; no event has occurred and, to the knowledge of the Borrower or the General Partner, no state or condition exists, which could give rise to any such litigation;
(f)
No Conflict - the execution and delivery by the Borrower and the General Partner and the performance by them of their obligations under, and compliance with the terms, conditions and provisions of, this Agreement and each other Loan Document will not conflict with or result in a breach of any of the terms, conditions or provisions of (i) its articles, by-laws, partnership agreement or other organizational documents, as the case may be; (ii) any Applicable Law; (iii) any Material Agreement or any material contractual restriction binding on or affecting it or its Assets; or (iv) any material judgment, injunction, determination or award which is binding on it in each such case except to the extent that such breach could not reasonably be expected to result in a Material Adverse Change;
(g)
Financial Statements - the financial statements and forecasts of the Borrower and its Subsidiaries which have been provided to the Agent are accurate and complete in all material respects, and fairly present the consolidated financial condition and business operations of the Borrower and its Subsidiaries, as at the date thereof and are prepared in a form and manner consistent with existing financial reporting practices of the Borrower in accordance with GAAP;
(h)
Books and Records - all books and records of the Borrower and its Subsidiaries have been fully and accurately kept and completed and there are no material inaccuracies or discrepancies of any kind contained or reflected therein. The Borrower’s and its Subsidiaries’ records, systems, controls, data or information are not recorded, stored, maintained, operated or otherwise wholly or partly dependent upon or held by any

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means (including any electric, mechanical or photographic process, whether computerized or not) which (including all means of access thereto and therefrom) are not under the direct control of Borrower or its Subsidiaries, as applicable;
(i)
No Material Adverse Change - there has been no Material Adverse Change since September 30, 2019;
(j)
Compliance with Laws and Agreements – the Borrower, its Subsidiaries and the General Partner are in compliance with all Applicable Laws and all agreements or contracts where any non-compliance could reasonably be expected to cause a Material Adverse Effect;
(k)
Approvals - all Governmental Approvals and other consents or authorizations necessary to permit the Borrower and its Subsidiaries and the General Partner (i) to execute, deliver and perform each Loan Document to which it is a party (if any), and to consummate the transactions contemplated thereby; and (ii) to own and operate the Business, have been obtained or effected and are in full force and effect. The Borrower and its Subsidiaries are in compliance with the requirements of all such Governmental Approvals and consents and there is no Claim existing, pending or, to the knowledge of the Borrower or the General Partner, threatened which could result in the revocation, cancellation, suspension or any adverse modification of any of such Governmental Approvals or consent;
(l)
No Default - no Default or Event of Default under this Agreement or the Master Trust Indenture has occurred or is continuing which has not (i) been expressly waived in writing by the Agent, the Trustee under the Master Trust Indenture and the holders of the Senior Bonds, Series 13-1, and the holders of the Senior Bonds, Series 15-1; or (ii) been remedied (or otherwise ceased to be continuing);
(m)
Ownership of Assets, Principal Property - the Borrower and its Subsidiaries each has good and marketable title to (and in the case of the Borrower) free and clear of all Liens, other than Permitted Liens, all of its respective Assets used in the Business. The Principal Property in the name of the General Partner is and will be held by the General Partner in trust for the Borrower;
(n)
Taxes -
(i)
the Borrower and its Subsidiaries are currently exempt from (i) income tax under the Income Tax Act (Canada), and (ii) realty taxes under the Assessment Act (Alberta); the Borrower is not in default of any of the filings, payments or other requirements necessary to maintain such exempt status, nor does the Borrower have any knowledge of any event which could result in the Borrower or AltaLink ceasing to be exempt from taxation under such statutes; and
(ii)
the Borrower and its Subsidiaries have filed or caused to be filed all tax returns which, to its knowledge, are required to have been filed, and have

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paid all taxes shown to be due and payable on said returns or on any assessments made against it or any of its property and all other taxes, fees or other charges imposed on it or any of its property by any Governmental Authority (other than those the amount or validity of which is currently being contested in good faith by appropriate proceedings and with respect to which reserves in conformity with GAAP have been provided in its books); and no tax liens have been filed and, to the knowledge of the Borrower no claims are being asserted with respect to any such taxes, fees or other charges;
(o)
No Proceedings - no essential portion of the Borrower’s or any of its Subsidiaries’ real or leased property has been taken or expropriated by any Governmental Authority nor has written notice or proceedings in respect thereof been given or commenced nor is the Borrower aware of any intent or proposal to give any such notice or commence any such proceedings;
(p)
Environmental - except as disclosed to the Agent, neither the Borrower nor any of its Subsidiaries has:
(i)
any knowledge of any Environmental Adverse Effect or any condition existing at, on or under the Principal Property which, in any case or in the aggregate, with the passage of time or the giving of notice or both, could reasonably be expected to give rise to liability of the Borrower or any of its Subsidiaries resulting in a Material Adverse Effect;
(ii)
any knowledge of any present or prior leaks or spills with respect to underground storage tanks and piping system or any other underground structures existing at, on or under Principal Property or of any past violations by any Applicable Laws, policies or codes of practice involving the Principal Property, which violations, in any case or in the aggregate, could reasonably be expected to have a Material Adverse Effect;
(iii)
any knowledge that it has any obligation under any Environmental Laws to pay any compensation or damages resulting from the operation of the Principal Property, or that it will have any such obligation resulting from the maintenance and operation of the Principal Property, which, in any case or in the aggregate, could reasonably be expected to have a Material Adverse Effect; and
(iv)
any Environmental Liability which, in any case or in the aggregate, could reasonably be expected to have a Material Adverse Effect except as disclosed by the Borrower to the Agent in writing prior to the Effective Date;
(q)
No Proceedings or Investigations - none of the Borrower or its Subsidiaries is, as at the date that this representation is made or deemed to be made, the subject of any civil, criminal or regulatory proceeding or governmental or regulatory investigation with respect to Environmental Laws nor are any of them aware of any threatened proceedings or investigations which, in any case or in the aggregate, could reasonably

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be expected to have a Material Adverse Effect except as disclosed in accordance with the notice requirements set out in Section 10.5. The Borrower and its Subsidiaries are actively and diligently proceeding to use all reasonable efforts to comply with all Environmental Laws and all such activities are being carried on in a prudent and responsible manner and with all due care and due diligence;
(r)
Insurance - the Borrower and its Subsidiaries maintain insurance or self insure (including business interruption insurance, property insurance and general liability insurance) with responsible insurance carriers and in such amounts and covering such risks as are usually carried by companies engaged in similar businesses and owning similar properties;
(s)
Pension Plans – Neither the Borrower nor any of its Subsidiaries (except AltaLink Management Ltd.) has established or is party to or obligated under any pension plans. All pension plans established by AltaLink Management Ltd. are being operated, administered and maintained in compliance with all laws, regulations and orders applicable thereto, except for such instances of non-compliance as have not resulted in and could not reasonably be expected to result in a Material Adverse Effect. All premiums, contributions and any other amounts required by applicable pension plan documents or Applicable Laws to be paid or accrued by AltaLink Management Ltd., to the extent failure to do so could reasonably be expected to result in a Material Adverse Effect, are being paid or accrued as required;
(t)
Subsidiaries - (i) the Borrower is the sole limited partner and is the owner of 99.99% of the Equity Securities in AltaLink and AltaLink Management Ltd. is the sole general partner and is the owner of .01% of the Equity Securities of AltaLink, (ii) no Person has any right or option to purchase or otherwise acquire any of the Equity Securities of AltaLink; and (iii) the Borrower does not own or hold any Equity Securities in, directly or indirectly, any other Person, other than as disclosed in Schedule 9.1(a), as amended from time to time and provided to the Lenders (provided such amendments shall not otherwise be contrary to this Agreement); and
(u)
Complete Disclosure - all written information and data concerning the Borrower, the General Partner and the Borrower’s Subsidiaries that have been prepared by it or any of its representatives or advisors and that have been made available to the Agent or the Lenders are and, at the time such information and data were made available, were true and correct in all material respects and do not, and, at the time such information and data were made available, did not, contain any untrue statement of a material fact, or omit to state a material fact necessary in order to make the statements contained in such information and data not misleading in light of the circumstances under which such statements were made.
9.2
Survival of Representations and Warranties.
All representations and warranties contained in this Agreement, the Loan Documents and any certificate or document delivered pursuant hereto shall survive the execution and delivery of this Agreement and the Loan Documents, the advance of each Accommodation and exercise of any

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remedies under this Agreement or under any of the Loan Documents, notwithstanding any investigation made at any time by or on behalf of the Agent or the Lenders.
ARTICLE 10    
COVENANTS
The Borrower covenants and agrees that, so long as any Accommodation is outstanding or the Borrower is entitled to obtain any Accommodation under the Credit Facility:
10.1
Reporting Covenants.
(a)
Information and Certificates. The Borrower shall furnish to the Agent (in “pdf” format where practicable, or in such other form as may be agreed between the Borrower and the Agent):
(i)
not later than one hundred and forty (140) days (or such earlier date as may be prescribed from time to time under applicable securities legislation for the delivery of annual financial statements to security holders) after the end of each Fiscal Year, the annual financial statements (consolidated and unconsolidated) of the Borrower consisting of a balance sheet and statements of income, retained earnings and changes in financial position for the year then ended and for the immediately preceding Fiscal Year together with the report on such consolidated statements of the Borrower’s Auditors and the discussion and analysis of such consolidated statements prepared by the management of the Borrower;
(ii)
not later than sixty (60) days (or such earlier date as may be prescribed from time to time under applicable securities legislation for the delivery of interim financial statements to security holders) after the end of the first, second and third Fiscal Quarters of each Fiscal Year, the unaudited interim financial statements (consolidated and unconsolidated) of the Borrower, including a balance sheet and statements of income and changes in financial position for the period then ended and for the year to date and for the comparative periods in the prior Fiscal Year of the Borrower;
(iii)
at the time the same are sent, copies of all financial statements and other information or material that are delivered to the Trustee under the Master Trust Indenture including, without limitation, notice of any “Event of Default” under the Master Trust Indenture;
(iv)
on or before thirty (30) days prior to the beginning of the next Fiscal Year of the Borrower, an annual consolidated and unconsolidated financial forecast of the Borrower;
(v)
a certified copy of any supplemental indenture which amends in any way the Master Trust Indenture; and

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(vi)
upon delivery of each of the items set out in Sections 10.1(a)(i) and (ii) of this Agreement, the Borrower’s Certificate of Compliance, which Certificate of Compliance shall be accompanied by, inter alia, details of the calculation of EBITDA in accordance with GAAP for the purposes of the Interest Coverage Ratio in Section 10.24(a), in form and substance satisfactory to the Lenders.
10.2
Payments Under This Agreement and Loan Documents.
The Borrower shall pay, discharge or otherwise satisfy all amounts payable under this Agreement in accordance with the terms of this Agreement and all amounts payable under any Loan Document in accordance with the terms thereof.
10.3
Proceeds.
The Borrower shall use the proceeds of any Accommodation only for the purposes permitted pursuant to Section 2.3
10.4
Inspection of Property, Books and Records, Discussions.
The Borrower and each of its Subsidiaries shall keep proper books of record and account in which full, true and correct entries in conformity with GAAP and all Applicable Laws and on a basis consistent with its financial statements shall be made of all dealings and transactions in relation to its business and activities, and permit representatives and agents of the Agent upon reasonable notice to the Borrower and during business hours, to visit and inspect any of the properties and examine and make abstracts from any of the books and records of the Borrower as often as may reasonably be desired, and, subject to applicable securities laws, to discuss the business, operations, property, condition and prospects (financial or otherwise) of the Borrower with those officers and employees of the Borrower designated by its senior executive officers.
10.5
Notices.
The Borrower shall promptly give notice to the Agent of:
(a)     the occurrence of any Default or Event of Default;
(b)
the commencement of, or receipt by the Borrower of a written threat of, any action, suit or proceeding against or affecting the Borrower before any Governmental Authority which, individually or in the aggregate, has, or has any reasonable likelihood of having, a Material Adverse Effect, and such further information in respect thereof as the Agent may request from time to time;
(c)
any notice of any violation or administrative or judicial complaint or order having been filed or, to the Borrower’s knowledge, about to be filed against the Borrower which has, or has any reasonable likelihood of having, a Material Adverse Effect;

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(d)
any notice from any Governmental Authority or any other Person alleging that the Borrower is or may be subject to any Environmental Liability which has, or has any reasonable likelihood of having, a Material Adverse Effect;
(e)
any notice of any material violation of Applicable Utilities Legislation;
(f)
the occurrence or non-occurrence of any other event which has, or has a reasonable likelihood of having, a Material Adverse Effect;
(g)    any changes in the ownership structure of the Borrower; and
(h)
any notice of a change in rating to the Senior Bonds (as such term is defined in the Master Trust Indenture) by any of the Rating Agencies.
10.6
Disbursements under Master Trust Indenture.
The Borrower shall disburse and apply all Net Revenues (as such term is defined in the Master Trust Indenture) in accordance with Section 4.1 of the Master Trust Indenture.
10.7
Cure Defects.
The Borrower shall promptly cure or cause to be cured any defects in the execution and delivery of any of the Loan Documents or any of the other agreements, instruments or documents contemplated thereby or executed pursuant thereto or any defects in the validity or enforceability of any of the Loan Documents and execute and deliver or cause to be executed and delivered all such agreements, instruments and other documents as the Agent may consider necessary or desirable for the foregoing purposes.
10.8
Carrying on Business.
The Borrower and each of its Subsidiaries shall own, maintain and repair or reconstruct the Principal Property and all other Assets, including licences, permits and intellectual property, necessary to operate the Business and directly receive all revenues associated therewith and shall at all times carry on and conduct the Business in a proper, efficient and businesslike manner and in accordance with good business practices so as to comply with all applicable regulatory requirements and preserve and protect the revenues thereof.
10.9
Insurance and Insurance Proceeds.
(a)
The Borrower and each of its Subsidiaries shall maintain insurance with respect to its properties and business and against such casualties and contingencies and in such types and such amounts as shall be in accordance with sound business practices which are standard in the industry and in accordance with any express requirements of Governmental Authorities, where applicable, including the right to self-insure and/or co-insure with respect to any of the insurance required to be maintained by the Borrower pursuant to this paragraph.

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(b)
Immediately upon receipt by the Borrower of any Insurance Proceeds, Borrower shall apply such Insurance Proceeds in accordance with Section 4.1 of the Master Trust Indenture. Notwithstanding the foregoing, to the extent that any Insurance Proceeds are used by the Borrower, within 12 months after receipt of same, to replace or repair the Assets in respect of which the Insurance Proceeds were received, then such Insurance Proceeds need not be so applied. Borrower shall provide Agent with a copy of any officer’s certificate provided pursuant to Section 6.10 of the Master Trust Indenture.
10.10
Compliance with Laws and Agreements.
The Borrower and each of its Subsidiaries shall at all times comply in all material respects with all requirements of the Applicable Utilities Legislation and all other Applicable Laws. The Borrower shall at all times comply in all material respects with all Material Agreements, including, without limitation, the Master Trust Indenture.
10.11
Taxes.
The Borrower and each of its Subsidiaries shall, from time to time, pay or cause to be paid all Taxes lawfully levied, assessed or imposed upon or in respect of its property or any part thereof or upon its income and profits as and when the same become due and payable and withhold and remit any amounts required to be withheld by it from payments due to others and remit the same to any government or agency thereof, and it will exhibit or cause to be exhibited to the Agent, when requested, the receipts and vouchers establishing such payment and will in all material respects duly observe and conform to all applicable requirements of any Governmental Authority relative to any of the property or rights of the Borrower and all covenants, terms and conditions upon or under which any such property or rights are held; provided, however, that the Borrower shall have the right to contest, in good faith and diligently by legal proceedings, any such Taxes and, during such contest, may delay or defer payment or discharge thereof.
10.12
Further Assurances.
At the Borrower’s cost and expense, upon request of the Agent, duly execute and deliver or cause to be duly executed and delivered to the Agent such further instruments and do and cause to be done such further acts as may be necessary or proper in the reasonable opinion of the Agent to carry out more effectually the provisions and purposes of the Loan Documents.
10.13
Limitation on Indebtedness.
The Borrower will not, and will not permit any Non-AltaLink Subsidiary to, directly or indirectly, create, incur assume, suffer to exist any Indebtedness other than (i) the Indebtedness under the Senior Bonds, Series 13-1, such Indebtedness not to exceed $200,000,000 excluding accrued but unpaid interest, in the aggregate at any time, (ii) the Indebtedness under the Senior Bonds, Series 15-1, such Indebtedness not to exceed $200,000,000 excluding accrued but unpaid interest, in the aggregate at any time, (iii) the Indebtedness owing to the Lenders and/or the Agent under this Agreement, (iv) other Indebtedness, including Capital Lease Obligations and Purchase Money Obligations, not to exceed, in the aggregate at any time, $10,000,000 or the Equivalent Amount

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thereof, and (v) Indebtedness of the Borrower under any interest rate, currency rate or commodity hedging agreement permitted under this Agreement.
10.14
Negative Pledge.
The Borrower will not, and will not permit any Non-AltaLink Subsidiary to, create, incur, assume or suffer to exist any Lien on any of its Assets, whether now owned or hereafter acquired, other than Permitted Liens.
10.15
Investments.
The Borrower shall not, directly or indirectly, make any Investments, other than (i) Investments in AltaLink and its present and future Subsidiaries, (ii) Investments in a wholly-owned Subsidiary of the Borrower or in a Non-AltaLink Subsidiary in conjunction with an Acquisition made by the Borrower and permitted by Section 10.18 of this Agreement or other Investments in such Subsidiaries (and provided for greater certainty that the aggregate amount of all such Investments in any Fiscal Year together with the amount of Acquisitions under Section 10.18 in any Fiscal Year shall not exceed the aggregate amount permitted by Section 10.18), and (iii) other Investments related to the Business to a maximum aggregate amount of $5,000,000. For purposes of this Section 10.15 and Section 10.16 (and paragraph 5 of the Certificate of Compliance), a Subsidiary of the Borrower (other than AltaLink) shall be deemed to be a wholly owned Subsidiary of the Borrower so long as (a) the Borrower is the sole limited partner and is the owner of 99.99% of the Equity Securities of such Subsidiary and the sole general partner of such Subsidiary is the owner of .01% of the Equity Securities of Subsidiary, (b) no Person has any right or option to purchase or otherwise acquire any of the Equity Securities of such Subsidiary, and (c) Berkshire Hathaway Energy Company continues to own (directly or indirectly) 100% of the Equity Securities of the general partner of such Subsidiary, provided however that the Borrower and its Subsidiaries may not make any Investment (including pursuant to Section 10.15(iii)) in respect of any activities covered in paragraph (g) of the definition of Business.
10.16
Change in Business and Ownership of AltaLink and Subsidiaries.
The Borrower and its Subsidiaries shall not engage in any business other than the Business. The Borrower shall ensure that (a) AltaLink is at all times a direct, wholly-owned Subsidiary of the Borrower, and (b) at no time shall the total revenues and total Assets, respectively, of all non wholly-owned Subsidiaries of the Borrower exceed 10% of the Borrower’s consolidated revenues or Consolidated Assets, as disclosed in the most recent audited financial statements delivered to the Agent and the Lenders pursuant to Section 10.1, as the case may be.
10.17
Mergers, Etc.
Neither the Borrower nor any Subsidiary of the Borrower shall enter into, any transaction (whether by way of reconstruction, reorganization, consolidation, amalgamation, winding-up, merger, transfer, sale, lease or otherwise) whereby all or any substantial part of its undertaking or Assets would become the property of any other Person.
10.18
Acquisitions.

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Neither the Borrower nor any Subsidiary of the Borrower shall make, directly or indirectly, any Acquisition other than Acquisitions which (i) pertain to the Business, and (ii) where the value of the Assets acquired do not, in any Fiscal Year, exceed the lesser of (y) 25% of the Consolidated Assets, and (z) 25% of consolidated revenues of the Borrower (determined in accordance with GAAP), in each case, as disclosed in the most recent audited financial statements delivered to Agent and Lenders pursuant to Section 10.1, and provided that no Default or Event of Default has occurred or is continuing or would occur as a result of such Acquisition, provided however that the Borrower and its Subsidiaries may not make any Acquisitions in respect of any activities covered in paragraph (g) of the definition of Business.
10.19
Transactions with Non-Arm’s Length Persons.
Neither the Borrower nor any Subsidiary of the Borrower shall, directly or indirectly, (a) purchase, acquire, lease or license any material property, assets, right or service from, or (b) sell, transfer, lease or license any property, assets, right or services to, any Person (including any partner and their respective Affiliates) not dealing at arm’s length with the Borrower, or any Affiliate of any such Person, except at prices and on terms not less favourable to the Borrower than those which could have been obtained in an arm’s length transaction with an arm’s length Person.
10.20
Environmental Covenants.
(a)
The Borrower and its Subsidiaries shall, at all times conduct and maintain the Business in compliance in all material respects with all Environmental Laws and Environmental Approvals.
(b)
If the Borrower or any of its Subsidiaries shall:
(i)
receive notice from any Governmental Authority that any material violation of any Environmental Law or Environmental Approval has been, may have been, or is about to be committed by the Borrower or its Subsidiaries;
(ii)
receive notice that any Remedial Order or other proceeding has been filed or is about to be filed against the Borrower or any of its Subsidiaries alleging material violations of any Environmental Law or requiring the Borrower or any of its Subsidiaries to take any material action in connection with the Release or threatened Release of a Hazardous Substance into the environment or requiring the cessation of a nuisance; or
(iii)
receive any notice from a Governmental Authority alleging that the Borrower or any of its Subsidiaries may be liable or responsible for material costs associated with a nuisance or a response to, or clean up of, a Release or threatened Release of a Hazardous Substance into the environment or any damages caused thereby;
then the Borrower shall in each such case provide the Agent with a copy of such notice within ten (10) days of the Borrower’s or Subsidiary’s receipt thereof, and thereafter shall keep the Agent informed in a timely manner of any developments in

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such matters, and shall provide to the Agent such other information in respect thereto as may be reasonably requested by the Agent from time to time.
10.21
Hedging Agreements.
Neither the Borrower nor any Subsidiary of the Borrower (excluding AltaLink) shall enter into any Financial Instrument Obligation (or similar understanding or obligation) except in accordance with Section 6.3 of the Master Trust Indenture.
10.22
Distributions.
The Borrower shall not make or commit to make any Distributions if a Default or Event of Default has occurred and is continuing or could reasonably be expected to result therefrom. Borrower shall provide Agent with satisfactory evidence of pro forma compliance with the financial covenants set out in Section 10.24 of this Agreement, after giving effect to such proposed Distribution and compliance with Section 4.1 of the Master Trust Indenture.
10.23
Fiscal Year.
Neither the Borrower nor any Subsidiary of the Borrower shall change its Fiscal Year.
10.24
Financial Covenants.
The Borrower shall comply with the following financial covenants:
(a)
Interest Coverage Ratio. The Borrower shall maintain, measured each Fiscal Quarter in each Fiscal Year, a ratio of EBITDA for the four Fiscal Quarters then ended to Interest Expense for the four Fiscal Quarters then ended, of not less than 2.25:1. The parties agree that for the purposes of this Section 10.24(a), and provided that the reporting requirements in Section 10.1(a)(vi) are complied with in respect of such calculation, EBITDA shall be calculated on the basis of GAAP (as in effect immediately prior to the adoption by the Borrower of IFRS), notwithstanding the fact that the Borrower may have adopted IFRS; and
(b)
Consolidated Total Debt to Consolidated Total Capitalization. The Borrower and its Subsidiaries shall maintain, during each Fiscal Quarter in each Fiscal Year, a maximum ratio of Consolidated Total Debt to Consolidated Total Capitalization of 80%.
10.25
Master Trust Indenture.
The Borrower covenants and agrees that so long as any Accommodation is outstanding or the Borrower is entitled to obtain any Accommodation under the Credit Facility, the Borrower will comply with all of the covenants, positive and negative, contained in the Master Trust Indenture. Notwithstanding the foregoing, in the event of any conflict or inconsistency between any of the provisions in this Agreement and any of the provisions in the Master Trust Indenture, as against the parties hereto and their respective successors and permitted assigns the provisions in this Agreement shall prevail.

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ARTICLE 11    
CONDITIONS PRECEDENT TO BORROWINGS
11.1
Conditions Precedent to the Closing.
The effectiveness of this Agreement is subject to the condition precedent that the Agent and each Lender shall be satisfied with, or the Borrower shall have delivered to the Agent, as the case may be, on or before the Effective Date, the following in form, substance and dated as of a date satisfactory to the Lenders and their counsel and in sufficient quantities for each Lender:
(a)
this Agreement shall have been duly executed and delivered by the Borrower and the General Partner;
(b)
completion of and satisfactory results with respect to, such financial, business and legal due diligence as reasonably requested by the Lenders;
(c)
the Agent or the Lenders shall have received any other Loan Documents required by the Agent or the Lenders duly executed by the Borrower and the General Partner, as the case may be;
(d)
the following documents in form, substance and execution acceptable to the Agent shall have been delivered to the Agent:
(i)
duly certified copies of the constating documents of the Borrower and the General Partner, all necessary resolutions of the board of directors or similar necessary proceedings taken and required to be taken by the Borrower to authorize the execution and delivery of this Agreement and the Loan Documents (excluding Loan Documents executed and delivered prior to the date hereof pursuant to the Existing Credit Agreement) to which it is a party and the entering into and performance of the transactions contemplated herein and therein;
(ii)
certificates of incumbency of the General Partner setting forth specimen signatures of the persons authorized to execute this Agreement, on behalf of the Borrower and the Loan Documents to which it is a party;
(iii)
certificate of status or the equivalent relative to the Borrower and the General Partner under its jurisdiction of creation; and
(iv)
the opinion of counsel for the Borrower in form and substance satisfactory to the Lenders;
(e)
there not having occurred a Material Adverse Change since September 30, 2019;
(f)
all fees payable on or before the date hereof in connection with the Credit Facility under this Agreement and any fee letter shall have been paid to the Agent; and
(g)
there shall exist no Default or Event of Default.

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11.2
Conditions Precedent to All Borrowings, Conversions.
The Lenders shall not be obliged to make available any portion of any Borrowing, or to give effect to any conversion or rollover, unless each of the following conditions is satisfied:
(a)
the Agent shall have received any required Borrowing Notice;
(b)
the Agent shall have received any required Documentary Credit agreement, or other Loan Document;
(c)
there shall exist no Default or Event of Default on the applicable Borrowing Date, nor shall any arise as a result of giving effect to the requested Borrowing;
(d)
all representations and warranties contained in ARTICLE 9 shall be true on and as of the Borrowing Date with the same effect as if such representations and warranties had been made on and as of such Borrowing Date; and
(e)
all fees payable on or before the subsequent Borrowing in connection with the Credit Facility under this Agreement or any other Loan Document shall have been paid to the Agent and the Lenders, as applicable.
11.3
Waiver.
The Lenders may, at their option, waive any condition precedent set out in Section 11.1 or 11.2 or make available any Borrowing prior to such condition precedent being fulfilled. Any such Borrowing shall be deemed to be made pursuant to the terms hereof. Any such waiver shall not be effective unless it is in writing and shall not operate to excuse the Borrower from full and complete compliance with this ARTICLE 11 or any other provision hereof on future occasions.
ARTICLE 12    
EVENTS OF DEFAULT
12.1
Events of Default.
Any of the following events shall constitute an “Event of Default” hereunder:
(a)
Default in Payment of any Amount Hereunder. If the Borrower fails to pay (i) any principal amount of the Accommodations when such amount becomes due and payable, (ii) any interest or fees owing to the Lenders and/or Agent or any of them hereunder, or under any Loan Document when due and payable hereunder or thereunder and such failure shall remain unremedied for five (5) Business Days or (iii) any other amount owing to the Lenders and/or Agent or any of them hereunder, or under any Loan Document when due and payable hereunder or thereunder and such failure shall remain unremedied for five (5) Business Days;
(b)
Representation or Warranty. If any representation and warranty made by the Borrower in or in connection with this Agreement or any of the other Loan Documents shall be untrue in any material respect on the date upon which it was given;

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(c)
Default in Certain Covenants.
(i)
If the Borrower or any of its Subsidiaries (as applicable and as if each Subsidiary of the Borrower were party hereto) shall fail, refuse or default in any material respect with the performance or observance of any of the covenants contained in Sections 10.13, 10.15, 10.16(b), and 10.18 to 10.23 inclusive, and such failure shall continue unremedied for 15 days; or
(ii)
If the Borrower or any of its Subsidiaries (as applicable and as if each Subsidiary of the Borrower were party hereto) shall fail, refuse or default in any material respect with the performance or observance of any of the covenants contained in Sections 10.14, 10.16(a), 10.17, 10.24 or 10.25, (provided that, in the case of Section 10.25, there shall be no Event of Default until the expiry of the applicable cure period, if any, under the Master Trust Indenture);
(d)
Default in Other Provisions. If the Borrower or any of its Subsidiaries (as applicable and as if each Subsidiary of the Borrower were party hereto) shall fail, refuse or default in any material respect with the performance or observance of any of the other covenants, agreements or conditions contained herein and such failure, refusal or default adversely affects the Lenders and, such failure, refusal or default continues for a period of thirty (30) days after written notice thereof by the Agent;
(e)
Indebtedness. If (i) the Borrower or any of its Subsidiaries fails to pay the principal of any of its Indebtedness (which shall, for greater certainty, exclude the Indebtedness under this Agreement but shall include (without limitation) the Indebtedness under the Master Trust Indenture and the Senior Bonds, Series 13-1, and the Senior Bonds, Series 15-1) which is outstanding in an aggregate principal amount exceeding (x) Cdn. $15,000,000 in the case of the Borrower and (y) Cdn. $10,000,000 in the case of AltaLink or any other Subsidiary of the Borrower (or the Equivalent Amount in any other currency) when such amount becomes due and payable (whether by scheduled maturity, required prepayment, acceleration, demand or otherwise) and such failure continues after the applicable grace period, if any, specified in the agreement or instrument relating to such Indebtedness described in paragraphs (x) and (y) above, without waiver of such failure by the holder of such Indebtedness on or before the expiration of such period; or (ii) any other event occurs or condition exists (including a failure to pay the premium or interest on such Indebtedness) and continues after the applicable grace period, if any, specified in any agreement or instrument relating to any such Indebtedness without waiver of such failure by the holder of such Indebtedness on or before the expiration of such period, if the effect of such event is to accelerate, or permit the acceleration of, such Indebtedness; or (iii) any such Indebtedness shall be declared to be, or otherwise becomes, due and payable prior to its stated maturity by reason of default;
(f)
Judgment. The rendering of a judgment or judgments against the Borrower or any of its Subsidiaries, in an aggregate amount in excess of Cdn. $20,000,000 (or the Equivalent Amount in any other currency), by a court or courts of competent

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jurisdiction, which judgment or judgments remain undischarged and unstayed for a period of sixty (60) days;
(g)
Change in Legislation. If there occurs any change in the Applicable Utilities Legislation or any other Applicable Laws resulting in a Material Adverse Effect on the Business of the Borrower or any of its Subsidiaries;
(h)
Termination of Material Agreements, licences etc.
(i)
If any Material Agreement is terminated for any reason prior to the expiry of its term (except as contemplated thereunder) unless: (A) such Material Agreement is replaced by the Borrower with a contract on commercially reasonable terms or (B) such termination does not result in a Material Adverse Effect;
(ii)
if a default occurs under, or if the Borrower fails to observe or perform any term, covenant or agreement contained in, any Material Agreement unless such default or failure does not result in a Material Adverse Effect; or
(iii)
if any permit, licence, consent or other authorization required to be kept in full force and effect hereunder with respect to the Business is revoked or suspended for any reason whatsoever and such revocation or suspension results in a Material Adverse Effect and such revocation and suspension continues for a period of 45 days, unless the Borrower does not contest such revocation or suspension in good faith, diligently and by appropriate means;
(i)
Winding Up. If an order shall be made or an effective resolution be passed for the winding-up or liquidation of the Borrower or any of its Subsidiaries or any such proceedings are initiated unless such proceedings are being actively and diligently contested by the Borrower in good faith;
(j)
Bankruptcy or Insolvency. If the Borrower or any of its Subsidiaries shall make a general assignment for the benefit of its creditors or a notice of intention to make a proposal or a proposal under the Bankruptcy and Insolvency Act (Canada), or shall become insolvent or be declared or adjudged bankrupt, or a receiving order be made against the Borrower or any of its Subsidiaries or if a liquidator, trustee in bankruptcy, receiver, receiver and manager or any other officer with similar powers shall be appointed to the Borrower or any of its Subsidiaries, or if the Borrower or any of its Subsidiaries shall propose a compromise, arrangement or reorganization under the Companies’ Creditors Arrangement Act (Canada) or any other legislation of any jurisdiction (including corporate statutes, as applicable) providing for the reorganization or winding-up of Borrower or any of its Subsidiaries or business entities or providing for an arrangement, composition, extension or adjustment with its creditors or shall voluntarily suspend transaction of its usual business, or shall take corporate or other action in furtherance of any of the foregoing purposes;

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(k)
Receiver. If any proceeding for the appointment of a receiver or trustee for the Borrower or any of its Subsidiaries or for any substantial part of the property of the Borrower or any of its Subsidiaries which is material to the conduct of the Business, and any such receivership or trusteeship remains undischarged for a period of sixty (60) days, or if the Borrower or any of its Subsidiaries becomes bankrupt or unable to pay its obligations as they become due or is declared to be bankrupt or unable to pay its obligations as they become due;
(l)
Full Force and Effect. If this Agreement or any material portion hereof shall, at any time after its respective execution and delivery and for any reason, cease in any way to be in full force and effect or if the validity or enforceability of this Agreement is disputed in any manner by such Borrower and the Credit Facility has not been repaid within 30 days of demand therefor by the Agent; and
(m)
Change of Control. If there shall occur any Change of Control.
12.2
Remedies.
Upon the occurrence of any Default or Event of Default, and at any time thereafter if the Default or Event of Default shall then be continuing, the Lenders in their sole discretion may direct the Agent to give notice to the Borrower that no further Accommodation will be available hereunder while the Default or Event of Default continues, whereupon the Lenders shall not be obliged to provide any further Borrowings to the Borrower while the Default or Event of Default continues. Upon the occurrence of any Event of Default, and at any time thereafter if the Event of Default shall then be continuing, the Lenders in their sole discretion, and the Agent acting on their behalf, may take any or all of the following actions:
(a)
demand payment of any principal, accrued interest, fees and other amounts which are then due and owing in respect of the Accommodation under the Credit Facility without presentment, protest or other notice of any kind, all of which are hereby expressly waived by the Borrower;
(b)
declare by notice to the Borrower the Credit Facility terminated, whereupon the same shall terminate immediately without any further notice of any kind;
(c)
commence such legal action or proceedings as it, in its sole discretion, may deem expedient, including the commencement of enforcement proceedings under the Loan Documents, all without any additional notice, presentation, demand, protest, notice of dishonour, entering into of possession of any of the assets, or any other action or notice, all of which the Borrower and General Partner hereby expressly waive; and
(d)
demand payment of the Senior Pledged Bond, Series 2 in accordance with the provisions of the Bond Delivery Agreement.
12.3
Remedies Cumulative.

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The rights and remedies of the Lenders and the Agent under this Agreement and the Loan Documents are cumulative and are in addition to and not in substitution for any other rights or remedies. Nothing contained herein or in the Loan Documents with respect to the indebtedness or liability of the Borrower to the Agent and the Lenders or any part thereof, nor any act or omission of the Agent and the Lenders with respect to the Loan Documents shall in any way prejudice or affect the rights, remedies and powers of the Agent and the Lenders hereunder or under the Loan Documents.
12.4
Appropriation of Moneys Received.
The Lenders, and the Agent on behalf of the Lenders as between the Lenders and the Borrower, may from time to time when an Event of Default has occurred and is continuing appropriate any monies received from the Borrower in or toward payment of such of the obligations of the Borrower hereunder as the Lenders in their sole discretion may see fit.
12.5
Non-Merger.
The taking of any action or dealing whatsoever by the Lender or the Agent in respect of the Borrower or any security shall not operate as a merger of any of the obligations of the Borrower to the Lenders or the Agent or in any way suspend payment or affect or prejudice the rights, remedies and powers, legal or equitable, which the Lenders or the Agent may have under Section 12.3 in connection with such obligations.
12.6
Waiver.
No delay on the part of the Lenders or the Agent in exercising any right or privilege hereunder shall operate as a waiver thereof. No Default or Event of Default shall be waived except by a written waiver in accordance with Section 21.1. Each written waiver shall apply only to the Default or Event of Default to which it is expressed to apply. No written waiver shall preclude the subsequent exercise by the Lenders or the Agent of any right, power or privilege hereunder or extend to or apply to any other Default or Event of Default.
12.7
Set-off.
Upon the occurrence and during the continuance of any Event of Default, each Lender is authorized at any time and from time to time, to the fullest extent permitted by law (including general principles of common law), to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by it to or for the credit or the account of the Borrower against any and all of the obligations of the Borrower under any of the Loan Documents, irrespective of whether or not the Lender has made demand under any of the Loan Documents and although such obligations may be unmatured or contingent. If an obligation is unascertained, the Lender may, in good faith, estimate the obligation and exercise its right of set-off in respect of the estimate, subject to providing the Borrower with an accounting when the obligation is finally determined. Each Lender shall promptly notify the Borrower after any set-off and application is made by it, provided that the failure to give notice shall not affect the validity of the set-off and application. The rights of the Lenders under this Section 12.7 are in addition to other rights and remedies (including all other rights of set-off) which the Lenders may have.

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ARTICLE 13    
YIELD PROTECTION
13.1
Increased Costs.
(a)
Increased Costs Generally. If any Change in Law shall:
(i)
impose, modify or deem applicable any reserve, special deposit, compulsory loan, insurance charge or similar requirement against assets of, deposits with or for the account of, or credit extended or participated in by, any Lender;
(ii)
subject any Lender to any Tax of any kind whatsoever with respect to this Agreement or any Accommodations made by it, or change the basis of taxation of payments to such Lender in respect thereof, except for Indemnified Taxes or Other Taxes covered by Section 13.2 and the imposition, or any change in the rate, of any Excluded Tax payable by such Lender; or
(iii)
impose on any Lender or any applicable interbank market any other condition, cost or expense affecting this Agreement or Accommodations made by such Lender,
and the result of any of the foregoing shall be to increase the cost to such Lender of making or maintaining any Accommodation (or of maintaining its obligation to make any such Accommodation), or to increase the cost to such Lender, or to reduce the amount of any sum received or receivable by such Lender hereunder (whether of principal, interest or any other amount), then upon request of such Lender the Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender for such additional costs incurred or reduction suffered.
(b)
Capital Requirements. If any Lender determines that any Change in Law affecting such Lender, or any lending office of such Lender or such Lender’s holding company, if any, regarding capital requirements has or would have the effect of reducing the rate of return on such Lender’s capital or on the capital of such Lender’s holding company, if any, as a consequence of this Agreement, the Commitments of such Lender or the Accommodations made by such Lender, to a level below that which such Lender or its holding company could have achieved but for such Change in Law (taking into consideration such Lender’s policies and the policies of its holding company with respect to capital adequacy), then from time to time the Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender or its holding company for any such reduction suffered.
(c)
Certificates for Reimbursement. A certificate of a Lender setting forth the amount or amounts necessary to compensate such Lender or its holding company, as the case may be, as specified in paragraph (a) or (b) of this Section (“Additional Compensation”), including a description of the event by reason of which it believes it is entitled to such compensation, and supplying reasonable supporting evidence

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(including, in the event of a Change in Law, a photocopy of the Applicable Law evidencing such change) and reasonable detail of the basis of calculation of the amount or amounts, and delivered to the Borrower shall be conclusive absent manifest error. The Borrower shall pay such Lender the amount shown as due on any such certificate within 10 days after receipt thereof. In the event the Lender subsequently recovers all or part of the Additional Compensation paid by the Borrower, it shall promptly repay an equal amount to the Borrower. The obligation to pay such Additional Compensation for subsequent periods will continue until the earlier of termination of the Accommodation or the Commitment affected by the Change in Law, change in capital requirement or the lapse or cessation of the Change in Law giving rise to the initial Additional Compensation. A Lender shall make reasonable efforts to limit the incidence of any such Additional Compensation and seek recovery for the account of the Borrower upon such Borrower’s request at such Borrower’s expense, provided such Lender in its reasonable determination suffers no appreciable economic, legal, regulatory or other disadvantage. Notwithstanding the foregoing provisions, a Lender shall only be entitled to rely upon the provisions of this Section 13.1 if and for so long as it is not treating the Borrower in any materially different or in any less favourable manner than is applicable to any other customers of such Lender, where such other customers are bound by similar provisions to the foregoing provisions of this Section 13.1.
(d)
Delay in Requests. Failure or delay on the part of any Lender to demand compensation pursuant to this Section shall not constitute a waiver of such Lender’s right to demand such compensation, except that the Borrower shall not be required to compensate a Lender pursuant to this Section for any increased costs incurred or reductions suffered more than nine months prior to the date that such Lender notifies the Borrower of the Change in Law giving rise to such increased costs or reductions and of such Lender’s intention to claim compensation therefore, unless the Change in Law giving rise to such increased costs or reductions is retroactive, in which case the nine-month period referred to above shall be extended to include the period of retroactive effect thereof.
13.2
Taxes.
(a)
Payments Subject to Taxes. If any Credit Party, the Agent or any Lender is required by Applicable Law to deduct or withhold any Indemnified Taxes (including any Other Taxes) in respect of any payment by or on account of any obligation of a Credit Party hereunder or under any other Loan Document, then (i) the sum payable shall be increased by that Credit Party when payable as necessary so that after making or allowing for all required deductions and withholds (including deductions and withholds applicable to additional sums payable under this Section) the Agent or Lender, as the case may be, receives an amount equal to the sum it would have received had no such deductions or withholds been required, (ii) the Credit Party shall make any such deductions or withholds required to be made by it under Applicable Law and (iii) the Credit Party shall timely pay the full amount required

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to be deducted or withheld to the relevant Governmental Authority in accordance with Applicable Law.
(b)
Payment of Other Taxes by the Borrower. Without limiting the provisions of paragraph (a) above, the Borrower shall timely pay any Other Taxes to the relevant Governmental Authority in accordance with Applicable Law.
(c)
Indemnification by the Borrower. The Borrower shall indemnify the Agent and each Lender, within 15 days after written demand therefor, for the full amount of any Indemnified Taxes or Other Taxes (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section) paid by the Agent or such Lender and any penalties, interest and reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to the Borrower by a Lender (with a copy to the Agent), or by the Agent on its own behalf or on behalf of a Lender, shall be conclusive absent manifest error. In the event the Lender subsequently recovers all or part of the payment made under this Section paid by the Borrower, it shall promptly repay an equal amount to the Borrower. A Lender shall make reasonable efforts to limit the incidence of any payments under this Section and seek recovery for the account of the Borrower upon the Borrower’s request at the Borrower’s expense, provided such Lender in its reasonable determination suffers no appreciable economic, legal, regulatory or other disadvantage.
(d)
Evidence of Payments. As soon as practicable after any payment of Indemnified Taxes or Other Taxes by a Credit Party to a Governmental Authority, the Credit Parties shall deliver to the Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Agent.
(e)
Status of Lenders. Any Foreign Lender that is entitled to an exemption from or reduction of withholding tax under the law of the jurisdiction in which the Borrower is resident for tax purposes, or any treaty to which such jurisdiction is a party, with respect to payments hereunder or under any other Loan Document shall, at the request of the Borrower, deliver to the Borrower (with a copy to the Agent), at the time or times prescribed by Applicable Law or reasonably requested by the Borrower or the Agent, such properly completed and executed documentation prescribed by Applicable Law as will permit such payments to be made without withholding or at a reduced rate of withholding. In addition any Lender, if requested by the Borrower or the Agent, shall deliver such other documentation prescribed by Applicable Law or reasonably requested by the Borrower or the Agent as will enable the Borrower or the Agent to determine whether or not such Lender is subject to withholding or information reporting requirements.

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(f)
Treatment of Certain Refunds and Tax Reductions. If the Agent or a Lender determines, in its sole discretion, that it has received a refund of any Taxes or Other Taxes as to which it has been indemnified by the Borrower or with respect to which a Credit Party has paid additional amounts pursuant to this Section 13.2 or that, because of the payment of such Taxes or Other Taxes, it has benefited from a reduction in Excluded Taxes otherwise payable by it, it shall pay to the Borrower or other Credit Party, as applicable, an amount equal to such refund or reduction (but only to the extent of indemnity payments made, or additional amounts paid, by the Borrower or other Credit Party under this Section with respect to the Taxes or Other Taxes giving rise to such refund or reduction), net of all out-of-pocket expenses of the Agent or such Lender, as the case may be, and without interest (other than any net after-Tax interest paid by the relevant Governmental Authority with respect to such refund). The Borrower or other Credit Party as applicable, upon the request of the Agent or such Lender, agrees to repay the amount paid over to the Borrower or other Credit Party (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to the Agent or such Lender if the Agent or such Lender is required to repay such refund or reduction to such Governmental Authority. This paragraph shall not be construed to require the Agent or any Lender to make available its tax returns (or any other information relating to its taxes that it deems confidential) to the Borrower or any other Person, to arrange its affairs in any particular manner or to claim any available refund or reduction.
(g)
FATCA. If a payment made to a Lender under any Loan Document would be subject to U.S. federal withholding Taxes imposed by FATCA, if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Internal Revenue Code, as applicable), such Lender shall deliver to the Borrower and the Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Agent such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Internal Revenue Code) and such additional documentation reasonably requested by the Borrower or the Agent as may be necessary for the Borrower and the Agent to comply with their obligations under FATCA and to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment. Solely for purposes of this clause (g), “FATCA” shall include any amendments made to FATCA after the date of this Agreement.
The Agreements in this Section 13.2 shall survive the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.
13.3
Mitigation Obligations: Replacement of Lenders.
(a)
Designation of a Different Lending Office. If any Lender requests compensation under Section 13.1, or requires the Borrower to pay any additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 13.2, then such Lender shall use reasonable efforts to designate a different

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lending office for funding or booking its Accommodations hereunder or to assign its rights and obligations hereunder to another of its offices, branches or Affiliates, if, in the judgment of such Lender (with the prior consent of the Borrower), such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Section 13.1 or Section 13.2, as the case may be, in the future and (ii) would not subject such Lender to any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender. The Borrower hereby agrees to pay all reasonable out-of-pocket costs and expenses incurred by any Lender in connection with any such designation or assignment.
(b)
Replacement of Lenders. If any Lender requests compensation under Section 13.1, if the Borrower is required to pay any additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 13.2, if any Lender’s obligations are suspended pursuant to Section 13.4 or if any Lender defaults in its obligation to fund Accommodations hereunder, then the Borrower may either, at its sole expense and effort, upon 10 days’ notice to such Lender and the Agent: (i) repay all outstanding amounts due to such affected Lender (or such portion which has not been acquired pursuant to clause (ii) below) and thereupon such Commitment of the affected Lender shall be permanently cancelled and the aggregate Commitment shall be permanently reduced by the same amount and the Commitment of each of the other Lenders shall remain the same; or (ii) require such Lender to assign, without recourse (in accordance with and subject to the restrictions contained in, and consents required by, Article 20), all of its interests, rights and obligations under this Agreement and the related Loan Documents to an assignee that shall assume such obligations (which assignee may be another Lender, if a Lender accepts such assignment), provided that:
(i)
the Borrower pays the Agent the assignment fee specified in Section 20.1(b)(vi);
(ii)
the assigning Lender receives payment of an amount equal to the outstanding principal of its Accommodations outstanding and participations in disbursements under Documentary Credits, accrued interest thereon, accrued fees and all other amounts payable to it hereunder and under the other Loan Documents (including any breakage costs and amounts required to be paid under this Agreement as a result of prepayment to a Lender) from the assignee (to the extent of such outstanding principal and accrued interest and fees) or the Borrower (in the case of all other amounts);
(c)
in the case of any such assignment resulting from a claim for compensation under Section 13.1 or payments required to be made pursuant to Section 13.2, such assignment will result in a reduction in such compensation or payments thereafter; and
(d)
such assignment does not conflict with Applicable Law.

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A Lender shall not be required to make any such assignment or delegation if, prior thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the Borrower to require such assignment and delegation cease to apply.
13.4
Illegality.
If any Lender determines that any Applicable Law has made it unlawful, or that any Governmental Authority has asserted that it is unlawful, for any Lender or its applicable lending office to make or maintain any Accommodations, or to determine or charge interest rates based upon any particular rate, then, on notice thereof by such Lender to the Borrower through the Agent, any obligation of such Lender with respect to the activity that is unlawful shall be suspended until such Lender notifies the Agent and the Borrower that the circumstances giving rise to such determination no longer exist. Upon receipt of such notice, the Borrower shall, upon demand from such Lender (with a copy to the Agent), prepay or, if conversion would avoid the activity that is unlawful, convert any Accommodations, or take any necessary steps with respect to any Documentary Credits in order to avoid the activity that is unlawful. Upon any such prepayment or conversion, the Borrower shall also pay accrued interest on the amount so prepaid or converted. Each Lender agrees to designate a different lending office if such designation will avoid the need for such notice and will not, in the good faith judgment of such Lender, otherwise be materially disadvantageous to such Lender.
ARTICLE 14    
RIGHT OF SETOFF
14.1
Right of Setoff.
If an Event of Default has occurred and is continuing, each of the Lenders and each of their respective Affiliates is hereby authorized at any time and from time to time to set off and apply any and all deposits (general or special, time or demand, provisional or final, in whatever currency) at any time held and other obligations (in whatever currency) at any time owing by such Lender or any such Affiliate to or for the credit or the account of any Credit Party against any and all of the obligations of the Borrower or any guarantor now or hereafter existing under this Agreement or any other Loan Document to such Lender, irrespective of whether or not such Lender has made any demand under this Agreement or any other Loan Document and although such obligations of the Credit Party may be contingent or unmatured or are owed to a branch or office of such Lender different from the branch or office holding such deposit or obligated on such indebtedness. The rights of each the Lenders and their respective Affiliates under this Section are in addition to other rights and remedies (including other rights of setoff, consolidation of accounts and bankers’ lien) that the Lenders or their respective Affiliates may have. Each Lender agrees to promptly notify the Borrower and the Agent after any such setoff and application, but the failure to give such notice shall not affect the validity of such setoff and application. If any Affiliate of a Lender exercises any rights under this Section 14.1, it shall share the benefit received in accordance with Section 15.1 as if the benefit had been received by the Lender of which it is an Affiliate.
ARTICLE 15    
SHARING OF PAYMENTS BY LENDERS
15.1
Sharing of Payments by Lenders.

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If any Lender, by exercising any right of setoff or counterclaim or otherwise, obtains any payment or other reduction that might result in such Lender receiving payment or other reduction of a proportion of the aggregate amount of its Accommodations and accrued interest thereon or other obligations hereunder greater than its pro rata share thereof as provided herein, then the Lender receiving such payment or other reduction shall (a) notify the Agent of such fact, and (b) purchase (for cash at face value) participations in the Accommodations outstanding and such other obligations of the other Lenders, or make such other adjustments as shall be equitable, so that the benefit of all such payments shall be shared by the Lenders rateably in accordance with the aggregate amount of principal of and accrued interest on their respective Accommodations outstanding and other amounts owing them, provided that:
(a)
if any such participations are purchased and all or any portion of the payment giving rise thereto is recovered, such participations shall be rescinded and the purchase price restored to the extent of such recovery, without interest;
(b)
the provisions of this Section shall not be construed to apply to (x) any payment made by any Credit Party pursuant to and in accordance with the express terms of this Agreement or (y) any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Accommodations or participations in disbursements under Documentary Credits to any assignee or Participant, other than to any Credit Party or any Affiliate of a Credit Party (as to which the provisions of this Section shall apply); and
(c)
the provisions of this Section shall not be construed to apply to (w) any payment made while no Event of Default has occurred and is continuing in respect of obligations of the Borrower to such Lender that do not arise under or in connection with the Loan Documents, (x) any payment made in respect of an obligation that is secured by a Permitted Lien or that is otherwise entitled to priority over the Borrower’s obligations under or in connection with the Loan Documents, (y) any reduction arising from an amount owing to a Credit Party upon the termination of derivatives entered into between the Credit Party and such Lender, or (z) any payment to which such Lender is entitled as a result of any form of credit protection obtained by such Lender.
The Credit Parties consent to the foregoing and agree, to the extent they may effectively do so under Applicable Law, that any Lender acquiring a participation pursuant to the foregoing arrangements may exercise against each Credit Party rights of setoff and counterclaim and similar rights of Lenders with respect to such participation as fully as if such Lender were a direct creditor of each Credit Party in the amount of such participation.
ARTICLE 16    
AGENT’S CLAWBACK
16.1
Agent’s Clawback.
(a)
Funding by Lenders; Presumption by Agent. Unless the Agent shall have received notice from a Lender prior to the proposed date of any advance of funds that such

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Lender will not make available to the Agent such Lender’s share of such advance, the Agent may assume that such Lender has made such share available on such date in accordance with the provisions of this Agreement concerning funding by Lenders and may, in reliance upon such assumption, make available to the Borrower a corresponding amount. In such event, if a Lender has not in fact made its share of the applicable advance available to the Agent, then the applicable Lender shall pay to the Agent forthwith on demand such corresponding amount with interest thereon, for each day from and including the date such amount is made available to the Borrower to but excluding the date of payment to the Agent, at a rate determined by the Agent in accordance with prevailing banking industry practice on interbank compensation. If such Lender pays such amount to the Agent, then such amount shall constitute such Lender’s Accommodation included in such advance. If the Lender does not do so forthwith, the Borrower shall pay to the Agent forthwith on written demand such corresponding amount with interest thereon at the interest rate applicable to the advance in question. Any payment by the Borrower shall be without prejudice to any claim the Borrower may have against a Lender that has failed to make such payment to the Agent.
(b)
Payments by Borrower; Presumptions by Agent. Unless the Agent shall have received notice from the Borrower prior to the date on which any payment is due to the Agent for the account of any Lender hereunder that the Borrower will not make such payment, the Agent may assume that the Borrower has made such payment on such date in accordance herewith and may, in reliance upon such assumption, distribute the amount due to the Lenders. In such event, if the Borrower has not in fact made such payment, then each of the Lenders severally agrees to repay to the Agent forthwith on demand the amount so distributed to such Lender with interest thereon, for each day from and including the date such amount is distributed to it to but excluding the date of payment to the Agent, at a rate determined by the Agent in accordance with prevailing banking industry practice on interbank compensation.
ARTICLE 17    
AGENCY
17.1
Appointment and Authority.
Each of the Lenders hereby irrevocably appoints the Agent to act on its behalf as the Agent hereunder and under the other Loan Documents and authorizes the Agent to take such actions on its behalf and to exercise such powers as are delegated to the Agent by the terms hereof or thereof, together with such actions and powers as are reasonably incidental thereto. The provisions of this Article are solely for the benefit of the Agent and the Lenders, and no Credit Party shall have rights as a third party beneficiary of any of such provisions.
17.2
Rights as a Lender.
The Person serving as the Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not the Agent and the term “Lender” or “Lenders” shall, unless otherwise expressly indicated or unless the context

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otherwise requires, include the Person serving as the Agent hereunder in its individual capacity. Such Person and its Affiliates may accept deposits from, lend money to, act as the financial advisor or in any other advisory capacity for and generally engage in any kind of business with any Credit Party or any Affiliate thereof as if such Person were not the Agent and without any duty to account to the Lenders.
17.3
Exculpatory Provisions.
(a)
The Agent shall not have any duties or obligations except those expressly set forth herein and in the other Loan Documents. Without limiting the generality of the foregoing, the Agent:
(i)
shall not be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing;
(ii)
shall not have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Loan Documents that the Agent is required to exercise as directed in writing by the Majority Lenders (or such other number or percentage of the Lenders as shall be expressly provided for in the Loan Documents), but the Agent shall not be required to take any action that, in its opinion or the opinion of its counsel, may expose the Agent to liability or that is contrary to any Loan Document or Applicable Law; and
(iii)
shall not, except as expressly set forth herein and in the other Loan Documents, have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrower or any of their Affiliates that is communicated to or obtained by the Person serving as the Agent or any of its Affiliates in any capacity.
(b)
The Agent shall not be liable for any action taken or not taken by it (i) with the consent or at the request of the Majority Lenders (or such other number or percentage of the Lenders as is necessary, or as the Agent believes in good faith is necessary, under the provisions of the Loan Documents) or (ii) in the absence of its own gross negligence or wilful misconduct. The Agent shall be deemed not to have knowledge of any Default unless and until notice describing the Default is given to the Agent by the Borrower or a Lender.
(c)
Except as otherwise expressly specified in this Agreement, the Agent shall not be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement or any other Loan Document, (ii) the contents of any certificate, report or other document delivered hereunder or thereunder or in connection herewith or therewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein or therein or the occurrence of any Default, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement, any other Loan Document or any other agreement, instrument or document or (v) the satisfaction

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of any condition specified in this Agreement, other than to confirm receipt of items expressly required to be delivered to the Agent.
17.4
Reliance by Agent.
The Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing (including any electronic message, Internet or intranet posting or other distribution) believed by it to be genuine and to have been signed, sent or otherwise authenticated by the proper Person. The Agent also may rely upon any statement made to it orally or by telephone and believed by it to have been made by the proper Person, and shall not incur any liability for relying thereon. In determining compliance with any condition hereunder to the making of an Accommodation that by its terms must be fulfilled to the satisfaction of a Lender, the Agent may presume that such condition is satisfactory to such Lender unless the Agent shall have received notice to the contrary from such Lender prior to the making of such Accommodation or the issuance of such Documentary Credit. The Agent may consult with legal counsel (who may be counsel for the Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts.
17.5
Indemnification of Agent.
Each Lender agrees to indemnify the Agent and hold it harmless (to the extent not reimbursed by the Borrower), rateably according to its Applicable Percentage (and not jointly or jointly and severally) from and against any and all losses, claims, damages, liabilities and related expenses, including the fees, charges and disbursements of any counsel, which may be incurred by or asserted against the Agent in any way relating to or arising out of the Loan Documents or the transactions therein contemplated. However, no Lender shall be liable for any portion of such losses, claims, damages, liabilities and related expenses resulting from the Agent’s gross negligence or wilful misconduct.
17.6
Delegation of Duties.
The Agent may perform any and all of its duties and exercise its rights and powers hereunder or under any other Loan Document by or through any one or more sub-agents appointed by the Agent from among the Lenders (including the Person serving as Agent) and their respective Affiliates. The Agent and any such sub-agent may perform any and all of its duties and exercise its rights and powers by or through their respective Related Parties. The provisions of this Article and other provisions of this Agreement for the benefit of the Agent shall apply to any such sub-agent and to the Related Parties of the Agent and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the Credit Facilities provided for herein as well as activities as Agent.
17.7
Replacement of Agent.
(a)
The Agent may at any time give notice of its resignation to the Lenders and the Borrower. Upon receipt of any such notice of resignation, the Majority Lenders shall have the right, with the prior consent of the Borrower, to appoint a successor,

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which shall be a Lender having an office in Toronto, Ontario or Calgary Alberta or an Affiliate of any such Lender with an office in Toronto or Calgary. The Agent may also be removed at any time by the Majority Lenders upon 30 days’ notice to the Agent and the Borrower as long as the Majority Lenders, with the prior consent of the Borrower, appoint and obtain the acceptance of a successor within such 30 days, which shall have an office in Toronto/Calgary, or an Affiliate of any such Lender with an office in Toronto/Calgary.
(b)
If no such successor shall have been so appointed by the Majority Lenders and shall have accepted such appointment within 30 days after the retiring Agent gives notice of its resignation, then the retiring Agent may on behalf of the Lenders, appoint a successor Agent meeting the qualifications specified in Section 17.7(a), provided that if the Agent shall notify the Borrower and the Lenders that no qualifying Person has accepted such appointment, then such resignation shall nonetheless become effective in accordance with such notice and (a) the retiring Agent shall be discharged from its duties and obligations hereunder and under the other Loan Documents (except that in the case of any collateral security held by the Agent on behalf of the Lenders under any of the Loan Documents, the retiring Agent shall continue to hold such collateral security until such time as a successor Agent is appointed); and (b) all payments, communications and determinations provided to be made by, to or through the Agent shall instead be made by or to each Lender directly, until such time as the Majority Lenders appoint a successor Agent as provided for above in the preceding paragraph.
(c)
Upon a successor’s appointment as Agent hereunder, such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the former Agent, and the former Agent shall be discharged from all of its duties and obligations hereunder or under the other Loan Documents (if not already discharged therefrom as provided in the preceding paragraph). The fees payable by the Borrower to a successor Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor. After the termination of the service of the former Agent, the provisions of this ARTICLE 17 and of ARTICLE 19 shall continue in effect for the benefit of such former Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while the former Agent was acting as Agent.
17.8
Non-Reliance on Agent and Other Lenders.
Each Lender acknowledges that it has, independently and without reliance upon the Agent or any other Lender or any of their Related Parties and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Agent or any other Lender or any of their Related Parties and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any other Loan Document or any related agreement or any document furnished hereunder or thereunder.

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17.9
Collective Action of the Lenders.
Each of the Lenders hereby acknowledges that to the extent permitted by Applicable Law, any collateral security and the remedies provided under the Loan Documents to the Lenders are for the benefit of the Lenders collectively and acting together and not severally and further acknowledges that its rights hereunder and under any collateral security are to be exercised not severally, but by the Agent upon the decision of the Majority Lenders (or such other number or percentage of the Lenders as shall be expressly provided for in the Loan Documents). Accordingly, notwithstanding any of the provisions contained herein or in any collateral security, each of the Lenders hereby covenants and agrees that it shall not be entitled to take any action hereunder or thereunder including, without limitation, any declaration of default hereunder or thereunder but that any such action shall be taken only by the Agent with the prior written agreement of the Majority Lenders (or such other number or percentage of the Lenders as shall be expressly provided for in the Loan Documents). Each of the Lenders hereby further covenants and agrees that upon any such written agreement being given, it shall co-operate fully with the Agent to the extent requested by the Agent. Notwithstanding the foregoing, in the absence of instructions from the Lenders and where in the sole opinion of the Agent, acting reasonably and in good faith, the exigencies of the situation warrant such action, the Agent may without notice to or consent of the Lenders take such action on behalf of the Lenders as it deems appropriate or desirable in the interest of the Lenders.
17.10
No Other Duties, etc.
Anything herein to the contrary notwithstanding, none of the bookrunners, arrangers or holders of similar titles, if any, specified in this Agreement shall have any powers, duties or responsibilities under this Agreement or any of the other Loan Documents, except in its capacity, as applicable, as the Agent or a Lender hereunder.
ARTICLE 18    
NOTICES: EFFECTIVENESS; ELECTRONIC COMMUNICATION
18.1
Notices, etc.
(a)
Notices Generally. Except in the case of notices and other communications expressly permitted to be given by telephone (and except as-provided in paragraph (b) below), all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by facsimile or telecopier to the addresses or facsimile or telecopier numbers specified elsewhere in this Agreement or, if to a Lender, to it at its address or telecopier number specified in the Register or, if to a Credit Party other than the Borrower, in care of the Borrower.
Notices sent by hand or overnight courier service, or mailed by certified or registered mail, shall be deemed to have been given when received; notices sent by facsimile or telecopier shall be deemed to have been given when sent (except that, if not given on a Business Day between 9:00 a.m. and 5:00 p.m. local time where the recipient is located, shall be deemed to have been given at 9:00 a.m. on the next Business Day for the recipient). Notices delivered

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through electronic communications to the extent provided in paragraph (b) below, shall be effective as provided in said paragraph (b).
(b)
Electronic Communications. Notices and other communications to the Lenders hereunder may be delivered or furnished by electronic communication (including e-mail and Internet or intranet websites) pursuant to procedures approved by the Agent, provided that the foregoing shall not apply to notices to any Lender if such Lender has notified the Agent that it is incapable of receiving notices under such Article by electronic communication. The Agent or the Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it, provided that approval of such procedures may be limited to particular notices or communications.
Unless the Agent otherwise prescribes, (i) notices and other communications sent to an e-mail address shall be deemed received upon the sender’s receipt of an acknowledgement from the intended recipient (such as by the “return receipt requested” function, as available, return e-mail or other written acknowledgement), provided that if such notice or other communication is not sent during the normal business hours of the recipient, such notice or communication shall be deemed to have been sent at the opening of business on the next Business Day for the recipient, and (ii) notices or communications posted to an Internet or intranet website shall be deemed received upon the deemed receipt by the intended recipient at its e-mail address as described in the foregoing clause (i) of notification that such notice or communication is available and identifying the website address therefor.
(c)
Change of Address, Etc. Any party hereto may change its address or telecopier number for notices and other communications hereunder by notice to the other parties hereto.
18.2
Notice Details
For purposes of Section 18.1, the notice details for the Agent, the Borrower and the General Partner are:
If to the Agent:
Royal Bank of Canada
20 King Street West, 4
th Floor
Toronto, ON M5H 1C4


Attention:    Manager Agency
Facsimile:    (416) 842-4023
Email:    rbcmagnt@rbccm.com

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If to the Borrower and/or the General Partner:
AltaLink Management Ltd.
2611 - 3rd Avenue SE
Calgary, Alberta T2A 7W7

Attention:    Christopher Lomore, Vice President, Treasurer
Facsimile:    (403) 267-3407
ARTICLE 19    
EXPENSES; INDEMNITY: DAMAGE WAIVER
19.1
Expenses; Indemnity: Damage Waiver.
(a)
Costs and Expenses. The Borrower shall pay (i) all reasonable out-of-pocket expenses incurred by the Agent and its Affiliates, including the reasonable fees, charges and disbursements of counsel for the Agent, in connection with the preparation, negotiation, execution, delivery and administration of this Agreement and the other Loan Documents or any amendments, modifications or waivers of the provisions hereof or thereof (whether or not the transactions contemplated hereby or thereby shall be consummated), and (ii) all reasonable out-of-pocket expenses incurred by the Agent or any Lender including the reasonable fees, charges and disbursements of counsel, in connection with the enforcement or protection of its rights in connection with this Agreement and the other Loan Documents, including its rights under this Section, or in connection with the Accommodations issued hereunder, including all such out-of-pocket expenses incurred during any workout, restructuring or negotiations in respect of such Accommodations.
(b)
Indemnification by the Borrower. The Borrower shall indemnify the Agent (and any sub-agent thereof), each Lender, and each Related Party of any of the foregoing Persons (each such Person being called an “Indemnitee”) against, and hold each Indemnitee harmless from, any and all losses, claims, damages, liabilities and related expenses, including the fees, charges and disbursements of any counsel for any Indemnitee, incurred by any Indemnitee or asserted against any Indemnitee by any third party or by any Credit Party arising out of, in connection with, or as a result of (i) the execution or delivery of this Agreement, any other Loan Document or any agreement or instrument contemplated hereby or thereby, the performance or non-performance by the parties hereto of their respective obligations hereunder or thereunder or the consummation or non-consummation of the transactions contemplated hereby or thereby, (ii) any Accommodation or the use or proposed use of the proceeds therefrom (including any refusal by the Documentary Credit Lender to honour a demand for payment under a Documentary Credit if the documents presented in connection with such demand do not strictly comply with the terms of such Documentary Credit), (iii) any actual or alleged presence or Release of Hazardous Substance on or from any property owned or operated by any Credit Party, or any Environmental Liabilities related in any way to any Credit Party, or (iv) any actual or prospective claim, litigation, investigation or proceeding relating

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to any of the foregoing, whether based on contract, tort or any other theory, whether brought by a third party or by a Credit Party and regardless of whether any Indemnitee is a party thereto, provided that such indemnity shall not, as to any Indemnitee, be available to the extent that such losses, claims, damages, liabilities or related expenses (x) are determined by a court of competent jurisdiction by final and nonappealable judgment to have resulted from the gross negligence or wilful misconduct of such Indemnitee or (y) result from a claim brought by the Borrower or any other Credit Party against an Indemnitee for breach of such Indemnitee’s obligations hereunder or under any other Loan Document, if the Credit Party has obtained a final and nonappealable judgment in its favour on such claim as determined by a court of competent jurisdiction, nor shall it be available in respect of matters specifically addressed in Section 13.1, Section 13.2 and Section 19.1(a).
(c)
Reimbursement by Lenders. To the extent that a Borrower for any reason fails to indefeasibly pay any amount required under paragraph (a) or (b) of this Section to be paid by it to the Agent (or any sub-agent thereof) or any Related Party of any of the foregoing, each Lender severally agrees to pay to the Agent (or any such sub-agent) or such Related Party, as the case may be, such Lender’s Applicable Percentage (determined as of the time that the applicable unreimbursed expense or indemnity payment is sought) of such unpaid amount, provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against the Agent (or any such sub-agent) in its capacity as such, or against any Related Party of any of the foregoing acting for the Agent (or any such sub-agent) in connection with such capacity. The obligations of the Lenders under this paragraph (a) are subject to the other provisions of this Agreement concerning several liability of the Lenders.
(d)
Waiver of Consequential Damages, Etc. To the fullest extent permitted by Applicable Law, the Credit Parties shall not assert, and hereby waive, any claim against any Indemnitee, on any theory of liability, for indirect, consequential, punitive, aggravated or exemplary damages (as opposed to direct damages) arising out of, in connection with, or as a result of, this Agreement, any other Loan Document or any agreement or instrument contemplated hereby (or any breach thereof), the transactions contemplated hereby or thereby, any Accommodation or the use of the proceeds thereof. No Indemnitee shall be liable for any damages arising from the use by unintended recipients of any information or other materials distributed by it through telecommunications, electronic or other information transmission systems in connection with this Agreement or the other Loan Documents or the transactions contemplated hereby or thereby.
(e)
Payments. All amounts due under this Section shall be payable promptly after demand therefor with documented particulars thereof. A certificate of the Agent or a Lender setting forth the amount or amounts owing to the Agent, Lender or a sub-agent or Related Party, as the case may be, as specified in this Section, including reasonable detail of the basis of calculation of the amount or amounts, and delivered to the Borrower shall be conclusive absent manifest error.

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ARTICLE 20    
SUCCESSORS AND ASSIGNS
20.1
Successors and Assigns.
(a)
Successors and Assigns Generally. The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby, except that no Credit Party may assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of the Agent and each Lender and no Lender may assign or otherwise transfer any of its rights or obligations hereunder except (i) to an Eligible Assignee in accordance with the provisions of paragraph (b) of this Section, (ii) by way of participation in accordance with the provisions of paragraph (d) of this Section, or (iii) by way of pledge or assignment of a security interest subject to the restrictions of paragraph (f) of this Section (and any other attempted assignment or transfer by any party hereto shall be null and void). Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby, Participants to the extent provided in paragraph (d) of this Section and, to the extent expressly contemplated hereby, the Related Parties of each of the Agent and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.
(b)
Assignments by Lenders. Any Lender may at any time assign to one or more Eligible Assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and the Accommodations outstanding at the time owing to it); provided that:
(i)
except if an Event of Default has occurred and is continuing or in the case of an assignment of the entire remaining amount of the assigning Lender’s Commitment and the Accommodations outstanding at the time owing to it or in the case of an assignment to a Lender or an Affiliate of a Lender or an Approved Fund with respect to a Lender, the aggregate amount of the Commitment being assigned (which for this purpose includes Accommodations outstanding thereunder) or, if the applicable Commitment is not then in effect, the principal outstanding balance of the Accommodations outstanding of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Agent or, if “Trade Date” is specified in the Assignment and Assumption, as of the Trade Date) shall not be less than $10,000,000, unless each of the Agent and, so long as no Event of Default has occurred and is continuing, the Borrower otherwise consent to a lower amount;
(ii)
each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement with respect to the Accommodations outstanding or the Commitment assigned, except that this clause (ii) shall not prohibit any Lender from

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assigning all or a portion of its rights and obligations among separate credits on a non-pro rata basis;
(iii)
any assignment must be approved by the Documentary Credit Lender (such approval not to be unreasonably withheld or delayed) unless the Person that is the proposed assignee is itself already a Lender;
(iv)
any assignment must be approved by the Agent (such approval not to be unreasonably withheld or delayed) unless the proposed assignee is a bank whose senior, unsecured, non-credit enhanced, long term debt is rated at least A3, A- or A low by at least two of Moodys, S&P and DBRS, respectively;
(v)
any assignment must be approved by the Borrower (such approval not to be unreasonably withheld or delayed) unless the proposed assignee is itself already a Lender or if an Event of Default has occurred and is continuing; and no assignment will be made to a Foreign Lender unless an Event of Default has occurred and is continuing; and
(vi)
the parties to each assignment shall execute and deliver to the Agent an Assignment and Assumption, together with a processing and recordation fee of Cdn $3,500 and the Eligible Assignee, if it shall not be a Lender, shall deliver to the Agent an Administrative Questionnaire.
Subject to acceptance and recording thereof by the Agent pursuant to clause (iv) of this paragraph (b), from and after the effective date specified in each Assignment and Assumption, the Eligible Assignee thereunder shall be a party to this Agreement with respect to the interest assigned and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement and the other Loan Documents, including any collateral security, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto) but shall continue to be entitled to the benefits of ARTICLE 13 and ARTICLE 19, and shall continue to be liable for any breach of this Agreement by such Lender, with respect to facts and circumstances occurring prior to the effective date of such assignment. Any payment by an assignee to an assigning Lender in connection with an assignment or transfer shall not be or be deemed to be a repayment by the Borrower or a new Accommodations to the Borrower.
(c)
Register. The Agent shall maintain at one of its offices in Toronto, Ontario a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitments of, and principal amounts of the Accommodations outstanding owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive, absent manifest error, and the Borrower, the Agent and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to

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the contrary. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.
(d)
Participations. Any Lender may at any time, without the consent of, or notice to, any Borrower or the Agent, sell participations to any Person (other than a natural person, a Credit Party or any Affiliate of a Credit Party ) (each, a “Participant”) in all or a portion of such Lender’s rights and/or obligations under this Agreement (including all or a portion of its Commitment and/or the Accommodations outstanding owing to it); provided that (i) such Lender’s obligations under this Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (iii) the Borrower, the Agent and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. Any payment by a Participant to a Lender in connection with a sale of a participation shall not be or be deemed to be a repayment by the Borrower or a new Loan to the Borrower.
Subject to paragraph (e) of this Section, the Borrower agrees that each Participant shall be entitled to the benefits of ARTICLE 13 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to paragraph (b) of this Section. To the extent permitted by Law, each Participant also shall be entitled to the benefits of ARTICLE 13 as though it were a Lender, provided such Participant agrees to be subject to ARTICLE 15 as though it were a Lender.
(e)
Limitation on Participants Rights. A Participant shall not be entitled to receive any greater payment under Section 13.1 and Section 13.2 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrower’s prior written consent. A Participant that would be a Foreign Lender if it were a Lender shall not be entitled to the benefits of Section 13.2.
(f)
Certain Pledges. Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, but no such pledge or assignment shall release such Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.
ARTICLE 21    
AMENDMENTS AND WAIVERS
21.1
Amendments and Waivers.
(a)
Subject to subsections (b) and (c), no acceptance, amendment or waiver of any provision of any of the Loan Documents, nor consent to any departure by the Borrower or any other Person from such provisions, shall be effective unless in writing and approved by the Majority Lenders. Any acceptance, amendment, waiver

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or consent shall be effective only in the specific instance and for the specific purpose for which it was given.
(b)
Only written acceptances, amendments, waivers or consents signed by all the Lenders shall (i) increase a Lender’s Commitment; (ii) reduce the principal or amount of, or interest on, directly or indirectly, any Accommodation outstanding or any fees; (iii) postpone any date fixed for any payment of principal of, or interest on, any Accommodation outstanding or any fees; (iv) change the percentage of the Commitments or the number or percentage of Lenders required for the Lenders, or any of them, or the Agent to take any action; (v) change the definition of Majority Lenders; (vi) release or cancel any security for any obligation of a Credit Party hereunder; or (vii) amend this Section 21.1(b).
(c)
Only written acceptances, amendments, waivers or consents signed by the Agent, in addition to the Majority Lenders, shall affect the rights or duties of the Agent under the Loan Documents.
21.2
Judgment Currency.
(a)
If, for the purposes of obtaining judgment in any court, it is necessary to convert a sum due to a Lender in any currency (the “Original Currency”) into another currency (the “Other Currency”), the parties agree, to the fullest extent that they may effectively do so, that the rate of exchange used shall be that at which, in accordance with normal banking procedures, such Lender could purchase the Original Currency with the Other Currency on the Business Day preceding the day on which final judgment is given or, if permitted by Applicable Law, on the day on which the judgment is paid or satisfied.
(b)
The obligations of the Borrower in respect of any sum due in the Original Currency from it to any Lender under any of the Loan Documents shall, notwithstanding any judgment in any Other Currency, be discharged only to the extent that on the Business Day following receipt by the Lender of any sum adjudged to be so due in the Other Currency, the Lender may, in accordance with normal banking procedures, purchase the Original Currency with such Other Currency. If the amount of the Original Currency so purchased is less than the sum originally due to the Lender in the Original Currency, the Borrower agrees, as a separate obligation and notwithstanding the judgment, to indemnify the Lender, against any loss, and, if the amount of the Original Currency so purchased exceeds the sum originally due to the Lender in the Original Currency, the Lender shall remit such excess to the Borrower.
ARTICLE 22    
GOVERNING LAW; JURISDICTION; ETC.
22.1
Governing Law; Jurisdiction; Etc.

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(a)
Governing Law. This Agreement shall be governed by, and construed in accordance with, the laws of the Province of Alberta and the laws of Canada applicable in that Province.
(b)
Submission to Jurisdiction. Each Credit Party irrevocably and unconditionally submits, for itself and its property, to the nonexclusive jurisdiction of the courts of the Province of Alberta, and any appellate court from any thereof, in any action or proceeding arising out of or relating to this Agreement or any other Loan Document, or for recognition or enforcement of any judgment, and each of the parties hereto irrevocably and unconditionally agrees that all claims in respect of any such action or proceeding may be heard and determined in such court. Each of the parties hereto agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Agreement or in any other Loan Document shall affect any right that the Agent or any Lender may otherwise have to bring any action or proceeding relating to this Agreement or any other Loan Document against any Credit Party or its properties in the courts of any jurisdiction.
(c)
Waiver of Venue. Each Credit Party irrevocably and unconditionally waives, to the fullest extent permitted by Applicable Law, any objection that it may now or hereafter have to the laying of venue of any action or proceeding arising out of or relating to this Agreement or any other Loan Document in any court referred to in paragraph (b) of this Section. Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by Applicable Law, the defence of an inconvenient forum to the maintenance of such action or proceeding in any such court.
ARTICLE 23    
WAIVER OF JURY TRIAL
23.1
Waiver of Jury Trial.
EACH PARTY HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PERSON HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PERSON WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.
ARTICLE 24    
COUNTERPARTS; INTEGRATION; EFFECTIVENESS; ELECTRONIC EXECUTION

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24.1
Counterparts; Integration; Effectiveness; Electronic Execution.
(a)
Counterparts; Integration; Effectiveness. This Agreement may be executed in counterparts (and by different parties hereto in different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. This Agreement shall become effective when it has been executed by the Agent and when the Agent has received counterparts hereof that, when taken together, bear the signatures of each of the other parties hereto. Delivery of an executed counterpart of a signature page of this Agreement by telecopy or by sending a scanned copy by electronic mail shall be effective as delivery of a manually executed counterpart of this Agreement.
(b)
Electronic Execution of Assignments. The words “execution,” “signed,” “signature,” and words of like import in any Assignment and Assumption shall be deemed to include electronic signatures or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any Applicable Law, including Parts 2 and 3 of the Personal Information Protection and Electronic Documents Act (Canada), the Electronic Transactions Act, (Alberta), the Personal Information Protection Act (Alberta) and other similar federal or provincial laws based on the Uniform Electronic Commerce Act of the Uniform Law Conference of Canada or its Uniform Electronic Evidence Act, as the case may be.
ARTICLE 25    
TREATMENT OF CERTAIN INFORMATION: CONFIDENTIALITY
25.1
Treatment of Certain Information: Confidentiality.
(a)
Each of the Agent and the Lenders agrees to maintain the confidentiality of the Information (as defined below), except that Information may be disclosed (a) to it, its Affiliates and its and its Affiliates’ respective partners, directors, officers, employees, agents, advisors and representatives (to the extent necessary to administer or enforce this Agreement and the other Loan Documents) (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Information and instructed to keep such Information confidential), (b) to the extent requested by any regulatory authority having jurisdiction over it (including any self-regulatory authority), (c) to the extent required by Applicable Laws or similar legal process, (d) to any other party hereto, (e) in connection with the exercise of any remedies hereunder or under any other Loan Document or any action or proceeding relating to this Agreement or any other Loan Document or the enforcement of rights hereunder or thereunder, (f) subject to an agreement containing provisions substantially the same as those of this Section, to (i) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights or obligations under this Agreement or (ii) any actual or prospective counterparty (or its advisors) to any swap, derivative, credit-linked note or similar transaction relating to the Borrower and its obligations, (g) with the consent of the

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Borrower or (h) to the extent such Information (x) becomes publicly available other than as a result of a breach of this Section by such Person or actually known to such Person or (y) becomes available to the Agent or any Lender on a non-confidential basis from a source other than a Credit Party. If the Agent or any Lender is requested or required to disclose any Information (other than by any bank examiner) pursuant to or as required by Applicable Laws or by a subpoena or similar legal process, the Agent or such Lender, as applicable, shall use its reasonable commercial efforts to provide the Borrower with notice of such requests or obligation in sufficient time so that the Borrower may seek an appropriate protective order or waive the Agent’s, or such Lender’s, as applicable, compliance with the provisions of this Section, and the Agent and such Lender, as applicable, shall, to the extent reasonable, co-operate with the Borrower in the Borrower obtaining any such protective order.
(b)
For purposes of this Section, “Information” means all information received from any Credit Party relating to any Credit Party or any of its Subsidiaries or any of their respective businesses, other than any such information that is available to the Agent or any Lender on a non-confidential basis prior to such receipt. Any Person required to maintain the confidentiality of Information as provided in this Section shall be considered to have complied with its obligation to do so if such Person has exercised the same degree of care to maintain the confidentiality of such Information as such Person would accord to its own confidential information. In addition, the Agent may disclose to any agency or organization that assigns standard identification numbers to loan facilities such basic information describing the facilities provided hereunder as is necessary to assign unique identifiers (and, if requested, supply a copy of this Agreement), it being understood that the Person to whom such disclosure is made will be informed of the confidential nature of such Information and instructed to make available to the public only such Information as such Person normally makes available in the course of its business of assigning identification numbers.
(c)
In addition, and notwithstanding anything herein to the contrary, the Agent may provide basic information concerning the Borrower and the Credit Facilities established herein to Loan Pricing Corporation and/or other recognized trade publishers of information for general circulation in the loan market.
ARTICLE 26    
MISCELLANEOUS
26.1
Further Assurances
The Borrower shall, from time to time forthwith upon reasonable request by the Agent do, make and execute all such documents, acts, matters and things as may be required by the Agent to give effect to this Agreement and any of the Loan Documents.
26.2
Acknowledgement
The Borrower is a limited partnership formed under the Partnership Act (Alberta), a limited partner of which is only liable for any of its liabilities or any of its losses to the extent of the amount that

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such limited partner has contributed or agreed to contribute to its capital and such limited partner’s pro rate share of any undistributed income.
[SIGNATURE PAGES FOLLOW]
IN WITNESS OF WHICH the parties hereto have duly executed this Agreement as of the date set forth on the first page of this Agreement.
 
 
ALTALINK INVESTMENT MANAGEMENT LTD., as general partner of ALTALINK INVESTMENTS, L.P.
By:
/s/ Calvin Haack
 
Name: Calvin Haack
 
Title: Director
By:
/s/ Jeffrey A. Austin
 
Name: Jeffrey A. Austin
 
Title: Director

 
 
ALTALINK INVESTMENT MANAGEMENT LTD.
By:
/s/ Calvin Haack
 
Name: Calvin Haack
 
Title: Director
By:
/s/ Jeffrey A. Austin
 
Name: Jeffrey A. Austin
 
Title: Director


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement




 
 
ROYAL BANK OF CANADA, as Agent
By:
/s/ Yvonne Brazier
 
Name: Yvonne Brazier
 
Title: Manager, Agency Services
 
 
By:
 
 
 
 
Name:
 
 
 
Title:


 
 
ROYAL BANK OF CANADA, as Lender
By:
/s/ Timothy P. Murray
 
Name: Timothy P. Murray
 
Title: Authorized Signatory
 
 
By:
 
 
 
 
Name:
 
 
 
Title:


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement




 
 
BANK OF MONTREAL, as Lender
By:
/s/ Carol McDonald
 
Name: Carol McDonald
 
Title: Managing Director
 
 
By:
/s/ McKenzie Mantei
 
 
 
Name: McKenzie Mantei
 
 
 
Title: Analyst


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement




 
 
ATB Financial, as Lender
By:
/s/ Trevor Guinard
 
Name: Director
 
Title: Portfolio Manager


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement




 
 
BANK OF NOVA SCOTIA, as Lender
By:
/s/ Kirt Millwood
 
Name: Kirt Millwood
 
Title: Managing Director
 
 
By:
/s/ Matthew Hartnoll
 
 
 
Name: Matthew Hartnoll
 
 
 
Title: Director


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement




 
 
NATIONAL BANK OF CANADA, as Lender
By:
/s/ James Dexter
 
Name: James Dexter
 
Title: Authorized Signatory
 
 
By:
/s/ Chuck Warnica
 
 
 
Name: Chuck Warnica
 
 
 
Title: Authorized Signatory


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



SCHEDULE 1
BORROWER’S CERTIFICATE OF COMPLIANCE
TO:    Royal Bank of Canada (“RBC”), as Agent for the Lenders, under the Credit Agreement
This Certificate is delivered to you pursuant to the amended and restated credit agreement made as of January 24, 2020 (as amended, restated or replaced from time to time, the “Credit Agreement”) between AltaLink Investments, L.P., AltaLink Investment Management Ltd. and RBC, as Agent and Lender and the other Lenders party thereto. Capitalized terms used in this Certificate and not otherwise defined have the meanings given in the Credit Agreement.
The undersigned has read the provisions of the Credit Agreement which are relevant to the furnishing of this Certificate. The undersigned has made such examination and investigation as was, in the opinion of the undersigned, necessary to enable the undersigned to express an informed opinion on the matters set out herein.
The undersigned hereby certifies that as of the date hereof:
1.
Representations and Warranties. All representations and warranties of the Borrower and the General Partner contained in the Credit Agreement are true and correct in all material respects as if made on and as of the date hereof, except as set out in Appendix I hereto or otherwise notified to the Agent under the Credit Agreement.
2.
Default/Event of Default. No Default or Event of Default under the Credit Agreement has occurred and is continuing.
3.
Financial Covenants. The Borrower is in compliance with the financial covenants set forth in Section 10.24 of the Credit Agreement and the detailed calculations evidencing such compliance are attached hereto.
4.
Ratings. [The ratings assigned by each of the Rating Agencies to the Senior Bonds, Series 13-1 is: l, and the Senior Bonds, Series 15-1 is l.]
5.
Change of Control Compliance. Pursuant to Section 10.16 of the Credit Agreement, the total revenues and total Assets of all non-wholly-owned Subsidiaries of the Borrower does not exceed 10% of the Borrower’s consolidated revenues or Consolidated Assets, as disclosed in the most recent audited financial statements delivered to the Agent and the Lenders.

[SIGNATURE PAGE FOLLOWS]

RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



DATED this ________ day of _________________, 20____.
 
 
ALTALINK INVESTMENT
MANAGEMENT LTD., as general partner of ALTALINK INVESTMENTS, L.P.
By:
 
 
Name:
 
Title:
By:
 
 
Name:
 
Title:

 
 
ALTALINK INVESTMENT
MANAGEMENT LTD.
By:
 
 
Name:
 
Title:
By:
 
 
Name:
 
Title:



RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



APPENDIX I
EXCEPTIONS AND QUALIFICATIONS TO
BORROWER’S CERTIFICATE OF COMPLIANCE




RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



SCHEDULE 2(A)
BORROWING NOTICE
Royal Bank of Canada
Agency Services Group
200 Bay Street
Royal Bank Plaza
12th Floor
Toronto, ON M5J 2W7

Attention:    Manager Agency
Facsimile:    (416) 842-4023

The Lenders under the Credit Agreement
Dear Sirs:
You are hereby notified that the undersigned, intends to avail itself of the Credit Facility established in its favour pursuant to the amended and restated credit agreement made as of January 24, 2020 (as amended, restated or replaced from time to time, the “Credit Agreement”) between AltaLink Investments, L.P., as Borrower, AltaLink Investment Management Ltd. and Royal Bank of Canada, as Agent and Lender, and the other Lenders which become a party thereto. Capitalized terms used in this Borrowing Notice and not otherwise defined have the meanings given in the Credit Agreement.
The undersigned hereby irrevocably requests a Borrowing as follows:
(a)
Prime Rate Loan in the amount of Cdn.$l, having a term of l [add same provision for any other amount and term requested];
(b)
U.S. Base Rate Loan in the amount of U.S.$l, having a term of l [add same provision for any other amount and term requested];
(c)
LIBOR Loan in the amount of U.S.$l, having a term and LIBOR Interest Period of l [add same provision for any other amount and term requested]; and
(d)
Bankers’ Acceptance in the aggregate amount of Cdn.$l having a term of l [add same provision for any other amount and term requested].
All Loans made pursuant to this Notice of Borrowing shall be credited to the undersigned’s account no. l at [insert account details]. In the case of a Bankers’ Acceptance or Documentary Credit, it shall be delivered to l. The requested Borrowing Date is l. [If the undersigned requires a bank draft to be issued by RBC as a debit to the undersigned account at the Borrower’s designated

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account and to be delivered on the undersigned’s behalf, add an irrevocable direction to that effect, specifying the Person to whom it is to be delivered.]
All representations and warranties of the Borrower contained in the Credit Agreement are true and correct in all material respects as if made on and as of the date hereof.
No Default or Event of Default under the Credit Agreement has occurred and is continuing.
DATED this _____ day _______________________ 20    __.

 
 
ALTALINK INVESTMENT MANAGEMENT LTD., as general partner of ALTALINK INVESTMENTS, L.P.
 
 
By:
 
 
Name:
 
Title:
 
 
By:
 
 
Name:
 
Title:


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



SCHEDULE 2(B)
NOTICE OF ROLL OVER
Royal Bank of Canada
Agency Services Group
200 Bay Street
Royal Bank Plaza
12th Floor
Toronto, ON M5J 2W7

Attention:    Manager Agency
Facsimile:    (416) 842-4023

The Lenders under the Credit Agreement
Dear Sirs:
We refer to Section 2.5 of the amended and restated credit agreement made as of January 24, 2020 (as amended, restated or replaced from time to time, the “Credit Agreement”) between AltaLink Investments, L.P., as Borrower, AltaLink Investment Management Ltd. and Royal Bank of Canada, as Agent and Lender, and the other Lenders which become a party thereto. Capitalized terms used in this Notice and not otherwise defined have the meanings given in the Credit Agreement.
The Borrower hereby confirms that:
(a)
it intends to repay the following Bankers’ Acceptances on the current maturity date:
(i)
aggregate Face Amount - $; and
(ii)
current maturity date _____________; and
(b)
the following Bankers’ Acceptances are to be rolled over in accordance with the Credit Agreement by the issuance of new Bankers’ Acceptances on the current maturity date specified below:
(i)
aggregate Face Amount of maturing Bankers’ Acceptances - $;
(ii)
current maturity date - ______________;
(iii)
new aggregate Face Amount - $    ;
(iv)
new Contract Period - _______________; and
(v)
new maturity date - ________________.

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The Borrower hereby represents and warrants that the conditions contained in the Credit Agreement have been satisfied and will be satisfied as of the date hereof and before and after giving effect to such roll over on the applicable roll over date.
DATED this     day             , 20    .
 
 
ALTALINK INVESTMENT MANAGEMENT LTD., as general partner of ALTALINK INVESTMENTS, L.P.
By:
 
 
Name:
 
Title:
By:
 
 
Name:
 
Title:


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



SCHEDULE 2(C)
CONVERSION OPTION NOTICE
Royal Bank of Canada
Agency Services Group
200 Bay Street
Royal Bank Plaza
12th Floor
Toronto, ON M5J 2W7

Attention:    Manager Agency
Facsimile:    (416) 842-4023

The Lenders under the Credit Agreement

Dear Sirs:
We refer to Section 2.5 of the amended and restated credit agreement made as of January 24, 2020 (as amended, restated or replaced from time to time, the “Credit Agreement”) between AltaLink Investments, L.P., as Borrower, AltaLink Investment Management Ltd. and Royal Bank of Canada, as Agent and Lender, and the other Lenders which become a party thereto. Capitalized terms used in this Notice and not otherwise defined have the meanings given in the Credit Agreement.
Pursuant to the Credit Agreement, we hereby give notice of our irrevocable request for a conversion of Advances in the amount of $______________ outstanding by way of [insert type of Loan] into corresponding Borrowings by way of [insert new type of Loan] on the _________ day of ___________, 20___. [The Contract Period for the new Bankers’ Acceptances shall be ________ with a new maturity date of ____________, 20____.][The term of the new [insert new type of Loan] shall be ________ with a new maturity date of ____________, 20____.]
The Borrower hereby represents and warrants that the conditions contained in the Credit Agreement have been satisfied and will be satisfied as of the date hereof and before and after giving effect to such conversion on the applicable conversion date.
DATED this         day             , 20____.
 
 
ALTALINK INVESTMENT MANAGEMENT LTD., as general partner of ALTALINK INVESTMENTS, L.P.
By:
 
 
Name:
 
Title:
 
 
By:
 
 
Name:
 
Title:


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



SCHEDULE 3
NOTICE OF EXTENSION
Royal Bank of Canada
Agency Services Group
200 Bay Street
Royal Bank Plaza
12th Floor
Toronto, ON M5J 2W7


Attention:    Manager Agency
Facsimile:    (416) 842-4023


Dear Sirs:
You are hereby notified that the undersigned wishes to extend the Maturity Date of each Lender for a three hundred and sixty-five (365) day period. Capitalized terms used in this Notice of Extension and not otherwise defined have the meanings given in the amended and restated credit agreement made as of January 24, 2020 between AltaLink Investments L.P., as Borrower, AltaLink Investment Management Ltd. and Royal Bank of Canada, as Agent and Lender, and the other Lenders party thereto, as amended, restated or replaced from time to time.
DATED this          day of             , 20    .

 
 
ALTALINK INVESTMENT MANAGEMENT LTD., as general partner of ALTALINK INVESTMENTS, L.P.
 
 
By:
 
 
Name:
 
Title:
 
 
By:
 
 
Name:
 
Title:




RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



SCHEDULE 4
FORM OF ISSUE NOTICE
[Date]
Royal Bank of Canada
Agency Services Group
200 Bay Street
Royal Bank Plaza
12th Floor
Toronto, ON M5J 2W7


Attention:    Manager Agency
Facsimile:    (416) 842-4023


Ladies and Gentlemen:
We refer to Section 3.2 of the amended and restated credit agreement made as of January 24, 2020 (as amended, restated or replaced from time to time, the “Credit Agreement”) between AltaLink Investments, L.P., as Borrower, AltaLink Investment Management Ltd. and Royal Bank of Canada, as Agent and Lender, and the other Lenders which become a party thereto. Capitalized terms used in this Notice and not otherwise defined have the meanings given in the Credit Agreement.
The undersigned hereby gives you notice pursuant to Section 3.2 of the Credit Agreement that the Borrower hereby requests an Issue under the Credit Agreement, and, in that connection, sets forth below the information relating to such Issue as required by Section 3.2 of the Credit Agreement:
(a)
The date of Issue, being a Business Day, is l.
(b)
The Face Amount of such Documentary Credit is Cdn $l/US$l .
(c)
The expiration date of such Documentary Credit, being a Business Day is l.
(d)
The proposed type of Documentary Credit is [letter of credit][letter of guarantee].
(e)
The name and address of the Beneficiary is l.

RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement

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(f)
[Insert any special terms or conditions for the Documentary Credit.]
Yours truly,
 
 
ALTALINK INVESTMENT MANAGEMENT LTD., as general partner of ALTALINK INVESTMENTS, L.P.
 
 
By:
 
 
Name:
 
Title:
 
 
By:
 
 
Name:
 
Title:


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



SCHEDULE 5
ASSIGNMENT AND ASSUMPTION
This Assignment and Assumption (the “Assignment and Assumption”) is dated as of the Effective Date set forth below and is entered into by and between [Insert name of Assignor] (the “Assignor”) and [Insert name of Assignee] (the “Assignee”). Capitalized terms used but not defined herein shall have the meanings given to them in the Credit Agreement identified below (as amended, the “Credit Agreement”), receipt of a copy of which is hereby acknowledged by the Assignee. The Standard Terms and Conditions set forth in Annex 1 attached hereto are hereby agreed to and incorporated herein by reference and made a part of this Assignment and Assumption as if set forth herein in full.
For an agreed consideration, the Assignor hereby irrevocably sells and assigns to the Assignee, and the Assignee hereby irrevocably purchases and assumes from the Assignor, subject to and in accordance with the Standard Terms and Conditions and the Credit Agreement, as of the Effective Date inserted by the Administrative Agent as contemplated below (i) all of the Assignor’s rights and obligations in its capacity as a Lender under the Credit Agreement and any other documents or instruments delivered pursuant thereto to the extent related to the amount and percentage interest identified below of all of such outstanding rights and obligations of the Assignor under the respective facilities identified below (including without limitation any letters of credit, guarantees, and swingline loans included in such facilities) and (ii) to the extent permitted to be assigned under Applicable Law, all claims, suits, causes of action and any other right of the Assignor (in its capacity as a Lender) against any Person, whether known or unknown, arising under or in connection with the Credit Agreement, any other documents or instruments delivered pursuant thereto or the loan-transactions governed thereby or in any way based on or related to any of the foregoing, including, but not limited to, contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above (the rights and obligations sold and assigned pursuant to clauses (i) and (ii) above being referred to herein collectively as, the “Assigned Interest”). Such sale and assignment is without recourse to the Assignor and, except as expressly provided in this Assignment and Assumption, without representation or warranty by the Assignor.
1.
Assignor:                        
2.
Assignee:                        
[and is an Affiliate/Approved Fund of [identify Lender]1]
3.
Borrower(s):                        
4.
Administrative Agent: Royal Bank of Canada, as the administrative agent under the Credit Agreement
5.
Credit Agreement:     The Credit Agreement dated as of January 24, 2020, among AltaLink Investments L.P., the Lenders parties thereto, Royal Bank of Canada as Administrative Agent, and the other agents parties thereto, as amended, restated or replaced from time to time.

RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement

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________________________________
1
Select as applicable.

6.
Assigned Interest:
Aggregate Amount of Commitment/Loans for all Lenders2
Amount of Commitment/Loans Assigned
Percentage Assigned of Commitment/Loans3
CUSIP Number
$
$
%
 
$
$
%
 
$
$
%
 

7.
Trade Date:                    4 














________________________
2
Amount to be adjusted by the counterparties to take into account any payments or prepayments made between the Trade Date and the Effective Date.
3
Set forth, to at least 9 decimals, as a percentage of the Commitment/Loans of all Lenders thereunder.
4
To be completed if the Assignor and the Assignee intend that the minimum assignment amount is to be determined as of the Trade Date.

RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement

- 3 -

Effective Date: ___________, 20___ [TO BE INSERTED BY ADMINISTRATIVE AGENT AND WHICH SHALL BE THE EFFECTIVE DATE OF RECORDATION OF TRANSFER IN THE REGISTER THEREFOR.]
The terms set forth in this Assignment and Assumption are hereby agreed to:
 
ASSIGNOR
[NAME OF ASSIGNOR]
 
 
 
 
By:
 
 
 
Title:
 
 
 
 
 
 
 
ASSIGNEE
[NAME OF ASSIGNEE]
 
 
 
 
By:
 
 
 
Title:
 
 
 
Consented to and Accepted:
 
 
 
 
 
Royal Bank of Canada, as
Administrative Agent
 
 
 
 
 
 
By
 
 
 
 
Title:
 
 
 
 
 
 
[Consented to:]5
 
 
 
 
 
 
[NAME OF RELEVANT PARTY]
 
 
 
 
 
 
By
 
 
 
 
Title:
 
 

 





_______________________________
5
To be added only if the consent of the Borrower and/or other parties (e.g. Documentary Credit Lender) is required by the terms of the Credit Agreement.

RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



ANNEX 1 to Assignment and Assumption
STANDARD TERMS AND CONDITIONS FOR
ASSIGNMENT AND ASSUMPTION
1.
Representations and Warranties.
1.1
Assignor. The Assignor (a) represents and warrants that (i) it is the legal and beneficial owner of the Assigned Interest, (ii) the Assigned Interest is free and clear of any lien, encumbrance or other adverse claim and (iii) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby; and (b) assumes no responsibility with respect to (i) any statements, warranties or representations made in or in connection with the Credit Agreement or any other Loan Document, (ii) the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents or any collateral thereunder, (iii) the financial condition of the Borrower, any of its Subsidiaries or Affiliates or any other Person obligated in respect of any Loan Document or (iv) the performance or observance by the Borrower, any of its Subsidiaries or Affiliates or any other Person of any of their respective obligations under any Loan Document.

1.2
Assignee. The Assignee (a) represents and warrants that (i) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and to become a Lender under the Credit Agreement, (ii) it meets all requirements of an Eligible Assignee under the Credit Agreement (subject to receipt of such consents as may be required under the Credit Agreement), (iii) from and after the Effective Date, it shall be bound by the provisions of the Credit Agreement as a Lender thereunder and, to the extent of the Assigned Interest, shall have the obligations of a Lender thereunder, (iv) it has received a copy of the Credit Agreement, together with copies of the most recent financial statements delivered pursuant to Section ___ thereof, as applicable, and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Assignment and Assumption and to purchase the Assigned Interest on the basis of which it has made such analysis and decision independently and without reliance on the Administrative Agent or any other Lender, and (v) if it is a Foreign Lender, attached to the Assignment and Assumption is any documentation required to be delivered by it pursuant to the terms of the Credit Agreement, duly completed and executed by the Assignee; and (b) agrees that (i) it will, independently and without reliance on the Administrative Agent, the Assignor or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents, and (ii) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender.
2.
Payments. From and after the Effective Date, the Administrative Agent shall make all payments in respect of the Assigned Interest (including payments of principal, interest, fees and other amounts) to the Assignee whether such amounts have accrued prior to, on or after the Effective Date. The Assignor and the Assignee shall make all appropriate adjustments

RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement

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in payments by the Administrative Agent for periods prior to the Effective Date or with respect to the making of this assignment directly between themselves.
3.
General Provisions. This Assignment and Assumption shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and permitted assigns. This Assignment and Assumption may be executed in any number of counterparts, which together shall constitute one instrument. Delivery of an executed counterpart of a signature page of this Assignment and Assumption by telecopy or by sending a scanned copy by electronic mail shall be effective as delivery of a manually executed counterpart of this Assignment and Assumption. This Assignment and Assumption shall be governed by, and construed in accordance with, the law governing the Credit Agreement.


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



SCHEDULE 6
COMMITMENTS OF THE LENDERS

Lenders
Lender’s Commitment (Cdn.$)
Applicable Percentage
Royal Bank of Canada
$100,000,000
33.3%
Bank of Montreal
$75,000,000
25%
Bank of Nova Scotia
$65,000,000
21.7%
National Bank of Canada
$40,000,000
13.3%
ATB Financial
$20,000,000
6.7%




RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



SCHEDULE 6.1(A)
FORM OF NOTICE OF REPAYMENT
(Letter to be typed on Borrower’s Letterhead)
_________________, 20____
Royal Bank of Canada
Agency Services Group
200 Bay Street
Royal Bank Plaza
12th Floor
Toronto, ON M5J 2W7

Attention:    Manager Agency
Facsimile:    (416) 842-4023

REPAYMENT NOTICE
Dear Sirs:
We refer to Section 6.1(a) of the amended and restated credit agreement made as of January 24, 2020 (as amended, restated or replaced from time to time, the “Credit Agreement”) between AltaLink Investments, L.P., as Borrower, AltaLink Investment Management Ltd. and Royal Bank of Canada, as Agent and Lender, and the other Lenders which become a party thereto. Capitalized terms used in this Notice and not otherwise defined have the meanings given in the Credit Agreement.
We hereby notify the Agent of our repayment of the Loan subject to and in accordance with the terms and provisions of the Credit Agreement in the amount of:
A. Repayment amount:
Prime Rate Loan:
_______________
Maturity Date
_______________
BA Rate Loan:
_______________
Maturity Date
_______________
US Bate Rate Loan:
_______________
Maturity Date
_______________
LIBOR Loan:
_______________
Maturity Date
_______________
B. Date of repayment:    _________________________
Proceeds of the repayment are to be deposited to the account of the Agent as follows:
Bank Name:                
Account Name:            
Transit #:                
Account Number:            CAD    l         USD    l
    

RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement

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Yours truly,
 
 
ALTALINK INVESTMENT MANAGEMENT LTD., as general partner of ALTALINK INVESTMENTS, L.P.
 
 
By:
 
 
Name:
 
Title:
 
 
By:
 
 
Name:
 
Title:




RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



SCHEDULE 7
SENIOR PLEDGED BOND, SERIES 2

[See Attached]


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



SCHEDULE 8
THIRD SUPPLEMENTAL INDENTURE

[See Attached]

RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement



SCHEDULE 9.1(A)
CREDIT PARTY AND SUBSIDIARY INFORMATION

RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement




SCHEDULE 10
MATERIAL AGREEMENTS

Nil.


RBC – AltaLink (AILP) – 2020 Amended and Restated Credit Agreement
EXHIBIT 10.4





FIFTH AMENDED AND RESTATED CREDIT AGREEMENT

ALTALINK, L.P.
as Borrower,
- and -
ALTALINK MANAGEMENT LTD.
as General Partner
- and -
THE BANK OF NOVA SCOTIA
as Administrative Agent of the Lenders, Co-Lead Arranger and Co-Bookrunner
- and -
ROYAL BANK OF CANADA
as Syndication Agent, Co-Lead Arranger and Co-Bookrunner
- and -
THE BANK OF MONTREAL AND NATIONAL BANK OF CANADA
as Co-Documentation Agents
- and -
THE BANK OF NOVA SCOTIA, ROYAL BANK OF CANADA, THE BANK OF MONTREAL, NATIONAL BANK OF CANADA, THE TORONTO-DOMINION BANK AND ATB FINANCIAL, AND ALL OTHER LENDERS WHICH FROM TIME TO TIME BECOME PARTIES HEREUNDER,
as Lenders




- 2 -





TABLE OF CONTENTS




 
 
 
Page
2

 
1.1
Definitions
2

 
1.2
References
11

 
1.3
Headings
11

 
1.4
Included Words
11

 
1.5
Amendment and Restatement: No Novation
11

 
1.6
Time
11

 
1.7
Governing Law/Attornment
11

 
1.8
Currency
12

 
1.9
Certificates and Opinions
12

 
Accounting Terms
12

 
Schedules
13

 
 
 
 
13

 
2.1
Credit Facility
13

 
2.2
Cancellation
13

 
2.3
Particulars of Borrowings
13

 
2.4
Borrowing Notice
14

 
2.5
Books of Account
15

 
2.6
Further Provisions Account/Evidence of Borrowings
15

 
2.7
Bankers’ Acceptances
16

 
2.8
Safekeeping of Drafts
19

 
2.9
Certification to Third Parties
19

 
BA Equivalent Loans and Discount Notes
20

 
Successor CDOR Rate.
20

 
 
 
 
22

 
3.1
Interest on Prime Rate Loans
22

 
3.2
Interest on Overdue Amounts
22

 
3.3
Other Interest
22

 
3.4
Interest Act (Canada)
22

 
3.5
Deemed Reinvestment Principle
23

 
3.6
Maximum Return
23

 
3.7
Inability to Determine Rates
23

 
 
 
 
24

 
4.1
Acceptance Fees
24

 
4.2
Standby Fee
24

 
4.3
Basis of Calculation of Fees
25

 
 
 
 
25

 
5.1
Voluntary Repayment of Outstanding Accommodations
25


 
i
 


TABLE OF CONTENTS
(continued)


 
5.2
Repayment on Maturity Date and Extension
26

 
5.3
Excess Accommodations
26

 
5.4
Illegality
27

 
 
 
 
27

 
6.1
Payments on Non-Business Days
27

 
6.2
Method and Place of Payment
27

 
6.3
Net Payments
27

 
6.4
Administrative Agent May Debit Account
27

 
6.5
Currency of Payment
28

 
6.6
Increased Costs
28

 
6.7
General Indemnity
29

 
6.8
Outstanding Bankers’ Acceptances or Discount Notes
30

 
6.9
Replacement of Lender
30

 
 
 
 
30

 
7.1
Security
30

 
 
 
 
31

 
8.1
Representations and Warranties
31

 
8.2
Survival of Representations and Warranties
34

 
 
 
 
34

 
9.1
Trust Indenture
34

 
9.2
Covenants
34

 
9.3
Maintenance of Total Capitalization
36

 
 
 
 
36

 
Conditions Precedent to Effectiveness of this Agreement
36

 
Conditions Precedent to All Borrowings, Conversions
37

 
Waiver
38

 
 
 
 
38

 
Events of Default
38

 
Remedies
39

 
Remedies Cumulative
39

 
Appropriation of Moneys Received
39

 
Non-Merger
40

 
Waiver
40

 
Set-off
40

 
 
 
 
41

 
Authorization of Administrative Agent and Relationship
41


 
ii
 


TABLE OF CONTENTS
(continued)


 
Disclaimer of Administrative Agent
41

 
Failure of Lender to Fund
42

 
Replacement of Lenders
43

 
Payments by the Borrower
44

 
Payments by Administrative Agent
45

 
Direct Payments
46

 
Administration of the Credit Facility
46

 
Rights of Administrative Agent
49

 
Acknowledgements, Representations and Covenants of Lenders
49

 
Collective Action of the Lenders
51

 
Successor Administrative Agent
51

 
Provisions Operative Between Lenders and Administrative Agent Only    
52

 
Assignments and Participation - Approvals
52

 
Assignments
52

 
Participation
53

 
 
 
 
54

 
Expenses
54

 
Further Assurances
54

 
Notices
54

 
Survival
56

 
Benefit of Agreement
56

 
Severability
57

 
Entire Agreement
57

 
Credit Documents
57

 
Counterparts
57

 
Amendments/Approvals and Consents/Waivers
57

 
Acknowledgement
57

 
 
 
 
 
 
 
 
 
 
 



 
iii
 




THIS FIFTH AMENDED AND RESTATED CREDIT AGREEMENT is made as of January 24, 2020
A M O N G :
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.,
as Borrower,
- and -
ALTALINK MANAGEMENT LTD.,
as General Partner,
- and -
THE BANK OF NOVA SCOTIA
as Administrative Agent of the Lenders, Co-Lead Arranger and Co-Bookrunner
- and -
ROYAL BANK OF CANADA
as Syndication Agent, Co-Lead Arranger and Co-Bookrunner
- and -
THE BANK OF MONTREAL AND NATIONAL BANK OF CANADA
as Co-Documentation Agents
- and -
THE BANK OF NOVA SCOTIA, ROYAL BANK OF CANADA, THE BANK OF MONTREAL, NATIONAL BANK OF CANADA, THE TORONTO-DOMINION BANK AND ATB FINANCIAL, AND ALL OTHER LENDERS WHICH FROM TIME TO TIME BECOME PARTIES HEREUNDER,
as Lenders
WHEREAS the Borrower, the General Partner, BNS, as administrative agent, co-lead arranger and co-bookrunner, RBC, as syndication agent, co-lead arranger and co-bookrunner, BMO, as co-documentation agent, NBC, as co-documentation agent, and the Lenders are party to a Fourth Amended and Restated Credit Agreement dated as of December 17, 2015 (such agreement, as amended by a first amending agreement dated as of December 15, 2016, a second amending agreement dated as of December 14, 2017, a third amending agreement dated as of April 19, 2018 and a fourth amending agreement dated as of December 14, 2018, the “Existing Credit



- 2 -

Agreement”) which Existing Credit Agreement was an amendment and restatement of an amended and restated credit agreement dated as of December 19, 2013;
AND WHEREAS the Borrower has requested, and the Lenders have agreed, to extend the Maturity Date and to make additional amendments to the Existing Credit Agreement and to amend and restate the Existing Credit Agreement, as herein contained;
AND WHEREAS BNS has agreed to act as sole Administrative Agent, Co-Lead Arranger and Co-Bookrunner, RBC has agreed to act as sole Syndication Agent, Co-Lead Arranger and Co-Bookrunner, and BMO and NBC have agreed to act as Co-Documentation Agents;
NOW THEREFORE THIS AGREEMENT WITNESSES that, in consideration of the mutual covenants and agreements contained in this Agreement, the Borrower, the General Partner, the Administrative Agent, Co-Lead Arrangers, Co-Bookrunners, Co-Documentation Agents, Syndication Agent and Lenders covenant and agree as follows:



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ARTICLE 1
INTERPRETATION
1.1
Definitions
In this Agreement, unless the context otherwise requires, all capitalized terms shall have the meaning ascribed thereto in the Trust Indenture provided that the following terms shall have the following meanings (whether or not defined in the Trust Indenture):
“Accommodations” means the Loans, Bankers’ Acceptances and Discount Notes under this Credit Facility and shall refer to any one or more of such types where the context requires.
“Administrative Agent” means BNS, or any Successor Administrative Agent appointed under Section 12.12.
“Advance” means an advance by the Lenders or any of them of any Accommodation, and shall include deemed Advances and conversions, renewals and rollovers of existing Advances, and any reference relating to the amount of Advances shall mean the Canadian Dollar Amount of all outstanding Accommodation.
“Advanced Share” means the percentage of the total amount of Advances to the Borrower that has been made by a particular Lender at any time.
“Administrative Agent’s Account” means the account at the Branch into which Lenders’ Advances shall be deposited for payment to the Borrower.
“Agreement” means this Fifth Amended and Restated Credit Agreement and the Schedules hereto, as amended, supplemented or restated from time to time.
“Applicable Laws” means (a) any domestic or foreign statute, law (including common and civil law), treaty, code, ordinance, rule, regulation, restriction or by-law (zoning or otherwise); (b) any judgment, order, writ, injunction, decision, ruling, decree or award; (c) any regulatory policy, practice, guideline or directive; or (d) any franchise, licence, qualification, authorization, consent, exemption, waiver, right, permit or other approval of any governmental authority, binding on or affecting the person referred to in the context in which the term is used or binding on or affecting the property of such person, in each case whether or not having the force of law.
“Applicable Margin” means the applicable fee or margin amount set out in the following grid for the rating which corresponds to the rating received from Standard & Poor’s, Moody’s or DBRS (collectively, the “Rating Agencies”) and which is determined below:



- 4 -

Rating
Standard & Poor’s, Moody’s and DBRS
B/A Margin
Prime Margin
Standby Fee
>A / A2 / A
70 bps
0 bps
14.0 bps
A / A2 / A
80 bps
0 bps
16.0 bps
A- / A3 / A (low)
100 bps
0 bps
20.0 bps
BBB+ / Baa1/ BBB (high)
120 bps
20 bps
24.0 bps
< BBB+ / Baa1 / BBB (high)
145 bps
45 bps
29.0 bps

The ratings set forth in the foregoing table are the ratings assigned by each of the Rating Agencies to the Borrower until such time as ratings are assigned to the Outstanding Senior Bonds after which time the ratings set forth on the foregoing table shall refer to the ratings assigned by each of the Rating Agencies to the Outstanding Senior Bonds. For purposes of this Agreement, if at any time the ratings assigned by the Rating Agencies fall within different rating categories in accordance with the above table, the applicable rating category for purposes of calculating the Applicable Margin shall be determined as follows:
(a)
if only two Rating Agencies publish ratings of the Borrower and/or the Outstanding Senior Bonds, as applicable, the rating category containing the highest assigned rating shall govern, unless the difference in the ratings published by such two Rating Agencies is: (i) two rating levels, in which case the applicable rating shall be deemed to be the average between such two ratings; and (ii) more than two rating levels, in which case the applicable rating shall be deemed to be the rating one level higher than the lowest of such ratings;
(b)
if all three Rating Agencies publish ratings of the Borrower and/or the Outstanding Senior Bonds, as applicable, and two (2) of the Rating Agencies publish a similar rating category, such similar rating category shall govern; and
(c)
if all three Rating Agencies publish ratings of the Borrower and/or the Outstanding Senior Bonds, as applicable, which are different, the middle rating category of the three ratings shall govern.
Any increase or decrease in the applicable Bankers’ Acceptance Fee resulting from a change in the rating assigned by one or more Rating Agencies shall be calculated with reference to the new Applicable Margin and fee effective on and after the date on which such rating change is published, notwithstanding that any affected Bankers’ Acceptance or Discount Note may have been made or issued prior to such date. In the case of outstanding Bankers’ Acceptance or Discount Note, an appropriate adjustment shall be made to the fees already collected in respect thereof and the difference shall be paid by, or refunded to, the Borrower, as the case may be, within five (5) Business Days after notice by the Administrative Agent to the Borrower of the amount of the adjustment.
“BA Discount Proceeds” means, in respect of any Bankers’ Acceptance or Discount Note, an amount calculated on the applicable Borrowing Date which is (rounded to the nearest full cent, with one-half of one cent being rounded up) equal to the face amount of such



- 5 -

Bankers’ Acceptance or Discount Note multiplied by the price, where the price is calculated by dividing one by the sum of one plus the product of (i) the BA Discount Rate applicable thereto expressed as a decimal fraction multiplied by (ii) a fraction, the numerator of which is the term of such Bankers’ Acceptance or Discount Note, as the case may be, and the denominator of which is three hundred and sixty-five (365), which calculated price will be rounded to the nearest multiple of 0.001%.
“BA Discount Rate” means, in respect of a Draft to be accepted by a Lender,
(a)
by a Schedule 1 Bank, CDOR; or
(b)
in respect of a Draft to be accepted and purchased by a Schedule 2 Bank or a BA Equivalent Loan to be made by a Non-Acceptance Lender, the lesser of:
(i)
CDOR plus 0.10%; and
(ii)
the respective discount rate quoted from time to time by such Schedule 1 Bank, Schedule 2 Bank or Non-Acceptance Lender as its discount rate for purchasing its bills of exchange or making BA Equivalent Loans, respectively, in an amount substantially equal to the reference amount (as defined below) at approximately 10:00 a.m. (Toronto, Ontario time) on the day of a proposed Advance by way of a Bankers’ Acceptance;
provided that if any such rate is less than zero, the BA Discount Rate will be deemed to be zero.
For the purposes of this definition, “reference amount” with respect to any Lender and any term of a Bankers’ Acceptance or a BA Equivalent Loan, means the amount of that Lender’s portion of the Loan being requested by the Borrower by way of a Bankers’ Acceptance or a BA Equivalent Loan for that term.
“BA Equivalent Loan” means a Loan made by a Non-Acceptance Lender evidenced by a Discount Note.
“BA Instruments” means, collectively, Bankers’ Acceptances, Drafts and BA Equivalent Loans, and, in the singular, any one of them.
“Bankers’ Acceptance” means a Draft drawn by the Borrower denominated in Canadian Dollars, for a term of one, two, three or six months or such other term as is readily acceptable, which term shall mature on a Business Day and on or before the applicable Maturity Date for an amount of Two Hundred and Fifty Thousand Canadian Dollars (Cdn.$250,000) or any whole multiple of Two Hundred and Fifty Thousand Canadian Dollars (Cdn.$250,000), the minimum aggregate amount of which included in any Borrowing shall be Two Hundred and Fifty Thousand Canadian Dollars (Cdn.$250,000), and accepted by a Lender pursuant to this Agreement.



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“Bankers’ Acceptance Fee” means the fee payable on the face amount of each Bankers’ Acceptance or issuance of a Discount Note, as the case may be, calculated and payable in the manner provided for in Section 4.1.
“BMO” means The Bank of Montreal, its successors and permitted assigns.
“BNS” means The Bank of Nova Scotia, its successors and permitted assigns.
“Bond Delivery Agreement” means the bond delivery agreement dated as of October 24, 2014 among the parties hereto as the same may be amended, supplemented, restated or otherwise modified from time to time.
“Borrower” means AltaLink, L.P., a limited partnership created and existing under the Partnership Act (Alberta) and its permitted successors and permitted assigns.
“Borrower’s Account” means an account for the Borrower designated by the Borrower and maintained for the Borrower at the Branch of Account, pursuant to an account operating agreement between the Borrower and BNS.
“Borrower’s Certificate of Compliance” means a certificate of the Borrower in the form of Schedule 1 and signed on behalf of the Borrower by any one of the President, Chief Executive Officer, the Chief Financial Officer, an Executive Vice President, a Vice President, the Secretary, the Treasurer or Vice President and Controller of the Borrower or any other senior officer of the General Partner so designated by a certificate signed by the Chairman or President of the General Partner and filed with the Administrative Agent for so long as such designation shall be in effect.
“Borrowing” means the aggregate Accommodation to be obtained by the Borrower from one or more of the Lenders on any Borrowing Date.
“Borrowing Date” means the Business Day specified in a Borrowing Notice on which a Lender is or Lenders are requested to provide Accommodation.
“Borrowing Notice” has the meaning set out in Section 2.4.
“Branch” means the Global Wholesale Services, 720 King Street West, 2nd Floor, Toronto, Ontario M5V 2T3, or such other branch of the Administrative Agent in the City of Calgary as the Administrative Agent may from time to time designate in writing to the Borrower and the Lenders.
“Branch of Account” means the Calgary Commercial Banking Centre of the BNS situated at 240-8th Avenue S.W., Calgary, Alberta, or such other branch of the BNS in the City of Calgary as BNS may from time to time designate in writing to the Borrower.
“Business Day” means any day (excluding Saturday, Sunday and any day which shall be a legal holiday in Calgary, Alberta and Toronto, Ontario) on which the Administrative Agent is open at the Branch for the conduct of regular banking business.
“Canadian Dollar” or “Cdn.$” means lawful money of Canada.



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“Canadian Dollar Amount” means, at any time, in relation to any outstanding Accommodation:
(a)
in relation to a Loan denominated in Canadian Dollars, the principal amount thereof; and
(b)
in relation to a Bankers’ Acceptance or Discount Note, the face amount thereof.
“CDOR” means, on any day and in relation to a Loan, the arithmetical average of the percentage discount rates (expressed to 5 decimal places) for Canadian dollar bankers’ acceptances in comparable amounts having an identical issue and maturity date which is quoted on the “Reuters’ Screen CDOR Page” (as defined in the International Swaps and Derivatives Association, Inc. definitions, as modified and amended from time to time) for acceptances of Schedule I banks under the Bank Act (Canada) (or if such screen shall not be available any successor or similar service selected by the Administrative Agent) as at approximately 10:00 a.m. (Toronto, Ontario time) on such day, or if such day is not a Business Day, then on the immediately preceding Business Day (as adjusted by the Administrative Agent in good faith after 10:00 a.m. (Toronto, Ontario time) or as soon thereafter as practicable to reflect any error in a posted rate of interest or in the posted average annual rate of interest). If neither such screen nor any successor or similar service is available, then “CDOR” shall mean, with respect to each Bankers’ Acceptance which is required to be accepted and purchased by a Lender hereunder on any Business Day, the percentage discount rate (expressed to 5 decimal places) determined by the Administrative Agent to be the average of the quoted discount rates at which Canadian dollar bankers’ acceptances in comparable amounts having an identical issue and maturity date are being bid for discount by a Schedule I Bank at approximately 10:00 a.m. (Toronto, Ontario time) or soon thereafter as practical on the day of the acceptance and purchase of the Bankers’ Acceptances hereunder. If any Lender does not furnish a timely quotation, the Administrative Agent shall determine the relevant BA Discount Rate on the basis of the quotation or quotations furnished by the remaining Lenders. Each determination of CDOR shall be conclusive and binding, absent manifest error, and be computed using any reasonable averaging and attribution method.
“Claim” shall have the meaning set out in Section 6.7.
“Co-Documentation Agents” means BMO and NBC, and their successors and permitted assigns.
“Co-Lead Arrangers and Co-Bookrunners” means BNS and RBC, and their successors and permitted assigns.
“Commercial Paper Program” means the commercial paper program established by the Borrower as contemplated by the “Information Memorandum Short-Term Promissory Notes” and Note Issuance and Payment Agreement between the Borrower and BNS each dated December 15, 2005, as amended, restated or supplemented from time to time.
“Commitment” means in respect of each Lender from time to time, the covenant to make Advances to the Borrower of the Lender’s Proportionate Share of the Committed Amount and, where the context requires, the maximum amount of Advances which such Lender has



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covenanted to make, as recorded on the Register maintained by the Administrative Agent referred to in Subsection 12.15(c).
“Committed Amount” means the aggregate maximum authorized amount of Accommodation under the Credit Facility from time to time.
“Contract Period” means, in respect of any BA Instrument, the applicable term of such BA Instrument selected by the Borrower in the related Borrowing Notice.
“Contributing Lender” shall have the meaning set out in Subsection 12.3(b).
“Credit Documents” means the Pledged Bond, Trust Indenture, forms of Drafts, or agreements relating to Bankers’ Acceptances or Discount Notes required by any Lender and, when executed and delivered by the Borrower.
“Credit Facility” means the credit facility established by the Lenders in favour of the Borrower pursuant to Section 2.1.
“Defaulting Lender” shall have the meaning set out in Subsection 12.3(b).
“Demand Date” means any date that repayment of Accommodation or any other amount outstanding under this Agreement is demanded under Article 11.
“Depository Bill” means a depository bill, as such term is defined in the Depository Bills and Notes Act (Canada) (as such legislation may be amended, replaced or otherwise modified from time to time).
“Discount Note” or “Discount Notes” means a non-interest bearing promissory note denominated in Canadian Dollars issued by the Borrower to a Non-Acceptance Lender to evidence a BA Equivalent Loan.
“Draft” means at any time a blank bill of exchange, within the meaning of the Bills of Exchange Act (Canada), drawn by the Borrower on a Lender and bearing such distinguishing letters and numbers as such Lender may require, but which at such time has not been completed or accepted by such Lender.
“Effective Date” means January 24, 2020 or such later date as may be agreed upon by the parties.
“Eighteenth Supplemental Indenture” means the Eighteenth Supplemental Indenture between the Borrower, the General Partner and the Trustee dated as of October 24, 2014 pursuant to which the Borrower shall issue the Pledged Bond, as such indenture may be amended, supplemented, restated or otherwise modified from time to time.



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“Environmental Adverse Effect” means one or more of the following in connection with an Environmental Matter:
(a)
impairment or adverse alteration of the quality of the natural environment for any use that can be made of it by humans, or by any animal, fish or plant that is useful to humans;
(b)
injury or damage to property or to plant or animal life;
(c)
harm or material discomfort to any Person;
(d)
an adverse effect on the health of any Person;
(e)
impairment of the safety of any Person;
(f)
rendering any property or plant or animal life unfit for human use;
(g)
loss of enjoyment of normal use of property; and
(h)
interference with the normal conduct of business.
“Environmental Liability” means any liability of the Borrower under any Environmental Laws or any other Applicable Laws for any adverse impact on the environment, health or safety, including the Release of a Hazardous Substance, and any liability for the costs of any clean-up, preventative or other remedial action including costs relating to studies undertaken or arising out of security fencing, alternative water supplies, temporary evacuation and housing and other emergency assistance undertaken by any Government Authority to prevent or minimize any actual or threatened Release by the Borrower of any Hazardous Substance.
“Environmental Matter” means any past, present or future activity, event or circumstance in respect of the environment, health or safety including the Release of any Hazardous Substance including any substance which is hazardous to Persons, animals, plants, or which has a detrimental effect on the soil, air or water, or the generation, treatment, storage, use, manufacture, holding, collection, processing, treatment, presence, transportation or disposal of any Hazardous Substances.
“Environmental Proceeding” means any judgment, action, proceeding or investigation pending before any court or Government Authority, including any environmental Government Authority, with respect to or threatened against or affecting the Borrower or relating to the assets or liabilities of the Borrower or any of their respective operations, in connection with any Environmental Laws, Environmental Matter or Environmental Liability.
“Event of Default” shall have the meaning specified in Section 11.1.
“Fee Letter” means the fifth amended and restated fee letter entered into between BNS, the Borrower and the General Partner dated January 24, 2020, as such fee letter may be amended, restated supplemented or otherwise modified from time to time.



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“GAAP” means generally accepted accounting principles in effect in Canada at the time any calculation or determination is made or required to be made in accordance with generally accepted accounting principles, applied in a consistent manner from period to period, including the accounting recommendations published in the CPA Canada Handbook.
“General Partner” means AltaLink Management Ltd.
“Governmental Approvals” means any authorization, order, permit, approval, grant, licence, consent, right, privilege, certificate or the like which may be issued or granted by law or by rule, regulation, policy or directive of any Government Authority now or hereafter required in connection with the use, management, maintenance and operation of the Business by the Borrower.
“IFRS” means International Financial Reporting Standards established by the International Accounting Standards Board.
“Lenders” means BNS, RBC, BMO, NBC, The Toronto-Dominion Bank and ATB Financial and all other financial institutions from time to time that have become a Lender in accordance with this Agreement and “Lender” means any one of them.
“Loan” means the amount of Canadian Dollars advanced by a Lender or Lenders to the Borrower on any Borrowing Date pursuant to a Borrowing Notice.
“Majority Lenders” means, at any time, Lenders having, in the aggregate, Proportionate Shares of a minimum of 66.7% of the Committed Amount.
“Market Disruption Event” means:
(a)
the CDOR rate is not available for the relevant interest period; or
(b)
due to one or more events, circumstances or conditions affecting any Lender, the cost to such Lender of funding in the relevant interbank markets would be in excess of:
(i)
the Prime Rate, in respect of a Prime Rate Loan; or
(ii)
the CDOR rate, in respect of a Bankers’ Acceptance.
“Material Adverse Effect” means a material adverse effect on the ability of the Borrower to perform its obligations under this Agreement or any of the other Credit Documents or on the validity or priority of any Security Interest held by the Administrative Agent, or an event which results in an Event of Default and includes an Environmental Adverse Effect which constitutes or results in any of the foregoing effects.
“Maturity Date” means December 14, 2024, as may be extended pursuant to Subsection 5.2(b).
“NBC” means National Bank of Canada, its successors and permitted assigns.



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Non-Acceptance Lender means a Lender which does not, as part of the ordinary course of its business accept Bankers’ Acceptances.
“Notice of Extension” shall have the meaning specified in Section 5.2.
Permitted JA Subsidiary” means a subsidiary of the Borrower formed for the sole purpose of facilitating the participation by the Borrower in a Permitted Joint Arrangement and “Permitted JA Subsidiaries” means one or more Permitted JA Subsidiary.
Permitted Joint Arrangements” means one or more arrangements with other parties related to the development or operating projects for the transmission of electricity in Canada (including the bidding process thereto) and “Permitted Joint Arrangement” means any one of the Permitted Joint Arrangements.
“Pledged Bond” means the Two Billion Canadian Dollars (Cdn.$2,000,000,000) Series 18 Bond of the Borrower issued and certified under the Trust Indenture.
“Prime Rate” means the rate per annum publicly declared by the Administrative Agent from time to time as its prime reference rate of interest for Canadian Dollar commercial loans made in Canada.
“Prime Rate Loan” means any Loan in Canadian Dollars with respect to which interest is calculated under this Agreement for the time being on the basis of the Prime Rate.
“Proportionate Share” means the percentage of the Committed Amount which a Lender has agreed to advance pursuant to the Credit Facility, as set out in Schedule 5, which percentage shall be amended and distributed to all parties by the Administrative Agent from time to time as other Persons become Lenders.
RBC” means Royal Bank of Canada, its successors and permitted assigns.
“Schedule 1 Bank” means a bank listed on Schedule 1 under the Bank Act (Canada).
“Schedule 2 Bank” means a bank listed on Schedule 2 under the Bank Act (Canada).
“Screen Rate” has the meaning specified in Section 2.11.
“Successor Rate” has the meaning specified in Section 2.11.
Syndication Agent” means RBC, its successors and permitted assigns.
“Trust Indenture” means the amended and restated trust indenture made as of the 28th day of April, 2003 between the Borrower, the General Partner and BNY Trust Company of Canada, as trustee, as supplemented by Supplemental Indentures each dated April 29, 2002, May 10, 2002, October 1, 2002, April 28, 2003, June 5, 2003, December 8, 2003, December 15, 2005 and May 9, 2006, May 21, 2008, December 18, 2009, August 18, 2010, December 17, 2010, September 1, 2011, June 29, 2012, November 15, 2012, May 22, 2013, October 24, 2014, June 30, 2015 and December 14, 2018, as such amended and restated trust indenture may be further amended and supplemented from time to time.



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“Undisbursed Credit” means, at any time, the excess, if any, of the limit of the Credit Facility then in effect over the Canadian Dollar Amount of all Accommodations then outstanding under the Credit Facility.
1.2
References
The terms “Article”, “Section”, “Subsection” or “Paragraph” followed by a number refer to the specified Article, Section, Subsection or Paragraph of this Agreement unless otherwise expressly stated or the context otherwise requires.
1.3
Headings
The Article or Section or other headings contained in this Agreement are inserted for convenience only and shall not affect the meaning or construction of any of the provisions of this Agreement.
1.4
Included Words
Words importing the singular number only shall include the plural and vice versa where the context requires. The word “include” and derivatives thereof means “include without limitation”.
1.5
Amendment and Restatement: No Novation
The parties hereto acknowledge and confirm that this Agreement does not constitute a novation of the Existing Credit Agreement, as amended, restated, supplemented, otherwise modified or replaced from time to time, and that all debts, liabilities and obligations of the Borrower under the Existing Credit Agreement, as amended, restated, supplemented, otherwise modified or replaced from time to time (i) shall be debts, liabilities and obligations of the Borrower under this Agreement, (ii) shall remain unaffected, except as amended hereby and (iii) shall constitute “Obligations” for the purposes of the Eighteenth Supplemental Indenture and shall be subject to the Pledged Bond.
1.6
Time
Unless otherwise expressly stated, any reference herein to a time shall mean local time in Calgary, Alberta.
1.7
Governing Law/Attornment
This Agreement and the Credit Documents shall be governed by and construed in accordance with the laws of the Province of Alberta and the laws of Canada applicable therein.
1.8
Currency
Unless otherwise specified herein, or the context otherwise requires, all statements of or references to dollar amounts in this Agreement and the Credit Documents shall mean Canadian Dollars.
1.9
Certificates and Opinions
(a)
Unless otherwise provided in a particular Schedule to this Agreement, each certificate and each opinion furnished pursuant to any provision of this Agreement shall specify



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the Section or Sections under which such certificate or opinion is furnished, shall include a statement that the Person making such certificate or giving such opinion has read the provisions of this Agreement relevant thereto and shall include a statement that, in the opinion of such Person, such Person has made such examination and investigation as is necessary to enable such Person to express an informed opinion on the matters set out in the certificate or opinion.
(b)
Whenever the delivery of a certificate or opinion is a condition precedent to the taking of any action by the Administrative Agent or a Lender or Lenders under this Agreement, the truth and accuracy of the facts and opinions stated in such certificate or opinion shall in each case be conditions precedent to the right of the Borrower to have such action taken, and each statement of fact contained therein shall be deemed to be a representation and warranty of the Borrower for the purposes of this Agreement.
1.10
Accounting Terms
Unless otherwise specified, all accounting terms used herein or in any other Credit Documents shall be interpreted in accordance with GAAP as now or hereafter adopted by (a) prior to January 1, 2011, the Canadian Institute of Chartered Accountants or any successor thereto; and (b) on and after January 1, 2011, IFRS, and all financial data submitted pursuant to this Agreement shall be prepared in accordance with such principles, consistently applied. In the event of a change in GAAP or following the adoption of IFRS, the Borrower and the Administrative Agent (with the approval of the Lenders) shall negotiate in good faith to revise (if appropriate) the financial ratios and financial covenants contained in this Agreement, such ratios and covenants to reflect GAAP as then in effect, in which case all calculations thereafter made for the purpose of determining compliance with such ratios and covenants shall be made on a basis consistent with GAAP in existence as at the date of such revisions. If the Borrower and the Administrative Agent cannot agree upon the required amendments immediately prior to the date of implementation of any accounting policy change, then all calculations of financial covenant, financial covenant thresholds or terms used in this Agreement or any other Credit Document shall be prepared and delivered on the basis of accounting policies of the Borrower as at the date hereof without reflecting such accounting policy change.
1.11
Schedules
The following are the Schedules attached to and forming part of this Agreement:
Schedule 1
-
Borrower’s Certificate of Compliance
Schedule 2(A)
-
Borrowing Notice
Schedule 2(B)
-
Notice of Roll Over
Schedule 2(C)
-
Conversion Option Notice
Schedule 3
-
Notice of Extension
Schedule 4
-
Assignment Agreement
Schedule 5
-
Lenders

ARTICLE 2    
AMOUNT AND TERMS OF THE COMMERCIAL PAPER BACK-UP FACILITY



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2.1
Credit Facility
Subject to and upon the terms and conditions set forth in this Agreement, the Lenders hereby establish in favour of the Borrower a revolving commercial paper back-up facility to be used for the purpose of supporting the Borrower’s Commercial Paper Program as well as for operating expenses, capital expenditures and working capital needs of the Borrower and the General Partner and their Subsidiaries, and for general corporate purposes including the payment of dividends by the Borrower on its equity securities, by way of Prime Rate Loans, Bankers’ Acceptances and Discount Notes and the aggregate Canadian Dollar Amount of all of the above outstanding at any time under this Credit Facility shall not exceed Five Hundred Million Canadian Dollars (Cdn$ 500,000,000).
2.2
Cancellation
Subject to the provisions of Article 5, the Borrower may, at any time, by giving not less than two (2) Business Days’ prior written notice of cancellation to the Administrative Agent, cancel all or any part of the Undisbursed Credit as designated by the Borrower without penalty, provided that, if it is a part only, the minimum amount cancelled is One Million Canadian Dollars (Cdn.$1,000,000) or any multiples of One Million Canadian Dollars (Cdn.$1,000,000) in excess thereof. Effective on the date of cancellation set out in the applicable notice of cancellation, the Credit Facility shall be permanently reduced by the amount of Canadian Dollars stated in the notice of cancellation.
2.3
Particulars of Borrowings
(a)
Notwithstanding any contrary provision contained in the Credit Documents, in the event of any conflict or inconsistency between any of the provisions in this Agreement and any of the provisions in Credit Documents, the provisions of this Agreement shall prevail.
(b)
No Borrowing shall be obtained at any time for any period which would extend beyond the earlier of (i) the date which is 364 days following the Borrowing Date in respect of such Borrowing, and (ii) the Maturity Date.
(c)
Subject to the provisions of Section 2.2 and Article 5, any Accommodation which is repaid may be subsequently re-drawn.
2.4
Borrowing Notice
Whenever the Borrower desires to obtain a Borrowing, it shall give to the Administrative Agent prior written notice in the form attached as Schedule 2(A), (B) or (C) as applicable (a “Borrowing Notice”), specifying, as applicable:
(a)
the amount, currency and type or types of Accommodation desired;
(b)
the Borrower’s Account at the Branch to which payment of the Borrowing is to be made, if applicable;
(c)
the Person to whom any Bankers’ Acceptance or Discount Note is to be delivered, if applicable;



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(d)
the requested Borrowing Date;
(e)
the term thereof; and
(f)
if applicable, the Accommodation to be renewed or converted and, where such Accommodation includes any Loan, the interest rate applicable thereto.
The Borrowing Notice shall be given to the relevant party entitled to receive same not later than 12:00 p.m. (Toronto, Ontario time):
(i)
on the applicable Borrowing Date, if the Accommodation is by way of Prime Rate Loans and is a new issue or if any such Accommodation to be drawn, converted or rolled over has a Canadian Dollar Amount in the aggregate equal to or greater than One Million Canadian Dollars (Cdn.$1,000,000) and multiples of One Million Canadian Dollars (Cdn.$1,000,000) in excess thereof. In the event such Accommodation causes a Lender to incur costs relating solely to the providing of same day notice, the Borrower shall pay such costs to such Lender immediately upon request therefor; and
(ii)
on the Business Day preceding the applicable Borrowing Date if the Accommodation is by way of Bankers’ Acceptances or Discount Notes and is a new issue or if any such Accommodation to be drawn, converted or rolled over has a Canadian Dollar Amount in the aggregate equal to or greater than Two Hundred and Fifty Thousand Canadian Dollars (Cdn.$250,000).
Any Borrowing Notice received by the Administrative Agent on any Business Day after 12:00 p.m. (Toronto, Ontario time) shall be deemed to have been given to such party on the next succeeding Business Day.
2.5
Books of Account
The Administrative Agent is hereby authorized to open and maintain books of account and other books and records evidencing all Bankers’ Acceptances and Discount Notes accepted and cancelled and all Loans advanced and repaid and all other amounts from time to time owing by the Borrower to the Lenders under this Agreement including interest, acceptance and standby and other fees, and to enter into such books and records details of all amounts from time to time owing, paid or repaid by the Borrower under this Agreement. The Borrower acknowledges, confirms and agrees with the Administrative Agent that all such books and records kept by the Administrative Agent will constitute prima facie evidence of the balance owing by the Borrower under this Agreement; provided, however, that the failure to make any entry or recording in such books and records shall not limit or otherwise affect the obligations of the Borrower under this Agreement. Notwithstanding the foregoing, each Lender is responsible for maintaining its own records as to Advances made by it, and in the event of any inconsistency between such Lender’s and the Administrative Agent’s records, the Administrative Agent’s records shall govern, absent manifest error.
2.6
Further Provisions Account/Evidence of Borrowings



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(a)
Co-ordination of Prime Rate Loans. Each Lender shall advance its Proportionate Share of each Prime Rate Loan in accordance with the following provisions:
(i)
the Administrative Agent shall advise each Lender of its receipt of a notice from the Borrower pursuant to Section 2.4, on the day such notice is received and shall, as soon as possible, advise each Lender of such Lender’s Proportionate Share of any Prime Rate Loan requested by the notice;
(ii)
each Lender shall deliver its Proportionate Share of such Loan to the Administrative Agent’s Account at the Branch not later than 11:00 a.m. (Toronto, Ontario time) on the Borrowing Date;
(iii)
when the Administrative Agent determines that all the conditions precedent to a Borrowing specified in this Agreement have been met or waived, it shall advance to the Borrower the amount delivered by each Lender by crediting the relevant Borrower’s Account(s) before 12:00 p.m. on the Borrowing Date, but if the conditions precedent to the Borrowing are not met or waived by 2:30 p.m. on the Borrowing Date, the Administrative Agent shall return the funds to the Lenders or invest them in an overnight investment as orally instructed by each Lender until such time as the Loan is advanced; and
(iv)
if the Administrative Agent determines that a Lender’s Proportionate Share of a Prime Rate Loan would not be a whole multiple of One Hundred Thousand Canadian Dollars (Cdn.$100,000), the amount to be advanced by that Lender may be increased or reduced by the Administrative Agent in its sole discretion to the nearest whole multiple of One Hundred Thousand Canadian Dollars (Cdn.$100,000).
2.7
Bankers’ Acceptances
(a)
Power of Attorney for the Execution of Bankers’ Acceptances. To facilitate acceptance of the Borrowings by way of Bankers’ Acceptances, the Borrower hereby appoints each Lender as its attorney to sign and endorse on its behalf, in handwriting or by facsimile or mechanical signature as and when deemed necessary by such Lender, blank forms of Drafts. In this respect, it is each Lender’s responsibility to maintain an adequate supply of blank forms of Drafts for acceptance under this Agreement. The Borrower recognizes and agrees that all Drafts signed and/or endorsed on its behalf by a Lender shall bind the Borrower fully and effectively as if signed in the handwriting of and duly issued by the proper signing officers of the Borrower. Each Lender is hereby authorized to issue such Drafts endorsed in blank in such face amounts as may be determined by such Lenders; provided that the aggregate amount thereof is equal to the aggregate amount of Bankers’ Acceptances required to be accepted and purchased by such Lender. No Lender shall be liable for any damage, loss or other claim arising by reason of any loss or improper use of any such instrument, except the gross negligence or wilful misconduct of the Lender or its officers, employees, agents or representatives. Each Lender shall maintain a record with respect to Bankers’ Acceptances held by it in blank hereunder, voided by it for



- 17 -

any reason, accepted and purchased by it hereunder, and cancelled at the respective maturities. Each Lender agrees to provide such records to the Borrower at the Borrower’s expense upon request.
Drafts drawn by the Borrower to be accepted as Bankers’ Acceptances shall be signed by a duly authorized officer or officers of the Borrower or by its attorneys. Notwithstanding that any Person whose signature appears on any Bankers’ Acceptance may no longer be an authorized signatory for the Borrower at the time of issuance of a Bankers’ Acceptance; that signature shall nevertheless be valid and sufficient for all purposes as if the authority had remained in force at the time of issuance and any Bankers’ Acceptance so signed shall be binding on the Borrower. Upon tender of each Draft the Borrower shall pay to the Lender the fee specified in Section 4.1 with respect to such Draft.
For clarity, Section 2.7 shall apply to Discount Notes, mutatis mutandis.
(b)
Sale of Bankers’ Acceptances. It shall be the responsibility of each Lender unless otherwise requested by the Borrower, to purchase its Bankers’ Acceptances at a discount rate equal to the BA Discount Rate.
In accordance with the procedures set forth in Paragraph 2.7(c)(iii), unless the Borrower requests the Lenders not to purchase the subject Bankers’ Acceptances, the Administrative Agent will make BA Discount Proceeds received by it from the Lenders available to the Borrower on the Borrowing Date by crediting the Borrower’s Account with such amount.
(c)
Coordination of BA Borrowings. Each Lender shall advance its Proportionate Share of each Borrowing by way of Bankers’ Acceptances in accordance with the following:
(i)
the Administrative Agent, promptly following receipt of a notice from the Borrower pursuant to Section 2.4 requesting a Borrowing by way of Bankers’ Acceptances, shall advise each Lender of the aggregate face amount and term(s) of the Bankers’ Acceptances to be accepted by it, which term(s) shall be identical for all Lenders. The aggregate face amount of Bankers’ Acceptances to be accepted by a Lender shall be determined by the Administrative Agent by reference to the respective Commitments of the Lenders, except that, if the face amount of a Bankers’ Acceptance would not be One Hundred Thousand Canadian Dollars (Cdn.$100,000) or a whole multiple thereof, the face amount shall be increased or reduced by the Administrative Agent in its sole discretion to the nearest whole multiple of One Hundred Thousand Canadian Dollars (Cdn.$100,000);
(ii)
unless requested by the Borrower not to purchase the subject Bankers’ Acceptances, each Lender shall transfer to the Administrative Agent at the Branch for value on each Borrowing Date immediately available Canadian Dollars in an aggregate amount equal to the BA Discount Proceeds of all Bankers’ Acceptances accepted and sold or purchased by the Lender on such



- 18 -

Borrowing Date, net of the applicable Bankers’ Acceptance Fees in respect of such Bankers’ Acceptances. Each Lender shall also advise the Administrative Agent (which shall promptly give the relevant particulars to the Borrower) as soon as possible of the discount rate at which it has sold or purchased its Bankers’ Acceptances;
(iii)
if the Borrower requests the Lenders not to purchase the subject Bankers’ Acceptances, each Lender will forward the subject Bankers’ Acceptances to the Administrative Agent for delivery against payment of the applicable Bankers’ Acceptance Fees; and
(iv)
if the Administrative Agent determines that all the conditions precedent to a Borrowing specified in this Agreement have been met or waived, it shall advance to the Borrower the amount delivered by each Lender by crediting the Borrower’s Account prior to 12:00 p.m. on the Borrowing Date, or, if applicable shall deliver the Bankers’ Acceptances as directed by the Borrower, but if the conditions precedent to the Borrowing are not met or waived by 2:30 p.m. on the Borrowing Date, the Administrative Agent shall return the funds to the Lenders or invest them in an overnight investment as orally instructed by each Lender until such time as the Advance is made.
(d)
Payment. The Borrower shall provide for the payment to the Administrative Agent for the account of the Lenders of the face amount of each Bankers’ Acceptance at its maturity, either by payment of the amount thereof or through utilization of the Credit Facility in accordance with this Agreement (by rolling over the Bankers’ Acceptance or converting it into other Accommodation or a combination thereof). The Borrower will continue to be required to provide as aforesaid for each Bankers’ Acceptance at maturity notwithstanding the fact that a Lender may be the holder of the Bankers’ Acceptance which has been accepted by such Lender.
(e)
Collateralization.
(i)
If any Bankers’ Acceptance is outstanding on the Demand Date or the Maturity Date, the Borrower shall on such date pay to the Administrative Agent for the account of the Lenders at the Branch in Canadian Dollars an amount equal to the face amount of such Bankers’ Acceptance.
(ii)
All funds received by the Administrative Agent pursuant to this Subsection 2.7(e) shall be held by the Administrative Agent for set-off on the maturity date of the Bankers’ Acceptance against the liability of the Borrower to the Lender in respect of such Bankers’ Acceptance and, until then, shall be invested from time to time in such form of investment at the Branch designated by the Borrower and approved by the Administrative Agent, for a term corresponding to the Maturity Date of the applicable Bankers’ Acceptance and shall bear interest at the rate payable by the Administrative Agent on deposits of similar currency, amount and maturity. The balance of all such funds (together with interest thereon) held by the



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Administrative Agent will be applied to repayment of all debts and liabilities of the Borrower to the Lender under this Agreement and the Credit Documents and following repayment of all such debts and liabilities any amount remaining shall be paid to the Borrower or as otherwise required by law.
(f)
Notice of Rollover or Conversion. The Borrower shall give the Administrative Agent notice in the form attached as Schedule 2(C) not later than 12:00 p.m. (Toronto, Ontario time) at least two (2) Business Days prior to the maturity date of Bankers’ Acceptances having an aggregate principal amount equal to or exceeding Two Hundred and Fifty Thousand Canadian Dollars (Cdn.$250,000), specifying the Accommodation into which the Bankers’ Acceptances will be renewed or converted on maturity.
(g)
Obligations Absolute. The obligations of the Borrower with respect to Bankers’ Acceptances under this Agreement shall be unconditional and irrevocable, and shall be paid strictly in accordance with the terms of this Agreement under all circumstances, including, without limitation, the following circumstances:
(i)
any lack of validity or enforceability of any Draft accepted by a Lender as a Bankers’ Acceptance; or
(ii)
the existence of any claim, set-off, defence or other right which the Borrower may have at any time against the holder of a Bankers’ Acceptance, a Lender or any other person or entity, whether in connection with this Agreement or otherwise.
(h)
Shortfall on Drawdowns, Rollovers and Conversions. The Borrower agrees that:
(i)
the difference between the amount of a Borrowing requested by the Borrower by way of Bankers’ Acceptance and the actual proceeds of the Bankers’ Acceptance;
(ii)
the difference between the actual proceeds of a Bankers’ Acceptance, and the amount required to pay a maturing Bankers’ Acceptance if a Bankers’ Acceptance is being rolled over; and
(iii)
the difference between the actual proceeds of a Bankers’ Acceptance and the amount required to repay any Borrowing which is being converted to a Bankers’ Acceptance,
shall be funded and paid by the Borrower from its own resources, by 12:00 p.m. (Toronto, Ontario time) on the day of the Borrowing or may be advanced as a Prime Rate Loan if the Borrower is otherwise entitled to such Accommodation and the Administrative Agent will apply such Prime Rate Loan to discharge the obligations of the Borrower under such Bankers’ Acceptance. Any such Prime Rate Loan so made shall be subject to the terms and provisions of this Agreement, including payment of interest at the rates specified in Section 3.1.



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(i)
Depository Bills and Notes Act. At the option of any Lender, Bankers’ Acceptances under this Agreement to be accepted by that Lender may be issued in the form of Depository Bills for a deposit with the Canadian Depository for Securities Limited pursuant to the Depository Bills and Notes Act (Canada). All Depository Bills so issued shall be governed by the provisions of this Section 2.7.
2.8
Safekeeping of Drafts
The responsibility of the Administrative Agent and the Lenders in respect of the safekeeping of Drafts, Bankers’ Acceptances, Discount Notes and other bills of exchange which are delivered to any of them hereunder shall be limited to the exercise of the same degree of care which such party gives to its own property, provided that such party shall not be deemed to be an insurer thereof.
2.9
Certification to Third Parties
The Administrative Agent will promptly provide to the Borrower and third parties at the request of the Borrower a certificate as to the Canadian Dollar Amount of Accommodations outstanding from time to time under this Agreement, and giving such other particulars in respect of the Indebtedness as the Borrower may reasonably request.
2.10
BA Equivalent Loans and Discount Notes
(a)
Whenever the Borrower requests a Loan by way of Bankers’ Acceptances, each Non-Acceptance Lender shall, in lieu of accepting a Bankers’ Acceptance, make a BA Equivalent Loan in an amount equal to the Non-Acceptance Lender’s percentage of the Loan.
(b)
As set out in the definition of Bankers’ Acceptances, that term includes Discount Notes and all terms of this Agreement applicable to Bankers’ Acceptances shall apply equally to Discount Notes evidencing BA Equivalent Loans with such changes as may in the context be necessary. For greater certainty:
(i)
the term of a Discount Note shall be the same as the term for Bankers’ Acceptances accepted and purchased on the same Borrowing Date in respect of the same Loan;
(ii)
an acceptance fee will be payable in respect of a Discount Note and shall be calculated at the same rate and in the same manner as the acceptance fee in respect of a Bankers’ Acceptance; and
(iii)
the CDOR rate applicable to a Discount Note shall be the CDOR rate applicable to Bankers’ Acceptances accepted by a Lender on the same drawdown, rollover or conversion, as the case may be, in respect of the same Loan.
2.11
Successor CDOR Rate.



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(a)
Notwithstanding anything to the contrary in this Agreement, if the Administrative Agent determines (which determination shall be final, conclusive and binding upon the Borrower absent manifest error), or the Borrower or the Majority Lenders notify the Administrative Agent (with, in the case of the Majority Lenders, a copy to Borrower) that the Borrower or the Majority Lenders (as applicable) have determined, that:
(i)
adequate and reasonable means do not exist for ascertaining the CDOR rate for any requested Contract Period, including because the Reuters “CDOR Page” (or any display substitutes therefor) of Reuters (or any successor thereof or Affiliate thereof) (the “Screen Rate”) is not available or published on a current basis and such circumstances are unlikely to be temporary; or
(ii)
the administrator of the applicable Screen Rate or a Government Authority having jurisdiction over the Administrative Agent has made a public statement identifying a specific date after which the applicable Screen Rate shall no longer be made available, or used for determining the interest rate of loans (such specific date, the “Scheduled Unavailability Date”); or
(iii)
syndicated loans currently being executed, or that include language similar to that contained in this Section 2.11, are being executed or amended (as applicable) to incorporate or adopt a new benchmark interest rate to replace the CDOR rate or the “CDOR Page” (or any display substitutes therefor) of Reuters (or any successor thereof or Affiliate thereof), as applicable,
then, reasonably promptly after such determination by the Administrative Agent or receipt by the Administrative Agent of such notice, as applicable, the Administrative Agent and the Borrower may amend this Agreement to replace the CDOR rate with an alternate benchmark rate selected by the Administrative Agent and the Borrower (including any mathematical or other adjustments to the benchmark (if any) incorporated therein), giving due consideration to any evolving or then existing convention for similar multi-currency syndicated credit facilities for such alternative benchmarks (any such proposed rate, a “Successor Rate”), together with any proposed Successor Rate Conforming Changes, and any such amendment shall become effective at 5:00 p.m., Toronto time, on the fifth Business Day after the Administrative Agent shall have posted such proposed amendment to all Lenders and the Borrower unless, prior to such time, the Lenders comprising the Majority Lenders have delivered to the Administrative Agent written notice that the Majority Lenders do not accept such amendment.
(b)
If no Successor Rate has been determined and the circumstances under Section 2.11(a) exist or the Scheduled Unavailability Date has occurred (as applicable), the Administrative Agent will promptly so notify the Borrower and each Lender. Thereafter, the Lenders shall not be required to honour any Advance or Borrowing Notice, as applicable, requesting a Borrowing by way of a BA Instrument under this Agreement. Upon receipt of such notice, (A) the Borrower may revoke any pending request for a conversion to or rollover of such BA Instrument (to the extent of the



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affected BA Instrument or Contract Period, as applicable) or, failing that, will be deemed to have converted such request into a request for conversion or rollover to a Prime Rate Loan in the amount specified therein, and (B) the Borrower hereby instructs the Administrative Agent to repay each affected BA Instrument with the proceeds of a Prime Rate Loan, as applicable, in each case to be drawn down on the last day of the then current Contract Period.
(c)
Notwithstanding anything else herein, any definition of “Successor Rate” shall provide that in no event shall such Successor Rate be less than zero for purposes of this Agreement.
(d)
For purposes of this Section 2.11, “Successor Rate Conforming Changes” means, with respect to any proposed Successor Rate, any conforming changes to the definition of Contract Period, timing and frequency of determining rates and making payments of interest and other administrative matters as may be appropriate, in the discretion of the Administrative Agent, to reflect the adoption of such Successor Rate and to permit the administration thereof by the Administrative Agent in a manner substantially consistent with market practice (or, if the Administrative Agent determines that adoption of any portion of such market practice is not administratively feasible or that no market practice for the administration of such Successor Rate exists, in such other manner of administration as the Administrative Agent determines in consultation with the Borrower).
ARTICLE 3    
INTEREST
3.1
Interest on Prime Rate Loans
Each Prime Rate Loan shall bear interest (both before and after demand, maturity, default and, to the extent permitted by law, judgment, with interest on overdue interest at the same rate) from and including the Borrowing Date for such Loan to, but not including, the date of repayment of such Loan on the unpaid principal amount of such Loan at a nominal rate per annum equal to the Prime Rate plus the Applicable Margin, which shall, in each case, change automatically without notice to the Borrower as and when: (i) the Prime Rate shall change so that at all times the rates set forth above shall be the Prime Rate then in effect; and (ii) the Applicable Margin shall change so that at all times the Applicable Margin shall be computed on the basis of the actual rating of the Borrower then in effect. Interest on each Prime Rate Loan shall be computed on the basis of the actual number of days elapsed divided by 365 or 366, as applicable. Interest in respect of outstanding Prime Rate Loans shall be payable monthly in arrears on the first Business Day of each month; provided, however, that interest on overdue interest shall be payable on demand.
3.2
Interest on Overdue Amounts
The Borrower will on demand pay interest to the Administrative Agent on all amounts (other than as provided in Section 3.1) payable by the Borrower pursuant to this Agreement that are not paid when due at the Prime Rate plus the Applicable Margin plus 2% per annum, in the case of amounts payable in Canadian Dollars, calculated daily and compounded monthly from the date of payment



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until paid in full (both before and after demand, maturity, default and, to the extent permitted by law, judgment), with interest on overdue interest at the same rate.
3.3
Other Interest
The Borrower shall pay interest on all amounts payable hereunder at the rate specified herein or, if no rate is specified, at the Prime Rate plus the Applicable Margin calculated daily and compounded monthly, from the date due until paid in full (both before and after demand, maturity, default and, to the extent permitted by law, judgment).
3.4
Interest Act (Canada)
For the purpose of the Interest Act (Canada), and disclosure thereunder, whenever any interest or any fee to be paid hereunder or in connection herewith is to be calculated on the basis other than a calendar year, the yearly rate of interest to which the rate used in such calculation is equivalent is the rate so used, multiplied by the actual number of days in the calendar year in which the same is to be ascertained and divided by the number of days used in the basis of such determination.
The Borrower and the General Partner acknowledge and confirm that this Section 3.4 satisfies the requirements of Section 4 of the Interest Act (Canada) to the extent it applies to the expression or statement of any interest payable under this Agreement and that each of the Borrower and the General Partner is able to calculate the yearly rate or percentage of interest payable under this Agreement based upon the methodology set out in this Section 3.4. The Borrower and the General Partner each agree not to plead or assert, whether by way of defence or otherwise, in any proceeding relating to this Agreement, that the interest payable hereunder and the calculation of interest herein have not been adequately disclosed to them, whether pursuant to Section 4 of the Interest Act (Canada) or any other Applicable Law or legal principle.
3.5
Deemed Reinvestment Principle
For the purpose of the Interest Act (Canada), the principle of deemed reinvestment of interest shall not apply to any interest calculation under this Agreement and the rates of interest stipulated in this Agreement are intended to be nominal rates and not effective rates or yields.
3.6
Maximum Return
It is the intent of the parties hereto that the return to the Lenders pursuant to this Agreement shall not exceed the maximum return permitted under the laws of Canada and if the return to the Lenders would, but for this provision, exceed the maximum return permitted under the laws of Canada, the return to the Lenders shall be limited to the maximum return permitted under the laws of Canada and this Agreement shall automatically be modified without the necessity of any further act or deed to give effect to the restriction on return set forth above.
3.7
Inability to Determine Rates
(a)
If the Administrative Agent or Lenders determine that for any reason a market for Bankers’ Acceptances does not exist at any time or the Lenders cannot for other reasons, after reasonable efforts, readily sell Bankers’ Acceptances or perform their



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other obligations under this Agreement with respect to Bankers’ Acceptances, the Administrative Agent will promptly so notify the Borrower and each Lender. Thereafter, the Borrower’s right to request the acceptance of Bankers’ Acceptances shall be and remain suspended until the Lenders determine and the Administrative Agent notifies the Borrower and each Lender that the condition causing such determination no longer exists. Any notice of drawdown or rollover in respect of a Bankers’ Acceptance which is outstanding shall be cancelled and any outstanding notice of conversion to convert a Prime Rate Loan into a Bankers’ Acceptance shall be cancelled and the request for a drawdown or rollover by means of Bankers’ Acceptance shall be deemed to be a request for a drawdown of, or rollover to, a Prime Rate Loan in the face amount of the requested Bankers’ Acceptance.
(b)
If a Market Disruption Event occurs for the Majority Lenders, which Lenders shall have aggregate Commitments representing at least 66.7% of the total Commitment (the “Requisite Disruption Lenders”), in relation to a Prime Rate Loan, Bankers’ Acceptance or Discount Note for any period, then the rate of interest on such Prime Rate Loan, Bankers’ Acceptance or Discount Note for such period (which, in any event, will not commence prior to the date the Borrower is notified in writing of such Market Disruption Event) for such Requisite Disruption Lenders shall be the rate per annum which is the sum of:
(i)
the Applicable Margin for such Prime Rate Loan, Bankers’ Acceptance or Discount Note for such period; plus
(ii)
the rate notified by such Requisite Disruption Lenders to the Borrower as soon as practicable and, in any event, before interest is due to be paid in respect of that period, to be that which expresses as a percentage rate per annum the cost to such Lenders of funding the Prime Rate Loan, Bankers’ Acceptance or Discount Note from whatever source they may reasonably select.
If a Market Disruption Event occurs with respect to Requisite Disruption Lenders and such Requisite Disruption Lenders, the Administrative Agent or the Borrower so requires, such Requisite Disruption Lenders, the Borrower and the Administrative Agent shall enter into negotiations (for a period of not more than 30 days) with a view to agreeing on a substitute basis for determining the rate of interest applicable in respect of such Requisite Disruption Lenders. Any alternative basis agreed pursuant to this Subsection 3.7(b) for such Requisite Disruption Lenders shall be binding on all such parties, it being agreed that such alternative basis shall apply only to such Requisite Disruption Lenders. In the absence of such agreement, the rate of interest applicable to any such Lender shall be the rate provided for above in this Subsection 3.7(b). If a Market Disruption Event occurs with respect to Requisite Disruption Lenders at any time, the Borrower may request that any outstanding notice of drawdown by way of, or rollover of Bankers’ Acceptance be deemed to be a request for a drawdown of, or conversion to, a Prime Rate Loan and that any outstanding notice of conversion to convert a Prime Rate Loan into a Bankers’ Acceptance shall be cancelled.



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ARTICLE 4    
FEES
4.1
Acceptance Fees
Upon the acceptance of any Draft pursuant to this Agreement, the Borrower will pay to the Administrative Agent for the account of the relevant Lenders an acceptance fee in Canadian Dollars calculated on the face amount and the term of such Draft, in accordance with the Applicable Margin in effect on the date of acceptance. The acceptance fees payable by the Borrower shall be calculated on the face amount of the Bankers’ Acceptance or the principal amount of a Discount Note, and shall be calculated on the basis of the number of days in the term of such Bankers’ Acceptance or Discount Note, as the case may be.
4.2
Standby Fee
The Borrower shall pay to the Administrative Agent a standby fee in Canadian Dollars so long as the Administrative Agent has not demanded or the Lenders have not ceased to make further advances under Section 11.2, calculated in accordance with the Applicable Margin on the amount of the Undisbursed Credit in existence during the period of calculation and as adjusted automatically upon any change thereof. Accrued standby fees shall be calculated quarterly and be due and payable quarterly in arrears on the first Business Day after the end of each quarter of each Fiscal Year of the Borrower.
4.3
Basis of Calculation of Fees
The fees payable under Sections 4.1, 4.2 and 4.3 with respect to any period shall be calculated on the basis of the actual number of days in such period divided by three hundred and sixty-five (365) days or three hundred and sixty-six (366) days, as the case may be.
ARTICLE 5    
PAYMENT
5.1
Voluntary Repayment of Outstanding Accommodations
(a)
Repayments. The Borrower shall have the right to voluntarily repay, which for the purpose of (i), (ii) and (iii) below includes renewals and conversions of, outstanding Accommodations from time to time on any Business Day without premium on the terms and conditions set forth in this Section and thereby permanently reducing the Credit Facility:
(i)
with respect to any voluntary repayment of Accommodation, unless the Administrative Agent with the consent of the Lenders otherwise approves, the Canadian Dollar Amount of Accommodation included in such repayment shall be Ten Million Canadian Dollars (Cdn.$10,000,000) or whole multiples of One Million Canadian Dollars (Cdn.$1,000,000) or the entire amount of that type of Accommodation outstanding, and the Borrower shall give the Administrative Agent a written notice of repayment, specifying the amount, the type or types of Accommodation(s) to be included in the repayment (and



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where such Accommodation includes any Loan, the currency thereof and the interest rate applicable thereto) and the applicable voluntary repayment date, which notice shall be irrevocable by the Borrower. The notice of repayment shall be given to the Administrative Agent not later than 12:00 p.m. (Toronto, Ontario time) on the second Business Day preceding the applicable repayment date in the case of Loans with a Canadian Dollar Amount in the aggregate equal to or greater than Ten Million Canadian Dollars (Cdn.$10,000,000);
(ii)
in all other cases, notice of repayment shall be given on the applicable repayment date;
(iii)
any notice of repayment received by the party entitled thereto on any Business Day after 12:00 p.m. (Toronto, Ontario time) shall be deemed to have been given to such party on the next succeeding Business Day. A notice of repayment of Accommodation may be included as part of a Borrowing Notice in respect of other Accommodation; and
(iv)
on the applicable voluntary repayment date the Borrower shall pay to the Administrative Agent for the account of the Lenders, the amount of any Accommodation that is subject to the repayment, together with all interest and other fees and amounts accrued, unpaid and due in respect of such repayment; provided, however, that accrued interest will not be repayable prior to the applicable interest payment date in Section 3.1 in respect of Prime Rate Loans unless the full balance outstanding thereunder is voluntarily repaid.
(b)
Repayment of Accommodations in form of Bankers’ Acceptances or Discount Notes. No repayment of any outstanding Accommodation in the form of a Bankers’ Acceptance or Discount Note shall be made otherwise than upon its expiration or maturity date.
5.2
Repayment on Maturity Date and Extension
(a)
Subject to Subsection 2.7(e) and to this Section, the Borrower shall repay in full all outstanding Accommodations, together with all interest, fees and other amounts payable hereunder on the Maturity Date to the Administrative Agent for the account of the Lenders.
(b)
By notice in writing to the Administrative Agent in the form of Schedule 3 (a “Notice of Extension”) given not more than 90 and not less than 45 days prior to each anniversary date of the date of this Agreement, the Borrower may request each Lender to extend the Maturity Date of such Lender for an additional period of 365 days. The Lenders agree that they shall give or withhold their consent in a timely manner so that the Administrative Agent may provide a response to the Borrower to the Notice of Extension within thirty (30) days from the date of such receipt, provided that the decision of any Lender to extend the Maturity Date in respect of such Lender shall be at the sole discretion of such Lender. The Borrower shall be entitled to



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replace any Lender which dissents in response to the Notice of Extension (a “Dissenting Lender”) with another existing Lender or Lenders without the consent of any of the remaining Lenders; or to replace a Dissenting Lender with any financial institution which is not an existing Lender with the consent of the Administrative Agent, such consent not to be unreasonably withheld. The Borrower shall be entitled, with the unanimous consent of the Lenders who have agreed to extend, to permanently cancel the Commitment of any Dissenting Lender and repay such Dissenting Lender, at which time the Committed Amount shall be permanently reduced by the amount of such Commitment.
5.3
Excess Accommodations
In addition to the other repayment rights, obligations or options set forth in this Article, if the aggregate Canadian Dollar Amount of all Accommodations outstanding under the Credit Facility at any time exceeds the then limit of the Credit Facility, the Borrower shall immediately upon request of the Administrative Agent repay such excess.
5.4
Illegality
Notwithstanding any other provision of this Agreement, if the making or continuation of any Accommodation shall have been made unlawful or prohibited due to compliance by any of the Administrative Agent and the Lenders in good faith with any change made after the date hereof in any law or governmental rule, regulation, guideline or order, or in any interpretation or application of any law or governmental rule, regulation, guideline or order by any competent authority, or with any request or directive (whether or not having the force of law) by any central bank, reserve board, superintendent of financial institutions or other comparable authority made after the date hereof, then the Administrative Agent will give notice thereof to the Borrower which shall repay such Accommodation within a reasonable period or such shorter period as may be required by law. During the continuation of any such event the Lenders will have no obligation under this Agreement to make or continue any Accommodations affected thereby.
ARTICLE 6    
PAYMENTS AND INDEMNITIES
6.1
Payments on Non-Business Days
Unless otherwise provided herein, whenever any payment to be made under this Agreement shall be stated to be due on a day which is not a Business Day, the due date thereof shall be extended to the next succeeding Business Day, and interest or fees shall be payable at the appropriate rate during such extension.
6.2
Method and Place of Payment
Unless otherwise provided herein, all payments made by the Borrower to the Administrative Agent under this Agreement will be made not later than 2:00 p.m. (Toronto, Ontario time) on the date when due, and all such payments will be made in immediately available funds. Any amounts received after that time shall be deemed to have been received by the Administrative Agent on the next Business Day.



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6.3
Net Payments
All payments by the Borrower under this Agreement shall be made without set-off or counterclaim or other deduction and without regard to any equities between the Borrower and the Administrative Agent or any of the Lenders or any other Person and free and clear of, and without reduction for or on account of, any present or future levies, imposts, duties, charges, fees, deductions or other withholdings, and if the Borrower is required by law to withhold any amount, then the Borrower will increase the amount of such payment to an amount which will ensure that the Administrative Agent receives the full amount of the original payment.
6.4
Administrative Agent May Debit Account
The Administrative Agent may debit any accounts of the Borrower with the Administrative Agent for any payment or amount due and payable by the Borrower pursuant to this Agreement without further direction from the Borrower to the Administrative Agent; provided that any such debit is not in conflict with the provisions of the Trust Indenture but in any event such debits may be made in accordance with the Administrative Agent’s centralized cash management arrangements with the Borrower.
6.5
Currency of Payment
Accommodations shall be repaid by the Borrower to the Administrative Agent or a Lender as required under this Agreement in the currency in which such Accommodation was obtained. Any payment on account of an amount payable under this Agreement in a particular currency (the “Proper Currency”) required by any authority having jurisdiction to be made (or which a Lender elects to accept) in a currency (the “Other Currency”) other than the Proper Currency, whether pursuant to a judgment or order of any court or tribunal or otherwise, shall constitute a discharge of the Borrower’s obligations under this Agreement only to the extent of the amount of the Proper Currency which each applicable Lender is able, as soon as practicable after receipt by it of such payment, to purchase with the amount of the Other Currency so received. If the amount of the Proper Currency which a Lender is so able to purchase is less than the amount of the Proper Currency originally due to it, the Borrower shall indemnify and hold such Lender harmless from and against all losses, costs, damages or expenses which such Lender may sustain, pay or incur as a result of such deficiency. This indemnity shall constitute an obligation separate and independent from any other obligation contained in this Agreement, shall give rise to a separate and independent cause of action, shall apply irrespective of any indulgence granted by the Lenders from time to time, shall continue in full force and effect notwithstanding any judgment or order for a liquidated sum in respect of an amount due under this Agreement or under any judgment or order and shall not merge in any order of foreclosure made in respect of any of the security given by the Borrower to or for the benefit of any Lender.
6.6
Increased Costs
If after the date of this Agreement any change in any law, regulation, treaty, directive, reserve or special deposit requirement or in the interpretation or application thereof by any court or administrative or governmental authority charged with the administration thereof, or compliance by a Lender with any request or directive (whether or not having the force of law) by any central



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bank, reserve board, superintendent of financial institutions, fiscal, monetary or other comparable authority shall:
(a)
subject the Lender to any tax of any kind whatsoever with respect to this Agreement or any Accommodation or change the basis of taxation of payments to the Lender of principal, interest, fees or any other amount payable under this Agreement (except for changes in the rate of tax on the overall net income of the Lender or capital tax imposed by the laws of Canada or any political subdivision thereof or taxing authority therein); or
(b)
impose, modify or make applicable any capital adequacy, reserve, assessment, special deposit or loans or similar requirement against assets held by, or deposits or other liabilities in or for the account of, or Loans or other Accommodations, credit facilities or commitments made available by, or any other acquisition of funds by, the Lender;
and the result of any of the foregoing is to impose or increase the cost to the Lender of making or maintaining any part of the Credit Facility or any Accommodations or to reduce any amount receivable by the Lender under this Agreement with respect thereto, then, in any such case, the Borrower shall pay to the Administrative Agent for the account of the relevant Lender within thirty (30) days after the date of demand by the Administrative Agent such additional amounts necessary to fully compensate the Lender for such additional cost or reduced amount receivable. If a Lender becomes entitled to claim any additional amounts pursuant to this Section, the Administrative Agent shall promptly upon receipt of particulars from the relevant Lender notify the Borrower of the event by reason of which the Lender has become so entitled and provide the Borrower with an explanation of the manner in which the liability of the Borrower under this Section has been determined. A certificate of the Lender as to any such additional amounts payable to it shall be prima facie evidence of the amount due. The Borrower shall have no obligation under this Section if any increase is due to the action of or change of status of any Lender.
6.7
General Indemnity
The Borrower shall indemnify the Administrative Agent and the Lenders and their directors, officers, employees, attorneys and agents against and hold each of them harmless from any loss, liabilities, damages, claims, costs and expenses (including fees and expenses of counsel to the Administrative Agent and the Lenders on a solicitor and his own client basis and reasonable fees and expenses of all independent consultants) (each a “Claim”) suffered or incurred by any of them arising out of, resulting from or in any manner connected with or related to:
(a)
any Environmental Matter, Environmental Liability or Environmental Proceeding; and
(b)
any loss or expense incurred in liquidating or re-employing deposits from which such funds were obtained, which the Administrative Agent or Lender may sustain or incur as a consequence of:
(i)
failure by the Borrower in proceeding with a Borrowing after the Borrower has given a Borrowing Notice;



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(ii)
failure by the Borrower in repaying a Borrowing after the Borrower has given a notice of repayment;
(iii)
any breach, non-observance or non-performance by the Borrower of any of its obligations, covenants, agreements, representations or warranties contained in this Agreement; and
(iv)
the repayment of any Bankers’ Acceptance or Discount Note otherwise than on the maturity date thereof.
The indemnity set forth herein shall be in addition to any other obligations or liabilities of the Borrower to any of the Administrative Agent and the Lenders at common law or otherwise and this Section and Section 6.3 shall survive the repayment of the Accommodations and the termination of this Agreement. A certificate of the Lender as to any such loss or expense, providing details of the calculation of such loss or expense, shall be prima facie evidence.
6.8
Outstanding Bankers’ Acceptances or Discount Notes
If the Credit Facility is terminated at any time prior to the maturity date of any Bankers’ Acceptance or Discount Note issued hereunder, the Borrower shall pay to the Lenders, on demand, an amount with respect to each such Bankers’ Acceptance or Discount Note equal to the total amounts which would be required to purchase in the Canadian Dollars market, as of 10:00 a.m. (Toronto, Ontario time) on the date of payment of such demand, Government of Canada treasury bills in an aggregate amount equal to the face amount of such Bankers’ Acceptance and Discount Note and having in each case a term to maturity similar to the period from such demand to maturity of such Bankers’ Acceptance or Discount Note. Upon payment by the Borrower as required under this Section, the Borrower shall have no further liability in respect of each such Bankers’ Acceptance or Discount Note and the Lenders shall be entitled to all of the benefits of, and be responsible for all payments to third parties under such Bankers’ Acceptance or Discount Note, and the Lenders shall indemnify and hold harmless the Borrower in respect of all amounts which the Borrower may be required to pay under each such Bankers’ Acceptance or Discount Note to any party other than the Lenders.
6.9
Replacement of Lender
Notwithstanding any other item or condition of this Agreement, if the Borrower becomes obligated in respect of a Lender to pay any additional amounts as provided in Section 6.6 and such additional payments are of a permanent nature, then the Borrower may, at its option, upon thirty (30) Business Days notice to the Administrative Agent and that Lender (which notice shall be irrevocable):
(a)
require such Lender to assign its full Commitment under which such Advances were made (such commitments being the “Affected Commitments”) and all outstanding Advances thereunder, to one or more assignees identified by the Borrower and acceptable to the Administrative Agent, acting reasonably, the assignment(s) to which assignee(s) shall have been made in accordance with Section 12.15; or
(b)
terminate the Affected Commitments and repay to such Lender any Advances outstanding thereunder to the extent such Affected Commitments and Advances thereunder are not assigned pursuant to Subsection 6.9(a).



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ARTICLE 7    
SECURITY
7.1
Security
As general and continuing security for the due payment and performance of all present and future indebtedness, liabilities and obligations of the Borrower to the Administrative Agent and to the Lenders under this Agreement, the Borrower shall provide to the Administrative Agent on behalf of the Lenders a pledge of the Pledged Bond, such pledge to be pursuant to the Bond Delivery Agreement. The parties hereby confirm that all present and future indebtedness, liabilities and obligations of the Borrower to the Administrative Agent and the Lenders under this Agreement and the other Credit Documents shall constitute “Obligations” for the purposes of the Eighteenth Supplemental Indenture and shall be subject to the Pledged Bond.
ARTICLE 8    
REPRESENTATIONS AND WARRANTIES
8.1
Representations and Warranties
To induce the Lenders to make Accommodations available to the Borrower, each of the Borrower and the General Partner, in its personal capacity, represents and warrants to the Administrative Agent and the Lenders that the following are true and correct in all material respects:
(a)
the Borrower is a limited partnership existing pursuant to the terms of the Partnership Act (Alberta) and has the legal capacity and right to own its property and assets and to carry on the Business;
(b)
the General Partner is a corporation, duly and validly incorporated, organized and existing as a corporation under the laws of the Province of Alberta and has the legal capacity to act as the General Partner of the Borrower;
(c)
each of the Borrower and the General Partner has the legal capacity and right to enter into the Credit Documents and do all acts and things and execute and deliver all agreements, documents and instruments as are required thereunder to be done, observed or performed by it in accordance with the terms and conditions thereof;
(d)
each of the Borrower and the General Partner has taken all necessary action to authorize the creation, execution and delivery of each of the Credit Documents, the performance of its obligations thereunder and the consummation of the transactions contemplated thereby;
(e)
each of the Credit Documents has been duly executed and delivered by each of the Borrower and the General Partner and constitutes a valid and legally binding obligation of the Borrower enforceable against it in accordance with its terms, subject only to bankruptcy, insolvency, reorganization, arrangement or other statutes or judicial decisions affecting the enforcement of creditors’ rights in general and to general principles of equity under which specific performance and injunctive relief may be refused by a court in its discretion;



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(f)
there is no existing, pending or, to the knowledge of the Borrower or the General Partner, threatened litigation by or against either of them which could reasonably be expected to be adversely determined to the rights of the Borrower or the General Partner and which could reasonably be expected to cause a Material Adverse Effect; no event has occurred, and no state or condition exists, which could give rise to any such litigation; provided, however, that if the Borrower has disclosed to the Lenders litigation which is not in compliance with the foregoing and the Lenders have waived all or any part of such non-compliance, no further waiver shall be required in respect of such litigation to the extent that the same has been waived by the Lenders;
(g)
there has been no change which could reasonably be expected to cause a Material Adverse Effect;
(h)
the Borrower is in compliance with all Applicable Laws where any non-compliance could reasonably be expected to cause a Material Adverse Effect;
(i)
all Governmental Approvals and other consents necessary to permit the Borrower and the General Partner (i) to execute, deliver and perform each Credit Document and to consummate the transactions contemplated thereby, and (ii) to own and operate the Business, have been obtained or effected and are in full force and effect. The Borrower is in compliance with the requirements of all such Governmental Approvals and consents and there is no Claim existing, pending or, to the knowledge of the Borrower or the General Partner, threatened which could result in the revocation, cancellation, suspension or any adverse modification of any of such Governmental Approvals or consent (except as may hereafter arise and be disclosed to the Administrative Agent);
(j)
no Default or Event of Default under this Agreement or the Trust Indenture has occurred;
(k)
the Borrower has good and marketable title to its assets, in each case free and clear of all Security Interests, other than Permitted Encumbrances;
(l)
the Borrower has paid all taxes due and owing to date;
(m)
no essential portion of the Borrower’s real or leased property has been taken or expropriated by any Government Authority nor has written notice or proceedings in respect thereof been given or commenced nor is the Borrower aware of any intent or proposal to give any such notice or commence any such proceedings;
(n)
the Principal Property in the name of the General Partner is and will be held by the General Partner in trust for the Borrower;
(o)
except as disclosed to the Administrative Agent:



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(i)
the Borrower does not have any knowledge of any Environmental Adverse Effect or any condition existing at, on or under the Principal Property which, in any case or in the aggregate, with the passage of time or the giving of notice or both, could reasonably be expected to give rise to liability of the Borrower resulting in a Material Adverse Effect;
(ii)
the Borrower has no knowledge of any present or prior leaks or spills with respect to underground storage tanks and piping system or any other underground structures existing at, on or under Principal Property or of any past violations by any Applicable Laws, policies or codes of practice involving the Principal Property, which violations, in any case or in the aggregate, could reasonably be expected to have a Material Adverse Effect;
(iii)
the Borrower has no knowledge that it has any obligation under any Environmental Laws to pay any compensation or damages resulting from the operation of the Principal Property, or that it will have any such obligation resulting from the maintenance and operation of the Principal Property, which, in any case or in the aggregate, could reasonably be expected to have a Material Adverse Effect; and
(iv)
the Borrower has no Environmental Liability which, in any case or in the aggregate, could reasonably be expected to have a Material Adverse Effect except as disclosed by the Borrower to the Administrative Agent in writing prior to the Effective Date;
(p)
the Borrower is not as at the date that this representation is made or deemed to be made the subject of any civil, criminal or regulatory proceeding or governmental or regulatory investigation with respect to Environmental Laws nor is it aware of any threatened proceedings or investigations which, in any case or in the aggregate, could reasonably be expected to have a Material Adverse Effect except as disclosed in accordance with the notice requirements set out in Section 9.2. The Borrower is actively and diligently proceeding to use all reasonable efforts to comply with all Environmental Laws and all such activities are being carried on in a prudent and responsible manner and with all due care and due diligence;
(q)
as of the Effective Date, the Borrower has no Subsidiaries other than Permitted JA Subsidiaries;
(r)
the authorized capital of the General Partner consists of an unlimited number of common shares. All of the shares issued are duly issued and outstanding as fully paid and non-accessible. The sole beneficial holders of such outstanding shares are BHE Alberta Ltd. and BHE GP Holdings Ltd.;
(s)
no labour disturbance by the employees of the Borrower exist or, to the knowledge of the Borrower, is imminent, that could reasonably be expected to have a Material Adverse Effect;
(t)
the sole limited partner of the Borrower is AltaLink Investments, L.P.;



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(u)
all of the property of the Borrower is insured with good and responsible companies against fire and other casualties in the same manner and to the same extent as such insurance usually carried by Persons carrying on a similar business and owning similar property and the Borrower maintains or causes to be maintained with good and responsible insurance companies adequate insurance against business interruption with respect to the operations of all of such property and liability on account of damage to Persons or property, including damages resulting from product liability, and all applicable workers compensation laws, in the same manner and to the same extent as such insurance is usually carried by Persons carrying on a similar business and owning similar property;
(v)
there is no damage or destruction to any of the property of the Borrower by fire or other casualty which could have a Material Adverse Effect that has not been repaired; and
(w)
the Borrower’s existing Commercial Paper Program continues to be in full force and effect.
8.2
Survival of Representations and Warranties
All representations and warranties contained in this Agreement, the Credit Documents and any certificate or document delivered pursuant hereto shall survive the execution and delivery of this Agreement and the Credit Documents, the advance of each Accommodation and exercise of any remedies under this Agreement or under any of the Credit Documents, notwithstanding any investigation made at any time by or on behalf of the Administrative Agent or the Lenders.
ARTICLE 9    
COVENANTS
9.1
Trust Indenture
The Borrower covenants and agrees that so long as any Accommodation is outstanding or the Borrower is entitled to obtain any Accommodation under the Credit Facility, the Borrower will comply with all of the covenants, both positive and negative, contained in the Trust Indenture which are hereby incorporated by reference into this Agreement. Non-compliance by the Borrower with any of these covenants cannot be waived by the Lenders other than in accordance with Subsection 12.8(c).
9.2
Covenants
The Borrower covenants and agrees that, so long as any Accommodation is outstanding or the Borrower is entitled to obtain any Accommodation under the Credit Facility:
(a)
Information and Certificates. The Borrower shall furnish to the Administrative Agent, with sufficient copies for all Lenders:
(i)
at the time the same are sent, copies of all financial statements and other information or material that are delivered to the Trustee under the Trust



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Indenture including, without limitation, notice of any “Event of Default” under the Trust Indenture;
(ii)
copies of any Supplemental Indenture which amends in any way the Trust Indenture; and
(iii)
upon delivery of each of the items set out in Paragraphs 6.4(a)(i) and (ii) of the Trust Indenture, the Borrower’s Certificate of Compliance; provided, however, that the obligation of the Borrower to deliver quarterly unaudited financial statements to the Administrative Agent shall apply only to the first, second and third fiscal quarters of each Fiscal Year.
(b)
Payments Under This Agreement and Credit Documents. The Borrower shall pay, discharge or otherwise satisfy all amounts payable under this Agreement in accordance with the terms of this Agreement and all amounts payable under any Credit Document in accordance with the terms thereof.
(c)
Proceeds. The Borrower shall use the proceeds of any Accommodation only for the purposes permitted pursuant to Section 2.1.
(d)
Inspection of Property, Books and Records, Discussions. The Borrower shall keep proper books of record and account in which full, true and correct entries in conformity with GAAP and all Applicable Laws shall be made of all dealings and transactions in relation to its business and activities, and permit representatives and agents of the Administrative Agent upon reasonable notice to the Borrower and during business hours, to visit and inspect any of the properties and examine and make abstracts from any of the books and records of the Borrower as often as may reasonably be desired, and, subject to applicable securities laws, to discuss the business, operations, property, condition and prospects (financial or otherwise) of the Borrower with those officers and employers of the Borrower designated by its senior executive officers.
(e)
Anti-Money Laundering and Terrorist Financing. The Borrower has taken, and shall continue to take, commercially reasonable measures (in any event as required by Applicable Laws) to ensure that it is and shall be in compliance with the Proceeds of Crime (Money Laundering) and Terrorist Financing Act (Canada) and all other present and future Applicable Laws of similar application to which the Borrower is subject.
(f)
Notices. The Borrower shall promptly give notice to the Administrative Agent of:
(i)
the occurrence of any Default or Event of Default;
(ii)
the commencement of, or receipt by the Borrower of a written threat of, any action, suit or proceeding against or affecting the Borrower before any Government Authority which, individually or in the aggregate, has, or has any reasonable likelihood of having, a Material Adverse Effect, and such



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further information in respect thereof as the Administrative Agent may request from time to time;
(iii)
any notice of any violation or administrative or judicial complaint or order having been filed or, to the Borrower’s knowledge, about to be filed against the Borrower which has, or has any reasonable likelihood of having, a Material Adverse Effect;
(iv)
any notice from any Government Authority or any other Person alleging that the Borrower is or may be subject to any Environmental Liability which has, or has any reasonable likelihood of having, a Material Adverse Effect;
(v)
the occurrence or non-occurrence of any other event which has, or has a reasonable likelihood of having, a Material Adverse Effect;
(vi)
any changes in the ownership structure to the Borrower; and
(vii)
any notice of a change in rating to the Senior Bonds by any of the Rating Agencies.
(g)
Permitted Joint Arrangements. (i) The total equity investment of the Borrower in Permitted JA Subsidiaries and Permitted Joint Arrangements shall not exceed an aggregate amount equal to Cdn.$200,000,000; and (ii) the Borrower shall not form any Subsidiaries other than Permitted JA Subsidiaries and shall not enter into any joint ventures or joint arrangements other than Permitted Joint Arrangements. The Borrower shall deliver to the Administrative Agent not later than sixty (60) days after the end of each fiscal quarter, an Officer’s Certificate certifying as to the matters in this Paragraph (g) including regarding what portion of the above Cdn.$200,000,000 has been used and how/where it has been used.
9.3
Maintenance of Total Capitalization
(a)
The Borrower covenants and agrees that, so long as any Accommodation is outstanding or the Borrower is entitled to obtain any Accommodation under the Credit Facilities, the aggregate amount of all Indebtedness of the Borrower (other than Financial Instrument Obligations in accordance with section 6.3 of the Trust Indenture) shall not exceed seventy-five percent (75%) of the Total Capitalization of the Borrower. For greater certainty, for the purposes of this Section 9.3, (i) the foregoing calculations of both the aggregate amount of all Indebtedness of the Borrower and the Total Capitalization of the Borrower shall exclude any non-recourse debt incurred by Permitted JA Subsidiaries in connection with their related Permitted Joint Arrangements as well as any equity contributions made in respect of such Permitted Joint Arrangements, to the extent in each case that the Borrower is in compliance with Subsection 9.2(g) in respect of such joint arrangement, and (ii) when ascertaining maintenance of Total Capitalization for this purpose, the exclusions shall apply to both the numerator component of that definition (ie exclusion of the related debt) and to the denominator component of that definition (ie exclusion of the related debt and equity).



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(b)
The Borrower shall deliver to the Administrative Agent not later than sixty (60) days after the end of each fiscal quarter, an Officer’s Certificate certifying as to the matter in Paragraph (a) above.
ARTICLE 10    
CONDITIONS PRECEDENT TO BORROWINGS
10.1
Conditions Precedent to Effectiveness of this Agreement
The effectiveness of this Agreement is subject to the condition precedent that the Administrative Agent and each Lender shall be satisfied with, or the Borrower shall have delivered to the Administrative Agent, as the case may be, on or before the Effective Date, the following in form, substance and dated as of a date satisfactory to the Lenders and their counsel and in sufficient quantities for each Lender:
(a)
there shall exist no Default or Event of Default on the Effective Date;
(b)
all representations and warranties contained in Section 8.1 shall be true on and as of the Effective Date with the same effect as if such representations and warranties had been made on and as of the Effective Date and, if required by the Administrative Agent, the Borrower shall have delivered to the Administrative Agent a Borrower’s Certificate of Compliance;
(c)
the Administrative Agent and the Lenders shall have received any Credit Documents required by the Administrative Agent and the Lenders duly executed by the Borrower;
(d)
the following documents in form, substance and execution acceptable to the Administrative Agent shall have been delivered to the Administrative Agent:
(i)
duly certified copies of the constating documents of the Borrower and the General Partner and of all necessary proceedings taken and required to be taken by the Borrower to authorize the execution and delivery of this Agreement and the Credit Documents to which it is a party and the entering into and performance of the transactions contemplated herein and therein;
(ii)
certificates of incumbency of the General Partner setting forth specimen signatures of the persons authorized to execute this Agreement and the Credit Documents to which it is a party;
(iii)
certificate of status or the equivalent relative to the Borrower and the General Partner under the laws of Canada or its jurisdiction of creation; and
(iv)
the opinion of counsel for the Borrower in form and substance satisfactory to the Administrative Agent and the Lenders;
(e)
the Administrative Agent and the Lenders shall have received evidence that all necessary corporate, governmental and other third party approvals have been



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obtained in form and substance acceptable to the Administrative Agent and the Lenders, each acting reasonably;
(f)
all fees payable on or before the date hereof in connection with the Credit Facility under this Agreement and the Fee Letter shall have been paid to the applicable parties; and
(g)
the Administrative Agent and the Lenders are satisfied in their sole and absolute discretion that all of the provisions of Article 9 have been complied with to their satisfaction.
10.2
Conditions Precedent to All Borrowings, Conversions
The Lenders shall not be obliged to make available any portion of any Borrowing or to give effect to any conversion or rollover unless the Borrower (by way of the delivery of a Borrower’s Certificate of Compliance), or the Borrower’s counsel (if appropriate), confirms to the Administrative Agent that each of the following conditions is satisfied:
(a)
the Administrative Agent shall have received any required Borrowing Notice;
(b)
there shall exist no Default or Event of Default on the said Borrowing Date;
(c)
all representations and warranties contained in Section 8.1 shall be true on and as of the applicable Borrowing Date with the same effect as if such representations and warranties had been made on and as of the applicable Borrowing Date and, if required by the Administrative Agent, the Borrower shall have delivered to the Administrative Agent a Borrower’s Certificate of Compliance;
(d)
all fees payable on or before the date of any subsequent Borrowing under the Fee Letter and this Agreement shall have been paid to the applicable party as and when due and payable thereunder; and
(e)
the Trust Indenture shall not have been amended in a manner which (i) could reasonably be expected to have a Material Adverse Effect; or (ii) modifies any section of the Trust Indenture which is incorporated by reference into this Agreement without the prior written consent of the Administrative Agent.
10.3
Waiver
The Lenders may, at their option, waive any condition precedent set out in Section 10.1 or 10.2 or make available any Borrowing prior to such condition precedent being fulfilled. Any such Borrowing shall be deemed to be made pursuant to the terms hereof. Any such waiver shall not be effective unless it is in writing and shall not operate to excuse the Borrower from full and complete compliance with this Article 10 or any other provision hereof on future occasions.
ARTICLE 11    
EVENTS OF DEFAULT
11.1
Events of Default



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Any of the following events shall constitute an “Event of Default” hereunder:
(a)
Trust Indenture. Each of the events set out in Section 10.1 of the Trust Indenture including applicable notice and grace periods;
(b)
Default in Payment of any Amount Hereunder. If the Borrower fails to pay any interest, fees or any amount owing to the Lenders or any of them hereunder (other than principal amounts), or under any Credit Document when due and payable hereunder or thereunder and the Borrower fails to pay such interest, fees or any amount owing to the Lenders or any of them hereunder (other than principal amounts) within five (5) Business Days after notice is given by the Administrative Agent to the Borrower. For clarity, the failure to pay a principal payment shall be an immediate Event of Default and the Administrative Agent shall have the remedies available pursuant to Section 11.2;
(c)
Default in Other Provisions. If the Borrower shall fail, refuse or default in any material respect with the performance or observance of any of the covenants, agreements or conditions contained herein and such failure, refusal or default adversely affects the Lenders and, such failure, refusal or default continues for a period of thirty (30) days after written notice thereof by the Administrative Agent; and
(d)
Full Force and Effect. If this Agreement or any material portion hereof shall, at any time after its respective execution and delivery and for any reason, cease in any way to be in full force and effect or if the validity or enforceability of this Agreement is disputed in any manner by the Borrower and the Credit Facility have not been repaid within 30 days of demand therefor by the Administrative Agent.
11.2
Remedies
Upon the occurrence of any Default or Event of Default, and at any time thereafter if the Default or Event of Default shall then be continuing, the Lenders in their sole discretion may direct the Administrative Agent to give notice to the Borrower that no further Accommodation will be available hereunder while the Default or Event of Default continues, whereupon the Lenders shall not be obliged to provide any further Borrowings to the Borrower while the Default or Event of Default continues. Upon the occurrence of any Event of Default, and at any time thereafter if the Event of Default shall then be continuing, the Lenders in their sole discretion, and the Administrative Agent acting on their behalf, may take any or all of the following actions:
(a)
demand payment of any principal, accrued interest, fees and other amounts which are then due and owing in respect of the Accommodations under the Credit Facility without presentment, protest or other notice of any kind, all of which are hereby expressly waived by the Borrower to the maximum extent permitted by Applicable Laws;
(b)
declare by notice to the Borrower the Credit Facility terminated, whereupon the same shall terminate immediately without any further notice of any kind;



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(c)
demand payment of the Pledged Bond in accordance with the provisions of the Bond Delivery Agreement; and
(d)
assign all or any part of the outstanding Accommodations and the amounts payable hereunder to any Person without reference to Article 12.
11.3
Remedies Cumulative
The rights and remedies of the Lenders and the Administrative Agent under this Agreement and the Credit Documents are cumulative.
11.4
Appropriation of Moneys Received
The Lenders, and the Administrative Agent on behalf of the Lenders as between the Lenders and the Borrower, may from time to time when an Event of Default has occurred and is continuing appropriate any monies received from the Borrower in or toward payment of such of the obligations of the Borrower hereunder as the Lenders in their sole discretion may see fit.
11.5
Non-Merger
The taking of any action or dealing whatsoever by the Lender or the Administrative Agent in respect of the Borrower or any security shall not operate as a merger of any of the obligations of the Borrower to the Lenders or the Administrative Agent or in any way suspend payment or affect or prejudice the rights, remedies and powers, legal or equitable, which the Lenders or the Administrative Agent may have under Section 11.3 in connection with such obligations.
11.6
Waiver
No delay on the part of the Lenders or the Administrative Agent in exercising any right or privilege hereunder shall operate as a waiver thereof. No Default or Event of Default shall be waived except by a written waiver in accordance with Section 13.10. Each written waiver shall apply only to the Default or Event of Default to which it is expressed to apply. No written waiver shall preclude the subsequent exercise by the Lenders or the Administrative Agent of any right, power or privilege hereunder or extend to or apply to any other Default or Event of Default.
11.7
Set-off
Each of the Administrative Agent and any Lender with whom the Borrower maintains any account or accounts shall enter into an agreement with the Trustee, in form and substance satisfactory to the Trustee, pursuant to which the Administrative Agent or such Lender, as applicable, confirms to the Trustee that:
(a)
in respect of any Funds and Accounts (as defined in the Trust Indenture) forming part of the Collateral (as defined in the Trust Indenture), the Trustee has a security interest in such Funds and Accounts and the cash on deposit therein are Permitted Investments forming part thereof;



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(b)
the Administrative Agent or such Lender, as applicable, has and will have no security interest in any such Fund or Account or the cash on deposit therein or Permitted Investments forming part thereof; and
(c)
the only rights of set-off which may be exercised by the Administrative Agent or such Lender in respect of any such Fund or Account or the cash on deposit therein or Permitted Investments forming part thereof are those arising out of the operation of the relevant account unless the Administrative Agent or such Lender has agreed to remit all amounts so set-off to the Trustee to be dealt with in accordance with the Trust Indenture;
provided that none of the foregoing shall apply to rights of set-off exercised by the Administrative Agent in the ordinary course of the operation of the Administrative Agent’s centralized cash management system with the Borrower.
Upon the occurrence of an Event of Default and a demand by the Administrative Agent for payment pursuant to Section 11.3, the Administrative Agent and each Lender is hereby authorized by the Borrower at any time and from time to time with notice to the Borrower to combine, consolidate and merge on behalf of the Trustee for the benefit of the Bondholders (as defined in the Trust Indenture) all or any of the Borrower’s Accounts with liabilities to the Administrative Agent or such Lender and to set-off, appropriate and apply on behalf of the Trustee for the benefit of such bondholders or to otherwise seize and remit to the Trustee any and all deposits by or for the benefit of the Borrower with any branch of the Administrative Agent or such Lender, general or special, matured or unmatured, and any other indebtedness and liability of the Administrative Agent or such Lender to the Borrower, matured or unmatured, against and on account of the indebtedness of the Borrower hereunder when due, notwithstanding that the balances of such accounts, deposits or indebtedness may or may not be expressed in the same currency.
ARTICLE 12    
THE ADMINISTRATIVE AGENT AND THE LENDERS
12.1
Authorization of Administrative Agent and Relationship
Each Lender hereby appoints BNS as Administrative Agent and BNS hereby accepts such appointment. The appointment may only be terminated as expressly provided in this Agreement. Each Lender hereby authorizes the Administrative Agent to take all action on its behalf and to exercise such powers and perform such duties under this Agreement as are expressly delegated to the Administrative Agent by its terms, together with all powers reasonably incidental thereto. Except as expressly specified in this Agreement, the Administrative Agent shall have only those duties and responsibilities of a solely mechanical and administrative nature that are expressly delegated to the Administrative Agent by this Agreement or are reasonably incidental thereto. The Administrative Agent may perform such duties by or through its agents or employees, but shall not by reason of this Agreement have a fiduciary duty in respect of any Lender. As to any matters not expressly provided for by this Agreement, the Administrative Agent is not required to exercise any discretion or to take any action, but is required to act or to refrain from acting (and is fully protected in so acting or refraining from acting) upon the instructions of the Lenders or the Majority Lenders, as the case may be. Those instructions shall be binding upon all Lenders, but the Administrative Agent



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is not required to take any action which exposes the Administrative Agent to personal liability or which is contrary to this Agreement or Applicable Laws.
12.2
Disclaimer of Administrative Agent
The Administrative Agent makes no representation or warranty, and assumes no responsibility with respect to the due execution, legality, validity, sufficiency, enforceability or collectability of this Agreement or any other Credit Document. The Administrative Agent assumes no responsibility for the financial condition of the Borrower, or for the performance of its obligations under this Agreement or any other Credit Document. The Administrative Agent assumes no responsibility with respect to the accuracy, authenticity, legality, validity, sufficiency or enforceability of any documents, papers, materials or other information furnished by the Borrower to the Administrative Agent on behalf of the Lenders. The Administrative Agent shall not be required to ascertain or inquire as to the performance or observance of any of the terms, conditions, provisions, covenants or agreements contained herein or as to the use of the proceeds of any credit hereunder or (unless the officers or employees of the Lender acting as Administrative Agent active in their capacity as officers or employees on the Borrower’s accounts have actual knowledge thereof, or have been notified thereof in writing by the Borrower or a Lender) of the existence or possible existence of any Default or Event of Default. Neither the Administrative Agent nor any of its directors, officers, agents or employees shall be liable for any action taken or omitted to be taken by it or them as Administrative Agent under or in connection with the Agreement, whether in the good faith exercise of any discretion expressly granted to the Administrative Agent or otherwise, except for actions or omissions arising from its or their own negligence or wilful misconduct. With respect to its Commitment, the Lender acting as Administrative Agent shall have the same rights and powers hereunder as any other Lender, and may exercise the same as though it were not performing the duties and functions delegated to it as Administrative Agent hereunder.
12.3
Failure of Lender to Fund
(a)
Unless the Administrative Agent has actual knowledge that a Lender has not made or will not make available to the Administrative Agent for value on a Borrowing Date the applicable amount required from such Lender pursuant to Article 2, the Administrative Agent shall be entitled to assume that such amount has been or will be received from such Lender when so due and the Administrative Agent may (but shall not be obliged to), in reliance upon such assumption, make available to the Borrower a corresponding amount. If such amount is not in fact received by the Administrative Agent from such Lender on such Borrowing Date and the Administrative Agent has made available a corresponding amount to the Borrower on such Borrowing Date as aforesaid, such Lender shall pay to the Administrative Agent on demand an amount equal to the product of (i) the rate per annum then in use at the Branch as a syndicate lender late payment rate, multiplied by (ii) the amount that should have been paid to the Administrative Agent by such Lender on such Borrowing Date and was not, multiplied by (iii) a fraction, the numerator of which is the number of days that have elapsed from and including such Borrowing Date to but excluding the date on which the amount is received by the Administrative Agent from such Lender and the denominator of which is three hundred and sixty-five (365). A certificate of the Administrative Agent containing details of the amount



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owing by a Lender under this Section shall be binding and conclusive in the absence of manifest error. If any such amount is not in fact received by the Administrative Agent from such Lender on such Borrowing Date, the Administrative Agent shall be entitled to recover from the Borrower, on demand, the related amount made available by the Administrative Agent to the Borrower as aforesaid together with interest thereon at the applicable rate per annum payable by the Borrower hereunder.
(b)
Notwithstanding the provisions of Subsection 12.3(a), if any Lender fails to make available to the Administrative Agent its Proportionate Share of any Advance (such Lender being herein called the “Defaulting Lender”), the Administrative Agent shall forthwith give notice of such failure by the Defaulting Lender to the other Lenders. The Administrative Agent shall then forthwith give notice to the other Lenders that any Lender may make available all or any portion of the Defaulting Lender’s share of such Advance in the place of the Defaulting Lender, but in no way shall any other Lender or the Administrative Agent be obliged to do so. If more than one Lender gives notice that it is prepared to make funds available in the place of a Defaulting Lender in such circumstances and the aggregate of the funds which such Lenders (herein collectively called the “Contributing Lenders” and individually called the “Contributing Lender”) are prepared to make available exceeds the amount of the Advance which the Defaulting Lender failed to make, then each Contributing Lender shall be deemed to have given notice that it is prepared to make available a portion of such Advance based on the Contributing Lenders’ relative Proportionate Shares. If any Contributing Lender makes funds available in the place of a Defaulting Lender in such circumstances, then the Defaulting Lender shall pay to any Contributing Lender making the funds available in its place, forthwith on demand any amount advanced on its behalf together with interest thereon at the rate applicable to such Advance from the date of advance to the date of payment, against payment by the Contributing Lender making the funds available of all interest received in respect of the Advance from the Borrower. The failure of any Lender to make available to the Administrative Agent its Proportionate Share of any Advance as required herein shall not relieve any other Lender of its obligations to make available to the Administrative Agent its Proportionate Share of any Advance as required herein.
12.4
Replacement of Lenders
(a)
If any Lender defaults in its obligation to fund any Loan hereunder, then the Borrower may, at its sole expense and effort, upon 10 days’ prior notice to such Lender and the Administrative Agent, require such Lender to assign and delegate, without recourse, all of its interests, rights and obligations under this Agreement and the related Credit Documents to an assignee that shall assume such obligations (which assignee may be another Lender, if a Lender accepts such assignment), provided that;
(i)
the Borrower pays the Administrative Agent an assignment fee specified in Subsection 12.4(b);



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(ii)
the assigning Lender receives payment of an amount equal to the outstanding principal of its Loans and accrued fees and all other amounts payable to it hereunder and under the other Credit Documents from the Assignee, defined below (to the extent of such outstanding principal and accrued interest and fees) or the Borrower (in the case of all other amounts); and
(iii)
such assignment does not conflict with Applicable Laws.
A Lender shall not be required to make any such assignment or delegation if, prior thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the Borrower to require such assignment and delegation cease to apply.
(b)
Any Lender (herein sometimes called an “Assigning Lender”) may, with the prior written consent of the Administrative Agent and unless an Event of Default has occurred, with the prior written consent of the Borrower, in each case not to be unreasonably withheld or delayed, assign all or any part of its rights to, and may have its obligations in respect of the Credit Facility assumed by, one or more financial institutions or other entities (each an “Assignee”) in minimum amounts of Cdn.$10,000,000 and in Cdn.$5,000,000 increments. Without limiting the generality of the foregoing, no Lender shall assign any portion of its Commitment (as set out on Schedule 5) if, after that assignment, the Assigning Lender’s commitment would be less than Cdn.$10,000,000. An assignment shall become effective when the Borrower and the Administrative Agent have been notified of it by the Assigning Lender and have received from the parties to the assignment an executed assignment and assumption agreement (the “Lender Assignment Agreement”), in a form reasonably satisfactory to the Administrative Agent, and the Administrative Agent has received from the Assignee an assignment fee of a minimum of Three Thousand, Five Hundred Canadian Dollars (Cdn.$3,500) per Lender per assignment. From and after the effective date specified in the Lender Assignment Agreement, the Assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Lender Assignment Agreement, shall have the rights and obligations of a Lender under this Agreement to the same extent as if it were an original party in respect of the rights or obligations assigned to it, and the Assigning Lender shall be released and discharged accordingly and to the same extent, and such Schedules as applicable shall be amended accordingly from time to time without further notice or other requirement. Each partial assignment shall be made as an assignment of a proportionate part of all of the Assigning Lender’s rights and obligations under this Agreement with respect to the Borrowing or the Commitment assigned.
12.5
Payments by the Borrower
Unless otherwise expressly provided in this Agreement as among the Lenders, all payments made by or on behalf of the Borrower pursuant to this Agreement shall be made to and received by the Administrative Agent and shall be distributed by the Administrative Agent to the Lenders as soon as possible upon receipt by the Administrative Agent. Subject to any other provision of this Agreement concerning the distribution of payments, the Administrative Agent shall cause distribution of:



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(a)
payments of interest in accordance with each Lender’s Advanced Share of the Advances to which the payment relates;
(b)
repayments of principal in accordance with each Lender’s Advanced Share of the Advances to which the payment relates;
(c)
payments of standby fees in accordance with Section 4.3; and
(d)
all other payments including, without limitation, amounts received upon realization, in accordance with each Lender’s Proportionate Share; provided, however, that with respect to proceeds of realization, no Lender shall receive an amount in excess of the amounts owing to it in respect of the Accommodations.
Subject to Section 12.6, if the Administrative Agent does not distribute a Lender’s share of a payment made by the Borrower to that Lender for value on the day that payment is made or deemed to have been made to the Administrative Agent, the Administrative Agent shall pay to the Lender on demand an amount equal to the product of (i) the rate per annum then in use at the Branch as a syndicate lender late payment rate, multiplied by (ii) the Lender’s share of the amount received by the Administrative Agent from the Borrower and not so distributed, multiplied by (iii) a fraction, the numerator of which is the number of days that have elapsed from and including the date of receipt of the payment by the Administrative Agent to but excluding the date on which the payment is made by the Administrative Agent to such Lender and the denominator of which is three hundred and sixty-five (365).
12.6
Payments by Administrative Agent
(a)
For greater certainty, the following provisions shall apply to any and all payments made by the Administrative Agent to the Lenders hereunder:
(i)
the Administrative Agent shall be under no obligation to make any payment (whether in respect of principal, interest, fees or otherwise) to any Lender until an amount in respect of such payment has been received by the Administrative Agent from the Borrower;
(ii)
if the Administrative Agent receives less than the full amount of any payment of principal, interest, fees or other amount owing by the Borrower under this Agreement, the Administrative Agent shall have no obligation to remit to each Lender any amount other than such Lender’s share of that amount which is actually received by the Administrative Agent;
(iii)
if a Lender’s share of an Advance has been advanced, or a Lender’s Commitment has been outstanding, for less than the full period to which any payment (other than a payment of principal) by the Borrower relates, such Lender’s entitlement to such payment shall be reduced in proportion to the length of time such Lender’s share of the Advance or such Lender’s Commitment, as the case may be, has actually been outstanding;



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(iv)
the Administrative Agent acting reasonably and in good faith shall, after consultation with the Lenders in the case of any dispute, determine in all cases the amount of all payments to which each Lender is entitled and such determination shall, in the absence of manifest error, be binding and conclusive; and
(v)
upon request, the Administrative Agent shall deliver a statement detailing any of the payments to the Lenders referred to herein.
(b)
Unless the Administrative Agent has actual knowledge that the Borrower has not made or will not make a payment to the Administrative Agent for value on the date in respect of which the Borrower has notified the Administrative Agent that the payment will be made, the Administrative Agent shall be entitled to assume that such payment has been or will be received from the Borrower when due and the Administrative Agent may (but shall not be obliged to), in reliance upon such assumption, pay the Lenders corresponding amounts. If the payment by the Borrower is in fact not received by the Administrative Agent on the required date and the Administrative Agent has made available corresponding amounts to the Lenders, the Borrower shall, without limiting its other obligations under this Agreement, indemnify the Administrative Agent against any and all liabilities, obligations, losses, damages, penalties, costs, expenses or disbursements of any kind or nature whatsoever that may be imposed on or incurred by the Administrative Agent as a result. A certificate of the Administrative Agent with respect to any amount owing by the Borrower under this Section shall be prima facie evidence of the amount owing in the absence of manifest error. The Administrative Agent shall be entitled to recover from each Lender to which a payment is made in reliance on the expectation of payment from the Borrower in accordance with this Section, the full amount of such payment that is not recovered from the Borrower, together with interest at the rate per annum then in use at the Branch as a syndicate lender late payment rate, from the date on which payment is made by the Administrative Agent to the date on which repayment is made by the Lender receiving such payment.
12.7
Direct Payments
The Lenders agree among themselves that, except as otherwise provided for in this Agreement, all sums received by a Lender relating to this Agreement whether received by voluntary payment, by the exercise of the right of set-off or compensation or by counterclaim, cross-action or otherwise, shall be shared by each Lender so that the ultimate exposure of each Lender is in accordance with its Advanced Share of all Advances under this Credit Facility, and each Lender undertakes to do all such things as may be reasonably required to give full effect to this Section, including without limitation, the purchase from other Lenders of their proportionate interest in the Borrowings by the Lender who has received an amount in excess of its Proportionate Share of amounts advanced under this Credit Facility as shall be necessary to cause such purchasing Lender to share the excess amount rateably with the other Lenders to the extent of their Advanced Share of any Advances under this Credit Facility. If any Lender shall obtain any payment of moneys due under this Agreement as referred to above, it shall forthwith remit such payment to the Administrative Agent and, upon



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receipt, the Administrative Agent shall distribute such payment in accordance with the provisions of Section 12.6.
12.8
Administration of the Credit Facility
(a)
Unless otherwise specified herein, the Administrative Agent shall perform the following duties under this Agreement:
(i)
prior to any Borrowing, provided that the Administrative Agent has received confirmation from the Borrower (by way of the delivery of a Borrower’s Certificate of Compliance or Borrowing Notice, as applicable), or the Borrower’s counsel (if appropriate), that the conditions in Sections 10.1 and 10.2 have been complied with, as applicable, advise the Lenders that all conditions precedent have been fulfilled in accordance with the terms of this Agreement, subject to Subsection 12.9(b) and any other applicable terms of this Agreement;
(ii)
use reasonable efforts to collect promptly all sums due and payable by the Borrower pursuant to this Agreement;
(iii)
hold all legal documents relating to the Credit Facility, maintain complete and accurate records showing all Advances made by the Lenders, all remittances and payments made by the Borrower to the Administrative Agent, all remittances and payments made by the Administrative Agent to the Lenders and all fees or any other sums received by the Administrative Agent and, except for accounts, records and documents relating to the fees payable under any separate fee agreement, allow each Lender and their respective advisers to examine such accounts, records and documents at their own expense, and provide any Lender, upon reasonable notice, with such copies thereof as such Lender may reasonably require from time to time at the Lender’s expense;
(iv)
except as otherwise specifically provided for in this Agreement, promptly advise each Lender upon receipt of each notice and deliver to each Lender, promptly upon receipt, all other written communications furnished by the Borrower to the Administrative Agent on behalf of the Lenders pursuant to this Agreement, including without limitation copies of financial reports and certificates which are to be furnished to the Administrative Agent;
(v)
forward to each of the Lenders, upon request, copies of this Agreement, and other Credit Documents (other than any separate fee agreement);
(vi)
promptly forward to each Lender, upon request, an up-to-date loan status report; and
(vii)
upon learning of same, promptly advise each Lender in writing of the occurrence of an Event of Default or Default or the occurrence of any event, condition or circumstance which would have a Material Adverse Effect on



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the ability of the Borrower to comply with this Agreement or of the occurrence of any material adverse change on the business, operations or assets of the Borrower, taken as a whole, provided that, except as aforesaid, the Administrative Agent shall be under no duty or obligation whatsoever to provide any notice to the Lenders and further provided that each Lender hereby agrees to notify the Administrative Agent of any Event of Default or Default of which it may reasonably become aware.
(b)
The Administrative Agent may take the following actions only with the prior consent of the Majority Lenders, unless otherwise specified in this Agreement:
(i)
subject to Subsection 12.8(c), exercise any and all rights of approval conferred upon the Lenders by this Agreement;
(ii)
amend, modify or waive any of the terms of this Agreement (including waiver of an Event of Default or Default) if such amendment, modification or waiver would have a Material Adverse Effect on the rights of the Lenders thereunder and if such action is not otherwise provided for in Subsection 12.8(c);
(iii)
declare an Event of Default or take action to enforce performance of the obligations of the Borrower and pursue any available legal remedy necessary;
(iv)
decide to accelerate the amounts outstanding under the Credit Facility; and
(v)
pay insurance premiums, taxes and any other sums as may be reasonably required to protect the interests of the Lenders.
(c)
The Administrative Agent may take the following actions only if the prior unanimous consent of the Lenders is obtained, unless otherwise specified herein:
(i)
amend, modify, discharge, terminate or waive any of the terms of this Agreement if such amendment, modification, discharge, termination or waiver would amend the Canadian Dollar Amount of any Accommodation outstanding, reduce the interest rate applicable to any Accommodation, reduce the fees or other amounts payable with respect to any Accommodation, extend any date fixed for payment of principal, interest or other amounts relating to the Credit Facility or extend the Maturity Date of the Credit Facility;
(ii)
amend the definition of “Majority Lenders” or this Subsection 12.8(c); and
(iii)
release, discharge or amend the Security Interest granted by the Borrower in favour of the Trustee.
(d)
Notwithstanding Subsection 12.8(b) and any other provision of this Agreement except for Subsection 12.8(c), in the absence of instructions from the Lenders and where, in the sole opinion of the Administrative Agent, acting reasonably and in good faith, the exigencies of the situation warrant such action to protect the interests



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of the Lenders, the Administrative Agent may without notice to or consent of the Lenders take such action on behalf of the Lenders as the Administrative Agent deems appropriate or desirable.
(e)
As between the Borrower, the Administrative Agent and the Lenders:
(i)
all statements, certificates, consents and other documents which the Administrative Agent purports to deliver on behalf of the Lenders or the Majority Lenders shall be binding on each of the Lenders, and the Borrower shall not be required to ascertain or confirm the authority of the Administrative Agent in delivering such documents;
(ii)
all certificates, statements, notices and other documents which are delivered by the Borrower to the Administrative Agent in accordance with this Agreement shall be deemed to have been duly delivered to each of the Lenders, except where this Agreement expressly requires delivery of notices of Advances and payments to the Administrative Agent and/or individual Lenders; and
(iii)
all payments which are delivered by the Borrower to the Administrative Agent in accordance with this Agreement shall be deemed to have been duly delivered to each of the Lenders.
12.9
Rights of Administrative Agent
(a)
In administering the Credit Facility, the Administrative Agent may retain, at the expense of the Lenders if such expenses are not recoverable from the Borrower, such solicitors, counsel, auditors and other experts and agents as the Administrative Agent may select, in its sole discretion, acting reasonably and in good faith after consultation with the Lenders.
(b)
The Administrative Agent shall be entitled to rely on any communication, instrument or document believed by it to be genuine and correct and to have been signed by the proper individual or individuals, and shall be entitled to rely and shall be protected in relying as to legal matters upon opinions of independent legal advisers selected by it. The Administrative Agent may also assume that any representation made by the Borrower is true and that no Event of Default or Default has occurred unless the officers or employees of the Administrative Agent have actual knowledge to the contrary or have received notice to the contrary from any other party to this Agreement.
(c)
The Administrative Agent may, without any liability to account, accept deposits from and lend money to and generally engage in any kind of banking or other business with the Borrower, as if it were not the Administrative Agent.
(d)
Except in its own right as a Lender, the Administrative Agent shall not be required to advance its own funds for any purpose, and in particular, shall not be required to pay with its own funds insurance premiums, taxes or public utility charges or the



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cost of repairs or maintenance with respect to the assets which are the subject matter of any security, nor shall it be required to pay with its own funds the fees of solicitors, counsel, auditors, experts or agents engaged by it as permitted hereby.
(e)
The Administrative Agent shall be entitled to receive a fee for acting as Administrative Agent, as agreed between the Administrative Agent and the Borrower pursuant to the terms of the Fee Letter.
12.10
Acknowledgements, Representations and Covenants of Lenders
(a)
It is acknowledged and agreed by each Lender that it has itself been, and will continue to be, solely responsible for making its own independent appraisal of and investigations into the financial condition, creditworthiness, property, affairs, status and nature of the Borrower. Accordingly, each Lender confirms to the Administrative Agent that it has not relied, and will not hereafter rely, on the Administrative Agent (i) to check or inquire on its behalf into the adequacy or completeness of any information provided by the Borrower under or in connection with this Agreement or the transactions herein contemplated (whether or not such information has been or is hereafter distributed to such Lender by the Administrative Agent) or (ii) to assess or keep under review on its behalf the financial condition, creditworthiness, property, affairs, status or nature of the Borrower.
(b)
Each Lender represents and warrants to the Administrative Agent and the Borrower that it has the legal capacity to enter into this Agreement pursuant to its constating documents and any applicable legislation and has not violated its constating documents or any applicable legislation by so doing.
(c)
Each Lender agrees to indemnify the Administrative Agent (to the extent not reimbursed by the Borrower), rateably according to its Proportionate Share, from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever which may be imposed on, incurred by, or asserted against the Administrative Agent in any way relating to or arising out of the Credit Documents or the transactions therein contemplated, provided that no Lender shall be liable for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from the Administrative Agent’s negligence or wilful misconduct. Without limiting the generality of the foregoing, each Lender agrees to reimburse the Administrative Agent promptly upon demand for its Proportionate Share of any out-of-pocket expenses (including counsel fees) incurred by the Administrative Agent in connection with the preservation of any rights of the Administrative Agent or the Lenders under, or the enforcement of, or legal advice in respect of rights or responsibilities under this Agreement, to the extent that the Administrative Agent is not reimbursed for such expenses by the Borrower. The obligation of the Lenders to indemnify the Administrative Agent shall survive the termination of this Agreement.



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(d)
Each of the Lenders acknowledges and confirms that in the event the Administrative Agent does not receive payment in accordance with this Agreement, it shall not be the obligation of the Administrative Agent to maintain the Credit Facility in good standing nor shall any Lender have recourse to the Administrative Agent in respect of any amounts owing to such Lender under this Agreement.
(e)
Each Lender acknowledges and agrees that its obligation to advance its Proportionate Share of Advances in accordance with the terms of this Agreement is independent and in no way related to the obligation of any other Lender hereunder.
(f)
Each Lender hereby acknowledges receipt of a copy of this Agreement and acknowledges that it is satisfied with the form and content of such documents.
(g)
Except to the extent recovered by the Administrative Agent from the Borrower, promptly following demand therefor, each Lender shall pay to the Administrative Agent an amount equal to such Lender’s Proportionate Share of any and all reasonable costs, expenses, claims, losses and liabilities incurred by the Administrative Agent in connection with this Agreement, except for those incurred by reason of the Administrative Agent’s negligence or wilful misconduct.
12.11
Collective Action of the Lenders
Each of the Lenders hereby acknowledges that to the extent permitted by Applicable Laws, the remedies provided under the Credit Documents to the Lenders are for the benefit of the Lenders collectively and acting together and not severally and further acknowledges that its rights hereunder and under any security are to be exercised not severally, but by the Administrative Agent upon the decision of the Majority Lenders or Lenders as required by this Agreement. Accordingly, notwithstanding any of the provisions contained herein, each of the Lenders hereby covenants and agrees that it shall not be entitled to take any action hereunder or thereunder including, without limitation, any declaration of default hereunder or thereunder but that any such action shall be taken only by the Administrative Agent with the prior written agreement of the Majority Lenders. Each of the Lenders hereby further covenants and agrees that upon any such written agreement being given by the Majority Lenders, it shall co-operate fully with the Administrative Agent to the extent requested by the Administrative Agent.
12.12
Successor Administrative Agent
Subject to the appointment and acceptance of a Successor Administrative Agent as provided in this Section, the Administrative Agent may resign at any time by giving thirty (30) days’ written notice thereof to the Lenders and the Borrower and may be removed at any time by all Lenders other than the Lender that is acting as Administrative Agent, upon thirty (30) days’ written notice of termination. Upon receipt of notice by the Lenders of the resignation of the Administrative Agent, or upon giving notice of termination to the Administrative Agent, the Majority Lenders (taking into account the Proportionate Share of the resigning or terminated Administrative Agent) may, within twenty-one (21) days and with the approval of the Borrower, such approval not to be unreasonably withheld or delayed, appoint a successor from among the Lenders or, if no Lender is willing to accept such an appointment, from among other financial institutions which each have combined capital and reserves in excess of Two Hundred and Fifty Million Canadian Dollars (Cdn.$250,000,000), and which have



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offices in Toronto, Ontario (the “Successor Administrative Agent”). If no Successor Administrative Agent has been so appointed and has accepted such appointment within twenty-one (21) days after the retiring Administrative Agent’s giving of notice of resignation or receiving of notice of termination, then the retiring Administrative Agent may, on behalf of the Lenders, appoint a Successor Administrative Agent in accordance herewith. Upon the acceptance of any appointment as Administrative Agent hereunder by a Successor Administrative Agent, the retiring Administrative Agent shall pay the Successor Administrative Agent any unearned portion of any fee paid to the Administrative Agent for acting as such, and the Successor Administrative Agent shall succeed to and become vested with all the rights, powers, privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent shall be discharged from its further duties and obligations as Administrative Agent under this Agreement and the other Credit Documents. After any retiring Administrative Agent’s resignation hereunder as Administrative Agent, the provisions of this Article shall continue to enure to its benefit and be binding upon it as to any actions taken or omitted to be taken by it while it was Administrative Agent hereunder.
12.13
Provisions Operative Between Lenders and Administrative Agent Only
Except for the provisions of Subsections 12.8(e), 12.10(b), Sections 12.11, 12.12, 12.14, 12.15 and 12.16, the provisions of this Article relating to the rights and obligations of the Lenders and the Administrative Agent shall be operative as between the Lenders and the Administrative Agent only, and the Borrower shall not have any rights or obligations under or be entitled to rely for any purpose upon such provisions.
12.14
Assignments and Participation - Approvals
A Lender may:
(a)
upon notice to the Borrower grant participation (a “Participation”) in all or any part of the rights, benefits and obligations of the Lenders hereunder to one or more Persons (each a “Participant”); or
(b)
assign (an “Assignment”) all or part of the rights, benefits and obligations of such Lender hereunder to one or more Persons (each an “Assignee”);
with the prior consent of the Borrower and the Administrative Agent, which consent may be withheld by any such party in its sole discretion. Any such Participant or Assignee may grant further Participation to other Participants or make further assignments to other Assignees; with the prior consent of the Borrower and the Administrative Agent, which consent may be withheld by any such party in its sole discretion. Notwithstanding the foregoing, no grant to a Participant or Assignment to an Assignee shall require the consent of the Borrower at a time when any Event of Default has occurred and is continuing.
12.15
Assignments
(a)
Subject to Section 12.14, the Lenders collectively or individually may assign to one or more Assignees all or a portion of their respective rights and obligations under this Agreement (an undivided portion thereof corresponding to the portion of the Commitment being assigned) by way of Assignment. The parties to each such



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Assignment shall execute and deliver an Assignment Agreement in the form set out in Schedule 4 to the Borrower, and to the Administrative Agent for its consent and recording in the Register and, except in the case of an Assignment by the Lenders collectively or an Assignment by a Lender to an affiliate of that Lender, shall pay a processing and recording fee of Three Thousand, Five Hundred Canadian Dollars (Cdn.$3,500) to the Administrative Agent. After such execution, delivery, consent and recording the Assignee thereunder shall be a party to this Agreement and, to the extent that rights and obligations hereunder have been assigned to it, have the rights and obligations of a Lender hereunder and the assigning Lender thereunder shall, to the extent that rights and obligations hereunder have been assigned by it pursuant to such Assignment Agreement, relinquish its rights and be released from its obligations under this Agreement, other than obligations in respect of which it is then in default and liabilities arising from its actions prior to the Assignment, and, in the case of an Assignment Agreement covering all or the remaining portion of an assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto. The Lenders agree that, provided that no Event of Default under this Agreement or the Trust Indenture has occurred, no assignment shall be made which would result in any increased costs to the Borrower.
(b)
The agreements of an Assignee contained in an Assignment Agreement shall benefit the assigning Lender thereunder, the other Lenders, the Administrative Agent and the Borrower in accordance with the terms of the Assignment Agreement.
(c)
The Administrative Agent shall maintain at its address referred to herein a copy of each Assignment Agreement delivered and consented to by the Lender and, where required, by the Borrower and a register for recording the names and addresses of the Lenders and the Commitment of each Lender from time to time (the “Register”). The entries in the Register shall be conclusive and binding for all purposes, absent manifest error. The Borrower, the Administrative Agent and each of the Lenders may treat each Person whose name is recorded in the Register as a Lender hereunder for all purposes of this Agreement, and need not recognize any Person as a Lender unless it is recorded in the Register as a Lender. The Register shall be available for inspection by any Lender or the Borrower at any reasonable time and from time to time upon reasonable prior notice.
(d)
Upon its receipt of an Assignment Agreement executed by an assigning Lender and an Assignee and approved by the Administrative Agent, and, where required, by the Borrower, the Administrative Agent shall, if the Assignment Agreement has been completed and is in the required form with such immaterial changes as are acceptable to the Administrative Agent:
(i)
record the information contained therein in the Register; and
(ii)
give prompt notice thereof to the other Lenders and the Borrower, and provide them with an updated version of Schedule 5.
12.16
Participation



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Each Lender may (subject to the provisions of Section 12.14) grant Participation to one or more financial institutions in or to all or a portion of its rights and obligations under this Agreement (including, without limitation, all or a portion of its Commitment), but the Participant shall not become a Lender and:
(a)
the Lender’s obligations under this Agreement (including, without limitation, its Commitment) shall remain unchanged;
(b)
the Lender shall remain solely responsible to the other parties hereto for the performance of such obligations;
(c)
the Borrower, the Administrative Agent and the other Lenders shall continue to deal solely and directly with the Lender in connection with the Lender’s rights and obligations under this Agreement; and
(d)
no Participant shall have any right to participate in any decision of the Lender or the Majority Lenders hereunder or to approve any amendment or waiver of any provision of this Agreement, or any consent to any departure by any Person therefrom.
ARTICLE 13    
MISCELLANEOUS
13.1
Expenses
The Borrower shall, whether or not any or all of the transactions hereby contemplated shall be consummated, pay all reasonable costs and expenses of the Administrative Agent and the Lenders in connection with the preparation, execution, delivery, registration granting or obtaining of consents or approvals or the exercise of any discretion under this Agreement, the Credit Documents and all related documentation and the amendment and enforcement of, and the preservation of any of the Administrative Agent’s and Lender’s rights under, this Agreement, the Credit Documents and all related documentation, provided that any legal counsel retained will represent both the Administrative Agent and the Lenders and no costs or expenses for legal counsel incurred by any Lender individually shall be payable pursuant to this Section 13.1.
13.2
Further Assurances
The Borrower shall, from time to time forthwith upon reasonable request by the Administrative Agent do, make and execute all such documents, acts, matters and things as may be required by the Administrative Agent to give effect to this Agreement and any of the Credit Documents.
13.3
Notices
Any notice or communication to be given hereunder may be effectively given by delivering the same to the addresses hereafter set forth or by sending the same by facsimile to the numbers hereafter set forth. Any notice so delivered shall be deemed to have been received on the date delivered and any facsimile notice shall be deemed to have been received on transmission, if in either case the date thereof is a Business Day and if it is prior to 4:00 p.m. (Toronto, Ontario time) and, if not, on the next Business Day following delivery or transmission. The addresses for delivery and numbers



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for facsimiles of the parties for the purposes hereof shall be as set forth on the execution pages of this Agreement. Any party may from time to time notify the other party, in accordance with the provisions hereof, of any change of its address or facsimile number which thereafter, until changed by like notice, shall be the address or facsimile number of such party for all purposes of this Agreement.
If to the Administrative Agent and/or Co-Lead Arranger and Co-Bookrunner:
The Bank of Nova Scotia
Global Banking and Markets
40 King Street West, 62
nd Floor
Toronto, Ontario M5W 2X6

Attention:    Director
Facsimile:    (416) 866-3329
Email:         agency.services@scotiabank.com
If to the Syndication Agent and/or Co-Lead Arranger and Co-Bookrunner:
Royal Bank of Canada
Royal Bank Plaza
200 Bay Street, 4th Floor, South Tower
P.O. Box 50
Toronto, Ontario M5J 2W7

Attention:    Managing Director
Facsimile:    (416) 842-5320
If to the Co-Documentation Agents:
Bank of Montreal
BMO Capital Markets
Suite 900, 525 – 8th Avenue SW
Calgary, Alberta T2P 1G1

Attention:    Carol McDonald, Director
Facsimile:    (403) 515-3650
and:
National Bank of Canada
Corporate & Investment Banking Group
450 – 1st Street SW, Suite 2802
Calgary, Alberta T2P 5H1

Attention:    James Dexter
Facsimile:    (403) 294-3078



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If to the Lenders:
The Toronto-Dominion Bank
Investment Banking
66 Wellington Street West, 9th Floor
Toronto, Ontario M5K 1A2

Attention:    Dave Manii
Facsimile:    (416) 944-5630
and:
ATB Financial
Suite 600, 444 – 7th Avenue SW
Calgary, Alberta T2P 0X8

Attention:    Tim Poole, Director
Facsimile:    (403) 974-5784
If to the Borrower and/or the General Partner:
AltaLink Management Ltd.
2611 – 3rd Avenue SE
Calgary, Alberta T2A 7W7

Attention:    Christopher Lomore, Vice President, Treasurer
Facsimile:    (403) 267-3407
with a copy to:
Borden Ladner Gervais LLP
Centennial Place, East Tower
1900, 520-3rd Avenue S.W.
Calgary, Alberta T2P 0R3

Attention:    Edward Wooldridge
Facsimile:     (403) 266-1395
13.4
Survival
All agreements, representations and warranties made herein shall survive the execution and delivery of this Agreement and the Credit Documents and the obtaining of Accommodations.
13.5
Benefit of Agreement
This Agreement shall be binding upon and enure to the benefit of the parties hereto and their respective successors and permitted assigns; provided, however, that the Borrower may not assign or transfer any of its rights or obligations hereunder other than as provided under Article 12.



- 57 -

13.6
Severability
Any provision of this Agreement which is prohibited or unenforceable in any jurisdiction shall not invalidate the remaining provisions hereof and any such prohibitions or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.
13.7
Entire Agreement
This Agreement, the Credit Documents and all documentation contemplated herein constitute the entire agreement among the parties relating to the subject matter hereof except for any fee agreements between the Borrower and the Administrative Agent.
13.8
Credit Documents
Notwithstanding any contrary provision contained in the Credit Documents, in the event of any conflict or inconsistency between any of the provisions in this Agreement and any of the provisions in the Credit Documents, as against the parties hereto and their respective successors and permitted assigns the provisions in this Agreement shall prevail.
13.9
Counterparts
This Agreement may be executed in any number of counterparts, each of which shall be considered to be an original, and which together shall constitute one and the same document.
13.10
Amendments/Approvals and Consents/Waivers
No amendment or waiver of any provision of this Agreement or of any Credit Document contemplated herein, nor consent to any departure by the Borrower therefrom, nor any approval, consent, opinion, confirmation of satisfaction, direction, specification or agreement to be given by the Lenders or the Administrative Agent on behalf of the Lenders hereunder shall be effective unless the same shall be in writing and signed by the Administrative Agent and then such amendment, waiver, consent, approval, opinion, confirmation of satisfaction, direction, specification or agreement shall be effective only in the specific instance and for the specific purpose for which it is given.
13.11
Acknowledgement
The Borrower is a limited partnership formed under the Partnership Act (Alberta), a limited partner of which is only liable for any of its liabilities or any of its losses to the extent of the amount that such limited partner has contributed or agreed to contribute to its capital and such limited partner’s pro rata share of any undistributed income.
[The remainder of this page intentionally left blank]






IN WITNESS OF WHICH the parties hereto have duly executed this Agreement as of the date set forth on the first page of this Agreement.
 
 
ALTALINK MANAGEMENT LTD., as General Partner of ALTALINK, L.P.


By:
/s/ David Koch
 
Name: David Koch
 
Title: Executive Vice President
and Chief Financial Officer
By:
/s/ Christopher J. Lomore
 
Name: Christopher J. Lomore
 
Title: Vice President, Treasurer

 
 
ALTALINK MANAGEMENT LTD.
By:
/s/ David Koch
 
Name: David Koch
 
Title: Executive Vice President
and Chief Financial Officer
By:
/s/ Christopher J. Lomore
 
Name: Christopher J. Lomore
 
Title: Vice President, Treasurer




Signature Page to Altalink (ALP) Fifth Amended and Restated Credit Agreement




 
 
THE BANK OF NOVA SCOTIA, as Administrative Agent, Co-Lead Arranger and Co-Bookrunner

By:
/s/ Clement Yu
 
Name: Clement Yu
 
Title: Director
 
 
By:
/s/ Venita Ramjattan
 
 
 
Name: Venita Ramjattan
 
 
 
Title: Analyst

 
 
THE BANK OF NOVA SCOTIA, as Lender
By:
/s/ Kirt Millwood
 
Name: Kirt Millwood
 
Title: Managing Director
 
 
By:
/s/ Matthew Hartnoll
 
 
 
Name: Matthew Hartnoll
 
 
 
Title: Director




Signature Page to Altalink (ALP) Fifth Amended and Restated Credit Agreement




 
 
ROYAL BANK OF CANADA, as Syndication Agent, Co-Lead Arranger, and Co-Bookrunner

By:
/s/ Timothy P. Murray
 
Name: Timonthy P. Murray
 
Title: Authorized Signatory

 
 
ROYAL BANK OF CANADA, as Lender
By:
/s/ Timothy P. Murray
 
Name: Timothy P. Murray
 
Title: Authorized Signatory





Signature Page to Altalink (ALP) Fifth Amended and Restated Credit Agreement




 
 
THE BANK OF MONTREAL, as Co-Documentation Agent
By:
/s/ Carol McDonald
 
Name: Carol McDonald
 
Title: Managing Director
 
 
By:
/s/ McKenzie Mantei
 
 
 
Name: McKenzie Mantei
 
 
 
Title: Analyst

 
 
THE BANK OF MONTREAL, as Lender
By:
/s/ Carol McDonald

 
Name: Carol McDonald
 
Title: Managing Director
 
 
By:
/s/ McKenzie Mantei
 
 
 
Name: McKenzie Mantei
 
 
 
Title: Analyst



Signature Page to Altalink (ALP) Fifth Amended and Restated Credit Agreement




 
 
NATIONAL BANK OF CANADA, as Co-Documentation Agent
By:
/s/ James Dexter
 
Name: James Dexter
 
Title: Authorized Signatory
 
 
By:
/s/ Chuck Warnica
 
 
 
Name: Chuck Warnica
 
 
 
Title: Authorized Signatory

 
 
NATIONAL BANK OF CANADA, as Lender
By:
/s/ James Dexter

 
Name: James Dexter
 
Title: Authorized Signatory
 
 
By:
/s/ Chuck Warnica

 
 
 
Name: Chuck Warnica
 
 
 
Title: Authorized Signatory



Signature Page to Altalink (ALP) Fifth Amended and Restated Credit Agreement




 
 
THE TORONTO-DOMINION BANK, as Lender
By:
/s/ Hassan Abbas
 
Name: Hassan Abbas
 
Title: Director
 
 
By:
/s/ David Manii
 
 
 
Name: David Manii
 
 
 
Title: Director


Signature Page to Altalink (ALP) Fifth Amended and Restated Credit Agreement




 
 
ATB FINANCIAL, as Lender
By:
/s/ Trevor Guinard
 
Name: Trevor Guinard
 
Title: Director
 
 
By:
/s/ Evan Hahn
 
 
 
Name: Evan Hahn
 
 
 
Title: Portfolio Manager




Signature Page to Altalink (ALP) Fifth Amended and Restated Credit Agreement









SCHEDULE 1
BORROWER’S CERTIFICATE OF COMPLIANCE

TO:
The Bank of Nova Scotia (“BNS”), as Administrative Agent for the Lenders, under the Credit Agreement
This Certificate is delivered to you pursuant to the Fifth Amended and Restated Credit Agreement made as of January 24, 2020, as amended, restated or replaced from time to time (the “Credit Agreement”) between AltaLink, L.P., AltaLink Management Ltd., BNS, as Administrative Agent, Co-Lead Arranger and Co-Bookrunner, Royal Bank of Canada (“RBC”), as Syndication Agent, Co-Lead Arranger and Co-Bookrunner, The Bank of Montreal (“BMO”) and National Bank of Canada (“NBC”), as Co-Documentation Agents, and BNS, RBC, BMO, NBC, The Toronto-Dominion Bank and ATB Financial, as Lenders, and the other Lenders which from time to time become a party thereto.
Capitalized terms used in this Certificate and not otherwise defined have the meanings given in the Credit Agreement.
The undersigned has read the provisions of the Credit Agreement which are relevant to the furnishing of this Certificate. The undersigned has made such examination and investigation as was, in the opinion of the undersigned, necessary to enable the undersigned to express an informed opinion on the matters set out herein.
The undersigned hereby certifies that as of the date hereof:
1.
Representations and Warranties. All representations and warranties of the Borrower and the General Partner contained in the Credit Agreement are true and correct in all material respects as if made on and as of the date hereof, except as set out in Appendix I hereto or otherwise notified to the Administrative Agent under the Credit Agreement.
2.
Default/Event of Default. No Default or Event of Default under the Credit Agreement has occurred and is continuing.
3.
Limitation on Indebtedness. The aggregate amount of all Indebtedness of the Borrower (other than Financial Instrument Obligations in accordance with Section 6.3 of the Trust Indenture) does not exceed seventy-five percent (75%) of the Total Capitalization of the Borrower.
4.
Permitted Joint Arrangements. (i) The total equity investment of the Borrower in Permitted JA Subsidiaries and Permitted Joint Arrangements does not exceed an aggregate amount equal to Cdn.$200,000,000; and (ii) the Borrower has not formed any Subsidiaries other than Permitted JA Subsidiaries and has not entered into any joint ventures or joint arrangements other than Permitted Joint Arrangements. The following represents investments by the Borrower in Permitted JA Subsidiaries and Permitted Joint Arrangements as of the date hereof which aggregate amount does not exceed Cdn.$200,000,000: [Borrower to provide details.].

ALP Fifth Amended and Restated Credit Agreement – Certificate of Compliance – Signature Page




DATED this      day of             , 20__ .
 
 
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.
 
Name: David Koch
 
Title: Executive Vice President
and Chief Financial Officer
By:
 
 
 
 
Name: Christopher J. Lomore
 
 
 
Title: Vice President, Treasurer
 
 
I/We have the authority to bind the Partnership.

 
 
ALTALINK MANAGEMENT LTD.
 
Name: David Koch
 
Title: Executive Vice President
and Chief Financial Officer
By:
 
 
 
 
Name: Christopher J. Lomore
 
 
 
Title: Vice President, Treasurer
 
 
 
 
 
 
I/We have the authority to bind the Corporation.



APPENDIX I
EXCEPTIONS AND QUALIFICATIONS TO
BORROWER’S CERTIFICATE OF COMPLIANCE



ALP Fifth Amended and Restated Credit Agreement – Certificate of Compliance – Signature Page







- 2 -

SCHEDULE 2(A)
BORROWING NOTICE
The Bank of Nova Scotia
Global Wholesale Services
720 King Street West
2nd Floor
Toronto, ON M5V 2T3
Attention:    John Hall, Director, Loan Operations
Facsimile:    (416) 866-5991
The Lenders under the Credit Agreement
Dear Sirs/Mesdames:
You are hereby notified that the undersigned, intends to avail itself of the Credit Facility established in its favour pursuant to the Fifth Amended and Restated Credit Agreement made as of January 24, 2020, as amended, restated or replaced from time to time (the “Credit Agreement”) between AltaLink, L.P., AltaLink Management Ltd., The Bank of Nova Scotia (“BNS”), as Administrative Agent, Co-Lead Arranger and Co-Bookrunner, Royal Bank of Canada (“RBC”), as Syndication Agent, Co-Lead Arranger and Co-Bookrunner, The Bank of Montreal (“BMO”) and National Bank of Canada (“NBC”), as Co-Documentation Agents, and BNS, RBC, BMO, NBC, The Toronto-Dominion Bank and ATB Financial, as Lenders, and the other Lenders which from time to time become a party thereto.
Capitalized terms used in this Borrowing Notice and not otherwise defined have the meanings given in the Credit Agreement.
The undersigned hereby irrevocably requests a Borrowing as follows:
(a)
Prime Rate Loan in the amount of Cdn.$l, having a term of l [add same provision for any other amount and term requested]; and
(b)
Bankers’ Acceptance or l in the aggregate amount of Cdn.$l having a term of l days [add same provision for any other amount and term requested].
All Loans made pursuant to this Borrowing Notice shall be credited to the undersigned’s account no. l at the Branch. In the case of a Bankers’ Acceptance, it shall be delivered to l. The requested Borrowing Date is l. [If the undersigned requires a bank draft to be issued by BNS as a debit to the undersigned account at the Branch and to be delivered on the undersigned’s behalf, add an irrevocable direction to that effect, specifying the Person to whom it is to be delivered.]
In the case of a Discount Note, it shall be delivered to l. The requested Borrowing Date is l.
All representations and warranties of the Borrower contained in the Credit Agreement are true and correct in all material respects as if made on and as of the date hereof.



- 3 -

No Default or Event of Default under the Credit Agreement has occurred and is continuing.

DATED this      day             , 20_____.
 
 
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.
By:
 
 
Name:
 
Title:
 
 
By:
 
 
 
 
Name:
 
 
 
Title:
 
 
I/We have the authority to bind the Partnership.






- 4 -

SCHEDULE 2(B)
NOTICE OF ROLL OVER
The Bank of Nova Scotia
Global Wholesale Services
720 King Street West
2nd Floor
Toronto, ON M5V 2T3
Attention:    John Hall, Director, Loan Operations
Facsimile:    (416) 866-5991
The Lenders under the Credit Agreement
Dear Sirs/Mesdames:
We refer to Section 2.4 of the Fifth Amended and Restated Credit Agreement made as of January 24, 2020, as amended, restated or replaced from time to time (the “Credit Agreement”) between AltaLink, L.P., AltaLink Management Ltd., The Bank of Nova Scotia (“BNS”), as Administrative Agent, Co-Lead Arranger and Co-Bookrunner, Royal Bank of Canada (“RBC”), as Syndication Agent, Co-Lead Arranger and Co-Bookrunner, The Bank of Montreal (“BMO”) and National Bank of Canada (“NBC”), as Co-Documentation Agents, and BNS, RBC, BMO, NBC, The Toronto-Dominion Bank and ATB Financial, as Lenders, and the other Lenders which from time to time become a party thereto.
Capitalized terms used in this Notice and not otherwise defined have the meanings given in the Credit Agreement.
The Borrower hereby confirms that:
(a)
it intends to repay the following Bankers’ Acceptances or Discount Note, as the case may be, on the current maturity date:
(i)
aggregate face amount - $____________;
(ii)
current maturity date _______________;
(b)
the following Bankers’ Acceptances or Discount Note, as the case may be, are to be rolled over in accordance with the Credit Agreement by the issuance of new Bankers’ Acceptances or Discount Note on the current maturity date specified below:
(i)
aggregate face amount of maturing Bankers’ Acceptances or Discount Note - $____________;
(ii)
current maturity date - ______________;
(iii)
new aggregate face amount - $____________;
(iv)
new contract period - _______________; and



- 5 -

(v)
new maturity date - ________________.
The Borrower hereby represents and warrants that the conditions contained in the Credit Agreement have been satisfied and will be satisfied as of the date hereof and before and after giving effect to such roll over on the applicable roll over date.
DATED this ___ day             , 20____.
 
 
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.
By:
 
 
Name:
 
Title:
 
 
By:
 
 
 
 
Name:
 
 
 
Title:
 
 
I/We have the authority to bind the Partnership.
    




- 6 -

SCHEDULE 2(C)
CONVERSION OPTION NOTICE
The Bank of Nova Scotia
Global Wholesale Services
720 King Street West
2nd Floor
Toronto, ON M5V 2T3
Attention:    John Hall, Director, Loan Operations
Facsimile:    (416) 866-5991
The Lenders under the Credit Agreement
Dear Sirs/Mesdames:
We refer to Section 2.4 of the Fifth Amended and Restated Credit Agreement made as of January 24, 2020, as amended, restated or replaced from time to time (the “Credit Agreement”) between AltaLink, L.P., AltaLink Management Ltd., The Bank of Nova Scotia (“BNS”), as Administrative Agent, Co-Lead Arranger and Co-Bookrunner, Royal Bank of Canada (“RBC”), as Syndication Agent, Co-Lead Arranger and Co-Bookrunner, The Bank of Montreal (“BMO”) and National Bank of Canada (“NBC”), as Co-Documentation Agents, and BNS, RBC, BMO, NBC, The Toronto-Dominion Bank and ATB Financial, as Lenders, and the other Lenders which from time to time become a party thereto.
Capitalized terms used in this Notice and not otherwise defined have the meanings given in the Credit Agreement.
Pursuant to the Credit Agreement, we hereby give notice of our irrevocable request for a conversion of Advances in the amount of $______________ outstanding by way of [insert type of loan] into corresponding Borrowings by way of [insert new type of loan] on the _________ day of ___________, 20____. [The contract period for the new Bankers’ Acceptances or Discount Note, as the case may be, shall be ________ with a new maturity date of ____________, 20____.][The term of the new [insert type of loan] shall be ________ with a new maturity date of ____________, 20____.]
The Borrower hereby represents and warrants that the conditions contained in the Credit Agreement have been satisfied and will be satisfied as of the date hereof and before and after giving effect to such conversion on the applicable conversion date.
DATED this      day             , 20____.
 
 
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.
By:
 
 
Name:
 
Title:
 
 
By:
 
 
 
 
Name:
 
 
 
Title:
 
 
I/We have the authority to bind the Partnership.



- 7 -






- 8 -

SCHEDULE 3
NOTICE OF EXTENSION
The Bank of Nova Scotia
Scotia Capital – Global Loan Syndications Canada
40 King Street West
62nd Floor - Scotia Plaza
Toronto, ON M5W 2X6
Attention:    Head, Agency Services
Facsimile:    (416) 866-3329
Dear Sirs/Mesdames:
You are hereby notified that the undersigned wishes to extend the Maturity Date for the Credit Facility for a three hundred and sixty-five (365) day period from the date stipulated in your acceptance of this request. Capitalized terms used in this Notice of Extension and not otherwise defined have the meanings given in the Fifth Amended and Restated Credit Agreement made as of January 24, 2020, between AltaLink, L.P., AltaLink Management Ltd., The Bank of Nova Scotia (“BNS”), as Administrative Agent, Co-Lead Arranger and Co-Bookrunner, Royal Bank of Canada (“RBC”), as Syndication Agent, Co-Lead Arranger and Co-Bookrunner, The Bank of Montreal (“BMO”) and National Bank of Canada (“NBC”), as Co-Documentation Agents, and BNS, RBC, BMO, NBC, The Toronto-Dominion Bank and ATB Financial, as Lenders, and the other Lenders which from time to time become a party thereto.
DATED this __ day of _______________, 20____.
 
 
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.
By:
 
 
Name:
 
Title:
 
 
By:
 
 
 
 
Name:
 
 
 
Title:
 
 
I/We have the authority to bind the Partnership.






- 9 -

SCHEDULE 4
ASSIGNMENT AGREEMENT
TO:        THE BANK OF NOVA SCOTIA (“BNS”)
AND TO:    ALTALINK, L.P. (the “Borrower”)
The Borrower has entered into the Fifth Amended and Restated Credit Agreement made as of January 24, 2020, as amended, restated or replaced from time to time, (the “Credit Agreement”) between the Borrower, AltaLink Management Ltd., BNS, as Administrative Agent, Co-Lead Arranger and Co-Bookrunner, Royal Bank of Canada (“RBC”), as Syndication Agent, Co-Lead Arranger and Co-Bookrunner, The Bank of Montreal (“BMO”) and National Bank of Canada (“NBC”), as Co-Documentation Agents, and BNS, RBC, BMO, NBC, The Toronto-Dominion Bank and ATB Financial, as Lenders, and the other Lenders which from time to time become a party thereto.
l (the “Assignee”) wishes to acquire some of the rights of l (the “Assignor”) under the Credit Agreement and accordingly the Assignor and the Assignee furnish this Assignment Agreement to the Borrower subject to the terms of the Credit Agreement. Capitalized terms in this Assignment Agreement shall have the meanings set out in the Credit Agreement.
1.
The Assignee acknowledges that it has received and reviewed a copy of the Credit Agreement and further acknowledges the provisions of the Credit Agreement.
2.
The Assignor hereby sells, assigns and transfers to the Assignee an undivided l% interest in the Credit Facility and the Credit Agreement so that the Assignor’s commitment will now be Cdn.$l and the Assignee’s commitment will be Cdn.$l.
3.
The Assignee, by its execution and delivery of this Assignment Agreement, agrees from and after the date hereof to be bound by and to perform all of the terms, conditions and covenants of the Credit Agreement applicable to the Assignor, all as if such Assignee had been an original party thereto. The Assignee will not set off any amounts owing by the Borrower to such Assignee (other than pursuant to this Assignment Agreement) against any amounts the Assignee is obliged to advance under the Credit Agreement.
4.
Notices under the Credit Agreement shall be given to the Assignee at the following address and facsimile number:
[Insert Address]

Attention: l
Facsimile: l
5.
The provisions hereof shall be binding upon the Assignee and the Assignor and their respective successors and permitted assigns and shall enure to the benefit of the Borrower and its successors and assigns.



- 10 -

6.
This Assignment Agreement shall be governed by and construed and interpreted in accordance with the laws of the Province of Alberta and the laws of Canada applicable therein.
IN WITNESS WHEREOF the undersigned have caused this Assignment Agreement to be duly executed this ___ day of ______________, 20____.
 
 
[NAME OF ASSIGNOR], as Assignor
By:
 
 
Name:
 
Title:
 
 
By:
 
 
 
 
Name:
 
 
 
Title:
 
 
I/We have the authority to bind the Corporation.


 
 
[NAME OF ASSIGNEE], as Assignee
By:
 
 
Name:
 
Title:
 
 
By:
 
 
 
 
Name:
 
 
 
Title:
 
 
I/We have the authority to bind the Corporation.




- 11 -

The Bank of Nova Scotia, as Administrative Agent consents to the above assignment.
 
 
THE BANK OF NOVA SCOTIA, as Administrative Agent
By:
 
 
Name:
 
Title:
By:
 
 
Name:
 
Title:
 
 



ACKNOWLEDGEMENT

ACKNOWLEDGED AND AGREED to this __ day of _______________, 20____.
 
 
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.
By:
 
 
Name:
 
Title:
 
 
By:
 
 
 
 
Name:
 
 
 
Title:
 
 
I/We have the authority to bind the Partnership.












- 2 -

SCHEDULE 5
LENDERS’ COMMITMENTS

Lender
Lender’s Commitment

The Bank of Nova Scotia

$119,000,000

Royal Bank of Canada

$119,000,000

The Bank of Montreal

$98,000,000

The Toronto-Dominion Bank

$77,000,000

National Bank of Canada

$53,000,000

ATB Financial

$34,000,000




EXHIBIT 10.5




FOURTH AMENDED AND RESTATED CREDIT AGREEMENT

ALTALINK, L.P.,
as Borrower
- and -
ALTALINK MANAGEMENT LTD.,
as General Partner
- and -
THE BANK OF NOVA SCOTIA,
as Agent of the Lenders, and as Lender
- and -
ALL OTHER LENDERS WHICH BECOME
PARTIES HEREUNDER,
as Lenders


 


TABLE OF CONTENTS


 
 
 
Page

2

 
1.1
Definitions
2

 
1.2
References
11

 
1.3
Headings
11

 
1.4
Included Words
11

 
1.5
Amendment and Restatement: No Novation
11

 
1.6
Accounting Terms
11

 
1.7
Time
12

 
1.8
Governing Law/Attornment
12

 
1.9
Currency
12

 
Certificates and Opinions
12

 
Schedules
12

 
 
 
 
13

 
2.1
Credit Facilities
13

 
2.2
Cancellation
13

 
2.3
Particulars of Borrowings
13

 
2.4
Borrowing Notice
14

 
2.5
Books of Account
15

 
2.6
Further Provisions Account/Evidence of Borrowings
15

 
2.7
Bankers’ Acceptances
16

 
2.8
Letters of Credit
20

 
2.9
LIBOR Loans
21

 
Safekeeping of Drafts
22

 
Certification to Third Parties
23

 
Successor LIBOR Rate
23

 
 
 
 
24

 
3.1
Interest on Loans
24

 
3.2
LIBOR Interest Period Determination
25

 
3.3
Interest on Overdue Amounts
26

 
3.4
Other Interest
26

 
3.5
Interest Act (Canada)
26

 
3.6
Deemed Reinvestment Principle
26

 
3.7
Maximum Return
26

 
 
 
 
27

 
4.1
Acceptance Fees
27

 
4.2
Letter of Credit
27

 
4.3
Standby Fee
27

 
4.4
Basis of Calculation of Fees
28

 
4.5
Extension Fee
28

 
 
 
 
28

 
5.1
Voluntary Repayment of Outstanding Accommodation
28


 


TABLE OF CONTENTS
(Continued)


 
5.2
Repayment on Maturity Date and Extension
30

 
5.3
Excess Accommodation
30

 
5.4
Illegality
31

 
 
 
 
31

 
6.1
Payments on Non-Business Days
31

 
6.2
Method and Place of Payment
31

 
6.3
Net Payments
31

 
6.4
Agent May Debit Account
31

 
6.5
Currency of Payment
32

 
6.6
Increased Costs
32

 
6.7
General Indemnity
33

 
6.8
Early Termination of LIBOR Interest Period
34

 
6.9
Outstanding Bankers’ Acceptances and Letters of Credit
34

 
Replacement of Lender
34

 
 
 
 
35

 
7.1
Security
35

 
 
 
 
35

 
8.1
Representations and Warranties
35

 
8.2
Survival of Representations and Warranties
38

 
 
 
 
38

 
9.1
Trust Indenture
38

 
9.2
Covenants
38

 
9.3
Maintenance of Total Capitalization
40

 
 
 
 
40

 
Conditions Precedent to Effectiveness of this Agreement
40

 
Conditions Precedent to All Borrowings, Conversions
41

 
Waiver
42

 
 
 
 
42

 
Events of Default
42

 
Remedies
43

 
Remedies Cumulative
43

 
Appropriation of Moneys Received
43

 
Non-Merger
43

 
Waiver
43

 
Set-off
44

 
 
 
 
44

 
Authorization of Agent and Relationship
44

 
Disclaimer of Agent
45

 
Failure of Lender to Fund
45





TABLE OF CONTENTS
(Continued)


 
Payments by the Borrower
46

 
Payments by Agent
47

 
Direct Payments
48

 
Administration of the Credit Facilities
48

 
Rights of Agent
51

 
Acknowledgements, Representations and Covenants of Lenders
51

 
Collective Action of the Lenders
52

 
Successor Agent
53

 
Provisions Operative Between Lenders and Agent Only
53

 
Assignments and Participation - Approvals
53

 
Assignments
54

 
Participation
55

 
 
 
 
55

 
Expenses
55

 
Further Assurances
56

 
Notices
56

 
Survival
57

 
Benefit of Agreement
57

 
Severability
57

 
Entire Agreement
57

 
Credit Documents
57

 
Counterparts
57

 
Amendments/Approvals and Consents/Waivers
57

 
Acknowledgement
58

 
 
 
 
 
 
 
 
 
 
 











THIS FOURTH AMENDED AND RESTATED CREDIT AGREEMENT is made as of January 24, 2020
A M O N G:
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.,
as Borrower,
- and -
ALTALINK MANAGEMENT LTD.,
as General Partner,
- and -
THE BANK OF NOVA SCOTIA
as Agent of the Lenders, and as Lender
- and -
ALL OTHER LENDERS WHICH BECOME PARTIES HEREUNDER,
as Lenders
WHEREAS the Borrower, the General Partner, BNS, as Agent of the Lenders and as Lender, and the Lenders are party to a Third Amended and Restated Credit Agreement dated as of December 17, 2015 (such agreement, as amended by a first amending agreement dated as of December 15, 2016, a second amending agreement dated as of December 14, 2017, a third amending agreement dated as of April 19, 2018, a fourth amending agreement dated December 14, 2018, the “Existing Credit Agreement”), which Existing Credit Agreement was an amendment and restatement of an amended and restated credit agreement dated as of December 19, 2013;
AND WHEREAS the Borrower has requested, and the Lenders have agreed, to extend the Maturity Date, and to make additional amendments to the Existing Credit Agreement and to amend and restate the Existing Credit Agreement, as herein contained;
NOW THEREFORE THIS AGREEMENT WITNESSES that, in consideration of the mutual covenants and agreements contained in this Agreement, the Borrower, the General Partner, the Agent and the Lenders covenant and agree as follows:

 


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ARTICLE 1
INTERPRETATION
1.1
Definitions
In this Agreement, unless the context otherwise requires, all capitalized terms shall have the meaning ascribed thereto in the Trust Indenture provided that the following terms shall have the following meanings (whether or not defined in the Trust Indenture):
“Accommodation” means the Loans, Letters of Credit and Bankers’ Acceptances under this Credit Facility and shall refer to any one or more of such types where the context requires.
“Advance” means an advance by the Lenders or any of them of any Accommodation, and shall include deemed Advances and conversions, renewals and rollovers of existing Advances, and any reference relating to the amount of Advances shall mean the Canadian Dollar Amount of all outstanding Accommodation.
“Advanced Share” means the percentage of the total amount of Advances to the Borrower that has been made by a particular Lender at any time.
“Agent” means BNS, or any Successor Agent appointed under Section 12.11.
“Agent’s Account” means the account at the Branch into which Lenders’ Advances shall be deposited for payment to the Borrower.
“Agreement” means this Fourth Amended and Restated Credit Agreement and the Schedules hereto, as may be further amended, supplemented or restated from time to time.
Applicable Laws” means (a) any domestic or foreign statute, law (including common and civil law), treaty, code, ordinance, rule, regulation, restriction or by-law (zoning or otherwise); (b) any judgment, order, writ, injunction, decision, ruling, decree or award; (c) any regulatory policy, practice, guideline or directive; or (d) any franchise, licence, qualification, authorization, consent, exemption, waiver, right, permit or other approval of any governmental authority, binding on or affecting the person referred to in the context in which the term is used or binding on or affecting the property of such person, in each case whether or not having the force of law.
“Applicable Margin” means the applicable fee or margin amount set out in the following grid for the rating which corresponds to the rating received from Standard & Poor’s, Moody’s or DBRS (collectively, the “Rating Agencies”) and which is determined below:




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Ratings
Category I
Category II
Category III
Category IV
Category V
Standard & Poor’s, Moody’s, and DBRS
> A / A2 / A
A / A2 / A
A - / A3 / A(low)
BBB+ /
Baa1 / BBB (high)
<BBB+ /
Baa1 / BBB (high)
Applicable Margin for Bankers’ Acceptances, LIBOR Loans & LC/fees
70 bps
80 bps
100 bps
120 bps
145 bps
Applicable Margin for Prime Rate Loans and US Base Rate Loans
0 bps
0 bps
0 bps
20 bps
45 bps
Standby Fee
14 bps
16 bps
20 bps
24 bps
29 bps

The ratings set forth in the foregoing table are the ratings assigned by each of the Rating Agencies to the Borrower until such time as ratings are assigned to the Outstanding Senior Bonds after which time the ratings set forth on the foregoing table shall refer to the ratings assigned by each of the Rating Agencies to the Outstanding Senior Bonds. For purposes of this Agreement, if at any time the ratings assigned by the Rating Agencies fall within different rating categories in accordance with the above table, the applicable rating category for purposes of calculating the Applicable Margin shall be determined as follows:
(a)
if only two Rating Agencies publish ratings of the Borrower and/or the Outstanding Senior Bonds, as applicable, the rating category containing the highest assigned rating shall govern, unless the difference in the ratings published by such two Rating Agencies is: (i) two rating levels, in which case the applicable rating shall be deemed to be the average between such two ratings; and (ii) more than two rating levels, in which case the applicable rating shall be deemed to be the rating one level higher than the lowest of such ratings;
(b)
if all three Rating Agencies publish ratings of the Borrower and/or the Outstanding Senior Bonds, as applicable, and two (2) of the Rating Agencies publish a similar rating category, such similar rating category shall govern; and
(c)
if all three Rating Agencies publish ratings of the Borrower and/or the Outstanding Senior Bonds, as applicable, which are different, the middle rating category of the three ratings shall govern.
Any increase or decrease in the Applicable Margin for LIBOR Loans and applicable Bankers’ Acceptance Fee resulting from a change in the rating assigned by one or more Rating Agency shall be calculated with reference to the new Applicable Margin and fee effective on and after the date on which such rating change is published, notwithstanding that any affected LIBOR Loan or Bankers’ Acceptance may have been made or issued prior to such date. In the case of outstanding Bankers’ Acceptance, an appropriate adjustment shall be made to the fees already collected in respect thereof and the difference shall be paid by, or refunded to, the Borrower, as the case may be, within five (5) Business Days after notice by the Agent to the Borrower of the amount of the adjustment.
“BA Discount Proceeds” means, in respect of any Bankers’ Acceptance, an amount calculated on the applicable Borrowing Date which is (rounded to the nearest full cent, with one-half of one cent being rounded up) equal to the face amount of such Bankers’ Acceptance multiplied by the price, where the price is calculated by dividing one by the sum of one plus




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the product of (i) the BA Discount Rate applicable thereto expressed as a decimal fraction multiplied by (ii) a fraction, the numerator of which is the term of such Bankers’ Acceptance and the denominator of which is three hundred and sixty-five (365), which calculated price will be rounded to the nearest multiple of 0.001%.
“BA Discount Rate” means, expressed as a rate per annum,
(a)
with respect to any Bankers’ Acceptance accepted on any date by a Lender which is a Schedule 1 Bank, such Lender’s discount rate for bankers’ acceptances accepted and purchased on such date by that Lender having a comparable face amount and identical maturity date to the face amount and maturity date of such Bankers’ Acceptance; and
(b)
with respect to any Bankers’ Acceptance accepted and purchased by a Lender which is a Schedule 2 Bank or not a bank, the lesser of (i) the discount rate, rounded upward to the nearest two decimal places, for bankers’ acceptances accepted by that Lender having a comparable face amount and identical maturity date to the face amount and maturity date of such Bankers’ Acceptance, and (ii) the discount rate, calculated on the same basis at the same time, for bankers’ acceptances accepted by the Agent, plus 0.075% per annum; calculated on the basis of a year of three hundred and sixty-five (365) days and determined in accordance with normal market practice at or about 10:00 a.m. on the applicable Borrowing Date;
provided that if any such rate is less than zero, the BA Discount Rate will be deemed to be zero.
“Bankers’ Acceptance” means a Draft drawn by the Borrower denominated in Canadian Dollars, for a term of one, two, three or six months or such other term as is readily acceptable, which term shall mature on a Business Day and on or before the applicable Maturity Date for an amount of Two Hundred and Fifty Thousand Canadian Dollars (Cdn.$250,000) or any whole multiple of Two Hundred and Fifty Thousand Canadian Dollars (Cdn.$250,000), the minimum aggregate amount of which included in any Borrowing shall be Two Hundred and Fifty Thousand Canadian Dollars (Cdn.$250,000), and accepted by a Lender pursuant to this Agreement.
“Bankers’ Acceptance Fee” means the fee payable on the face amount of each Bankers’ Acceptance calculated and payable in the manner provided for in Section 4.1.
“BNS” means The Bank of Nova Scotia, its successors and permitted assigns.
“Bond Delivery Agreement” means the bond delivery agreement dated as of October 24, 2014 among the parties hereto as the same may be amended, supplemented, restated or otherwise modified from time to time.
“Borrower” means AltaLink, L.P., a limited partnership created and existing under the Partnership Act (Alberta) and its permitted successors and permitted assigns.




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“Borrower’s Account” means an account for the Borrower designated by the Borrower and maintained for the Borrower at the Branch of Account, pursuant to an account operating agreement between the Borrower and BNS.
“Borrower’s Certificate of Compliance” means a certificate of the Borrower in the form of Schedule 1 and signed on behalf of the Borrower by any one of the President, Chief Executive Officer, the Chief Financial Officer, an Executive Vice President, a Vice President, or the Secretary, of the Borrower or any other senior officer of the General Partner so designated by a certificate signed by the Chairman or President of the General Partner and filed with the Agent for so long as such designation shall be in effect.
“Borrowing” means the aggregate Accommodation to be obtained by the Borrower from one or more of the Lenders on any Borrowing Date.
“Borrowing Date” means the Business Day specified in a Borrowing Notice on which a Lender is or Lenders are requested to provide Accommodation (and also includes the date on which any Loan by way of Overdraft is obtained by the Borrower).
“Borrowing Notice” has the meaning set out in Section 2.4.
“Branch” means the Calgary Commercial Banking Centre of the Agent situated at 240-8th Avenue S.W., Calgary, Alberta, or such other branch of the Agent in the City of Calgary as the Agent may from time to time designate in writing to the Borrower.
“Branch of Account” means the Calgary Commercial Banking Centre of the BNS situated at 240-8th Avenue S.W., Calgary, Alberta, or such other branch of the BNS in the City of Calgary as BNS may from time to time designate in writing to the Borrower.
“Business Day” means:
(a)
with respect to a Prime Rate Loan, Bankers’ Acceptance or any other type of Accommodation denominated in Canadian Dollars, any day (excluding Saturday, Sunday and any day which shall be a legal holiday in Calgary, Alberta) on which the Agent is open at the Branch for the conduct of regular banking business;
(b)
with respect to a U.S. Base Rate Loan or any other type of Accommodation denominated in U.S. Dollars (except as provided in paragraph (c) of this definition), any day (excluding Saturday, Sunday and any day which shall be in New York, New York or Calgary, Alberta a legal holiday) on which the Agent is open at the Branch for the conduct of regular banking business and banking institutions generally are open for the conduct of regular banking business in New York, New York;
(c)
with respect to a LIBOR Loan, any day which is a day for dealings by and between banks in U.S. Dollar deposits in the London interbank eurocurrency market (excluding Saturday, Sunday and any day which shall be in London, England, New York, New York or Calgary, Alberta a legal holiday) on which the Agent is open at the Branch for the conduct of regular banking business and banking institutions generally are open for the conduct of regular banking business in London, England, Calgary, Alberta and New York, New York; and




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(d)
in all other cases, any day (excluding Saturday, Sunday and any day which shall be in Calgary, Alberta a legal holiday) on which the Agent is open at the Branch for the conduct of regular banking business.
“Canadian Dollar” or “Cdn.$” means lawful money of Canada.
“Canadian Dollar Amount” means, at any time, in relation to any outstanding Accommodation:
(a)
in relation to a Loan denominated in Canadian Dollars, the principal amount thereof;
(b)
in relation to a Bankers’ Acceptance, the face amount thereof;
(c)
in relation to a Loan denominated in U.S. Dollars, the Equivalent Amount expressed in Canadian Dollars of the principal amount thereof; and
(d)
in relation to a Letter of Credit the amount of the maximum aggregate liability (contingent or actual) of the Letter of Credit Lender pursuant to such Letter of Credit expressed in Canadian Dollars.
“Claim” shall have the meaning set out in Section 6.7.
“Commitment” means in respect of each Lender from time to time, the covenant to make Advances to the Borrower of the Lender’s Proportionate Share of the Committed Amount and, where the context requires, the maximum amount of Advances which such Lender has covenanted to make, as recorded on the Register maintained by the Agent referred to in Subsection 12.14(c).
“Committed Amount” means the aggregate maximum authorized amount of Accommodation under the Credit Facilities from time to time.
“Contract Period” means, in respect of any LIBOR Loan, the applicable LIBOR Interest Period selected by the Borrower in the related Borrowing Notice.
“Contributing Lender” shall have the meaning set out in Subsection 12.3(b).
“Credit Documents” means the Pledged Bond, the Trust Indenture, letter of credit documents, forms of Drafts, or agreements relating to Bankers’ Acceptances required by any Lender and, when executed and delivered by the Borrower.
“Credit Facilities” means the credit facilities established by the Lenders in favour of the Borrower pursuant to Section 2.1.
“Defaulting Lender” shall have the meaning set out in Subsection 12.3(b).
“Demand Date” means any date that repayment of Accommodation or any other amount outstanding under this Agreement is demanded under Article 11.




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“Depository Bill” means a depository bill, as such term is defined in the Depository Bills and Notes Act (Canada) (as such legislation may be amended, replaced or otherwise modified from time to time).
“Draft” means at any time a blank bill of exchange, within the meaning of the Bills of Exchange Act (Canada), drawn by the Borrower on a Lender and bearing such distinguishing letters and numbers as such Lender may require, but which at such time has not been completed or accepted by such Lender.
“Effective Date” means January 24, 2020 or such later date as may be agreed upon by the Borrower and Agent.
“Environmental Adverse Effect” means one or more of the following in connection with an Environmental Matter:
(a)
impairment or adverse alteration of the quality of the natural environment for any use that can be made of it by humans, or by any animal, fish or plant that is useful to humans;
(b)
injury or damage to property or to plant or animal life;
(c)
harm or material discomfort to any Person;
(d)
an adverse effect on the health of any Person;
(e)
impairment of the safety of any Person;
(f)
rendering any property or plant or animal life unfit for human use;
(g)
loss of enjoyment of normal use of property; and
(h)
interference with the normal conduct of business.
“Environmental Liability” means any liability of the Borrower under any Environmental Laws or any other Applicable Laws for any adverse impact on the environment, health or safety, including the Release of a Hazardous Substance, and any liability for the costs of any clean-up, preventative or other remedial action including costs relating to studies undertaken or arising out of security fencing, alternative water supplies, temporary evacuation and housing and other emergency assistance undertaken by any Government Authority to prevent or minimize any actual or threatened Release by the Borrower of any Hazardous Substance.
“Environmental Matter” means any past, present or future activity, event or circumstance in respect of the environment, health or safety including the Release of any Hazardous Substance including any substance which is hazardous to Persons, animals, plants, or which has a detrimental effect on the soil, air or water, or the generation, treatment, storage, use, manufacture, holding, collection, processing, treatment, presence, transportation or disposal of any Hazardous Substances.




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“Environmental Proceeding” means any judgment, action, proceeding or investigation pending before any court or Government Authority, including any environmental Government Authority, with respect to or threatened against or affecting the Borrower or relating to the assets or liabilities of the Borrower or any of their respective operations, in connection with any Environmental Laws, Environmental Matter or Environmental Liability.
“Equivalent Amount” means, with respect to any two currencies, the amount obtained in one such currency when an amount in the second currency is translated into the first currency using the Bank of Canada noon rate of exchange between such currencies on the Business Day for which such computation is made or, if such rate is not available, using the spot buying rate of the Agent for the purchase of the first currency with the applicable amount of the second currency in effect at the Branch at or about noon on the Business Day with respect to which such computation is required or, in the absence of such a buying rate on such date, using such other rate as the Agent may reasonably select.
“Event of Default” shall have the meaning specified in Section 11.1.
“General Partner” means AltaLink Management Ltd.
“Governmental Approvals” means any authorization, order, permit, approval, grant, licence, consent, right, privilege, certificate or the like which may be issued or granted by law or by rule, regulation, policy or directive of any Governmental Authority now or hereafter required in connection with the use, management, maintenance and operation of the Business by the Borrower.
“IFRS” means International Financial Reporting Standards established by the International Accounting Standards Board.
“LC Fee” shall have the meaning specified in Section 4.2.
“Lenders” means BNS and all other financial institutions from time to time that have become a Lender in accordance with this Agreement and the Letter of Credit Lender and “Lender” means any one of them.
“Letter of Credit” means a letter of credit issued as provided in Section 2.8 by the Letter of Credit Lender in favour of any Person with respect to the liability of the Borrower to pay a fixed maximum amount of Canadian Dollars, provided that no Letter of Credit shall have a term of more than one year or a term ending after the applicable Maturity Date.
“Letter of Credit Lender” means BNS and/or such other Lenders which agree to provide the Borrower with Letters of Credit pursuant to this Agreement.
“LIBOR Interest Period” means, from time to time with respect to a LIBOR Loan, the applicable interest period of one, two, three or six months ending on a Business Day and on or before the applicable Maturity Date, as selected in accordance with Section 3.2.
“LIBOR Loan” means any Loan in U.S. Dollars with respect to which interest is calculated under this Agreement for the time being on the basis of the LIBOR Rate, the minimum




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aggregate principal amount of which included in any Borrowing shall be Two Hundred and Fifty Thousand U.S. Dollars (U.S.$250,000) or any greater amount which is a whole multiple of Two Hundred and Fifty Thousand U.S. Dollars (U.S.$250,000).
“LIBOR Rate” means, with respect to each LIBOR Interest Period for each LIBOR Loan, the rate of interest which appears on the LIBOR page of the Reuters Screen as of 11:00 a.m. (London, England time) on the second Business Day prior to the commencement of such LIBOR Interest Period or, if such Reuters Screen rate is not available on such day, there shall be substituted for such rate the annual interest rate for deposits of U.S. Dollars for a period most nearly comparable to such LIBOR Interest Period which appears on page 3750 of the Dow Jones Telerate Screen as of 11:00 a.m. (London, England time) on the second Business Day prior to the commencement of such LIBOR Interest Period for loans of a corresponding amount for a corresponding LIBOR Interest Period or, if neither such screen rate is available on such day, there shall be substituted for such rate the annual interest rate, rounded upward to the nearest l/16th of 1%, at which deposits in U.S. Dollars in amounts comparable to the amount of such LIBOR Loan, for value on the first day of such LIBOR Interest Period and for a term equal to the requested LIBOR Interest Period, are offered to the Agent in accordance with its normal practice in the London interbank market at or about 11:00 a.m. (London, England time) on the second Business Day prior to the commencement of such LIBOR Interest Period, as determined by the Agent.
“Loan” means the amount of Canadian Dollars or U.S. Dollars advanced by a Lender or Lenders to the Borrower on any Borrowing Date pursuant to a Borrowing Notice or by way of Overdraft or as otherwise provided herein and includes a Prime Rate Loan, a LIBOR Loan and a U.S. Base Rate Loan.
“Majority Lenders” means, at any time, Lenders having, in the aggregate, Proportionate Shares of a minimum of 66.7% of the Committed Amount.
“Material Adverse Effect” means a material adverse effect on the ability of the Borrower to perform its obligations under this Agreement or any of the other Credit Documents or on the validity or priority of any Security Interest held by the Agent, or an event which results in an Event of Default and includes an Environmental Adverse Effect which constitutes or results in any of the foregoing effects.
“Maturity Date” means December 14, 2024, as may be extended pursuant to Subsection 5.2(b).
“Nineteenth Supplemental Indenture” means the Nineteenth Supplemental Indenture between the Borrower, the General Partner and the Trustee dated as of October 24, 2014 pursuant to which the Borrower shall issue the Pledged Bond, as such indenture may be amended, supplemented, restated or otherwise modified from time to time.
“Notice of Extension” shall have the meaning specified in Section 5.2.
“Overdraft” means the amount of Canadian Dollars or U.S. Dollars advanced by the Overdraft Lender to the Borrower by way of Prime Rate Loans and U.S. Base Rate Loans.




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“Overdraft Lender” means BNS and/or such other Lenders which agree to provide the Borrower with Overdrafts pursuant to this Agreement.
Permitted JA Subsidiary” means a subsidiary of the Borrower formed for the sole purpose of facilitating the participation by the Borrower in a Permitted Joint Arrangement and “Permitted JA Subsidiaries” means one or more Permitted JA Subsidiary.
Permitted Joint Arrangements” means one or more arrangements with other parties related to the development or operating projects for the transmission of electricity in Canada (including the bidding process thereto) and “Permitted Joint Arrangement” means any one of the Permitted Joint Arrangements.
“Pledged Bond” means the Two Hundred and Fifty Million Canadian Dollars (Cdn.$250,000,000) Series 19 Bond of the Borrower issued and certified under the Trust Indenture.
“Prime Rate” means the rate per annum publicly declared by the Agent from time to time as its prime reference rate of interest for Canadian Dollar commercial loans made in Canada.
“Prime Rate Loan” means any Loan in Canadian Dollars with respect to which interest is calculated under this Agreement for the time being on the basis of the Prime Rate.
“Proportionate Share” means the percentage of the Committed Amount which a Lender has agreed to advance pursuant to the Credit Facility, as set out in Schedule 5, which percentage shall be amended and distributed to all parties by the Agent from time to time as other Persons become Lenders.
“Schedule 1 Bank” means a bank listed on Schedule 1 under the Bank Act (Canada).
“Schedule 2 Bank” means a bank listed on Schedule 2 under the Bank Act (Canada).
“Screen Rate” has the meaning specified in Section 2.12.
“Successor Rate” has the meaning specified in Section 2.12.
“Trust Indenture” means the amended and restated trust indenture made as of the 28th day of April, 2003 between the Borrower, the General Partner and BNY Trust Company of Canada, as trustee, as supplemented by Supplemental Indentures each dated April 29, 2002, May 10, 2002, October 1, 2002, April 28, 2003, June 5, 2003, December 8, 2003, December 15, 2005 and May 9, 2006, May 21, 2008, December 18, 2009, August 18, 2010, December 17, 2010, September 1, 2011, June 29, 2012, November 15, 2012, May 22, 2013, October 24, 2014, June 30, 2015 and December 14, 2018, as such amended and restated trust indenture may be further amended and supplemented from time to time.
“Undisbursed Credit” means, at any time, the excess, if any, of the limit of the Credit Facilities then in effect over the Canadian Dollar Amount of all Accommodation then outstanding under the Credit Facilities.
“U.S. Base Rate” means the rate per annum publicly declared by the Agent from time to time as its prime reference rate of interest for U.S. Dollar commercial loans made in Canada.




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“U.S. Base Rate Loan” means any Loan in U.S. Dollars with respect to which interest is calculated under this Agreement for the time being on the basis of the U.S. Base Rate.
“U.S. Dollars” or “U.S.$” means lawful money of the United States of America.
1.2
References
The terms “Article”, “Section”, “Subsection” or “paragraph” followed by a number refer to the specified Article, Section, Subsection or paragraph of this Agreement unless otherwise expressly stated or the context otherwise requires.
1.3
Headings
The Article or Section or other headings contained in this Agreement are inserted for convenience only and shall not affect the meaning or construction of any of the provisions of this Agreement.
1.4
Included Words
Words importing the singular number only shall include the plural and vice versa where the context requires. The word “include” and derivatives thereof means “include without limitation”.    
1.5
Amendment and Restatement: No Novation
The parties hereto acknowledge and confirm that this Agreement does not constitute a novation of the Existing Credit Agreement, as amended, restated, supplemented, otherwise modified or replaced from time to time, and that all debts, liabilities and obligations of the Borrower under the Existing Credit Agreement, as amended, restated, supplemented, otherwise modified or replaced from time to time (i) shall be debts, liabilities and obligations of the Borrower under this Agreement, (ii) shall remain unaffected, except as amended hereby and (iii) shall constitute “Obligations” for the purposes of the Nineteenth Supplemental Indenture and shall be subject to the Pledged Bond.
1.6    Accounting Terms
Unless otherwise specified, all accounting terms used herein or in any other Credit Documents shall be interpreted in accordance with GAAP as now or hereafter adopted by (a) prior to January 1, 2011, the Canadian Institute of Chartered Accountants or any successor thereto; and (b) on and after January 1, 2011, IFRS, and all financial data submitted pursuant to this Agreement shall be prepared in accordance with such principles, consistently applied. In the event of a change in GAAP or following the adoption of IFRS, the Borrower and the Agent (with the approval of the Lenders) shall negotiate in good faith to revise (if appropriate) the financial ratios and financial covenants contained in this Agreement, such ratios and covenants to reflect GAAP as then in effect, in which case all calculations thereafter made for the purpose of determining compliance with such ratios and covenants shall be made on a basis consistent with GAAP in existence as at the date of such revisions. If the Borrower and the Agent cannot agree upon the required amendments immediately prior to the date of implementation of any accounting policy change, then all calculations of financial covenant, financial covenant thresholds or terms used in this Agreement or any other Credit Document shall be prepared and delivered on the basis of accounting policies of the Borrower as at the date hereof without reflecting such accounting policy change.




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1.7    Time
Unless otherwise expressly stated, any reference herein to a time shall mean local time in Calgary, Alberta.
1.8
Governing Law/Attornment
This Agreement and the Credit Documents shall be governed by and construed in accordance with the laws of the Province of Alberta and the laws of Canada applicable therein.
1.9
Currency
Unless otherwise specified herein, or the context otherwise requires, all statements of or references to dollar amounts in this Agreement and the Credit Documents shall mean Canadian Dollars.
1.10
Certificates and Opinions
(a)
Unless otherwise provided in a particular Schedule to this Agreement, each certificate and each opinion furnished pursuant to any provision of this Agreement shall specify the Section or Sections under which such certificate or opinion is furnished, shall include a statement that the Person making such certificate or giving such opinion has read the provisions of this Agreement relevant thereto and shall include a statement that, in the opinion of such Person, such Person has made such examination and investigation as is necessary to enable such Person to express an informed opinion on the matters set out in the certificate or opinion.
(b)
Whenever the delivery of a certificate or opinion is a condition precedent to the taking of any action by the Agent or a Lender or Lenders under this Agreement, the truth and accuracy of the facts and opinions stated in such certificate or opinion shall in each case be conditions precedent to the right of the Borrower to have such action taken, and each statement of fact contained therein shall be deemed to be a representation and warranty of the Borrower for the purposes of this Agreement.
1.11
Schedules
The following are the Schedules attached to and forming part of this Agreement:
Schedule 1
-
Borrower’s Certificate of Compliance
Schedule 2(A)
-
Borrowing Notice
Schedule 2(B)
-
Notice of Roll Over
Schedule 2(C)
-
Conversion Option Notice
Schedule 3
-
Notice of Extension
Schedule 4
-
Assignment Agreement
Schedule 5
-
Lenders

ARTICLE 2    
AMOUNT AND TERMS OF THE CREDIT FACILITIES




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2.1
Credit Facilities
(a)
Subject to and upon the terms and conditions set forth in this Agreement, the Lenders hereby establish in favour of the Borrower a revolving credit facility to be used for operating expenses, capital expenditures and working capital needs of the Borrower and the General Partner and their Subsidiaries, and for general corporate purposes, including the payment of dividends by the Borrower on its equity securities, by way of Prime Rate Loans, U.S. Base Rate Loans, Bankers’ Acceptances and LIBOR Loans, and also included within this Credit Facility shall be a credit to the maximum aggregate Canadian Dollar Amount of Seventy-Five Million Canadian Dollars (Cdn.$75,000,000) to be provided by:
(i)
the Letter of Credit Lender only by way of Letters of Credit on such terms as are agreed upon between the Borrower and the Letter of Credit Lender, and/or
(ii)
the Overdraft Lender only by way of Overdrafts;
the aggregate Canadian Dollar Amount of all of the above outstanding at any time under this Credit Facility shall not exceed Seventy-Five Million Canadian Dollars (Cdn.$75,000,000).
2.2
Cancellation
Subject to the provisions of Article 5, the Borrower may, at any time, by giving not less than two (2) Business Days’ prior written notice of cancellation to the Agent, cancel all or any part of the Undisbursed Credit as designated by the Borrower without penalty, provided that, if it is a part only, the minimum amount cancelled is One Million Canadian Dollars (Cdn.$1,000,000) or any multiples of One Million Canadian Dollars (Cdn.$1,000,000) in excess thereof. Effective on the date of cancellation set out in the applicable notice of cancellation, the relevant Credit Facility or Credit Facilities shall be permanently reduced by the amount of Canadian Dollars stated in the notice of cancellation.
2.3
Particulars of Borrowings
(a)
Notwithstanding any contrary provision contained in the Credit Documents, in the event of any conflict or inconsistency between any of the provisions in this Agreement and any of the provisions in Credit Documents, as against the parties hereto, the provisions of this Agreement shall prevail.
(b)
No Borrowing shall be obtained at any time for any period which would extend beyond the earlier of (i) the date which is 364 days following the Borrowing Date in respect of such Borrowing and (ii) the Maturity Date.
(c)
Subject to the provisions of Section 2.2 and Article 5, any Accommodation which is repaid may be subsequently re-drawn.
2.4
Borrowing Notice




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Whenever the Borrower desires to obtain a Borrowing (other than by way of Overdraft), it shall give to the:
(a)
Agent, in the case of Borrowings under this Credit Facility (other than the Letters of Credit), and
(b)
Letter of Credit Lender, with a copy to the Agent, in the case of Borrowings by way of Letters of Credit,
prior written notice in the form attached as Schedule 2(A), (B) or (C) as applicable (a “Borrowing Notice”), specifying, as applicable:
(c)
the amount, currency and type or types of Accommodation desired including, in the case of a Letter of Credit, the Letter of Credit Lender’s specific required form thereof and the particulars of the related indebtedness;
(d)
the Borrower’s Account at the Branch to which payment of the Borrowing is to be made, if applicable;
(e)
the Person to whom any Bankers’ Acceptance or Letter of Credit is to be delivered, if applicable;
(f)
the requested Borrowing Date;
(g)
the term thereof,
(h)
if applicable, the Accommodation to be renewed or converted and, where such Accommodation includes any Loan, the currency thereof and the interest rate applicable thereto;
(i)
if such Borrowing includes a Loan, whether it is to be a Prime Rate Loan, U.S. Base Rate Loan or a LIBOR Loan; and
(j)
if such Borrowing includes a LIBOR Loan, the LIBOR Interest Period to be applicable to such Loan;
provided that the application for a Letter of Credit delivered to the Letter of Credit Lender as part of the Credit Documents with respect to such Letter of Credit, to the extent that it includes all of the information required by this Section to be provided to the Letter of Credit Lender with respect thereto, may constitute the Borrowing Notice with respect to such Letter of Credit.
The Borrowing Notice shall be given to the relevant party entitled to receive same not later than 10:00 a.m.:
(a)
on the Business Day preceding the applicable Borrowing Date if the Accommodation is by way of Prime Rate Loans or U.S. Base Rate Loans and is a new issue or if any such Accommodation to be drawn, converted or rolled over has a Canadian Dollar Amount in the aggregate equal to or greater than One Million Canadian Dollars




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(Cdn.$1,000,000) and multiples of One Million Canadian Dollars (Cdn.$1,000,000) in excess thereof;
(b)
on the Business Day preceding the applicable Borrowing Date if the Accommodation is by way of Bankers’ Acceptances and is a new issue or if any such Accommodation to be drawn, converted or rolled over has a Canadian Dollar Amount in the aggregate equal to or greater than Two Hundred and Fifty Thousand Canadian Dollars (Cdn.$250,000); and
(c)
on the third Business Day preceding the applicable Borrowing Date if any new Accommodation or any Accommodation to be renewed or converted is a LIBOR Loan.
If any Accommodation to be drawn, renewed or converted is a Letter of Credit, the Letter of Credit Lender shall be given such sufficient prior notice as such party may reasonably require in the circumstances.
In all other cases, the Borrowing Notice shall be given to the party entitled thereto on the applicable Borrowing Date.
Any Borrowing Notice received by the Agent or the Letter of Credit Lender, as applicable, on any Business Day after 10:00 a.m. shall be deemed to have been given to such party on the next succeeding Business Day.
2.5
Books of Account
The Agent is hereby authorized to open and maintain books of account and other books and records evidencing all Bankers’ Acceptances accepted and cancelled and all Loans advanced and repaid and all other amounts from time to time owing by the Borrower to the Lenders under this Agreement including interest, acceptance, letters of credit and standby and other fees, and to enter into such books and records details of all amounts from time to time owing, paid or repaid by the Borrower under this Agreement. The Borrower acknowledges, confirms and agrees with the Agent that all such books and records kept by the Agent will constitute prima facie evidence of the balance owing by the Borrower under this Agreement; provided, however, that the failure to make any entry or recording in such books and records shall not limit or otherwise affect the obligations of the Borrower under this Agreement. Notwithstanding the foregoing, each Lender is responsible for maintaining its own records as to Advances made by it, and in the event of any inconsistency between such Lender’s and the Agent’s records, the Agent’s records shall govern, absent manifest error.
2.6
Further Provisions Account/Evidence of Borrowings
(a)
Overdraft. The Borrower shall be entitled to obtain Accommodations from the Overdraft Lender in amounts in Canadian Dollars or U.S. Dollars by way of Overdraft. The aggregate amount of all amounts debited from the Borrower’s Account at the Branch on each day, net of all deposits or credits to such account during such day, shall:




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(i)
in the case of a Loan by way of Overdraft in Canadian Dollars, bear interest at the Prime Rate; and
(ii)
in the case of a Loan by way of Overdraft in U.S. Dollars, bear interest at the U.S. Base Rate.
(b)
Co-ordination of Prime Rate and U.S. Base Rate Loans. Each Lender shall advance its Proportionate Share of each Prime Rate and U.S. Base Rate Loan in accordance with the following provisions:
(i)
the Agent shall advise each Lender of its receipt of a notice from the Borrower pursuant to Section 2.4, on the day such notice is received and shall, as soon as possible, advise each Lender of such Lender’s Proportionate Share of any Prime Rate or U.S. Base Rate Loan requested by the notice;
(ii)
each Lender shall deliver its Proportionate Share of such Loan to the Agent’s Account at the Branch not later than 11:00 a.m. on the Borrowing Date;
(iii)
when the Agent determines that all the conditions precedent to a Borrowing specified in this Agreement have been met or waived, it shall advance to the Borrower the amount delivered by each Lender by crediting the relevant Borrower’s Account(s) before 12:00 p.m. on the Borrowing Date, but if the conditions precedent to the Borrowing are not met or waived by 2:30 p.m. on the Borrowing Date, the Agent shall return the funds to the Lenders or invest them in an overnight investment as orally instructed by each Lender until such time as the Loan is advanced; and
(iv)
if the Agent determines that a Lender’s Proportionate Share of a Prime Rate or U.S. Base Rate Loan would not be a whole multiple of One Hundred Thousand Canadian Dollars (Cdn.$100,000) or One Hundred Thousand U.S. Dollars (U.S.$100,000), the amount to be advanced by that Lender may be increased or reduced by the Agent in its sole discretion to the nearest whole multiple of One Hundred Thousand Canadian Dollars (Cdn.$100,000) or One Hundred Thousand U.S. Dollars (U.S.$100,000).
2.7
Bankers’ Acceptances
(a)
Power of Attorney for the Execution of Bankers’ Acceptances. To facilitate acceptance of the Borrowings by way of Bankers’ Acceptances, the Borrower hereby appoints each Lender as its attorney to sign and endorse on its behalf, in handwriting or by facsimile or mechanical signature as and when deemed necessary by such Lender, blank forms of Drafts. In this respect, it is each Lender’s responsibility to maintain an adequate supply of blank forms of Drafts for acceptance under this Agreement. The Borrower recognizes and agrees that all Drafts signed and/or endorsed on its behalf by a Lender shall bind the Borrower fully and effectively as if signed in the handwriting of and duly issued by the proper signing officers of the Borrower. Each Lender is hereby authorized to issue such Drafts endorsed in blank in such face amounts as may be determined by such Lenders; provided that the




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aggregate amount thereof is equal to the aggregate amount of Bankers’ Acceptances required to be accepted and purchased by such Lender. No Lender shall be liable for any damage, loss or other claim arising by reason of any loss or improper use of any such instrument, except the gross negligence or wilful misconduct of the Lender or its officers, employees, agents or representatives. Each Lender shall maintain a record with respect to Bankers’ Acceptances held by it in blank hereunder, voided by it for any reason, accepted and purchased by it hereunder, and cancelled at the respective maturities. Each Lender agrees to provide such records to the Borrower at the Borrower’s expense upon request.
Drafts drawn by the Borrower to be accepted as Bankers’ Acceptances shall be signed by a duly authorized officer or officers of the Borrower or by its attorneys. Notwithstanding that any Person whose signature appears on any Bankers’ Acceptance may no longer be an authorized signatory for the Borrower at the time of issuance of a Bankers’ Acceptance; that signature shall nevertheless be valid and sufficient for all purposes as if the authority had remained in force at the time of issuance and any Bankers’ Acceptance so signed shall be binding on the Borrower. Upon tender of each Draft the Borrower shall pay to the Lender the fee specified in Section 4.1 with respect to such Draft.
(b)
Sale of Bankers’ Acceptances. It shall be the responsibility of each Lender unless otherwise requested by the Borrower, to purchase its Bankers’ Acceptances at a discount rate equal to the BA Discount Rate.
In accordance with the procedures set forth in paragraph 2.7(c)(iii), unless the Borrower requests the Lenders not to purchase the subject Bankers’ Acceptances, the Agent will make BA Discount Proceeds received by it from the Lenders available to the Borrower on the Borrowing Date by crediting the Borrower’s Account with such amount.
Notwithstanding the foregoing, if in the determination of the Majority Lenders acting reasonably a market for Bankers’ Acceptances does not exist at any time, or the Lenders collectively cannot for other reasons readily sell Bankers’ Acceptances or perform their other obligations under this Agreement with respect to Bankers’ Acceptances, then upon at least two (2) Business Days’ written notice by the Agent to the Borrower, the Borrower’s right to request Accommodation by way of Bankers’ Acceptances shall be and remain suspended until the Agent notifies the Borrower that any condition causing such determination no longer exists.
(c)
Coordination of BA Borrowings. Each Lender shall advance its Proportionate Share of each Borrowing by way of Bankers’ Acceptances in accordance with the following:
(i)
the Agent, promptly following receipt of a notice from the Borrower pursuant to Section 2.4 requesting a Borrowing by way of Bankers’ Acceptances, shall advise each Lender of the aggregate face amount and term(s) of the Bankers’ Acceptances to be accepted by it, which term(s) shall be identical for all Lenders. The aggregate face amount of Bankers’ Acceptances to be accepted




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by a Lender shall be determined by the Agent by reference to the respective Commitments of the Lenders, except that, if the face amount of a Bankers’ Acceptance would not be One Hundred Thousand Canadian Dollars (Cdn.$100,000) or a whole multiple thereof, the face amount shall be increased or reduced by the Agent in its sole discretion to the nearest whole multiple of One Hundred Thousand Canadian Dollars (Cdn.$100,000);
(ii)
unless requested by the Borrower not to purchase the subject Bankers’ Acceptances, each Lender shall transfer to the Agent at the Branch for value on each Borrowing Date immediately available Canadian Dollars in an aggregate amount equal to the BA Discount Proceeds of all Bankers’ Acceptances accepted and sold or purchased by the Lender on such Borrowing Date, net of the applicable Bankers’ Acceptance Fees in respect of such Bankers’ Acceptances. Each Lender shall also advise the Agent (which shall promptly give the relevant particulars to the Borrower) as soon as possible of the discount rate at which it has sold or purchased its Bankers’ Acceptances;
(iii)
if the Borrower requests the Lenders not to purchase the subject Bankers’ Acceptances, each Lender will forward the subject Bankers’ Acceptances to the Agent for delivery against payment of the applicable Bankers’ Acceptance Fees; and
(iv)
if the Agent determines that all the conditions precedent to a Borrowing specified in this Agreement have been met or waived, it shall advance to the Borrower the amount delivered by each Lender by crediting the Borrower’s Account prior to 12:00 p.m. on the Borrowing Date, or, if applicable shall deliver the Bankers’ Acceptances as directed by the Borrower, but if the conditions precedent to the Borrowing are not met or waived by 2:30 p.m. on the Borrowing Date, the Agent shall return the funds to the Lenders or invest them in an overnight investment as orally instructed by each Lender until such time as the Advance is made.
(d)
Payment. The Borrower shall provide for the payment to the Agent for the account of the Lenders of the face amount of each Bankers’ Acceptance at its maturity, either by payment of the amount thereof or through utilization of the Credit Facilities in accordance with this Agreement (by rolling over the Bankers’ Acceptance or converting it into other Accommodation or a combination thereof). The Borrower will continue to be required to provide as aforesaid for each Bankers’ Acceptance at maturity notwithstanding the fact that a Lender may be the holder of the Bankers’ Acceptance which has been accepted by such Lender.
(e)
Collateralization.
(i)
If any Bankers’ Acceptance is outstanding on the Demand Date or the Maturity Date, the Borrower shall on such date pay to the Agent for the account of the Lenders at the Branch in Canadian Dollars an amount equal to the face amount of such Bankers’ Acceptance.




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(ii)
All funds received by the Agent pursuant to this Subsection 2.7(e) shall be held by the Agent for set-off on the maturity date of the Bankers’ Acceptance against the liability of the Borrower to the Lender in respect of such Bankers’ Acceptance and, until then, shall be invested from time to time in such form of investment at the Branch designated by the Borrower and approved by the Agent, for a term corresponding to the Maturity Date of the applicable Bankers’ Acceptance and shall bear interest at the rate payable by the Agent on deposits of similar currency, amount and maturity. The balance of all such funds (together with interest thereon) held by the Agent will be applied to repayment of all debts and liabilities of the Borrower to the Lender under this Agreement and the Credit Documents and following repayment of all such debts and liabilities any amount remaining shall be paid to the Borrower or as otherwise required by law.
(f)
Notice of Rollover or Conversion. The Borrower shall give the Agent notice in the form attached as Schedule 2(C) not later than 12:00 p.m. (Toronto time) on the Business Day prior to the maturity date of Bankers’ Acceptances having an aggregate principal amount equal to or exceeding Two Hundred and Fifty Thousand Canadian Dollars (Cdn.$250,000), specifying the Accommodation into which the Bankers’ Acceptances will be renewed or converted on maturity.
(g)
Obligations Absolute. The obligations of the Borrower with respect to Bankers’ Acceptances under this Agreement shall be unconditional and irrevocable, and shall be paid strictly in accordance with the terms of this Agreement under all circumstances, including, without limitation, the following circumstances:
(i)
any lack of validity or enforceability of any Draft accepted by a Lender as a Bankers’ Acceptance; or
(ii)
the existence of any claim, set-off, defence or other right which the Borrower may have at any time against the holder of a Bankers’ Acceptance, a Lender or any other person or entity, whether in connection with this Agreement or otherwise.
(h)
Shortfall on Drawdowns, Rollovers and Conversions. The Borrower agrees that:
(i)
the difference between the amount of a Borrowing requested by the Borrower by way of Bankers’ Acceptances and the actual proceeds of the Bankers’ Acceptances;
(ii)
the difference between the actual proceeds of a Bankers’ Acceptance and the amount required to pay a maturing Bankers’ Acceptance if a Bankers’ Acceptance is being rolled over; and
(iii)
the difference between the actual proceeds of a Bankers’ Acceptance and the amount required to repay any Borrowing which is being converted to a Bankers’ Acceptance;




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shall be funded and paid by the Borrower from its own resources, by 12:00 p.m. (Toronto time) on the day of the Borrowing or may be advanced as a Prime Rate Loan if the Borrower is otherwise entitled to such Accommodation and the Agent will apply such Prime Rate Loan to discharge the obligations of the Borrower under such Bankers’ Acceptance. Any such Prime Rate Loan so made shall be subject to the terms and provisions of this Agreement, including payment of interest at the rates specified in Section 3.1.
(i)
Depository Bills and Notes Act. At the option of any Lender, Bankers’ Acceptances under this Agreement to be accepted by that Lender may be issued in the form of Depository Bills for a deposit with the Canadian Depository for Securities Limited pursuant to the Depository Bills and Notes Act (Canada). All Depository Bills so issued shall be governed by the provisions of this Section 2.7.
2.8
Letters of Credit
(a)
As provided under Section 2.4, a Borrowing Notice for a Borrowing by way of Letter of Credit shall be in the form required by the Letter of Credit Lender. If the Borrower is otherwise entitled to make a Borrowing under the Letter of Credit, the Letter of Credit Lender shall issue the Letter of Credit to the Borrower on the Borrowing Date, or as soon thereafter as the Letter of Credit Lender is satisfied with the form of Letter of Credit to be issued.
(b)
The Letter of Credit Lender will notify the Borrower and the Agent of any payment made by the Letter of Credit Lender under any Letter of Credit. The Borrower will immediately following receipt of any such notice provide to the Agent for the account of the Letter of Credit Lender funds in an amount equal to the amount of such payment made by the Letter of Credit Lender, either by payment of such amount or through utilization of the Credit Facilities, in accordance with this Agreement. If the Borrower does not provide such funds as provided for above, the Letter of Credit Lender may (but shall not be obliged to and without prejudice to the Letter of Credit Lender’s rights in respect of such failure of the Borrower) make a Prime Rate Loan to the Borrower whether or not a Default or Event of Default has occurred in an amount equal to the amount of such payment made by the Lender, and apply such Loan to reimburse the Lender for payments made pursuant to such Letter of Credit. Such Loan shall be subject to the terms and provisions of this Agreement including payment of interest at the rates specified in Subsection 3.1(a) or (b) as applicable.
(c)
If any Letter of Credit is outstanding on the Demand Date or the Maturity Date, the Borrower shall on such date pay to the Agent for the account of the Letter of Credit Lender at the Branch in Canadian Dollars, an amount equal to the amount of all Accommodation obtained by the Borrower by way of such Letter of Credit or provide security therefor satisfactory to the Lender.
(d)
All funds received by the Agent pursuant to Subsection 2.8(c) shall be held by the Agent for set-off on the date of payment by the Letter of Credit Lender under the Letter of Credit against the liability of the Borrower to the Letter of Credit Lender in respect of such Letter of Credit and, until then, shall be invested from time to time




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in such form of investment designated by the Borrower and approved by the Agent for such term as the Agent may determine and shall bear interest at the rate payable by the Agent on deposits of similar currency, amount and maturity. The balance of all such funds (together with interest thereon) held by the Agent will be applied to repayment of all debts and liabilities of the Borrower to the Letter of Credit Lender under this Agreement and the Credit Documents, and following repayment of all such debts and liabilities any amount remaining shall be paid to the Borrower or as otherwise required by law.
2.9
LIBOR Loans
(a)
LIBOR Loans shall only be made available to the Borrower to the extent the Agent determines (which determination shall be made in good faith and shall be conclusive and binding) that U.S. Dollars are available to the Lenders on the London interbank eurocurrency market. The Agent will use all reasonable efforts to coordinate the obtaining of U.S. Dollars on the London interbank eurocurrency market and to quote LIBOR Rates on request of the Borrower from time to time. If at any time prior to the proposed commencement of a LIBOR Interest Period the Agent shall determine (which determination shall be made in good faith and shall be conclusive and binding) that by reason of circumstances affecting the London interbank eurocurrency market or the position of the Majority Lenders therein (i) adequate and reasonable means do not exist for ascertaining the LIBOR Rate to be applicable during such LIBOR Interest Period, (ii) the proposed LIBOR Rate does not adequately and fairly reflect the cost to the Lenders of funding or maintaining such LIBOR Loans, or (iii) U.S. Dollars for such LIBOR Interest Period are not readily available to the Lenders, as the case may be, in the London interbank eurocurrency market, then the Agent shall give notice thereof to the Borrower prior to 10:30 a.m. on the day which is two (2) Business Days in advance of the proposed commencement of such LIBOR Interest Period, and such Loan, if not then outstanding as a LIBOR Loan, shall not be made and, if then outstanding as a LIBOR Loan, the Borrower shall then give a Borrowing Notice in accordance with Section 2.4 converting the LIBOR Loan on the expiration of the then applicable LIBOR Interest Period to another Accommodation.
(b)
The Borrower shall give the Agent notice in writing not later than 10:00 a.m. on the third Business Day prior to the expiry of the LIBOR Interest Period in respect of a LIBOR Loan specifying the new LIBOR Interest Period (if the LIBOR Loan is to be renewed) or the Accommodation into which the LIBOR Loan will be converted on such expiry.
(c)
If no notice is given by the Borrower as provided in paragraph (a) or (b) above, the LIBOR Loan will be automatically converted on the expiration of the then applicable LIBOR Interest Period to a U.S. Base Rate Loan, without prejudice to the Lenders’ rights in respect of the failure to give the notice and whether or not a Default or Event of Default has occurred, in the principal amount of the funds required to be provided to the Agent for the account of the Lenders pursuant to this Section.
(d)
If any LIBOR Loan is outstanding on the Demand Date or the Maturity Date, the Borrower shall on such date pay to the Agent for the account of the Lenders at the




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Branch in U.S. Dollars an amount equal to the principal amount of such LIBOR Loan.
(e)
All funds received by the Agent pursuant to paragraph (d) shall be held by the Agent for set-off on the maturity date of the LIBOR Loan against the liability of the Borrower to the Lenders in respect of such LIBOR Loan and, until then, shall be invested from time to time in such form of investment at the Branch designated by the Borrower and approved by the Agent, for a term corresponding to the maturity date of the applicable LIBOR Loan and shall bear interest at the rate payable by the Agent on deposits of similar currency, amount and maturity. The balance of all such funds (together with interest thereon) held by the Agent will be applied to repayment of all debts and liabilities of the Borrower to the Lenders under this Agreement and the Credit Documents and following repayment of all such debts and liabilities any amount remaining shall be paid to the Borrower or as otherwise required by law.
(f)
Each Lender shall advance its Proportionate Share of each LIBOR Loan in accordance with the following provisions:
(i)
the Agent shall advise each Lender of its receipt of a notice from a Borrower pursuant to Section 2.4 on the day such notice is received and shall, as soon as possible, advise each Lender of the amount of its Proportionate Share of any Borrowing by way of LIBOR Loan requested by the notice;
(ii)
each Lender shall deliver its share of the Borrowing to the Agent’s Account at the Branch not later than 11:00 a.m. on the Borrowing Date;
(iii)
when the Agent determines that all the conditions precedent to a Borrowing specified in this Agreement have been met, it shall advance to the Borrower the amount delivered by each Lender by crediting the Borrower’s Account, but if the conditions precedent to the Borrowing are not met by 2:30 p.m. on the Borrowing Date, the Agent shall return the funds to the Lenders or invest them in an overnight investment as orally instructed by each Lender until such time as the LIBOR Loan is advanced; and
(iv)
if the Agent determines that the amount of a Lender’s Proportionate Share of the LIBOR Loan would not be a whole multiple of One Hundred Thousand U.S. Dollars (U.S.$100,000), the amount to be advanced by that Lender may be increased or reduced by the Agent in its sole discretion to the nearest whole multiple of One Hundred Thousand U.S. Dollars (U.S.$100,000).
2.10
Safekeeping of Drafts
The responsibility of the Agent and the Lenders in respect of the safekeeping of Drafts, Bankers’ Acceptances and other bills of exchange which are delivered to any of them hereunder shall be limited to the exercise of the same degree of care which such party gives to its own property, provided that such party shall not be deemed to be an insurer thereof.
2.11
Certification to Third Parties




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The Agent will promptly provide to the Borrower and third parties at the request of the Borrower a certificate as to the Canadian Dollar Amount of Accommodation outstanding from time to time under this Agreement, and giving such other particulars in respect of the Indebtedness as the Borrower may reasonably request.
2.12
Successor LIBOR Rate
(a)
Notwithstanding anything to the contrary in this Agreement, if the Agent determines (which determination shall be final, conclusive and binding upon the Borrower absent manifest error), or the Borrower or the Majority Lenders notify the Agent (with, in the case of the Majority Lenders, a copy to Borrower) that the Borrower or the Majority Lenders (as applicable) have determined, that:
(i)
adequate and reasonable means do not exist for ascertaining the LIBOR Rate for any requested Contract Period, including because the Reuters Screen LIBOR01 Page (or any display substitutes therefor) of Reuters (or any successor thereof or Affiliate thereof) (the “Screen Rate”) is not available or published on a current basis and such circumstances are unlikely to be temporary; or
(ii)
the administrator of the applicable Screen Rate or a Government Authority having jurisdiction over the Agent has made a public statement identifying a specific date after which the applicable Screen Rate shall no longer be made available, or used for determining the interest rate of loans (such specific date, the “Scheduled Unavailability Date”); or
(iii)
syndicated loans currently being executed, or that include language similar to that contained in this Section 2.12, are being executed or amended (as applicable) to incorporate or adopt a new benchmark interest rate to replace the LIBOR Rate or the Reuters Screen LIBOR01 Page (or any display substitutes therefor) of Reuters (or any successor thereof or Affiliate thereof), as applicable,
then, reasonably promptly after such determination by the Agent or receipt by the Agent of such notice, as applicable, the Agent and the Borrower may amend this Agreement to replace the LIBOR Rate with an alternate benchmark rate selected by the Agent and the Borrower (including any mathematical or other adjustments to the benchmark (if any) incorporated therein), giving due consideration to any evolving or then existing convention for similar multi-currency syndicated credit facilities for such alternative benchmarks (any such proposed rate, a “Successor Rate”), together with any proposed Successor Rate Conforming Changes, and any such amendment shall become effective at 5:00 p.m., Toronto time, on the fifth Business Day after the Agent shall have posted such proposed amendment to all Lenders and the Borrower unless, prior to such time, the Lenders comprising the Majority Lenders have delivered to the Agent written notice that the Majority Lenders do not accept such amendment.




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(b)
If no Successor Rate has been determined and the circumstances under Section 2.12(a) exist or the Scheduled Unavailability Date has occurred (as applicable), the Agent will promptly so notify the Borrower and each Lender. Thereafter, the Lenders shall not be required to honour any Advance or Borrowing Notice, as applicable, requesting a Borrowing by way of a LIBOR Loan under this Agreement. Upon receipt of such notice, (A) the Borrower may revoke any pending request for a conversion to or rollover of such LIBOR Loan (to the extent of the affected LIBOR Loan or Contract Period, as applicable) or, failing that, will be deemed to have converted such request into a request for conversion or rollover to a U.S. Base Rate Loan in the amount specified therein, and (B) the Borrower hereby instructs the Agent to repay each affected LIBOR Loan with the proceeds of a U.S. Base Rate Loan in the amount of such affected LIBOR Loan in each case to be drawn down on the last day of the then current Contract Period.
(c)
Notwithstanding anything else herein, any definition of “Successor Rate” shall provide that in no event shall such Successor Rate be less than zero for purposes of this Agreement.
(d)
For purposes of this Section 2.12, “Successor Rate Conforming Changes” means, with respect to any proposed Successor Rate, any conforming changes to the definitions of LIBOR Interest Period, Contract Period, timing and frequency of determining rates and making payments of interest and other administrative matters as may be appropriate, in the discretion of the Agent, to reflect the adoption of such Successor Rate and to permit the administration thereof by the Agent in a manner substantially consistent with market practice (or, if the Agent determines that adoption of any portion of such market practice is not administratively feasible or that no market practice for the administration of such Successor Rate exists, in such other manner of administration as the Agent determines in consultation with the Borrower).
ARTICLE 3    
INTEREST
3.1
Interest on Loans
(a)
Prime Rate Loan. Each Prime Rate Loan shall bear interest (both before and after demand, maturity, default and, to the extent permitted by law, judgment, with interest on overdue interest at the same rate) from and including the Borrowing Date for such Loan to, but not including, the date of repayment of such Loan on the unpaid principal amount of such Loan at a nominal rate per annum equal to the Prime Rate, which shall, in each case, change automatically without notice to the Borrower as and when the Prime Rate shall change so that at all times the rates set forth above shall be the Prime Rate then in effect. Interest on each Prime Rate Loan shall be computed on the basis of the actual number of days elapsed divided by three hundred and sixty-five (365) or three hundred and sixty-six (366), as applicable. Interest in respect of outstanding Prime Rate Loans shall be payable monthly in arrears on the first Business Day of each month; provided, however, that interest on overdue interest shall be payable on demand.




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(b)
U.S. Base Rate Loan. Each U.S. Base Rate Loan shall bear interest (both before and after demand, maturity, default and, to the extent permitted by law, judgment, with interest on overdue interest at the same rate) from and including the Borrowing Date for such Loan to, but not including, the date of repayment of such Loan on the unpaid principal amount of such Loan at a nominal rate per annum equal to the U.S. Base Rate, which shall, in each case, change automatically without notice to the Borrower as and when the U.S. Base Rate shall change so that at all times the rates set forth above shall be the U.S. Base Rate then in effect. Interest on each U.S. Base Rate Loan shall be computed on the basis of the actual number of days elapsed divided by three hundred and sixty-five (365) or three hundred and sixty-six (366), as applicable. Interest in respect of outstanding U.S. Base Rate Loans shall be payable monthly in arrears on the first Business Day of each month; provided, however, that interest on overdue interest shall be payable on demand.
(c)
LIBOR Loans. Each LIBOR Loan shall bear interest (both before and after demand, maturity, default and, to the extent permitted by law, judgment, with interest on overdue interest at the same rate) from and including the Borrowing Date for such LIBOR Loan to, but not including, the date of repayment thereof on the unpaid principal amount thereof at a nominal rate per annum equal to the LIBOR Rate determined by the Agent for each LIBOR Interest Period applicable to such LIBOR Loan plus the Applicable Margin in effect on the first day of such LIBOR Interest Period. Interest on each LIBOR Loan shall be computed on the basis of the actual number of days elapsed divided by three hundred and sixty (360). Interest in respect of each LIBOR Loan shall be payable on the last day of each LIBOR Interest Period applicable thereto and also, with respect to each LIBOR Interest Period which is longer than ninety (90) days, the last day of such LIBOR Interest Period and each date within such LIBOR Interest Period which is the first Business Day following the expiration of each ninety (90) day interval after the first day of such LIBOR Interest Period; provided, however, that interest on overdue interest shall be payable on demand.
3.2
LIBOR Interest Period Determination
The Borrower shall select the duration of each LIBOR Interest Period by facsimile or telephone notice (to be confirmed the same day in writing) received by the Agent not later than 10:00 a.m. on the third Business Day preceding the applicable Borrowing Date. The first LIBOR Interest Period for any LIBOR Loan shall commence on (and include) the Borrowing Date for such LIBOR Loan, and each LIBOR Interest Period occurring thereafter for such LIBOR Loan shall commence on (and include) the day following the expiration of the next preceding LIBOR Interest Period. Notwithstanding the foregoing, if any LIBOR Interest Period would otherwise expire on a day which is not a Business Day, such LIBOR Interest Period shall expire on the next succeeding Business Day provided it is in the same calendar month, and otherwise shall expire on the preceding Business Day.
3.3
Interest on Overdue Amounts
The Borrower will on demand pay interest to the Agent on all amounts (other than as provided in Section 3.1) payable by the Borrower pursuant to this Agreement that are not paid when due at the




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applicable interest rate per annum from time to time set out in Category IV for the Applicable Margin for Prime Rate Loans provided in the definition of “Applicable Margin”, in the case of amounts payable in Canadian Dollars, or, the applicable interest rate per annum from time to time set out in Category IV for the Applicable Margin for US Base Rate Loans provided in the definition of “Applicable Margin” in the case of amounts payable in U.S. Dollars, in each case calculated daily and compounded monthly from the date of payment until paid in full (both before and after demand, maturity, default and, to the extent permitted by law, judgment), with interest on overdue interest at the same rate.
3.4
Other Interest
The Borrower shall pay interest on all amounts payable hereunder at the rate specified herein or, if no rate is specified, at the Prime Rate plus the Applicable Margin calculated daily and compounded monthly, from the date due until paid in full (both before and after demand, maturity, default and, to the extent permitted by law, judgment).
3.5
Interest Act (Canada)
For the purpose of the Interest Act (Canada), and disclosure thereunder, whenever any interest or any fee to be paid hereunder or in connection herewith is to be calculated on the basis other than a calendar year, the yearly rate of interest to which the rate used in such calculation is equivalent is the rate so used, multiplied by the actual number of days in the calendar year in which the same is to be ascertained and divided by the number of days used in the basis of such determination.
The Borrower and the General Partner acknowledge and confirm that this Section 3.5 satisfies the requirements of Section 4 of the Interest Act (Canada) to the extent it applies to the expression or statement of any interest payable under this Agreement and that each of the Borrower and the General Partner is able to calculate the yearly rate or percentage of interest payable under this Agreement based upon the methodology set out in this Section 3.5. The Borrower and the General Partner each agree not to plead or assert, whether by way of defence or otherwise, in any proceeding relating to this Agreement, that the interest payable hereunder and the calculation of interest herein have not been adequately disclosed to them, whether pursuant to Section 4 of the Interest Act (Canada) or any other Applicable Law or legal principle.
3.6
Deemed Reinvestment Principle
For the purpose of the Interest Act (Canada), the principle of deemed reinvestment of interest shall not apply to any interest calculation under this Agreement and the rates of interest stipulated in this Agreement are intended to be nominal rates and not effective rates or yields.
3.7
Maximum Return
It is the intent of the parties hereto that the return to the Lenders pursuant to this Agreement shall not exceed the maximum return permitted under the laws of Canada and if the return to the Lenders would, but for this provision, exceed the maximum return permitted under the laws of Canada, the return to the Lenders shall be limited to the maximum return permitted under the laws of Canada and this Agreement shall automatically be modified without the necessity of any further act or deed to give effect to the restriction on return set forth above.




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ARTICLE 4    
FEES
4.1
Acceptance Fees
Upon the acceptance of any Draft pursuant to this Agreement, the Borrower will pay to the Agent for the account of the relevant Lenders an acceptance fee in Canadian Dollars calculated on the face amount and the term of such Draft, in accordance with the Applicable Margin in effect on the date of acceptance. The acceptance fees payable by the Borrower shall be calculated on the face amount of the Bankers’ Acceptance and shall be calculated on the basis of the number of days in the term of such Bankers’ Acceptance.
4.2
Letter of Credit
(a)
The Borrower shall pay in advance, on a quarterly basis, to the Agent for the account of the Letter of Credit Lender the following:
(i)
a fee (“LC Fee”) payable upon the issuance, extension or renewal of each Letter of Credit calculated by multiplying the Applicable Margin by the amount of such Letter of Credit; provided however that the minimum LC Fee for each Letter of Credit shall be an aggregate total of at least Two Hundred Canadian Dollars (Cdn.$200.00) per annum (based on quarterly payments equal to Fifty Canadian Dollars (Cdn.$50.00) per quarter); and
(ii)
any and all standard administration fees charged from time to time by the Lender, including any reasonable out-of-pocket expenses incurred by the Lender.
(b)
The initial quarterly payment of the minimum LC Fee with respect to each Letter of Credit shall be payable the date upon which such Letter of Credit is issued, extended or renewed, as the case may be.
(c)
Notwithstanding the foregoing, the minimum LC Fee shall not be payable by the Borrower in connection with the issuance, extension or renewal of a Letter of Credit prior to May 1, 2013.
4.3
Standby Fee
The Borrower shall pay to the Agent a standby fee in Canadian Dollars so long as the Agent has not demanded or the Lenders have not ceased to make further advances under Section 11.2, calculated in accordance with the Applicable Margin on the amount of the Undisbursed Credit in existence during the period of calculation and as adjusted automatically upon any change thereof. Accrued standby fees shall be calculated quarterly and be due and payable quarterly in arrears on the first Business Day after the end of each quarter of each Fiscal Year of the Borrower.
4.4
Basis of Calculation of Fees




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The fees payable under Sections 4.1, 4.2 and 4.3 with respect to any period shall be calculated on the basis of the actual number of days in such period divided by three hundred and sixty-five (365) days or three hundred and sixty-six (366) days, as the case may be.
4.5
Extension Fee
In consideration of the Lenders amending the terms of this Agreement as set out herein, the Borrower shall pay to the Agent on the acceptance, execution and delivery of this Agreement an up-front fee of 3.5 bps on Cdn.$75,000,000, which for clarity is Cdn.$26,250.
ARTICLE 5    
PAYMENT
5.1
Voluntary Repayment of Outstanding Accommodation
(a)
Repayments. The Borrower shall have the right to voluntarily repay, which for the purpose of (i), (ii) and (iii) below includes renewals and conversions of, outstanding Accommodations from time to time on any Business Day without premium on the terms and conditions set forth in this Section and thereby permanently reducing the Credit Facilities:
(i)
With respect to any voluntary repayment of Accommodation (other than Overdrafts), unless the Agent with the consent of the Lenders otherwise approves, the Canadian Dollar Amount of Accommodation included in such repayment shall be Ten Million Canadian Dollars (Cdn.$10,000,000) or whole multiples of One Million Canadian Dollars (Cdn.$1,000,000) or the entire amount of that type of Accommodation outstanding, the U.S. Dollar amount of Accommodation included in such repayment shall be Ten Million U.S. Dollars (U.S.$10,000,000) or whole multiples of One Million U.S. Dollars (U.S.$1,000,000) or the entire amount of that type of Accommodation outstanding, and the Borrower shall give the Agent a written notice of repayment, specifying the amount, the type or types of Accommodation to be included in the repayment (and where such Accommodation includes any Loan, the currency thereof and the interest rate applicable thereto) and the applicable voluntary repayment date, which notice shall be irrevocable by the Borrower. The notice of repayment shall be given to the Agent not later than 10:00 a.m.:
(A)
on the second Business Day preceding the applicable repayment date in the case of Loans with a Canadian Dollar Amount in the aggregate equal to or greater than Ten Million Canadian Dollars (Cdn.$10,000,000);
(B)
on the second Business Day preceding the applicable repayment date in the case of Bankers’ Acceptances in an aggregate face amount equal to or greater than Ten Million Canadian Dollars (Cdn.$10,000,000); and




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(C)
on the third Business Day preceding the applicable repayment date in the case of LIBOR Loans.
(ii)
In all other cases, notice of repayment shall be given on the applicable repayment date.
(iii)
Any notice of repayment received by the party entitled thereto on any Business Day after 11:00 a.m. shall be deemed to have been given to such party on the next succeeding Business Day. A notice of repayment of Accommodation may be included as part of a Borrowing Notice in respect of other Accommodation.
(iv)
With respect to voluntary repayment of Overdrafts, there is no requirement for a minimum payment and no requirement for notice.
(v)
On the applicable voluntary repayment date the Borrower shall pay to the Agent for the account of the Lenders, the amount of any Accommodation that is subject to the repayment, together with all interest and other fees and amounts accrued, unpaid and due in respect of such repayment; provided, however, that accrued interest will not be repayable prior to the applicable interest payment date in Section 3.1 in respect of Overdrafts or in respect of Prime Rate Loans or U.S. Base Rate Loans unless the full balance outstanding thereunder is voluntarily repaid.
(b)
Repayment of Certain Types of Accommodation. The following provisions shall also apply to the voluntary repayment by the Borrower of the following types of Accommodation:
(i)
Subject to Subsection 5.1(c), no repayment of any LIBOR Loan shall be made otherwise than upon the expiration of any applicable LIBOR Interest Period; and
(ii)
No repayment of any outstanding Accommodation in the form of a Bankers’ Acceptance shall be made otherwise than upon the expiration or maturity date or, in the case of a Letter of Credit, on the date of surrender thereof to the Letter of Credit Lender.
(c)
Repayment of LIBOR Loans. Notwithstanding Subsections 5.1(a) and 5.1(b), a LIBOR Loan may be repaid at any time within the thirty (30) day period after the Borrower receives notice that it is required to pay any amount under Section 6.6 in respect of such Accommodation, provided that in addition to the other amounts required to be paid pursuant to this Section at the time of such repayment, the Borrower pays to the Agent for the account of the Lenders at such time all reasonable breakage costs incurred by the Lenders with respect to, and all other amounts payable by the Borrower under Sections 6.7 and 6.8 in connection with, such repayment. A certificate of a Lender or Lenders as to such costs, providing details of the calculation of such costs, shall be prima facia evidence.




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5.2
Repayment on Maturity Date and Extension
(a)
Subject to Subsections 2.7(e), 2.8(c), 2.9(d) and to this Section, the Borrower shall repay in full all outstanding Accommodation, together with all interest, fees and other amounts payable hereunder on the applicable Maturity Date to the Agent for the account of the Letter of Credit Lender, the Overdraft Lender or the Lenders, as applicable.
(b)
By notice in writing to the Agent in the form of Schedule 3 (a “Notice of Extension”) given not more than 90 and not less than 45 days prior to each anniversary date of the date of this Agreement, the Borrower may request each Lender to extend the Maturity Date of such Lender for an additional period of 365 days. The Lenders agree that they shall give or withhold their consent in a timely manner so that the Agent may provide a response to the Borrower to the Notice of Extension within thirty (30) days from the date of such receipt, provided that the decision of any Lender to extend the Maturity Date in respect of such Lender shall be at the sole discretion of such Lender. The Borrower shall be entitled to replace any Lender which dissents in response to the Notice of Extension (a “Dissenting Lender”) with another existing Lender or Lenders without the consent of any of the remaining Lenders; or to replace a Dissenting Lender with any financial institution which is not an existing Lender with the consent of the Agent, such consent not to be unreasonably withheld. The Borrower shall be entitled, with the unanimous consent of the Lenders who have agreed to extend, to permanently cancel the Commitment of any Dissenting Lender and repay such Dissenting Lender, at which time the Committed Amount shall be permanently reduced by the amount of such Commitment.
5.3
Excess Accommodation
In addition to the other repayment rights, obligations or options set forth in this Article, if the aggregate Canadian Dollar Amount of all Accommodation outstanding under the Credit Facility at any time exceeds the then limit of the Credit Facility, the Borrower shall immediately upon request of the Agent:
(a)
to the extent any of the Accommodation is Prime Rate Loans, U.S. Base Rate Loans or Bankers’ Acceptances, repay such excess; or
(b)
in the case of LIBOR Loans, pay to the Agent for the account of the Lenders an amount in U.S. Dollars equivalent to the amount by which the limit of the Credit Facility is exceeded.
Funds paid under paragraph (b) shall be invested from time to time in such form of investment at the Branch designated by the Borrower and approved by the Agent, for terms corresponding to the applicable LIBOR Interest Period or the term of the other applicable Accommodation, as the case may be, and shall bear interest at the rate payable by the Agent on deposits of similar currency, amount and maturity.
5.4
Illegality




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Notwithstanding any other provision of this Agreement, if the making or continuation of any Accommodation shall have been made unlawful or prohibited due to compliance by any of the Agent and the Lenders in good faith with any change made after the date hereof in any law or governmental rule, regulation, guideline or order, or in any interpretation or application of any law or governmental rule, regulation, guideline or order by any competent authority, or with any request or directive (whether or not having the force of law) by any central bank, reserve board, superintendent of financial institutions or other comparable authority made after the date hereof, then the Agent will give notice thereof to the Borrower which shall repay such Accommodation within a reasonable period or such shorter period as may be required by law. During the continuation of any such event the Lenders will have no obligation under this Agreement to make or continue any Accommodation affected thereby.
ARTICLE 6    
PAYMENTS AND INDEMNITIES
6.1
Payments on Non-Business Days
Unless otherwise provided herein, whenever any payment to be made under this Agreement shall be stated to be due on a day which is not a Business Day, the due date thereof shall be extended to the next succeeding Business Day, and interest or fees shall be payable at the appropriate rate during such extension.
6.2
Method and Place of Payment
Unless otherwise provided herein, all payments made by the Borrower to the Agent under this Agreement will be made not later than 2:00 p.m. (Toronto, Ontario time) on the date when due, and all such payments will be made in immediately available funds. Any amounts received after that time shall be deemed to have been received by the Agent on the next Business Day.
6.3
Net Payments
All payments by the Borrower under this Agreement shall be made without set-off or counterclaim or other deduction and without regard to any equities between the Borrower and the Agent or any of the Lenders or any other Person and free and clear of, and without reduction for or on account of, any present or future levies, imposts, duties, charges, fees, deductions or other withholdings, and if the Borrower is required by law to withhold any amount, then the Borrower will increase the amount of such payment to an amount which will ensure that the Agent receives the full amount of the original payment.
6.4
Agent May Debit Account
The Agent may debit any accounts of the Borrower with the Agent for any payment or amount due and payable by the Borrower pursuant to this Agreement without further direction from the Borrower to the Agent; provided that any such debit is not in conflict with the provisions of the Trust Indenture but in any event such debits may be made in accordance with the Agent’s centralized cash management arrangements with the Borrower.
6.5
Currency of Payment




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Accommodation shall be repaid by the Borrower to the Agent or a Lender as required under this Agreement in the currency in which such Accommodation was obtained. Any payment on account of an amount payable under this Agreement in a particular currency (the “Proper Currency”) required by any authority having jurisdiction to be made (or which a Lender elects to accept) in a currency (the “Other Currency”) other than the Proper Currency, whether pursuant to a judgment or order of any court or tribunal or otherwise, shall constitute a discharge of the Borrower’s obligations under this Agreement only to the extent of the amount of the Proper Currency which each applicable Lender is able, as soon as practicable after receipt by it of such payment, to purchase with the amount of the Other Currency so received. If the amount of the Proper Currency which a Lender is so able to purchase is less than the amount of the Proper Currency originally due to it, the Borrower shall indemnify and hold such Lender harmless from and against all losses, costs, damages or expenses which such Lender may sustain, pay or incur as a result of such deficiency. This indemnity shall constitute an obligation separate and independent from any other obligation contained in this Agreement, shall give rise to a separate and independent cause of action, shall apply irrespective of any indulgence granted by the Lenders from time to time, shall continue in full force and effect notwithstanding any judgment or order for a liquidated sum in respect of an amount due under this Agreement or under any judgment or order and shall not merge in any order of foreclosure made in respect of any of the security given by the Borrower to or for the benefit of any Lender.
6.6
Increased Costs
If after the date of this Agreement any change in any law, regulation, treaty, directive, reserve or special deposit requirement or in the interpretation or application thereof by any court or administrative or governmental authority charged with the administration thereof, or compliance by a Lender with any request or directive (whether or not having the force of law) by any central bank, reserve board, superintendent of financial institutions, fiscal, monetary or other comparable authority shall:
(a)
subject the Lender to any tax of any kind whatsoever with respect to this Agreement or any Accommodation or change the basis of taxation of payments to the Lender of principal, interest, fees or any other amount payable under this Agreement (except for changes in the rate of tax on the overall net income of the Lender or capital tax imposed by the laws of Canada or any political subdivision thereof or taxing authority therein); or
(b)
impose, modify or make applicable any capital adequacy, reserve, assessment, special deposit or loans or similar requirement against assets held by, or deposits or other liabilities in or for the account of, or Loans or other Accommodation, credit facilities or commitments made available by, or any other acquisition of funds by, the Lender;
and the result of any of the foregoing is to impose or increase the cost to the Lender of making or maintaining any part of the Credit Facilities or any Accommodation or to reduce any amount receivable by the Lender under this Agreement with respect thereto, then, in any such case, the Borrower shall pay to the Agent for the account of the relevant Lender within thirty (30) days after the date of demand by the Agent such additional amounts necessary to fully compensate the Lender for such additional cost or reduced amount receivable. If a Lender becomes entitled to claim any




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additional amounts pursuant to this Section, the Agent shall promptly upon receipt of particulars from the relevant Lender notify the Borrower of the event by reason of which the Lender has become so entitled and provide the Borrower with an explanation of the manner in which the liability of the Borrower under this Section has been determined. A certificate of the Lender as to any such additional amounts payable to it shall be prima facie evidence of the amount due.
6.7
General Indemnity
The Borrower shall indemnify the Agent and the Lenders and their directors, officers, employees, attorneys and agents against and hold each of them harmless from any loss, liabilities, damages, claims, costs and expenses (including fees and expenses of counsel to the Agent and the Lenders on a solicitor and his own client basis and reasonable fees and expenses of all independent consultants) (each a “Claim”) suffered or incurred by any of them arising out of, resulting from or in any manner connected with or related to:
(a)
any Environmental Matter, Environmental Liability or Environmental Proceeding; and
(b)
any loss or expense incurred in liquidating or re-employing deposits from which such funds were obtained, which the Agent or Lender may sustain or incur as a consequence of:
(i)
failure by the Borrower to make payment when due of the principal amount of or interest on any LIBOR Loan;
(ii)
failure by the Borrower in proceeding with a Borrowing after the Borrower has given a Borrowing Notice;
(iii)
failure by the Borrower in repaying a Borrowing after the Borrower has given a notice of repayment;
(iv)
any breach, non-observance or non-performance by the Borrower of any of its obligations, covenants, agreements, representations or warranties contained in this Agreement; and
(v)
except as otherwise provided in Subsection 5.1(c), the repayment of any LIBOR Loan otherwise than on the expiration of any applicable LIBOR Interest Period or the repayment of any Bankers’ Acceptance otherwise than on the maturity date thereof.
The indemnity set forth herein shall be in addition to any other obligations or liabilities of the Borrower to any of the Agent and the Lenders at common law or otherwise and this Section and Section 6.3 shall survive the repayment of the Accommodation and the termination of this Agreement. A certificate of the Lender as to any such loss or expense, providing details of the calculation of such loss or expense, shall be prima facie evidence.
6.8
Early Termination of LIBOR Interest Period




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Without limiting Section 6.7, if the Agent is required to arrange for early termination of any LIBOR Interest Period or to arrange to acquire funds for any period other than a LIBOR Interest Period to permit the Borrower to repay any LIBOR Loan, the Borrower shall reimburse the Lenders for all losses and reasonable out-of-pocket expenses incurred by them as a result of the early termination of the LIBOR Interest Period in question or as a result of entering into the new arrangement to the extent that such losses and expenses result from such payment. If any such early termination or new arrangement cannot be effected by the Agent on behalf of the Lenders, the Borrower shall continue to pay interest to the Agent in U.S. Dollars at the LIBOR Rate specified hereunder upon an amount of U.S. Dollars equal to the amount of the principal repayment for the remainder of the then current LIBOR Interest Period. The indemnity set forth herein shall be in addition to any other obligations or liabilities of the Borrower to any of the Agent and the Lenders at common law or otherwise and this Section shall survive the repayment of the Accommodation and the termination of this Agreement. A certificate of a Lender or Lenders as to any such loss or expense, providing details of the calculation of such loss or expense, shall be prima facie evidence.
6.9
Outstanding Bankers’ Acceptances and Letters of Credit
If the Credit Facility is terminated at any time prior to the maturity date of any Bankers’ Acceptance or Letter of Credit issued hereunder, the Borrower shall pay to the Lenders, on demand, an amount with respect to each such Bankers’ Acceptance or Letter of Credit equal to the total amounts which would be required to purchase in the Canadian Dollars market, as of 10:00 a.m. on the date of payment of such demand, Government of Canada treasury bills in an aggregate amount equal to the face amount of such Bankers’ Acceptance or Letter of Credit and having in each case a term to maturity similar to the period from such demand to maturity of such Bankers’ Acceptance or Letter of Credit. Upon payment by the Borrower as required under this Section, the Borrower shall have no further liability in respect of each such Bankers’ Acceptance or Letter of Credit and the Lenders shall be entitled to all of the benefits of, and be responsible for all payments to third parties under, such Bankers’ Acceptance or Letter of Credit and the Lenders shall indemnify and hold harmless the Borrower in respect of all amounts which the Borrower may be required to pay under each such Bankers’ Acceptance or Letter of Credit to any party other than the Lenders.
6.10
Replacement of Lender
Notwithstanding any other item or condition of this Agreement, if the Borrower becomes obligated in respect of a Lender to pay any additional amounts as provided in Section 6.6 and such additional payments are of a permanent nature, then the Borrower may, at its option, upon thirty (30) Business Days notice to the Agent and that Lender (which notice shall be irrevocable):
(a)
require such Lender to assign its full Commitment under which such Advances were made (such commitments being the “Affected Commitments”) and all outstanding Advances thereunder, to one or more assignees identified by the Borrower and acceptable to the Agent, acting reasonably, the assignment(s) to which assignee(s) shall have been made in accordance with Section 12.14; or
(b)
terminate the Affected Commitments and repay to such Lender any Advances outstanding thereunder to the extent such Affected Commitments and Advances thereunder are not assigned pursuant to Subsection 6.10(a).




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ARTICLE 7    
SECURITY
7.1
Security
As general and continuing security for the due payment and performance of all present and future indebtedness, liabilities and obligations of the Borrower to the Agent and to the Lenders under this Agreement, the Borrower shall provide to the Agent on behalf of the Lenders a pledge of the Pledged Bond, such pledge to be pursuant to the Bond Delivery Agreement. The parties hereby confirm that all present and future indebtedness, liabilities and obligations of the Borrower to the Agent and the Lenders under this Agreement and the other Credit Documents shall constitute “Obligations” for the purposes of the Nineteenth Supplemental Indenture and shall be subject to the Pledged Bond.
ARTICLE 8    
REPRESENTATIONS AND WARRANTIES
8.1
Representations and Warranties
To induce the Lenders to make Accommodation available to the Borrower, each of the Borrower and the General Partner, in its personal capacity, represents and warrants to the Agent and the Lenders that the following are true and correct in all material respects:
(a)
the Borrower is a limited partnership existing pursuant to the terms of the Partnership Act (Alberta) and has the legal capacity and right to own its property and assets and to carry on the Business;
(b)
the General Partner is a corporation, duly and validly incorporated, organized and existing as a corporation under the laws of the Province of Alberta and has the legal capacity to act as the General Partner of the Borrower;
(c)
each of the Borrower and the General Partner has the legal capacity and right to enter into the Credit Documents and do all acts and things and execute and deliver all agreements, documents and instruments as are required thereunder to be done, observed or performed by it in accordance with the terms and conditions thereof;
(d)
each of the Borrower and the General Partner has taken all necessary action to authorize the creation, execution and delivery of each of the Credit Documents, the performance of its obligations thereunder and the consummation of the transactions contemplated thereby;
(e)
each of the Credit Documents has been duly executed and delivered by each of the Borrower and the General Partner and constitutes a valid and legally binding obligation of the Borrower enforceable against it in accordance with its terms, subject only to bankruptcy, insolvency, reorganization, arrangement or other statutes or judicial decisions affecting the enforcement of creditors’ rights in general and to general principles of equity under which specific performance and injunctive relief may be refused by a court in its discretion;




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(f)
there is no existing, pending or, to the knowledge of the Borrower or the General Partner, threatened litigation by or against either of them which could reasonably be expected to be adversely determined to the rights of the Borrower or the General Partner and which could reasonably be expected to cause a Material Adverse Effect; no event has occurred, and no state or condition exists, which could give rise to any such litigation; provided, however, that if the Borrower has disclosed to the Lenders litigation which is not in compliance with the foregoing and the Lenders have waived all or any part of such non-compliance, no further waiver shall be required in respect of such litigation to the extent that the same has been waived by the Lenders;
(g)
the financial information relating to the Business delivered to the Agent pursuant to or in connection with this Agreement (the “Projection”) was prepared using assumptions that reflect the Borrower’s planned course of action for the period covered by the Projection, given management’s judgement as to the most probable set of economic conditions, together with certain hypotheses. Hypotheses are assumptions that assume a set of economic conditions or courses of action that are consistent with management’s intended course of action and represent plausible circumstances but for which there is no corroborative evidence. The Projection has been prepared as “special purpose” information (as defined under GAAP principles) and as such is not presented in the format of historical financial statements.
(h)
there has been no change which could reasonably be expected to cause a Material Adverse Effect;
(i)
the Borrower is in compliance with all Applicable Laws where any non-compliance could reasonably be expected to cause a Material Adverse Effect;
(j)
all Governmental Approvals and other consents necessary to permit the Borrower and the General Partner (i) to execute, deliver and perform each Credit Document, and to consummate the transactions contemplated thereby, and (ii) to own and operate the Business, have been obtained or effected and are in full force and effect. The Borrower is in compliance with the requirements of all such Governmental Approvals and consents and there is no Claim existing, pending or, to the knowledge of the Borrower or the General Partner, threatened which could result in the revocation, cancellation, suspension or any adverse modification of any of such Governmental Approvals or consent (except as may hereafter arise and be disclosed to the Agent);
(k)
no Default or Event of Default under this Agreement or the Trust Indenture has occurred which has not (i) been expressly waived in writing by the Agent, the Trustee under the Trust Indenture and the holders of the Senior Bonds, or (ii) been remedied (or otherwise ceased to be continuing);
(l)
the Borrower has good and marketable title to its assets, in each case free and clear of all Security Interests, other than Permitted Encumbrances;
(m)
the Borrower has paid all taxes due and owing to date;




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(n)
no essential portion of the Borrower’s real or leased property has been taken or expropriated by any Government Authority nor has written notice or proceedings in respect thereof been given or commenced nor is the Borrower aware of any intent or proposal to give any such notice or commence any such proceedings; and
(o)
the Principal Property in the name of the General Partner is and will be held by the General Partner in trust for the Borrower;
(p)
Except as disclosed to the Agent:
(i)
the Borrower does not have any knowledge of any Environmental Adverse Effect or any condition existing at, on or under the Principal Property which, in any case or in the aggregate, with the passage of time or the giving of notice or both, could reasonably be expected to give rise to liability of the Borrower resulting in a Material Adverse Effect;
(ii)
the Borrower has no knowledge of any present or prior leaks or spills with respect to underground storage tanks and piping system or any other underground structures existing at, on or under Principal Property or of any past violations by any Applicable Laws, policies or codes of practice involving the Principal Property, which violations, in any case or in the aggregate, could reasonably be expected to have a Material Adverse Effect;
(iii)
the Borrower has no knowledge that it has any obligation under any Environmental Laws to pay any compensation or damages resulting from the operation of the Principal Property, or that it will have any such obligation resulting from the maintenance and operation of the Principal Property, which, in any case or in the aggregate, could reasonably be expected to have a Material Adverse Effect; and
(iv)
the Borrower has no Environmental Liability which, in any case or in the aggregate, could reasonably be expected to have a Material Adverse Effect except as disclosed by the Borrower to the Agent in writing prior to the Effective Date.
(q)
The Borrower is not as at the date that this representation is made or deemed to be made the subject of any civil, criminal or regulatory proceeding or governmental or regulatory investigation with respect to Environmental Laws nor is it aware of any threatened proceedings or investigations which, in any case or in the aggregate, could reasonably be expected to have a Material Adverse Effect except as disclosed in accordance with the notice requirements set out in Section 9.2. The Borrower is actively and diligently proceeding to use all reasonable efforts to comply with all Environmental Laws and all such activities are being carried on in a prudent and responsible manner and with all due care and due diligence; and
(r)
As of the Effective Date, the Borrower has no Subsidiaries other than Permitted JA Subsidiaries.




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8.2
Survival of Representations and Warranties
All representations and warranties contained in this Agreement, the Credit Documents and any certificate or document delivered pursuant hereto shall survive the execution and delivery of this Agreement and the Credit Documents, the advance of each Accommodation and exercise of any remedies under this Agreement or under any of the Credit Documents, notwithstanding any investigation made at any time by or on behalf of the Agent or the Lenders.
ARTICLE 9    
COVENANTS
9.1
Trust Indenture
The Borrower covenants and agrees that so long as any Accommodation is outstanding or the Borrower is entitled to obtain any Accommodation under the Credit Facilities, the Borrower will comply with all of the covenants, both positive and negative, contained in the Trust Indenture which are hereby incorporated by reference into this Agreement. Non-compliance by the Borrower with any of these covenants cannot be waived by the Lenders other than in accordance with Subsection 12.7(c).
9.2
Covenants
The Borrower covenants and agrees that, so long as any Accommodation is outstanding or the Borrower is entitled to obtain any Accommodation under the Credit Facilities:
(a)
Information and Certificates. The Borrower shall furnish to the Agent, with sufficient copies for all Lenders:
(i)
at the time the same are sent, copies of all financial statements and other information or material that are delivered to the Trustee under the Trust Indenture including, without limitation, notice of any “Event of Default” under the Trust Indenture;
(ii)
copies of any Supplemental Indenture which amends in any way the Trust Indenture; and
(iii)
upon delivery of each of the items set out in Paragraphs 6.4(a)(i) and (ii) of the Trust Indenture, the Borrower’s Certificate of Compliance, provided, however, that the obligation of the Borrower to deliver quarterly unaudited financial statements to the Agent shall apply only to the first, second and third fiscal quarters of each Fiscal Year.
(b)
Payments Under This Agreement and Credit Documents. The Borrower shall pay, discharge or otherwise satisfy all amounts payable under this Agreement in accordance with the terms of this Agreement and all amounts payable under any Credit Document in accordance with the terms thereof.
(c)
Proceeds. The Borrower shall use the proceeds of any Accommodation only for the purposes permitted pursuant to Section 2.1.




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(d)
Inspection of Property, Books and Records, Discussions. The Borrower shall keep proper books of record and account in which full, true and correct entries in conformity with GAAP and all Applicable Laws shall be made of all dealings and transactions in relation to its business and activities, and permit representatives and agents of the Agent upon reasonable notice to the Borrower and during business hours, to visit and inspect any of the properties and examine and make abstracts from any of the books and records of the Borrower as often as may reasonably be desired, and, subject to applicable securities laws, to discuss the business, operations, property, condition and prospects (financial or otherwise) of the Borrower with those officers and employers of the Borrower designated by its senior executive officers.
(e)
Anti-Money Laundering and Terrorist Financing. The Borrower has taken, and shall continue to take, commercially reasonable measures (in any event as required by Applicable Laws) to ensure that it is and shall be in compliance with the Proceeds of Crime (Money Laundering) and Terrorist Financing Act (Canada) and all other present and future Applicable Laws of similar application to which the Borrower is subject.
(f)
Notices. The Borrower shall promptly give notice to the Agent of:
(i)
the occurrence of any Default or Event of Default;
(ii)
the commencement of, or receipt by the Borrower of a written threat of, any action, suit or proceeding against or affecting the Borrower before any Government Authority which, individually or in the aggregate, has, or has any reasonable likelihood of having, a Material Adverse Effect, and such further information in respect thereof as the Agent may request from time to time;
(iii)
any notice of any violation or administrative or judicial complaint or order having been filed or, to the Borrower’s knowledge, about to be filed against the Borrower which has, or has any reasonable likelihood of having, a Material Adverse Effect;
(iv)
any notice from any Government Authority or any other Person alleging that the Borrower is or may be subject to any Environmental Liability which has, or has any reasonable likelihood of having, a Material Adverse Effect;
(v)
the occurrence or non-occurrence of any other event which has, or has a reasonable likelihood of having, a Material Adverse Effect;
(vi)
any changes in the ownership structure to the Borrower; and
(vii)
any notice of a change in rating to the Senior Bonds by any of the Rating Agencies.
(g)
Permitted Joint Arrangements. (i) The total equity investment of the Borrower in Permitted JA Subsidiaries and Permitted Joint Arrangements shall not exceed an




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aggregate amount equal to Cdn.$200,000,000; and (ii) the Borrower shall not form any Subsidiaries other than Permitted JA Subsidiaries and shall not enter into any joint ventures or joint arrangements other than Permitted Joint Arrangements. The Borrower shall deliver to the Agent not later than sixty (60) days after the end of each fiscal quarter, an Officer’s Certificate certifying as to the matters in this paragraph (g) including regarding what portion of the above Cdn.$200,000,000 has been used and how/where it has been used.
9.3
Maintenance of Total Capitalization
(a)
The Borrower covenants and agrees that, so long as any Accommodation is outstanding or the Borrower is entitled to obtain any Accommodation under the Credit Facilities, the aggregate amount of all Indebtedness of the Borrower (other than Financial Instrument Obligations in accordance with section 6.3 of the Trust Indenture) shall not exceed seventy-five percent (75%) of the Total Capitalization of the Borrower. For greater certainty, for the purposes of this Section 9.3, (i) the foregoing calculations of both the aggregate amount of all Indebtedness of the Borrower and the Total Capitalization of the Borrower shall exclude any non-recourse debt incurred by Permitted JA Subsidiaries in connection with their related Permitted Joint Arrangements as well as any equity contributions made in respect of such Permitted Joint Arrangements, to the extent in each case that the Borrower is in compliance with Subsection 9.2(g) in respect of such joint arrangement, and (ii) when ascertaining maintenance of Total Capitalization for this purpose, the exclusions shall apply to both the numerator component of that definition (i.e. exclusion of the related debt) and to the denominator component of that definition (i.e. exclusion of the related debt and equity).
(b)
The Borrower shall deliver to the Agent not later than sixty (60) days after the end of each fiscal quarter, an Officer’s Certificate certifying as to the matter in paragraph (a) above.
ARTICLE 10    
CONDITIONS PRECEDENT TO BORROWINGS
10.1
Conditions Precedent to Effectiveness of this Agreement
The effectiveness of this Agreement is subject to the condition precedent that the Agent and each Lender shall be satisfied with, or the Borrower shall have delivered to the Agent, as the case may be, on or before the Effective Date, the following in form, substance and dated as of a date satisfactory to the Lenders and their counsel and in sufficient quantities for each Lender:
(a)
there shall exist no Default or Event of Default on the Effective Date;
(b)
all representations and warranties contained in Section 8.1 shall be true on and as of the Effective Date with the same effect as if such representations and warranties had been made on and as of the Effective Date and, if required by the Agent, the Borrower shall have delivered to the Agent a Borrower’s Certificate of Compliance;




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(c)
the Agent and the Lenders shall have received any Credit Documents required by the Agent and the Lenders duly executed by the Borrower;
(d)
the following documents in form, substance and execution acceptable to the Agent shall have been delivered to the Agent:
(i)
duly certified copies of the constating documents of the Borrower and the General Partner and of all necessary proceedings taken and required to be taken by the Borrower to authorize the execution and delivery of this Agreement and the Credit Documents to which it is a party and the entering into and performance of the transactions contemplated herein and therein;
(ii)
certificates of incumbency of the General Partner setting forth specimen signatures of the persons authorized to execute this Agreement and the Credit Documents to which it is a party;
(iii)
certificate of status or the equivalent relative to the Borrower and the General Partner under the laws of Canada or its jurisdiction of creation; and
(iv)
the opinion of counsel for the Borrower in form and substance satisfactory to the Agent and the Lenders;
(e)
the Agent and the Lenders shall have received evidence that all necessary corporate, governmental and other third party approvals have been obtained in form and substance acceptable to the Agent and the Lenders, each acting reasonably;
(f)
all fees payable on or before the date hereof in connection with the Credit Facilities under this Agreement and any fee letter shall have been paid to the applicable parties; and
(g)
the Agent and the Lenders are satisfied in their sole and absolute discretion that all of the provisions of Article 9 have been complied with to their satisfaction.
10.2
Conditions Precedent to All Borrowings, Conversions
The Lenders shall not be obliged to make available any portion of any Borrowing or to give effect to any conversion or rollover unless the Borrower (by way of the delivery of a Borrower’s Certificate of Compliance), or the Borrower’s counsel (if appropriate), confirms to the Agent that each of the following conditions is satisfied:
(a)
the Agent shall have received any required Borrowing Notice;
(b)
there shall exist no Default or Event of Default on the said Borrowing Date;
(c)
all representations and warranties contained in Section 8.1 shall be true on and as of the applicable Borrowing Date with the same effect as if such representations and warranties had been made on and as of the applicable Borrowing Date and, if required by the Agent, the Borrower shall have delivered to the Agent a Borrower’s Certificate of Compliance;




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(d)
all fees payable on or before the date of any subsequent Borrowing in connection with the Credit Facilities under this Agreement shall have been paid to the applicable party as and when due and payable thereunder; and
(e)
the Trust Indenture shall not have been amended in a manner which (i) could reasonably be expected to have a Material Adverse Effect, or (ii) modifies any section of the Trust Indenture which is incorporated by reference into this Agreement without the prior written consent of the Agent.
10.3
Waiver
The Lenders may, at their option, waive any condition precedent set out in Section 10.1 or 10.2 or make available any Borrowing prior to such condition precedent being fulfilled. Any such Borrowing shall be deemed to be made pursuant to the terms hereof. Any such waiver shall not be effective unless it is in writing and shall not operate to excuse the Borrower from full and complete compliance with this Article 10 or any other provision hereof on future occasions.
ARTICLE 11    
EVENTS OF DEFAULT
11.1
Events of Default
Any of the following events shall constitute an “Event of Default” hereunder:
(a)
Trust Indenture. Each of the events set out in Section 10.1 of the Trust Indenture including applicable notice and grace periods;
(b)
Default in Payment of any Amount Hereunder. If the Borrower fails to pay any interest, fees or any amount owing to the Lenders or any of them hereunder (other than principal amounts), or under any Credit Document when due and payable hereunder or thereunder and the Borrower fails to pay such interest, fees or any amount owing to the Lenders or any of them hereunder (other than principal amounts) within five (5) Business Days after notice is given by the Agent to the Borrower. For clarity, the failure to pay a principal payment shall be an immediate Event of Default and the Agent shall have the remedies available pursuant to Section 11.2;
(c)
Default in Other Provisions. If the Borrower shall fail, refuse or default in any material respect with the performance or observance of any of the covenants, agreements or conditions contained herein and such failure, refusal or default adversely affects the Lenders and, such failure, refusal or default continues for a period of thirty (30) days after written notice thereof by the Agent; and
(d)
Full Force and Effect. If this Agreement or any material portion hereof shall, at any time after its respective execution and delivery and for any reason, cease in any way to be in full force and effect or if the validity or enforceability of this Agreement is disputed in any manner by the Borrower and the Credit Facilities have not been repaid within thirty (30) days of demand therefor by the Agent.
11.2
Remedies




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Upon the occurrence of any Default or Event of Default, and at any time thereafter if the Default or Event of Default shall then be continuing, the Lenders in their sole discretion may direct the Agent to give notice to the Borrower that no further Accommodation will be available hereunder while the Default or Event of Default continues, whereupon the Lenders shall not be obliged to provide any further Borrowings to the Borrower while the Default or Event of Default continues. Upon the occurrence of any Event of Default, and at any time thereafter if the Event of Default shall then be continuing, the Lenders in their sole discretion, and the Agent acting on their behalf, may take any or all of the following actions:
(a)
demand payment of any principal, accrued interest, fees and other amounts which are then due and owing in respect of the Accommodation under the Credit Facilities without presentment, protest or other notice of any kind, all of which are hereby expressly waived by the Borrower to the maximum extent permitted by Applicable Laws;
(b)
declare by notice to the Borrower the Credit Facilities terminated, whereupon the same shall terminate immediately without any further notice of any kind;
(c)
demand payment of the Pledged Bond in accordance with the provisions of the Bond Delivery Agreement; and
(d)
assign all or any part of the outstanding Accommodation and the amounts payable hereunder to any Person without reference to Article 12.
11.3
Remedies Cumulative
The rights and remedies of the Lenders and the Agent under this Agreement and the Credit Documents are cumulative.
11.4
Appropriation of Moneys Received
The Lenders, and the Agent on behalf of the Lenders as between the Lenders and the Borrower, may from time to time when an Event of Default has occurred and is continuing appropriate any monies received from the Borrower in or toward payment of such of the obligations of the Borrower hereunder as the Lenders in their sole discretion may see fit.
11.5
Non-Merger
The taking of any action or dealing whatsoever by the Lender or the Agent in respect of the Borrower or any security shall not operate as a merger of any of the obligations of the Borrower to the Lenders or the Agent or in any way suspend payment or affect or prejudice the rights, remedies and powers, legal or equitable, which the Lenders or the Agent may have under Section 11.3 in connection with such obligations.
11.6
Waiver
No delay on the part of the Lenders or the Agent in exercising any right or privilege hereunder shall operate as a waiver thereof. No Default or Event of Default shall be waived except by a written waiver in accordance with Section 13.10. Each written waiver shall apply only to the Default or




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Event of Default to which it is expressed to apply. No written waiver shall preclude the subsequent exercise by the Lenders or the Agent of any right, power or privilege hereunder or extend to or apply to any other Default or Event of Default.
11.7
Set-off
Each of the Agent and any Lender with whom the Borrower maintains any account or accounts shall enter into an agreement with the Trustee, in form and substance satisfactory to the Trustee, pursuant to which the Agent or such Lender, as applicable, confirms to the Trustee that:
(a)
in respect of any Funds and Accounts (as defined in the Trust Indenture) forming part of the Collateral (as defined in the Trust Indenture), the Trustee has a security interest in such Funds and Accounts and the cash on deposit therein are Permitted Investments forming part thereof;
(b)
the Agent or such Lender, as applicable, has and will have no security interest in any such Fund or Account or the cash on deposit therein or Permitted Investments forming part thereof; and
(c)
the only rights of set-off which may be exercised by the Agent or such Lender in respect of any such Fund or Account or the cash on deposit therein or Permitted Investments forming part thereof are those arising out of the operation of the relevant account unless the Agent or such Lender has agreed to remit all amounts so set-off to the Trustee to be dealt with in accordance with the Trust Indenture;
provided that none of the foregoing shall apply to rights of set-off exercised by the Agent in the ordinary course of the operation of the Agents’ centralized cash management system with the Borrower.
Upon the occurrence of an Event of Default and a demand by the Agent for payment pursuant to Section 11.3, the Agent and each Lender is hereby authorized by the Borrower at any time and from time to time with notice to the Borrower to combine, consolidate and merge on behalf of the Trustee for the benefit of the Bondholders (as defined in the Trust Indenture) all or any of the Borrower’s Accounts with liabilities to the Agent or such Lender and to set-off, appropriate and apply on behalf of the Trustee for the benefit of such bondholders or to otherwise seize and remit to the Trustee any and all deposits by or for the benefit of the Borrower with any branch of the Agent or such Lender, general or special, matured or unmatured, and any other indebtedness and liability of the Agent or such Lender to the Borrower, matured or unmatured, against and on account of the indebtedness of the Borrower hereunder when due, notwithstanding that the balances of such accounts, deposits or indebtedness may or may not be expressed in the same currency.
ARTICLE 12    
THE AGENT AND THE LENDERS
12.1
Authorization of Agent and Relationship
Each Lender hereby appoints BNS as Agent and BNS hereby accepts such appointment. The appointment may only be terminated as expressly provided in this Agreement. Each Lender hereby




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authorizes the Agent to take all action on its behalf and to exercise such powers and perform such duties under this Agreement as are expressly delegated to the Agent by its terms, together with all powers reasonably incidental thereto. Except as expressly specified in this Agreement, the Agent shall have only those duties and responsibilities of a solely mechanical and administrative nature that are expressly delegated to the Agent by this Agreement or are reasonably incidental thereto. The Agent may perform such duties by or through its agents or employees, but shall not by reason of this Agreement have a fiduciary duty in respect of any Lender. As to any matters not expressly provided for by this Agreement, the Agent is not required to exercise any discretion or to take any action, but is required to act or to refrain from acting (and is fully protected in so acting or refraining from acting) upon the instructions of the Lenders or the Majority Lenders, as the case may be. Those instructions shall be binding upon all Lenders, but the Agent is not required to take any action which exposes the Agent to personal liability or which is contrary to this Agreement or Applicable Laws.
12.2
Disclaimer of Agent
The Agent makes no representation or warranty, and assumes no responsibility with respect to the due execution, legality, validity, sufficiency, enforceability or collectability of this Agreement or any other Credit Document. The Agent assumes no responsibility for the financial condition of the Borrower, or for the performance of its obligations under this Agreement or any other Credit Document. The Agent assumes no responsibility with respect to the accuracy, authenticity, legality, validity, sufficiency or enforceability of any documents, papers, materials or other information furnished by the Borrower to the Agent on behalf of the Lenders. The Agent shall not be required to ascertain or inquire as to the performance or observance of any of the terms, conditions, provisions, covenants or agreements contained herein or as to the use of the proceeds of any credit hereunder or (unless the officers or employees of the Lender acting as Agent active in their capacity as officers or employees on the Borrower’s accounts have actual knowledge thereof, or have been notified thereof in writing by the Borrower or a Lender) of the existence or possible existence of any Default or Event of Default. Neither the Agent nor any of its directors, officers, agents or employees shall be liable for any action taken or omitted to be taken by it or them as Agent under or in connection with the Agreement, whether in the good faith exercise of any discretion expressly granted to the Agent or otherwise, except for actions or omissions arising from its or their own negligence or wilful misconduct. With respect to its Commitment, the Lender acting as Agent shall have the same rights and powers hereunder as any other Lender, and may exercise the same as though it were not performing the duties and functions delegated to it as Agent hereunder.
12.3
Failure of Lender to Fund
(a)
Unless the Agent has actual knowledge that a Lender has not made or will not make available to the Agent for value on a Borrowing Date the applicable amount required from such Lender pursuant to Article 2, the Agent shall be entitled to assume that such amount has been or will be received from such Lender when so due and the Agent may (but shall not be obliged to), in reliance upon such assumption, make available to the Borrower a corresponding amount. If such amount is not in fact received by the Agent from such Lender on such Borrowing Date and the Agent has made available a corresponding amount to the Borrower on such Borrowing Date as aforesaid, such Lender shall pay to the Agent on demand an amount equal to the product of (i) the rate per annum then in use at the Branch as a syndicate lender late




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payment rate, multiplied by (ii) the amount that should have been paid to the Agent by such Lender on such Borrowing Date and was not, multiplied by (iii) a fraction, the numerator of which is the number of days that have elapsed from and including such Borrowing Date to but excluding the date on which the amount is received by the Agent from such Lender and the denominator of which is three hundred and sixty-five (365). A certificate of the Agent containing details of the amount owing by a Lender under this Section shall be binding and conclusive in the absence of manifest error. If any such amount is not in fact received by the Agent from such Lender on such Borrowing Date, the Agent shall be entitled to recover from the Borrower, on demand, the related amount made available by the Agent to the Borrower as aforesaid together with interest thereon at the applicable rate per annum payable by the Borrower hereunder.
(b)
Notwithstanding the provisions of Subsection 12.3(a), if any Lender fails to make available to the Agent its Proportionate Share of any Advance (such Lender being herein called the “Defaulting Lender”), the Agent shall forthwith give notice of such failure by the Defaulting Lender to the other Lenders. The Agent shall then forthwith give notice to the other Lenders that any Lender may make available all or any portion of the Defaulting Lender’s share of such Advance in the place of the Defaulting Lender, but in no way shall any other Lender or the Agent be obliged to do so. If more than one Lender gives notice that it is prepared to make funds available in the place of a Defaulting Lender in such circumstances and the aggregate of the funds which such Lenders (herein collectively called the “Contributing Lenders” and individually called the “Contributing Lender”) are prepared to make available exceeds the amount of the Advance which the Defaulting Lender failed to make, then each Contributing Lender shall be deemed to have given notice that it is prepared to make available a portion of such Advance based on the Contributing Lenders’ relative Proportionate Shares. If any Contributing Lender makes funds available in the place of a Defaulting Lender in such circumstances, then the Defaulting Lender shall pay to any Contributing Lender making the funds available in its place, forthwith on demand any amount advanced on its behalf together with interest thereon at the rate applicable to such Advance from the date of advance to the date of payment, against payment by the Contributing Lender making the funds available of all interest received in respect of the Advance from the Borrower. The failure of any Lender to make available to the Agent its Proportionate Share of any Advance as required herein shall not relieve any other Lender of its obligations to make available to the Agent its Proportionate Share of any Advance as required herein.
12.4
Payments by the Borrower
Unless otherwise expressly provided in this Agreement as among the Lenders, all payments made by or on behalf of the Borrower pursuant to this Agreement shall be made to and received by the Agent and shall be distributed by the Agent to the Lenders as soon as possible upon receipt by the Agent. Subject to any other provision of this Agreement concerning the distribution of payments, the Agent shall cause distribution of:




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(a)
payments of interest in accordance with each Lender’s Advanced Share of the Advances to which the payment relates;
(b)
repayments of principal in accordance with each Lender’s Advanced Share of the Advances to which the payment relates;
(c)
payments of standby fees in accordance with Section 4.3; and
(d)
all other payments including, without limitation, amounts received upon realization, in accordance with each Lender’s Proportionate Share; provided, however, that with respect to proceeds of realization, no Lender shall receive an amount in excess of the amounts owing to it in respect of the Accommodations.
Subject to Section 12.5, if the Agent does not distribute a Lender’s share of a payment made by the Borrower to that Lender for value on the day that payment is made or deemed to have been made to the Agent, the Agent shall pay to the Lender on demand an amount equal to the product of (i) the rate per annum then in use at the Branch as a syndicate lender late payment rate, multiplied by (ii) the Lender’s share of the amount received by the Agent from the Borrower and not so distributed, multiplied by (iii) a fraction, the numerator of which is the number of days that have elapsed from and including the date of receipt of the payment by the Agent to but excluding the date on which the payment is made by the Agent to such Lender and the denominator of which is three hundred and sixty-five (365).
12.5
Payments by Agent
(a)
For greater certainty, the following provisions shall apply to any and all payments made by the Agent to the Lenders hereunder:
(i)
the Agent shall be under no obligation to make any payment (whether in respect of principal, interest, fees or otherwise) to any Lender until an amount in respect of such payment has been received by the Agent from the Borrower;
(ii)
if the Agent receives less than the full amount of any payment of principal, interest, fees or other amount owing by the Borrower under this Agreement, the Agent shall have no obligation to remit to each Lender any amount other than such Lender’s share of that amount which is actually received by the Agent;
(iii)
if a Lender’s share of an Advance has been advanced, or a Lender’s Commitment has been outstanding, for less than the full period to which any payment (other than a payment of principal) by the Borrower relates, such Lender’s entitlement to such payment shall be reduced in proportion to the length of time such Lender’s share of the Advance or such Lender’s Commitment, as the case may be, has actually been outstanding;
(iv)
the Agent acting reasonably and in good faith shall, after consultation with the Lenders in the case of any dispute, determine in all cases the amount of




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all payments to which each Lender is entitled and such determination shall, in the absence of manifest error, be binding and conclusive; and
(v)
upon request, the Agent shall deliver a statement detailing any of the payments to the Lenders referred to herein.
(b)
Unless the Agent has actual knowledge that the Borrower has not made or will not make a payment to the Agent for value on the date in respect of which the Borrower has notified the Agent that the payment will be made, the Agent shall be entitled to assume that such payment has been or will be received from the Borrower when due and the Agent may (but shall not be obliged to), in reliance upon such assumption, pay the Lenders corresponding amounts. If the payment by the Borrower is in fact not received by the Agent on the required date and the Agent has made available corresponding amounts to the Lenders, the Borrower shall, without limiting its other obligations under this Agreement, indemnify the Agent against any and all liabilities, obligations, losses, damages, penalties, costs, expenses or disbursements of any kind or nature whatsoever that may be imposed on or incurred by the Agent as a result. A certificate of the Agent with respect to any amount owing by the Borrower under this Section shall be prima facie evidence of the amount owing in the absence of manifest error. The Agent shall be entitled to recover from each Lender to which a payment is made in reliance on the expectation of payment from the Borrower in accordance with this Section, the full amount of such payment that is not recovered from the Borrower, together with interest at the rate per annum then in use at the Branch as a syndicate lender late payment rate, from the date on which payment is made by the Agent to the date on which repayment is made by the Lender receiving such payment.
12.6
Direct Payments
The Lenders agree among themselves that, except as otherwise provided for in this Agreement, all sums received by a Lender relating to this Agreement whether received by voluntary payment, by the exercise of the right of set-off or compensation or by counterclaim, cross-action or otherwise, shall be shared by each Lender so that the ultimate exposure of each Lender is in accordance with its Advanced Share of all Advances under this Credit Facility, and each Lender undertakes to do all such things as may be reasonably required to give full effect to this Section, including without limitation, the purchase from other Lenders of their proportionate interest in the Borrowings by the Lender who has received an amount in excess of its Proportionate Share of amounts advanced under this Credit Facility as shall be necessary to cause such purchasing Lender to share the excess amount rateably with the other Lenders to the extent of their Advanced Share of any Advances under this Credit Facility. If any Lender shall obtain any payment of moneys due under this Agreement as referred to above, it shall forthwith remit such payment to the Agent and, upon receipt, the Agent shall distribute such payment in accordance with the provisions of Section 12.5.
12.7
Administration of the Credit Facilities




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(a)
Unless otherwise specified herein, the Agent shall perform the following duties under this Agreement:
(i)
prior to any Borrowing, ensure that all conditions precedent have been fulfilled in accordance with the terms of this Agreement, subject to Subsection 12.8(b) and any other applicable terms of this Agreement;
(ii)
use reasonable efforts to collect promptly all sums due and payable by the Borrower pursuant to this Agreement;
(iii)
hold all legal documents relating to the Credit Facilities, maintain complete and accurate records showing all Advances made by the Lenders, all remittances and payments made by the Borrower to the Agent, all remittances and payments made by the Agent to the Lenders and all fees or any other sums received by the Agent and, except for accounts, records and documents relating to the fees payable under any separate fee agreement, allow each Lender and their respective advisers to examine such accounts, records and documents at their own expense, and provide any Lender, upon reasonable notice, with such copies thereof as such Lender may reasonably require from time to time at the Lender’s expense;
(iv)
except as otherwise specifically provided for in this Agreement, promptly advise each Lender upon receipt of each notice and deliver to each Lender, promptly upon receipt, all other written communications furnished by the Borrower to the Agent on behalf of the Lenders pursuant to this Agreement, including without limitation copies of financial reports and certificates which are to be furnished to the Agent;
(v)
forward to each of the Lenders, upon request, copies of this Agreement, and other Credit Documents (other than any separate fee agreement);
(vi)
promptly forward to each Lender, upon request, an up-to-date loan status report; and
(vii)
upon learning of same, promptly advise each Lender in writing of the occurrence of an Event of Default or Default or the occurrence of any event, condition or circumstance which would have a Material Adverse Effect on the ability of the Borrower to comply with this Agreement or of the occurrence of any material adverse change on the business, operations or assets of the Borrower, taken as a whole, provided that, except as aforesaid, the Agent shall be under no duty or obligation whatsoever to provide any notice to the Lenders and further provided that each Lender hereby agrees to notify the Agent of any Event of Default or Default of which it may reasonably become aware.




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(b)
The Agent may take the following actions only with the prior consent of the Majority Lenders, unless otherwise specified in this Agreement:
(i)
subject to Subsection 12.7(c), exercise any and all rights of approval conferred upon the Lenders by this Agreement;
(ii)
amend, modify or waive any of the terms of this Agreement (including waiver of an Event of Default or Default) if such amendment, modification or waiver would have a Material Adverse Effect on the rights of the Lenders thereunder and if such action is not otherwise provided for in Subsection 12.7(c);
(iii)
declare an Event of Default or take action to enforce performance of the obligations of the Borrower and pursue any available legal remedy necessary;
(iv)
decide to accelerate the amounts outstanding under the Credit Facilities; and
(v)
pay insurance premiums, taxes and any other sums as may be reasonably required to protect the interests of the Lenders.
(c)
The Agent may take the following actions only if the prior unanimous consent of the Lenders is obtained, unless otherwise specified herein:
(i)
amend, modify, discharge, terminate or waive any of the terms of this Agreement if such amendment, modification, discharge, termination or waiver would amend the Canadian Dollar Amount of any Accommodation outstanding, reduce the interest rate applicable to any Accommodation, reduce the fees or other amounts payable with respect to any Accommodation, extend any date fixed for payment of principal, interest or other amounts relating to the Credit Facilities or extend the Maturity Date of the Credit Facility; and
(ii)
amend the definition of “Majority Lenders” or this Subsection 12.7(c).
(d)
Notwithstanding Subsection 12.7(b) and any other provision of this Agreement except for Subsection 12.7(c), in the absence of instructions from the Lenders and where, in the sole opinion of the Agent, acting reasonably and in good faith, the exigencies of the situation warrant such action to protect the interests of the Lenders, the Agent may without notice to or consent of the Lenders take such action on behalf of the Lenders as the Agent deems appropriate or desirable.
(e)
As between the Borrower, the Agent and the Lenders:
(i)
all statements, certificates, consents and other documents which the Agent purports to deliver on behalf of the Lenders or the Majority Lenders shall be binding on each of the Lenders, and the Borrower shall not be required to ascertain or confirm the authority of the Agent in delivering such documents;
(ii)
all certificates, statements, notices and other documents which are delivered by the Borrower to the Agent in accordance with this Agreement shall be




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deemed to have been duly delivered to each of the Lenders, except where this Agreement expressly requires delivery of notices of Advances and payments to the Agent and/or individual Lenders;
(iii)
except in connection with Overdrafts and Letters of Credit, all payments which are delivered by the Borrower to the Agent in accordance with this Agreement shall be deemed to have been duly delivered to each of the Lenders.
12.8
Rights of Agent
(a)
In administering the Credit Facility, the Agent may retain, at the expense of the Lenders if such expenses are not recoverable from the Borrower, such solicitors, counsel, auditors and other experts and agents as the Agent may select, in its sole discretion, acting reasonably and in good faith after consultation with the Lenders.
(b)
The Agent shall be entitled to rely on any communication, instrument or document believed by it to be genuine and correct and to have been signed by the proper individual or individuals, and shall be entitled to rely and shall be protected in relying as to legal matters upon opinions of independent legal advisers selected by it. The Agent may also assume that any representation made by the Borrower is true and that no Event of Default or Default has occurred unless the officers or employees of the Agent have actual knowledge to the contrary or have received notice to the contrary from any other party to this Agreement. In determining whether the Borrower is entitled to an Advance by way of Overdraft or Letter of Credit, the Overdraft Lender or Letter of Credit Lender, as applicable, providing that Advance, shall be entitled to the same protection to which the Agent is entitled under this Subsection 12.8(b).
(c)
The Agent may, without any liability to account, accept deposits from and lend money to and generally engage in any kind of banking or other business with the Borrower, as if it were not the Agent.
(d)
Except in its own right as a Lender, the Agent shall not be required to advance its own funds for any purpose, and in particular, shall not be required to pay with its own funds insurance premiums, taxes or public utility charges or the cost of repairs or maintenance with respect to the assets which are the subject matter of any security, nor shall it be required to pay with its own funds the fees of solicitors, counsel, auditors, experts or agents engaged by it as permitted hereby.
(e)
The Agent shall be entitled to receive a fee for acting as Agent, as agreed between the Agent and the Borrower.
12.9
Acknowledgements, Representations and Covenants of Lenders
(a)
It is acknowledged and agreed by each Lender that it has itself been, and will continue to be, solely responsible for making its own independent appraisal of and investigations into the financial condition, creditworthiness, property, affairs, status




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and nature of the Borrower. Accordingly, each Lender confirms to the Agent that it has not relied, and will not hereafter rely, on the Agent (i) to check or inquire on its behalf into the adequacy or completeness of any information provided by the Borrower under or in connection with this Agreement or the transactions herein contemplated (whether or not such information has been or is hereafter distributed to such Lender by the Agent) or (ii) to assess or keep under review on its behalf the financial condition, creditworthiness, property, affairs, status or nature of the Borrower.
(b)
Each Lender represents and warrants to the Agent and the Borrower that it has the legal capacity to enter into this Agreement pursuant to its constating documents and any applicable legislation and has not violated its constating documents or any applicable legislation by so doing.
(c)
Each Lender agrees to indemnify the Agent (to the extent not reimbursed by the Borrower), rateably according to its Proportionate Share, from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever which may be imposed on, incurred by, or asserted against the Agent in any way relating to or arising out of the Credit Documents or the transactions therein contemplated, provided that no Lender shall be liable for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from the Agent’s negligence or wilful misconduct. Without limiting the generality of the foregoing, each Lender agrees to reimburse the Agent promptly upon demand for its Proportionate Share of any out-of-pocket expenses (including counsel fees) incurred by the Agent in connection with the preservation of any rights of the Agent or the Lenders under, or the enforcement of, or legal advice in respect of rights or responsibilities under this Agreement, to the extent that the Agent is not reimbursed for such expenses by the Borrower. The obligation of the Lenders to indemnify the Agent shall survive the termination of this Agreement.
(d)
Each of the Lenders acknowledges and confirms that in the event the Agent does not receive payment in accordance with this Agreement, it shall not be the obligation of the Agent to maintain the Credit Facilities in good standing nor shall any Lender have recourse to the Agent in respect of any amounts owing to such Lender under this Agreement.
(e)
Each Lender acknowledges and agrees that its obligation to advance its Proportionate Share of Advances in accordance with the terms of this Agreement is independent and in no way related to the obligation of any other Lender hereunder.
(f)
Each Lender hereby acknowledges receipt of a copy of this Agreement and acknowledges that it is satisfied with the form and content of such documents.
(g)
Except to the extent recovered by the Agent from the Borrower, promptly following demand therefor, each Lender shall pay to the Agent an amount equal to such Lender’s Proportionate Share of any and all reasonable costs, expenses, claims, losses and




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liabilities incurred by the Agent in connection with this Agreement, except for those incurred by reason of the Agent’s negligence or wilful misconduct.
12.10
Collective Action of the Lenders
Each of the Lenders hereby acknowledges that to the extent permitted by Applicable Laws, the remedies provided under the Credit Documents to the Lenders are for the benefit of the Lenders collectively and acting together and not severally and further acknowledges that its rights hereunder and under any security are to be exercised not severally, but by the Agent upon the decision of the Majority Lenders or Lenders as required by this Agreement. Accordingly, notwithstanding any of the provisions contained herein, each of the Lenders hereby covenants and agrees that it shall not be entitled to take any action hereunder or thereunder including, without limitation, any declaration of default hereunder or thereunder but that any such action shall be taken only by the Agent with the prior written agreement of the Majority Lenders. Each of the Lenders hereby further covenants and agrees that upon any such written agreement being given by the Majority Lenders, it shall co-operate fully with the Agent to the extent requested by the Agent.
12.11
Successor Agent
Subject to the appointment and acceptance of a Successor Agent as provided in this Section, the Agent may resign at any time by giving thirty (30) days’ written notice thereof to the Lenders and the Borrower and may be removed at any time by all Lenders other than the Lender that is acting as Agent, upon thirty (30) days’ written notice of termination. Upon receipt of notice by the Lenders of the resignation of the Agent, or upon giving notice of termination to the Agent, the Majority Lenders (taking into account the Proportionate Share of the resigning or terminated Agent) may, within twenty-one (21) days and with the approval of the Borrower, such approval not to be unreasonably withheld or delayed, appoint a successor from among the Lenders or, if no Lender is willing to accept such an appointment, from among other financial institutions which each have combined capital and reserves in excess of Two Hundred and Fifty Million Canadian Dollars (Cdn.$250,000,000), and which have offices in Calgary (the “Successor Agent”). If no Successor Agent has been so appointed and has accepted such appointment within twenty-one (21) days after the retiring Agent’s giving of notice of resignation or receiving of notice of termination, then the retiring Agent may, on behalf of the Lenders, appoint a Successor Agent in accordance herewith. Upon the acceptance of any appointment as Agent hereunder by a Successor Agent, the retiring Agent shall pay the Successor Agent any unearned portion of any fee paid to the Agent for acting as such, and the Successor Agent shall succeed to and become vested with all the rights, powers, privileges and duties of the retiring Agent, and the retiring Agent shall be discharged from its further duties and obligations as Agent under this Agreement and the other Credit Documents. After any retiring Agent’s resignation hereunder as Agent, the provisions of this Article shall continue to enure to its benefit and be binding upon it as to any actions taken or omitted to be taken by it while it was Agent hereunder.
12.12
Provisions Operative Between Lenders and Agent Only
Except for the provisions of Subsections 12.7(e), 12.9(b), Sections 12.10, 12.11, 12.13, 12.14 and 12.15, the provisions of this Article relating to the rights and obligations of the Lenders and the Agent shall be operative as between the Lenders and the Agent only, and the Borrower shall not have any rights or obligations under or be entitled to rely for any purpose upon such provisions.




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12.13
Assignments and Participation - Approvals
A Lender may:
(a)
upon notice to the Borrower grant participation (a “Participation”) in all or any part of the rights, benefits and obligations of the Lenders hereunder to one or more Persons (each a “Participant”); or
(b)
assign (an “Assignment”) all or part of the rights, benefits and obligations of such Lender hereunder to one or more Persons (each an “Assignee”);
with the prior consent of the Borrower, the Agent and the Letter of Credit Lender, which consent may be withheld by any such party in its sole discretion. Any such Participant or Assignee may grant further Participation to other Participants or make further assignments to other Assignees; with the prior consent of the Borrower, the Agent and the Letter of Credit Lender, which consent may be withheld by any such party in its sole discretion. Notwithstanding the foregoing, no grant to a Participant or Assignment to an Assignee shall require the consent of the Borrower at a time when any Event of Default has occurred and is continuing.
12.14
Assignments
(a)
Subject to Section 12.13, the Lenders collectively or individually may assign to one or more Assignees all or a portion of their respective rights and obligations under this Agreement (an undivided portion thereof corresponding to the portion of the Commitment being assigned) by way of Assignment. The parties to each such Assignment shall execute and deliver an Assignment Agreement in the form set out in Schedule 4 to the Borrower, and to the Agent for its consent and recording in the Register and, except in the case of an Assignment by the Lenders collectively or an Assignment by a Lender to an affiliate of that Lender, shall pay a processing and recording fee of Three Thousand, Five Hundred Canadian Dollars (Cdn.$3,500) to the Agent. After such execution, delivery, consent and recording the Assignee thereunder shall be a party to this Agreement and, to the extent that rights and obligations hereunder have been assigned to it, have the rights and obligations of a Lender hereunder and the assigning Lender thereunder shall, to the extent that rights and obligations hereunder have been assigned by it pursuant to such Assignment Agreement, relinquish its rights and be released from its obligations under this Agreement, other than obligations in respect of which it is then in default and liabilities arising from its actions prior to the Assignment, and, in the case of an Assignment Agreement covering all or the remaining portion of an assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto.
(b)
The agreements of an Assignee contained in an Assignment Agreement shall benefit the assigning Lender thereunder, the other Lenders, the Agent and the Borrower in accordance with the terms of the Assignment Agreement.
(c)
The Agent shall maintain at its address referred to herein a copy of each Assignment Agreement delivered and consented to by the Lender and, where required, by the




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Borrower and a register for recording the names and addresses of the Lenders and the Commitment of each Lender from time to time (the “Register”). The entries in the Register shall be conclusive and binding for all purposes, absent manifest error. The Borrower, the Agent and each of the Lenders may treat each Person whose name is recorded in the Register as a Lender hereunder for all purposes of this Agreement, and need not recognize any Person as a Lender unless it is recorded in the Register as a Lender. The Register shall be available for inspection by any Lender or the Borrower at any reasonable time and from time to time upon reasonable prior notice.
(d)
Upon its receipt of an Assignment Agreement executed by an assigning Lender and an Assignee and approved by the Agent, and, where required, by the Borrower, the Agent shall, if the Assignment Agreement has been completed and is in the required form with such immaterial changes as are acceptable to the Agent:
(i)
record the information contained therein in the Register; and
(ii)
give prompt notice thereof to the other Lenders and the Borrower, and provide them with an updated version of Schedule 5.
12.15
Participation
Each Lender may (subject to the provisions of Section 12.13) grant Participation to one or more financial institutions in or to all or a portion of its rights and obligations under this Agreement (including, without limitation, all or a portion of its Commitment), but the Participant shall not become a Lender and:
(a)
the Lender’s obligations under this Agreement (including, without limitation, its Commitment) shall remain unchanged;
(b)
the Lender shall remain solely responsible to the other parties hereto for the performance of such obligations;
(c)
the Borrower, the Agent and the other Lenders shall continue to deal solely and directly with the Lender in connection with the Lender’s rights and obligations under this Agreement; and
(d)
no Participant shall have any right to participate in any decision of the Lender or the Majority Lenders hereunder or to approve any amendment or waiver of any provision of this Agreement, or any consent to any departure by any Person therefrom.
ARTICLE 13    
MISCELLANEOUS
13.1
Expenses
The Borrower shall, whether or not any or all of the transactions hereby contemplated shall be consummated, pay all reasonable costs and expenses of the Agent and the Lenders in connection with the preparation, execution, delivery, registration granting or obtaining of consents or approvals or the exercise of any discretion under this Agreement, the Credit Documents and all related




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documentation and the amendment and enforcement of, and the preservation of any of the Agent’s and Lender’s rights under, this Agreement, the Credit Documents and all related documentation, provided that any legal counsel retained will represent both the Agent and the Lenders and no costs or expenses for legal counsel incurred by any Lender individually shall be payable pursuant to this Section 13.1.
13.2
Further Assurances
The Borrower shall, from time to time forthwith upon reasonable request by the Agent do, make and execute all such documents, acts, matters and things as may be required by the Agent to give effect to this Agreement and any of the Credit Documents.
13.3
Notices
Any notice or communication to be given hereunder may be effectively given by delivering the same to the addresses hereafter set forth or by sending the same by facsimile to the numbers hereafter set forth. Any notice so delivered shall be deemed to have been received on the date delivered and any facsimile notice shall be deemed to have been received on transmission, if in either case the date thereof is a Business Day and if it is prior to 4:00 p.m. (Toronto, Ontario time) and, if not, on the next Business Day following delivery or transmission. The addresses for delivery and numbers for facsimiles of the parties for the purposes hereof shall be as set forth on the execution pages of this Agreement. Any party may from time to time notify the other party, in accordance with the provisions hereof, of any change of its address or facsimile number which thereafter, until changed by like notice, shall be the address or facsimile number of such party for all purposes of this Agreement.
(a)
If to the Agent:
The Bank of Nova Scotia
Global Banking and Markets
40 King Street West, 62nd Floor
Toronto, Ontario M5W 2X6

Attention:    Director
Facsimile:    416-866-3329
(b)
If to the Borrower and/or the General Partner:
AltaLink Management Ltd.
2611-3rd Avenue S.E.
Calgary, Alberta T2A 7W7

Attention:    Christopher Lomore, Vice President, Treasurer
Facsimile:    (403) 267-3407




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with a copy to:
Borden Ladner Gervais LLP
Centennial Place, East Tower
1900, 520-3rd Avenue S.W.
Calgary, Alberta T2P 0R3

Attention:    Edward Wooldridge
Facsimile:     (403) 266-1395
13.4
Survival
All agreements, representations and warranties made herein shall survive the execution and delivery of this Agreement and the Credit Documents and the obtaining of Accommodations.
13.5
Benefit of Agreement
This Agreement shall be binding upon and enure to the benefit of the parties hereto and their respective successors and permitted assigns; provided, however, that the Borrower may not assign or transfer any of its rights or obligations hereunder other than as provided under Article 12.
13.6
Severability
Any provision of this Agreement which is prohibited or unenforceable in any jurisdiction shall not invalidate the remaining provisions hereof and any such prohibitions or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.
13.7
Entire Agreement
This Agreement, the Credit Documents and all documentation contemplated herein constitute the entire agreement among the parties relating to the subject matter hereof except for any fee agreements between the Borrower and the Agent.
13.8
Credit Documents
Notwithstanding any contrary provision contained in the Credit Documents, in the event of any conflict or inconsistency between any of the provisions in this Agreement and any of the provisions in the Credit Documents, as against the parties hereto and their respective successors and permitted assigns the provisions in this Agreement shall prevail.
13.9
Counterparts
This Agreement may be executed in any number of counterparts, each of which shall be considered to be an original, and which together shall constitute one and the same document.
13.10
Amendments/Approvals and Consents/Waivers
No amendment or waiver of any provision of this Agreement or of any Credit Document contemplated herein, nor consent to any departure by the Borrower therefrom, nor any approval,




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consent, opinion, confirmation of satisfaction, direction, specification or agreement to be given by the Lenders or the Agent on behalf of the Lenders hereunder shall be effective unless the same shall be in writing and signed by the Agent and then such amendment, waiver, consent, approval, opinion, confirmation of satisfaction, direction, specification or agreement shall be effective only in the specific instance and for the specific purpose for which it is given.
13.11
Acknowledgement
The Borrower is a limited partnership formed under the Partnership Act (Alberta), a limited partner of which is only liable for any of its liabilities or any of its losses to the extent of the amount that such limited partner has contributed or agreed to contribute to its capital and such limited partner’s pro rata share of any undistributed income.
[Signature page to follow.]

IN WITNESS OF WHICH the parties hereto have duly executed this Agreement as of the date set forth on the first page of this Agreement.
 
 
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.
By:
/s/ David Koch
 
Name: David Koch
 
Title: Executive Vice President
and Chief Financial Officer
By:
/s/ Christopher J. Lomore
 
Name: Christopher J. Lomore
 
Title: Vice President, Treasurer

 
 
ALTALINK MANAGEMENT LTD.
By:
/s/ David Koch
 
Name: David Koch
 
Title: Executive Vice President
and Chief Financial Officer
By:
/s/ Christopher J. Lomore
 
Name: Christopher J. Lomore
 
Title: Vice President, Treasurer





- 1 -

 
 
THE BANK OF NOVA SCOTIA, as Agent
By:
/s/ Clement Yu
 
Name: Clement Yu
 
Title: Director
 
By:
/s/ Venita Ramjattan
 
 
Name: Venita Ramjattan
 
 
Title: Analyst

 
 
THE BANK OF NOVA SCOTIA, as Lender
By:
/s/ Kirt Millwood
 
Name: Kirt Millwood
 
Title: Managing Director
 
By:
/s/ Matthew Hartnoll
 
 
Name: Matthew Hartnoll
 
 
Title: Director









SCHEDULE 1
BORROWER’S CERTIFICATE OF COMPLIANCE
TO:
The Bank of Nova Scotia (“BNS”), as Agent for the Lenders, under the Credit Agreement
This Certificate is delivered to you pursuant to the Fourth Amended and Restated Credit Agreement made as of January 24, 2020, as amended, restated or replaced from time to time (the “Credit Agreement”) between AltaLink, L.P., AltaLink Management Ltd. and BNS, as Agent and Lender and the other Lenders party thereto. Capitalized terms used in this Certificate and not otherwise defined have the meanings given in the Credit Agreement.
The undersigned has read the provisions of the Credit Agreement which are relevant to the furnishing of this Certificate. The undersigned has made such examination and investigation as was, in the opinion of the undersigned, necessary to enable the undersigned to express an informed opinion on the matters set out herein.
The undersigned hereby certifies that as of the date hereof:
1.
Representations and Warranties. All representations and warranties of the Borrower and the General Partner contained in the Credit Agreement are true and correct in all material respects as if made on and as of the date hereof, except as set out in Appendix I hereto or otherwise notified to the Agent under the Credit Agreement.
2.
Default/Event of Default. No Default or Event of Default under the Credit Agreement has occurred and is continuing.
3.
Limitation on Indebtedness. The aggregate amount of all Indebtedness of the Borrower (other than Financial Instrument Obligations in accordance with Section 6.3 of the Trust Indenture) does not exceed seventy-five percent (75%) of the Total Capitalization of the Borrower.
4.
Permitted Joint Arrangements. (i) The total equity investment of the Borrower in Permitted JA Subsidiaries and Permitted Joint Arrangements does not exceed an aggregate amount equal to Cdn.$200,000,000; and (ii) the Borrower has not formed any Subsidiaries other than Permitted JA Subsidiaries and has not entered into any joint ventures or joint arrangements other than Permitted Joint Arrangements. The following represents investments by the Borrower in Permitted JA Subsidiaries and Permitted Joint Arrangements as of the date hereof which aggregate amount does not exceed Cdn.$200,000,000: [Borrower to provide details.]



- 2 -


DATED this      day of             , 20__ .
 
 
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.
By:
 
 
Name: David Koch
 
Title: Executive Vice President
and Chief Financial Officer
By:
 
 
Name: Christopher J. Lomore
 
Title: Vice President, Treasurer

 
 
ALTALINK MANAGEMENT LTD.
By:
 
 
Name: David Koch
 
Title: Executive Vice President
and Chief Financial Officer
By:
 
 
Name: Christopher J. Lomore
 
Title: Vice President, Treasurer


APPENDIX I

EXCEPTIONS AND QUALIFICATIONS TO
BORROWER’S CERTIFICATE OF COMPLIANCE



Revolving Facility – Certificate of Compliance – Signature Page







- 2 -

SCHEDULE 2(A)
BORROWING NOTICE
The Bank of Nova Scotia
Calgary Business Support Centre
2850 Sunridge Boulevard NE
Calgary, AB T1Y 6G2
Attention:    Document Services Officer
Facsimile:    1-877-909-7038
The Lenders under the Credit Agreement
Dear Sirs/Mesdames:
You are hereby notified that the undersigned, intends to avail itself of the Credit Facilities established in its favour pursuant to the Fourth Amended and Restated Credit Agreement made as of January 24, 2020, as amended, restated or replaced from time to time (the “Credit Agreement”) between AltaLink, L.P., as Borrower, AltaLink Management Ltd. and The Bank of Nova Scotia, as Agent and Lender, and the other Lenders which become a party thereto. Capitalized terms used in this Borrowing Notice and not otherwise defined have the meanings given in the Credit Agreement.
The undersigned hereby irrevocably requests a Borrowing pursuant to [describe applicable credit facility] as follows:
(a)
Prime Rate Loan in the amount of Cdn.$l, having a term of l [add same provision for any other amount and term requested];
(b)
U.S. Base Rate Loan in the amount of U.S.$l, having a term of l [add same provision for any other amount and term requested];
(c)
LIBOR Loan in the amount of U.S.$l, having a term and LIBOR Interest Period of l days [add same provision for any other amount and term requested];
(d)
Bankers’ Acceptance in the aggregate amount of Cdn.$l having a term of l days [add same provision for any other amount and term requested]; and
(e)
Letter of Credit in the amount of Cdn.$l for the purpose of l.
All Loans made pursuant to this Borrowing Notice shall be credited to the undersigned’s account no. l at the Branch. In the case of a Bankers’ Acceptance or Letter of Credit, it shall be delivered to l. The requested Borrowing Date is l. [If the undersigned requires a bank draft to be issued by BNS as a debit to the undersigned account at the Branch and to be delivered on the undersigned’s behalf, add an irrevocable direction to that effect, specifying the Person to whom it is to be delivered.]
All representations and warranties of the Borrower contained in the Credit Agreement are true and correct in all material respects as if made on and as of the date hereof.



- 3 -

No Default or Event of Default under the Credit Agreement has occurred and is continuing.
DATED this      day of             , 20__ .
 
 
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.
By:
 
 
Name:
 
Title:
By:
 
 
Name:
 
Title:






- 4 -

SCHEDULE 2(B)
NOTICE OF ROLL OVER
The Bank of Nova Scotia
Calgary Business Support Centre
2850 Sunridge Boulevard NE
Calgary, AB T1Y 6G2
Attention:    Document Services Officer
Facsimile:    1-877-909-7038
The Lenders under the Credit Agreement
Dear Sirs/Mesdames:
We refer to Section 2.4 of the Fourth Amended and Restated Credit Agreement made as of January 24, 2020, as amended, restated or replaced from time to time (the “Credit Agreement”) between AltaLink, L.P., as Borrower, AltaLink Management Ltd. and The Bank of Nova Scotia, as Agent and Lender, and the other Lenders which become a party thereto. Capitalized terms used in this Notice and not otherwise defined have the meanings given in the Credit Agreement.
The Borrower hereby confirms that:
(a)
it intends to repay the following Bankers’ Acceptances on the current maturity date:
(i)
aggregate face amount - $_______________;
(ii)
current maturity date ______________, 201__;
(a)
the following Bankers’ Acceptances are to be rolled over in accordance with the Credit Agreement by the issuance of new Bankers’ Acceptances on the current maturity date specified below:
(i)
aggregate face amount of maturing Bankers’ Acceptances - $__________;
(ii)
current maturity date - _____________, 201__;
(iii)
new aggregate face amount - $_____________;
(iv)
new contract period - _______________; and
(v)
new maturity date - _______________, 201__.



- 5 -

The Borrower hereby represents and warrants that the conditions contained in the Credit Agreement have been satisfied and will be satisfied as of the date hereof and before and after giving effect to such roll over on the applicable roll over date.
DATED this      day of             , 20__ .
 
 
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.
By:
 
 
Name:
 
Title:
By:
 
 
Name:
 
Title:






- 6 -

SCHEDULE 2(C)
CONVERSION OPTION NOTICE
The Bank of Nova Scotia
Calgary Business Support Centre
2850 Sunridge Boulevard NE
Calgary, AB T1Y 6G2
Attention:    Document Services Officer
Facsimile:    1-877-909-7038
The Lenders under the Credit Agreement
Dear Sirs/Mesdames:
We refer to Section 2.4 of the Fourth Amended and Restated Credit Agreement made as of January 24, 2020, as amended, restated or replaced from time to time (the “Credit Agreement”) between AltaLink, L.P., as Borrower, AltaLink Management Ltd. and The Bank of Nova Scotia, as Agent and Lender, and the other Lenders which become a party thereto. Capitalized terms used in this Notice and not otherwise defined have the meanings given in the Credit Agreement.
Pursuant to the Credit Agreement, we hereby give notice of our irrevocable request for a conversion of Advances in the amount of $______________ outstanding by way of [insert type of loan] into corresponding Borrowings by way of [insert new type of loan] on the _________ day of ___________, 20___. [The contract period for the new Bankers’ Acceptances shall be __________________ with a new maturity date of ____________, 20___.] [The term of the new [insert type of loan] shall be _______________ with a new maturity date of _________, 20____.]
The Borrower hereby represents and warrants that the conditions contained in the Credit Agreement have been satisfied and will be satisfied as of the date hereof and before and after giving effect to such conversion on the applicable conversion date.
DATED this      day of             , 20__ .
 
 
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.
By:
 
 
Name:
 
Title:
By:
 
 
Name:
 
Title:





- 1 -





- 2 -

SCHEDULE 3
NOTICE OF EXTENSION
The Bank of Nova Scotia
Scotia Capital Corporate Banking - Power 62nd Floor
40 King Street West
Scotia Plaza
Toronto, ON M5W 2X6
Attention:    Managing Director
Facsimile:    (416) 866-3329
Dear Sirs/Mesdames:
You are hereby notified that the undersigned wishes to extend the Maturity Date for the Credit Facility for a three hundred and sixty-five (365) day period from the date stipulated in your acceptance of this request. Capitalized terms used in this Notice of Extension and not otherwise defined have the meanings given in the Fourth Amended and Restated Credit Agreement made as of January 24, 2020 between AltaLink L.P., as Borrower, AltaLink Management Ltd. and The Bank of Nova Scotia, as Agent and Lender, and the other Lenders party thereto, as amended, restated or replaced from time to time.
DATED this      day of             , 20__ .
 
 
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.
By:
 
 
Name:
 
Title:
By:
 
 
Name:
 
Title:






- 3 -

SCHEDULE 4
ASSIGNMENT AGREEMENT
TO:        THE BANK OF NOVA SCOTIA (the “Agent”)
AND TO:    ALTALINK, L.P. (the “Borrower”)
The Borrower has entered into the Fourth Amended and Restated Credit Agreement made as of January 24, 2020, as amended, restated or replaced from time to time, (the “Credit Agreement”) between the Borrower, AltaLink Management Ltd. and the Agent and the Lenders. l (the “Assignee”) wishes to acquire some of the rights of l (the “Assignor”) under the Credit Agreement and accordingly the Assignor and the Assignee furnish this Assignment Agreement to the Borrower subject to the terms of the Credit Agreement. Capitalized terms in this Assignment Agreement shall have the meanings set out in the Credit Agreement.
1.
The Assignee acknowledges that it has received and reviewed a copy of the Credit Agreement and further acknowledges the provisions of the Credit Agreement.
2.
The Assignor hereby sells, assigns and transfers to the Assignee an undivided l% interest in the Credit Facility and the Credit Agreement so that the Assignor’s commitment will now be $l and the Assignee’s commitment will be $l.
3.
The Assignee, by its execution and delivery of this Assignment Agreement, agrees from and after the date hereof to be bound by and to perform all of the terms, conditions and covenants of the Credit Agreement applicable to the Assignor, all as if such Assignee had been an original party thereto. The Assignee will not set off any amounts owing by the Borrower to such Assignee (other than pursuant to this Assignment Agreement) against any amounts the Assignee is obliged to advance under the Credit Agreement.
4.
Notices under the Credit Agreement shall be given to the Assignee at the following address and facsimile number:
[Insert Address]

Attention:    l
Facsimile:    l
5.
The provisions hereof shall be binding upon the Assignee and the Assignor and their respective successors and permitted assigns and shall enure to the benefit of the Borrower and its successors and assigns.



- 4 -

6.
This Assignment Agreement shall be governed by and construed and interpreted in accordance with the laws of the Province of Alberta and the laws of Canada applicable therein.
IN WITNESS WHEREOF the undersigned have caused this Assignment Agreement to be duly executed this __ day of _______________, 20____.
 
 
[NAME OF ASSIGNOR], as Assignor
By:
 
 
Name:
 
Title:
By:
 
 
Name:
 
Title:

 
 
[NAME OF ASSIGNEE], as Assignee
By:
 
 
Name:
 
Title:
By:
 
 
Name:
 
Title:







ACKNOWLEDGEMENT
ACKNOWLEDGED AND AGREED to this __ day of _______________, 20____.
 
 
ALTALINK MANAGEMENT LTD., as general partner of ALTALINK, L.P.
By:
 
 
Name:
 
Title:
By:
 
 
Name:
 
Title:







SCHEDULE 5
LENDERS
The Bank of Nova Scotia








EXHIBIT 10.8

SUMMARY OF KEY TERMS OF COMPENSATION ARRANGEMENTS
WITH PACIFICORP NAMED EXECUTIVE OFFICERS AND DIRECTORS

PacifiCorp's named executive officers (other than its Chairman of the Board of Directors and Chief Executive Officer, William J. Fehrman) each receive an annual salary and participate in health insurance and other benefit plans on the same basis as other employees, as well as certain other compensation and benefit plans described in PacifiCorp's Annual Report on Form 10-K. Mr. Fehrman is employed by PacifiCorp's parent company, Berkshire Hathaway Energy Company ("BHE") and is not directly compensated by PacifiCorp. PacifiCorp reimburses BHE for the cost of Mr. Fehrman's time spent on PacifiCorp matters, including compensation paid to him by BHE, pursuant to an intercompany administrative services agreement among BHE and its subsidiaries.

The named executive officers are also eligible to receive a cash incentive award under PacifiCorp's Annual Incentive Plan ("AIP"). The AIP provides for a discretionary annual cash award that is determined on a subjective basis and paid in December. In addition to the AIP, the named executive officers are eligible to receive discretionary cash performance awards periodically during the year to reward the accomplishment of significant non-recurring tasks or projects. The named executive officers are participants in PacifiCorp's Long-Term Incentive Partnership Plan ("LTIP"). A copy of the LTIP is included in Exhibit 10.15 to this Form 10-K.

Base salary for named executive officers for PacifiCorp's fiscal year ending December 31, 2020 (excluding Mr. Fehrman) is shown in the following table:

Name and Title
 
Base Salary
 
 
 
Stefan A. Bird
 
$
365,000

President and Chief Executive Officer, Pacific Power
 
 
 
 
 
Gary W. Hoogeveen
 
350,000

President and Chief Executive Officer, Rocky Mountain Power
 
 
 
 
 
Nikki L. Kobliha
 
239,571

Vice President, Chief Financial Officer and Treasurer
 
 

Mr. Bird, Mr. Hoogeveen and Ms. Kobliha are also directors of PacifiCorp, but do not receive additional compensation for their service as directors other than what they receive as employees of PacifiCorp. Mr. Fehrman and Mr. Patrick J. Goodman and Ms. Natalie L. Hocken are directors of PacifiCorp as well as employees of BHE, but do not receive additional compensation for their service as directors of PacifiCorp other than what they receive as employees of BHE.








EXHIBIT 10.15








PacifiCorp

LONG-TERM INCENTIVE PARTNERSHIP PLAN

Effective January 1, 2014 and Restated Effective December 1, 2019

PLAN DOCUMENT






PACIFICORP

LONG-TERM INCENTIVE PARTNERSHIP PLAN


ARTICLE I – PURPOSE AND EFFECTIVE DATE
1.1
Purpose. The purpose of this Long-Term Incentive Partnership Plan (the “Plan”) is to permit a select group of management employees of PacifiCorp and its subsidiaries to share in significant increases in the value of the Company realized through the efforts of these individuals. It is intended that the Plan, by providing this award and deferral opportunity, will assist the Company in retaining and attracting individuals of exceptional ability and will act as an incentive to align their interests with those of the Company. For purposes of Internal Revenue Code Section 409A, Incentive Accounts are considered to be part of a non-elective account balance plan type and Deferral Accounts are considered to be part of an elective account balance plan type.
1.2
Effective Date. The Plan is effective as of January 1, 2014 and restated effective December 1, 2019.
ARTICLE II – DEFINITIONS
For the purpose of the Plan, the following terms shall have the meanings indicated, unless the context clearly indicates otherwise:
2.1Base Salary. “Base Salary” means the annual base salary rate payable to a Participant effective January 1 (or the date of hire, if later) of the calendar year for a particular Award Year. For purposes of the Plan, Base Salary shall be calculated before reduction for any amounts deferred by the Participant pursuant to the Company’s tax qualified plans which may be maintained under Section 401(k) or Section 125 of the Internal Revenue Code of 1986, as amended (the “Code”), or pursuant to the PacifiCorp Voluntary Deferred Compensation Plan or any other non-qualified plan which permits the voluntary deferral of compensation. Inclusion of any forms of compensation other than such “wages” and deferred “wages” is subject to approval of the BHE President and the Presidents.
2.2Beneficiary. “Beneficiary” means the person, persons or entity, as designated by the Participant, entitled under Article VIII to receive any Plan benefits payable after the Participant’s death.
2.3BHE President. “BHE President” means the President and CEO of Berkshire Hathaway Energy Company.
2.4Board. “Board” means the Board of Directors of PacifiCorp or any duly authorized committee.
2.5Company. “Company” means PacifiCorp, a Portland, Oregon based entity, and any directly or indirectly affiliated subsidiary entities, and any predecessor or successor to the business of any thereof. With respect to the obligation to make payments to any Participant under the Plan, Company shall mean PacifiCorp and any affiliated subsidiary entity that employs the Participant, but not any other Company. For purposes of determining whether there has been a Separation from Service with the Company, Company means all entities with





whom the Company would be considered a single employer under Code Sections 414 (b) and (c).
2.6Determination Date. “Determination Date” means every day of the year.
2.7Disability. “Disability” means a condition of a Participant who by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months: (i) is unable to engage in any substantial gainful activity; or (ii) is receiving income replacement benefits for a period of not less than 3 months under a long term disability plan covering employees of the Company.
2.8Incentive Account(s). “Incentive Account(s)” means the account or accounts maintained on the books of the Company with respect to each Incentive Award and used solely to calculate the amount which may be payable to each Participant under the Plan and shall not constitute a separate fund of assets. Participants may have more than one Incentive Account maintained on their behalf.
2.9Incentive Award(s). “Incentive Award(s)” means the award determined and allocated under the terms of the Plan. Each Incentive Award(s) shall be designated by the year to which the award relates (the “Award Year”) even though the value of the award may be determined and credited to a Participant’s Incentive Account in a subsequent year. An example: The Year 2014 Incentive Award may relate to the performance of the Company over the calendar year 2014 (the Award Year), even though the Incentive Award will only be determinable in 2015.
2.10Interest. “Interest” means the amount credited to each Participant’s Incentive Account(s) on each Determination Date. The Company shall select investment funds or benchmarks (which shall be published indices, mutual funds or exchange traded funds which have ticker symbols, trade on an established exchange and can be valued on a daily basis) from which a Participant may direct the investment of his or her Incentive Account(s). Each Incentive Account may be invested independently from the Participant’s other Incentive Accounts. Investment elections by a Participant may be made only once per calendar year during a time period announced by the Company. Such time period will be communicated to Participants early in each calendar year. No investment election changes will be permitted until the investment election time period in the following calendar year. If a Participant fails to make an investment election during the applicable time period, the investment for the Incentive Account announced for the immediate prior calendar year will default to the most conservative investment fund as selected by the Company, and the investment of all other Incentive Accounts of the Participant, if any, shall be based on the Participant’s most recent investment election for those Incentive Accounts (and the default shall apply to all Incentive Awards if a Participant fails to make an investment election when the individual directed investment program is first implemented). Such credits to a Participant’s Incentive Account(s) may be either positive or negative to reflect the increase or decrease in value of the Incentive Account(s) in accordance with the provisions of this Plan. The Incentive Awards and any Interest credited to the Incentive Account(s) of a Participant are bookkeeping entries only and the Participant shall not have any right to distribution of or ownership interest in any investment vehicle chosen for the crediting of Interest to the Incentive Account(s).





2.11Net Income. “Net Income” means the definition as applied under Generally Accepted Accounting Principles. The BHE President and the Presidents may adjust Net Income for extraordinary and non-recurring events, when appropriate.
2.12Participant. “Participant” means any employee who is eligible, pursuant to Article III, below, to participate in this Plan, and who has been so notified by the BHE President and the Presidents. Such employee shall remain a Participant in this Plan for any award that has been made until such time as all benefits payable for that specific Award Year have been paid in accordance with the provisions hereof. A Participant may have an Incentive Account(s) or a Deferred Account and not be chosen to participate in a subsequent Award Year.
2.13Plan. “Plan” means this PacifiCorp Long-Term Incentive Partnership Plan as amended from time to time.
2.14Presidents. “Presidents” means the President and CEO of Pacific Power and the President and CEO of Rocky Mountain Power.
2.15Retirement and Retirement Age. “Retirement” means termination of employment with the Company after attaining age fifty-five (55) and “Retirement Age” means age fifty-five (55).
2.16Separation from Service. “Separation from Service” or “Separates from Service” means a Participant’s termination of employment with the Company or as otherwise defined in Applicable Guidance (see Section 7.1(a)).
2.17Vest or Vested. “Vest” or “Vested” means deferred compensation which is not subject to a Substantial Risk of Forfeiture (as defined in Applicable Guidance) or to a requirement to perform further services for the Employer.
ARTICLE III – ELIGIBILITY AND PARTICIPATION
3.1Eligibility. Eligibility to participate in the Plan shall be limited to those select key employees of the Company who are designated by the BHE President and the Presidents from time to time. The BHE President shall not be a Participant in the Plan. The Presidents may participate in the Plan but only the BHE President shall make determinations regarding participation, the value of the target Incentive Award, and the establishment and achievement of any individual performance goals for the Presidents with respect to a particular Award Year.
3.2Participation. An employee’s participation in the Plan for any Award Year shall be effective upon notification to the employee by the Presidents.
ARTICLE IV – INCENTIVE AWARD
4.1Annual Award. Prior to or during each Award Year, the BHE President and the Presidents shall determine whether an Incentive Award shall be available for such Award Year. If an Incentive Award is made available, the BHE President and the Presidents will establish the award categories based upon Net Income target goals and/or such other criteria as they deem appropriate for the Award Year (including, but not limited to customer satisfaction, operational excellence, financial, safety, environmental, regulatory integrity, and risk management goals, and any individual goals specified for a particular Participant).
4.2Allocation of Award. The BHE President and the Presidents shall determine the amount of the Incentive Award for which each Participant shall be eligible for the Award Year





(if the established goals are met for an Award Year), usually expressed as a percentage of the Participant’s Base Salary.
4.3Determination of Annual Awards. The value of any Incentive Award shall be determined by the BHE President and the Presidents as soon as practical after the close of the Award Year, but in no event shall the value of the Award be determined later than March 1st of the year following the Award Year.
4.4Reduction of Awards. The BHE President and the Presidents may, in their sole discretion, establish certain criteria that must be met for an Incentive Award to be awarded in full. These criteria may include the achievement of certain customer satisfaction, operational excellence, financial, safety, environmental, regulatory integrity or risk management goals or other goals (whether Company or individual) established by the BHE President and the Presidents. The determination of whether any applicable goals have been achieved with respect to an Incentive Award shall be determined by the BHE President and the Presidents, as of the time that the dollar value of that Incentive Award is determined in Section 4.3 above. If any such goal is not met, the BHE President and the Presidents may reduce the Incentive Award by an amount as they determine in their sole discretion. In addition, with respect to an individual Participant and a particular Award Year, the BHE President and the Presidents may determine that the Participant will not receive an Incentive Award for such Award Year regardless of whether the Participant has received an Incentive Award in a prior Award Year or made a deferral election for such Award Year.

ARTICLE V – INCENTIVE ACCOUNT(S)
5.1Accounts. The Company shall maintain a separate bookkeeping account on behalf of each Participant in the Plan for each Incentive Award. The value of any Incentive Award allocated to each Participant plus any Interest earned thereon shall be added to such Participant’s Incentive Account for the applicable Award Year. Any distribution attributable to an Incentive Account shall reduce the Incentive Account as of the date of distribution. These Incentive Accounts shall be used solely to calculate the amount payable to each Participant under the Plan and shall not constitute a separate fund of assets.
5.2Timing of Credits. The value of a Participant’s Incentive Award for an Award Year shall be credited to a Participant’s Incentive Account for such Award Year as of the day determined by the BHE President and the Presidents, but in no event shall the date be later than March 1st of the year following the Award Year. Each Incentive Account shall be increased or decreased by the Interest credited on each Determination Date as though the balance of that Incentive Account as of the date the Incentive Award is credited to a Participant’s Incentive Account had been invested as provided in Section 2.10. Any distributions to a Participant shall reduce the Participant’s Incentive Account(s) as of the date of such distribution.
5.3Vesting of Accounts. Each Participant shall be twenty-five percent (25%) Vested in his or her Incentive Account on December 31st of the Award Year and an additional twenty-five percent (25%) on December 31 of each subsequent year; provided, however, for the 2014 Award Year, such vesting rate shall be twenty percent (20%) per year rather than twenty-five percent (25%). Participants must be employed on December 31st to Vest for the year. The BHE President may accelerate Vesting (but not accelerate payment), or may establish criteria with respect to a Participant (in addition to the passage of time) before Vesting will occur with





respect to any Incentive Award; provided, however, that any portion of an Incentive Award that has already Vested with the passage of time shall not be subject to any such additional vesting criteria, and provided further that no additional vesting criteria shall postpone the date of payment of the Incentive Award as provided under Section 6.1. The Participant shall be considered to be one hundred percent (100%) Vested in the event of termination of service as a result of a Disability or death.
5.4Statement of Accounts. The Company shall give to each Participant a statement showing the balances in the Participant’s Incentive Account(s) no less frequently than on an annual basis.
ARTICLE VI – PLAN BENEFITS
6.1Normal Benefit. The balance of each Participant’s Incentive Account(s) shall be paid as soon as administratively feasible following the end of the third year following the Award Year, but in any event no later than two and one-half (2 ½) months following the end of such third year; provided, however, for the 2014 Award Year, such payment timing shall be following the end of the fourth year following the Award Year. Unless deferred pursuant to Section 6.3 below, such amount shall be paid in a lump sum based upon the value of the Incentive Account as of December 31 immediately prior to the payment date (or the value as of the immediately preceding business day prior to December 31 if December 31 is not a business day).
6.2Early Termination Benefit. In the event that a Participant Separates from Service with the Company prior to the end of the third year following the end of an Award Year (or prior to the end of the fourth year following the end of the 2014 Award Year), the Participant shall receive the Vested portion of the Incentive Account(s) as of the most recent Determination Date preceding the date of payment, payable in a lump sum; provided, however, that if the Participant has a deferral election on file with respect to an Incentive Account pursuant to Article VII, and incurs a Separation from Service after reaching Retirement Age, payment of the Vested amount of any Incentive Account shall be governed by Article VII with respect to the deferral election made by the Participant. If paid in a lump sum, the amount shall be paid as soon as administratively feasible after the Separation from Service, but in no event later than two and one-half (2 ½) months following the date of Separation from Service. In addition, the provisions of Section 7.2(A) shall apply to distributions under this Section 6.2.
6.3Deferred Benefit. With respect to any Incentive Award, the Participant may elect, in a manner acceptable to the Company, to defer the receipt of all or a portion of the value of the Incentive Account due under this Plan by filing an election to do so before the beginning of the Award Year relating to the Incentive Award to be deferred. Any deferral election filed after the start of an Award Year must meet the requirements of Section 7.4(B) (Changes to Payment Election).
a)
The portion of the Incentive Account previously elected to be deferred shall be transferred as of the last day of the third year following the end of the Award Year (or as of the last day of the fourth year following the end of the 2014 Award Year) to a Deferred Account (or as soon as administratively feasible following Separation from Service if an appropriate deferral election has previously been made) and shall thereafter be subject to the terms and conditions of Article VII herein (any portion not previously elected to be deferred shall be paid pursuant to the provisions of Section 6.1 above);
b)
Such an election shall comply with the provisions of Section 7.4(A) and shall only permit the deferral of benefits otherwise payable under Section 6.1 above, and the limited circumstance set forth in Section 6.2 in the event of Retirement; and





c)
Such an election shall completely satisfy and discharge all obligations on the part of the Company to the Participant (and the Participant’s Beneficiary) with respect to such Incentive Account, and the Participant’s (and Participant’s Beneficiary’s) rights under the Plan with respect to such Incentive Account shall terminate and shall be governed by the provisions of the Plan dealing with Deferred Accounts.
An example: A Participant may elect to defer the receipt of his 2015 Incentive Award by filing an election to do so prior to December 31, 2014. If such election is in a form acceptable to the Company, the balance of the Vested portion of the 2015 Incentive Account as of December 31, 2018, shall be transferred to a Deferred Account for the Participant as of that date.
6.4Death Benefit. In the event of the death of a Participant prior to payment of any Incentive Account(s), the Participant’s Beneficiary shall receive the value of the Incentive Account(s) determined as of the date of death. Such amounts shall be paid in a lump sum as soon as administratively feasible after the death of the Participant, but in no event later than two and one-half (2 ½) months following the date of the Participant’s death.
6.5Withholding and Payroll Taxes. The Company that employs the Participant at the time of payment shall withhold from any payment made pursuant to the Plan, from an Incentive Account, any taxes required to be withheld from such payments under law. A Beneficiary, however, may elect not to have withholding of federal income tax pursuant to Section 3405(a)(2) of the Code, or any successor provision thereto (U.S. only). If FICA/Medicare taxes are due with respect to all or a portion of an Incentive Account prior to payment from the account, the Participant shall make arrangements satisfactory to the Company for payment of the Participant’s share of such taxes, which may include withholding of such taxes from other regular pay of the Participant.
6.6Payment to Guardian. If a Plan benefit is payable to a minor, a person declared incompetent or a person incapable of handling the disposition of the property, the Company may direct payment to the guardian, legal representative or person having the care and custody of such minor or person. The Company may require proof of incompetence, incapacity or guardianship, as it may deem appropriate prior to distribution. Such distribution shall completely discharge the Company from all liability with respect to such benefit.
6.7Effect of Payment. The full payment of the applicable benefit under this Article VI shall completely discharge all obligations on the part of the Company to the Participant (and the Participant’s Beneficiary) with respect to the Incentive Account(s), and the Participant’s (and Participant’s Beneficiary’s) rights under the Plan with respect to the Incentive Account(s) shall terminate.
ARTICLE VII – DEFERRED BENEFIT
7.1Definitions. For the purposes of this Article VII, the following terms shall have the meanings indicated, unless the context clearly indicates otherwise.
a)    “Applicable Guidance” means Treasury Regulations issued pursuant to Code §409A or other written Treasury or IRS guidance regarding Code §409A.
b)    “Deferred Account” means the account established under the Plan for each Participant who elects to defer receipt of benefits under Section 6.3. A Deferred Account shall





consist of subaccounts as selected by the Participant, which may be a Retirement Account and an In-Service Account. The Deferred Account is 100% Vested.
c)    “Earnings” means the notional earnings, gains and losses applicable to a Participant’s Deferred Account as described in Section 7.7.
d)    “Separation From Service” means a Participant’s termination of employment with the Company or as otherwise defined in Applicable Guidance.
e)    “Specified Employee” means a Participant who is described in Code §416(i), disregarding paragraph (5) thereof. However, a Participant is not a Specified Employee unless any stock of the Company (or of a member of the same group of controlled entities as Company) is publicly traded on an established securities market or otherwise.
f)    “Specified Time or Pursuant to a Fixed Schedule” means a specific time or schedule (but not the occurrence of an event) as a Participant payment election may specify, and otherwise as described in Applicable Guidance.
g)    “Unforeseeable Emergency” means: (i) a severe financial hardship to the Participant resulting from a sudden and unexpected illness or accident of the Participant, the Participant’s spouse or a dependent (as defined in Code §152(a)) of the Participant; (ii) loss of the Participant’s property due to casualty; or (iii) other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the Participant’s control. The amount of the distribution may not exceed the amount necessary to satisfy the Unforeseeable Emergency plus taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which the hardship may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the Participant’s assets, to the extent that liquidation of such assets would not itself cause severe financial hardship.
7.2Separation from Service or Death. The Company will pay to the Participant the balance held in the Participant’s Deferred Account following the earlier of the Participant’s Separation from Service or death. Payment will commence at the time and payment will be made in the form and method specified under Section 7.4. In the event of the Participant’s death, the Plan will pay to the Participant’s Beneficiary the Participant’s Deferred Account balance or any remaining amount thereof if benefits to the Participant already have commenced, in accordance with the Participant’s election.
(A)    Distribution to Specified Employees. Notwithstanding anything to the contrary in the Plan or in a Participant payment election, the Company may not distribute to a Specified Employee, based on Separation from Service, earlier than 6 months following Separation from Service (or if earlier, upon the Specified Employee’s death).
7.3Other Payment Events. In addition to the payment events under Section 7.2, the Company will pay to a Participant all or any part of the Participant’s Deferred Account: (i) at a Specified Time or Pursuant to a Fixed Schedule elected by the Participant with respect to an In-Service subaccount; or (ii) based upon an Unforeseeable Emergency. Payment will commence at the time and payment will be made in the form and method specified under Section 7.4.
7.4Form, Timing and Method/Payment Election. All distributions will be in cash. Subject to the provisions of this paragraph, a Participant shall make an initial payment election





as to the method of payment under Section 7.4(A) and may make a change to an election under Section 7.4(B). If no election to defer payment of an Award has been made by the deadline as set forth in Section 6.3, the timing and method of payment for an Award as set forth in Section 6.1, 6.2 and 6.4 shall be deemed to be the Participant’s initial deferral election for purposes of a change to an election under Section 7.4(B). Until the Company completely distributes a Participant’s Deferred Account, the Plan will continue to credit the Participant’s Deferred Account with Earnings, in accordance with Section 7.7. Except as provided below, a Participant may elect either a lump sum payment or substantially equal annual installments (not to exceed 10) with respect to a Retirement subaccount and an In-Service subaccount. If no election is made as to method, payment shall be made in a lump sum. If no election is made with respect to an In-Service subaccount as to a specified time to begin payments, the date of the regularly scheduled payment for an Incentive Account shall be deemed to be the date to begin payments. Distributions from a Retirement subaccount as a result of Separation from Service after Retirement Age shall be made (or commence) in January following the calendar year in which Separation from Service occurs. Except as provided below, payments from an In-Service subaccount shall commence as soon as administratively feasible following the date selected by the Participant. If Separation from Service occurs after Retirement Age and before commencement of distribution from an In-Service subaccount, the In-Service subaccount shall be added to the Retirement subaccount and distributed accordingly. Distributions from an In-Service subaccount or a Retirement subaccount, when a Separation from Service occurs prior to Retirement Age (including death prior to Retirement Age), shall be made as soon as administratively feasible following the date of Separation from Service (or death) and shall be made in a lump sum payment (except that payments from the remaining account balance in an In-Service subaccount, where payments have already commenced prior to Separation from Service, shall continue to be made under the schedule then in effect). Payments made because of Unforeseeable Emergency shall be made (or commence) as soon as administratively feasible following such event. In the event of death after attaining Retirement Age or after payments from a Deferred Account have begun, a lump sum payment to the Beneficiary shall be made as soon as administratively feasible after date of death if the Participant had previously elected a lump sum distribution to the Beneficiary pursuant to Section 7.4(A) (initial payment election) or pursuant to Section 7.4(B)(1) (change to payment election). Disability shall not be treated as a distribution event if Separation from Service has not occurred.
(A)    Initial Payment Election. A Participant, as to an In-Service subaccount shall make an initial payment election with respect to a Specified Time or Pursuant to a Fixed Schedule at the time of the Participant’s first deferred benefit election into such subaccount. As to a Retirement subaccount, a Participant shall make an initial payment election as to a method of payment (Fixed Schedule) at the time of his or her first deferred benefit election into such subaccount (the Specified Time being a date following Separation of Service as provided in Section 7.4 above). A Participant shall make any permissible initial payment election on a form the Company provides for that purpose. At the time of any such first deferred benefit election into any subaccount in his or her Deferred Account, a Participant may elect to have a lump sum payment made to his or her Beneficiary in lieu of the form of payment that otherwise has been selected for payout during the Participant’s life.





(B)    Changes to Payment Election. A Participant may change the Participant’s initial payment election (or change election) as to any subaccount in his or her Deferred Account, including any Plan default payment applicable in the absence of an election. Any such change election must comply with this Section 7.4(B). A Participant must make any change election on a form the Company provides for such purpose.
(1)    Conditions on Changes to Payment Elections. Any Participant change election: (i) may not take effect until at least 12 months following the date of the change election; (ii) must result in the first payment under the change election being made not earlier than 5 years following the date upon which the originally-elected payment would have been made (except if payment is on account of death, or Unforeseeable Emergency); and (iii) if the change election relates to a Participant’s previous election of a Specified Time or Pursuant to a Fixed Schedule, the Participant must make the change election not less than 12 months prior to the date of the first scheduled payment under the election being changed (or, in the case of installment payments treated as a single payment, 12 months prior to the date the first amount was scheduled to be paid).
(2)    Definition of “Payment.” Except as otherwise provided in Section 7.4(B)(3), a “payment” for purposes of applying Section 7.4(B)(1) is each separately identified amount the Company is obligated to pay to a Participant on a determinable date and includes amounts paid for the benefit of the Participant. An amount is “separately identified” only if the Company can objectively determine the amount.
(3)    Installment Payments. As set forth in Applicable Guidance, and for purposes of making a change to a payment election under this Section 7.4(B), a series of installment payments will be treated as a single payment. For purposes of this Section 7.4(B)(3), a “series of installment payments” means payment of a series of substantially equal periodic amounts to be paid over a predetermined number of years, except to the extent that any increase in the payment amounts reflects reasonable Earnings through the date of payment.
(4)    Coordination with Anti-Acceleration Rule. In applying Section 7.4(C), “payment” means as described in Sections 7.4(B)(2) and (3). A Participant under a change payment election may change the form of payment to a more rapid schedule (including a change from installments to a lump-sum payment) without violating Section 7.4(C), provided any such change remains subject to the change payment election provisions under this Section 7.4(B). Accordingly, if the Participant’s payment change election modifies the payment method from installments to a lump-sum payment, a payment change election must satisfy Section 7.4(B)(1) measured from the first installment payment. If a payment change election only modifies the timing of an installment payment, the payment change election must apply to each installment and must satisfy Section 7.4(B) measured from each installment payment.
(C)    No Acceleration. Neither the Company nor the Participant may accelerate the time or schedule of any payment under the Plan except as Applicable Guidance may permit. For this purpose, the following are not an acceleration: (i) a payment required under a domestic relations order under Code §414(p)(1)(B); (ii) a payment required under a certificate of divestiture under Code §1043(b)(2); or (iii) a payment to





pay the FICA tax (and income tax withholding related to the FICA) on the deferred compensation.
(D)    Cash-Out Upon Separation. Notwithstanding a Participant’s payment election or any contrary Plan terms, the Company will distribute in a single cash payment the entire Deferred Account of a Participant who has incurred a Separation from Service where the Participant’s Deferred Account balance does not exceed $10,000. The Company will make any payment under this Section as soon as administratively feasible following Separation from Service.
7.5Withholding of Income Tax. The Company that employs the Participant at the time of payment or employed the Participant immediately prior to a Separation from Service (with the Company including such payment on a Form W-2 issued by the Company to the Participant) will withhold from any payment made under the Plan from a Deferred Account and from any amount taxable under Code §409A, all applicable taxes, and any and all other amounts required to be withheld under federal, state or local law, including Applicable Guidance.
7.6Administration of Payment Date(s). The Company may pay a Participant’s Deferred Account balance on any date that is administratively feasible following any Plan specified payment date or date of any authorized distribution event or the date specified in any valid payment election, but in no event later than two and one-half (2 ½) months following any such date; and provided further that the Participant shall not be permitted, directly or indirectly, to designate the taxable year of the payment.
7.7Notional Earnings. The Company, under the Plan, periodically will credit Deferred Accounts with a determinable amount of notional Earnings (as a specified fixed or floating interest rate or other specified index or indices based on established and published financial investment benchmarks). The Participant has the right to direct the investment of the Participant’s Deferred Account pursuant to conditions established by the Company. This right is limited strictly to investment direction and the Participant will not be entitled to the distribution of any Deferred Account asset except as the Plan otherwise permits. Except as otherwise provided in the Plan or trust, all Plan assets, including all incidents of ownership, at all times will be the sole property of the Company.
ARTICLE VIII – BENEFICIARY DESIGNATION
8.1Beneficiary Designation. Each Participant shall have the right, at any time, to designate one (1) or more persons or entities as Beneficiary (both primary as well as secondary) to whom benefits under the Plan shall be paid in the event of Participant’s death prior to complete distribution of the Participant’s Incentive Account(s) or Deferred Account balances. Each Beneficiary designation shall be in a written form prescribed by the Company and shall be effective only when filed with the Company during the Participant’s lifetime.
8.2Changing Beneficiary. Any Beneficiary designation may be changed by a Participant without the consent of the previously named Beneficiary by the filing of a new Beneficiary designation with the Company. The filing of a new designation shall cancel all designations previously filed.





8.3Change in Marital Status. If the Participant’s marital status changes after the Participant has designated a Beneficiary, the following shall apply until such time as the Participant submits a revised Beneficiary form.
a)
If the Participant is married at death but was unmarried when the designation was made, the designation shall be void.
b)
If the Participant is unmarried at death but was married when the designation was made:
i)    The designation shall be void if the former spouse was named as Beneficiary.
ii)    The designation shall remain valid if the spouse was not named and a non-spouse Beneficiary was named.
c)
If the Participant was married when the designation was made and is married to a different spouse at death:
i)    The designation shall be void if the former spouse was named as Beneficiary.
ii)    The designation shall remain valid if the former spouse was not named and a non-spouse Beneficiary was named.
8.4No Beneficiary Designation. If any Participant fails to designate a Beneficiary in the manner provided above, if the designation is void, or if the Beneficiary designated by a deceased Participant dies before the Participant or before complete distribution of the Participant’s benefits, the Participant’s Beneficiary shall be the person in the first of the following classes in which there is a survivor:
a)The Participant’s surviving spouse;
b)
The Participant’s children (including stepchildren) in equal shares, except if any of the children predeceases the Participant but leaves surviving descendant, then such descendant shall take by right of representation the share the deceased child would have taken if living;
c)The Participant’s estate.
8.5Effect of Payment. Payment to Beneficiary or other proper legal representative of the Beneficiary shall completely discharge the Company’s obligations under the Plan and the Company may require a release to that effect from the Beneficiary or other proper legal representative of the Beneficiary prior to the distribution.
8.6Minor or Incompetent Beneficiary. If a Beneficiary is a minor or otherwise reasonably determined by the Employer to be legally incompetent, the Employer may cause the Plan to pay the Participant’s Vested Incentive Account(s) or Deferred Account balances to a guardian, trustee or other proper legal representative of the Beneficiary.
ARTICLE IX – ADMINISTRATION
9.1Binding Effect of Decisions. Subject to the rights of a Participant under the claims procedure set forth in Article X, the decision or action of the BHE President and the Presidents with respect to any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final, conclusive and binding upon all persons having any interest in the Plan.





ARTICLE X – CLAIMS PROCEDURE
10.1Claim. Any person or entity claiming a benefit, requesting an interpretation or ruling under the Plan (hereinafter referred to as “Claimant”) shall present the request in writing to the BHE President and the Presidents, who shall respond in writing as soon as practical. The decision shall be in writing and shall state the reasons and the relevant Plan provisions. All decisions on review shall be final and bind all parties concerned.
10.2Denial of Claim. If the claim or request is denied, the written notice of denial shall state:
a)
The reasons for denial, with specific reference to the Plan provisions on which the denial is based;
b)
A description of any additional material or information required and an explanation of why it is necessary; and
c)
An explanation of the Plan’s claim review procedure.
10.3Review of Claim Denial. Any Claimant whose claim or request is denied or who has not received a response within sixty (60) days may request a review by notice given in writing to the BHE President and the Presidents. Such request must be made within sixty (60) days after receipt by the Claimant of the written notice of denial, or in the event Claimant has not received a response sixty (60) days after receipt by the BHE President and the Presidents of Claimant’s claim or request. The claim or request shall be reviewed by the BHE President and the Presidents, who may, but shall not be required to, grant the Claimant a hearing. On review, the Claimant may have representation, examine pertinent documents, and submit issues and comments in writing.
10.4Final Decision. The decision on review shall normally be made within sixty (60) days after receipt of Claimant’s claim or request. If an extension of time is required for a hearing or other special circumstances, the Claimant shall be notified and the time limit shall be one hundred twenty (120) days.
ARTICLE XI – AMENDMENT AND TERMINATION OF PLAN
11.1Amendment. The Company reserves the right to amend the Plan at any time to comply with Code §409A and Applicable Guidance or for any other purpose, provided that such amendment will not result in taxation to any Participant under Code §409A. Except as the Plan and Applicable Guidance otherwise may require, the Company may make any such amendments effective immediately.
11.2Termination. The Company, by action of the Board, may terminate, but is not required to terminate, the Plan and distribute Plan Accounts under the following circumstances:
(1) Dissolution/Bankruptcy. The Company may terminate the Plan within 12 months following a dissolution of a corporate Company taxable under Code §331 or with approval of a Bankruptcy court under 11 U.S.C. §503(b)(1)(A), provided that the deferred compensation is paid to the Participants and is included in the Participants’ gross income in the latest calendar year: (i) in which the plan termination occurs; (ii) in which the amounts no longer are subject to a Substantial Risk of Forfeiture; or (iii) in which the payment is administratively practicable.





(2) Change in Control. The Company may terminate the Plan within the 30 days preceding or the 12 months following a Change in Control (as defined in Applicable Guidance) provided the Company distributes all Plan Accounts (and must distribute the accounts under any substantially similar Company plan which plan the Company also must terminate) within 12 months following the Plan termination.
(3) Other. The Company may terminate the Plan for any other reason in the Company’s discretion provided that: (i) the Company also terminates all aggregated plans in which any Participant also is a participant; (ii) the Company makes no payments under the Plan in the 12 months following the Plan termination date other than payments the Company would have made under the Plan irrespective of Plan termination; (iii) the Company makes all payments within 24 months following the Plan termination date; and (iv) the Company within 3 years following the Plan termination date does not adopt a new plan covering any Participant that would be an aggregated plan.
(4) Applicable Guidance and Plan Types. The Company may terminate the Plan under such other circumstances as Applicable Guidance may permit. In addition, for purposes of plan termination, the portion of the Plan representing Incentive Accounts shall be considered to be a non-elective account balance plan type and the portion of the Plan representing Deferral Accounts shall be considered to be an elective account balance plan type.
ARTICLE XII – MISCELLANEOUS
12.1Unfunded Plan. To the extent the Plan is considered an “employee benefit pension plan” under Section 3 (2) the Employee Retirement Income Security Act of 1974, as amended (“ERISA”) with respect to any Participant (because some or all of the payments with respect to a Participant under the Plan have been elected by the Participant to be made from a Retirement Account), the Plan, as to any such Participant, is an unfunded plan maintained primarily to provide deferred compensation benefits for a select group of “management or highly-compensated employees” within the meaning of Sections 201, 301 and 401 of the ERISA, and therefore is exempt from the provisions of Parts 2, 3 and 4 of Title I of ERISA. Accordingly, the Board may terminate the Plan and make no further benefit payments or remove certain employees as Participants if it is determined by the United States Department of Labor, a court of competent jurisdiction, or an opinion of counsel that the Plan constitutes an employee pension benefit plan within the meaning of Section 3(2) of ERISA (as currently in effect or hereafter amended) which is not so exempt.
12.2Company Obligation. The obligation to make benefit payments to any Participant under the Plan shall be an obligation solely of the Company.
12.3Unsecured General Creditor. Notwithstanding any other provision of the Plan, Participants and Participants’ Beneficiaries shall be unsecured general creditors, with no secured or preferential rights to any assets of the Company or any other party for payment of benefits under the Plan. Any property held by the Company for the purpose of generating the cash flow for benefit payments shall remain its general, unpledged and unrestricted assets. The Company’s obligation under the Plan shall be an unfunded and unsecured promise to pay money in the future.





12.4Trust Fund. The Company shall be responsible for the payment of all benefits provided under the Plan. At its discretion, the Company may establish one (1) or more trusts for the purpose of assisting in the payment of such benefits. Although such a trust shall be irrevocable, its assets shall be held for payment of all the Company’s general creditors in the event of insolvency. To the extent any benefits provided under the Plan are paid from any such trust, the Company shall have no further obligation to pay them. If not paid from the trust, such benefits shall remain the obligation of the Company.
12.5Nonassignability. Neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate or convey in advance of actual receipt of the amounts, if any, payable hereunder, or any part thereof, which are, and all rights to which are, expressly declared to be unassignable and non-transferable except only pursuant to the designated Beneficiary in the event of death or Disability or pursuant to a legal will or the laws of intestate succession. No part of the amounts payable shall, prior to actual payment, be subject to seizure or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, nor be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency.
12.6Not a Contract of Employment. The Plan shall not constitute a contract of employment between the Company and the Participant. Nothing in the Plan shall give a Participant the right to be retained in the service of the Company or to interfere with the right of the Company to discipline or discharge a Participant at any time.
12.7Protective Provisions. A Participant will cooperate with the Company by furnishing any and all information requested by the Company, in order to facilitate the payment of benefits hereunder.
12.8Governing Law. The provisions of the Plan shall be construed and interpreted according to the laws of the State of Oregon, except as preempted by federal law.
12.9Validity. If any provision of the Plan shall be held illegal or invalid for any reason, said illegality or invalidity shall not affect the remaining parts hereof, but the Plan shall be construed and enforced as if such illegal and invalid provision had never been inserted herein.
12.10Notice and Elections. Any notice required or permitted under the Plan shall be sufficient if in writing and hand delivered or sent by registered or certified mail. Such notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification. Mailed notice to the BHE President and the Presidents or to the Company shall be directed to the Company’s address. Mailed notice to a Participant or Beneficiary shall be directed to the individual’s last known address in the Company’s records. Any election made under the Plan must be in writing and delivered (electronically, by facsimile, or by mail) to the Company pursuant to procedures established by the Company. The Employer will prescribe the form of any Plan notice or election to be given to or made by Participants. Any notice or election will be deemed given or made as of the date of actual receipt, or if given or made by certified mail, as of 3 business days after mailing.





12.11Successors. The provisions of this Plan shall bind and inure to the benefit of the Company and its successors and assigns. The term successors as used herein shall include any corporate or other business entity which shall, whether by merger, consolidation, purchase or otherwise, acquire all or substantially all of the business and assets of the Company, and successors of any such corporation or other business entity.
12.12Account Statements. The Company will provide each Participant with a statement of the Participant’s Incentive Accounts and Deferral Accounts at least annually as of the last day of the most recent calendar year. The Company also will provide account statements to any Beneficiary of a deceased Participant with an Incentive Account or Deferral Account remaining in the Plan.
12.13Accounting. The Company will maintain for each Participant as is necessary for proper administration of the Plan, an Incentive Account for each Award year and a Deferral Account (and Retirement and In-Service subaccounts).
12.14Costs and Expenses. The Company will pay the costs, expenses and fees associated with the operation of the Plan, excluding those incurred by Participants or Beneficiaries. The Company will pay costs, expenses or fees charged by or incurred by the trustee only as provided in the trust or other agreement between the Company and the trustee.
12.15Reporting. The Company will report deferred compensation for Participants on Form W-2 in accordance with Applicable Guidance.






Berkshire Hathaway Energy Company

BY: /s/ William J. Fehrman
William J. Fehrman
President and CEO

DATED: December 2, 2019

 
Pacific Power, an unincorporated division of PacifiCorp

BY: /s/ Stefan Bird
Stefan Bird
President and CEO

DATED: November 26, 2019


Rocky Mountain Power, an unincorporated division of PacifiCorp

BY: /s/ Gary Hoogeveen
Gary Hoogeveen
President and CEO

DATED: November 26, 2019







EXHIBIT 21.1

BERKSHIRE HATHAWAY ENERGY COMPANY
SUBSIDIARIES AND JOINT VENTURES

Pursuant to Item 601(b)(21)(ii) of Regulation S-K, we have omitted certain subsidiaries (all of which, when considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary as of the end of our last fiscal year).

PPW Holdings LLC
Delaware
PacifiCorp
Oregon
MidAmerican Funding, LLC
Iowa
MHC Inc.
Iowa
MidAmerican Energy Company
Iowa
NVE Holdings, LLC
Delaware
NV Energy, Inc.
Nevada
Nevada Power Company
Nevada
Sierra Pacific Power Company
Nevada
Northern Powergrid Holdings Company
United Kingdom
Northern Powergrid UK Holdings
United Kingdom
Northern Powergrid Limited
United Kingdom
Northern Electric plc.
United Kingdom
Northern Powergrid (Northeast) Limited
United Kingdom
Yorkshire Power Group Limited
United Kingdom
Yorkshire Electricity Group plc.
United Kingdom
Northern Powergrid (Yorkshire) plc.
United Kingdom
NNGC Acquisition, LLC
Delaware
Northern Natural Gas Company
Delaware
KR Holding, LLC
Delaware
Kern River Gas Transmission Company
Delaware
BHE Canada, LLC
Delaware
BHE Canada Holdings Corporation
Canada
BHE AltaLink Ltd.
Canada
AltaLink Holdings, L.P.
Canada
AltaLink Investments, L.P.
Canada
AltaLink, L.P.
Canada
BHE U.S. Transmission, LLC
Delaware
BHE Renewables, LLC
Delaware
BHE Wind, LLC
Delaware
HomeServices of America, Inc.
Delaware





EXHIBIT 23.1




CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-228511 on Form S-8 of our report dated February 21, 2020, relating to the consolidated financial statements and financial statement schedules of Berkshire Hathaway Energy Company and subsidiaries appearing in this Annual Report on Form 10-K of Berkshire Hathaway Energy Company for the year ended December 31, 2019.

/s/ Deloitte & Touche LLP

Des Moines, Iowa
February 21, 2020






EXHIBIT 23.2



CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


We consent to the incorporation by reference in Registration Statement No. 333-227592 on Form S-3 of our report dated February 21, 2020, relating to the consolidated financial statements of PacifiCorp and subsidiaries appearing in this Annual Report on Form 10-K of PacifiCorp for the year ended December 31, 2019.


/s/ Deloitte & Touche LLP


Portland, Oregon
February 21, 2020






EXHIBIT 23.3




CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-225916 on Form S-3 of our report dated February 21, 2020, relating to the financial statements and financial statement schedule of MidAmerican Energy Company appearing in this Annual Report on Form 10-K of MidAmerican Energy Company for the year ended December 31, 2019.


/s/ Deloitte & Touche LLP

Des Moines, Iowa
February 21, 2020






EXHIBIT 23.4

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-234207 on Form S-3 of our report dated February 21, 2020 relating to the consolidated financial statements of Nevada Power Company and subsidiaries appearing in this Annual Report on Form 10-K of Nevada Power Company for the year ended December 31, 2019.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada
February 21, 2020






EXHIBIT 24.1




POWER OF ATTORNEY


The undersigned, a member of the Board of Directors or an officer of BERKSHIRE HATHAWAY ENERGY COMPANY, an Iowa corporation (the "Company"), hereby constitutes and appoints Natalie L. Hocken and Jeffery B. Erb and each of them, as his/her true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for and in his/her stead, in any and all capacities, to sign on his/her behalf the Company's Annual Report on Form 10-K for the fiscal year ending December 31, 2019 and to execute any amendments thereto and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission and applicable stock exchanges, with the full power and authority to do and perform each and every act and thing necessary or advisable to all intents and purposes as he/she might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, or his/her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Executed as of February 21, 2020

/s/ William J. Fehrman
 
/s/ Patrick J. Goodman
WILLIAM J. FEHRMAN
 
PATRICK J. GOODMAN
 
 
 
/s/ Gregory E. Abel
 
/s/ Warren E. Buffett
GREGORY E. ABEL
 
WARREN E. BUFFETT
 
 
 
/s/ Marc D. Hamburg
 
/s/ Walter Scott, Jr.
MARC D. HAMBURG
 
WALTER SCOTT, JR.






EXHIBIT 31.1
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, William J. Fehrman, certify that:
1.
I have reviewed this Annual Report on Form 10-K of Berkshire Hathaway Energy Company;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: February 21, 2020
/s/ William J. Fehrman
 
 
William J. Fehrman
 
 
President and Chief Executive Officer
 
 
(principal executive officer)
 





EXHIBIT 31.2
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Patrick J. Goodman, certify that:
1.
I have reviewed this Annual Report on Form 10-K of Berkshire Hathaway Energy Company;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: February 21, 2020
/s/ Patrick J. Goodman
 
 
Patrick J. Goodman
 
 
Executive Vice President and Chief Financial Officer
 
 
(principal financial officer)
 





EXHIBIT 31.3
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, William J. Fehrman, certify that:
1.
I have reviewed this Annual Report on Form 10-K of PacifiCorp;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: February 21, 2020
/s/ William J. Fehrman
 
 
William J. Fehrman
 
 
Chairman of the Board of Directors and Chief Executive Officer
 
 
(principal executive officer)
 






EXHIBIT 31.4
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Nikki L. Kobliha, certify that:
1.
I have reviewed this Annual Report on Form 10-K of PacifiCorp;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: February 21, 2020
/s/ Nikki L. Kobliha
 
 
Nikki L. Kobliha
 
 
Vice President, Chief Financial Officer and Treasurer
 
 
(principal financial officer)
 






EXHIBIT 31.5
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Adam L. Wright, certify that:
1.
I have reviewed this Annual Report on Form 10-K of MidAmerican Energy Company;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: February 21, 2020
/s/ Adam L. Wright
 
 
Adam L. Wright
 
 
President and Chief Executive Officer
 
 
(principal executive officer)
 





EXHIBIT 31.6
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Thomas B. Specketer, certify that:
1.
I have reviewed this Annual Report on Form 10-K of MidAmerican Energy Company;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: February 21, 2020
/s/ Thomas B. Specketer
 
 
Thomas B. Specketer
 
 
Vice President and Chief Financial Officer
 
 
(principal financial officer)
 





EXHIBIT 31.7
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Adam L. Wright, certify that:
1.
I have reviewed this Annual Report on Form 10-K of MidAmerican Funding, LLC;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: February 21, 2020
/s/ Adam L. Wright
 
 
Adam L. Wright
 
 
President
 
 
(principal executive officer)
 





EXHIBIT 31.8
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Thomas B. Specketer, certify that:
1.
I have reviewed this Annual Report on Form 10-K of MidAmerican Funding, LLC;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: February 21, 2020
/s/ Thomas B. Specketer
 
 
Thomas B. Specketer
 
 
Vice President and Controller
 
 
(principal financial officer)
 





EXHIBIT 31.9
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Douglas A. Cannon, certify that:
1.
I have reviewed this Annual Report on Form 10-K of Nevada Power Company (dba NV Energy);
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: February 21, 2020
/s/ Douglas A. Cannon
 
 
Douglas A. Cannon
 
 
President and Chief Executive Officer
 
 
(principal executive officer)
 






EXHIBIT 31.10
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Michael E. Cole, certify that:
1.
I have reviewed this Annual Report on Form 10-K of Nevada Power Company (dba NV Energy);
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: February 21, 2020
/s/ Michael E. Cole
 
 
Michael E. Cole
 
 
Vice President and Chief Financial Officer
 
 
(principal financial officer)
 
 





EXHIBIT 31.11
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Douglas A. Cannon, certify that:
1.
I have reviewed this Annual Report on Form 10-K of Sierra Pacific Power Company (dba NV Energy);
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: February 21, 2020
/s/ Douglas A. Cannon
 
 
Douglas A. Cannon
 
 
President and Chief Executive Officer
 
 
(principal executive officer)
 







EXHIBIT 31.12
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Michael E. Cole, certify that:
1.
I have reviewed this Annual Report on Form 10-K of Sierra Pacific Power Company (dba NV Energy);
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: February 21, 2020
/s/ Michael E. Cole
 
 
Michael E. Cole
 
 
Vice President and Chief Financial Officer
 
 
(principal financial officer)
 







EXHIBIT 32.1
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002

I, William J. Fehrman, President and Chief Executive Officer of Berkshire Hathaway Energy Company (the "Company"), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)
the Annual Report on Form 10-K of the Company for the annual period ended December 31, 2019 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Date: February 21, 2020
/s/ William J. Fehrman
 
 
William J. Fehrman
 
 
President and Chief Executive Officer
 
 
(principal executive officer)
 







EXHIBIT 32.2
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002

I, Patrick J. Goodman, Executive Vice President and Chief Financial Officer of Berkshire Hathaway Energy Company (the "Company"), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)
the Annual Report on Form 10-K of the Company for the annual period ended December 31, 2019 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Date: February 21, 2020
/s/ Patrick J. Goodman
 
 
Patrick J. Goodman
 
 
Executive Vice President and Chief Financial Officer
 
 
(principal financial officer)
 








EXHIBIT 32.3
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002

I, William J. Fehrman, Chairman of the Board of Directors and Chief Executive Officer of PacifiCorp, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)
the Annual Report on Form 10-K of PacifiCorp for the annual period ended December 31, 2019 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of PacifiCorp.
Date: February 21, 2020
/s/ William J. Fehrman
 
 
William J. Fehrman
 
 
Chairman of the Board of Directors and Chief Executive Officer
 
 
(principal executive officer)
 






EXHIBIT 32.4
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002

I, Nikki L. Kobliha, Vice President, Chief Financial Officer and Treasurer of PacifiCorp, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)
the Annual Report on Form 10-K of PacifiCorp for the annual period ended December 31, 2019 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of PacifiCorp.
Date: February 21, 2020
/s/ Nikki L. Kobliha
 
 
Nikki L. Kobliha
 
 
Vice President, Chief Financial Officer and Treasurer
 
 
(principal financial officer)
 






EXHIBIT 32.5
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002

I, Adam L. Wright, President and Chief Executive Officer of MidAmerican Energy Company , certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)
the Annual Report on Form 10-K of MidAmerican Energy Company for the annual period ended December 31, 2019 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of MidAmerican Energy Company.
Date: February 21, 2020
/s/ Adam L. Wright
 
 
Adam L. Wright
 
 
President and Chief Executive Officer
 
 
(principal executive officer)
 






EXHIBIT 32.6
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002

I, Thomas B. Specketer, Vice President and Chief Financial Officer of MidAmerican Energy Company, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)
the Annual Report on Form 10-K of MidAmerican Energy Company for the annual period ended December 31, 2019 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of MidAmerican Energy Company.
Date: February 21, 2020
/s/ Thomas B. Specketer
 
 
Thomas B. Specketer
 
 
Vice President and Chief Financial Officer
 
 
(principal financial officer)
 






EXHIBIT 32.7
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002

I, Adam L. Wright, President of MidAmerican Funding, LLC, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)
the Annual Report on Form 10-K of MidAmerican Funding, LLC for the annual period ended December 31, 2019 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of MidAmerican Funding, LLC.
Date: February 21, 2020
/s/ Adam L. Wright
 
 
Adam L. Wright
 
 
President
 
 
(principal executive officer)
 






EXHIBIT 32.8
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002

I, Thomas B. Specketer, Vice President and Controller of MidAmerican Funding, LLC, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)
the Annual Report on Form 10-K of MidAmerican Funding, LLC for the annual period ended December 31, 2019 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of MidAmerican Funding, LLC.
Date: February 21, 2020
/s/ Thomas B. Specketer
 
 
Thomas B. Specketer
 
 
Vice President and Controller
 
 
(principal financial officer)
 






EXHIBIT 32.9
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
 
I, Douglas A. Cannon, President and Chief Executive Officer of Nevada Power Company (dba NV Energy), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)
the Annual Report on Form 10-K of Nevada Power Company for the annual period ended December 31, 2019 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Nevada Power Company.
Date: February 21, 2020
/s/ Douglas A. Cannon
 
 
Douglas A. Cannon
 
 
President and Chief Executive Officer
 
 
(principal executive officer)
 

 

 






EXHIBIT 32.10
 CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
 
I, Michael E. Cole, Vice President and Chief Financial Officer of Nevada Power Company (dba NV Energy), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)
the Annual Report on Form 10-K of Nevada Power Company for the annual period ended December 31, 2019 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Nevada Power Company.
Date: February 21, 2020
/s/ Michael E. Cole
 
 
Michael E. Cole
 
 
Vice President and Chief Financial Officer
 
 
(principal financial officer)
 






EXHIBIT 32.11
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
 
I, Douglas A. Cannon, President and Chief Executive Officer of Sierra Pacific Power Company (dba NV Energy), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)
the Annual Report on Form 10-K of Sierra Pacific Power Company for the annual period ended December 31, 2019 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Sierra Pacific Power Company.
Date: February 21, 2020
/s/ Douglas A. Cannon
 
 
Douglas A. Cannon
 
 
President and Chief Executive Officer
 
 
(principal executive officer)
 






EXHIBIT 32.12 
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
 
I, Michael E. Cole, Vice President and Chief Financial Officer of Sierra Pacific Power Company (dba NV Energy), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge: 
(1)
the Annual Report on Form 10-K of Sierra Pacific Power Company for the annual period ended December 31, 2019 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Sierra Pacific Power Company.
Date: February 21, 2020
/s/ Michael E. Cole
 
 
Michael E. Cole
 
 
Vice President and Chief Financial Officer
 
 
(principal financial officer)
 






EXHIBIT 95


MINE SAFETY VIOLATIONS AND OTHER LEGAL MATTER DISCLOSURES
PURSUANT TO SECTION 1503(a) OF THE DODD-FRANK WALL STREET
REFORM AND CONSUMER PROTECTION ACT

PacifiCorp and its subsidiaries operate certain coal mines and coal processing facilities (collectively, the "mining facilities") that are regulated by the Federal Mine Safety and Health Administration ("MSHA") under the Federal Mine Safety and Health Act of 1977 (the "Mine Safety Act"). MSHA inspects PacifiCorp's mining facilities on a regular basis. The total number of reportable Mine Safety Act citations, orders, assessments and legal actions for the year ended December 31, 2019 are summarized in the table below and are subject to contest and appeal. The severity and assessment of penalties may be reduced or, in some cases, dismissed through the contest and appeal process. Amounts are reported regardless of whether PacifiCorp has challenged or appealed the matter. Mines that are closed or idled are not included in the information below as no reportable events occurred at those locations during the year ended December 31, 2019. There were no mining-related fatalities during the year ended December 31, 2019. PacifiCorp has not received any notice of a pattern, or notice of the potential to have a pattern, of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards under Section 104(e) of the Mine Safety Act during the year ended December 31, 2019.

 
 
Mine Safety Act
 
 
 
Legal Actions
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
Section 104
 
 
 
Section
 
Value of
 
 
 
 
 
 
Significant
 
Section
 
107(a)
 
Proposed
 
Pending
 
 
 
 
and
Section
104(d)
Section
Imminent
 
MSHA
 
as of Last
Instituted
Resolved
 
 
Substantial
104(b)
Citations/
110(b)(2)
Danger
 
Assessments
 
Day of
During
During
Mining Facilities
 
Citations(1)
Orders(2)
Orders(3)
Violations(4)
Orders(5)
 
(in thousands)
 
Period(6)
Period
Period
 
 
 
 
 
 
 
 
 
 
 
 
 
Bridger (surface)
 





 

 



Bridger (underground)
 
5


2



 
$
43

 
1

3

4

Wyodak Coal Crushing Facility
 





 

 





(1)
Citations for alleged violations of mandatory health and safety standards that could significantly or substantially contribute to the cause and effect of a safety or health hazard under Section 104 of the Mine Safety Act.
(2)
For alleged failure to totally abate the subject matter of a Mine Safety Act Section 104(a) citation within the period specified in the citation.
(3)
For alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mandatory health or safety standard. Subsequently, MSHA modified the Section 104(d)(1) citation to a Section 104(a) citation and also vacated the Section 104(d)(1) order.
(4)
For alleged flagrant violations (i.e., reckless or repeated failure to make reasonable efforts to eliminate a known violation of a mandatory health or safety standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury).
(5)
For the existence of any condition or practice in a coal or other mine which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated.
(6)
Amounts include one contest of proposed penalties under Subpart C of the Federal Mine Safety and Health Review Commission's procedural rules. The pending legal actions are not exclusive to citations, notices, orders and penalties assessed by MSHA during the reporting period.