UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2020

or

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

For the transition period from ______ to _______

		Exact name of registrant as specified in its charter
		State or other jurisdiction of incorporation or organization
Commission		Address of principal executive offices		IRS Employer
File Number		Registrant's telephone number, including area code		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
		N/A
		(Former name or former address, if changed from last report)

---

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	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

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

---

---

---

---

ECAM		Energy Cost Adjustment Mechanism
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
GAAP		Accounting principles generally accepted in the United States of America
GEMA		Gas and Electricity Markets Authority
GWh		Gigawatt Hour
GTA		General Tariff Application
IPUC		Idaho Public Utilities Commission
ICC		Illinois Commerce Commission
IRP		Integrated Resource Plan
IUB		Iowa Utilities Board
kV		Kilovolt
KHSA		Klamath Hydroelectric Settlement Agreement
MATS		Mercury and Air Toxics Standards
MW		Megawatt
MWh		Megawatt Hour
NAAQS		National Ambient Air Quality Standards
NOx		Nitrogen Oxides
OATT		Open Access Transmission Tariff
Ofgem		Office of Gas and Electric Markets
OPUC		Oregon Public Utility Commission
PTC		Production Tax Credit
PUCN		Public Utilities Commission of Nevada
RAC		Renewable Adjustment Clause
REC		Renewable Energy Credit
RPS		Renewable Portfolio Standards
RRA		Renewable Energy Credit and Sulfur Dioxide Revenue Adjustment Mechanism
SCR		Selective Catalytic Reduction
SEC		United States Securities and Exchange Commission
SIP		State Implementation Plan
SO2		Sulfur Dioxide
TAM		Transition Adjustment Mechanism
UPSC		Utah Public Service Commission
WPSC		Wyoming Public Service Commission
WUTC		Washington Utilities and Transportation Commission

---

•	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, pandemics (including potentially in relation to COVID-19), 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;

•	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 the portion of the natural gas transmission and storage business acquired from Dominion Energy, Inc. on November 1, 2020, and future acquired operations into a Registrant's business;

•	the expected timing and likelihood of completion of the proposed transaction to acquire the remaining portion of Dominion Energy, Inc.'s natural gas transmission and storage business, including the ability to obtain the required clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended;

•	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.

---

Item 1.	Financial Statements

Berkshire Hathaway Energy Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		4
Consolidated Balance Sheets		5
Consolidated Statements of Operations		7
Consolidated Statements of Comprehensive Income		8
Consolidated Statements of Changes in Equity		9
Consolidated Statements of Cash Flows		10
Notes to Consolidated Financial Statements		11
PacifiCorp and its subsidiaries
Report of Independent Registered Public Accounting Firm		63
Consolidated Balance Sheets		64
Consolidated Statements of Operations		66
Consolidated Statements of Changes in Shareholders' Equity		67
Consolidated Statements of Cash Flows		68
Notes to Consolidated Financial Statements		69
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm		89
Balance Sheets		90
Statements of Operations		92
Statements of Changes in Shareholder's Equity		93
Statements of Cash Flows		94
Notes to Financial Statements		95
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm		104
Consolidated Balance Sheets		105
Consolidated Statements of Operations		107
Consolidated Statements of Changes in Member's Equity		108
Consolidated Statements of Cash Flows		109
Notes to Consolidated Financial Statements		110
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		127
Consolidated Balance Sheets		128
Consolidated Statements of Operations		129
Consolidated Statements of Changes in Shareholder's Equity		130
Consolidated Statements of Cash Flows		131
Notes to Consolidated Financial Statements		132
Sierra Pacific Power Company
Report of Independent Registered Public Accounting Firm		147
Balance Sheets		148
Statements of Operations		149
Statements of Changes in Shareholder's Equity		150
Statements of Cash Flows		151
Notes to Financial Statements		152

1

---

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations

Berkshire Hathaway Energy Company and its subsidiaries		29
PacifiCorp and its subsidiaries		79
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company		114
Nevada Power Company and its subsidiaries		139
Sierra Pacific Power Company		160

2

---

Berkshire Hathaway Energy Company and its subsidiaries

Consolidated Financial Section

3

---

PART I

Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Berkshire Hathaway Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of September 30, 2020, the related consolidated statements of operations, comprehensive income and changes in equity for the three-month and nine-month periods ended September 30, 2020 and 2019, and of cash flows for the nine-month periods ended September 30, 2020 and 2019, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2019, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 21, 2020, we expressed an unqualified opinion on those consolidated financial statements and included an explanatory paragraph regarding changes in accounting principles. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2019, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of the Company's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

November 6, 2020

4

---

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,				December 31,
	2020				2019
ASSETS
Current assets:
Cash and cash equivalents	$	1,769			$	1,040
Restricted cash and cash equivalents	309				212
Trade receivables, net	2,120				1,910
Inventories	1,034				873
Mortgage loans held for sale	2,178				1,039
Amounts held in trust	472				211
Other current assets	915				628
Total current assets	8,797				5,913
Property, plant and equipment, net	75,252				73,305
Goodwill	9,667				9,722
Regulatory assets	2,728				2,766
Investments and restricted cash and cash equivalents and investments	10,603				6,255
Other assets	2,139				2,090
Total assets	$	109,186			$	100,051

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

5

---

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	September 30,				December 31,
	2020				2019
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,881			$	1,839
Accrued interest	579				493
Accrued property, income and other taxes	710				537
Accrued employee expenses	509				285
Short-term debt	2,400				3,214
Current portion of long-term debt	1,783				2,539
Other current liabilities	1,758				1,350
Total current liabilities	9,620				10,257
BHE senior debt	11,012				8,231
BHE junior subordinated debentures	100				100
Subsidiary debt	30,259				28,483
Regulatory liabilities	6,636				7,100
Deferred income taxes	10,839				9,653
Other long-term liabilities	3,851				3,649
Total liabilities	72,317				67,473
Commitments and contingencies (Note 9)
Equity:
BHE shareholders' equity:
Common stock - 115 shares authorized, no par value, 76 and 77 shares issued and outstanding	—				—
Additional paid-in capital	6,377				6,389
Long-term income tax receivable	(530		)		(530		)
Retained earnings	32,804				28,296
Accumulated other comprehensive loss, net	(1,883		)		(1,706		)
Total BHE shareholders' equity	36,768				32,449
Noncontrolling interests	101				129
Total equity	36,869				32,578
Total liabilities and equity	$	109,186			$	100,051

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

6

---

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Operating revenue:
Energy	$	4,451			$	4,337			$	11,504			$	11,729
Real estate	1,742				1,307				3,828				3,419
Total operating revenue	6,193				5,644				15,332				15,148
Operating expenses:
Energy:
Cost of sales	1,169				1,230				3,095				3,471
Operations and maintenance	1,033				845				2,564				2,469
Depreciation and amortization	789				795				2,323				2,243
Property and other taxes	152				130				456				427
Real estate	1,503				1,194				3,492				3,210
Total operating expenses	4,646				4,194				11,930				11,820
Operating income	1,547				1,450				3,402				3,328
Other income (expense):
Interest expense	(504		)		(475		)		(1,490		)		(1,428		)
Capitalized interest	24				23				60				56
Allowance for equity funds	50				56				122				126
Interest and dividend income	17				25				57				91
Gains (losses) on marketable securities, net	1,797				(234		)		2,407				(296		)
Other, net	36				2				61				67
Total other income (expense)	1,420				(603		)		1,217				(1,384		)
Income before income tax expense (benefit) and equity loss	2,967				847				4,619				1,944
Income tax expense (benefit)	80				(302		)		(111		)		(526		)
Equity loss	(41		)		(4		)		(91		)		(12		)
Net income	2,846				1,145				4,639				2,458
Net income attributable to noncontrolling interests	4				8				11				15
Net income attributable to BHE shareholders	$	2,842			$	1,137			$	4,628			$	2,443

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

 

7

---

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Net income	$	2,846			$	1,145			$	4,639			$	2,458
Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $(3), $(4), $10, and $(6)	(6		)		(26		)		38				(40		)
Foreign currency translation adjustment	244				(172		)		(195		)		(66		)
Unrealized gains (losses) on cash flow hedges, net of tax of $2, $3, $(5), and $(8)	4				7				(20		)		(28		)
Total other comprehensive income (loss), net of tax	242				(191		)		(177		)		(134		)
Comprehensive income	3,088				954				4,462				2,324
Comprehensive income attributable to noncontrolling interests	4				8				11				15
Comprehensive income attributable to BHE shareholders	$	3,084			$	946			$	4,451			$	2,309

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

8

---

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(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, June 30, 2019	77			$	—			$	6,355			$	(457	)		$	26,651			$	(1,888	)		$	126			$	30,787
Net income	—			—				—				—				1,137				—				7				1,144
Other comprehensive loss	—			—				—				—				—				(191		)		—				(191		)
Distributions	—			—				—				—				—				—				(6		)		(6		)
Other equity transactions	—			—				—				—				1				—				5				6
Balance, September 30, 2019	77			$	—			$	6,355			$	(457	)		$	27,789			$	(2,079	)		$	132			$	31,740
Balance, December 31, 2018	77			$	—			$	6,371			$	(457	)		$	25,624			$	(1,945	)		$	130			$	29,723
Net income	—			—				—				—				2,443				—				14				2,457
Other comprehensive loss	—			—				—				—				—				(134		)		—				(134		)
Common stock repurchases	—			—				(16		)		—				(277		)		—				—				(293		)
Distributions	—			—				—				—				—				—				(16		)		(16		)
Other equity transactions	—			—				—				—				(1		)		—				4				3
Balance, September 30, 2019	77			$	—			$	6,355			$	(457	)		$	27,789			$	(2,079	)		$	132			$	31,740
Balance, June 30, 2020	76			$	—			$	6,377			$	(530	)		$	29,962			$	(2,125	)		$	101			$	33,785
Net income	—			—				—				—				2,842				—				3				2,845
Other comprehensive income	—			—				—				—				—				242				—				242
Distributions	—			—				—				—				—				—				(4		)		(4		)
Other equity transactions	—			—				—				—				—				—				1				1
Balance, September 30, 2020	76			$	—			$	6,377			$	(530	)		$	32,804			$	(1,883	)		$	101			$	36,869
Balance, December 31, 2019	77			$	—			$	6,389			$	(530	)		$	28,296			$	(1,706	)		$	129			$	32,578
Net income	—			—				—				—				4,628				—				10				4,638
Other comprehensive loss	—			—				—				—				—				(177		)		—				(177		)
Common stock repurchases	(1	)		—				(6		)		—				(120		)		—				—				(126		)
Distributions	—			—				—				—				—				—				(11		)		(11		)
Purchase of noncontrolling interest	—			—				(5		)		—				—				—				(28		)		(33		)
Other equity transactions	—			—				(1		)		—				—				—				1				—
Balance, September 30, 2020	76			$	—			$	6,377			$	(530	)		$	32,804			$	(1,883	)		$	101			$	36,869

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

9

---

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2020				2019
Cash flows from operating activities:
Net income	$	4,639			$	2,458
Adjustments to reconcile net income to net cash flows from operating activities:
(Gains) losses on marketable securities, net	(2,407		)		296
Depreciation and amortization	2,357				2,278
Allowance for equity funds	(122		)		(126		)
Equity loss, net of distributions	146				43
Changes in regulatory assets and liabilities	(87		)		108
Deferred income taxes and amortization of investment tax credits	791				(92		)
Other, net	(6		)		44
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(1,668		)		(594		)
Derivative collateral, net	53				(19		)
Pension and other postretirement benefit plans	(69		)		(40		)
Accrued property, income and other taxes, net	97				195
Accounts payable and other liabilities	796				109
Net cash flows from operating activities	4,520				4,660
Cash flows from investing activities:
Capital expenditures	(4,607		)		(4,898		)
Acquisitions, net of cash acquired	—				(28		)
Purchases of marketable securities	(322		)		(242		)
Proceeds from sales of marketable securities	308				223
Equity method investments	(2,062		)		(1,144		)
Other, net	50				54
Net cash flows from investing activities	(6,633		)		(6,035		)
Cash flows from financing activities:
Proceeds from BHE senior debt	3,231				—
Repayments of BHE senior debt	(350		)		—
Common stock purchases	(126		)		(293		)
Proceeds from subsidiary debt	2,648				3,463
Repayments of subsidiary debt	(1,558		)		(1,821		)
Net (repayments of) proceeds from short-term debt	(815		)		594
Purchase of noncontrolling interest	(33		)		—
Other, net	(60		)		(42		)
Net cash flows from financing activities	2,937				1,901
Effect of exchange rate changes	4				(3		)
Net change in cash and cash equivalents and restricted cash and cash equivalents	828				523
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	1,268				883
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	2,096			$	1,406

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

10

---

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)	General

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 primarily 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 (which primarily consists of BHE Renewables, LLC and CalEnergy Philippines) 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.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2020 and for the three- and nine-month periods ended September 30, 2020 and 2019. The results of operations for the three- and nine-month periods ended September 30, 2020 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2019 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2020.

Coronavirus Disease 2019 ("COVID-19")

In March 2020, COVID-19 was declared a global pandemic and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and on worldwide economic conditions. COVID-19 has impacted many of the Company's customers ranging from high unemployment levels, an inability to pay bills and business closures or operating at reduced capacity levels. While COVID-19 has impacted the Company's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. These impacts include, but are not limited to, lower operating revenue and higher bad debt expense. The duration and extent of COVID-19 and its future impact on the Company's businesses cannot be reasonably estimated at this time. Accordingly, significant estimates used in the preparation of the Company's unaudited Consolidated Financial Statements, including those associated with evaluations of certain long-lived assets, goodwill and other intangible assets for impairment, expected credit losses on amounts owed to the Company and potential regulatory deferral or recovery of certain costs may be subject to significant adjustments in future periods.

11

---

(2)	Business Acquisition

On November 1, 2020, BHE completed its acquisition of substantially all of the natural gas transmission and storage business of Dominion Energy, Inc. ("DEI") and Dominion Energy Questar Corporation ("Dominion Questar"), exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "Questar Pipeline Group") (the "GT&S Transaction"). Under the terms of the Purchase and Sale Agreement, dated July 3, 2020 (the "GT&S Purchase Agreement"), BHE paid approximately $2.7 billion in cash (the "GT&S Cash Consideration"), subject to adjustment for cash and indebtedness as of closing, and assumed approximately $5.3 billion of existing indebtedness for borrowed money for 100% of the equity interests of Eastern Gas Transmission and Storage, Inc. (formerly known as Dominion Energy Transmission, Inc.) and Carolina Gas Transmission, LLC (formerly known as Dominion Energy Carolina Gas Transmission, LLC); 50% of the equity interests of Iroquois Gas Transmission System L.P.; and a 25% economic interest in Cove Point LNG, LP ("Cove Point") (formerly known as Dominion Energy Cove Point LNG, LP ), consisting of 100% of the general partnership interest and 25% of the total limited partnership interests. BHE became the operator of Cove Point after the GT&S Transaction. The GT&S Transaction received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended ("HSR Approval") in October 2020, and approval by the Department of Energy with respect to a change in control of Cove Point and the Federal Communications Commission with respect to the transfer of certain licenses earlier in 2020.

On October 5, 2020, DEI and Dominion Questar, as permitted under the terms of the GT&S Purchase Agreement, delivered notice to BHE of their election to terminate the GT&S Transaction with respect to the Questar Pipeline Group and, in connection with the execution of the Q-Pipe Purchase Agreement referenced below, to waive the related termination fee under the GT&S Purchase Agreement. Also on October 5, 2020, BHE entered into a second Purchase and Sale Agreement (the "Q-Pipe Purchase Agreement") with Dominion Questar providing for BHE's purchase of the Questar Pipeline Group from Dominion Questar (the "Q-Pipe Transaction") after receipt of HSR Approval, which is currently anticipated in early 2021, for a cash purchase price of approximately $1.3 billion (the "Q-Pipe Cash Consideration"), subject to adjustment for cash and indebtedness as of the closing, and the assumption of approximately $430 million of existing indebtedness for borrowed money. DEI is also a party to the Q-Pipe Purchase Agreement, as guarantor for certain provisions regarding the Purchase Price Repayment Amount (as defined below) and other matters.

Under the Q-Pipe Purchase Agreement, BHE delivered the Q-Pipe Cash Consideration to Dominion Questar on November 2, 2020. If the Q-Pipe Transaction does not close, Dominion Questar has agreed to repay all or (depending on the repayment date) substantially all of the Q-Pipe Cash Consideration (the "Purchase Price Repayment Amount") to BHE on or prior to December 31, 2021. If HSR Approval has not been obtained by June 30, 2021, upon BHE's written request, Dominion Questar will seek alternative buyers for all or a material portion of the Questar Pipeline Group (an "Alternative Transaction"). The Purchase Price Repayment Amount may be paid in cash or in shares of common stock, no par value, of DEI, or a combination thereof, subject to certain limitations as to stock repayments set forth in the Q-Pipe Purchase Agreement; provided any payment on or after December 15, 2021 must be paid in cash only.

The assets acquired in the GT&S Transaction include over 5,700 miles of operational natural gas transmission lines, with approximately 13.9 billion cubic feet ("Bcf") per day of transportation capacity and 733 Bcf of operated natural gas storage with 299 Bcf of company-owned working storage capacity, and a liquefied natural gas ("LNG") export, import and storage facility, with LNG storage of 14.6 Bcf.

On October 29, 2020, BHE issued $3.75 billion of its 4.00% Perpetual Preferred Stock (the "Perpetual Preferred") to certain subsidiaries of Berkshire Hathaway Inc. in order to fund the GT&S Cash Consideration and the Q-Pipe Cash Consideration. Under the terms of the Perpetual Preferred, BHE is permitted to redeem such Perpetual Preferred at par at any time.

12

---

(3)	Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):

			As of
	Depreciable		September 30,				December 31,
	Life		2020				2019
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years		$	82,743			$	81,127
Interstate natural gas pipeline assets	3-80 years		8,281				8,165
			91,024				89,292
Accumulated depreciation and amortization			(27,401		)		(26,353		)
Regulated assets, net			63,623				62,939
Nonregulated assets:
Independent power plants	5-30 years		7,002				6,983
Other assets	3-30 years		1,950				1,834
			8,952				8,817
Accumulated depreciation and amortization			(2,455		)		(2,183		)
Nonregulated assets, net			6,497				6,634
Net operating assets			70,120				69,573
Construction work-in-progress			5,132				3,732
Property, plant and equipment, net			$	75,252			$	73,305

Construction work-in-progress includes $5.0 billion as of September 30, 2020 and $3.6 billion as of December 31, 2019, related to the construction of regulated assets.

13

---

(4)	Investments and Restricted Cash and Cash Equivalents and Investments

Investments and restricted cash and cash equivalents and investments consists of the following (in millions):

	As of
	September 30,				December 31,
	2020				2019
Investments:
BYD Company Limited common stock	$	3,525			$	1,122
Rabbi trusts	412				410
Other	205				187
Total investments	4,142				1,719
Equity method investments:
BHE Renewables tax equity investments	5,000				3,130
Electric Transmission Texas, LLC	597				555
Bridger Coal Company	78				81
Other	168				181
Total equity method investments	5,843				3,947
Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds	631				599
Other restricted cash and cash equivalents	327				230
Total restricted cash and cash equivalents and investments	958				829
Total investments and restricted cash and cash equivalents and investments	$	10,943			$	6,495
Reflected as:
Current assets	$	340			$	240
Noncurrent assets	10,603				6,255
Total investments and restricted cash and cash equivalents and investments	$	10,943			$	6,495

Investments

Gains (losses) on marketable securities, net recognized during the period consists of the following (in millions):

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Unrealized gains (losses) recognized on marketable securities still held at the reporting date	$	1,794			$	(236	)		$	2,403			$	(297	)
Net gains recognized on marketable securities sold during the period	3				2				4				1
Gains (losses) on marketable securities, net	$	1,797			$	(234	)		$	2,407			$	(296	)

14

---

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 September 30, 2020 and December 31, 2019, 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 September 30, 2020 and December 31, 2019, 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
	September 30,				December 31,
	2020				2019
Cash and cash equivalents	$	1,769			$	1,040
Restricted cash and cash equivalents	309				212
Investments and restricted cash and cash equivalents and investments	18				16
Total cash and cash equivalents and restricted cash and cash equivalents	$	2,096			$	1,268

(5)	Recent Financing Transactions

Long-Term Debt

In October 2020, BHE issued $500 million of its 1.650% Senior Notes due 2031 and $1.5 billion of its 2.850% Senior Notes due 2051. BHE intends to use the net proceeds to repay approximately $1.2 billion of debt at Eastern Energy Gas Holdings, LLC (formerly known as Dominion Energy Gas Holdings, LLC) as it matures over the months following the GT&S Transaction, to fund its commitments under certain tax equity investments in third party sponsored renewable energy projects and for general corporate purposes.

In September 2020, AltaLink, L.P. issued C$225 million of its 1.509% Senior Secured Notes due 2030 and intends to use the net proceeds to repay or refinance a portion of its short-term indebtedness and for general corporate purposes.

In June 2020, Northern Powergrid (Northeast) plc issued £300 million of its 1.875% Green Bonds due 2062 and intends to use the net proceeds to finance and refinance eligible green projects in certain categories within Northern Powergrid's green project portfolio.

In April 2020, PacifiCorp issued $400 million of its 2.70% First Mortgage Bonds due 2030 and $600 million of its 3.30% First Mortgage Bonds due 2051. PacifiCorp intends to use the net proceeds to fund capital expenditures, primarily for renewable resources and associated transmission projects, and for general corporate purposes.

In March 2020, BHE issued $1.25 billion of its 4.05% Senior Notes due 2025, $1.1 billion of its 3.70% Senior Notes due 2030 and $900 million of its 4.25% Senior Notes due 2050. BHE used the net proceeds to refinance a portion of the Company's short-term indebtedness and for general corporate purposes.

In January 2020, Nevada Power issued $425 million of its 2.40% General and Refunding Mortgage Notes, Series DD, due 2030 and $300 million of its 3.125% General and Refunding Mortgage Notes, Series EE, due 2050. Nevada Power used the net proceeds for the early redemption of $575 million of its 2.75% General and Refunding Mortgage Notes, Series BB, due April 2020 and for general corporate purposes.

In January 2020, Pinyon Pines I and II issued $382 million of fifteen year variable-rate term loans due 2034 with a portion of the proceeds used to repay $284 million of existing variable-rate term loans due April 2020. 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. The variable interest rate as of September 30, 2020 was 1.77% while the fixed interest rate as of September 30, 2020 was 3.23%.

15

---

Credit Facilities

In May 2020, MidAmerican Energy terminated its $400 million unsecured credit facility expiring August 2020 and entered into a $600 million unsecured credit facility, which expires May 2021, with an option to extend for up to three months, and has a variable rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread. The facility requires that MidAmerican Energy's ratio of consolidated debt to total capitalization not exceed 0.65 to 1.0 as of the last day of any quarter.

In April 2020, AltaLink entered into a C$100 million revolving credit facility expiring April 2021 with a recurring one-year extension option subject to lender consent. The credit facility requires that AltaLink's ratio of consolidated debt to total capitalization not exceed 0.75 to 1.0 as of the last day of each quarter.

In April 2020, AltaLink Investments, L.P. entered into a C$200 million revolving term credit facility expiring April 2021 with a recurring one-year extension option subject to lender consent. The credit facility requires that AltaLink Investments, L.P.'s ratio of consolidated debt to total capitalization not exceed 0.80 to 1.0 as of the last day of each quarter.

(6)	Income Taxes

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax benefit is as follows:

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2020			2019			2020			2019
Federal statutory income tax rate	21	%		21	%		21	%		21	%
Income tax credits	(20	)		(43	)		(23	)		(35	)
State income tax, net of federal income tax benefit	3			(3	)		2			(6	)
Income tax effect of foreign income	1			(1	)		—			(2	)
Effects of ratemaking	(2	)		(9	)		(2	)		(5	)
Other, net	—			(1	)		—			—
Effective income tax rate	3	%		(36	)%		(2	)%		(27	)%

Income tax credits relate primarily to production tax credits ("PTCs") 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.

Income tax effect on foreign income includes, among other items, a deferred income tax charge of $35 million in 2020 related to the United Kingdom's corporate income tax rate that was scheduled to decrease from 19% to 17% effective April 1, 2020; however, the rate was maintained at 19% through amended legislation enacted in July 2020.

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. For the nine-month periods ended September 30, 2020 and 2019, the Company received net cash payments for federal income taxes from Berkshire Hathaway totaling $1.0 billion and $534 million, respectively.

16

---

(7)	Employee Benefit Plans

Domestic Operations

Net periodic benefit cost (credit) for the domestic pension and other postretirement benefit plans included the following components (in millions):

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Pension:
Service cost	$	4			$	4			$	11			$	12
Interest cost	23				27				69				82
Expected return on plan assets	(35		)		(38		)		(105		)		(115		)
Net amortization	8				8				25				24
Net periodic benefit cost	$	—			$	1			$	—			$	3
Other postretirement:
Service cost	$	1			$	1			$	5			$	6
Interest cost	6				6				16				20
Expected return on plan assets	(9		)		(10		)		(25		)		(30		)
Net amortization	(1		)		—				(5		)		(3		)
Net periodic benefit credit	$	(3	)		$	(3	)		$	(9	)		$	(7	)

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $13 million and $1 million, respectively, during 2020. As of September 30, 2020, $9 million and $1 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

Foreign Operations

Net periodic benefit (credit) cost for the United Kingdom pension plan included the following components (in millions):

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Service cost	$	4			$	3			$	12			$	11
Interest cost	10				13				30				39
Expected return on plan assets	(26		)		(24		)		(76		)		(74		)
Settlement	—				21				—				21
Net amortization	11				9				32				27
Net periodic benefit (credit) cost	$	(1	)		$	22			$	(2	)		$	24

Amounts other than the service cost for the United Kingdom pension plan are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the United Kingdom pension plan are expected to be £43 million during 2020. As of September 30, 2020, £32 million, or $41 million, of contributions had been made to the United Kingdom pension plan.

17

---

(8)	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 financial 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 September 30, 2020
Assets:
Commodity derivatives		$	2			$	98			$	107			$	(35	)		$	172
Interest rate derivatives		—				1				88				—				89
Mortgage loans held for sale		—				2,178				—				—				2,178
Money market mutual funds(2)		1,493				—				—				—				1,493
Debt securities:
United States government obligations		186				—				—				—				186
International government obligations		—				5				—				—				5
Corporate obligations		—				75				—				—				75
Municipal obligations		—				4				—				—				4
Agency, asset and mortgage-backed obligations		—				5				—				—				5
Equity securities:
United States companies		347				—				—				—				347
International companies		3,533				—				—				—				3,533
Investment funds		202				—				—				—				202
		$	5,763			$	2,366			$	195			$	(35	)		$	8,289
Liabilities:
Commodity derivatives		$	—			$	(106	)		$	(11	)		$	69			$	(48	)
Interest rate derivatives		(5		)		(56		)		—				—				(61		)
		$	(5	)		$	(162	)		$	(11	)		$	69			$	(109	)

18

---

		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	)

(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $34 million and $79 million as of September 30, 2020 and December 31, 2019, respectively.

(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.

19

---

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 (in millions):

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
					Interest								Interest
	Commodity				Rate				Commodity				Rate
	Derivatives				Derivatives				Derivatives				Derivatives
2020:
Beginning balance	$	44			$	78			$	97			$	14
Changes included in earnings	(7		)		243				(11		)		579
Changes in fair value recognized in net regulatory assets	20				—				(36		)		—
Purchases	1				—				4				—
Settlements	38				(233		)		42				(505		)
Ending balance	$	96			$	88			$	96			$	88

2019:
Beginning balance	$	86			$	23			$	99			$	10
Changes included in earnings	1				158				6				305
Changes in fair value recognized in OCI	—				—				(1		)		—
Changes in fair value recognized in net regulatory assets	(17		)		—				(40		)		—
Purchases	—				—				4				—
Settlements	8				(161		)		10				(295		)
Ending balance	$	78			$	20			$	78			$	20

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 Balance Sheets. 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 (in millions):

	As of September 30, 2020								As of December 31, 2019
	Carrying				Fair				Carrying				Fair
	Value				Value				Value				Value
Long-term debt	$	43,154			$	53,008			$	39,353			$	46,004

(9)	Commitments and Contingencies

Construction Commitments

During the nine-month period ended September 30, 2020, MidAmerican Energy entered into firm construction commitments totaling $274 million for the remainder of 2020 through 2021, substantially related to the construction of wind-powered generating facilities in Iowa.

Easements

During the nine-month period ended September 30, 2020, MidAmerican Energy entered into non-cancelable easements with minimum payment commitments totaling $102 million through 2060 for land in Iowa on which some of its wind-powered generating facilities will be located.

20

---

Maintenance and Service Contracts

During the nine-month period ended September 30, 2020, MidAmerican Energy entered into non-cancelable maintenance and service contracts related to wind-powered generating facilities with minimum payment commitments totaling $75 million through 2031.

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 Solar Farm LLC ("Topaz") and owns a 49% interest in Agua Caliente Solar, LLC ("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 ("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. 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.

PG&E paid in full all amounts invoiced to date for post-petition energy deliveries for both Topaz and Agua Caliente as well as for the power delivered from January 1 through January 28, 2019. The PG&E Bankruptcy Filing was an event of default under the Topaz PPA ("PPA Default"); however, the Company maintained 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 had occurred under the Topaz indenture. On July 1, 2020, PG&E announced it had emerged from bankruptcy, successfully completing its restructuring process and implementing PG&E's Plan of Reorganization (the "Plan") that was confirmed by the United States Bankruptcy Court on June 20, 2020. The Company believes that no impairment exists and that current debt obligations will be met, as PG&E's emergence from bankruptcy has cured the PPA Default and PG&E's Plan includes the assumption of both the Topaz and Agua Caliente PPAs. The Company began receiving distributions from Topaz and Agua Caliente in the second half of 2020 in accordance with the provisions of each respective debt agreement.

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. The Company 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 and are described below.

    

California and Oregon 2020 Wildfires

In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damage, personal injuries and loss of life and widespread power outages in Oregon and California (the "2020 Wildfires"). The wildfires have spread across certain parts of PacifiCorp's service territory and surrounding areas in Oregon and California. Certain of the wildfires are still burning and are at various levels of containment. Investigations into the cause and origin of each wildfire are complex and ongoing. Although those investigations are not complete, several civil actions (including a putative class action complaint) have been filed in Oregon on behalf of citizens and businesses who suffered damages from fires allegedly caused by PacifiCorp. The final determinations of liability, however, will only be made following comprehensive investigations and litigation processes. In California, under the doctrine of inverse condemnation, courts have held investor-owned utilities liable for property damages along with associated interest and attorneys' fees where its facilities are a substantial cause of a wildfire that caused the property damage, even if the utility is not at fault. To date, no lawsuits arising from the 2020 Wildfires have been filed in California. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its equipment. Even if inverse condemnation or other provisions do not apply, PacifiCorp could nevertheless be found liable for all damages proximately caused by negligence, including property damage, fire suppression costs, personal injury damages and interest.

21

---

PacifiCorp has accrued its best estimate of the potential losses associated with the 2020 Wildfires that are considered probable of being incurred. Given the early stages of the investigations into the cause and origin of the 2020 Wildfires and the uncertainty surrounding potential damages, it is reasonably possible PacifiCorp may incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred. PacifiCorp has some level of insurance coverage that may apply to damages caused by wildfires, but it may be insufficient to cover all such damages. PacifiCorp has accrued its best estimate of the expected probable insurance recovery associated with the estimated losses accrued.

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.

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. The FERC approved partial transfer of the Klamath license in July 2020, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and its customers. The order does not immediately take effect and PacifiCorp is working with its settlement partners to implement the agreement.

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.

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.

22

---

(10)	Revenue from Contracts with Customers

Energy Products and Services

The following table summarizes the Company's energy products and services revenue from contracts with customers ("Customer Revenue") by regulated energy and nonregulated energy, with further disaggregation of regulated energy by line of business, including a reconciliation to the Company's reportable segment information included in Note 13 (in millions):

		For the Three-Month Period Ended September 30, 2020
		PacifiCorp				MidAmerican Funding				NV Energy				Northern Powergrid				BHE Pipeline Group				BHE Transmission				BHE Renewables				BHE and Other(1)				Total
Customer Revenue:
Regulated:
Retail electric		$	1,344			$	661			$	977			$	—			$	—			$	—			$	—			$	(1	)		$	2,981
Retail gas		—				70				14				—				—				—				—				—				84
Wholesale		59				56				14				—				—				—				—				1				130
Transmission and    distribution		33				15				30				208				—				169				—				—				455
Interstate pipeline		—				—				—				—				264				—				—				(29		)		235
Other		42				—				—				—				—				—				—				—				42
Total Regulated		1,478				802				1,035				208				264				169				—				(29		)		3,927
Nonregulated		—				4				(1		)		6				—				6				270				145				430
Total Customer Revenue		1,478				806				1,034				214				264				175				270				116				4,357
Other revenue		1				6				8				32				—				—				39				8				94
Total		$	1,479			$	812			$	1,042			$	246			$	264			$	175			$	309			$	124			$	4,451

		For the Nine-Month Period Ended September 30, 2020
		PacifiCorp				MidAmerican Funding				NV Energy				Northern Powergrid				BHE Pipeline Group				BHE Transmission				BHE Renewables				BHE and Other(1)				Total
Customer Revenue:
Regulated:
Retail electric		$	3,532			$	1,539			$	2,144			$	—			$	—			$	—			$	—			$	(1	)		$	7,214
Retail gas		—				341				81				—				—				—				—				—				422
Wholesale		76				157				34				—				—				—				—				(1		)		266
Transmission and    distribution		79				48				75				632				—				502				—				—				1,336
Interstate pipeline		—				—				—				—				885				—				—				(103		)		782
Other		88				—				1				—				—				—				—				—				89
Total Regulated		3,775				2,085				2,335				632				885				502				—				(105		)		10,109
Nonregulated		—				13				1				18				—				14				641				394				1,081
Total Customer Revenue		3,775				2,098				2,336				650				885				516				641				289				11,190
Other revenue		54				16				23				83				5				—				90				43				314
Total		$	3,829			$	2,114			$	2,359			$	733			$	890			$	516			$	731			$	332			$	11,504

23

---

		For the Three-Month Period Ended September 30, 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		$	1,320			$	651			$	998			$	—			$	—			$	—			$	—			$	(1	)		$	2,968
Retail gas		—				61				16				—				—				—				—				—				77
Wholesale		8				56				6				—				—				—				—				(1		)		69
Transmission and    distribution		26				16				27				195				—				179				—				—				443
Interstate pipeline		—				—				—				—				221				—				—				(25		)		196
Other		—				—				—				—				—				—				—				—				—
Total Regulated		1,354				784				1,047				195				221				179				—				(27		)		3,753
Nonregulated		—				9				—				9				—				5				276				161				460
Total Customer Revenue		1,354				793				1,047				204				221				184				276				134				4,213
Other revenue		13				4				7				26				5				—				53				16				124
Total		$	1,367			$	797			$	1,054			$	230			$	226			$	184			$	329			$	150			$	4,337

		For the Nine-Month Period Ended September 30, 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		$	3,613			$	1,561			$	2,183			$	—			$	—			$	—			$	—			$	(1	)		$	7,356
Retail gas		—				416				74				—				—				—				—				—				490
Wholesale		47				232				34				—				—				—				—				(2		)		311
Transmission and    distribution		76				47				75				634				—				514				—				—				1,346
Interstate pipeline		—				—				—				—				805				—				—				(86		)		719
Other		—				—				1				—				—				—				—				—				1
Total Regulated		3,736				2,256				2,367				634				805				514				—				(89		)		10,223
Nonregulated		—				25				—				27				—				13				599				442				1,106
Total Customer Revenue		3,736				2,281				2,367				661				805				527				599				353				11,329
Other revenue		57				18				22				75				4				—				146				78				400
Total		$	3,793			$	2,299			$	2,389			$	736			$	809			$	527			$	745			$	431			$	11,729

(1)	The BHE and Other reportable segment represents amounts related principally to other entities, corporate functions and intersegment eliminations.

24

---

Real Estate Services

The following table summarizes the Company's real estate services Customer Revenue by line of business (in millions):

	HomeServices
	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Customer Revenue:
Brokerage	$	1,449			$	1,172			$	3,183			$	3,087
Franchise	23				20				54				53
Total Customer Revenue	1,472				1,192				3,237				3,140
Other revenue	270				115				591				279
Total	$	1,742			$	1,307			$	3,828			$	3,419

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 September 30, 2020, by reportable segment (in millions):

	Performance obligations expected to be satisfied:
	Less than 12 months				More than 12 months				Total
BHE Pipeline Group	$	979			$	5,213			$	6,192
BHE Transmission	663				166				829
Total	$	1,642			$	5,379			$	7,021

(11)	BHE Shareholders' Equity

For the nine-month periods ended September 30, 2020 and 2019, BHE repurchased 180,358 shares of its common stock for $126 million and 447,712 shares of its common stock for $293 million, respectively.

(12)    Components of Other Comprehensive Income (Loss), Net

The following table shows the change in AOCI attributable to BHE shareholders by each component of OCI, net of applicable income tax (in millions):

		Unrecognized				Foreign				Unrealized				AOCI
		Amounts on				Currency				Gains (Losses)				Attributable
		Retirement				Translation				on Cash				To BHE
		Benefits				Adjustment				Flow Hedges				Shareholders, Net
Balance, December 31, 2018		$	(358	)		$	(1,623	)		$	36			$	(1,945	)
Other comprehensive loss		(40		)		(66		)		(28		)		(134		)
Balance, September 30, 2019		$	(398	)		$	(1,689	)		$	8			$	(2,079	)
Balance, December 31, 2019		$	(417	)		$	(1,296	)		$	7			$	(1,706	)
Other comprehensive income (loss)		38				(195		)		(20		)		(177		)
Balance, September 30, 2020		$	(379	)		$	(1,491	)		$	(13	)		$	(1,883	)

25

---

(13)	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):

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Operating revenue:
PacifiCorp	$	1,479			$	1,367			$	3,829			$	3,793
MidAmerican Funding	812				797				2,114				2,299
NV Energy	1,042				1,054				2,359				2,389
Northern Powergrid	246				230				733				736
BHE Pipeline Group	264				226				890				809
BHE Transmission	175				184				516				527
BHE Renewables	309				329				731				745
HomeServices	1,742				1,307				3,828				3,419
BHE and Other(1)	124				150				332				431
Total operating revenue	$	6,193			$	5,644			$	15,332			$	15,148

Depreciation and amortization:
PacifiCorp	$	234			$	272			$	696			$	686
MidAmerican Funding	179				184				530				540
NV Energy	128				121				377				361
Northern Powergrid	69				60				195				186
BHE Pipeline Group	45				28				134				85
BHE Transmission	61				59				176				177
BHE Renewables	72				71				214				210
HomeServices	11				11				34				35
BHE and Other(1)	1				—				1				(2		)
Total depreciation and amortization	$	800			$	806			$	2,357			$	2,278

26

---

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Operating income:
PacifiCorp	$	361			$	333			$	851			$	885
MidAmerican Funding	232				234				444				444
NV Energy	347				313				587				547
Northern Powergrid	106				98				327				337
BHE Pipeline Group	101				87				442				398
BHE Transmission	79				91				236				244
BHE Renewables	143				183				244				298
HomeServices	239				113				336				209
BHE and Other(1)	(61		)		(2		)		(65		)		(34		)
Total operating income	1,547				1,450				3,402				3,328
Interest expense	(504		)		(475		)		(1,490		)		(1,428		)
Capitalized interest	24				23				60				56
Allowance for equity funds	50				56				122				126
Interest and dividend income	17				25				57				91
Gains (losses) on marketable securities, net	1,797				(234		)		2,407				(296		)
Other, net	36				2				61				67
Total income before income tax expense (benefit) and equity loss	$	2,967			$	847			$	4,619			$	1,944

Interest expense:
PacifiCorp	$	107			$	101			$	319			$	299
MidAmerican Funding	79				74				238				223
NV Energy	56				55				171				173
Northern Powergrid	34				33				97				102
BHE Pipeline Group	15				14				44				38
BHE Transmission	38				40				111				118
BHE Renewables	41				44				125				132
HomeServices	1				6				9				20
BHE and Other(1)	133				108				376				323
Total interest expense	$	504			$	475			$	1,490			$	1,428

Operating revenue by country:
United States	$	5,773			$	5,222			$	14,086			$	13,875
United Kingdom	246				229				733				734
Canada	174				183				512				526
Philippines and other	—				10				1				13
Total operating revenue by country	$	6,193			$	5,644			$	15,332			$	15,148

Income before income tax expense (benefit) and equity loss by country:
United States	$	2,839			$	728			$	4,220			$	1,546
United Kingdom	82				49				250				228
Canada	44				55				130				134
Philippines and other	2				15				19				36
Total income before income tax expense (benefit) and equity loss by country	$	2,967			$	847			$	4,619			$	1,944

27

---

	As of
	September 30,				December 31,
	2020				2019
Assets:
PacifiCorp	$	26,686			$	24,861
MidAmerican Funding	23,372				22,664
NV Energy	14,705				14,128
Northern Powergrid	8,491				8,385
BHE Pipeline Group	6,313				6,100
BHE Transmission	8,799				8,776
BHE Renewables	11,630				9,961
HomeServices	5,366				3,846
BHE and Other(1)	3,824				1,330
Total assets	$	109,186			$	100,051

(1)	The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.

The following table shows the change in the carrying amount of goodwill by reportable segment for the nine-month period ended September 30, 2020 (in millions):

																	BHE Pipeline Group
	PacifiCorp				MidAmerican Funding				NV Energy				Northern Powergrid								BHE Transmission				BHE Renewables				HomeServices
																																	Total
December 31, 2019	$	1,129			$	2,102			$	2,369			$	978			$	73			$	1,520			$	95			$	1,456			$	9,722
Foreign currency translation	—				—				—				(18		)		—				(37		)		—				—				(55		)
September 30, 2020	$	1,129			$	2,102			$	2,369			$	960			$	73			$	1,483			$	95			$	1,456			$	9,667

28

---

Item 2.	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 unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. The Company's actual results in the future could differ significantly from the historical results.

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 primarily consists of Northern Natural Gas and Kern River), BHE Transmission (which consists of BHE Canada (which primarily consists of AltaLink) 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. 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 for the Third Quarter and First Nine Months of 2020 and 2019

Overview

Net income for the Company's reportable segments is summarized as follows (in millions):

	Third Quarter															First Nine Months
	2020				2019				Change							2020				2019				Change
Net income attributable to BHE shareholders:
PacifiCorp	$	286			$	278			$	8			3	%		$	629			$	626			$	3			—	%
MidAmerican Funding	337				279				58				21			695				622				73				12
NV Energy	249				206				43				21			367				316				51				16
Northern Powergrid	26				37				(11		)		(30	)		172				181				(9		)		(5	)
BHE Pipeline Group	78				66				12				18			321				295				26				9
BHE Transmission	58				65				(7		)		(11	)		173				172				1				1
BHE Renewables	162				167				(5		)		(3	)		395				335				60				18
HomeServices	177				82				95				*			246				150				96				64
BHE and Other	1,469				(43		)		1,512				*			1,630				(254		)		1,884				*
Total net income attributable to BHE shareholders	$	2,842			$	1,137			$	1,705			*			$	4,628			$	2,443			$	2,185			89	%

*    Not meaningful

Net income attributable to BHE shareholders increased $1,705 million for the third quarter of 2020 compared to 2019. The third quarter of 2020 included a pre-tax unrealized gain of $1,787 million ($1,299 million after-tax) compared to a pre-tax unrealized loss in the third quarter of 2019 of $234 million ($170 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted net income attributable to BHE shareholders for the third quarter of 2020 was $1,543 million, an increase of $236 million, or 18%, compared to adjusted net income attributable to BHE shareholders in the third quarter of 2019 of $1,307 million.

29

---

Net income attributable to BHE shareholders increased $2,185 million for the first nine months of 2020 compared to 2019. The first nine months of 2020 included a pre-tax unrealized gain of $2,402 million ($1,746 million after-tax) compared to a pre-tax unrealized loss in the first nine months of 2019 of $311 million ($226 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted net income attributable to BHE shareholders for the first nine months of 2020 was $2,882 million, an increase of $213 million, or 8%, compared to adjusted net income attributable to BHE shareholders in the first nine months of 2019 of $2,669 million.

The increase in net income attributable to BHE shareholders for the third quarter of 2020 compared to 2019 was due to the following:

•

PacifiCorp's net income increased $8 million, primarily due to higher utility margin of $50 million (excluding the favorable impact of the Oregon RAC settlement of $27 million offset by higher depreciation expense), higher PTCs recognized of $35 million due to repowered wind projects placed in-service and $11 million of higher allowances for equity and borrowed funds used during construction, partially offset by higher operations and maintenance expenses of $80 million, primarily due to costs associated with the KHSA and wildfires, and higher interest expense of $6 million. Utility margin increased due to higher wholesale revenue, price impacts from changes in sales mix, the impacts of retail customer volumes and lower coal-fueled generation costs, partially offset by lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms. Retail customer volumes were flat as the favorable impact of weather and an increase in the average number of customers were largely offset by the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage.

•

MidAmerican Funding's net income increased $58 million, primarily due to a higher income tax benefit of $68 million from higher PTCs recognized of $36 million, which were due to higher wind generation driven by repowering and new wind projects placed in-service in 2019, and from the favorable impacts of ratemaking, and higher electric utility margin of $11 million (excluding the impacts of higher energy efficiency program revenue of $3 million offset by higher operations and maintenance expenses), partially offset by higher operations and maintenance expenses from increased storm restoration costs from a 2020 event and wind projects placed in-service in 2019 and lower allowances for equity and borrowed funds used during construction of $13 million. Electric utility margin increased due to higher retail customer volumes and higher wholesale revenue, partially offset by higher generation and purchased power costs and price impacts from changes in sales mix. Electric retail customer volumes increased 2.3%, primarily due to increased usage for certain industrial customers, partially offset by the impacts of COVID-19, which resulted in lower commercial and industrial customer usage and higher residential customer usage.

•

NV Energy's net income increased $43 million, primarily due to higher electric utility margin of $68 million and lower income tax expense from the favorable impacts of ratemaking, partially offset by higher operations and maintenance expenses of $26 million, mainly from higher earnings sharing accruals at Nevada Power, and higher depreciation and amortization expense of $8 million from higher plant placed in-service. Electric utility margin increased due to a favorable regulatory decision, higher retail customer volumes and price impacts from changes in sales mix. Electric retail customer volumes, including distribution only service customers, increased 2.1%, primarily due to the favorable impact of weather, partially offset by the impacts of COVID-19, which resulted in lower distribution only service, commercial and industrial customer usage and higher residential customer usage.

•

Northern Powergrid's net income decreased $11 million, primarily due to higher income tax expense, partially offset by lower overall pension expense of $23 million, largely resulting from lower pension settlement costs in 2020 compared to 2019, and higher distribution revenue of $4 million from increased tariff rates offset by 5.4% lower units distributed largely due to the impacts of COVID-19. The United Kingdom's corporate income tax rate was scheduled to decrease from 19% to 17% effective April 1, 2020; however, the rate was maintained at 19% through amended legislation enacted in July 2020, which resulted in a deferred income tax charge of $35 million.

•	BHE Pipeline Group's net income increased $12 million, primarily due to higher transportation revenue of $17 million and a favorable, after-tax, rate case settlement at Northern Natural Gas of $9 million, partially offset by higher property and other tax expense of $13 million, including a non-recurring state property tax refund in 2019.

•	BHE Transmission's net income decreased $7 million, primarily due to favorable regulatory decisions received in August 2019 at AltaLink, partially offset by lower non-regulated interest expense at BHE Canada.

30

---

•

BHE Renewables' net income decreased $5 million, primarily due to lower hydro earnings of $8 million from lower rainfall, lower natural gas earnings of $7 million, primarily due to lower margins, and lower geothermal earnings of $6 million, primarily due to higher operations and maintenance expenses, partially offset by higher wind earnings of $18 million. Wind earnings were higher primarily due to favorable tax equity investment earnings of $22 million, which improved due to $28 million of earnings from projects reaching commercial operation, partially offset by lower commitment fee income of $8 million.

•	HomeServices' net income increased $95 million, primarily due to increased earnings at mortgage due to higher refinance activity from the favorable interest rate environment and higher earnings at brokerage due to a 13% increase in closed units from the delay in activity due to the impacts of COVID-19 during the first half of 2020.

•	BHE and Other's net loss improved $1,512 million, primarily due to the change in the after-tax unrealized position of the Company's investment in BYD Company Limited of $1,469 million and $96 million of higher federal income tax credits recognized on a consolidated basis, partially offset by higher operations and maintenance expenses and higher interest expense.

The increase in net income attributable to BHE shareholders for the first nine months of 2020 compared to 2019 was due to the following:

•

PacifiCorp's net income increased $3 million, primarily due higher PTCs recognized of $52 million due to repowered wind projects placed in-service, $32 million of higher allowances for equity and borrowed funds used during construction and higher utility margin of $16 million (excluding the favorable impact of the Oregon RAC settlement of $34 million offset by higher depreciation expense), partially offset by higher operations and maintenance expenses of $66 million, primarily due to costs associated with the KHSA and wildfires, higher interest expense of $20 million and higher pension and other postretirement costs of $10 million. Utility margin increased due to lower coal-fueled and natural gas-fueled generation costs and higher wholesale revenue, partially offset by lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms and unfavorable retail customer volumes. Retail customer volumes decreased 1.8% primarily due to the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by an increase in the average number of customers and the favorable impact of weather.

•

MidAmerican Funding's net income increased $73 million, primarily due to a higher income tax benefit of $128 million from higher PTCs recognized of $92 million, which were due to higher wind generation driven by repowering and new wind projects placed in-service in 2019, and the favorable impacts of ratemaking, higher electric utility margin of $7 million (excluding the impacts of lower energy efficiency program revenue of $30 million offset by lower operations and maintenance expenses) and lower depreciation and amortization expense of $9 million, partially offset by lower allowances for equity and borrowed funds used during construction of $34 million, higher interest expense of $15 million, lower cash surrender value of corporate-owned life insurance policies and lower natural gas utility margin of $7 million (excluding the impacts of lower energy efficiency program revenue of $13 million offset by lower operations and maintenance expenses). Electric utility margin increased due to higher retail customer volumes and lower generation and purchased power costs, partially offset by lower wholesale revenue and price impacts from changes in sales mix. Electric retail customer volumes increased 1.1%, primarily due to increased usage for certain industrial customers, partially offset by the impacts of COVID-19, which resulted in lower commercial and industrial customer usage and higher residential customer usage. Natural gas utility margin decreased due to 10.4% lower retail customer volumes primarily due to the unfavorable impact of weather.

•

NV Energy's net income increased $51 million, primarily due to higher electric utility margin of $80 million, lower pension and post-retirement costs of $8 million and lower income tax expense from the favorable impacts of ratemaking, partially offset by higher operations and maintenance expenses of $24 million, mainly from higher earnings sharing accruals at Nevada Power, and higher depreciation and amortization expense of $16 million from higher plant placed in-service. Electric utility margin increased due to higher retail customer volumes, price impacts from changes in sales mix and a favorable regulatory decision. Electric retail customer volumes, including distribution only service customers, increased 0.4%, primarily due to the favorable impact of weather, partially offset by the impacts of COVID-19, which resulted in lower industrial, distribution only service and commercial customer usage and higher residential customer usage.

31

---

•

Northern Powergrid's net income decreased $9 million, primarily due to higher income tax expense from the change in corporate income tax rate and higher distribution-related operating expenses, partially offset by lower overall pension expense of $27 million, largely resulting from lower pension settlement costs in 2020 compared to 2019, lower interest expense of $5 million and higher distribution revenue of $2 million from increased tariff rates offset by 6.5% lower units distributed largely due to the impacts of COVID-19.

•

BHE Pipeline Group's net income increased $26 million, primarily due to higher transportation revenue of $41 million and a favorable, after-tax, rate case settlement at Northern Natural Gas of $20 million, partially offset by higher property and other tax expense of $16 million, including a non-recurring state property tax refund in 2019, higher depreciation and amortization expense of $11 million, lower storage revenue of $5 million and higher interest expense of $4 million.

•

BHE Transmission's net income increased $1 million, primarily due to lower non-regulated interest expense at BHE Canada, higher net income at BHE U.S. Transmission of $5 million mainly due to improved equity earnings from the Electric Transmission Texas, LLC investment, and a favorable regulatory decision received in April 2020 at AltaLink, partially offset by favorable regulatory decisions received in August 2019 at AltaLink.

•

BHE Renewables' net income increased $60 million, primarily due to higher wind earnings of $96 million and higher solar earnings of $13 million due to lower operations and maintenance expenses, lower interest expense and higher generation, partially offset by lower geothermal earnings of $22 million, primarily due to higher operations and maintenance expenses, lower natural gas earnings of $16 million, primarily due to lower margins, and lower hydro earnings of $11 million from lower rainfall. Wind earnings were higher primarily due to favorable tax equity investment earnings of $94 million, which improved largely due to $101 million of earnings from projects reaching commercial operation, partially offset by lower commitment fee income of $15 million.

•	HomeServices' net income increased $96 million, primarily due to increased earnings at mortgage due to higher refinance activity from the favorable interest rate environment, partially offset by an unfavorable contingent earn-out remeasurement.

•

BHE and Other's net loss improved $1,884 million, primarily due to the change in the after-tax unrealized position of the Company's investment in BYD Company Limited of $1,972 million and $51 million of higher federal income tax credits recognized on a consolidated basis, partially offset by consolidated state income tax benefits recognized in 2019, higher interest expense, higher operations and maintenance expenses and lower cash surrender value of corporate-owned life insurance policies.

32

---

Reportable Segment Results

Operating revenue and operating income for the Company's reportable segments are summarized as follows (in millions):

	Third Quarter															First Nine Months
	2020				2019				Change							2020				2019				Change
Operating revenue:
PacifiCorp	$	1,479			$	1,367			$	112			8	%		$	3,829			$	3,793			$	36			1	%
MidAmerican Funding	812				797				15				2			2,114				2,299				(185		)		(8	)
NV Energy	1,042				1,054				(12		)		(1	)		2,359				2,389				(30		)		(1	)
Northern Powergrid	246				230				16				7			733				736				(3		)		—
BHE Pipeline Group	264				226				38				17			890				809				81				10
BHE Transmission	175				184				(9		)		(5	)		516				527				(11		)		(2	)
BHE Renewables	309				329				(20		)		(6	)		731				745				(14		)		(2	)
HomeServices	1,742				1,307				435				33			3,828				3,419				409				12
BHE and Other	124				150				(26		)		(17	)		332				431				(99		)		(23	)
Total operating revenue	$	6,193			$	5,644			$	549			10	%		$	15,332			$	15,148			$	184			1	%

 

Operating income:
PacifiCorp	$	361			$	333			$	28			8	%		$	851			$	885			$	(34	)		(4	)%
MidAmerican Funding	232				234				(2		)		(1	)		444				444				—				—
NV Energy	347				313				34				11			587				547				40				7
Northern Powergrid	106				98				8				8			327				337				(10		)		(3	)
BHE Pipeline Group	101				87				14				16			442				398				44				11
BHE Transmission	79				91				(12		)		(13	)		236				244				(8		)		(3	)
BHE Renewables	143				183				(40		)		(22	)		244				298				(54		)		(18	)
HomeServices	239				113				126				*			336				209				127				61
BHE and Other	(61		)		(2		)		(59		)		*			(65		)		(34		)		(31		)		91
Total operating income	$	1,547			$	1,450			$	97			7	%		$	3,402			$	3,328			$	74			2	%

*    Not meaningful

PacifiCorp

Operating revenue increased $112 million for the third quarter of 2020 compared to 2019 due to higher wholesale and other revenue of $73 million and higher retail revenue of $39 million. Wholesale and other revenue increased primarily due to higher wholesale prices and $27 million from the Oregon RAC settlement (offset in depreciation expense). Retail revenue increased due to price impacts of $22 million from changes in sales mix and the impacts of retail customer volumes. Retail customer volumes were flat as the favorable impact of weather and an increase in the average number of customers were largely offset by the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage.

Operating income increased $28 million for the third quarter of 2020 compared to 2019, primarily due to higher utility margin of $50 million (excluding the impacts of the Oregon RAC settlement) and lower depreciation and amortization of $38 million, partially offset by higher operations and maintenance expenses of $80 million, primarily due to costs associated with the KHSA and wildfires. The decrease in depreciation and amortization expense reflects accelerated depreciation totaling $65 million (offset in income tax expense) of Oregon's share of certain retired wind equipment from the Oregon RAC settlement due to repowering projects that were placed in-service in 2019 compared to $27 million (offset in other revenue) due to repowering projects that were placed in-service in 2020. Utility margin increased primarily due to higher wholesale revenue, price impacts from changes in sales mix, the impacts of retail customer volumes and lower coal-fueled generation costs, partially offset by lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms.

33

---

Operating revenue increased $36 million for the first nine months of 2020 compared to 2019 due higher wholesale and other revenue of $63 million, partially offset by lower retail revenue of $27 million. Wholesale and other revenue increased primarily due to higher wholesale prices and $34 million from the Oregon RAC settlement (offset in depreciation expense), partially offset by lower wholesale volumes. Retail revenue decreased due to unfavorable retail customer volumes of $33 million, partially offset by favorable price impacts of $6 million from changes in sales mix. Retail customer volumes decreased 1.8% primarily due to the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by an increase in the average number of customers and the favorable impact of weather.

Operating income decreased $34 million for the first nine months of 2020 compared to 2019, primarily due to higher operations and maintenance expenses of $66 million, primarily due to costs associated with the KHSA and wildfires, and higher depreciation and amortization expense of $10 million, partially offset by an increase in utility margin of $16 million (excluding the impacts of the Oregon RAC settlement). The increase in depreciation and amortization expense reflects accelerated depreciation totaling $74 million ($34 million offset in other revenue and $40 million offset in income tax expense) of Oregon's share of certain retired wind equipment from the Oregon RAC settlement due to repowering projects that were placed in-service in 2020 compared to $65 million (offset in income tax expense) due to repowering projects that were placed in-service in 2019. Utility margin increased $16 million (excluding the impacts of the Oregon RAC settlement) primarily due to lower coal-fueled and natural gas-fueled generation costs and higher wholesale revenue, partially offset by lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms and unfavorable retail customer volumes.

MidAmerican Funding

Operating revenue increased $15 million for the third quarter of 2020 compared to 2019, primarily due to higher electric operating revenue of $13 million and higher electric and natural gas energy efficiency program revenue of $6 million (offset in operations and maintenance expense), partially offset by lower other revenue of $5 million, primarily from nonregulated utility construction services. Electric operating revenue increased due to higher retail revenue of $11 million and higher wholesale and other revenue of $2 million. Electric retail revenue increased primarily due to higher retail customer usage of $14 million, partially offset by price impacts of $4 million from changes in sales mix. Electric retail customer volumes increased 2.3%, primarily due to increased usage for certain industrial customers, partially offset by the impacts of COVID-19, which resulted in lower commercial and industrial customer usage and higher residential customer usage. Electric wholesale and other revenue increased due to higher wholesale volumes, partially offset by lower average wholesale per-unit prices.

Operating income decreased $2 million for the third quarter of 2020 compared to 2019, primarily due to higher operations and maintenance expenses not recovered through energy efficiency programs, partially offset by higher electric utility margin of $11 million (excluding $3 million of higher energy efficiency program revenue) and lower depreciation and amortization expense. Operations and maintenance expenses increased mainly due to higher storm restoration expenses related to an intense storm in the third quarter of 2020 and higher wind-powered generation costs due to new and repowered generating facilities, partially offset by lower natural gas and electric distribution costs and lower fossil-fueled generating facility maintenance. Electric utility margin increased primarily due to higher retail customer volumes and higher wholesale revenue, partially offset by higher generation and purchased power costs and price impacts from changes in sales mix. Depreciation and amortization expense reflects lower Iowa revenue sharing accruals of $30 million, substantially offset by an increase related to new wind-powered generating facilities and other plant placed in-service.

Operating revenue decreased $185 million for the first nine months of 2020 compared to 2019 due to lower natural gas operating revenue of $85 million, lower electric operating revenue of $45 million, lower electric and natural gas energy efficiency program revenue of $43 million (offset in operations and maintenance expense) and lower other revenue of $12 million, primarily from nonregulated utility construction services. Natural gas operating revenue decreased primarily due to lower recoveries through the purchased gas adjustment clause of $78 million (offset in cost of sales) from a lower average per-unit cost of natural gas sold and lower volumes and a 10.4% decrease in retail customer volumes, primarily due to the unfavorable impact of weather. Electric operating revenue decreased due to lower wholesale and other revenue of $60 million, partially offset by higher retail revenue of $15 million. Electric wholesale and other revenue decreased primarily due to lower average wholesale per-unit prices. Electric retail revenue increased primarily due to higher customer usage of $32 million, partially offset by price impacts of $18 million from changes in sales mix. Electric retail customer volumes increased 1.1% due to increased usage for certain industrial customers, partially offset by the impacts of COVID-19, which resulted in lower commercial and industrial customer usage and higher residential customer usage.

34

---

Operating income was unchanged for the first nine months of 2020 compared to 2019, primarily due to lower depreciation and amortization expense of $9 million and higher electric utility margin of $7 million (excluding $30 million of lower energy efficiency program revenue), partially offset by higher property and other taxes of $8 million and lower natural gas utility margin of $7 million (excluding $13 million of lower energy efficiency program revenue) due to the unfavorable impact of weather. Depreciation and amortization expense reflects lower Iowa revenue sharing accruals of $84 million, partially offset by an increase related to new wind-powered generating facilities and other plant placed in-service. Electric utility margin increased primarily due to higher retail customer volumes and lower generation and purchased power costs, partially offset by lower wholesale revenue and price impacts from changes in sales mix. Operations and maintenance expenses not recovered through energy efficiency programs reflect higher wind-powered generation costs due to new and repowered generating facilities and higher storm restoration costs, substantially offset by lower fossil-fueled generating facility maintenance and lower electric and natural gas distribution operations costs.

NV Energy

Operating revenue decreased $12 million for the third quarter of 2020 compared to 2019, primarily due to lower electric operating revenue of $9 million. Electric operating revenue decreased primarily due to lower energy rates (offset in cost of sales), partially offset by a favorable regulatory decision, higher retail customer volumes and price impacts from changes in sales mix. Electric retail customer volumes, including distribution only service customers, increased 2.1%, primarily due to the favorable impact of weather, partially offset by the impacts of COVID-19, which resulted in lower distribution only service, commercial and industrial customer usage and higher residential customer usage.

Operating income increased $34 million for the third quarter of 2020 compared to 2019, primarily due to higher electric utility margin of $68 million, partially offset by higher operations and maintenance expenses of $26 million, mainly from higher earnings sharing accruals at Nevada Power, and higher depreciation and amortization expense of $8 million from higher plant placed in-service. Electric utility margin increased primarily due to a favorable regulatory decision, higher retail customer volumes and price impacts from changes in sales mix.

Operating revenue decreased $30 million for the first nine months of 2020 compared to 2019, primarily due to lower electric operating revenue of $39 million, partially offset by higher natural gas operating revenue of $8 million, mainly due to a higher average per-unit cost of natural gas sold of $9 million (offset in cost of sales). Electric operating revenue decreased primarily due to lower energy rates (offset in cost of sales), partially offset by the higher retail customer volumes, price impacts from changes in sales mix and a favorable regulatory decision. Electric retail customer volumes, including distribution only service customers, increased 0.4%, primarily due to the favorable impact of weather, largely offset by the impacts of COVID-19, which resulted in lower industrial, distribution only service and commercial customer usage and higher residential customer usage.

Operating income increased $40 million for the first nine months of 2020 compared to 2019, primarily due to higher electric utility margin of $80 million, partially offset by higher operations and maintenance expenses of $24 million, mainly from higher earnings sharing accruals at Nevada Power, and higher depreciation and amortization expense of $16 million from higher plant placed in-service. Electric utility margin increased primarily due to higher retail customer volumes, price impacts from changes in sales mix and a favorable regulatory decision.

Northern Powergrid

Operating revenue increased $16 million for the third quarter of 2020 compared to 2019, primarily due to the weaker United States dollar of $11 million and higher distribution revenue of $4 million from increased tariff rates offset by 5.4% lower units distributed largely due to the impacts of COVID-19. Operating income increased $8 million for the third quarter of 2020 compared to 2019, primarily due to the weaker United States dollar of $5 million and the higher distribution revenue.

Operating revenue decreased $3 million for the first nine months of 2020 compared to 2019, primarily due to lower other revenue of $4 million, partially offset by higher distribution revenue of $2 million from increased tariff rates offset by 6.5% lower units distributed largely due to the impacts of COVID-19. Operating income decreased $10 million for the first nine months of 2020 compared to 2019, primarily due to higher distribution-related operating expenses of $12 million.

35

---

BHE Pipeline Group

Operating revenue increased $38 million for the third quarter of 2020 compared to 2019, primarily due to a favorable rate case settlement at Northern Natural Gas of $24 million and higher transportation revenue of $17 million. Operating income increased $14 million for the third quarter of 2020 compared to 2019, primarily due to the higher transportation revenue and a favorable rate case settlement at Northern Natural Gas of $10 million, partially offset by higher property and other tax expense of $13 million, including a non-recurring state property tax refund in 2019.

Operating revenue increased $81 million for the first nine months of 2020 compared to 2019 due to a favorable rate case settlement at Northern Natural Gas of $72 million and higher transportation revenue of $41 million, partially offset by lower gas sales of $27 million at Northern Natural Gas related to system balancing activities (largely offset in cost of sales) and lower storage revenue of $5 million. Operating income increased $44 million for the first nine months of 2020 compared to 2019, primarily due to the higher transportation revenue and a favorable rate case settlement at Northern Natural Gas of $25 million, partially offset by higher property and other tax expense of $16 million, including a non-recurring state property tax refund in 2019, higher depreciation and amortization expense of $11 million and the lower storage revenue.

BHE Transmission

Operating revenue decreased $9 million for the third quarter of 2020 compared to 2019 and operating income decreased $12 million for the third quarter of 2020 compared to 2019. The decreases were primarily due to favorable regulatory decisions received in August 2019 at AltaLink.

Operating revenue decreased $11 million for the first nine months of 2020 compared to 2019 and operating income decreased $8 million for the first nine months of 2020 compared to 2019. The decreases were primarily due to favorable regulatory decisions received in August 2019 at AltaLink and the stronger United States dollar, partially offset by a favorable regulatory decision received in April 2020 at AltaLink.

 

BHE Renewables

Operating revenue decreased $20 million for the third quarter of 2020 compared to 2019, primarily due to lower hydro revenues of $10 million from lower rainfall, lower solar revenues of $8 million due to lower generation and an unfavorable change in the valuation of a power purchase agreement of $4 million, partially offset by higher natural gas revenues of $5 million from favorable generation. Operating income decreased $40 million for the third quarter of 2020 compared to 2019, primarily due to the lower operating revenue, higher fuel costs of $10 million at the natural gas facilities and higher operations and maintenance expenses of $10 million at the geothermal and natural gas facilities.

Operating revenue decreased $14 million for the first nine months of 2020 compared to 2019, primarily due to lower hydro revenues of $10 million from lower rainfall and an unfavorable change in the valuation of a power purchase agreement of $10 million, partially offset by higher solar revenues of $3 million from favorable generation. Operating income decreased $54 million for the first nine months of 2020 compared to 2019, primarily due to higher fuel costs of $24 million at the natural gas facilities, the lower operating revenue and higher operations and maintenance expenses of $19 million at the geothermal projects, partially offset by the lower operations and maintenance expenses of $8 million at the solar projects.

HomeServices

Operating revenue increased $435 million for the third quarter of 2020 compared to 2019, primarily due to increased brokerage revenue of $263 million from a 13% increase in closed units due to the delay in activity from the impacts of COVID-19 during the first half of 2020 and increased mortgage revenue of $153 million from a 71% increase in closed mortgage volume due to higher refinance activity from the favorable interest rate environment. Operating income increased $126 million for the third quarter of 2020 compared to 2019, primarily due to favorable operating performance at mortgage from the favorable interest rate environment.

Operating revenue increased $409 million for the first nine months of 2020 compared to 2019, primarily due to increased mortgage revenue of $310 million from a 68% increase in closed mortgage volume due to higher refinance activity from the favorable interest rate environment and increased brokerage revenue of $71 million from a 6% increase in the average home sales price offset by a 2% decrease in closed units. Operating income increased $127 million for the first nine months of 2020 compared to 2019, primarily due to improved operating performance at mortgage from the favorable interest rate environment, partially offset by an unfavorable contingent earn-out remeasurement.

36

---

BHE and Other

Operating revenue decreased $26 million for the third quarter of 2020 compared to 2019 and $99 million for the first nine months of 2020 compared to 2019, primarily due to lower electricity and natural gas volumes at MidAmerican Energy Services, LLC. Operating loss increased $59 million for the third quarter of 2020 compared to 2019, primarily due to higher operations and maintenance expenses and lower margin of $8 million at MidAmerican Energy Services, LLC, mainly due to unfavorable changes in unrealized positions on derivative contracts. Operating loss increased $31 million for the first nine months of 2020 compared to 2019, primarily due to higher operations and maintenance expenses, partially offset by higher margin of $7 million at MidAmerican Energy Services, LLC, primarily due to favorable changes in unrealized positions on derivatives contracts offset by lower electricity volumes.

Consolidated Other Income and Expense Items

Interest expense

Interest expense is summarized as follows (in millions):

	Third Quarter															First Nine Months
	2020				2019				Change							2020				2019				Change
Subsidiary debt	$	371			$	366			$	5			1	%		$	1,113			$	1,102			$	11			1	%
BHE senior debt and other	132				108				24				22			373				322				51				16
BHE junior subordinated debentures	1				1				—				—			4				4				—				—
Total interest expense	$	504			$	475			$	29			6	%		$	1,490			$	1,428			$	62			4	%

Interest expense increased $29 million for the third quarter of 2020 compared to 2019 and $62 million for the first nine months of 2020 compared to 2019, primarily due to higher average long-term debt balances at BHE, PacifiCorp, MidAmerican Energy and BHE Pipeline Group, partially offset by lower short- and long-term borrowing rates.

Capitalized interest

Capitalized interest increased $1 million for the third quarter of 2020 compared to 2019 and $4 million for the first nine months of 2020 compared to 2019, primarily due to higher construction work-in-progress balances at PacifiCorp, partially offset by lower construction work-in-progress balances at MidAmerican Energy.

Allowance for equity funds

Allowance for equity funds decreased $6 million for the third quarter of 2020 compared to 2019 and $4 million for the first nine months of 2020 compared to 2019, primarily due to lower construction work-in-progress balances at MidAmerican Energy, partially offset by higher construction work-in-progress balances at PacifiCorp.

Interest and dividend income

Interest and dividend income decreased $8 million for the third quarter of 2020 compared to 2019 and $34 million for the first nine months of 2020 compared to 2019, primarily due to lower cash balances, lower interest rates and a declining financial asset balance at the Casecnan project.

Gains (losses) on marketable securities, net

Gains (losses) on marketable securities, net was favorable $2,031 million for the third quarter of 2020 compared to 2019 and $2,703 million for the first nine months of 2020 compared to 2019, primarily due to the change in the unrealized position on the Company's investment in BYD Company Limited of $2,021 million and $2,713 million, respectively.

37

---

Other, net

Other, net increased $34 million for the third quarter of 2020 compared to 2019, primarily due to lower pension and other postretirement expense of $25 million, largely resulting from higher pension settlement losses recognized at Northern Powergrid in 2019, and higher cash surrender value of corporate-owned life insurance policies, partially offset by lower commitment fee income of $8 million at BHE Renewables.

Other, net decreased $6 million for the first nine months 2020 compared to 2019, primarily due to lower cash surrender value of corporate-owned life insurance policies and lower commitment fee income of $15 million at BHE Renewables, partially offset by lower pension and postretirement expense of $29 million, largely resulting from higher pension settlement losses recognized at Northern Powergrid in 2019.

Income tax expense (benefit)

Income tax benefit decreased $382 million for the third quarter of 2020 compared to 2019 and the effective tax rate was 3% for the third quarter of 2020 and (36)% for the third quarter of 2019. The effective tax rate increased primarily due to higher income before taxes from the Company's investment in BYD Company Limited, a deferred income tax charge of $35 million resulting from the United Kingdom's corporate income tax rate change and the unfavorable impacts of ratemaking of $6 million, partially offset by higher PTCs recognized of $227 million.

Income tax benefit decreased $415 million for the first nine months 2020 compared to 2019 and the effective tax rate was (2)% for the first nine months 2020 and (27)% first nine months of 2019. The effective tax rate increased primarily due to higher income before taxes from the Company's investment in BYD Company Limited, consolidated state income tax benefits recognized in 2019 and a deferred income tax charge of $35 million resulting from the United Kingdom's corporate income tax rate change, partially offset by higher PTCs recognized of $371 million and the favorable impacts of ratemaking of $28 million.

PTCs are recognized in earnings for interim periods based on the application of an estimated annual effective tax rate to pre-tax earnings. 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. PTCs recognized in 2020 were $1,046 million, or $371 million higher than 2019, while PTCs earned in 2020 were $818 million, or $314 million higher than 2019. The difference between PTCs recognized and earned of $228 million as of September 30, 2020, will be reflected in earnings over the remainder of 2020.

The United Kingdom's corporate income tax rate was scheduled to decrease from 19% to 17% effective April 1, 2020; however, the rate was maintained at 19% through amended legislation enacted in July 2020, which resulted in a deferred income tax charge of $35 million.

Equity loss

Equity loss increased $37 million for the third quarter of 2020 compared to 2019 and $79 million for the first nine months of 2020 compared to 2019, primarily due to 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.

38

---

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 the Company's Annual Report on Form 10-K for the year ended December 31, 2019 for further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of September 30, 2020, 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	$	64			$	590			$	193			$	217			$	254			$	76			$	375			$	1,769
Credit facilities	3,500				1,200				1,509				650				194				882				2,933				10,868
Less:
Short-term debt	(100		)		—				—				—				—				(198		)		(2,102		)		(2,400		)
Tax-exempt bond support and letters of credit	—				(256		)		(370		)		—				—				(2		)		—				(628		)
Net credit facilities	3,400				944				1,139				650				194				682				831				7,840
Total net liquidity	$	3,464			$	1,534			$	1,332			$	867			$	448			$	758			$	1,206			$	9,609
Credit facilities:
Maturity dates	2022				2022				2021, 2022				2022				2022				2021, 2024				2020, 2021, 2022

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2020 and 2019 were $4.5 billion and $4.7 billion, respectively. The decrease was primarily due to changes in working capital, partially offset by favorable income tax cash flows.

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 used for each payment date.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2020 and 2019 were $(6.6) billion and $(6.0) billion, respectively. The change was primarily due to higher funding of tax equity investments, partially offset by lower capital expenditures of $291 million. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

39

---

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2020 was $2.9 billion. Sources of cash totaled $5.9 billion and consisted of proceeds from BHE senior debt issuances totaling $3.2 billion and proceeds from subsidiary debt issuances totaling $2.6 billion. Uses of cash totaled $2.9 billion and consisted mainly of repayments of subsidiary debt totaling $1.6 billion, net repayments of short-term debt totaling $815 million, repayments of BHE senior debt totaling $350 million and common stock repurchases totaling $126 million.

For a discussion of recent financing transactions, refer to Note 5 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Net cash flows from financing activities for the nine-month period ended September 30, 2019 was $1.9 billion. Sources of cash totaled $4.1 billion and consisted of proceeds from subsidiary debt issuances totaling $3.5 billion and net proceeds from short-term debt totaling $594 million. Uses of cash totaled $2.2 billion and consisted mainly of repayments of subsidiary debt totaling $1.8 billion and common stock repurchases totaling $293 million.

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.

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 regulatory approvals, 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, 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. Expenditures for certain assets may ultimately include acquisitions of existing assets.

40

---

The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):

	Nine-Month Periods								Annual
	Ended September 30,								Forecast
	2019				2020				2020
Capital expenditures by business:
PacifiCorp	$	1,449			$	1,618			$	2,652
MidAmerican Funding	1,909				1,341				1,923
NV Energy	448				509				690
Northern Powergrid	372				492				689
BHE Pipeline Group	403				428				578
BHE Transmission	175				276				328
BHE Renewables	97				46				105
HomeServices	38				21				30
BHE and Other(1)	7				(124		)		(115		)
Total	$	4,898			$	4,607			$	6,880

Capital expenditures by type:
Wind generation	$	2,060			$	1,374			$	2,140
Electric transmission	472				437				548
Other growth	514				501				735
Operating	1,852				2,295				3,457
Total	$	4,898			$	4,607			$	6,880

(1)	BHE and Other represents amounts related principally to other entities, corporate functions and intersegment eliminations.

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 $676 million and $1.0 billion for the nine-month periods ended September 30, 2020 and 2019, respectively. MidAmerican Energy anticipates costs associated with the construction of wind-powered generating facilities will total an additional $193 million for 2020. Wind XI, a 2,000-MW project constructed over several years, was completed in January 2020. Wind XII is a 592-MW project, including 253 MWs placed in-service as of September 30, 2020, with the remaining facilities expected to be placed in-service by the end of 2020. MidAmerican Energy obtained pre-approved ratemaking principles for both of these projects and expects all of these wind-powered generating facilities to qualify for 100% of federal 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. MidAmerican Energy currently has three such wind-powered generation projects under construction totaling 319 MWs that are expected to be placed in-service by the end of 2020 and to qualify for 100% of federal PTCs available.

◦

Repowering certain existing wind-powered generating facilities at MidAmerican Energy totaling $25 million and $332 million for the nine-month periods ended September 30, 2020 and 2019, respectively. The repowering projects entail the replacement of significant components of older turbines. Planned spending for the repowered generating facilities totals $19 million for the remainder of 2020. Of the 998 MWs of current repowering projects not in-service as of September 30, 2020, 591 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.

41

---

◦

Construction of wind-powered generating facilities at PacifiCorp totaling $705 million and $245 million for the nine-month periods ended September 30, 2020 and 2019, respectively. Construction includes the 1,190 MWs of new wind-powered generating facilities that are expected to be placed in-service in 2020 and 2021 and the energy production is expected to qualify for 100% of the federal PTCs available for ten years once the equipment is placed in-service. PacifiCorp anticipates costs associated with the construction of wind-powered generating facilities will total an additional $522 million for 2020.

◦

Repowering certain existing wind-powered generating facilities at PacifiCorp totaling $99 million and $442 million for the nine-month periods ended September 30, 2020 and 2019, respectively. 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 $3 million for the remainder of 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.

•	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, additional Energy Gateway Transmission segments expected to be placed in service in 2023 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 CCRs.

Natural Gas Transmission and Storage Business Acquisition

On November 1, 2020, BHE completed its acquisition of substantially all of the natural gas transmission and storage business of Dominion Energy, Inc. ("DEI") and Dominion Energy Questar Corporation ("Dominion Questar"), exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "Questar Pipeline Group") (the "GT&S Transaction"). Under the terms of the Purchase and Sale Agreement, dated July 3, 2020 (the "GT&S Purchase Agreement"), BHE paid approximately $2.7 billion in cash (the "GT&S Cash Consideration"), subject to adjustment for cash and indebtedness as of closing, and assumed approximately $5.3 billion of existing indebtedness for borrowed money.

On October 5, 2020, DEI and Dominion Questar, as permitted under the terms of the GT&S Purchase Agreement, delivered notice to BHE of their election to terminate the GT&S Transaction with respect to the Questar Pipeline Group and, in connection with the execution of the Q-Pipe Purchase Agreement referenced below, to waive the related termination fee under the GT&S Purchase Agreement. Also on October 5, 2020, BHE entered into a second Purchase and Sale Agreement (the "Q-Pipe Purchase Agreement") with Dominion Questar providing for BHE's purchase of the Questar Pipeline Group from Dominion Questar (the "Q-Pipe Transaction") after receipt of HSR Approval, which is currently anticipated in early 2021, for a cash purchase price of approximately $1.3 billion (the "Q-Pipe Cash Consideration"), subject to adjustment for cash and indebtedness as of the closing, and the assumption of approximately $430 million of existing indebtedness for borrowed money. Under the Q-Pipe Purchase Agreement, BHE delivered the Q-Pipe Cash Consideration to Dominion Questar on November 2, 2020.

On October 29, 2020, BHE issued $3.75 billion of its 4.00% Perpetual Preferred Stock (the "Perpetual Preferred") to certain subsidiaries of Berkshire Hathaway Inc. in order to fund the GT&S Cash Consideration and the Q-Pipe Cash Consideration. Under the terms of the Perpetual Preferred, BHE is permitted to redeem such Perpetual Preferred at par at any time.

Other Renewable 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 $2.1 billion for the nine-month period ended September 30, 2020, and has commitments as of September 30, 2020, subject to satisfaction of certain specified conditions, to provide equity contributions of $682 million for the remainder of 2020 and $197 million in 2021 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.

42

---

Contractual Obligations

As of September 30, 2020, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2019 other than the recent financing transactions and renewable tax equity investments previously discussed.

COVID-19

In March 2020, COVID-19 was declared a global pandemic and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and many of the customers served by the Company. While COVID-19 has impacted the Company's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. In April 2020, most jurisdictions in which the Company operates instituted varying levels of "stay-at-home" orders and other measures, requiring non-essential businesses to remain closed, which impacted most of the Company's retail electric and natural gas customers and, therefore, their needs and usage patterns for electricity and natural gas as evidenced by a reduction in consumption through September 2020 compared to the same period in 2019. These jurisdictions have since moved to varying phases of recovery plans with most businesses opening subject to certain operating restrictions. As the impacts of COVID-19 and related customer and governmental responses remain uncertain, including the duration of restrictions on business openings, a reduction in the consumption of electricity or natural gas may continue to occur, particularly in the commercial and industrial classes. Due to regulatory requirements and voluntary actions taken by the Utilities and Northern Powergrid related to customer collection activity and suspension of disconnections for non-payment, the Utilities and Northern Powergrid have seen delays and reductions in cash receipts from retail customers related to the impacts of COVID-19, which could result in higher than normal bad debt write-offs. The amount of such reductions in cash receipts through September 2020 has not been material compared to the same period in 2019 but uncertainty remains. Regulatory jurisdictions may allow for the deferral or recovery of certain costs incurred in responding to COVID-19. Refer to "Regulatory Matters" in Part I, Item 2 of this Form 10-Q for further discussion. Residential property transactions may decline in the future at HomeServices due to the varying phases of state recovery plans and associated duration of restrictions on business openings, other measures and general economic uncertainty.

Several of the Company's businesses have been deemed essential and their employees have been identified as "critical infrastructure employees" allowing them to move within communities and across jurisdictional boundaries as necessary to maintain the electric generation, transmission and distribution systems and the natural gas transportation and distribution systems. In response to the effects of COVID-19, the Company has implemented various business continuity plans to protect its employees and customers. Such plans include a variety of actions, including situational use of personal protective equipment by employees when interacting with customers and implementing practices to enhance social distancing at the workplace. Such practices have included work-from-home, staggered work schedules, rotational work location assignments, increased cleaning and sanitation of work spaces and providing general health reminders intended to help lower the risk of spreading COVID-19.

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 ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs 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.

The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation 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. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.

43

---

On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expands the breadth and scope of the PJM's MOPR, which is effective as of the PJM's next capacity auction. While the FERC included some limited exemptions in its order, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. 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. In response to the FERC's order, the PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. On October 15, 2020, the FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting the PJM's two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, the FERC also accepted the PJM's proposal to condense the schedule of activities leading up to the next capacity auction but did not specify when that schedule would commence given that a key element of the MOPR level computation remains pending before the FERC in another proceeding.

On May 21, 2020, the FERC issued an order involving reforms to the PJM's day-ahead and real-time reserves markets that need to be reflected in the calculation of MOPR levels. In approving reforms to the PJM's reserves markets, the FERC also directed the PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and related services, which will then be used in calculating a number of parameters and assumptions used in the capacity market, including MOPR levels. The PJM submitted its new revenue projection methodology on August 5, 2020. On review of this compliance filing, the FERC is expected to address how these additional reforms will impact MOPR levels, the timeline for implementing the new revenue projection methodology, and the timing for commencing the capacity auction schedule.

Exelon Generation is currently working with the PJM and other stakeholders to pursue the FRR option as an alternative to the next PJM capacity auction. If Illinois implements the FRR option, Quad Cities Station could be removed from the PJM's capacity auction and instead supply capacity and be compensated under the FRR program. If Illinois cannot implement an FRR program in its PJM zones, then the MOPR will apply to Quad Cities Station, resulting in higher offers for its units that may not clear the capacity market. Implementing the FRR program in Illinois will require both legislative and regulatory changes. MidAmerican Energy cannot predict whether or when such legislative and regulatory changes can be implemented or their potential impact on the continued operation of Quad Cities Station.

Regulatory Matters

BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2019 and new regulatory matters occurring in 2020.

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 general rate case. In January 2020, the OPUC issued an order adopting the 2020 Protocol. The WPSC held a hearing and issued a bench decision approving the 2020 Protocol in March 2020. In April 2020, the UPSC and the IPUC issued orders approving the 2020 Protocol.

44

---

Depreciation Rate Study

In September 2018, PacifiCorp filed applications for depreciation rate changes with the UPSC, the OPUC, the WPSC, the WUTC and the IPUC based on PacifiCorp's 2018 depreciation rate study, requesting the rates become effective January 1, 2021. Based on the proposed depreciation rates, annual depreciation expense would increase approximately $300 million. Parties to the applications in each state have since evaluated the study and updates provided by PacifiCorp and have participated in multi-party discussions. Updates since September 2018 include the filing of PacifiCorp's 2020 decommissioning studies in which a third‑party consultant was engaged to estimate decommissioning costs associated with coal-fueled generating facilities.

In December 2019, PacifiCorp incorporated the depreciation rate study into its general rate case filing with the WUTC, which was later updated to incorporate the 2020 decommissioning studies. In July 2020, PacifiCorp filed a stipulation with the WUTC resolving all issues addressed in PacifiCorp's depreciation rate study application. The stipulation is subject to the WUTC's approval and an order is expected by the end of 2020.

In March 2020, PacifiCorp filed a partial settlement stipulation with the UPSC to which all but one intervening party agreed. The partial settlement adopts certain aspects of the 2018 depreciation rate study as filed for coal-fueled generating facilities and established a secondary phase to the proceeding to address decommissioning costs for PacifiCorp's coal‑fueled generating facilities and equipment replaced as a result of PacifiCorp's wind repowering projects. The second phase is scheduled to conclude in November 2020. The stipulation provides for the treatment of Cholla Unit 4 to be addressed in PacifiCorp's pending general rate case. In April 2020, the UPSC approved the stipulation as filed.

In March 2020, PacifiCorp filed motions with the OPUC to remove matters associated with its coal-fueled generating facilities from the depreciation rate study and instead expand its general rate case to address depreciation rates and decommissioning costs associated with its coal-fueled generating facilities. In April 2020, the motions were granted by the OPUC. In August 2020, PacifiCorp filed an all‑party stipulation with the OPUC resolving all remaining issues in the depreciation study. A final decision on the stipulation is pending.

In April 2020, PacifiCorp filed a stipulation with the WPSC resolving all issues addressed in PacifiCorp's depreciation rate study application with ratemaking treatment of certain matters to be addressed in PacifiCorp's general rate case. The general rate case will determine ratemaking treatment of Cholla Unit 4; Wyoming's share of coal-fueled generating facilities, including additional decommissioning costs identified in PacifiCorp's 2020 decommissioning studies; and certain matters related to the repowering of PacifiCorp's wind-powered generating facilities. The stipulation was approved by the WPSC during a hearing and a subsequent bench decision in August 2020. The general rate case hearing was rescheduled for February 2021. As a result of the hearing date change, PacifiCorp filed an application in October 2020 with the WPSC requesting authorization to defer costs associated with impacts of the depreciation study.

In June 2020, PacifiCorp filed a partial settlement stipulation with the IPUC to which all but one intervening party agreed. The partial settlement adopts certain aspects of the 2018 depreciation rate study as filed for coal-fueled generating facilities and proposes a secondary phase to the proceeding be established in order to address decommissioning costs for PacifiCorp's coal‑fueled generating facilities. In August 2020, the IPUC approved the stipulation and authorized a secondary phase to the proceeding to address decommissioning costs for PacifiCorp's coal‑fueled generating facilities.

As a result of delaying the general rate case filing in Idaho to 2021 for an anticipated effective date of January 1, 2022, PacifiCorp reached a separate agreement with parties to defer the incremental depreciation expense from the 2018 depreciation study for one year, during 2021. In October 2020, a settlement stipulation was filed with the IPUC to defer the incremental decommissioning expense from the 2020 decommissioning studies for one year, during 2021, consistent with the treatment of the incremental depreciation expense.

Retirement Plan Settlement Charge

During 2018, the PacifiCorp Retirement Plan incurred a settlement charge 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 October 2019, the request for a memorandum account was re-filed as an application with the CPUC. In 2019, the WUTC approved the requested deferral, while the UPSC and the WPSC denied the request. In January 2020, the OPUC issued an order denying PacifiCorp's request. In April 2020, the CPUC approved the request to establish a memorandum account effective December 31, 2018.

45

---

COVID-19

In March and April 2020, PacifiCorp filed applications requesting authorization to defer costs associated with COVID‑19 with the UPSC, the OPUC, the WPSC, the WUTC and the IPUC. In April 2020, as ordered by the CPUC, PacifiCorp filed to establish the COVID‑19 Pandemic Protections Memorandum Account. The memorandum account was approved in September 2020, retroactive to March 4, 2020. In April 2020, the WPSC approved PacifiCorp's application to defer costs associated with COVID‑19, subject to a public notice period, and required associated benefits arising from COVID‑19 to be offset against the deferred costs. During the public notice period, one party to the proceeding filed a petition for a rehearing of the matter. The WPSC has scheduled a hearing for this matter in April 2021. In July, September and October 2020, the IPUC, the UPSC and the OPUC, respectively, approved PacifiCorp's applications to defer costs associated with COVID‑19, requiring associated benefits arising from COVID‑19 to be offset against the deferred costs.

Utah

In March 2019, PacifiCorp filed its annual EBA application with the UPSC requesting recovery of $24 million, or 1.1%, of 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 the UPSC issued an order approving full recovery of the 2018 deferred costs beginning April 1, 2020.

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. Twenty-four communities in Utah, including Salt Lake City, passed the resolution 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. The program details, including costs, are being developed with the communities for a future filing with the UPSC.

In March 2020, PacifiCorp filed its annual EBA application with the UPSC requesting recovery of $37 million, or 1.0%, of deferred power costs from customers for the period January 1, 2019 through December 31, 2019, reflecting the difference between base and actual net power costs in the 2019 deferral period. Hearings are scheduled for January 2021 for rates effective March 1, 2021.

In March 2020, Utah's governor signed Utah House Bill 66, Wildland Fire Planning and Cost Recovery Amendments, which requires PacifiCorp to prepare a wildfire protection plan to be approved by the UPSC. All investments, including the cost of capital, made to implement an approved plan are recoverable in rates. The bill also provides a potential liability safe harbor if PacifiCorp is in compliance with its approved wildfire mitigation plan. In addition, the legislation clarifies the standard for real property losses and eliminates the current standard of treble damages awarded for tree losses. The first wildland fire protection plan was filed with the UPSC in June 2020 and was approved by the UPSC in October 2020.

In March 2020, Utah's governor signed Utah House Bill 396, Electric Vehicle Charging Infrastructure Amendments, which directs the UPSC to enable PacifiCorp to recover in rates up to $50 million of electric vehicle infrastructure. The legislation also prohibits a third‑party from generating electricity onsite to directly resell to customers through electric vehicle charging infrastructure.

In May 2020, PacifiCorp filed a general rate case with the UPSC requesting an increase in base rates of $96 million, or 4.8%, which PacifiCorp proposed to be implemented over a three-year period with 2.6% effective January 1, 2021, 1.1% effective January 1, 2022 and 1.1% effective January 1, 2023. The increase reflects recovery of Energy Vision 2020 investments, updated depreciation rates, a wildland fire mitigation cost tracking mechanism to implement Utah House Bill 66, and rate design modernization proposals. The application also requests authorization to discontinue operations and recover costs associated with the early retirement of Cholla Unit 4. The proposed increase reflects several rate mitigation measures that include use of the balance in the Sustainable Transportation and Energy Plan regulatory liability account to buy-down the undepreciated plant balance of certain coal-fueled generation units, including Cholla Unit 4, and the use of a portion of the deferred income tax benefits associated with 2017 Tax Reform to buy-down certain regulatory assets and further depreciate the Dave Johnston plant balance. Hearings are scheduled for November 2020.

46

---

Oregon

In December 2018, PacifiCorp filed a 2019 RAC application requesting recovery of costs associated with repowering of approximately 900 MWs of company-owned and installed wind facilities expected to be completed in 2019. The associated net power cost and PTC benefits were previously included in the 2019 TAM. An all-party settlement 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 with rates to be increased as the repowering projects are completed. 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 of $5 million, or 0.4%, was effective April 1, 2020 for the two remaining repowered facilities that were placed in service by the end of March 2020. As part of the settlement, parties agreed that the Oregon‑allocated net book value of certain undepreciated equipment replaced as a result of the applicable repowering projects would be depreciated and offset with excess deferred income taxes resulting from 2017 Tax Reform. During the nine-month period ended September 30, 2020, accelerated depreciation of $40 million and offsetting amortization of excess deferred income taxes was recognized associated with the two remaining repowered facilities included in the 2019 RAC. In October 2020, PacifiCorp filed its annual update for plants placed into service in 2019 requesting an overall rate increase of $2 million, or 0.2%, effective November 1, 2020. The rate increase is expected to be in effect until January 1, 2021 when new rates from the general rate case reset the RAC rates to zero.

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 wind equipment in this filing with PacifiCorp's OATT revenue related deferral from 2017 through 2019. An all-party settlement was filed in January 2020 supporting the filed request and was approved by the OPUC in March 2020. Based on a final cost update for the Glenrock III wind facility, and including the net power cost and PTC benefits, a 0.02% rate decrease became effective April 1, 2020. In September 2020, PacifiCorp filed for a rate change after the repowered Dunlap wind facility was placed in service. Based on the final cost update for the Dunlap wind facility, and including the net power cost and PTC benefits, an additional rate increase of $2 million, or 0.1%, became effective September 18, 2020. As a result of the settlement, accelerated depreciation of $34 million and offsetting amortization of PacifiCorp's OATT deferral was recognized during the nine-month period ended September 30, 2020 associated with undepreciated equipment replaced as a result of the repowering of the Glenrock III and Dunlap wind facilities.

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 expense. In January 2020, the OPUC authorized the automatic adjustment clause, rate schedule and application for deferral. PacifiCorp began recovering the estimated OCAT expense effective February 1, 2020. The recovery adjustment for 2020 is 0.41% and the rate is being applied as a percentage surcharge on customers' bills.

In February 2020, PacifiCorp filed a general rate case in Oregon requesting a total rate increase of $71 million, or 5.4%, effective January 1, 2021. The rate case includes 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 June 2020, PacifiCorp filed reply testimony requesting a revised net rate increase of $67 million, or 5.0%, on January 1, 2021. The reply testimony includes a proposal to offset the costs associated with the early retirement of Cholla Unit 4 with a portion of the deferred income tax benefits associated with 2017 Tax Reform rather than recovering these costs through a separate tariff as proposed in the initial filing. The revised net rate increase also includes PacifiCorp's proposal to provide an annual credit to customers of $6 million for amortization of the remaining deferred income tax benefits associated with 2017 Tax Reform over a two-year period beginning January 2021. In August 2020, PacifiCorp filed its surrebuttal testimony requesting a revised net rate increase of $41 million, or 3.1%, effective January 1, 2021. This includes the proposed annual credit to customers of the remaining deferred income tax benefits associated with 2017 Tax Reform that was modified to $7 million. PacifiCorp also filed a partial stipulation that would settle all rate design and rate spread issues in the general rate case. In PacifiCorp's closing brief filed in October 2020, PacifiCorp modified the requested net rate increase to $40 million, or 3.0%, to accept the OPUC staff adjustment correcting the ongoing advanced meter infrastructure operating costs reflected in the case.

47

---

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 new and repowered wind resources, including an increase in PTCs. In June 2020, PacifiCorp filed reply testimony in its annual TAM with updated forecast net power costs resulting in a rate decrease of $47 million, or 3.6%, effective January 1, 2021. In August 2020, PacifiCorp filed a stipulation with the OPUC settling all issues in the proceeding. The terms of the stipulation result in an overall rate decrease based on the June update of $50 million, or 3.8%, effective January 1, 2021. In October 2020, the OPUC approved the stipulation. The overall rate impact will be finalized when the final update that incorporates the terms of the stipulation is filed in November 2020.

In September 2020, PacifiCorp filed an application for deferred accounting associated with restoring service to customers and repairing, replacing and restoring damaged utility facilities due to wildfires in Oregon.

Wyoming

In July 2019, Wyoming Senate Enrolled Act No. 74 ("SEA 74") went into effect. The legislation, among other things, requires electric utilities to make a good faith effort to sell a coal-fueled 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. In March 2020, the Wyoming governor signed Senate Enrolled Act No. 23, which allows a 1 MW or greater customer to purchase electricity from a coal-fueled generation facility purchased from an electric utility under SEA 74. 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.

In March 2020, PacifiCorp filed a general rate case with the WPSC requesting an increase in base rates of $7 million, or 1.1%, effective January 1, 2021. The increase reflects recovery of Energy Vision 2020 investments, updated depreciation rates and rate design modernization proposals. The application also requests a revision to the ECAM to eliminate the sharing band and requests authorization to discontinue operations and recover costs associated with the early retirement of Cholla Unit 4. The proposed increase reflects several rate mitigation measures that include use of the remaining 2017 Tax Reform benefits to buy down plant balances, including Cholla Unit 4, and spreading the recovery of the depreciation of certain coal-fueled generation units over time periods that extend beyond the depreciable lives proposed in the depreciation rate study. In September 2020, PacifiCorp filed its rebuttal testimony that proposed an increase to its requested base rate from $7 million to $9 million and an update to the rate mitigation measures for using the 2017 Tax Reform benefits. The WPSC determined that the rebuttal testimony filed constituted a material and substantial change to the original application and vacated the hearing that was scheduled for October 2020. The WPSC is re-noticing PacifiCorp's case and rescheduled the hearings for February 2021 with a rate effective date sometime after the hearing in 2021.

In March 2020, the Wyoming governor signed House of Representatives Enrolled Act No. 79, which requires the WPSC to adopt a standard to specify a percentage of an electric utility's electricity to be generated from coal‑fueled generation utilizing carbon capture technology by no later than 2030. The bill allows electric utilities to implement a surcharge not to exceed 2% of customer bills to recover costs to comply with the standard. 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.

In April 2020, PacifiCorp filed its annual ECAM and RRA application with the WPSC requesting recovery of $7 million, or 1.0% of deferred net power costs from customers for the period January 1, 2019 through December 31, 2019, reflecting the difference between base and actual net power costs in the 2019 deferral period. The rate change went into effect on an interim basis June 15, 2020. This increase will be offset in part by continued rate credits associated with 2017 Tax Reform benefits and bonus depreciation for which minor adjustments are proposed to go into effect in the same timeframe. The hearing is set for December 2020.

Washington

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.

48

---

In December 2019, PacifiCorp submitted its 2021 Washington general rate case requesting an overall decrease to rates of $4 million, or 1.1%, effective January 1, 2021. The case includes a proposed ten-year annual surcredit of $7 million to customers primarily associated with the amortization of excess deferred income taxes from 2017 Tax Reform. The case also 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. In April 2020, PacifiCorp submitted supplemental testimony and exhibits to incorporate the impacts of the recently completed decommissioning studies for PacifiCorp's coal-fueled generating resources and update net power costs. The updates resulted in a revised request for an overall increase to rates of $11 million, or 3.2%. The parties subsequently reached a settlement in principle. In July 2020, the resulting all-party settlement was filed reflecting a rate decrease of $4 million or 1.2%. The settlement adjusts the current $8 million annual surcredit associated with 2017 Tax Reform that was set to expire January 1, 2021 to a five-year annual surcredit of $12 million, primarily associated with the amortization of excess deferred income taxes from 2017 Tax Reform. The settlement also includes approval of the new cost allocation methodology, updated depreciation rates and rate design modernization proposals. While recovery of the Energy Vision 2020 investments is reflected in the settlement, revenue associated with those investments placed into service after May 1, 2020 will be subject to a prudency review in a separate filing in 2021 to address the cost recovery. In October 2020, PacifiCorp filed a petition for rehearing and motion to amend the settlement stipulation to reflect an increase to net power costs. In the settlement, parties had agreed to offset any increase to net power costs in the October update with the power cost adjustment mechanism deferral account balance. The October update resulted in an increase greater than the balance in the deferral account. To maintain the intent of the settlement to update net power costs and decrease rates for customers, PacifiCorp and the parties to the settlement reached an agreement to reflect this difference in the deferral account for future ratemaking. In November 2020, PacifiCorp and parties filed joint testimony supporting the amended settlement. The settlement is subject to approval by the WUTC.

Idaho

In April 2020, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $21 million, or 3.0%, for deferred costs in 2019. 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, changes in PTCs, RECs, and a resource tracking mechanism to match costs with the benefits of wind repowering projects until they are reflected in base rates. This deferral is partially offset by $3 million related to amortization of excess deferred income taxes stemming from 2017 Tax Reform and net of recovery for a regulatory asset related to the prior depreciation study. In May 2020, the IPUC issued an order approving the application as filed with rates effective June 1, 2020.

In March 2020, PacifiCorp filed a notice of intent to file a general rate case with the IPUC. However, in June 2020, PacifiCorp negotiated a settlement with parties that allowed PacifiCorp to avoid filing a general rate case in 2020. The parties will support PacifiCorp's proposal to defer the incremental depreciation expense from the 2018 depreciation study during 2021, request deferred accounting treatment for unrecovered investment and closure costs when Cholla Unit 4 is retired, use a portion of the deferred income tax benefits associated with 2017 Tax Reform to buy-down Cholla Unit 4 and offset future rate increases, and include the Pryor Mountain wind facility and the repowering of the Foote Creek I wind facility in the resource tracking mechanism. In return, PacifiCorp will delay filing a general rate case until 2021 with rates effective January 1, 2022. In July 2020, PacifiCorp filed the general rate case settlement stipulation and the related application for an accounting order.

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 a $6 million, or 5.1%, rate decrease effective February 6, 2020. The CPUC's final order also resulted in an additional rate decrease of $6 million, or 5.1%, over the next three years due to the amortization of excess deferred income taxes attributed to 2017 Tax Reform.

California Senate Bill 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. 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 for which it received approval in June 2020.

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 memorandum account would be used to track costs associated with the unrecovered plant balance, decommissioning and other closure-related costs until PacifiCorp requests recovery in its next general rate case or other proceeding. In July 2020, the CPUC issued a decision approving the requested memorandum account with an effective date of December 27, 2019.

49

---

In August 2020, PacifiCorp filed an application with the CPUC to address California energy costs and Greenhouse Gas ("GHG") Allowance costs. The application includes a $7 million, or 6.7% decrease in energy costs, which is largely attributed to PTCs for new and repowered Energy Vision 2020 resources, and an increase of $1 million, or 0.8%, to recover costs for purchasing GHG allowances as required by the state's Cap-and-Trade Program. If this application is approved, this would result in an overall decrease of $6 million, or 5.9% effective January 1, 2021.

In September 2020, PacifiCorp notified the CPUC of activation of PacifiCorp's Catastrophic Events Memorandum Account in order to track costs for restoring service to customers and repairing, replacing and restoring damaged utility facilities due to wildfires in Happy Camp, California.

MidAmerican Energy

COVID-19

In May 2020, the IUB issued an order authorizing MidAmerican Energy to use a regulatory asset account to record and track increased costs and other financial impacts associated with COVID-19. At such time as MidAmerican Energy deems appropriate, it may initiate a proceeding with the IUB to seek recovery of such costs and other financial impacts. MidAmerican Energy cannot predict at this time the amount of such financial impacts from COVID-19 or when it will seek recovery of such costs with the IUB.

Iowa Transmission Legislation

In June 2020, Iowa signed into law legislation that grants incumbent electric transmission owners the right to construct, own and maintain electric transmission lines that have been approved for construction in a federally registered planning authority's transmission plan and that connect to the incumbent electric transmission owner's facility. Also known as the Right of First Refusal, the law ensures MidAmerican Energy, as an incumbent electric transmission owner, has the legal right to construct, own and maintain transmission lines that have been approved by the Midcontinent Independent System Operator, Inc. (or another federally registered planning authority) in MidAmerican Energy's service territory. To exercise the legal right, MidAmerican Energy must notify the IUB within 90 days of any such approval for construction that it intends to construct, own and maintain the electric transmission line. The law still requires an incumbent electric transmission owner to obtain a state franchise from the IUB to construct, erect, maintain or operate an electric transmission line and, upon issuance of a franchise, the incumbent electric transmission owner provide the IUB an estimate of the cost to construct the electric transmission line and, until the construction is complete, a quarterly report updating the estimated cost to construct the electric transmission line. Legal challenges have been brought against similar laws in other states, but courts that have ruled on such cases have upheld the states' laws. In October 2020, a lawsuit challenging the law was filed in Iowa by national transmission interests. The suit raises issues specific to Iowa law, and the State of Iowa is defending the suit.

NV Energy (Nevada Power and Sierra Pacific)

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 resolved all cost of capital and revenue requirement issues and provided for an annual revenue reduction of $5 million and required 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 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 April 2020, the PUCN issued a final order approving a weather normalization methodology that changed the additional annual revenue reduction from $3 million to $2 million with an effective date of January 1, 2020. Customers billed under rates utilizing the initial revenue reduction will be issued credits in the fourth quarter of 2020.

50

---

In June 2020, Nevada Power filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue reduction of $96 million but requested an annual revenue reduction of $120 million. In September 2020, Nevada Power filed an all-party settlement for the electric regulatory rate review. The settlement resolved all but one issue and provided for an annual revenue reduction of $93 million and required Nevada Power to issue a $120 million one-time bill credit, composed primarily of existing regulatory liabilities, to customers beginning in October 2020. The continuation of the earning sharing mechanism was the one issue that was not addressed in the settlement. In October 2020, the PUCN held a hearing on the continuation of the earning sharing mechanism and issued an interim order accepting the settlement and requiring the one-time bill credit be issued to customers. An order that will delineate the remaining parts of the settlement and conclude on the continuation of the earning sharing mechanism is expected by the end of 2020 and new rates will be effective on January 1, 2021.

    

In June 2020, Sierra Pacific filed with the PUCN a petition, which was later changed to an application, to adjudicate and establish the cost recovery mechanism for the One Nevada Transmission Line ("ON Line") addressing the reallocated portion of the ON Line revenue requirement. This filing was made concurrent with the Nevada Power regulatory rate review application, which addresses the ON Line reallocated revenue requirement related to Nevada Power. A hearing with the PUCN for the application is scheduled in November 2020.

 

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. The judicial review occurred in January 2020 and the district court issued an order in March 2020 denying the petition and affirming the PUCN's order. In May 2020, the Nevada Utilities filed a notice of appeal to the Nevada Supreme Court of the district court's order. The Nevada Utilities have agreed to withdraw the notice of appeal as a part of the Nevada Power electric regulatory rate review settlement. A final order on the settlement is expected by the end of 2020.

Customer Price Stability Tariff

In November 2018, the Nevada Utilities made filings with the PUCN to implement the Customer Price Stability Tariff ("CPST"). The Nevada Utilities have designed the CPST 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 that is based on renewable resources. The CPST provides for an energy rate that would replace the base tariff energy rate and DEAA. 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. In May 2020, the Nevada Utilities refiled the CPST incorporating the considerations raised by the PUCN and other intervenors. A hearing was held in September 2020 and an order is expected in November 2020.

Natural Disaster Protection Plan

In May 2019, Senate Bill 329 ("SB 329"), Natural Disaster Mitigation Measures, was signed into law, which requires the Nevada Utilities to submit a natural disaster protection plan to the PUCN. The PUCN adopted natural disaster protection plan regulations in January 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 submitted their initial natural disaster protection plan to the PUCN and filed their first application seeking recovery of 2019 expenditures in February 2020. In June 2020, a hearing was held and an order was issued in August 2020 that granted the joint application, made minor adjustments to the budget and approved the 2019 costs for recovery starting in October 2020. In October 2020, intervening parties filed petitions for reconsideration.

51

---

COVID-19

In March 2020, the PUCN issued an emergency order for the Nevada Utilities to establish regulatory asset accounts related to the costs of maintaining service to customers affected by COVID-19 whose services would have been terminated or disconnected under normally-applicable terms of service. The Nevada Utilities may incur significant costs as a result of COVID-19, including, but not limited to, higher credit loss expenses resulting from a higher than average level of write-offs of uncollectible accounts associated with the suspension of disconnections and late payment fees to assist customers facing unprecedented economic pressures. The Nevada Utilities also expect to incur additional costs that cannot currently be predicted given the unprecedented nature of COVID-19.

Northern Powergrid Distribution Companies

In July 2020, GEMA, through the Ofgem, published its draft determinations for transmission and gas distribution networks in Great Britain. These determinations do not apply directly to Northern Powergrid, as its next price control, ("ED2"), will begin in April 2023 and is subject to a separate process. However, Ofgem's determinations for other Great Britain energy networks are likely to be indicative for ED2. Regarding the allowed return on capital, Ofgem's draft determinations include an expected cost of equity of 3.95% (plus up to 0.25% if a sector does not outperform on incentive schemes and inflation calculated using the United Kingdom's consumer price index including owner occupiers' housing costs) with a 40% equity ratio regulatory assumption. This is approximately 250 basis points lower than the comparable cost of equity for Northern Powergrid's current regulatory settlement, after accounting for differences in the inflation index and equity ratio.

In September 2020, the Competition and Markets Authority ("CMA") published its provisional findings for price control redeterminations for four water companies that rejected their settlement. The CMA proposes to overturn the water regulator's proposal for a 4.2% cost of equity, replacing it with 5.08%. The CMA is the appeal body for energy network price control appeals, although energy networks do not have access to the same price control redetermination process.

In respect of Northern Powergrid's current price control ("ED1"), GEMA published a decision in October 2019 to make allowance for certain additional costs totaling £12 million, plus RPI inflation from 2012-13, 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, the 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, the 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 January 2020, the FERC approved Northern Natural Gas' filing to implement its interim rates subject to refund, effective January 1, 2020.

In June 2020, a settlement agreement was filed with the FERC, resolving the Section 5 investigation and Section 4 rate case and providing for increased service rates and depreciation rates. Market Area transportation reservation rates increased 28.5% and storage reservation rates increased 67.0% from the rates that were in effect in 2019. Depreciation rates are 2.3% for onshore transmission plant, 2.95% for LNG storage plant, 13.0% for intangible plant, and 2.75% for general plant. The settlement also provides for a Section 4 and Section 5 rate action moratorium through June 30, 2022, subject to certain exceptions, as well as provides for minimum annual maintenance capital spending. The settlement rates were implemented May 1, 2020, and the Company's provision for rate refunds for January 2020 through April 2020 totaled $69 million. The FERC approved the settlement in September 2020, and rate refunds to customers were processed in early October 2020.

52

---

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 April 2019, AltaLink filed an update to its 2019-2021 GTA 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.

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 was 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. In November 2019, the hearing to examine the excluded matters was completed and written arguments were filed in January 2020.

In October 2019, AltaLink filed a letter with the AUC to request the continuation of the monthly interim refundable transmission tariff effective January 1, 2020, until a final tariff is approved. In October 2019, the AUC confirmed the interim refundable transmission tariff at C$74 million per month, until otherwise directed by the AUC.

In April 2020, the AUC issued its decision with respect to AltaLink's 2019-2021 GTA. The AUC approved the negotiated settlement agreement as filed and rendered its decision and directions on the excluded matters. The AUC declined to approve AltaLink's proposed salvage methodology at that time, but indicated it would initiate a generic proceeding to review the matter on an industry-wide basis. Reverting the salvage method back to the traditional pre-collection approach increases the amount of salvage collected by approximately C$82 million, resulting in an increase to AltaLink's cash transmission tariffs collected from customers for the 2019-2021 period by approximately C$77 million. The AUC approved C$13 million of AltaLink's requested additional C$20 million of forecast transmission line clearance capital on placeholder basis and reviewed the remaining C$7 million capital investment in AltaLink's subsequent compliance filing. Also, C$3 million of forecast operating expenses and C$4 million of forecast capital investment were approved to reduce the risk of fires, with an additional C$31 million of capital reviewed in the compliance filing. Finally, the AUC approved C$6 million of retirements for towers and fixtures.

In July 2020, the AUC approved AltaLink's compliance filing establishing revised revenue requirements of C$895 million for 2019, C$894 million for 2020 and C$898 million for 2021, exclusive of the assets transferred to the PiikaniLink Limited Partnership and the KainaiLink Limited Partnership. The AUC also approved a revised monthly tariff of C$71 million for September 2020 to December 2020 and monthly tariff of C$74 million for 2021. The 2021 revenue requirement is based on 8.5% return on equity and 37% deemed equity set by the AUC as placeholders.

The AUC deferred its decision on AltaLink's proposed salvage methodology included in AltaLink's 2019-2021 GTA, pending a generic proceeding to consider the broader implications. This generic proceeding was closed and in July 2020, AltaLink filed an application with the AUC for the review and variance of the AUC's decision with respect to AltaLink's proposed salvage methodology. In September 2020, the AUC granted this review on the basis that there are changed circumstances that could lead the AUC to materially vary or rescind the majority hearing panel's findings on AltaLink's proposed salvage methodology. In October 2020, AltaLink filed responses to information requests from the AUC, written argument was filed by intervening parties and written reply argument was filed by AltaLink. A decision from the AUC is expected in January 2021.

        

53

---

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.

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.

In March 2020, as a result of COVID-19, the AUC suspended the proceeding for an indefinite period. This decision will be subject to review and reassessment by the AUC every 30 to 60 days. In May 2020, the AUC proposed a method to determine fair cost of capital parameters for 2021 given the circumstances presented by the COVID-19 pandemic. The AUC outlined four options for utilities and interested parties to consider and subsequently added a fifth option that sets the 2021 return on equity at 8.3% as a balance between certainty and economic conditions.

In July 2020, AltaLink requested that the AUC continue to hold the proceeding in abeyance and revisit the issue in another 30 to 60 days. AltaLink also requested that if the AUC determines the proceeding should resume, the AUC should set a date for the filing of evidence by all parties in the first quarter of 2021 and that the proceeding should address return on equity for 2021 and 2022 only.

In August 2020, the AUC issued a letter indicating that it had decided not to resume the GCOC proceeding at that time and would continue to assess when, and under what conditions, the proceeding could resume.

In October 2020, the AUC issued its decision and set the final approved return on equity and deemed equity ratio for AltaLink by extending the current approved 8.5% and 37%, respectively, for the duration of 2021.

2014-2015 Deferral Account Reconciliation Application

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.

AltaLink filed compliance filings in February and September 2019 reflecting the AUC's directives and AUC approval was received in November 2019. However, the AUC had previously 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.

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.

In March 2020, the AUC issued a letter indicating that it would provide further process steps after AltaLink submitted its remaining responses to information requests and the Consumers' Coalition of Alberta files its intervener evidence. In May 2020, AltaLink provided additional responses to information requests as directed by the AUC. In accordance with the AUC's revised process schedule, the Consumers' Coalition of Alberta filed its intervener evidence in June 2020, and AltaLink subsequently filed information requests on the intervener evidence in June 2020 and filed its rebuttal evidence in July 2020.

In August 2020, the AUC determined that a hearing is not required and issued a proceeding schedule to provide for argument, reply argument and the close of record by September 2020. In September 2020, AltaLink and interveners filed written argument and reply argument, and a decision from the AUC is expected by the end of 2020.

54

---

2019 Deferral Account Reconciliation Application

In October 2020, AltaLink filed its application with the AUC, which includes ten projects with total gross capital additions of C$129 million, including applicable AFUDC.

        

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 as of December 2017, 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 effective in January 2018. 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.

In March 2020, as a result of COVID-19, the AUC advised that it would be immediately deferring all public hearings, consultations or information sessions until further notice and requested FortisAlberta to advise the AUC whether it wishes to amend its motion. In April 2020, FortisAlberta filed its response requesting an oral hearing, to commence in 105 days.

In May 2020, the AUC denied FortisAlberta's request for an oral hearing, but requested expert tax evidence on three areas of disagreement between AltaLink and FortisAlberta. AltaLink and FortisAlberta filed expert evidence in July 2020. The AUC set a further process of information requests and responses and written submissions, which were scheduled to be completed in September 2020.

In September 2020, AltaLink and FortisAlberta filed a written argument and a reply argument. In November 2020, the AUC issued its decision with respect to FortisAlberta's review and variance proceeding. In its decision, the AUC rescinded its original September 2019 decision that directed (i) FortisAlberta to transfer the unamortized contribution balance of approximately C$375 million to AltaLink and (ii) the new contribution policy proposed by AltaLink be applied. The AUC's decision was based on two main areas: (i) if the original decision was confirmed, FortisAlberta would incur incremental income tax, carrying costs and debt restructuring costs of at least C$117 million that would be required to be recovered from ratepayers and (ii) the AUC determined that a majority of the approximately C$40 million in savings to ratepayers, which the hearing panel relied on as the basis for their original decision, can be achieved by directing FortisAlberta to adjust the applicable amortization rate for its AESO contributions to match the service lives of the transmission assets. The AUC will initiate a separate proceeding to (i) examine the legal basis of the current AESO customer contribution policy as it pertains to all transmission facility owners and distribution facility owners, (ii) consider whether there is a need for a new policy, including consideration of AltaLink's proposed policy and (iii) if approved, set the date on which any new policy would commence.

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 discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2019, and new environmental matters occurring in 2020.

55

---

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 the EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA.

New Source Performance Standards for Methane Emissions

In August 2020, the EPA finalized regulations to rescind standards for methane emissions from the oil and gas sector. The changes eliminate requirements to regulate methane emissions from the production, processing, transmission and storage of oil and gas. The rule was immediately challenged by environmental and tribal groups, as well as numerous states. In September 2020, the D.C. Circuit issued an administrative stay blocking the rule from taking effect while the court considers whether a long-term suspension is warranted. Until such time as litigation is exhausted, the relevant Registrants cannot determine whether additional action may be required.

National Ambient Air Quality Standards

Under the authority of the Clean Air Act, the EPA sets minimum NAAQS for six principal pollutants, consisting of carbon monoxide, lead, NO_x, particulate matter, ozone and SO₂, 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 NAAQS.

In December 2012, the EPA finalized more stringent fine particulate matter NAAQS, 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 June 2020, the EPA proposed a determination of attainment for the 2006 24-hour fine particulate matter for Salt Lake City and Provo serious nonattainment areas. The determination is based upon quality-assured, quality controlled and certified ambient air monitoring data showing that the area has attained the 2006 standard based on the 2017-2019 monitoring. The comment period for the proposal ended in August 2020.

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 in April 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 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.

56

---

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.

In December 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. The EPA proposed to determine that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112; however, the EPA proposed to retain the emission standards and other requirements of the MATS rule, because the EPA did not propose to remove coal- and oil-fueled power plants from the list of sources regulated under Section 112. In May 2020, the EPA published its decision to repeal the appropriate and necessary findings in the MATS rule and retain the overall emission standards. The rule took effect in July 2020. A number of petitions for review were filed in the D.C. Circuit by parties challenging and supporting the EPA's decision to rescind the appropriate and necessary finding. Until litigation over the rule is exhausted, the relevant Registrants cannot fully determine the impacts of the changes to the MATS rule.

In March 2020, the D.C. Circuit issued an opinion in Chesapeake Climate Action Network v. EPA regarding consolidated challenges to the EPA's startup and shutdown provisions contained in the 2012 MATS rule. The MATS rule's provisions governing startup and shutdown require electric generating units comply with work practice standards as opposed to numerical limits during these periods. The EPA denied petitions for reconsideration of these provisions in 2016 and environmentalists challenged this denial. The D.C. Circuit vacated the reconsideration denials, remanding the petition to the EPA for further action. The court did not make a determination on the merits of the arguments concerning the EPA's legal authority to set work practice standards. The existing work practice standards and the alternate definition for when startup ends continue to be applicable. Until the EPA finalizes action to respond to the court's order, the relevant Registrants cannot fully determine the impacts of the remand.

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.

57

---

The state of Utah issued a regional haze SIP requiring the installation of SO₂, NO_x and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the SO₂ portion of the Utah regional haze SIP and disapproved the NO_x 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 NO_x controls and require the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. The EPA's final action on the Utah regional haze SIP was effective in August 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 dispersion model. In January 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. In June 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporates a BART alternative into Utah's regional haze SIP. The BART alternative makes the shutdown of PacifiCorp's Carbon plant enforceable under the SIP and removes the requirement to install SCR technology on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of Air Quality submitted the SIP revision to the EPA for approval by the end of 2019.

In January 2020, the EPA published its proposed approval of the Utah Regional Haze SIP Alternative, which makes the shutdown of the Carbon plant federally enforceable and adopts as BART the existing NO_x controls and emission limits on the Hunter and Huntington plants. The proposed approval withdraws the FIP requirements for the Hunter and Huntington plants to install SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With the approval, the EPA also finalized its withdrawal of the FIP requirements for the Hunter and Huntington plants. The Utah Regional Haze SIP Alternative will take effect 30 days after publication in the Federal Register.

The state of Wyoming issued two regional haze SIPs requiring the installation of SO₂, NO_x and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the SO₂ 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 NO_x and particulate matter SIP and instead issue a FIP. The EPA withdrew its initial proposed actions on the NO_x 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-NO_x 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-NO_x 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 in March 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 with settlement negotiations ongoing. In September 2020, specific parties reached a settlement agreement in principle, which would resolve the appeal, and are working to finalize a written agreement in the fourth quarter of 2020. In May 2020, the Wyoming Air Quality Division issued a permit approving PacifiCorp's monthly and annual NO_x and SO₂ emission limits on the four Jim Bridger units. Also in May 2020, the Wyoming Department of Environmental Quality submitted a regional haze SIP revision to the EPA. The revised SIP grants approval of PacifiCorp's Jim Bridger reasonable progress reassessment application and incorporates PacifiCorp's proposed emission limits in lieu of the requirement to install SCR systems on Jim Bridger Units 1 and 2. PacifiCorp anticipates the EPA will initiate a public comment process during the fourth quarter of 2020 as part of the federal review and approval process.

58

---

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. In April 2014, the EPA and the United States Army Corps of Engineers ("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. In January 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. In July 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 in September 2019. In January 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. In December 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. In January 2020, the EPA and the 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 took effect in June 2020, redefines what waters qualify as navigable waters of the United States 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 EPA and the Corps of Engineers 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.

In April 2020, the United States Supreme Court established a new test for Clean Water Act jurisdiction in County of Maui, Hawaii v. Hawaii Wildlife Fund, finding that the statute can cover discharges of contaminated groundwater in certain circumstances. The United States Supreme Court outlined a seven-factor test to determine whether discharges conveyed through groundwater to surface water are "functionally equivalent" to direct discharges, finding that the time it takes for pollutants to travel through groundwater and the distance traveled are the two most important factors in the test. The United States Supreme Court remanded County of Maui, Hawaii to the Ninth Circuit Court of Appeals for further adjudication, which subsequently remanded the case to the district court to determine whether additional discovery is needed before applying the new seven-factor test. Until the functional equivalent test is applied by the courts, the Registrants cannot determine the impact of this case on their operations.

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 Resource Conservation and Recovery Act. The final rule was released by the EPA in December 2014, was published in the Federal Register in April 2015 and was effective in October 2015. The final rule regulates coal combustion byproducts as non-hazardous waste under the Resource Conservation and Recovery Act Subtitle D and establishes minimum nationwide standards for the disposal of CCR. 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.

59

---

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 facility. 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 in or before December 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.

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 in November 2017 over certain portions of the 2015 rule that had not been settled or otherwise remanded. In August 2018, the D.C. Circuit issued its opinion in Utility Solid Waste Activities Group v. EPA, finding it was arbitrary and capricious for the 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 the EPA for reconsideration with specific instructions to consider harm to the environment, not just to human health. The D.C. Circuit also held the EPA's decision to not regulate legacy ponds was arbitrary and capricious. While the D.C. Circuit's decision was pending, the EPA, in March 2018, issued a proposal to address provisions of the final CCR rule that were remanded back to the agency in June 2016, by the D.C. Circuit. The proposal included provisions that establish alternative performance standards for owners and operators of CCR units located in states that have approved permit programs or are otherwise subject to oversight through a permit program administered by the EPA. The first phase of the CCR rule amendments was finalized by the EPA in July 2018 and made effective in August 2018 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater performance standards for certain constituents, the 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 2020. Following the March 2019 submittal of competing motions from environmental groups and the EPA to stay or remand this deadline extension, the D.C. Circuit granted the EPA's request to remand the rule and left the October 2020 deadline in place while the agency undertakes a new rulemaking establishing a new deadline for initiating closure. In August 2019, the EPA released its "Phase 2" proposal, which contains targeted amendments to the CCR rule in response to court remands and the 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 CCR 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 CCR 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 CCR rule. The EPA accepted comments on the Phase 2 proposal through October 2019.

60

---

In September 2020, the EPA finalized its Holistic Approach to Closure: Part A rule ("Part A rule") in response to the D.C. Circuit's revocation of certain provisions of the CCR rule and to clarify certain other provisions of the rule. The Part A rule reclassifies compacted-soil lined surface impoundments from "lined" to "unlined," establishes a deadline of April 11, 2021, by which all unlined surface impoundments must initiate closure, and revises the alternative closure provisions to grant facilities additional time to initiate closure in order to manage CCR and non-CCR wastestreams either due to a lack of alternative capacity or with a commitment to closure the coal-fueled operating unit and complete closure of unlined impoundments by a date certain. The Part A rule also revises certain requirements regarding annual groundwater monitoring and corrective action reports and publicly accessible CCR internet sites. MidAmerican Energy and NV Energy have already initiated closure or will initiate closure of all surface impoundments by April 11, 2021. On October 16, 2020, the EPA released the pre-publication version of the final Holistic Approach to Closure: Part B rule ("Part B rule"). The Part B rule finalizes a two-step process, as set forth in the March 2020 proposal, allowing facilities to request approval to continue operating an existing unlined CCR surface impoundment with an alternate liner system. The other provisions that were contained in the Part B proposal, including (1) options to use CCR during closure of a CCR unit, (2) an additional closure-by-removal option and (3) new requirements for annual closure progress reports, were not finalized with the Part B rule. These options will be addressed by the EPA in a subsequent rulemaking action. In addition to the Part A and Part B rules, the EPA has proposed the Phase II rule, the federal CCR permit program rule, and the advanced notice of proposed rulemaking for legacy impoundments. Until the proposals are finalized and fully litigated, the Registrants cannot determine whether additional action may be required.

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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2019. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2019.

61

---

PacifiCorp and its subsidiaries

Consolidated Financial Section

62

---

PART I

Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PacifiCorp

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of September 30, 2020, the related consolidated statements of operations and changes in shareholders' equity for the three-month and nine-month periods ended September 30, 2020 and 2019, and of cash flows for the nine-month periods ended September 30, 2020 and 2019, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

 

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of PacifiCorp as of December 31, 2019, and the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 21, 2020, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2019, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of PacifiCorp's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

/s/ Deloitte & Touche LLP

 

Portland, Oregon

November 6, 2020

63

---

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

		As of
		September 30,				December 31,
		2020				2019
ASSETS
Current assets:
Cash and cash equivalents		$	590			$	30
Trade receivables, net		730				644
Other receivables, net		38				70
Inventories		491				394
Other current assets		233				152
Total current assets		2,082				1,290
Property, plant and equipment, net		22,042				20,973
Regulatory assets		952				1,060
Other assets		451				374
Total assets		$	25,527			$	23,697

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

64

---

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

		As of
		September 30,				December 31,
		2020				2019
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable		$	764			$	679
Accrued interest		114				116
Accrued property, income and other taxes		180				96
Accrued employee expenses		124				75
Short-term debt		—				130
Current portion of long-term debt		438				38
Other current liabilities		235				226
Total current liabilities		1,855				1,360
Long-term debt		8,211				7,620
Regulatory liabilities		2,847				2,913
Deferred income taxes		2,583				2,563
Other long-term liabilities		965				804
Total liabilities		16,461				15,260
Commitments and contingencies (Note 9)
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		4,600				3,972
Accumulated other comprehensive loss, net		(15		)		(16		)
Total shareholders' equity		9,066				8,437
Total liabilities and shareholders' equity		$	25,527			$	23,697

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

65

---

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Operating revenue	$	1,479			$	1,367			$	3,829			$	3,793
Operating expenses:
Cost of fuel and energy	499				464				1,299				1,313
Operations and maintenance	332				252				829				763
Depreciation and amortization	234				272				696				686
Property and other taxes	53				46				154				146
Total operating expenses	1,118				1,034				2,978				2,908
Operating income	361				333				851				885
Other income (expense):
Interest expense	(107		)		(101		)		(319		)		(299		)
Allowance for borrowed funds	14				11				36				26
Allowance for equity funds	29				21				73				51
Interest and dividend income	2				5				8				17
Other, net	5				6				9				22
Total other income (expense)	(57		)		(58		)		(193		)		(183		)
Income before income tax expense (benefit)	304				275				658				702
Income tax expense (benefit)	18				(3		)		30				77
Net income	$	286			$	278			$	628			$	625

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

66

---

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)

(Amounts in millions)

																		Accumulated
										Additional								Other				Total
		Preferred				Common				Paid-in				Retained				Comprehensive				Shareholders'
		Stock				Stock				Capital				Earnings				Loss, Net				Equity
Balance, June 30, 2019		$	2			$	—			$	4,479			$	3,548			$	(12	)		$	8,017
Net income		—				—				—				278				—				278
Balance, September 30, 2019		$	2			$	—			$	4,479			$	3,826			$	(12	)		$	8,295
Balance, December 31, 2018		$	2			$	—			$	4,479			$	3,377			$	(13	)		$	7,845
Net income		—				—				—				625				—				625
Other comprehensive (loss) income		—				—				—				(1		)		1				—
Common stock dividends declared		—				—				—				(175		)		—				(175		)
Balance, September 30, 2019		$	2			$	—			$	4,479			$	3,826			$	(12	)		$	8,295
Balance, June 30, 2020		$	2			$	—			$	4,479			$	4,314			$	(15	)		$	8,780
Net income		—				—				—				286				—				286
Balance, September 30, 2020		$	2			$	—			$	4,479			$	4,600			$	(15	)		$	9,066
Balance, December 31, 2019		$	2			$	—			$	4,479			$	3,972			$	(16	)		$	8,437
Net income		—				—				—				628				—				628
Other comprehensive income		—				—				—				—				1				1
Balance, September 30, 2020		$	2			$	—			$	4,479			$	4,600			$	(15	)		$	9,066

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

67

---

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2020				2019
Cash flows from operating activities:
Net income	$	628			$	625
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	696				686
Allowance for equity funds	(73		)		(51		)
Changes in regulatory assets and liabilities	(17		)		(31		)
Deferred income taxes and amortization of investment tax credits	(48		)		(78		)
Other, net	2				(3		)
Changes in other operating assets and liabilities:
Trade receivables, other receivables and other assets	(154		)		21
Inventories	(97		)		(4		)
Derivative collateral, net	22				5
Accrued property, income and other taxes, net	84				99
Accounts payable and other liabilities	248				(2		)
Net cash flows from operating activities	1,291				1,267
Cash flows from investing activities:
Capital expenditures	(1,618		)		(1,449		)
Other, net	31				9
Net cash flows from investing activities	(1,587		)		(1,440		)
Cash flows from financing activities:
Proceeds from long-term debt	987				990
Repayments of long-term debt	—				(350		)
Net repayments of short-term debt	(130		)		(30		)
Dividends paid	—				(175		)
Other, net	—				(2		)
Net cash flows from financing activities	857				433
Net change in cash and cash equivalents and restricted cash and cash equivalents	561				260
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	36				92
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	597			$	352

 

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

68

---

PACIFICORP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)	General

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").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2020 and for the three- and nine-month periods ended September 30, 2020 and 2019. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and nine-month periods ended September 30, 2020 and 2019. The results of operations for the three- and nine-month periods ended September 30, 2020 and 2019 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2019 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in PacifiCorp's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2020.

Coronavirus Disease 2019 ("COVID-19")

In March 2020, COVID‑19 was declared a global pandemic and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and on economic conditions in the United States. COVID-19 has impacted many of PacifiCorp's customers ranging from high unemployment levels, an inability to pay bills and business closures or operating at reduced capacity levels. While COVID‑19 has impacted PacifiCorp's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. These impacts include, but are not limited to, lower operating revenue from reductions in the consumption of electricity by retail utility customers, particularly in the commercial and industrial customer classes, and higher bad debt expense resulting from a higher than average level of write-offs of uncollectible accounts associated with the suspension of disconnections across PacifiCorp's service territory and suspension of late payment fees in certain jurisdictions implemented to assist customers. While PacifiCorp does not currently expect a significant increase in employer contributions to its retirement plans, continued market volatility caused by COVID-19 may lead to increased contributions in the future. The duration and extent of COVID‑19 and its future impact on PacifiCorp's business cannot be reasonably estimated at this time and the longer-term impacts of COVID-19 and related customer and governmental responses remain uncertain. Accordingly, significant estimates used in the preparation of PacifiCorp's unaudited Consolidated Financial Statements, including those associated with evaluations of certain long-lived assets for impairment, expected credit losses on amounts owed to PacifiCorp and potential regulatory deferral or recovery of certain costs may be subject to significant adjustments in future periods.

69

---

In March and April 2020, PacifiCorp filed applications requesting authorization to defer costs associated with COVID‑19 with the Utah Public Service Commission ("UPSC"), the Oregon Public Utility Commission ("OPUC"), the Wyoming Public Service Commission ("WPSC"), the Washington Utilities and Transportation Commission and the Idaho Public Utilities Commission ("IPUC"). In April 2020, as ordered by the California Public Utilities Commission, PacifiCorp filed to establish the COVID‑19 Pandemic Protections Memorandum Account. The memorandum account was approved in September 2020, retroactive to March 4, 2020. In April 2020, the WPSC approved PacifiCorp's application to defer costs associated with COVID‑19, subject to a public notice period, and required associated benefits arising from COVID‑19 to be offset against the deferred costs. During the public notice period, one party to the proceeding filed a petition for a rehearing of the matter. In July, September and October 2020, the IPUC, the UPSC and the OPUC, respectively, approved PacifiCorp's applications to defer costs associated with COVID‑19, requiring associated benefits arising from COVID‑19 to be offset against the deferred costs.

(2)	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 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. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2020 and December 31, 2019, 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
	September 30,				December 31,
	2020				2019
Cash and cash equivalents	$	590			$	30
Restricted cash included in other current assets	4				4
Restricted cash included in other assets	3				2
Total cash and cash equivalents and restricted cash and cash equivalents	$	597			$	36

(3)	Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):

			As of
			September 30,				December 31,
	Depreciable Life		2020				2019
Utility Plant:
Generation	14 - 67 years		$	12,475			$	12,509
Transmission	58 - 75 years		6,687				6,482
Distribution	20 - 70 years		7,522				7,307
Intangible plant(1)	5 - 75 years		1,027				1,016
Other	5 - 60 years		1,483				1,449
Utility plant in service			29,194				28,763
Accumulated depreciation and amortization			(9,886		)		(9,803		)
Utility plant in-service, net			19,308				18,960
Other non-regulated, net of accumulated depreciation and amortization	59 years		9				10
Plant, net			19,317				18,970
Construction work-in-progress			2,725				2,003
Property, plant and equipment, net			$	22,042			$	20,973

(1)	Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years.

70

---

During the nine-month period ended September 30, 2020, PacifiCorp acquired wind turbines from BHE Wind, LLC, an indirect wholly owned subsidiary of BHE, for $147 million. The wind turbines will be installed as part of newly constructed wind-powered generating facilities that are planned to be placed in service in 2020 and 2021.

(4)	Recent Financing Transactions

Long-Term Debt

In April 2020, PacifiCorp issued $400 million of its 2.70% First Mortgage Bonds due 2030 and $600 million of its 3.30% First Mortgage Bonds due 2051. PacifiCorp intends to use the net proceeds to fund capital expenditures, primarily for renewable resources and associated transmission projects, and for general corporate purposes.

(5)	Income Taxes

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:

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2020			2019			2020			2019
Federal statutory income tax rate	21	%		21	%		21	%		21	%
State income tax, net of federal income tax benefit	3			3			3			3
Federal income tax credits	(15	)		(3	)		(12	)		(4	)
Effects of ratemaking	(2	)		(3	)		(2	)		(2	)
Amortization of excess deferred income taxes	(2	)		(18	)		(6	)		(7	)
Other	1			(1	)		1			—
Effective income tax rate	6	%		(1	)%		5	%		11	%

Income tax credits relate primarily to production tax credits ("PTCs") 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 for the nine-month periods ended September 30, 2020 and 2019 is primarily attributable to the amortization of $30 million and $49 million, respectively, 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.

Berkshire Hathaway includes BHE and its subsidiaries in its United States federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for federal and state income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. For the nine-month periods ended September 30, 2020 and 2019, PacifiCorp made net cash payments for federal and state income tax to BHE totaling $79 million and $128 million, respectively.

71

---

(6)	Employee Benefit Plans

Net periodic benefit credit for the pension and other postretirement benefit plans included the following components (in millions):

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Pension:
Service cost	$	—			$	—			$	—			$	—
Interest cost	9				11				27				33
Expected return on plan assets	(14		)		(17		)		(42		)		(50		)
Net amortization	4				3				13				9
Net periodic benefit credit	$	(1	)		$	(3	)		$	(2	)		$	(8	)
Other postretirement:
Service cost	$	—			$	—			$	1			$	1
Interest cost	2				3				7				9
Expected return on plan assets	(3		)		(6		)		(10		)		(16		)
Net amortization	—				1				—				1
Net periodic benefit credit	$	(1	)		$	(2	)		$	(2	)		$	(5	)

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $- million, respectively, during 2020. As of September 30, 2020, $3 million of contributions had been made to the pension plans.

(7)	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 regulated 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, geopolitical factors, 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, manage 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.

There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Note 8 for additional information on derivative contracts.

72

---

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 September 30, 2020
Not designated as hedging contracts(1):
Commodity assets	$	44			$	11			$	2			$	—			$	57
Commodity liabilities	(2		)		—				(31		)		(33		)		(66		)
Total	42				11				(29		)		(33		)		(9		)
Total derivatives	42				11				(29		)		(33		)		(9		)
Cash collateral receivable	—				—				14				11				25
Total derivatives - net basis	$	42			$	11			$	(15	)		$	(22	)		$	16
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	)

(1)	PacifiCorp's commodity derivatives are generally included in rates and as of September 30, 2020 and December 31, 2019, a regulatory asset of $9 million and $62 million, respectively, was recorded related to the net derivative liability of $9 million and $63 million, respectively.

The following table reconciles the beginning and ending balances of PacifiCorp's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Beginning balance	$	68			$	101			$	62			$	96
Changes in fair value	(49		)		16				(21		)		(12		)
Net gains (losses) reclassified to operating revenue	1				(11		)		14				(27		)
Net (losses) gains reclassified to cost of fuel and energy	(11		)		(25		)		(46		)		24
Ending balance	$	9			$	81			$	9			$	81

73

---

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 (in millions):

	Unit of		September 30,			December 31,
	Measure		2020			2019
Electricity sales, net	Megawatt hours		(2	)		(2	)
Natural gas purchases	Decatherms		102			129

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 derivative contracts 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 PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2020, 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 $62 million and $80 million as of September 30, 2020 and December 31, 2019, respectively, for which PacifiCorp had posted collateral of $25 million and $47 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 September 30, 2020 and December 31, 2019, PacifiCorp would have been required to post $33 million and $27 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.

74

---

(8)	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 financial 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 September 30, 2020
Assets:
Commodity derivatives		$	—			$	57			$	—			$	(4	)		$	53
Money market mutual funds(2)		587				—				—				—				587
Investment funds		25				—				—				—				25
		$	612			$	57			$	—			$	(4	)		$	665
Liabilities - Commodity derivatives		$	—			$	(66	)		$	—			$	29			$	(37	)
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	)

(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $25 million and $47 million as of September 30, 2020 and December 31, 2019, 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.

75

---

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 7 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. 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 (in millions):

		As of September 30, 2020								As of December 31, 2019
		Carrying				Fair				Carrying				Fair
		Value				Value				Value				Value
Long-term debt		$	8,649			$	10,860			$	7,658			$	9,280

(9)	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. PacifiCorp 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 and are described below.

76

---

California and Oregon 2020 Wildfires

In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damage, personal injuries and loss of life and widespread power outages in Oregon and California (the "2020 Wildfires"). The wildfires have spread across certain parts of PacifiCorp's service territory and surrounding areas in Oregon and California. Certain of the wildfires are still burning and are at various levels of containment. Investigations into the cause and origin of each wildfire are complex and ongoing. Although those investigations are not complete, several civil actions (including a putative class action complaint) have been filed in Oregon on behalf of citizens and businesses who suffered damages from fires allegedly caused by PacifiCorp. The final determinations of liability, however, will only be made following comprehensive investigations and litigation processes. In California, under the doctrine of inverse condemnation, courts have held investor-owned utilities liable for property damages along with associated interest and attorneys' fees where its facilities are a substantial cause of a wildfire that caused the property damage, even if the utility is not at fault. To date, no lawsuits arising from the 2020 Wildfires have been filed in California. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its equipment. Even if inverse condemnation or other provisions do not apply, PacifiCorp could nevertheless be found liable for all damages proximately caused by negligence, including property damage, fire suppression costs, personal injury damages and interest.

PacifiCorp has accrued its best estimate of the potential losses associated with the 2020 Wildfires that are considered probable of being incurred. Given the early stages of the investigations into the cause and origin of the 2020 Wildfires and the uncertainty surrounding potential damages, it is reasonably possible PacifiCorp may incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred. PacifiCorp has some level of insurance coverage that may apply to damages caused by wildfires, but it may be insufficient to cover all such damages. PacifiCorp has accrued its best estimate of the expected probable insurance recovery associated with the estimated losses accrued.

Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local 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 PacifiCorp's current and future operations. PacifiCorp 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.

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. The FERC approved partial transfer of the Klamath license in July 2020, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and its customers. The order does not immediately take effect and PacifiCorp is working with its settlement partners to implement the agreement.

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.

77

---

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.

(10)	Revenue from Contracts with Customers

The following table summarizes PacifiCorp's revenue from contracts with customers ("Customer Revenue") by customer class (in millions):

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Customer Revenue:
Retail:
Residential	$	519			$	478			$	1,363			$	1,316
Commercial	418				419				1,122				1,152
Industrial	293				306				838				887
Other retail	114				100				209				203
Total retail	1,344				1,303				3,532				3,558
Wholesale	59				8				76				47
Transmission	33				26				79				76
Other Customer Revenue	42				17				88				55
Total Customer Revenue	1,478				1,354				3,775				3,736
Other revenue	1				13				54				57
Total operating revenue	$	1,479			$	1,367			$	3,829			$	3,793

78

---

Item 2.	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 PacifiCorp's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10‑Q. PacifiCorp's actual results in the future could differ significantly from the historical results.

Results of Operations for the Third Quarter and First Nine Months of 2020 and 2019

Overview

Net income for the third quarter of 2020 was $286 million, an increase of $8 million, or 3%, compared to 2019. Net income increased primarily due to higher utility margin of $50 million (excluding the impacts of the Oregon RAC settlement of $27 million offset in depreciation expense), higher PTCs recognized of $35 million due to repowered wind-powered generating facilities and higher allowances for equity and borrowed funds used during construction of $11 million, partially offset by higher operations and maintenance expenses of $80 million primarily due to costs associated with the KHSA and wildfires, higher property taxes of $7 million and higher interest expense of $6 million. Utility margin increased primarily due to higher wholesale and retail revenues, lower coal-fueled generation volumes and lower purchased electricity prices, partially offset by lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms and higher purchased electricity volumes. Retail customer volumes remained relatively unchanged primarily due to the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by the favorable impact of weather and an increase in the average number of customers. Energy generated decreased 4% for the third quarter of 2020 compared to 2019 primarily due to lower coal-fueled and hydroelectric generation, partially offset by higher wind-powered and natural gas-fueled generation. Wholesale electricity sales volumes increased 9% and purchased electricity volumes increased 18%.

Net income for the first nine months of 2020 was $628 million, an increase of $3 million compared to 2019. Net income increased primarily due to higher PTCs recognized of $52 million due to repowered wind-powered generating facilities, higher allowances for equity and borrowed funds used during construction of $32 million and higher utility margin of $16 million (excluding the impacts of the Oregon RAC settlement of $34 million offset in depreciation expense), partially offset by higher operations and maintenance expenses of $66 million primarily due to costs associated with the KHSA and wildfires, higher interest expense of $20 million, higher pension and other postretirement costs of $10 million and increased property taxes of $8 million. Utility margin increased primarily due to lower coal-fueled generation volumes, higher wholesale and retail sales prices, lower purchased electricity prices and lower natural gas-fueled generation costs, partially offset by lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms, lower retail and wholesale customer sales volumes, higher purchased electricity volumes and higher coal-fueled generation prices. Retail customer volumes decreased 1.8% primarily due to the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by an increase in the average number of customers and the favorable impact of weather. Energy generated decreased 5% for the first nine months of 2020 compared to 2019 primarily due to lower coal-fueled and natural gas-fueled generation, partially offset by higher wind-powered and hydroelectric generation. Wholesale electricity sales volumes decreased 14% and purchased electricity volumes increased 9%.

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 directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in PacifiCorp's revenue are comparable to changes in such expenses. 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.

79

---

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 comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):

	Third Quarter															First Nine Months
	2020				2019				Change							2020				2019				Change
Utility margin:
Operating revenue	$	1,479			$	1,367			$	112			8	%		$	3,829			$	3,793			$	36			1	%
Cost of fuel and energy	499				464				35				8			1,299				1,313				(14		)		(1	)
Utility margin	980				903				77				9			2,530				2,480				50				2
Operations and maintenance	332				252				80				32			829				763				66				9
Depreciation and amortization	234				272				(38		)		(14	)		696				686				10				1
Property and other taxes	53				46				7				15			154				146				8				5
Operating income	$	361			$	333			$	28			8	%		$	851			$	885			$	(34	)		(4	)%

80

---

A comparison of PacifiCorp's key operating results is as follows:

	Third Quarter															First Nine Months
	2020				2019				Change							2020				2019				Change
Utility margin (in millions):
Operating revenue	$	1,479			$	1,367			$	112			8	%		$	3,829			$	3,793			$	36			1	%
Cost of fuel and energy	499				464				35				8			1,299				1,313				(14		)		(1	)
Utility margin	$	980			$	903			$	77			9	%		$	2,530			$	2,480			$	50			2	%
Sales (GWhs):
Residential	4,622				4,298				324				8	%		12,699				12,213				486				4	%
Commercial	4,799				4,877				(78		)		(2	)		13,157				13,622				(465		)		(3	)
Industrial, irrigation and other	5,446				5,686				(240		)		(4	)		14,907				15,693				(786		)		(5	)
Total retail	14,867				14,861				6				—			40,763				41,528				(765		)		(2	)
Wholesale	1,053				962				91				9			3,266				3,778				(512		)		(14	)
Total sales	15,920				15,823				97				1	%		44,029				45,306				(1,277		)		(3	)%
Average number of retail customers  (in thousands)	1,971				1,935				36				2	%		1,963				1,928				35				2	%
Average revenue per MWh:
Retail	$	90.25			$	87.64			$	2.61			3	%		$	86.60			$	85.65			$	0.95			1	%
Wholesale	$	57.54			$	21.08			$	36.46			173	%		$	38.58			$	26.58			$	12.00			45	%
Heating degree days	194				271				(77		)		(28	)%		6,132				6,739				(607		)		(9	)%
Cooling degree days	1,658				1,462				196				13	%		2,097				1,773				324				18	%
Sources of energy (GWhs)(1):
Coal	8,576				9,391				(815		)		(9	)%		22,001				25,059				(3,058		)		(12	)%
Natural gas	3,638				3,619				19				1			8,881				8,995				(114		)		(1	)
Hydroelectric(2)	414				480				(66		)		(14	)		2,351				2,211				140				6
Wind and other(2)	720				353				367				104			2,696				1,710				986				58
Total energy generated	13,348				13,843				(495		)		(4	)		35,929				37,975				(2,046		)		(5	)
Energy purchased	3,621				3,071				550				18			11,245				10,357				888				9
Total	16,969				16,914				55				—	%		47,174				48,332				(1,158		)		(2	)%
Average cost of energy per MWh:
Energy generated(3)	$	18.65			$	19.17			$	(0.52	)		(3	)%		$	17.95			$	19.41			$	(1.46	)		(8	)%
Energy purchased	$	53.28			$	62.25			$	(8.97	)		(14	)%		$	45.85			$	49.88			$	(4.03	)		(8	)%

(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.

81

---

Utility margin increased $77 million for the third quarter of 2020 compared to 2019 primarily due to:

•	$40 million of higher wholesale revenue primarily due to higher average market prices and higher volumes;

•

$39 million of higher retail revenue primarily due to price impacts from changes in sales mix and higher retail customer volumes. While retail volume changes contributed to the increase in retail revenue due to favorable weather impacts, higher average number of customers and changes in sales mix, overall retail volumes were relatively flat due to the offsetting net impacts of decreases in commercial and industrial customer usage and increased residential customer usage driven by COVID-19;

•	$27 million of higher other revenue due to impacts of the Oregon RAC settlement (offset in depreciation expense); and

•	$15 million of lower coal-fueled generation costs primarily due to lower volumes.

The increases above were partially offset by:

•	$52 million of lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms; and

•	$2 million of higher purchased electricity costs primarily due to higher volumes, partially offset by lower average market prices.

Operations and maintenance increased $80 million, or 32%, for the third quarter of 2020 compared to 2019 primarily due to costs associated with the KHSA, increased wildfire and storm related costs, and increased bad debt expense.

Depreciation and amortization decreased $38 million, or 14%, for the third quarter of 2020 compared to 2019 primarily due to prior year accelerated depreciation of $65 million (offset in income tax expense) for Oregon's share of certain retired wind equipment due to repowering, compared to current year accelerated depreciation of $27 million (offset in other revenue), due to the Oregon RAC settlement.

Property and other taxes increased $7 million, or 15%, for the third quarter of 2020 compared to 2019 primarily due to higher property taxes in Oregon and Utah.

 

Interest expense increased $6 million, or 6% for the third quarter of 2020 compared to 2019 primarily due to higher average long-term debt balances, partially offset by a lower weighted average long-term debt interest rate.

Allowance for borrowed and equity funds increased $11 million, or 34%, for the third quarter of 2020 compared to 2019 primarily due to higher qualified construction work-in-progress balances.

Interest and dividend income decreased $3 million, or 60%, for the third quarter of 2020 compared to 2019 primarily due to lower interest rates in the current year.

Income tax expense increased $21 million, for the third quarter of 2020 compared to the third quarter of 2019. The effective tax rate was 6% for 2020 and (1)% for 2019. The effective tax rate increased primarily due to lower amortization of Oregon's allocated excess deferred income taxes pursuant to the Oregon RAC settlement, 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, partially offset by increased PTCs from PacifiCorp's repowered wind-powered generating facilities.

Utility margin increased $50 million for the first nine months of 2020 compared to 2019 primarily due to:

•	$74 million of lower coal-fueled generation costs primarily due to lower volumes, partially offset by higher prices;

•	$34 million of higher other revenue due to impacts of the Oregon RAC settlement (offset in depreciation expense);

•	$26 million of higher wholesale revenue due to higher average market prices, partially offset by lower volumes;

•	$20 million of lower natural gas-fueled generation costs due to lower natural gas prices and lower volumes;

•	$8 million from favorable wheeling activities; and

•	$1 million of lower purchased electricity costs primarily due to lower average market prices, partially offset by higher volumes.

82

---

The increases above were partially offset by:

•	$87 million of lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms; and

•

$27 million of lower retail revenue from lower volumes, partially offset by price impacts from changes in sales mix. Retail customer volumes decreased 1.8% primarily due to the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by an increase in the average number of customers and the favorable impact of weather.

Operations and maintenance increased $66 million, or 9%, for the first nine months of 2020 compared to 2019 primarily due to costs associated with the KHSA, increased wildfire and storm related costs, higher vegetation management costs and increased bad debt expense.

Depreciation and amortization increased $10 million, or 1%, for the first nine months of 2020 compared to 2019, primarily due to current year accelerated depreciation of $74 million ($34 million offset in other revenue and $40 million offset in income tax expense) as a result of the Oregon RAC settlement, partially offset by prior year accelerated depreciation of $65 million (offset in income tax expense) on Oregon's share of certain retired wind equipment due to repowering.

Property and other taxes increased $8 million, or 5% for the first nine months of 2020 compared to 2019, primarily due to higher property taxes in Oregon and Utah.

Interest expense increased $20 million, or 7% for the first nine months of 2020 compared to 2019 primarily due to higher average long-term debt balances, partially offset by a lower weighted average long-term debt interest rate.

Allowance for borrowed and equity funds increased $32 million, or 42%, for the first nine months of 2020 compared to 2019 primarily due to higher qualified construction work-in-progress balances.

Interest and dividend income decreased $9 million, or 53%, for the first nine months of 2020 compared to 2019 primarily due to lower interest rates in the current year.

Other, net decreased $13 million, or 59% for the first nine months of 2020 compared to 2019 primarily due to higher pension and other postretirement costs of $10 million.

Income tax expense decreased $47 million, or 61%, for the first nine months of 2020 compared to 2019. The effective tax rate was 5% for 2020 and 11% for 2019. The effective tax rate decreased primarily due to increased PTCs from PacifiCorp's repowered wind-powered generating facilities, partially offset by lower amortization of Oregon's allocated excess deferred income taxes pursuant to the Oregon RAC settlement 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.

Liquidity and Capital Resources

 

As of September 30, 2020, PacifiCorp's total net liquidity was as follows (in millions):

Cash and cash equivalents		$	590
Credit facilities		1,200
Less:
Tax-exempt bond support		(256		)
Net credit facilities		944
Total net liquidity		$	1,534
Credit facilities:
Maturity dates		2022

83

---

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2020 and 2019 were $1,291 million and $1,267 million, respectively. The change was primarily due to lower cash paid for income taxes and lower operating expense payments due to timing, partially offset by lower collections from retail customers.

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 nine-month periods ended September 30, 2020 and 2019 were $(1,587) million and $(1,440) million, respectively. The change is primarily due to an increase in capital expenditures of $169 million, partially offset by proceeds from the settlement of notes receivable of $25 million associated with the sale of certain Utah mining assets in 2015. Refer to "Future Uses of Cash" for discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2020 was $857 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $987 million. Uses of cash consisted of $130 million for the repayment of short-term debt.

Net cash flows from financing activities for the nine-month period ended September 30, 2019 was $433 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $990 million. Uses of cash consisted substantially of $350 million for the repayment of long-term debt, $175 million for common stock dividends paid to PPW Holdings LLC and $30 million for the repayment of short-term debt.

    

Short-term Debt

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of September 30, 2020, PacifiCorp had no short-term debt outstanding. As of December 31, 2019, PacifiCorp had $130 million of short-term debt outstanding at a weighted average interest rate of 2.05%.

Long-term Debt

 

In April 2020, PacifiCorp issued $400 million of its 2.70% First Mortgage Bonds due 2030 and $600 million of its 3.30% First Mortgage Bonds due 2051. PacifiCorp intends to use the net proceeds to fund capital expenditures, primarily for renewable resource and associated transmission projects, and for general corporate purposes.

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 regulatory approvals, 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.

84

---

Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):

	Nine-Month Periods								Annual
	Ended September 30,								Forecast
	2019				2020				2020
Transmission system investment	$	370			$	184			$	268
Wind investment	687				804				1,329
Operating and other	392				630				1,055
Total	$	1,449			$	1,618			$	2,652

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 consistent with generation resources sought in PacifiCorp's 2020 All Source RFP ("2020AS RFP"). Forecast spending for the Aeolus-Bridger/Anticline line totals $131 million in 2020.

•	Wind investment includes the following:

◦

Construction of wind-powered generating facilities at PacifiCorp totaling $705 million and $245 million for the nine-month periods ended September 30, 2020 and 2019, respectively. Construction includes the 1,190 MWs of new wind-powered generating facilities that are expected to be placed in-service in 2020 and 2021 and the energy production is expected to qualify for 100% of the federal PTCs available for ten years once the equipment is placed in-service. PacifiCorp anticipates costs associated with the construction of wind-powered generating facilities will total an additional $522 million for 2020.

◦

Repowering existing wind-powered generating facilities at PacifiCorp totaling $99 million and $442 million for the nine-month periods ended September 30, 2020 and 2019, respectively. 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 ten years following each facility's return to service. PacifiCorp anticipates costs for these activities will total an additional $3 million for 2020.

•	Remaining investments relate to operating projects that consist of advanced meter infrastructure costs, routine expenditures for generation, transmission and distribution, planned spend for wildfire mitigation and other infrastructure needed to serve existing and expected demand.

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.

In October 2019, PacifiCorp filed its 2019 IRP with its state commissions. In November 2019, the WUTC temporarily suspended its practice of acknowledging utility IRPs, including PacifiCorp's 2019 IRP, due to ongoing implementation activities associated with Washington state's Senate Bill 5116, the Clean Energy Transformation Act. In May 2020, the OPUC acknowledged the 2019 IRP with conditions. The UPSC also acknowledged the 2019 IRP in May 2020. In September 2020, the IPUC acknowledged the 2019 IRP. The WPSC review of the 2019 IRP is ongoing. In October 2020, the WPSC concluded its docket investigating the 2019 IRP. A decision from the WPSC in the 2019 IRP filing docket is yet to be issued.

85

---

Requests for Proposals

PacifiCorp issues individual requests for proposals ("RFP") to procure resources identified in the IRP or resources driven by customer demands. The IRP and the RFPs provide for the identification and staged procurement of resources to meet load or state-specific compliance obligations. 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.

A draft of the 2020AS RFP was filed for approval with the UPSC and the OPUC in April 2020. In July 2020, the UPSC and the OPUC approved the 2020AS RFP, and PacifiCorp issued the 2020AS RFP to market. The 2020AS RFP is seeking bids for resources capable of coming online by the end of 2024 up to the level of resources identified in PacifiCorp's 2019 IRP. Bids were submitted in August 2020, and a final shortlist of winning bids will be identified by June 2021. The initial shortlist includes a total of 6,982 MWs of new generation and storage capacity. Of the total, 5,652 MWs are new generation resources (represented by 3,173 MWs of solar generation and 2,479 MWs of wind generation) and an additional 1,330 MWs of new battery storage assets, which includes 1,130 MWs of solar collocated battery storage and 200 MWs of stand-alone battery storage. The 2019 IRP preferred portfolio includes 1,823 MWs of solar resources collocated with 595 MWs of battery energy storage systems and 1,920 MWs of new wind resources coming online by the end of 2024. The resources included in the IRP are enabled by new transmission investments, including Energy Gateway South, a 400-mile, 500-kV transmission line connecting southeastern Wyoming to northern Utah.

Contractual Obligations

As of September 30, 2020, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2019.

COVID-19

In March 2020, COVID‑19 was declared a global pandemic and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and many of the customers served by PacifiCorp. While COVID-19 has impacted PacifiCorp's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. In April 2020, all states in which PacifiCorp operates instituted varying levels of "stay-at-home" orders and other measures, requiring non-essential businesses to remain closed, which impacted PacifiCorp's customers and, therefore, their needs and usage patterns for electricity as evidenced by a reduction in consumption due to COVID-19 through September 2020 compared to the same period in 2019. These states have since moved to varying phases of recovery plans with most businesses opening subject to certain operating restrictions. As the impacts of COVID-19 and related customer and governmental responses remain uncertain, including the duration of restrictions on business openings, a reduction in the consumption of electricity may continue to occur, particularly in the commercial and industrial classes. Due to regulatory requirements and voluntary actions taken by PacifiCorp related to customer collection activity and suspension of disconnections for non-payment, PacifiCorp has seen delays and reductions in cash receipts from retail customers related to the impacts of COVID-19, which could result in higher than normal bad debt write-offs. The amount of such reductions in cash receipts through September 2020 has not been material compared to the same period in 2019 but uncertainty remains. Regulatory jurisdictions may allow for deferral or recovery of certain costs incurred in responding to COVID‑19. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for further discussion. While PacifiCorp does not currently expect a significant increase in employer contributions to its retirement plans, continued market volatility caused by COVID-19 may lead to increased contributions in the future.

PacifiCorp's business has been deemed essential and its employees have been identified as "critical infrastructure employees" allowing them to move within communities and across jurisdictional boundaries as necessary to maintain its electric generation, transmission and distribution system. In response to the effects of COVID‑19, PacifiCorp has implemented its business continuity plan to protect its employees and customers. Such plans include a variety of actions, including situational use of personal protective equipment by employees when interacting with customers and implementing practices to enhance social distancing at the workplace. Such practices have included work-from-home, staggered work schedules, rotational work location assignments, increased cleaning and sanitation of work spaces and providing general health reminders intended to help lower the risk of spreading COVID‑19.

Regulatory Matters

PacifiCorp is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding PacifiCorp's current regulatory matters.

86

---

Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local 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 the EPA and various 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 PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and financial results. PacifiCorp believes it is in material compliance with all applicable laws and regulations.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws.

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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, pension and other postretirement benefits, income taxes and revenue recognition-unbilled revenue. For additional discussion of PacifiCorp's critical accounting estimates, see Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2019. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2019.

87

---

MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company

Consolidated Financial Section

88

---

PART I

Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

MidAmerican Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of September 30, 2020, the related statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2020 and 2019, and of cash flows for the nine-month periods ended September 30, 2020 and 2019, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the balance sheet of MidAmerican Energy as of December 31, 2019, and the related statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 21, 2020, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2019, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of MidAmerican Energy's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

November 6, 2020

89

---

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,				December 31,
	2020				2019
ASSETS
Current assets:
Cash and cash equivalents	$	188			$	287
Trade receivables, net	303				291
Inventories	266				226
Other current assets	70				90
Total current assets	827				894
Property, plant and equipment, net	19,049				18,375
Regulatory assets	333				289
Investments and restricted investments	849				818
Other assets	210				188
Total assets	$	21,268			$	20,564

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

90

---

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	September 30,				December 31,
	2020				2019
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	463			$	519
Accrued interest	86				78
Accrued property, income and other taxes	215				225
Other current liabilities	170				219
Total current liabilities	934				1,041
Long-term debt	7,210				7,208
Regulatory liabilities	1,083				1,406
Deferred income taxes	2,997				2,626
Asset retirement obligations	768				704
Other long-term liabilities	336				339
Total liabilities	13,328				13,324
Commitments and contingencies (Note 8)
Shareholder's equity:
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding	—				—
Additional paid-in capital	561				561
Retained earnings	7,379				6,679
Total shareholder's equity	7,940				7,240
Total liabilities and shareholder's equity	$	21,268			$	20,564

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

91

---

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Operating revenue:
Regulated electric	$	728			$	712			$	1,717			$	1,792
Regulated natural gas and other	84				84				389				505
Total operating revenue	812				796				2,106				2,297
Operating expenses:
Cost of fuel and energy	115				113				266				318
Cost of natural gas purchased for resale and other	40				45				210				302
Operations and maintenance	212				189				559				600
Depreciation and amortization	180				184				531				540
Property and other taxes	33				31				102				94
Total operating expenses	580				562				1,668				1,854
Operating income	232				234				438				443
Other income (expense):
Interest expense	(74		)		(68		)		(224		)		(207		)
Allowance for borrowed funds	5				7				12				20
Allowance for equity funds	16				27				33				59
Other, net	14				4				30				34
Total other income (expense)	(39		)		(30		)		(149		)		(94		)
Income before income tax benefit	193				204				289				349
Income tax benefit	(147		)		(78		)		(411		)		(282		)
Net income	$	340			$	282			$	700			$	631

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

92

---

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions)

	Common Stock				Additional Paid-in Capital				Retained Earnings				Total Shareholder's Equity
Balance, June 30, 2019	$	—			$	561			$	6,234			$	6,795
Net income	—				—				282				282
Balance, September 30, 2019	$	—			$	561			$	6,516			$	7,077
Balance, December 31, 2018	$	—			$	561			$	5,885			$	6,446
Net income	—				—				631				631
Balance, September 30, 2019	$	—			$	561			$	6,516			$	7,077
Balance, June 30, 2020	$	—			$	561			$	7,039			$	7,600
Net income	—				—				340				340
Balance, September 30, 2020	$	—			$	561			$	7,379			$	7,940
Balance, December 31, 2019	$	—			$	561			$	6,679			$	7,240
Net income	—				—				700				700
Balance, September 30, 2020	$	—			$	561			$	7,379			$	7,940

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

93

---

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2020				2019
Cash flows from operating activities:
Net income	$	700			$	631
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	531				540
Amortization of utility plant to other operating expenses	25				25
Allowance for equity funds	(33		)		(59		)
Deferred income taxes and amortization of investment tax credits	76				31
Other, net	(56		)		16
Changes in other operating assets and liabilities:
Trade receivables and other assets	(15		)		(1		)
Inventories	(40		)		3
Pension and other postretirement benefit plans	(17		)		(9		)
Accrued property, income and other taxes, net	(10		)		(28		)
Accounts payable and other liabilities	48				62
Net cash flows from operating activities	1,209				1,211
Cash flows from investing activities:
Capital expenditures	(1,341		)		(1,909		)
Purchases of marketable securities	(251		)		(139		)
Proceeds from sales of marketable securities	244				126
Other, net	9				19
Net cash flows from investing activities	(1,339		)		(1,903		)
Cash flows from financing activities:
Proceeds from long-term debt	—				1,460
Repayments of long-term debt	—				(500		)
Net repayments of short-term debt	—				(240		)
Other, net	(1		)		—
Net cash flows from financing activities	(1		)		720
Net change in cash and cash equivalents and restricted cash and cash equivalents	(131		)		28
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	330				56
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	199			$	84

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

94

---

MIDAMERICAN ENERGY COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

(1)	General

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. 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").

The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of September 30, 2020, and for the three- and nine-month periods ended September 30, 2020 and 2019. The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2020 and 2019. The results of operations for the three- and nine-month periods ended September 30, 2020, are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Financial Statements. Note 2 of Notes to Financial Statements included in MidAmerican Energy's Annual Report on Form 10-K for the year ended December 31, 2019, describes the most significant accounting policies used in the preparation of the unaudited Financial Statements. There have been no significant changes in MidAmerican Energy's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2020.

Coronavirus Disease 2019 ("COVID-19")

In March 2020, COVID-19 was declared a global pandemic, and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and on economic conditions in the United States. COVID-19 has impacted many of MidAmerican Energy's customers ranging from high unemployment levels, an inability to pay bills and business closures or operating at reduced capacity levels. While COVID-19 has impacted MidAmerican Energy's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. These impacts include, but are not limited to, lower operating revenue and higher bad debt expense. The duration and extent of COVID-19 and its future impact on MidAmerican Energy's business cannot be reasonably estimated at this time. Accordingly, significant estimates used in the preparation of MidAmerican Energy's unaudited Financial Statements, including those associated with evaluations of certain long-lived assets for impairment, expected credit losses on amounts owed to MidAmerican Energy and potential regulatory recovery of certain costs may be subject to significant adjustments in future periods.

In May 2020, the Iowa Utilities Board ("IUB") issued an order authorizing MidAmerican Energy to use a regulatory asset account to track increased costs and other financial impacts, including changes in revenue, associated with COVID-19. At such time as MidAmerican Energy deems appropriate, it may initiate a proceeding with the IUB to seek recovery of such costs and other financial impacts. MidAmerican Energy cannot predict at this time the amount of such financial impacts from COVID-19 or when, or if, it will seek recovery of such costs with the IUB.

95

---

(2)	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 September 30, 2020 and December 31, 2019, consist substantially of funds restricted for wildlife preservation and, as of December 31, 2019, 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 September 30, 2020 and December 31, 2019, 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
	September 30,				December 31,
	2020				2019
Cash and cash equivalents	$	188			$	287
Restricted cash and cash equivalents in other current assets	11				43
Total cash and cash equivalents and restricted cash and cash equivalents	$	199			$	330

(3)	Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):

			As of
			September 30,				December 31,
	Depreciable Life		2020				2019
Utility plant in service, net:
Generation	20-70 years		$	15,917			$	15,687
Transmission	52-75 years		2,303				2,124
Electric distribution	20-75 years		4,281				4,095
Natural gas distribution	29-75 years		1,873				1,820
Utility plant in service			24,374				23,726
Accumulated depreciation and amortization			(6,584		)		(6,139		)
Utility plant in service, net			17,790				17,587
Nonregulated property, net:
Nonregulated property gross	20-50 years		7				7
Accumulated depreciation and amortization			(1		)		(1		)
Nonregulated property, net			6				6
			17,796				17,593
Construction work-in-progress			1,253				782
Property, plant and equipment, net			$	19,049			$	18,375

96

---

(4)	Recent Financing Transactions

Credit Facilities

In May 2020, MidAmerican Energy terminated its $400 million unsecured credit facility expiring August 2020 and entered into a $600 million unsecured credit facility, which expires May 2021, with an option to extend for up to three months, and has a variable rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread. The 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 any quarter.

(5)	Income Taxes

A reconciliation of the federal statutory income tax rate to MidAmerican Energy's effective income tax rate applicable to income before income tax benefit is as follows:

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2020			2019			2020			2019
Federal statutory income tax rate	21	%		21	%		21	%		21	%
Income tax credits	(55	)		(35	)		(122	)		(75	)
State income tax, net of federal income tax benefit	(27	)		(18	)		(29	)		(19	)
Effects of ratemaking	(15	)		(7	)		(13	)		(7	)
Other, net	—			1			1			(1	)
Effective income tax rate	(76	)%		(38	)%		(142	)%		(81	)%

Income tax credits relate primarily to production tax credits ("PTCs") from 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. MidAmerican Energy recognizes its renewable electricity PTCs throughout the year based on when the credits are earned and excludes them from the annual effective tax rate that is the basis for the interim recognition of other income tax expense. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.

Berkshire Hathaway includes BHE and subsidiaries in its United States federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Energy's provision for income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. 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. BHE made net cash payments for income tax to MidAmerican Energy totaling $500 million and $309 million for the nine-month periods ended September 30, 2020 and 2019, respectively.

(6)	Employee Benefit Plans

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. 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.

97

---

Net periodic benefit credit for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Pension:
Service cost	$	2			$	2			$	4			$	5
Interest cost	7				7				19				22
Expected return on plan assets	(10		)		(10		)		(30		)		(31		)
Net amortization	—				—				1				—
Net periodic benefit credit	$	(1	)		$	(1	)		$	(6	)		$	(4	)
Other postretirement:
Service cost	$	1			$	1			$	3			$	4
Interest cost	2				2				5				7
Expected return on plan assets	(4		)		(3		)		(10		)		(9		)
Net amortization	(1		)		(1		)		(4		)		(3		)
Net periodic benefit credit	$	(2	)		$	(1	)		$	(6	)		$	(1	)

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $7 million and $1 million, respectively, during 2020. As of September 30, 2020, $5 million and $1 million of contributions had been made to the pension and other postretirement benefit plans, respectively.

(7)	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.

98

---

The following table presents MidAmerican Energy's financial 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 September 30, 2020:
Assets:
Commodity derivatives		$	—			$	11			$	3			$	(2	)		$	12
Money market mutual funds(2)		194				—				—				—				194
Debt securities:
United States government obligations		186				—				—				—				186
International government obligations		—				5				—				—				5
Corporate obligations		—				75				—				—				75
Municipal obligations		—				4				—				—				4
Agency, asset and mortgage-backed obligations		—				5				—				—				5
Equity securities:
United States companies		347				—				—				—				347
International companies		8				—				—				—				8
Investment funds		21				—				—				—				21
		$	756			$	100			$	3			$	(2	)		$	857
Liabilities - commodity derivatives		$	—			$	(3	)		$	(1	)		$	3			$	(1	)

		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	)

(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $1 million as of September 30, 2020 and December 31, 2019, 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.

99

---

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 Balance Sheets. 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 (in millions):

	As of September 30, 2020								As of December 31, 2019
	Carrying Value				Fair Value				Carrying Value				Fair Value
Long-term debt	$	7,210			$	8,975			$	7,208			$	8,283

(8)	Commitments and Contingencies

Construction Commitments

During the nine-month period ended September 30, 2020, MidAmerican Energy entered into firm construction commitments totaling $274 million for the remainder of 2020 through 2021, substantially related to the construction of wind-powered generating facilities in Iowa.

Easements

During the nine-month period ended September 30, 2020, MidAmerican Energy entered into non-cancelable easements with minimum payment commitments totaling $102 million through 2060 for land in Iowa on which some of its wind-powered generating facilities will be located.

Maintenance and Service Contracts

During the nine-month period ended September 30, 2020, MidAmerican Energy entered into non-cancelable maintenance and service contracts related to wind-powered generating facilities with minimum payment commitments totaling $75 million through 2031.

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.

Environmental Laws and Regulations

MidAmerican Energy is subject to federal, state and local 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 its current and future operations. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.

100

---

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 approved base return on equity ("ROE") effective January 2015. Prior to September 2016, the rates in effect were based on a 12.38% 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 reduces 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 a 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. In May 2020, the FERC issued an order on rehearing of the November 2019 order. The May 2020 order affirmed the FERC's prior decision to dismiss the second complaint and established an ROE of 10.02% (10.52% including the 0.50% adder) for the 15-month refund period of the first complaint and prospectively from September 2016 to the date of the May 2020 order. These orders continue to be subject to judicial appeal. MidAmerican Energy cannot predict the ultimate outcome of these matters and, as of September 30, 2020, has accrued an $11 million liability for refunds of amounts collected under the higher ROE during the periods covered by both complaints.

(9)	Revenue from Contracts with Customers

The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business and customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 10, (in millions):

	For the Three-Month Period Ended September 30, 2020																For the Nine-Month Period Ended September 30, 2020
	Electric				Natural Gas				Other				Total				Electric				Natural Gas				Other				Total
Customer Revenue:
Retail:
Residential	$	241			$	46			$	—			$	287			$	555			$	233			$	—			$	788
Commercial	99				13				—				112				242				71				—				313
Industrial	280				2				—				282				640				9				—				649
Natural gas transportation services	—				8				—				8				—				26				—				26
Other retail(1)	42				1				—				43				103				2				—				105
Total retail	662				70				—				732				1,540				341				—				1,881
Wholesale	46				10				—				56				116				41				—				157
Multi-value transmission projects	14				—				—				14				47				—				—				47
Other Customer Revenue	—				—				4				4				—				—				5				5
Total Customer Revenue	722				80				4				806				1,703				382				5				2,090
Other revenue	6				—				—				6				14				2				—				16
Total operating revenue	$	728			$	80			$	4			$	812			$	1,717			$	384			$	5			$	2,106

101

---

	For the Three-Month Period Ended September 30, 2019																For the Nine-Month Period Ended September 30, 2019
	Electric				Natural Gas				Other				Total				Electric				Natural Gas				Other				Total
Customer Revenue:
Retail:
Residential	$	228			$	41			$	—			$	269			$	547			$	282			$	—			$	829
Commercial	101				10				—				111				255				95				—				350
Industrial	274				3				—				277				641				12				—				653
Natural gas transportation services	—				7				—				7				—				27				—				27
Other retail(1)	48				—				—				48				118				—				—				118
Total retail	651				61				—				712				1,561				416				—				1,977
Wholesale	41				15				—				56				168				64				—				232
Multi-value transmission projects	17				—				—				17				47				—				—				47
Other Customer Revenue	—				—				8				8				—				—				23				23
Total Customer Revenue	709				76				8				793				1,776				480				23				2,279
Other revenue	3				—				—				3				16				2				—				18
Total operating revenue	$	712			$	76			$	8			$	796			$	1,792			$	482			$	23			$	2,297

(1)	Other retail includes provisions for rate refunds, for which any actual refunds will be reflected in the applicable customer classes upon resolution of the related regulatory proceeding.

102

---

(10)	Segment Information

MidAmerican Energy has identified two reportable 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 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.

The following tables provide information on a reportable segment basis (in millions):

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Operating revenue:
Regulated electric	$	728			$	712			$	1,717			$	1,792
Regulated natural gas	80				76				384				482
Other	4				8				5				23
Total operating revenue	$	812			$	796			$	2,106			$	2,297
Operating income:
Regulated electric	$	238			$	243			$	398			$	396
Regulated natural gas	(6		)		(8		)		40				45
Other	—				(1		)		—				2
Total operating income	232				234				438				443
Interest expense	(74		)		(68		)		(224		)		(207		)
Allowance for borrowed funds	5				7				12				20
Allowance for equity funds	16				27				33				59
Other, net	14				4				30				34
Income before income tax benefit	$	193			$	204			$	289			$	349

	As of
	September 30, 2020				December 31, 2019
Assets:
Regulated electric	$	19,782			$	19,093
Regulated natural gas	1,479				1,468
Other	7				3
Total assets	$	21,268			$	20,564

103

---

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers and Member of

MidAmerican Funding, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of September 30, 2020, the related consolidated statements of operations and changes in member's equity for the three-month and nine-month periods ended September 30, 2020 and 2019, and of cash flows for the nine-month periods ended September 30, 2020 and 2019, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB) and in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Funding as of December 31, 2019, and the related consolidated statements of operations, changes in member's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 21, 2020, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2019, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of MidAmerican Funding's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB and with auditing standards generally accepted in the United States of America applicable to reviews of interim financial information. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB and with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

November 6, 2020

104

---

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,				December 31,
	2020				2019
ASSETS
Current assets:
Cash and cash equivalents	$	193			$	288
Trade receivables, net	303				291
Inventories	266				226
Other current assets	73				91
Total current assets	835				896
Property, plant and equipment, net	19,049				18,377
Goodwill	1,270				1,270
Regulatory assets	333				289
Investments and restricted investments	851				820
Other assets	210				188
Total assets	$	22,548			$	21,840

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

105

---

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	September 30,				December 31,
	2020				2019
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	463			$	520
Accrued interest	87				84
Accrued property, income and other taxes	215				226
Note payable to affiliate	184				171
Other current liabilities	171				219
Total current liabilities	1,120				1,220
Long-term debt	7,450				7,448
Regulatory liabilities	1,083				1,406
Deferred income taxes	2,995				2,621
Asset retirement obligations	768				704
Other long-term liabilities	336				340
Total liabilities	13,752				13,739
Commitments and contingencies (Note 8)
Member's equity:
Paid-in capital	1,679				1,679
Retained earnings	7,117				6,422
Total member's equity	8,796				8,101
Total liabilities and member's equity	$	22,548			$	21,840

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

106

---

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Operating revenue:
Regulated electric	$	728			$	712			$	1,717			$	1,792
Regulated natural gas and other	84				85				397				507
Total operating revenue	812				797				2,114				2,299
Operating expenses:
Cost of fuel and energy	115				113				266				318
Cost of natural gas purchased for resale and other	40				45				211				301
Operations and maintenance	212				190				560				602
Depreciation and amortization	180				184				531				540
Property and other taxes	33				31				102				94
Total operating expenses	580				563				1,670				1,855
Operating income	232				234				444				444
Other income (expense):
Interest expense	(79		)		(74		)		(238		)		(223		)
Allowance for borrowed funds	5				7				12				20
Allowance for equity funds	16				27				33				59
Other, net	15				5				30				36
Total other income (expense)	(43		)		(35		)		(163		)		(108		)
Income before income tax benefit	189				199				281				336
Income tax benefit	(148		)		(80		)		(414		)		(286		)
Net income	$	337			$	279			$	695			$	622

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

107

---

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY (Unaudited)

(Amounts in millions)

	Paid-in Capital				Retained Earnings				Total Member's Equity
Balance, June 30, 2019	$	1,679			$	5,993			$	7,672
Net income	—				279				279
Balance, September 30, 2019	$	1,679			$	6,272			$	7,951
Balance, December 31, 2018	$	1,679			$	5,650			$	7,329
Net income	—				622				622
Balance, September 30, 2019	$	1,679			$	6,272			$	7,951
Balance, June 30, 2020	$	1,679			$	6,780			$	8,459
Net income	—				337				337
Balance, September 30, 2020	$	1,679			$	7,117			$	8,796
Balance, December 31, 2019	$	1,679			$	6,422			$	8,101
Net income	—				695				695
Balance, September 30, 2020	$	1,679			$	7,117			$	8,796

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

108

---

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2020				2019
Cash flows from operating activities:
Net income	$	695			$	622
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	531				540
Amortization of utility plant to other operating expenses	25				25
Allowance for equity funds	(33		)		(59		)
Deferred income taxes and amortization of investment tax credits	79				30
Other, net	(56		)		18
Changes in other operating assets and liabilities:
Trade receivables and other assets	(16		)		(6		)
Inventories	(40		)		3
Pension and other postretirement benefit plans	(17		)		(9		)
Accrued property, income and other taxes, net	(13		)		(28		)
Accounts payable and other liabilities	44				58
Net cash flows from operating activities	1,199				1,194
Cash flows from investing activities:
Capital expenditures	(1,341		)		(1,909		)
Purchases of marketable securities	(251		)		(139		)
Proceeds from sales of marketable securities	244				126
Other, net	10				19
Net cash flows from investing activities	(1,338		)		(1,903		)
Cash flows from financing activities:
Proceeds from long-term debt	—				1,460
Repayments of long-term debt	—				(500		)
Net change in note payable to affiliate	13				17
Net repayments of short-term debt	—				(240		)
Other, net	(1		)		—
Net cash flows from financing activities	12				737
Net change in cash and cash equivalents and restricted cash and cash equivalents	(127		)		28
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	331				57
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	204			$	85

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

109

---

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)	General

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. 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.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2020, and for the three- and nine-month periods ended September 30, 2020 and 2019. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and nine-month periods ended September 30, 2020 and 2019. The results of operations for the three- and nine-month periods ended September 30, 2020, are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in MidAmerican Funding's Annual Report on Form 10-K for the year ended December 31, 2019, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in MidAmerican Funding's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2020.

Coronavirus Disease 2019 ("COVID-19")

In March 2020, COVID-19 was declared a global pandemic, and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and on economic conditions in the United States. COVID-19 has impacted many of MidAmerican Energy's customers ranging from high unemployment levels, an inability to pay bills and business closures or operating at reduced capacity levels. While COVID-19 has impacted MidAmerican Funding's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. These impacts include, but are not limited to, lower operating revenue and higher bad debt expense. The duration and extent of COVID-19 and its future impact on MidAmerican Funding's business cannot be reasonably estimated at this time. Accordingly, significant estimates used in the preparation of MidAmerican Funding's unaudited Consolidated Financial Statements, including those associated with evaluations of certain long-lived assets and goodwill for impairment, expected credit losses on amounts owed to MidAmerican Funding and potential regulatory recovery of certain costs may be subject to significant adjustments in future periods.

In May 2020, the Iowa Utilities Board ("IUB") issued an order authorizing MidAmerican Energy to use a regulatory asset account to track increased costs and other financial impacts, including changes in revenue, associated with COVID-19. At such time as MidAmerican Energy deems appropriate, it may initiate a proceeding with the IUB to seek recovery of such costs and other financial impacts. MidAmerican Energy cannot predict at this time the amount of such financial impacts from COVID-19 or when, or if, it will seek recovery of such costs with the IUB.

110

---

(2)	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 September 30, 2020 and December 31, 2019, consist substantially of funds restricted for wildlife preservation and, as of December 31, 2019, 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 September 30, 2020 and December 31, 2019, 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
	September 30,				December 31,
	2020				2019
Cash and cash equivalents	$	193			$	288
Restricted cash and cash equivalents in other current assets	11				43
Total cash and cash equivalents and restricted cash and cash equivalents	$	204			$	331

(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 as of September 30, 2020 and December 31, 2019, nonregulated property gross of $‑million and $3 million, respectively, and related accumulated depreciation and amortization of $- million and $1 million, respectively.

(4)	Recent Financing Transactions

Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.

(5)	Income Taxes

A reconciliation of the federal statutory income tax rate to MidAmerican Funding's effective income tax rate applicable to income before income tax benefit is as follows:

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2020			2019			2020			2019
Federal statutory income tax rate	21	%		21	%		21	%		21	%
Income tax credits	(56	)		(36	)		(126	)		(78	)
State income tax, net of federal income tax benefit	(27	)		(18	)		(30	)		(20	)
Effects of ratemaking	(16	)		(7	)		(13	)		(7	)
Other, net	—			—			1			(1	)
Effective income tax rate	(78	)%		(40	)%		(147	)%		(85	)%

Income tax credits relate primarily to production tax credits ("PTCs") from 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. MidAmerican Energy recognizes its renewable electricity PTCs throughout the year based on when the credits are earned and excludes them from the annual effective tax rate that is the basis for the interim recognition of other income tax expense. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.

111

---

Berkshire Hathaway includes BHE and subsidiaries in its United States federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Funding's and MidAmerican Energy's provisions for income tax have been computed on a stand-alone basis, and substantially all of their currently payable or receivable income tax is remitted to or received from BHE. The timing of MidAmerican Funding'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. BHE made net cash payments for income tax to MidAmerican Funding totaling $504 million and $313 million for the nine-month period ended September 30, 2020 and 2019, respectively.

(6)	Employee Benefit Plans

Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements.

(7)	Fair Value Measurements

Refer to Note 7 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 (in millions):

	As of September 30, 2020								As of December 31, 2019
	Carrying Value				Fair Value				Carrying Value				Fair Value
Long-term debt	$	7,450			$	9,313			$	7,448			$	8,599

(8)	Commitments and Contingencies

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.

Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements.

(9)	Revenue from Contracts with Customers

Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements. Additionally, MidAmerican Funding had other Accounting Standards Codification Topic 606 revenue of $- million and $1 million for the three-month periods ended September 30, 2020 and 2019, respectively, and $8 million and $2 million for the nine-month periods ended September 30, 2020 and 2019, respectively.

112

---

(10)	Segment Information

MidAmerican Funding has identified two reportable 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 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 financial results and assets of nonregulated operations, MHC and MidAmerican Funding.

The following tables provide information on a reportable segment basis (in millions):

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Operating revenue:
Regulated electric	$	728			$	712			$	1,717			$	1,792
Regulated natural gas	80				76				384				482
Other	4				9				13				25
Total operating revenue	$	812			$	797			$	2,114			$	2,299
Operating income:
Regulated electric	$	238			$	243			$	398			$	396
Regulated natural gas	(6		)		(8		)		40				45
Other	—				(1		)		6				3
Total operating income	232				234				444				444
Interest expense	(79		)		(74		)		(238		)		(223		)
Allowance for borrowed funds	5				7				12				20
Allowance for equity funds	16				27				33				59
Other, net	15				5				30				36
Income before income tax benefit	$	189			$	199			$	281			$	336

	As of
	September 30, 2020				December 31, 2019
Assets(1):
Regulated electric	$	20,973			$	20,284
Regulated natural gas	1,558				1,547
Other	17				9
Total assets	$	22,548			$	21,840

(1)	Assets by reportable segment reflect the assignment of goodwill to applicable reporting units.

113

---

Item 2.	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 unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements and MidAmerican Energy's historical unaudited Financial Statements and Notes to Financial Statements in Part I, Item 1 of this Form 10-Q. MidAmerican Funding's and MidAmerican Energy's actual results in the future could differ significantly from the historical results.

Results of Operations for the Third Quarter and First Nine Months of 2020 and 2019

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the third quarter of 2020 was $340 million, an increase of $58 million, or 21%, compared to 2019 primarily due to higher income tax benefit of $69 million from higher PTCs recognized of $36 million, which was due to higher wind generation driven by repowering and new wind projects placed in service in 2019, and the effects of ratemaking, higher electric utility margin, and higher cash surrender value of corporate-owned life insurance policies, partially offset by higher operations and maintenance expenses from storm restoration and the addition of wind turbines in 2019 and lower allowances for equity and borrowed funds used during construction of $13 million. Electric utility margin increased primarily due to higher retail customer volumes, higher wholesale revenue and higher recoveries through bill riders, partially offset by higher generation and purchased power costs. Electric retail customer volumes increased 2.3%, primarily due to increased usage for certain industrial customers, partially offset by the impacts of COVID-19, which resulted in lower commercial and industrial customer usage and higher residential customer usage.

MidAmerican Energy's net income for the first nine months of 2020 was $700 million, an increase of $69 million, or 11%, compared to 2019 primarily due to higher income tax benefit of $129 million, largely due to higher PTCs recognized of $93 million from higher wind generation, which was driven by repowering and new wind projects placed in-service in 2019, and the effects of ratemaking, lower operations and maintenance expenses and lower depreciation and amortization expense of $9 million, partially offset by lower allowances for equity and borrowed funds used during construction of $34 million, lower electric and natural gas utility margins, higher interest expense of $17 million and higher property and other taxes of $8 million. Electric utility margin decreased due to lower wholesale revenue, the price impacts from changes in sales mix and lower recoveries through bill riders, partially offset by higher retail customer volumes and lower generation and purchased power costs. Electric retail customer volumes increased 1.1% due to increased usage for certain industrial customers, partially offset by the impacts of COVID-19, which resulted in lower commercial and industrial customer usage and higher residential customer usage. Natural gas utility margin decreased due to lower energy efficiency program revenue and 10.4% lower retail customer volumes primarily due to the unfavorable impact of weather.

MidAmerican Funding -

MidAmerican Funding's net income for the third quarter of 2020 was $337 million, an increase of $58 million, or 21%, compared to 2019. MidAmerican Funding's net income for the first nine months of 2020 was $695 million, an increase of $73 million, or 12%, compared to 2019. The increases were primarily due to the changes in MidAmerican Energy's earnings discussed above.

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.

114

---

MidAmerican Energy'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 MidAmerican Energy's expense 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 explain 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 comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to MidAmerican Energy's operating income (in millions):

		Third Quarter														First Nine Months
		2020				2019				Change						2020				2019				Change
Electric utility margin:
Operating revenue		$	728			$	712			$	16		2	%		$	1,717			$	1,792			$	(75	)	(4	)%
Cost of fuel and energy		115				113				2			2			266				318				(52		)	(16	)
Electric utility margin		613				599				14			2	%		1,451				1,474				(23		)	(2	)%
Natural gas utility margin:
Operating revenue		80				76				4			5	%		384				482				(98		)	(20	)%
Natural gas purchased for resale		39				39				—			—			209				287				(78		)	(27	)
Natural gas utility margin		41				37				4			11	%		175				195				(20		)	(10	)%
Utility margin		654				636				18			3	%		1,626				1,669				(43		)	(3	)%
Other operating revenue		4				8				(4		)	(50	)		5				23				(18		)	(78	)%
Other cost of sales		1				6				(5		)	(83	)		1				15				(14		)	(93	)
Operations and maintenance		212				189				23			12			559				600				(41		)	(7	)
Depreciation and amortization		180				184				(4		)	(2	)		531				540				(9		)	(2	)
Property and other taxes		33				31				2			6			102				94				8			9
Operating income		$	232			$	234			$	(2	)	(1	)%		$	438			$	443			$	(5	)	(1	)%

115

---

Electric Utility Margin

A comparison of key operating results related to electric utility margin is as follows:

	Third Quarter															First Nine Months
	2020				2019				Change							2020				2019				Change
Utility margin (in millions):
Operating revenue	$	728			$	712			$	16			2	%		$	1,717			$	1,792			$	(75	)		(4	)%
Cost of fuel and energy	115				113				2				2			266				318				(52		)		(16	)
Utility margin	$	613			$	599			$	14			2	%		$	1,451			$	1,474			$	(23	)		(2	)%
Sales (GWhs):
Residential	2,053				1,950				103				5	%		5,226				5,105				121				2	%
Commercial	1,013				1,037				(24		)		(2	)		2,800				2,930				(130		)		(4	)
Industrial	3,758				3,652				106				3			10,884				10,567				317				3
Other	398				420				(22		)		(5	)		1,117				1,200				(83		)		(7	)
Total retail	7,222				7,059				163				2			20,027				19,802				225				1
Wholesale	2,541				1,708				833				49			7,535				7,312				223				3
Total sales	9,763				8,767				996				11	%		27,562				27,114				448				2	%
Average number of retail customers (in thousands)	796				786				10				1	%		794				785				9				1	%
Average revenue per MWh:
Retail	$	91.62			$	92.13			$	(0.51	)		(1	)%		$	86.92			$	78.83			$	8.09			10	%
Wholesale	$	17.34			$	23.00			$	(5.66	)		(25	)%		$	14.54			$	22.81			$	(8.27	)		(36	)%
Heating degree days	96				12				84				*			3,698				4,218				(520		)		(12	)%
Cooling degree days	795				862				(67		)		(8	)%		1,155				1,142				13				1	%
Sources of energy (GWhs)(1):
Coal	3,169				3,764				(595		)		(16	)%		5,771				10,101				(4,330		)		(43	)%
Nuclear	1,000				962				38				4			2,902				2,846				56				2
Natural gas	324				297				27				9			517				361				156				43
Wind and other(2)	4,274				2,954				1,320				45			14,268				11,252				3,016				27
Total energy generated	8,767				7,977				790				10			23,458				24,560				(1,102		)		(4	)
Energy purchased	1,166				1,026				140				14			4,592				3,072				1,520				49
Total	9,933				9,003				930				10	%		28,050				27,632				418				2	%
Average cost of energy per MWh:
Energy generated(3)	$	7.34			$	9.35			$	(2.01	)		(21	)%		$	5.53			$	8.27			$	(2.74	)		(33	)%
Energy purchased	$	43.32			$	37.29			$	6.03			16	%		$	29.67			$	37.37			$	(7.70	)		(21	)%

*    Not meaningful.

(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 generating facilities 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.

116

---

Electric utility margin increased $14 million for the third quarter of 2020 compared to 2019, due to:

(1)	Higher retail utility margin of $20 million primarily due to -

•	an increase of $13 million from higher recoveries through bill riders, net of energy costs, due to lower refunds related to the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit) and an increase of $3 million in electric energy efficiency program revenue (offset in operations and maintenance expense);

•	an increase of $12 million from non-weather-related factors, net of price impacts from changes in sales mix, including increased usage for certain industrial customers and the impacts of COVID-19, which generally resulted in lower commercial and industrial customer usage and higher residential customer usage;

•	a decrease of $3 million from lower other retail revenue, including steam sales; and

•	a decrease of $2 million from the unfavorable impact of weather.

(2)	Lower wholesale utility margin of $5 million due to lower margins per unit, reflecting lower market prices and higher energy costs, partially offset by higher sales volumes of 48.8%.

Electric utility margin decreased $23 million for the first nine months of 2020 compared to 2019 primarily due to:

(1)	Lower wholesale utility margin of $28 million due to lower market prices, partially offset by lower energy costs and higher sales volumes of 3.0%;

(2)	Higher retail utility margin of $4 million primarily due to -

•	an increase of $14 million from non-weather-related factors, net of price impacts from changes in sales mix, including increased usage for certain industrial customers and the impacts of COVID-19, which generally resulted in lower commercial and industrial customer usage and higher residential customer usage;

•

a decrease of $6 million from lower recoveries through bill riders, net of energy costs, primarily due to a decrease of $30 million in electric energy efficiency program revenue (offset in operations and maintenance expense), partially offset by lower refunds related to the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit) and higher recoveries for transmission costs (offset in operations and maintenance expense); and

•	a decrease of $4 million from lower other retail revenue, including steam sales.

117

---

Natural Gas Utility Margin

A comparison of key operating results related to natural gas utility margin is as follows:

	Third Quarter															First Nine Months
	2020				2019				Change							2020				2019				Change
Utility margin (in millions):
Operating revenue	$	80			$	76			$	4			5	%		$	384			$	482			$	(98	)		(20)	%
Natural gas purchased for resale	39				39				—				—			209				287				(78		)		(27	)
Utility margin	$	41			$	37			$	4			11	%		$	175			$	195			$	(20	)		(10)	%
Throughput (000's Dths):
Residential	3,190				2,633				557				21	%		34,146				38,130				(3,984		)		(10)	%
Commercial	1,671				1,522				149				10			15,634				18,103				(2,469		)		(14	)
Industrial	1,105				929				176				19			3,687				3,424				263				8
Other	6				10				(4		)		(40	)		54				58				(4		)		(7	)
Total retail sales	5,972				5,094				878				17			53,521				59,715				(6,194		)		(10	)
Wholesale sales	5,622				7,251				(1,629		)		(22	)		24,391				25,856				(1,465		)		(6	)
Total sales	11,594				12,345				(751		)		(6	)		77,912				85,571				(7,659		)		(9	)
Natural gas transportation service	24,973				27,011				(2,038		)		(8	)		82,092				81,378				714				1
Total throughput	36,567				39,356				(2,789		)		(7)	%		160,004				166,949				(6,945		)		(4)	%
Average number of retail customers (in thousands)	769				760				9				1	%		770				761				9				1	%
Average revenue per retail Dth sold	$	10.43			$	10.65			$	(0.22	)		(2)	%		$	5.91			$	6.55			$	(0.64	)		(10)	%
Heating degree days	122				19				103				*			3,899				4,408				(509		)		(12)	%
Average cost of natural gas per retail Dth sold	$	4.74			$	4.83			$	(0.09	)		(2)	%		$	3.12			$	3.74			$	(0.62	)		(17)	%
Combined retail and wholesale average cost of natural gas per Dth sold	$	3.32			$	3.17			$	0.15			5	%		$	2.68			$	3.35			$	(0.67	)		(20)	%

*    Not meaningful.

Natural gas utility margin increased $4 million for the third quarter of 2020 compared to 2019 primarily due to:

(1)	An increase of $3 million from higher natural gas energy efficiency program revenue (offset in operations and maintenance expense); and

(2)	An increase of $1 million from the favorable impact of weather and other usage factors.

Natural gas utility margin decreased $20 million for the first nine months of 2020 compared to 2019 primarily due to:

(1)	A decrease of $13 million from lower natural gas energy efficiency program revenue (offset in operations and maintenance expense);

(2)	A decrease of $7 million from the unfavorable impact of weather in the first quarter;

(3)	A decrease of $1 million from non-weather rate and usage variances, in part due to sales mix; and

(4)	An increase of $2 million from rider refunds related to the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit).

118

---

Operating Expenses

MidAmerican Energy -

Operations and maintenance increased $23 million for the third quarter of 2020 compared to 2019 primarily due to higher electric distribution expenses of $17 million driven by storm restoration related to significant wind damage from the derecho storm in August 2020, higher wind-powered generation operations and maintenance expenses of $7 million due to additional and repowered wind turbines and easements, higher energy efficiency program expense of $4 million (offset in operating revenue) and higher customer accounts costs of $2 million driven by greater bad debt expense, partially offset by lower deferred compensation costs of $4 million and lower natural gas distribution costs of $3 million.

Operations and maintenance decreased $41 million for the first nine months of 2020 compared to 2019 primarily due to lower energy efficiency program expense of $43 million (offset in operating revenue), lower fossil-fueled generating facility maintenance of $13 million, lower natural gas distribution expenses of $8 million, a nuclear property insurance premium refund of $5 million, lower deferred compensation costs of $5 million and lower nonregulated operations expenses of $4 million, partially offset by higher wind-powered generation operations and maintenance expenses of $23 million due to additional wind turbines and easements, higher electric distribution costs of $8 million largely driven by storm restoration related to the derecho storm in August 2020 and higher transmission operations costs from the Midcontinent Independent System Operator, Inc. of $4 million (offset in operating revenue).

Depreciation and amortization for the third quarter and first nine months of 2020 decreased $4 million and $9 million, respectively, compared to 2019 primarily due to lower Iowa revenue sharing accruals of $30 million and $84 million, respectively, substantially offset by an increase related to new and repowered wind-powered generating facilities and other plant placed in-service.

Property and other taxes increased $8 million for the first nine months of 2020 compared to 2019 due to higher retail sales and wind-powered generating facility increases.

Other Income (Expense)

MidAmerican Energy -

Interest expense increased $6 million and $17 million for the third quarter and first nine months, respectively, of 2020 compared to 2019 due to higher average long-term debt balances.

Allowance for borrowed and equity funds decreased $13 million and $34 million for the third quarter and first nine months, respectively, of 2020 compared to 2019 primarily due to lower construction work-in-progress balances related to wind-powered generation.

Other, net increased $10 million for the third quarter of 2020 compared to 2019 primarily due to higher cash surrender values of corporate-owned life insurance policies of $4 million and lower non-service costs of postretirement employee benefit plans.

Other, net decreased $4 million for the first nine months of 2020 compared to 2019 primarily due to lower cash surrender values of corporate-owned life insurance policies of $9 million and lower interest income of $6 million from unfavorable cash positions, partially offset by lower non-service costs of postretirement employee benefit plans.

Income Tax Benefit

MidAmerican Energy -

MidAmerican Energy's income tax benefit increased $69 million for the third quarter of 2020 compared to 2019, and the effective tax rate was (76)% for 2020 and (38)% for 2019. For the first nine months of 2020 compared to 2019, MidAmerican Energy's income tax benefit increased $129 million, and the effective tax rate was (142)% for 2020 and (81)% for 2019. The change in the effective tax rates for 2020 compared to 2019 was due to the higher PTCs, state income tax impacts, the effects of ratemaking and a lower pretax income in 2020.

119

---

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, including those facilities where a significant portion of the equipment was replaced, commonly referred to as repowered facilities, are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the nine-month periods ended September 30, 2020 and 2019 totaled $352 million and $259 million, respectively.

MidAmerican Funding -

MidAmerican Funding's income tax benefit increased $68 million for the third quarter of 2020 compared to 2019, and the effective tax rate was (78)% for 2020 and (40)% for 2019. For the first nine months of 2020 compared to 2019, MidAmerican Funding's income tax benefit increased $128 million, and the effective tax rate was (147)% for 2020 and (85)% for 2019. The changes in the effective tax rates were principally due to the factors discussed for MidAmerican Energy.

Liquidity and Capital Resources

As of September 30, 2020, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):

MidAmerican Energy:
Cash and cash equivalents		$	188
Credit facilities, maturing 2021 and 2022		1,505
Less:
Tax-exempt bond support		(370		)
Net credit facilities		1,135
MidAmerican Energy total net liquidity		$	1,323
MidAmerican Funding:
MidAmerican Energy total net liquidity		$	1,323
Cash and cash equivalents		5
MHC, Inc. credit facility, maturing 2021		4
MidAmerican Funding total net liquidity		$	1,332

Operating Activities

MidAmerican Energy's net cash flows from operating activities for the nine-month periods ended September 30, 2020 and 2019, were $1,209 million and $1,211 million, respectively. MidAmerican Funding's net cash flows from operating activities for the nine-month periods ended September 30, 2020 and 2019, were $1,199 million and $1,194 million, respectively. Cash flows from operating activities reflect higher income tax receipts, lower cash margins for MidAmerican Energy's regulated electric and natural gas businesses, higher interest paid due to long-term debt issued in October 2019, higher settlement payments for asset retirement obligations and higher payments to vendors.

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.

Investing Activities

MidAmerican Energy's net cash flows from investing activities for the nine-month periods ended September 30, 2020 and 2019, were $(1,339) million and $(1,903) million, respectively. MidAmerican Funding's net cash flows from investing activities for the nine-month periods ended September 30, 2020 and 2019, were $(1,338) million and $(1,903) million, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures, which decreased due to lower wind-powered generating facility construction and repowering expenditures. Purchases and proceeds related to marketable securities substantially consist of activity within the Quad Cities Generating Station nuclear decommissioning trust and other trust investments.

120

---

Financing Activities

MidAmerican Energy's net cash flows from financing activities for the nine-month periods ended September 30, 2020 and 2019 were $(1) million and $720 million, respectively. MidAmerican Funding's net cash flows from financing activities for the nine-month periods ended September 30, 2020 and 2019, were $12 million and $737 million, 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. 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. Through its commercial paper program, MidAmerican Energy paid $240 million in 2019. MidAmerican Funding received $13 million and $17 million in 2020 and 2019, respectively, through its note payable with BHE.

Debt Authorizations and Related Matters

MidAmerican Energy has authority from the FERC to issue, through April 2, 2022, commercial paper and bank notes aggregating $1.5 billion at interest rates not to exceed the applicable London Interbank Offered Rate 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 $600 million unsecured credit facility, which expires in May 2021, with an option to extend for up to three months, 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 shelf 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.

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 regulatory approvals, 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.

121

---

MidAmerican Energy's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):

	Nine-Month Periods								Annual
	Ended September 30,								Forecast
	2019				2020				2020
Wind-powered generation under ratemaking principles	$	1,027			$	274			$	387
Renewable generation not under ratemaking principles	—				404				501
Wind-powered generation repowering	332				25				44
Other	550				638				991
Total	$	1,909			$	1,341			$	1,923

MidAmerican Energy's historical and forecast capital expenditures for 2020 include the following:

•

The construction of wind-powered generating facilities in Iowa. Wind XI, a 2,000-MW project constructed over several years, was completed in January 2020. Wind XII is a 592-MW project, including 253 MWs placed in-service as of September 30, 2020, and facilities expected to be placed in-service by the end of 2020. MidAmerican Energy obtained pre-approved ratemaking principles for both of these projects and 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 will not be subject to pre-approved ratemaking principles. MidAmerican Energy currently has three such wind-powered generation projects under construction totaling 319 MWs that are expected to be placed in-service by the end of 2020 and to qualify for 100% of PTCs available. In the nine-month period ended September 30, 2020, MidAmerican Energy purchased 80 MWs (nominal ratings) of wind-powered generating facilities that began commercial operation in 2012 and are not eligible for PTCs.

•

The repowering of the oldest of MidAmerican Energy's wind-powered generating facilities in Iowa. The repowering projects entail the replacement of significant components of the facilities, which is expected to qualify such facilities for the re-establishment of PTCs for ten years following each facility's return to service at rates that depend upon the year in which construction begins. Of the 998 MWs of current repowering projects not in-service as of September 30, 2020, 591 MWs are currently expected to qualify for 80% of the PTCs available for ten years following each facility's return to service and 407 MWs are expected to qualify for 60% of such credits.

•	Remaining costs primarily relate to routine expenditures for generation, transmission, distribution and other infrastructure needed to serve existing and expected demand.

Contractual Obligations

As of September 30, 2020, there have been no material changes outside the normal course of business in MidAmerican Energy's and MidAmerican Funding's contractual obligations from the information provided in Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2019.

122

---

COVID-19

In March 2020, COVID-19 was declared a global pandemic, and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and many of the customers served by MidAmerican Energy. While COVID-19 has impacted MidAmerican Energy's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. In April 2020, all states in which MidAmerican Energy operates instituted varying levels of "stay-at-home" orders and other measures, requiring non-essential businesses to remain closed, which impacted MidAmerican Energy's customers and, therefore, their needs and usage patterns for electricity and natural gas as evidenced by a reduction in consumption due to COVID-19 through September 2020 compared to the same period in 2019. These states have since moved to varying phases of recovery plans with most businesses opening subject to certain operating restrictions. As the impacts of COVID-19 and related customer and governmental responses remain uncertain, including the duration of restrictions on business openings, a reduction in the consumption of electricity or natural gas may continue to occur, particularly in the commercial and industrial classes. Due to regulatory requirements and voluntary actions taken by MidAmerican Energy related to customer collection activity and suspension of disconnections for non-payment, MidAmerican Energy has seen delays and reductions in cash receipts from retail customers related to the impacts of COVID-19, which could result in higher than normal bad debt write-offs. The amount of such reductions in cash receipts through September 2020 has not been material compared to the same period in 2019, but uncertainty remains. Regulatory jurisdictions may allow for recovery of certain costs incurred in responding to COVID-19. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for further discussion.

MidAmerican Energy's business has been deemed essential and its employees have been identified as "critical infrastructure employees" allowing them to move within communities and across jurisdictional boundaries as necessary to maintain its electric generation, transmission and distribution system and its natural gas distribution system. In response to the effects of COVID-19, MidAmerican Energy has implemented its business continuity plan to protect its employees and customers. Such plans include a variety of actions, including situational use of personal protective equipment by employees when interacting with customers and implementing practices to enhance social distancing at the workplace. Such practices have included work-from-home, staggered work schedules, rotational work location assignments, increased cleaning and sanitation of work spaces and providing general health reminders intended to help lower the risk of spreading COVID-19.

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 ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs 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.

The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation 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. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.

123

---

On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expands the breadth and scope of the PJM's MOPR, which is effective as of the PJM's next capacity auction. While the FERC included some limited exemptions in its order, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. 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. In response to the FERC's order, the PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. On October 15, 2020, the FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting the PJM's two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, the FERC also accepted the PJM's proposal to condense the schedule of activities leading up to the next capacity auction but did not specify when that schedule would commence given that a key element of the MOPR level computation remains pending before the FERC in another proceeding.

On May 21, 2020, the FERC issued an order involving reforms to the PJM's day-ahead and real-time reserves markets that need to be reflected in the calculation of MOPR levels. In approving reforms to the PJM's reserves markets, the FERC also directed the PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and related services, which will then be used in calculating a number of parameters and assumptions used in the capacity market, including MOPR levels. The PJM submitted its new revenue projection methodology on August 5, 2020. On review of this compliance filing, the FERC is expected to address how these additional reforms will impact MOPR levels, the timeline for implementing the new revenue projection methodology, and the timing for commencing the capacity auction schedule.

Exelon Generation is currently working with the PJM and other stakeholders to pursue the FRR option as an alternative to the next PJM capacity auction. If Illinois implements the FRR option, Quad Cities Station could be removed from the PJM's capacity auction and instead supply capacity and be compensated under the FRR program. If Illinois cannot implement an FRR program in its PJM zones, then the MOPR will apply to Quad Cities Station, resulting in higher offers for its units that may not clear the capacity market. Implementing the FRR program in Illinois will require both legislative and regulatory changes. MidAmerican Energy cannot predict whether or when such legislative and regulatory changes can be implemented or their potential impact on the continued operation of Quad Cities Station.

Regulatory Matters

MidAmerican Energy is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding MidAmerican Energy's current regulatory matters.

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 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 the EPA and various 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 consolidated financial results. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

124

---

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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of MidAmerican Energy's and MidAmerican Funding's critical accounting estimates, see Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2019. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2019.

125

---

Nevada Power Company and its subsidiaries

Consolidated Financial Section

126

---

PART I

Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Nevada Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of September 30, 2020, the related consolidated statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2020 and 2019, and of cash flows for the nine-month periods ended September 30, 2020 and 2019, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Nevada Power as of December 31, 2019, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 21, 2020, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2019, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of Nevada Power's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

November 6, 2020

127

---

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)

	As of
	September 30,				December 31,
	2020				2019
ASSETS
Current assets:
Cash and cash equivalents	$	152			$	15
Trade receivables, net	386				215
Inventories	66				62
Prepayments	54				42
Other current assets	70				30
Total current assets	728				364
Property, plant and equipment, net	6,643				6,538
Finance lease right of use assets, net	354				441
Regulatory assets	782				800
Other assets	59				59
Total assets	$	8,566			$	8,202
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	209			$	194
Accrued interest	38				30
Accrued property, income and other taxes	76				25
Current portion of long-term debt	—				575
Regulatory liabilities	172				93
Customer deposits	50				62
Other current liabilities	84				58
Total current liabilities	629				1,037
Long-term debt	2,496				1,776
Finance lease obligations	338				430
Regulatory liabilities	1,129				1,163
Deferred income taxes	712				714
Other long-term liabilities	276				285
Total liabilities	5,580				5,405
Commitments and contingencies (Note 8)
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	682				493
Accumulated other comprehensive loss, net	(4		)		(4		)
Total shareholder's equity	2,986				2,797
Total liabilities and shareholder's equity	$	8,566			$	8,202
The accompanying notes are an integral part of the consolidated financial statements.

128

---

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Operating revenue	$	808			$	806			$	1,706			$	1,728
Operating expenses:
Cost of fuel and energy	287				353				654				752
Operations and maintenance	139				109				295				263
Depreciation and amortization	92				89				273				267
Property and other taxes	12				11				35				34
Total operating expenses	530				562				1,257				1,316
Operating income	278				244				449				412
Other income (expense):
Interest expense	(40		)		(41		)		(122		)		(129		)
Allowance for borrowed funds	1				1				3				2
Allowance for equity funds	1				2				5				4
Other, net	6				4				12				17
Total other income (expense)	(32		)		(34		)		(102		)		(106		)
Income before income tax expense	246				210				347				306
Income tax expense	52				45				74				66
Net income	$	194			$	165			$	273			$	240
The accompanying notes are an integral part of these consolidated financial statements.

129

---

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions, except shares)

																	Accumulated
									Additional								Other				Total
		Common Stock							Paid-in				Retained				Comprehensive				Shareholder's
		Shares			Amount				Capital				Earnings				Loss, Net				Equity
Balance, June 30, 2019		1,000			$	—			$	2,308			$	580			$	(4	)		$	2,884
Net income		—			—				—				165				—				165
Balance, September 30, 2019		1,000			$	—			$	2,308			$	745			$	(4	)		$	3,049
Balance, December 31, 2018		1,000			$	—			$	2,308			$	600			$	(4	)		$	2,904
Net income		—			—				—				240				—				240
Dividends declared		—			—				—				(95		)		—				(95		)
Balance, September 30, 2019		1,000			$	—			$	2,308			$	745			$	(4	)		$	3,049
Balance, June 30, 2020		1,000			$	—			$	2,308			$	488			$	(4	)		$	2,792
Net income		—			—				—				194				—				194
Balance, September 30, 2020		1,000			$	—			$	2,308			$	682			$	(4	)		$	2,986
Balance, December 31, 2019		1,000			$	—			$	2,308			$	493			$	(4	)		$	2,797
Net income		—			—				—				273				—				273
Dividends declared		—			—				—				(85		)		—				(85		)
Other equity transactions		—			—				—				1				—				1
Balance, September 30, 2020		1,000			$	—			$	2,308			$	682			$	(4	)		$	2,986
The accompanying notes are an integral part of these consolidated financial statements.

130

---

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2020				2019
Cash flows from operating activities:
Net income	$	273			$	240
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	273				267
Allowance for equity funds	(5		)		(4		)
Changes in regulatory assets and liabilities	38				62
Deferred income taxes and amortization of investment tax credits	(3		)		(42		)
Deferred energy	(38		)		39
Amortization of deferred energy	(30		)		37
Other, net	5				(4		)
Changes in other operating assets and liabilities:
Trade receivables and other assets	(112		)		(110		)
Inventories	(4		)		2
Accrued property, income and other taxes	48				53
Accounts payable and other liabilities	(39		)		15
Net cash flows from operating activities	406				555
Cash flows from investing activities:
Capital expenditures	(343		)		(283		)
Proceeds from sale of assets	26				2
Net cash flows from investing activities	(317		)		(281		)
Cash flows from financing activities:
Proceeds from long-term debt	718				495
Repayments of long-term debt	(575		)		(500		)
Dividends paid	(85		)		(95		)
Other, net	(12		)		(11		)
Net cash flows from financing activities	46				(111		)
Net change in cash and cash equivalents and restricted cash and cash equivalents	135				163
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	25				121
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	160			$	284
The accompanying notes are an integral part of these consolidated financial statements.

131

---

NEVADA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)	General

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 the 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").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2020 and for the three- and nine-month periods ended September 30, 2020 and 2019. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2020 and 2019. The results of operations for the three- and nine-month periods ended September 30, 2020 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2019 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Nevada Power's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2020.

Coronavirus Disease 2019 ("COVID-19")

In March 2020, COVID-19 was declared a global pandemic and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and on economic conditions in the United States. COVID-19 has impacted many of Nevada Power's customers ranging from high unemployment levels, an inability to pay bills and business closures or operating at reduced capacity levels. While COVID-19 has impacted Nevada Power's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. These impacts include, but are not limited to, lower operating revenue from reductions in the consumption of electricity by retail utility customers, particularly in the commercial, industrial and distribution only service customer classes as the longer term impacts of COVID-19 and related customer and governmental responses remain uncertain, and higher bad debt expense resulting from a higher than average level of write-offs of uncollectible accounts associated with the suspension of disconnections and late payment fees to assist customers. The duration and extent of COVID-19 and its future impact on Nevada Power's business cannot be reasonably estimated at this time. Accordingly, significant estimates used in the preparation of Nevada Power's unaudited Consolidated Financial Statements, including those associated with evaluations of certain long-lived assets for impairment, expected credit losses on amounts owed to Nevada Power and potential regulatory recovery of certain costs may be subject to significant adjustments in future periods.

In March 2020, the Public Utilities Commission of Nevada ("PUCN") issued an emergency order for Nevada Power to establish a regulatory asset account related to the costs of maintaining service to customers affected by COVID-19 whose services would have been terminated or disconnected under normally-applicable terms of service.

132

---

(2)	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 September 30, 2020 and December 31, 2019, consist of funds restricted by the PUCN for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2020 and December 31, 2019, 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
	September 30,				December 31,
	2020				2019
Cash and cash equivalents	$	152			$	15
Restricted cash and cash equivalents included in other current assets	8				10
Total cash and cash equivalents and restricted cash and cash equivalents	$	160			$	25

(3)	Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):

			As of
	Depreciable Life		September 30,				December 31,
			2020				2019
Utility plant:
Generation	30 - 55 years		$	3,612			$	3,541
Transmission	45 - 70 years		1,455				1,444
Distribution	20 - 65 years		3,738				3,567
General and intangible plant	5 - 65 years		784				741
Utility plant			9,589				9,293
Accumulated depreciation and amortization			(3,112		)		(2,951		)
Utility plant, net			6,477				6,342
Other non-regulated, net of accumulated depreciation and amortization	45 years		1				1
Plant, net			6,478				6,343
Construction work-in-progress			165				195
Property, plant and equipment, net			$	6,643			$	6,538

(4)	Regulatory Matters

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. 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. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel and energy in future time periods.

133

---

Regulatory Rate Review

In June 2020, Nevada Power filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue reduction of $96 million but requested an annual revenue reduction of $120 million. In September 2020, Nevada Power filed an all-party settlement for the electric regulatory rate review. The settlement resolved all but one issue and provided for an annual revenue reduction of $93 million and required Nevada Power to issue a $120 million one-time bill credit, composed primarily of existing regulatory liabilities, to customers beginning in October 2020. The continuation of the earning sharing mechanism was the one issue that was not addressed in the settlement. In October 2020, the PUCN held a hearing on the continuation of the earning sharing mechanism and issued an interim order accepting the settlement and requiring the one-time bill credit be issued to customers. An order that will delineate the remaining parts of the settlement and conclude on the continuation of the earning sharing mechanism is expected by the end of 2020 and new rates will be effective on January 1, 2021.

Natural Disaster Protection Plan

In May 2019, Senate Bill 329 ("SB 329"), Natural Disaster Mitigation Measures, was signed into law, which requires Nevada Power to submit a natural disaster protection plan to the PUCN. The PUCN adopted natural disaster protection plan regulations in January 2020, that require Nevada Power 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 Nevada Power to prevent or respond to a fire or other natural disaster. The expenditures incurred by Nevada Power in developing and implementing the natural disaster protection plan are required to be held in a regulatory asset account, with Nevada Power filing an application for recovery on or before March 1 of each year. Nevada Power submitted their initial natural disaster protection plan to the PUCN and filed their first application seeking recovery of 2019 expenditures in February 2020. In June 2020, a hearing was held and an order was issued in August 2020 that granted the joint application, made minor adjustments to the budget and approved the 2019 costs for recovery starting in October 2020. In October 2020, intervening parties filed petitions for reconsideration.

2017 Tax Reform

In February 2018, Nevada Power made a filing 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. The judicial review occurred in January 2020 and the district court issued an order in March 2020 denying the petition and affirming the PUCN's order. In May 2020, Nevada Power filed a notice of appeal to the Nevada Supreme Court of the district court's order. Nevada Power has agreed to withdraw the notice of appeal as a part of the Nevada Power electric regulatory rate review settlement. A final order on the settlement is expected by the end of 2020.

(5)	Recent Financing Transactions

Long-Term Debt

In May 2020, Nevada Power repurchased and entered into a re-offering of the following series of fixed-rate tax-exempt bonds: $40 million of its Coconino County Pollution Control Refunding Revenue Bonds, Series 2017A, due 2032; $13 million of its Coconino County Pollution Control Refunding Revenue Bonds, Series 2017B, due 2039; and $40 million of its Clark County Pollution Control Refunding Revenue Bonds, Series 2017, due 2036. The Series 2017A bond was offered at a fixed rate of 1.875% and the Series 2017B and Series 2017 bonds were offered at a fixed rate of 1.65%.

In January 2020, Nevada Power issued $425 million of 2.40% General and Refunding Mortgage Notes, Series DD, due 2030 and $300 million of its 3.125% General and Refunding Mortgage Notes, Series EE, due 2050. Nevada Power used the net proceeds for the early redemption of $575 million of its 2.75% General and Refunding Mortgage Notes, Series BB, due April 2020 and for general corporate purposes.

134

---

(6)    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. 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 (in millions):

	As of
	September 30,				December 31,
	2020				2019
Qualified Pension Plan:
Other long-term liabilities	$	18			$	18
Non-Qualified Pension Plans:
Other current liabilities	1				1
Other long-term liabilities	9				9
Other Postretirement Plans:
Other long-term liabilities	2				2

(7)	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.

135

---

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 September 30, 2020
Assets:
Commodity derivatives	$	—			$	—			$	6			$	6
Money market mutual funds(1)	142				—				—				142
Investment funds	2				—				—				2
	$	144			$	—			$	6			$	150
Liabilities - commodity derivatives	$	—			$	—			$	(6	)		$	(6	)
As of December 31, 2019
Assets:
Money market mutual funds(1)	$	10			$	—			$	—			$	10
Investment funds	2				—				—				2
	$	12			$	—			$	—			$	12
Liabilities - commodity derivatives	$	—			$	—			$	(8	)		$	(8	)

(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 September 30, 2020 and 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 investment funds 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.

136

---

The following table reconciles the beginning and ending balances of Nevada Power's commodity derivative assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Beginning balance	$	(44	)		(11		)		$	(8	)		$	3
Changes in fair value recognized in regulatory assets	13				(13		)		(31		)		(30		)
Settlements	31				6				39				9
Ending balance	$	—			$	(18	)		$	—			$	(18	)

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 (in millions):

	As of September 30, 2020								As of December 31, 2019
	Carrying				Fair				Carrying				Fair
	Value				Value				Value				Value
Long-term debt	$	2,496			$	3,210			$	2,351			$	2,848

(8)	Commitments and Contingencies

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.

Environmental Laws and Regulations

Nevada Power is subject to federal, state and local 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 Nevada Power's current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.

137

---

(9)	Revenue from Contracts with Customers

The following table summarizes Nevada Power's revenue from contracts with customers ("Customer Revenue") by customer class (in millions):

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Customer Revenue:
Retail:
Residential	$	495			$	468			$	993			$	934
Commercial	127				142				317				346
Industrial	147				169				300				351
Other	3				4				8				15
Total fully bundled	772				783				1,618				1,646
Distribution only service	8				9				20				24
Total retail	780				792				1,638				1,670
Wholesale, transmission and other	21				8				48				39
Total Customer Revenue	801				800				1,686				1,709
Other revenue	7				6				20				19
Total revenue	$	808			$	806			$	1,706			$	1,728

138

---

Item 2.    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 unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Nevada Power's actual results in the future could differ significantly from the historical results.

Results of Operations for the Third Quarter and First Nine Months of 2020 and 2019

Overview

Net income for the third quarter of 2020 was $194 million, an increase of $29 million, or 18%, compared to 2019 primarily due to $68 million of higher utility margin primarily due to the favorable impacts of weather, price impacts from changes in sales mix and revenue recognized due to a favorable regulatory decision. This increase is offset by $30 million of higher operations and maintenance expenses, primarily due to a higher accrual for earnings sharing of $20 million and higher regulatory-directed debits of $11 million, partially offset by lower long-term incentive plan costs and higher income tax expense of $7 million due to higher pre-tax income.

Net income for the first nine months of 2020 was $273 million, an increase of $33 million, or 14%, compared to 2019 primarily due to $76 million of higher utility margin primarily due to the favorable impacts of weather, price impacts from changes in sales mix and revenue recognized due to a favorable regulatory decision. The increase is offset by $32 million of higher operations and maintenance expenses, primarily due to higher regulatory-directed debits of $22 million and a higher accrual for earnings sharing of $14 million, partially offset by lower plant operation and maintenance costs of $9 million, lower long-term incentive plan costs and higher income tax expense of $8 million due to higher pre-tax income.

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 electric 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 are directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in Nevada Power's expenses 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 sales 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 (in millions):

		Third Quarter														First Nine Months
		2020				2019				Change						2020				2019				Change
Utility margin:
Operating revenue		$	808			$	806			$	2		—	%		$	1,706			$	1,728			$	(22	)	(1	)%
Cost of fuel and energy		287				353				(66		)	(19	)		654				752				(98		)	(13	)
Utility margin		521				453				68			15			1,052				976				76			8
Operations and maintenance		139				109				30			28			295				263				32			12
Depreciation and amortization		92				89				3			3			273				267				6			2
Property and other taxes		12				11				1			9			35				34				1			3
Operating income		$	278			$	244			$	34		14	%		$	449			$	412			$	37		9	%

139

---

A comparison of Nevada Power's key operating results is as follows:

		Third Quarter														First Nine Months
		2020				2019				Change						2020				2019				Change
Utility margin (in millions):
Operating revenue		$	808			$	806			$	2		—	%		$	1,706			$	1,728			$	(22	)	(1	)%
Cost of fuel and energy		287				353				(66		)	(19	)		654				752				(98		)	(13	)
Utility margin		$	521			$	453			$	68		15	%		$	1,052			$	976			$	76		8	%
Sales (GWhs):
Residential		4,378				3,908				470			12	%		8,557				7,692				865			11	%
Commercial		1,471				1,569				(98		)	(6	)		3,553				3,698				(145		)	(4	)
Industrial		1,477				1,600				(123		)	(8	)		3,735				4,140				(405		)	(10	)
Other		48				49				(1		)	(2	)		142				143				(1		)	(1	)
Total fully bundled(1)		7,374				7,126				248			3			15,987				15,673				314			2
Distribution only service		664				786				(122		)	(16	)		1,776				2,006				(230		)	(11	)
Total retail		8,038				7,912				126			2			17,763				17,679				84			—
Wholesale		82				50				32			64			316				314				2			1
Total GWhs sold		8,120				7,962				158			2	%		18,079				17,993				86			—	%
Average number of retail customers (in thousands)		970				954				16			2	%		966				950				16			2	%
Average revenue per MWh:
Retail - fully bundled(1)		$	104.72			$	109.94			$	(5.22	)	(5	)%		$	101.21			$	105.04			$	(3.83	)	(4	)%
Wholesale		$	78.36			$	36.63			$	41.73		114	%		$	41.28			$	35.64			$	5.64		16	%
Heating degree days		—				—				—			—			984				1,108				(124		)	(11	)%
Cooling degree days		2,537				2,392				145			6	%		3,847				3,511				336			10	%
Sources of energy (GWhs)(2)(3):
Natural gas		4,888				5,042				(154		)	(3	)%		10,628				10,296				332			3	%
Coal		—				377				(377		)	*			—				968				(968		)	*
Renewables		18				20				(2		)	(10	)		54				50				4			8
Total energy generated		4,906				5,439				(533		)	(10	)		10,682				11,314				(632		)	(6	)
Energy purchased		2,366				1,787				579			32			5,532				4,958				574			12
Total		7,272				7,226				46			1	%		16,214				16,272				(58		)	—	%
Average total cost of energy per MWh(4)		$	39.38			$	48.80			$	(9.42	)	(19	)%		$	40.32			$	48.33			$	(8.01	)	(17	)%

*    Not meaningful

(1)	Fully bundled includes sales to customers for combined energy, transmission and distribution services.

(2)

The average total cost of energy per MWh and sources of energy excludes - GWhs and 15 GWhs of coal and 152 GWhs and 199 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2020 and 2019, respectively. The average total cost of energy per MWh and sources of energy excludes - GWhs and 133 GWhs of coal and 1,180 GWhs and 1,122 GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 2020 and 2019, respectively.

(3)	GWh amounts are net of energy used by the related generating facilities.

(4)	The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.

140

---

Utility margin increased $68 million, or 15%, for the third quarter of 2020 compared to 2019 primarily due to:

•	$21 million of revenue recognized due to a favorable regulatory decision,

•	$17 million in higher residential customer volumes from the favorable impact of weather,

•	$14 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 1.6% primarily due to the favorable impacts of weather, offset by the impacts of COVID-19, which resulted in lower industrial, commercial and distribution only service customer usage and higher residential customer usage,

•	$9 million of higher transmission and wholesale revenue,

•	$4 million due to higher energy efficiency program rates (offset in operations and maintenance expense) and

•	$4 million of customer growth mainly from residential customers.

Operations and maintenance increased $30 million, or 28%, for the third quarter of 2020 compared to 2019 primarily due to a higher accrual for earnings sharing of $20 million, higher regulatory-directed debits of $11 million, relating to costs recognized for a bill credit to be paid in the fourth quarter as a result of the Nevada Power regulatory rate review stipulation, the deferral of the non-labor cost saving from the Navajo generating station retirement in 2019 and the deferral of costs for the ON Line lease to be returned to customers (offset in depreciation and amortization and other income (expense)) and higher energy efficiency program costs (offset in operating revenue), partially offset by lower long-term incentive plan costs.

Depreciation and amortization increased $3 million, or 3%, for the third quarter of 2020 compared to 2019 primarily due to higher plant placed in service, offset by lower depreciation expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).

Other income (expense) is favorable $2 million, or 6%, for the third quarter of 2020 compared to 2019 primarily due to higher cash surrender value of corporate-owned life insurance policies, lower interest expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense) and lower pension costs.

Income tax expense increased $7 million, or 16%, for the third quarter of 2020 compared to 2019 due to higher pre-tax income. The effective tax rate was 21% in 2020 and 2019.

Utility margin increased $76 million, or 8%, for the first nine months of 2020 compared to 2019 primarily due to:

•	$32 million in higher residential customer volumes from the favorable impacts of weather,

•	$21 million of revenue recognized due to a favorable regulatory decision,

•	$9 million due to higher energy efficiency program rates (offset in operations and maintenance expense),

•	$8 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 0.5% primarily due to the favorable impacts of weather, offset by the impacts of COVID-19, which resulted in lower industrial, commercial and distribution only service customer usage and higher residential customer usage,

•	$7 million of higher transmission and wholesale revenue and

•	$4 million due to customer growth, mainly residential.

The increase in utility margin was offset by:

•	$5 million of higher revenue reductions related to customer service agreements.

Operations and maintenance increased $32 million, or 12%, for the first nine months of 2020 compared to 2019 primarily due to higher regulatory-directed debits of $22 million, relating to the deferral of the non-labor cost saving from the Navajo generating station retirement in 2019, the deferral of costs for the ON Line lease to be returned to customers due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in depreciation and amortization and other income (expense)) and costs recognized for a bill credit to be paid in the fourth quarter as a result of the Nevada Power regulatory rate review stipulation, a higher accrual for earnings sharing of $14 million and higher energy efficiency program costs (offset in operating revenue), partially offset by lower plant operation and maintenance costs and lower long-term incentive plan costs.

141

---

Depreciation and amortization increased $6 million, or 2%, for the first nine months of 2020 compared to 2019 primarily due to higher plant placed in service, offset by lower depreciation expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).

Other income (expense) is favorable $4 million, or 4%, for the first nine months of 2020 compared to 2019 primarily due to lower interest expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense), lower pension costs and lower interest expense on long-term debt due to lower interest rates, offset by lower cash surrender value of corporate-owned life insurance policies and lower other income due to a licensing agreement with a third party in 2019.

Income tax expense increased $8 million, or 12%, for the first nine months of 2020 compared to 2019 due to higher pre-tax income. The effective tax rate was 21% in 2020 and 22% in 2019.

Liquidity and Capital Resources

As of September 30, 2020, Nevada Power's total net liquidity was as follows (in millions):

Cash and cash equivalents		$	152
Credit facility		400
Total net liquidity		$	552
Credit facility:
Maturity date		2022

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2020 and 2019 were $406 million and $555 million, respectively. The change was primarily due to lower collections from customers, the timing of payments for operating costs, higher payments for generation long-term service agreements, decreased collections of customer advances and lower proceeds from a licensing agreement with a third party in 2019, partially offset by lower payments for income taxes, a decrease in payments for fuel costs and lower interest payments for long-term debt.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2020 and 2019 were $(317) million and $(281) million, respectively. The change was primarily due to increased capital expenditures, partially offset by higher proceeds from sale of assets primarily related to the regulatory-directed reallocation of ON Line assets between Nevada Power and Sierra Pacific. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month periods ended September 30, 2020 and 2019 were $46 million and $(111) million, respectively. The change was primarily due to greater proceeds from the issuance of long-term debt and lower dividends paid to NV Energy, Inc., partially offset by higher repayments of long-term debt.

Long-Term Debt

In May 2020, Nevada Power repurchased and entered into a re-offering of the following series of fixed-rate tax-exempt bonds: $40 million of its Coconino County Pollution Control Refunding Revenue Bonds, Series 2017A, due 2032; $13 million of its Coconino County Pollution Control Refunding Revenue Bonds, Series 2017B, due 2039; and $40 million of its Clark County Pollution Control Refunding Revenue Bonds, Series 2017, due 2036. The Series 2017A bond was offered at a fixed rate of 1.875% and the Series 2017B and Series 2017 bonds were offered at a fixed rate of 1.65%.

In January 2020, Nevada Power issued $425 million of 2.40% General and Refunding Mortgage Notes, Series DD, due 2030 and $300 million of 3.125% General and Refunding Mortgage Notes, Series EE, due 2050. Nevada Power used the net proceeds for the early redemption of $575 million of its 2.75% General and Refunding Mortgage Notes, Series BB, due April 2020 and for general corporate purposes.

142

---

Debt Authorizations

Nevada Power currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $3.2 billion (excluding borrowings under Nevada Power's $400 million secured credit facility); and (2) maintain a revolving credit facility of up to $1.3 billion. Nevada Power currently has an effective automatic shelf registration statement with the SEC to issue an indeterminate amount of general and refunding mortgage securities through October 2022.

Future Uses of Cash

Nevada Power 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 use of its secured revolving credit facility, 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 Nevada Power has access to external financing depends on a variety of factors, including regulatory approvals, Nevada Power's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

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.

Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):

	Nine-Month Periods								Annual
	Ended September 30,								Forecast
	2019				2020				2020
Generation development	$	—			$	17			$	20
Distribution	148				182				229
Transmission system investment	18				13				21
Other	117				131				203
Total	$	283			$	343			$	473

Nevada Power's forecast capital expenditures include investments related to operating projects that consist of routine expenditures for generation, transmission, distribution and other infrastructure needed to serve existing and expected demand.

Contractual Obligations

As of September 30, 2020, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2019.

143

---

COVID-19

In March 2020, COVID-19 was declared a global pandemic and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and many of the customers served by Nevada Power. While COVID-19 has impacted Nevada Power's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. In April 2020, the state of Nevada instituted a "stay-at-home" order requiring non-essential businesses, including casinos, to remain closed, which impacted Nevada Power's customers and, therefore, their needs and usage patterns for electricity as evidenced by a reduction in weather-normalized consumption due to COVID-19 through September 2020 compared to the same period in 2019. The state of Nevada has since moved to a long-term recovery plan with most businesses, including casinos, opening subject to capacity and other operating limitations that will be revised as the state and counties meet certain metrics. As the impacts of COVID-19 and related customer and governmental responses remain uncertain, including the duration of restrictions on business openings, a reduction in the consumption of electricity may continue to occur, particularly in the commercial and industrial classes as well as distribution only service customers. Due to regulatory requirements and voluntary actions taken by Nevada Power related to customer collection activity and suspension of disconnections for non-payment, Nevada Power has seen delays and reductions in cash receipts, from retail customers related to the impacts of COVID-19, which could result in higher than normal bad debt write-offs. The amount of such reductions in cash receipts through September 2020 has not been material compared to the same period in 2019 but uncertainty remains. The PUCN has approved the deferral of certain costs incurred in responding to COVID-19. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for further discussion.

Nevada Power's business has been deemed essential and its employees have been identified as "critical infrastructure employees" allowing them to move within communities and across jurisdictional boundaries as necessary to maintain its electric generation, transmission and distribution system. In response to the effects of COVID-19, Nevada Power has implemented its business continuity plan to protect its employees and customers. Such plans include a variety of actions, including situational use of personal protective equipment by employees when interacting with customers and implementing practices to enhance social distancing at the workplace. Such practices have included work-from-home, staggered work schedules, rotational work location assignments, increased cleaning and sanitation of work spaces and providing general health reminders intended to help lower the risk of spreading COVID-19.

Regulatory Matters

Nevada Power is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Nevada Power's 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 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 the EPA and various 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 Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. Nevada Power believes it is in material compliance with all applicable laws and regulations.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

144

---

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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Nevada Power's critical accounting estimates, see Item 7 of Nevada Power's Annual Report on Form 10‑K for the year ended December 31, 2019. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2019.

145

---

Sierra Pacific Power Company

Financial Section

146

---

PART I

Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of Sierra Pacific Power Company ("Sierra Pacific") as of September 30, 2020, the related statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2020 and 2019, and of cash flows for the nine-month periods ended September 30, 2020 and 2019, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the balance sheet of Sierra Pacific as of December 31, 2019, and the related statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 21, 2020, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2019, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of Sierra Pacific's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

November 6, 2020

147

---

SIERRA PACIFIC POWER COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)

	As of
	September 30,				December 31,
	2020				2019
ASSETS
Current assets:
Cash and cash equivalents	$	22			$	27
Trade receivables, net	102				109
Income taxes receivable	2				14
Inventories	75				57
Regulatory assets	50				12
Other current assets	29				20
Total current assets	280				239
Property, plant and equipment, net	3,143				3,075
Regulatory assets	287				283
Other assets	159				74
Total assets	$	3,869			$	3,671
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	133			$	103
Accrued interest	11				14
Accrued property, income and other taxes	12				12
Regulatory liabilities	44				49
Customer deposits	16				21
Other current liabilities	36				21
Total current liabilities	252				220
Long-term debt	1,164				1,135
Finance lease obligations	123				40
Regulatory liabilities	460				489
Deferred income taxes	362				347
Other long-term liabilities	118				120
Total liabilities	2,479				2,351
Commitments and contingencies (Note 9)
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	280				210
Accumulated other comprehensive loss, net	(1		)		(1		)
Total shareholder's equity	1,390				1,320
Total liabilities and shareholder's equity	$	3,869			$	3,671
The accompanying notes are an integral part of the financial statements.

148

---

SIERRA PACIFIC POWER COMPANY

STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Operating revenue:
Regulated electric	$	220			$	232			$	569			$	586
Regulated natural gas	15				16				83				75
Total operating revenue	235				248				652				661
Operating expenses:
Cost of fuel and energy	81				93				233				254
Cost of natural gas purchased for resale	4				6				44				35
Operations and maintenance	40				46				123				130
Depreciation and amortization	36				31				104				94
Property and other taxes	6				5				17				17
Total operating expenses	167				181				521				530
Operating income	68				67				131				131
Other income (expense):
Interest expense	(14		)		(12		)		(42		)		(36		)
Allowance for borrowed funds	—				—				1				1
Allowance for equity funds	1				—				3				2
Other, net	3				1				7				4
Total other income (expense)	(10		)		(11		)		(31		)		(29		)
Income before income tax expense	58				56				100				102
Income tax expense	6				12				10				22
Net income	$	52			$	44			$	90			$	80
The accompanying notes are an integral part of these financial statements.

149

---

SIERRA PACIFIC POWER COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions, except shares)

																	Accumulated
									Additional								Other				Total
		Common Stock							Paid-in				Retained				Comprehensive				Shareholder's
		Shares			Amount				Capital				Earnings				Loss, Net				Equity
Balance, June 30, 2019		1,000			$	—			$	1,111			$	143			$	—			$	1,254
Net income		—			—				—				44				—				44
Balance, September 30, 2019		1,000			$	—			$	1,111			$	187			$	—			$	1,298
Balance, December 31, 2018		1,000			$	—			$	1,111			$	153			$	—			$	1,264
Net income		—			—				—				80				—				80
Dividends declared		—			—				—				(46		)		—				(46		)
Balance, September 30, 2019		1,000			$	—			$	1,111			$	187			$	—			$	1,298
Balance, June 30, 2020		1,000			$	—			$	1,111			$	228			$	(1	)		$	1,338
Net income		—			—				—				52				—				52
Balance, September 30, 2020		1,000			$	—			$	1,111			$	280			$	(1	)		$	1,390
Balance, December 31, 2019		1,000			$	—			$	1,111			$	210			$	(1	)		$	1,320
Net income		—			—				—				90				—				90
Dividends declared		—			—				—				(20		)		—				(20		)
Balance, September 30, 2020		1,000			$	—			$	1,111			$	280			$	(1	)		$	1,390
The accompanying notes are an integral part of these financial statements.

150

---

SIERRA PACIFIC POWER COMPANY

STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2020				2019
Cash flows from operating activities:
Net income	$	90			$	80
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	104				94
Allowance for equity funds	(3		)		(2		)
Changes in regulatory assets and liabilities	(30		)		30
Deferred income taxes and amortization of investment tax credits	3				(5		)
Deferred energy	(5		)		7
Amortization of deferred energy	(6		)		(5		)
Other, net	—				(3		)
Changes in other operating assets and liabilities:
Trade receivables and other assets	(83		)		(3		)
Inventories	(18		)		(7		)
Accrued property, income and other taxes	8				10
Accounts payable and other liabilities	119				(7		)
Net cash flows from operating activities	179				189
Cash flows from investing activities:
Capital expenditures	(192		)		(165		)
Other, net	—				1
Net cash flows from investing activities	(192		)		(164		)
Cash flows from financing activities:
Proceeds from long-term debt	30				125
Repayments of long-term debt	—				(109		)
Dividends paid	(20		)		(46		)
Other, net	(3		)		(3		)
Net cash flows from financing activities	7				(33		)
Net change in cash and cash equivalents and restricted cash and cash equivalents	(6		)		(8		)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	32				76
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	26			$	68
The accompanying notes are an integral part of these financial statements.

151

---

SIERRA PACIFIC POWER COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

(1)	General

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").

The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of September 30, 2020 and for the three- and nine-month periods ended September 30, 2020 and 2019. The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2020 and 2019. The results of operations for the three- and nine-month periods ended September 30, 2020 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Financial Statements. Note 2 of Notes to Financial Statements included in Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2019 describes the most significant accounting policies used in the preparation of the unaudited Financial Statements. There have been no significant changes in Sierra Pacific's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2020.

Coronavirus Disease 2019 ("COVID-19")

In March 2020, COVID-19 was declared a global pandemic and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and on economic conditions in the United States. COVID-19 has impacted many of Sierra Pacific's customers ranging from high unemployment levels, an inability to pay bills and business closures or operating at reduced capacity levels. While COVID-19 has impacted Sierra Pacific's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. These impacts include, but are not limited to, lower operating revenue from reductions in the consumption of electricity by retail utility customers, particularly in the commercial, industrial and distribution only service customer classes as the longer term impacts of COVID-19 and related customer and governmental responses remain uncertain, and higher bad debt expense resulting from a higher than average level of write-offs of uncollectible accounts associated with the suspension of disconnections and late payment fees to assist customers. The duration and extent of COVID-19 and its future impact on Sierra Pacific's business cannot be reasonably estimated at this time. Accordingly, significant estimates used in the preparation of Sierra Pacific's unaudited Financial Statements, including those associated with evaluations of certain long-lived assets for impairment, expected credit losses on amounts owed to Sierra Pacific and potential regulatory recovery of certain costs may be subject to significant adjustments in future periods.

In March 2020, the Public Utilities Commission of Nevada ("PUCN") issued an emergency order for Sierra Pacific to establish a regulatory asset account related to the costs of maintaining service to customers affected by COVID-19 whose services would have been terminated or disconnected under normally-applicable terms of service.

152

---

(2)	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 September 30, 2020 and December 31, 2019, consist of funds restricted by the PUCN for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2020 and December 31, 2019, 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
	September 30,				December 31,
	2020				2019
Cash and cash equivalents	$	22			$	27
Restricted cash and cash equivalents included in other current assets	4				5
Total cash and cash equivalents and restricted cash and cash equivalents	$	26			$	32

(3)	Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):

			As of
	Depreciable Life		September 30,				December 31,
			2020				2019
Utility plant:
Electric generation	25 - 60 years		$	1,129			$	1,133
Electric transmission	50 - 100 years		911				840
Electric distribution	20 - 100 years		1,724				1,669
Electric general and intangible plant	5 - 70 years		187				178
Natural gas distribution	35 - 70 years		424				417
Natural gas general and intangible plant	5 - 70 years		14				14
Common general	5 - 70 years		344				338
Utility plant			4,733				4,589
Accumulated depreciation and amortization			(1,733		)		(1,629		)
Utility plant, net			3,000				2,960
Other non-regulated, net of accumulated depreciation and amortization	70 years		2				2
Plant, net			3,002				2,962
Construction work-in-progress			141				113
Property, plant and equipment, net			$	3,143			$	3,075

(4)	Regulatory Matters

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. 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. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel and energy in future time periods.

153

---

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 resolved all cost of capital and revenue requirement issues and provided for an annual revenue reduction of $5 million and required 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 April 2020, the PUCN issued a final order approving the weather normalization methodology that changed the additional annual revenue reduction from $3 million to $2 million with an effective date of January 1, 2020. Customers billed under rates utilizing the initial revenue reduction will be issued credits in the fourth quarter of 2020.

Natural Disaster Protection Plan

In May 2019, Senate Bill 329 ("SB 329"), Natural Disaster Mitigation Measures, was signed into law, which requires Sierra Pacific to submit a natural disaster protection plan to the PUCN. The PUCN adopted natural disaster protection plan regulations in January 2020, that require Sierra Pacific 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 Sierra Pacific to prevent or respond to a fire or other natural disaster. The expenditures incurred by Sierra Pacific in developing and implementing the natural disaster protection plan are required to be held in a regulatory asset account, with Sierra Pacific filing an application for recovery on or before March 1 of each year. Sierra Pacific submitted their initial natural disaster protection plan to the PUCN and filed their first application seeking recovery of 2019 expenditures in February 2020. In June 2020, a hearing was held and an order was issued in August 2020 that granted the joint application, made minor adjustments to the budget and approved the 2019 costs for recovery starting in October 2020. In October 2020, intervening parties filed petitions for reconsideration.

2017 Tax Reform

In February 2018, Sierra Pacific made a filing 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. The judicial review occurred in January 2020 and the district court issued an order in March 2020 denying the petition and affirming the PUCN's order. In May 2020, Sierra Pacific filed a notice of appeal to the Nevada Supreme Court of the district court's order. Sierra Pacific has agreed to withdraw the notice of appeal as a part of the Nevada Power electric regulatory rate review settlement. A final order on the settlement is expected by the end of 2020.

(5)	Recent Financing Transactions

Long-Term Debt

In September 2020, Sierra Pacific entered into a re-offering of $30 million of its Washoe County Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036. The series was offered at a fixed rate of 0.625% for a two-year term subject to mandatory purchase by Sierra Pacific in April 2022 at which date the interest rate may be adjusted.

154

---

In April 2020, Sierra Pacific entered into a re-offering of the following series of tax-exempt bonds that were held in treasury: $30 million of its Washoe County Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $59 million of its Washoe County Gas Facilities Refunding Revenue Bonds, Series 2016A, due 2031; and $20 million of its Humboldt County Water Facilities Refunding Revenue Bonds, Series 2016A, due 2029. The interest rate mode of these bonds was changed to a variable rate from an annual fixed rate. Sierra Pacific holds the Washoe and Humboldt County Series 2016A bonds and they could be issued at a future date if deemed necessary.

(6)    Income Taxes

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:

	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2020			2019			2020			2019
Federal statutory income tax rate	21	%		21	%		21	%		21	%
Effects of ratemaking	(11	)		—			(10	)		—
Other	—			—			(1	)		1
Effective income tax rate	10	%		21	%		10	%		22	%

Effects of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act pursuant to an order issued by the PUCN effective January 1, 2020.

(7)	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. 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 (in millions):

	As of
	September 30,				December 31,
	2020				2019
Qualified Pension Plan:
Other long-term liabilities	$	2			$	4
Non-Qualified Pension Plans:
Other current liabilities	1				1
Other long-term liabilities	7				8
Other Postretirement Plans:
Other long-term liabilities	7				7

155

---

(8)	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 September 30, 2020
Assets:
Commodity derivatives	$	—			$	—			$	2			$	2
Money market mutual funds(1)	18				—				—				18
Investment funds	1				—				—				1
	$	19			$	—			$	2			$	21
As of December 31, 2019
Assets - money market mutual funds(1)	$	25			$	—			$	—			$	25
Liabilities - commodity derivatives	$	—			$	—			$	(1	)		$	(1	)

(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 investment funds 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 (in millions):

	As of September 30, 2020								As of December 31, 2019
	Carrying				Fair				Carrying				Fair
	Value				Value				Value				Value
Long-term debt	$	1,164			$	1,362			$	1,135			$	1,258

156

---

(9)	Commitments and Contingencies

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.

Environmental Laws and Regulations

Sierra Pacific is subject to federal, state and local 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 Sierra Pacific's current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.

(10)	Revenue from Contracts with Customers

The following table summarizes Sierra Pacific's revenue from contracts with customers ("Customer Revenue") by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 11 (in millions):

	Three-Month Periods
	Ended September 30,
	2020												2019
	Electric				Natural Gas				Total				Electric				Natural Gas				Total
Customer Revenue:
Retail:
Residential	$	76			$	11			$	87			$	75			$	11			$	86
Commercial	71				3				74				80				3				83
Industrial	57				1				58				58				1				59
Other	1				—				1				2				—				2
Total fully bundled	205				15				220				215				15				230
Distribution only service	1				—				1				1				—				1
Total retail	206				15				221				216				15				231
Wholesale, transmission and other	13				—				13				16				—				16
Total Customer Revenue	219				15				234				232				15				247
Other revenue	1				—				1				—				1				1
Total revenue	$	220			$	15			$	235			$	232			$	16			$	248

157

---

	Nine-Month Periods
	Ended September 30,
	2020												2019
	Electric				Natural Gas				Total				Electric				Natural Gas				Total
Customer Revenue:
Retail:
Residential	$	208			$	54			$	262			$	201			$	49			$	250
Commercial	183				20				203				188				18				206
Industrial	132				8				140				143				6				149
Other	3				—				3				5				—				5
Total fully bundled	526				82				608				537				73				610
Distribution only service	3				—				3				3				—				3
Total retail	529				82				611				540				73				613
Wholesale, transmission and other	37				—				37				44				—				44
Total Customer Revenue	566				82				648				584				73				657
Other revenue	3				1				4				2				2				4
Total revenue	$	569			$	83			$	652			$	586			$	75			$	661

158

---

(11)	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):

	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
	2020				2019				2020				2019
Operating revenue:
Regulated electric	$	220			$	232			$	569			$	586
Regulated natural gas	15				16				83				75
Total operating revenue	$	235			$	248			$	652			$	661
Operating income:
Regulated electric	$	66			$	67			$	119			$	119
Regulated natural gas	2				—				12				12
Total operating income	68				67				131				131
Interest expense	(14		)		(12		)		(42		)		(36		)
Allowance for borrowed funds	—				—				1				1
Allowance for equity funds	1				—				3				2
Other, net	3				1				7				4
Income before income tax expense	$	58			$	56			$	100			$	102

	As of
	September 30,				December 31,
	2020				2019
Assets:
Regulated electric	$	3,515			$	3,319
Regulated natural gas	318				308
Other(1)	36				44
Total assets	$	3,869			$	3,671

(1)	Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.

159

---

Item 2.    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 unaudited Financial Statements and Notes to Financial Statements in Part I, Item 1 of this Form 10-Q. Sierra Pacific's actual results in the future could differ significantly from the historical results.

Results of Operations for the Third Quarter and First Nine Months of 2020 and 2019

Overview

Net income for the third quarter of 2020 was $52 million, an increase of $8 million, or 18%, compared to 2019 primarily due to $6 million of lower income tax expense due to the recognition of amortization of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act following regulatory approval effective January 1, 2020, $6 million of lower operations and maintenance expenses, primarily due to lower long-term incentive plan costs and higher regulatory-directed credits, partially offset by $5 million of higher depreciation and amortization mainly due to higher plant in service.

Net income for the first nine months of 2020 was $90 million, an increase of $10 million, or 13%, compared to 2019 primarily due to $12 million of lower income tax expense due to the recognition of amortization of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act following regulatory approval effective January 1, 2020, $7 million of lower operations and maintenance expenses, primarily due to higher regulatory-directed credits and lower long-term incentive plan costs, and $4 million of higher electric utility margin, partially offset by $10 million of higher depreciation and amortization mainly due to higher plant in service and $2 million of unfavorable other income (expense).

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 customers through regulatory recovery mechanisms and as a result, changes in Sierra Pacific's expenses result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain 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.

160

---

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 (in millions):

		Third Quarter														First Nine Months
		2020				2019				Change						2020				2019				Change
Electric utility margin:
Operating revenue		$	220			$	232			$	(12	)	(5	)%		$	569			$	586			$	(17	)	(3	)%
Cost of fuel and energy		81				93				(12		)	(13	)		233				254				(21		)	(8	)
Electric utility margin		139				139				—			—			336				332				4			1
Natural gas utility margin:
Operating revenue		15				16				(1		)	(6	)%		83				75				8			11	%
Natural gas purchased for resale		4				6				(2		)	(33	)		44				35				9			26
Natural gas utility margin		11				10				1			10			39				40				(1		)	(3	)
Utility margin		150				149				1			1	%		375				372				3			1	%
Operations and maintenance		40				46				(6		)	(13	)%		123				130				(7		)	(5	)%
Depreciation and amortization		36				31				5			16			104				94				10			11
Property and other taxes		6				5				1			20			17				17				—			—
Operating income		$	68			$	67			$	1		1	%		$	131			$	131			$	—		—	%

161

---

Electric Utility Margin

A comparison of key operating results related to electric utility margin is as follows:

		Third Quarter														First Nine Months
		2020				2019				Change						2020				2019				Change
Electric utility margin (in millions):
Electric operating revenue		$	220			$	232			$	(12	)	(5	)%		$	569			$	586			$	(17	)	(3	)%
Cost of fuel and energy		81				93				(12		)	(13	)		233				254				(21		)	(8	)
Electric utility margin		$	139			$	139			$	—		—	%		$	336			$	332			$	4		1	%
Sales (GWhs):
Residential		796				696				100			14	%		2,016				1,881				135			7	%
Commercial		865				903				(38		)	(4	)		2,288				2,281				7			—
Industrial		923				886				37			4			2,643				2,815				(172		)	(6	)
Other		4				4				—			—			12				12				—			—
Total fully bundled(1)		2,588				2,489				99			4			6,959				6,989				(30		)	—
Distribution only service		422				416				6			1			1,259				1,212				47			4
Total retail		3,010				2,905				105			4			8,218				8,201				17			—
Wholesale		87				100				(13		)	(13	)		376				458				(82		)	(18	)
Total GWhs sold		3,097				3,005				92			3	%		8,594				8,659				(65		)	(1	)%
Average number of retail customers (in thousands)		359				353				6			2	%		358				352				6			2	%
Average revenue per MWh:
Retail - fully bundled(1)		$	79.22			$	85.85			$	(6.63	)	(8	)%		$	75.65			$	76.73			$	(1.08	)	(1	)%
Wholesale		$	79.72			$	46.68			$	33.04		71	%		$	54.54			$	50.03			$	4.51		9	%
Heating degree days		15				119				(104		)	(87	)%		2,672				2,882				(210		)	(7	)%
Cooling degree days		946				891				55			6	%		1,166				1,107				59			5	%
Sources of energy (GWhs)(2)(3):
Natural gas		1,587				1,468				119			8	%		3,967				3,714				253			7	%
Coal		496				376				120			32			716				928				(212		)	(23	)
Renewables(4)		12				13				(1		)	(8	)		31				30				1			3
Total energy generated		2,095				1,857				238			13			4,714				4,672				42			1
Energy purchased		1,173				937				236			25			3,625				3,243				382			12
Total		3,268				2,794				474			17	%		8,339				7,915				424			5	%
Average total cost of energy per MWh(5)		$	24.95			$	33.33			$	(8.38	)	(25	)%		$	27.96			$	32.05			$	(4.09	)	(13	)%

(1)	Fully bundled includes sales to customers for combined energy, transmission and distribution services.

(2)

The average total cost of energy per MWh and sources of energy excludes 3 GWhs and - GWhs of coal and 7 GWhs and - GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2020 and 2019, respectively. The average total cost of energy per MWh and sources of energy excludes 3 GWhs and - GWhs of coal and 7 GWhs and - GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 2020 and 2019, respectively.

(3)	GWh amounts are net of energy used by the related generating facilities.

(4)	Includes the Fort Churchill Solar Array which is under lease by Sierra Pacific.

(5)	The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.

162

---

Natural Gas Utility Margin

A comparison of key operating results related to natural gas utility margin is as follows:

		Third Quarter														First Nine Months
		2020				2019				Change						2020				2019				Change
Utility margin (in millions):
Operating revenue		$	15			$	16			$	(1	)	(6	)%		$	83			$	75			$	8		11	%
Natural gas purchased for resale		4				6				(2		)	(33	)		44				35				9			26
Natural gas utility margin		$	11			$	10			$	1		10	%		$	39			$	40			$	(1	)	(3	)%
Sold (000's Dths):
Residential		786				814				(28		)	(3	)%		6,724				7,454				(730		)	(10	)%
Commercial		424				491				(67		)	(14	)		3,309				3,878				(569		)	(15	)
Industrial		249				278				(29		)	(10	)		1,244				1,357				(113		)	(8	)
Total retail		1,459				1,583				(124		)	(8	)%		11,277				12,689				(1,412		)	(11	)%
Average number of retail customers (in thousands)		174				171				3			2	%		174				170				4			2	%
Average revenue per retail Dth sold		$	9.89			$	10.11			$	(0.22	)	(2	)%		$	7.33			$	5.91			$	1.42		24	%
Heating degree days		15				119				(104		)	(87	)%		2,672				2,882				(210		)	(7	)%
Average cost of natural gas per retail Dth sold		$	3.01			$	3.79			$	(0.78	)	(21	)%		$	3.93			$	2.76			$	1.18		43	%

Electric utility margin remained consistent for the third quarter of 2020 compared to 2019 primarily due:

•	$2 million in higher residential customer volumes from the favorable impacts of weather,

•	$1 million due to higher energy efficiency program rates (offset in operations and maintenance expense),

•	$1 million of residential customer growth and

•	$1 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 3.6% primarily due to the favorable impacts of weather, offset by the impacts of COVID-19, which resulted in consistent industrial and commercial usage and higher residential customer usage.

The increase in utility margin was offset by:

•	$4 million of lower transmission and wholesale revenue and

•	$1 million of higher revenue reductions related to customer service agreements.

Operations and maintenance decreased $6 million, or 13%, for the third quarter of 2020 compared to 2019 primarily due to higher regulatory-directed credits relating to the deferral of costs for the ON Line lease to be collected from customers due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in depreciation and amortization and other income (expense)), lower long-term incentive plan costs and lower plant operations and maintenance expenses, partially offset by higher energy efficiency program costs (offset in operating revenue) and lower regulatory-directed credits relating to the amortization of an excess reserve balance that ended in 2019.

Depreciation and amortization increased $5 million, or 16%, for the third quarter of 2020 compared to 2019 primarily due to higher plant placed in service and higher depreciation expense on the ON Line finance lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).

Other income (expense) is favorable $1 million, or 9%, for the third quarter of 2020 compared to 2019 primarily due to lower pension costs, offset by higher interest expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).

163

---

Income tax expense decreased $6 million, or 50%, for the third quarter of 2020 compared to 2019. The effective tax rate was 10% in 2020 and 21% in 2019 and decreased due to the recognition of amortization of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act following regulatory approval effective January 1, 2020.

Electric utility margin increased $4 million, or 1%, for the first nine months of 2020 compared to 2019 primarily due:

•	$4 million in higher residential customer volumes from the favorable impact of weather,

•	$3 million due to higher energy efficiency program rates (offset in operations and maintenance expense),

•	$2 million of residential customer growth and

•	$1 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 0.2% primarily due to the favorable impact of weather, offset by the impacts of COVID-19, which resulted in lower industrial and commercial usage and higher residential customer usage.

The increase in utility margin was offset by:

•	$5 million of lower transmission and wholesale revenue and

•	$1 million of higher revenue reductions related to customer service agreements.

Operations and maintenance decreased $7 million, or 5%, for the first nine months of 2020 compared to 2019 primarily due to higher regulatory-directed credits relating to the deferral of costs for the ON Line lease to be collected from customers due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in depreciation and amortization and other income (expense)) of $7 million, lower plant operations and maintenance expenses and lower long-term incentive plan costs, offset by higher energy efficiency program costs (offset in operating revenue) and lower regulatory-directed credits relating to the amortization of an excess reserve balance that ended in 2019.

Depreciation and amortization increased $10 million, or 11%, for the first nine months of 2020 compared to 2019 primarily due to higher plant placed in service and higher depreciation expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).

Other income (expense) is unfavorable $2 million, or 7%, for the first nine months of 2020 compared to 2019 primarily due to higher interest expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense) and lower cash surrender value of corporate-owned life insurance policies, offset by lower pension costs.

Income tax expense decreased $12 million, or 55%, for the first nine months of 2020 compared to 2019. The effective tax rate was 10% in 2020 and 22% in 2019 and decreased due to the recognition of amortization of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act following regulatory approval effective January 1, 2020.

Liquidity and Capital Resources

As of September 30, 2020, Sierra Pacific's total net liquidity was as follows (in millions):

Cash and cash equivalents		$	22
Credit facility		250
Total net liquidity		$	272
Credit facility:
Maturity date		2022

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2020 and 2019 were $179 million and $189 million, respectively. The change was primarily due to lower collections from customers, higher inventory purchases and decreased collections of customer advances, partially offset by lower payments for income taxes and the timing of payments for operating costs.

164

---

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2020 and 2019 were $(192) million and $(164) million, respectively. The change was primarily due to increased capital expenditures including expenditures related to the regulatory-directed reallocation of ON Line assets between Nevada Power and Sierra Pacific. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month periods ended September 30, 2020 and 2019 were $7 million and $(33) million, respectively. The change was primarily due to lower payments to repurchase long-term debt and lower dividends paid to NV Energy, Inc., partially offset by lower proceeds from the re-offering of previously repurchased long-term debt.

Long-Term Debt

In September 2020, Sierra Pacific entered into a re-offering of $30 million of its Washoe County Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036. The series was offered at a fixed rate of 0.625% for a two-year term subject to mandatory purchase by Sierra Pacific in April 2022 at which date the interest rate may be adjusted.

In April 2020, Sierra Pacific entered into a re-offering of the following series of tax-exempt bonds that were held in treasury: $30 million of its Washoe County Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $59 million of its Washoe County Gas Facilities Refunding Revenue Bonds, Series 2016A, due 2031; and $20 million of its Humboldt County Water Facilities Refunding Revenue Bonds, Series 2016A, due 2029. The interest rate mode of these bonds was changed to a variable rate from an annual fixed rate. Sierra Pacific holds the Washoe and Humboldt County Series 2016A bonds and they could be issued at a future date if deemed necessary.

Debt Authorizations

Sierra Pacific currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $1.6 billion (excluding borrowings under Sierra Pacific's $250 million secured credit facility); and (2) maintain a revolving credit facility of up to $600 million.

Future Uses of Cash

Sierra Pacific 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 use of its secured revolving credit facility, 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 Sierra Pacific has access to external financing depends on a variety of factors, including regulatory approvals, Sierra Pacific's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

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.

165

---

Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):

	Nine-Month Periods								Annual
	Ended September 30,								Forecast
	2019				2020				2020
Distribution	$	117			$	107			$	132
Transmission system investment	10				46				28
Other	38				39				57
Total	$	165			$	192			$	217

Sierra Pacific's forecast capital expenditures include investments related to operating projects that consist of routine expenditures for generation, transmission, distribution and other infrastructure needed to serve existing and expected demand.

Contractual Obligations

As of September 30, 2020, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2019.

COVID-19

In March 2020, COVID-19 was declared a global pandemic and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and many of the customers served by Sierra Pacific. While COVID-19 has impacted Sierra Pacific's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. In April 2020, the state of Nevada instituted a "stay-at-home" order requiring non-essential businesses, including casinos, to remain closed, which impacted Sierra Pacific's customers and, therefore, their needs and usage patterns for electricity and natural gas. The state of Nevada has since moved to a long-term recovery plan with most businesses, including casinos, opening subject to capacity and other operating limitations that will be revised as the state and counties meet certain metrics. As the impacts of COVID-19 and related customer and governmental responses remain uncertain, including the duration of restrictions on business openings, a reduction in the consumption of electricity or natural gas may occur, particularly in the commercial and industrial classes as well as distribution only service customers. Due to regulatory requirements and voluntary actions taken by Sierra Pacific related to customer collection activity and suspension of disconnections for non-payment, Sierra Pacific has seen delays and reductions in cash receipts from retail customers related to the impacts of COVID-19, which could result in higher than normal bad debt write-offs. The amount of such reductions in cash receipts through September 2020 has not been material compared to the same period in 2019 but uncertainty remains. The PUCN has approved the deferral of certain costs incurred in responding to COVID-19. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for further discussion.

Sierra Pacific's business has been deemed essential and its employees have been identified as "critical infrastructure employees" allowing them to move within communities and across jurisdictional boundaries as necessary to maintain its electric generation, transmission and distribution system and its natural gas distribution system. In response to the effects of COVID-19, Sierra Pacific has implemented its business continuity plan to protect its employees and customers. Such plans include a variety of actions, including situational use of personal protective equipment by employees when interacting with customers and implementing practices to enhance social distancing at the workplace. Such practices have included work-from-home, staggered work schedules, rotational work location assignments, increased cleaning and sanitation of work spaces and providing general health reminders intended to help lower the risk of spreading COVID-19.

Regulatory Matters

Sierra Pacific is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Sierra Pacific's current regulatory matters.

166

---

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 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 the EPA and various 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 Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and financial results. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Sierra Pacific's critical accounting estimates, see Item 7 of Sierra Pacific's Annual Report on Form 10‑K for the year ended December 31, 2019. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2019.

Item 3.	Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting the Registrants, see Item 7A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2019. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2019. Refer to Note 7 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q for disclosure of the respective Registrant's derivative positions as of September 30, 2020.

Item 4.	Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q, 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 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 Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission'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 September 30, 2020 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

167

---

PART II

Item 1.	Legal Proceedings

PacifiCorp

On September 30, 2020, a putative class action complaint against PacifiCorp was filed, captioned Jeanyne James et. al. vs. PacifiCorp, Case No. 20cv33885, Circuit Court, Multnomah County, Oregon. The complaint was filed on behalf of certain named Oregon residents and businesses and all Oregon citizens and entities whose real or personal property was harmed by wildfires in Oregon beginning on or after September 7, 2020. The complaint alleges that PacifiCorp's assets contributed to the Oregon wildfires occurring on or after September 7, 2020 and that PacifiCorp acted with gross negligence, among other things. The complaint was amended November 2, 2020 to seek the following damages: (i) damages for real and personal property and other economic losses in excess of $600 million; (ii) double the amount of property and economic damages based on alleged gross negligence; (iii) treble damages for specific costs associated with loss of timber, trees and shrubbery; (iv) double the damages for the costs of litigation and reforestation; and (v) prejudgment interest. The plaintiffs demand a trial by jury and have reserved their right to amend the complaint to allege claims for punitive damages. Other individual lawsuits alleging similar claims have been filed in Oregon related to the 2020 wildfires. Investigations as to the cause and origin of the wildfires are ongoing.

For more information regarding certain legal proceedings affecting PacifiCorp, refer to Note 9 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q.

Item 1A.	Risk Factors

There has been no material change to each Registrant's risk factors from those disclosed in Item 1A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2019, except as disclosed below.

Each Registrant's business could be adversely affected by COVID-19 or other pathogens, or similar crises.

Each Registrant's business could be adversely affected by the worldwide outbreak of COVID-19 generally and more specifically in the markets in which we operate, including, without limitation, if each Registrant's utility customers experience decreases in demand for their products and services and thereby reduce their consumption of electricity or natural gas that the respective Registrant supplies, or if such Registrant experiences material payment defaults by its customers. For example, if the tourism industry in Nevada experiences a significant and extended decrease as a result of changes in customer behavior, demand for electricity sold by Nevada Power and Sierra Pacific could decrease. In addition, each Registrant's results and financial condition may be adversely affected by federal, state or local legislation related to COVID-19 (or other similar laws, regulations, orders or other governmental or regulatory actions) that would impose a moratorium on terminating electric or natural gas utility services, including related assessment of late fees, due to non-payment or other circumstances. Certain Registrants have already temporarily implemented certain of these measures, either voluntarily or in accordance with requirements of the respective Registrant's public utility commissions. These requirements will likely remain for the duration of the COVID-19 emergency. Additionally, HomeServices' residential real estate brokerage business could experience a decline (which could be significant) in residential property transactions if potential customers elect to defer purchases in reaction to any substantial outbreak, or fear of such outbreak, of COVID-19 or other pathogen, or due to general economic uncertainty such as high unemployment levels, in some or all of the real estate markets in which HomeServices operates. The government and regulators could impose other requirements on each Registrant's business that could have an adverse impact on such Registrant's financial results.

Further, the recent outbreak of COVID-19, or another pathogen, could disrupt supply chains (including supply chains for energy generation, steel or transmission wire) relating to the markets each Registrant serves, which could adversely impact such Registrant's ability to generate or supply power. In addition, such disruptions to the supply chain could delay certain construction and other capital expenditure projects, including construction and repowering of PacifiCorp's and MidAmerican Energy's wind-powered generation projects. Such disruptions could adversely affect the impacted Registrant's future financial results.

Such declines in demand, any inability to generate or supply power or delays in capital projects could also significantly reduce cash flows at BHE's subsidiaries, thereby reducing the availability of distributions to BHE, which could adversely affect its financial results.

168

---

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

On October 29, 2020, BHE issued 3,750,000 shares of its 4.00% Perpetual Preferred Stock (the "Perpetual Preferred") to certain subsidiaries of its parent, Berkshire Hathaway, for an aggregate purchase price of $3.75 billion (the "New Preferred Investment"), in order to provide funding for (i) the GT&S Cash Consideration and (ii) the Q-Pipe Cash Consideration, each as defined in Note 2 of the Notes to Consolidated Financial Statements of BHE in Part I, Item 1 of this Form 10-Q.

The New Preferred Investment was effected pursuant to a private placement and was exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereunder.

Item 3.	Defaults Upon Senior Securities

Not applicable.

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 Wall Street Reform and Consumer Protection Act is included in Exhibit 95 to this Form 10-Q.

Item 5.	Other Information

Not applicable.

Item 6.	Exhibits

The following is a list of exhibits filed as part of this Quarterly Report.

169

---

Exhibit No.	Description

BERKSHIRE HATHAWAY ENERGY

2.1	Purchase and Sale Agreement, dated as of July 3, 2020, by and among Dominion Energy, Inc., Dominion Energy Questar Corporation and Berkshire Hathaway Energy Company (incorporated by reference to Exhibit 2.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated July 6, 2020).

2.2	Purchase and Sale Agreement, dated as of October 5, 2020, by and between Dominion Energy Questar Corporation, Dominion Energy, Inc. and Berkshire Hathaway Energy Company (incorporated by reference to Exhibit 2.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated October 6, 2020).

3.1	Third Amended and Restated Articles of Incorporation of Berkshire Hathaway Energy Company, effective as of October 27, 2020 (incorporated by reference to Exhibit 3.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated November 2, 2020).

4.1	Fourteenth Supplemental Indenture, dated as of March 24, 2020, by and between Berkshire Hathaway Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 4.05% Senior Notes due 2025 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated March 25, 2020).

4.2	Fifteenth Supplemental Indenture, dated as of March 27, 2020, by and between Berkshire Hathaway Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 3.70% Senior Notes due 2030 and the 4.25% Senior Notes due 2050 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated March 27, 2020).

4.3	Sixteenth Supplemental Indenture, dated as of October 29, 2020, by and between Berkshire Hathaway Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to 1.650% Senior Notes due 2031 and the 2.850% Senior Notes due 2051 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated November 2, 2020).

4.4	Trust Deed, dated as of June 16, 2020, by and between Northern Powergrid (Northeast) plc and HSBC Corporate Trustee Company (UK) Limited, Trustee, relating to the £300,000,000 in principal amount of 1.875% Green Bonds due 2062 (incorporated by reference to Exhibit 4.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).

4.5	Twenty-Third Supplemental Indenture, dated as of September 11, 2020, by and between AltaLink, L.P., AltaLink Management Ltd. and BNY Trust Company of Canada, as trustee, relating to the C$225,000,000 in principal amount of the 1.509% Series 2020-1 Senior Secured Notes due 2021.

10.1	Credit Agreement, dated as of April 27, 2020, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).

10.2	Credit Agreement, dated as of April 27, 2020, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).

15.1	Awareness Letter of Independent Registered Public Accounting Firm.

31.1	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

PACIFICORP

15.2	Awareness Letter of Independent Registered Public Accounting Firm.

31.3	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

170

---

32.3	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.4	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP

4.6	Thirty-First Supplemental Indenture, dated as of April 1, 2020, to PacifiCorp's Mortgage and Deed of Trust dated as of January 9, 1989 (incorporated by reference to Exhibit 4.1 to the PacifiCorp Current Report on Form 8-K dated April 8, 2020).

95	Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act.

MIDAMERICAN ENERGY

15.3	Awareness Letter of Independent Registered Public Accounting Firm.

31.5	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.6	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.5	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.6	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND MIDAMERICAN ENERGY

10.3	$600,000,000, 364-Day Credit Agreement, dated as of May 12, 2020, among MidAmerican Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, and Mizuho Bank, Ltd., as Administrative Agent (incorporated by reference to Exhibit 10.3 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).

MIDAMERICAN FUNDING

31.7	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.8	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.7	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.8	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

NEVADA POWER

15.4	Awareness Letter of Independent Registered Public Accounting Firm.

31.9	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.10	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.9	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.10	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIERRA PACIFIC

31.11	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.12	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.11	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.12	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

171

---

ALL REGISTRANTS

101

The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, 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.

172

---

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	BERKSHIRE HATHAWAY ENERGY COMPANY
Date: November 6, 2020	/s/ Calvin D. Haack
	Calvin D. Haack
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)
	PACIFICORP
Date: November 6, 2020	/s/ Nikki L. Kobliha
	Nikki L. Kobliha
	Vice President, Chief Financial Officer and Treasurer
	(principal financial and accounting officer)
	MIDAMERICAN FUNDING, LLC
	MIDAMERICAN ENERGY COMPANY
Date: November 6, 2020	/s/ Thomas B. Specketer
	Thomas B. Specketer
	Vice President and Controller
	of MidAmerican Funding, LLC and
	Vice President and Chief Financial Officer
	of MidAmerican Energy Company
	(principal financial and accounting officer)
	NEVADA POWER COMPANY
Date: November 6, 2020	/s/ Michael E. Cole
	Michael E. Cole
	Vice President, Chief Financial Officer and Treasurer
	(principal financial and accounting officer)
	SIERRA PACIFIC POWER COMPANY
Date: November 6, 2020	/s/ Michael E. Cole
	Michael E. Cole
	Vice President, Chief Financial Officer and Treasurer
	(principal financial and accounting officer)

173