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 June 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)

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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

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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
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
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

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•	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;

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•	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 future acquired operations into a Registrant's business;

•	the expected timing and likelihood of completion of the proposed transaction with Dominion Energy, Inc., including the ability to obtain the required regulatory approvals and the terms and conditions of such regulatory approvals;

•	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.

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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		61
Consolidated Balance Sheets		62
Consolidated Statements of Operations		64
Consolidated Statements of Changes in Shareholders' Equity		65
Consolidated Statements of Cash Flows		66
Notes to Consolidated Financial Statements		67
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm		85
Balance Sheets		86
Statements of Operations		88
Statements of Changes in Shareholder's Equity		89
Statements of Cash Flows		90
Notes to Financial Statements		91
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm		100
Consolidated Balance Sheets		101
Consolidated Statements of Operations		103
Consolidated Statements of Changes in Member's Equity		104
Consolidated Statements of Cash Flows		105
Notes to Consolidated Financial Statements		106
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		122
Consolidated Balance Sheets		123
Consolidated Statements of Operations		124
Consolidated Statements of Changes in Shareholder's Equity		125
Consolidated Statements of Cash Flows		126
Notes to Consolidated Financial Statements		127
Sierra Pacific Power Company
Report of Independent Registered Public Accounting Firm		141
Balance Sheets		142
Statements of Operations		143
Statements of Changes in Shareholder's Equity		144
Statements of Cash Flows		145
Notes to Financial Statements		146

1

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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		76
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company		110
Nevada Power Company and its subsidiaries		134
Sierra Pacific Power Company		154

2

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Berkshire Hathaway Energy Company and its subsidiaries

Consolidated Financial Section

3

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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 June 30, 2020, the related consolidated statements of operations, comprehensive income and changes in equity for the three-month and six-month periods ended June 30, 2020 and 2019, and of cash flows for the six-month periods ended June 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

August 7, 2020

4

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BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,				December 31,
	2020				2019
ASSETS
Current assets:
Cash and cash equivalents	$	1,815			$	1,040
Restricted cash and cash equivalents	237				212
Trade receivables, net	1,904				1,910
Income tax receivable	503				—
Inventories	1,002				873
Mortgage loans held for sale	1,617				1,039
Amounts held in trust	435				211
Other current assets	715				628
Total current assets	8,228				5,913
Property, plant and equipment, net	73,825				73,305
Goodwill	9,612				9,722
Regulatory assets	2,831				2,766
Investments and restricted cash and cash equivalents and investments	7,874				6,255
Other assets	2,047				2,090
Total assets	$	104,417			$	100,051

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

5

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BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	June 30,				December 31,
	2020				2019
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,656			$	1,839
Accrued interest	529				493
Accrued property, income and other taxes	456				537
Accrued employee expenses	330				285
Short-term debt	2,289				3,214
Current portion of long-term debt	1,872				2,539
Other current liabilities	1,842				1,350
Total current liabilities	8,974				10,257
BHE senior debt	11,011				8,231
BHE junior subordinated debentures	100				100
Subsidiary debt	29,922				28,483
Regulatory liabilities	6,965				7,100
Deferred income taxes	10,002				9,653
Other long-term liabilities	3,658				3,649
Total liabilities	70,632				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	29,962				28,296
Accumulated other comprehensive loss, net	(2,125		)		(1,706		)
Total BHE shareholders' equity	33,684				32,449
Noncontrolling interests	101				129
Total equity	33,785				32,578
Total liabilities and equity	$	104,417			$	100,051

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

6

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BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Operating revenue:
Energy	$	3,419			$	3,567			$	7,053			$	7,392
Real estate	1,193				1,327				2,086				2,112
Total operating revenue	4,612				4,894				9,139				9,504
Operating expenses:
Energy:
Cost of sales	888				1,027				1,926				2,241
Operations and maintenance	794				822				1,531				1,624
Depreciation and amortization	725				728				1,534				1,448
Property and other taxes	153				148				304				297
Real estate	1,116				1,210				1,989				2,016
Total operating expenses	3,676				3,935				7,284				7,626
Operating income	936				959				1,855				1,878
Other income (expense):
Interest expense	(503		)		(476		)		(986		)		(953		)
Capitalized interest	19				17				36				33
Allowance for equity funds	38				38				72				70
Interest and dividend income	20				36				40				66
Gains (losses) on marketable securities, net	583				6				610				(62		)
Other, net	52				30				25				65
Total other income (expense)	209				(349		)		(203		)		(781		)
Income before income tax benefit and equity (loss) income	1,145				610				1,652				1,097
Income tax benefit	(7		)		(76		)		(191		)		(224		)
Equity (loss) income	(32		)		2				(50		)		(8		)
Net income	1,120				688				1,793				1,313
Net income attributable to noncontrolling interests	4				4				7				7
Net income attributable to BHE shareholders	$	1,116			$	684			$	1,786			$	1,306

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

 

7

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BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)

	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Net income	$	1,120			$	688			$	1,793			$	1,313
Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $2, $5, $13, and $(2)	10				18				44				(14		)
Foreign currency translation adjustment	109				(49		)		(439		)		106
Unrealized gains (losses) on cash flow hedges, net of tax of $3, $(9), $(7), and $(11)	9				(27		)		(24		)		(35		)
Total other comprehensive income (loss), net of tax	128				(58		)		(419		)		57
Comprehensive income	1,248				630				1,374				1,370
Comprehensive income attributable to noncontrolling interests	4				4				7				7
Comprehensive income attributable to BHE shareholders	$	1,244			$	626			$	1,367			$	1,363

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

8

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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, March 31, 2019	77			$	—			$	6,355			$	(457	)		$	25,968			$	(1,830	)		$	126			$	30,162
Net income	—			—				—				—				684				—				4				688
Other comprehensive loss	—			—				—				—				—				(58		)		—				(58		)
Distributions	—			—				—				—				—				—				(3		)		(3		)
Other equity transactions	—			—				—				—				(1		)		—				(1		)		(2		)
Balance, June 30, 2019	77			$	—			$	6,355			$	(457	)		$	26,651			$	(1,888	)		$	126			$	30,787
Balance, December 31, 2018	77			$	—			$	6,371			$	(457	)		$	25,624			$	(1,945	)		$	130			$	29,723
Net income	—			—				—				—				1,306				—				7				1,313
Other comprehensive income	—			—				—				—				—				57				—				57
Common stock purchases	—			—				(16		)		—				(277		)		—				—				(293		)
Distributions	—			—				—				—				—				—				(10		)		(10		)
Other equity transactions	—			—				—				—				(2		)		—				(1		)		(3		)
Balance, June 30, 2019	77			$	—			$	6,355			$	(457	)		$	26,651			$	(1,888	)		$	126			$	30,787
Balance, March 31, 2020	76			$	—			$	6,382			$	(530	)		$	28,846			$	(2,253	)		$	127			$	32,572
Net income	—			—				—				—				1,116				—				4				1,120
Other comprehensive income	—			—				—				—				—				128				—				128
Distributions	—			—				—				—				—				—				(2		)		(2		)
Purchase of noncontrolling interest	—			—				(5		)		—				—				—				(28		)		(33		)
Balance, June 30, 2020	76			$	—			$	6,377			$	(530	)		$	29,962			$	(2,125	)		$	101			$	33,785
Balance, December 31, 2019	77			$	—			$	6,389			$	(530	)		$	28,296			$	(1,706	)		$	129			$	32,578
Net income	—			—				—				—				1,786				—				7				1,793
Other comprehensive loss	—			—				—				—				—				(419		)		—				(419		)
Common stock purchases	(1	)		—				(6		)		—				(120		)		—				—				(126		)
Distributions	—			—				—				—				—				—				(7		)		(7		)
Purchase of noncontrolling interest	—			—				(5		)		—				—				—				(28		)		(33		)
Other equity transactions	—			—				(1		)		—				—				—				—				(1		)
Balance, June 30, 2020	76			$	—			$	6,377			$	(530	)		$	29,962			$	(2,125	)		$	101			$	33,785

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

9

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BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2020				2019
Cash flows from operating activities:
Net income	$	1,793			$	1,313
Adjustments to reconcile net income to net cash flows from operating activities:
(Gains) losses on marketable securities, net	(610		)		62
Depreciation and amortization	1,557				1,472
Allowance for equity funds	(72		)		(70		)
Equity loss, net of distributions	64				37
Changes in regulatory assets and liabilities	(7		)		1
Deferred income taxes and amortization of investment tax credits	288				25
Other, net	18				23
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(783		)		(550		)
Derivative collateral, net	16				(30		)
Pension and other postretirement benefit plans	(45		)		(41		)
Accrued property, income and other taxes, net	(605		)		(140		)
Accounts payable and other liabilities	240				32
Net cash flows from operating activities	1,854				2,134
Cash flows from investing activities:
Capital expenditures	(2,793		)		(2,750		)
Acquisitions, net of cash acquired	—				(29		)
Purchases of marketable securities	(272		)		(190		)
Proceeds from sales of marketable securities	256				185
Equity method investments	(1,087		)		(211		)
Other, net	58				36
Net cash flows from investing activities	(3,838		)		(2,959		)
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	2,448				3,464
Repayments of subsidiary debt	(1,410		)		(1,763		)
Net (repayments of) proceeds from short-term debt	(920		)		64
Purchase of noncontrolling interest	(33		)		—
Other, net	(42		)		(25		)
Net cash flows from financing activities	2,798				1,447
Effect of exchange rate changes	(12		)		1
Net change in cash and cash equivalents and restricted cash and cash equivalents	802				623
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	$	2,070			$	1,506

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

10

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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 June 30, 2020 and for the three- and six-month periods ended June 30, 2020 and 2019. The results of operations for the three- and six-month periods ended June 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 six-month period ended June 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 June 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.

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(2)	Business Acquisitions

On July 3, 2020, BHE entered into a Purchase and Sale Agreement (the "Purchase Agreement") with Dominion Energy, Inc. ("DEI") and Dominion Energy Questar Corporation ("Dominion Questar," and together with DEI, the "Sellers") to purchase substantially all of the natural gas transmission and storage business of DEI and Dominion Questar (the "Transaction"). As part of the Transaction, BHE will acquire 100% of Dominion Energy Transmission, Inc., Dominion Energy Carolina Gas Transmission, LLC and Dominion Energy Questar Pipeline, LLC; 50% of Iroquois Gas Transmission System L.P.; and a 25% economic interest in Dominion Energy Cove Point LNG, LP ("Cove Point"), consisting of 100% of the general partnership interest and 25% of the total limited partnership interests. BHE will be the operator of Cove Point after the Transaction. The assets to be acquired include over 7,700 miles of natural gas transmission lines, with approximately 20.8 billion cubic feet ("Bcf") per day of transportation capacity and 900 Bcf of operated natural gas storage with 364 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.

The Transaction is valued at approximately $9.7 billion, consisting of a cash purchase price of approximately $4.0 billion, subject to adjustment for cash and indebtedness as of the closing, and the assumption of approximately $5.7 billion of existing indebtedness for borrowed money. BHE expects to fund the purchase price, net of cash acquired, with capital from its shareholders.

The consummation of the transactions contemplated by the Purchase Agreement is subject to customary closing conditions, including without limitation (i) the expiration or termination of any applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended ("HSR Approval"), (ii) the approval by the Department of Energy (the "DOE") with respect to a change of control of Cove Point, which holds certain foreign LNG import and export authorizations subject to the DOE's jurisdiction; and (iii) the approval by the Federal Communications Commission ("FCC") with respect to the transfer of certain FCC licenses. The Transaction is expected to close in the fourth quarter of 2020, subject to satisfaction of the foregoing conditions, among other things.

The Purchase Agreement provides that if HSR Approval has not been obtained on or before 75 days following execution of the Purchase Agreement, so long as they are not in material breach of any of their representations, warranties, covenants or other agreements under the Purchase Agreement, the Sellers may exclude from the sale certain entities that own and operate natural gas pipelines in the Western United States (such termination with respect to these certain entities, a "Q-Pipe Termination"). In the event of a Q-Pipe Termination, the Sellers will complete an internal reorganization that will exclude these certain entities from the transactions contemplated by the Purchase Agreement and the cash purchase price will be reduced as set forth in the Purchase Agreement.

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(3)	Property, Plant and Equipment, Net

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

			As of
	Depreciable		June 30,				December 31,
	Life		2020				2019
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years		$	81,518			$	81,127
Interstate natural gas pipeline assets	3-80 years		8,215				8,165
			89,733				89,292
Accumulated depreciation and amortization			(26,921		)		(26,353		)
Regulated assets, net			62,812				62,939
Nonregulated assets:
Independent power plants	5-30 years		7,004				6,983
Other assets	3-30 years		1,846				1,834
			8,850				8,817
Accumulated depreciation and amortization			(2,336		)		(2,183		)
Nonregulated assets, net			6,514				6,634
Net operating assets			69,326				69,573
Construction work-in-progress			4,499				3,732
Property, plant and equipment, net			$	73,825			$	73,305

Construction work-in-progress includes $4.4 billion as of June 30, 2020 and $3.6 billion as of December 31, 2019, related to the construction of regulated assets.

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(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
	June 30,				December 31,
	2020				2019
Investments:
BYD Company Limited common stock	$	1,737			$	1,122
Rabbi trusts	396				410
Other	191				187
Total investments	2,324				1,719
Equity method investments:
BHE Renewables tax equity investments	4,183				3,130
Electric Transmission Texas, LLC	580				555
Bridger Coal Company	83				81
Other	108				181
Total equity method investments	4,954				3,947
Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds	607				599
Other restricted cash and cash equivalents	255				230
Total restricted cash and cash equivalents and investments	862				829
Total investments and restricted cash and cash equivalents and investments	$	8,140			$	6,495
Reflected as:
Current assets	$	266			$	240
Noncurrent assets	7,874				6,255
Total investments and restricted cash and cash equivalents and investments	$	8,140			$	6,495

Investments

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

	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Unrealized gains (losses) recognized on marketable securities still held at the reporting date	$	584			$	7			$	609			$	(61	)
Net (losses) gains recognized on marketable securities sold during the period	(1		)		(1		)		1				(1		)
Gains (losses) on marketable securities, net	$	583			$	6			$	610			$	(62	)

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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 June 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 June 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
	June 30,				December 31,
	2020				2019
Cash and cash equivalents	$	1,815			$	1,040
Restricted cash and cash equivalents	237				212
Investments and restricted cash and cash equivalents and investments	18				16
Total cash and cash equivalents and restricted cash and cash equivalents	$	2,070			$	1,268

(5)	Recent Financing Transactions

Long-Term Debt

In June 2020, Northern Powergrid (Northeast) plc issued £300 million of its 1.875% Green Bonds due June 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 June 30, 2020 was 1.80% while the fixed interest rate as of June 30, 2020 was 3.23%.

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.

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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						Six-Month Periods
	Ended June 30,						Ended June 30,
	2020			2019			2020			2019
Federal statutory income tax rate	21	%		21	%		21	%		21	%
Income tax credits	(20	)		(29	)		(28	)		(29	)
State income tax, net of federal income tax benefit	2			—			1			(8	)
Income tax effect of foreign income	(2	)		(1	)		(2	)		(2	)
Effects of ratemaking	(1	)		(2	)		(3	)		(2	)
Other, net	(1	)		(1	)		(1	)		—
Effective income tax rate	(1	)%		(12	)%		(12	)%		(20	)%

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.

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 six-month periods ended June 30, 2020 and 2019, the Company made payments for federal income taxes to Berkshire Hathaway totaling $100 million and $- million, respectively.

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(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								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Pension:
Service cost	$	4			$	4			$	7			$	8
Interest cost	23				28				46				55
Expected return on plan assets	(35		)		(39		)		(70		)		(77		)
Net amortization	8				7				17				16
Net periodic benefit cost	$	—			$	—			$	—			$	2
Other postretirement:
Service cost	$	3			$	3			$	4			$	5
Interest cost	4				8				10				14
Expected return on plan assets	(7		)		(10		)		(16		)		(20		)
Net amortization	(3		)		(1		)		(4		)		(3		)
Net periodic benefit credit	$	(3	)		$	—			$	(6	)		$	(4	)

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 June 30, 2020, $6 million and $- 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								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Service cost	$	4			$	4			$	8			$	8
Interest cost	10				13				20				26
Expected return on plan assets	(25		)		(25		)		(50		)		(50		)
Net amortization	11				9				21				18
Net periodic benefit (credit) cost	$	—			$	1			$	(1	)		$	2

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 June 30, 2020, £21 million, or $27 million, of contributions had been made to the United Kingdom pension plan.

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(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 June 30, 2020
Assets:
Commodity derivatives		$	1			$	54			$	106			$	(27	)		$	134
Interest rate derivatives		—				1				78				—				79
Mortgage loans held for sale		—				1,617				—				—				1,617
Money market mutual funds(2)		1,357				—				—				—				1,357
Debt securities:
United States government obligations		176				—				—				—				176
International government obligations		—				4				—				—				4
Corporate obligations		—				73				—				—				73
Municipal obligations		—				3				—				—				3
Agency, asset and mortgage-backed obligations		—				5				—				—				5
Equity securities:
United States companies		336				—				—				—				336
International companies		1,745				—				—				—				1,745
Investment funds		194				—				—				—				194
		$	3,809			$	1,757			$	184			$	(27	)		$	5,723
Liabilities:
Commodity derivatives		$	(2	)		$	(136	)		$	(62	)		$	94			$	(106	)
Interest rate derivatives		(5		)		(60		)		—				—				(65		)
		$	(7	)		$	(196	)		$	(62	)		$	94			$	(171	)

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		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 $67 million and $79 million as of June 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.

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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								Six-Month Periods
	Ended June 30,								Ended June 30,
					Interest								Interest
	Commodity				Rate				Commodity				Rate
	Derivatives				Derivatives				Derivatives				Derivatives
2020:
Beginning balance	$	52			$	45			$	97			$	14
Changes included in earnings	(1		)		264				(4		)		336
Changes in fair value recognized in net regulatory assets	(16		)		—				(56		)		—
Purchases	1				—				3				—
Settlements	8				(231		)		4				(272		)
Ending balance	$	44			$	78			$	44			$	78

2019:
Beginning balance	$	86			$	18			$	99			$	10
Changes included in earnings	8				94				5				147
Changes in fair value recognized in OCI	(1		)		—				(1		)		—
Changes in fair value recognized in net regulatory assets	(12		)		—				(23		)		—
Purchases	3				—				4				—
Settlements	2				(89		)		2				(134		)
Ending balance	$	86			$	23			$	86			$	23

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 June 30, 2020								As of December 31, 2019
	Carrying				Fair				Carrying				Fair
	Value				Value				Value				Value
Long-term debt	$	42,905			$	52,847			$	39,353			$	46,004

(9)	Commitments and Contingencies

Construction Commitments

During the six-month period ended June 30, 2020, MidAmerican Energy entered into firm construction commitments totaling $269 million for the remainder of 2020 through 2021 related to the construction of wind-powered generating facilities in Iowa.

Easements

During the six-month period ended June 30, 2020, MidAmerican Energy entered into non-cancelable easements with minimum payment commitments totaling $98 million through 2060 for land in Iowa on which some of its wind-powered generating facilities will be located.

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Maintenance and Service Contracts

During the six-month period ended June 30, 2020, MidAmerican Energy entered into non-cancelable maintenance and service contracts related to wind-powered generating facilities with minimum payment commitments totaling $72 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 also expects to begin 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.

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.

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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 evaluating the order in coordination with its settlement partners, including continued implementation of the agreement. Requests for rehearing are due on August 17, 2020.

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

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(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 June 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		$	1,066			$	468			$	638			$	—			$	—			$	—			$	—			$	—			$	2,172
Retail gas		—				84				20				—				—				—				—				—				104
Wholesale		17				37				6				—				—				—				—				(1		)		59
Transmission and    distribution		24				18				22				191				—				164				—				—				419
Interstate pipeline		—				—				—				—				221				—				—				(26		)		195
Other		20				—				—				—				—				—				—				—				20
Total Regulated		1,127				607				686				191				221				164				—				(27		)		2,969
Nonregulated		—				3				1				5				—				5				212				122				348
Total Customer Revenue		1,127				610				687				196				221				169				212				95				3,317
Other revenue		17				6				8				25				4				—				32				10				102
Total		$	1,144			$	616			$	695			$	221			$	225			$	169			$	244			$	105			$	3,419

		For the Six-Month Period Ended June 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		$	2,188			$	878			$	1,167			$	—			$	—			$	—			$	—			$	—			$	4,233
Retail gas		—				271				67				—				—				—				—				—				338
Wholesale		17				101				20				—				—				—				—				(2		)		136
Transmission and    distribution		46				33				45				424				—				333				—				—				881
Interstate pipeline		—				—				—				—				621				—				—				(74		)		547
Other		46				—				1				—				—				—				—				—				47
Total Regulated		2,297				1,283				1,300				424				621				333				—				(76		)		6,182
Nonregulated		—				9				2				12				—				8				371				249				651
Total Customer Revenue		2,297				1,292				1,302				436				621				341				371				173				6,833
Other revenue		53				10				15				51				5				—				51				35				220
Total		$	2,350			$	1,302			$	1,317			$	487			$	626			$	341			$	422			$	208			$	7,053

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		For the Three-Month Period Ended June 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		$	1,107			$	467			$	658			$	—			$	—			$	—			$	—			$	—			$	2,232
Retail gas		—				95				21				—				—				—				—				—				116
Wholesale		11				66				10				—				—				—				—				(1		)		86
Transmission and    distribution		25				15				24				209				—				168				—				—				441
Interstate pipeline		—				—				—				—				212				—				—				(24		)		188
Other		—				—				—				—				—				—				—				—				—
Total Regulated		1,143				643				713				209				212				168				—				(25		)		3,063
Nonregulated		—				10				—				10				—				7				197				142				366
Total Customer Revenue		1,143				653				713				219				212				175				197				117				3,429
Other revenue		24				7				8				24				—				—				52				23				138
Total		$	1,167			$	660			$	721			$	243			$	212			$	175			$	249			$	140			$	3,567

		For the Six-Month Period Ended June 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		$	2,293			$	910			$	1,185			$	—			$	—			$	—			$	—			$	—			$	4,388
Retail gas		—				355				58				—				—				—				—				—				413
Wholesale		39				176				28				—				—				—				—				(1		)		242
Transmission and    distribution		50				31				48				439				—				335				—				—				903
Interstate pipeline		—				—				—				—				584				—				—				(61		)		523
Other		—				—				1				—				—				—				—				—				1
Total Regulated		2,382				1,472				1,320				439				584				335				—				(62		)		6,470
Nonregulated		—				16				—				18				—				8				323				281				646
Total Customer Revenue		2,382				1,488				1,320				457				584				343				323				219				7,116
Other revenue(2)		44				14				15				49				(1		)		—				93				62				276
Total		$	2,426			$	1,502			$	1,335			$	506			$	583			$	343			$	416			$	281			$	7,392

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

(2)	Includes net payments to counterparties for the financial settlement of certain derivative contracts at BHE Pipeline Group.

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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								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Customer Revenue:
Brokerage	$	957			$	1,204			$	1,734			$	1,915
Franchise	15				19				31				33
Total Customer Revenue	972				1,223				1,765				1,948
Other revenue	221				104				321				164
Total	$	1,193			$	1,327			$	2,086			$	2,112

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 June 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	$	884			$	4,888			$	5,772

(11)	BHE Shareholders' Equity

For the six-month periods ended June 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) income		(14		)		106				(35		)		57
Balance, June 30, 2019		$	(372	)		$	(1,517	)		$	1			$	(1,888	)
Balance, December 31, 2019		$	(417	)		$	(1,296	)		$	7			$	(1,706	)
Other comprehensive income (loss)		44				(439		)		(24		)		(419		)
Balance, June 30, 2020		$	(373	)		$	(1,735	)		$	(17	)		$	(2,125	)

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(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								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Operating revenue:
PacifiCorp	$	1,144			$	1,167			$	2,350			$	2,426
MidAmerican Funding	616				660				1,302				1,502
NV Energy	695				721				1,317				1,335
Northern Powergrid	221				243				487				506
BHE Pipeline Group	225				212				626				583
BHE Transmission	169				175				341				343
BHE Renewables	244				249				422				416
HomeServices	1,193				1,327				2,086				2,112
BHE and Other(1)	105				140				208				281
Total operating revenue	$	4,612			$	4,894			$	9,139			$	9,504

Depreciation and amortization:
PacifiCorp	$	210			$	209			$	462			$	414
MidAmerican Funding	175				179				351				356
NV Energy	125				120				249				240
Northern Powergrid	63				63				126				126
BHE Pipeline Group	25				29				89				57
BHE Transmission	55				60				115				118
BHE Renewables	71				69				142				139
HomeServices	12				11				23				24
BHE and Other(1)	—				(1		)		—				(2		)
Total depreciation and amortization	$	736			$	739			$	1,557			$	1,472

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	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Operating income:
PacifiCorp	$	256			$	268			$	490			$	552
MidAmerican Funding	110				94				212				210
NV Energy	161				150				240				234
Northern Powergrid	89				110				221				239
BHE Pipeline Group	92				68				341				311
BHE Transmission	81				77				157				153
BHE Renewables	84				97				101				115
HomeServices	77				117				97				96
BHE and Other(1)	(14		)		(22		)		(4		)		(32		)
Total operating income	936				959				1,855				1,878
Interest expense	(503		)		(476		)		(986		)		(953		)
Capitalized interest	19				17				36				33
Allowance for equity funds	38				38				72				70
Interest and dividend income	20				36				40				66
Gains (losses) on marketable securities, net	583				6				610				(62		)
Other, net	52				30				25				65
Total income before income tax benefit and equity (loss) income	$	1,145			$	610			$	1,652			$	1,097

Interest expense:
PacifiCorp	$	110			$	102			$	212			$	198
MidAmerican Funding	78				74				159				149
NV Energy	57				56				115				118
Northern Powergrid	31				35				63				69
BHE Pipeline Group	15				12				29				24
BHE Transmission	35				39				73				78
BHE Renewables	42				44				84				88
HomeServices	3				7				8				14
BHE and Other(1)	132				107				243				215
Total interest expense	$	503			$	476			$	986			$	953

Operating revenue by country:
United States	$	4,224			$	4,476			$	8,313			$	8,653
United Kingdom	221				242				487				505
Canada	167				175				338				343
Philippines and other	—				1				1				3
Total operating revenue by country	$	4,612			$	4,894			$	9,139			$	9,504

Income before income tax benefit and equity (loss) income by country:
United States	$	1,027			$	482			$	1,381			$	818
United Kingdom	59				76				168				179
Canada	46				39				86				79
Philippines and other	13				13				17				21
Total income before income tax benefit and equity (loss) income by country	$	1,145			$	610			$	1,652			$	1,097

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	As of
	June 30,				December 31,
	2020				2019
Assets:
PacifiCorp	$	26,128			$	24,861
MidAmerican Funding	23,155				22,664
NV Energy	14,420				14,128
Northern Powergrid	8,083				8,385
BHE Pipeline Group	6,182				6,100
BHE Transmission	8,616				8,776
BHE Renewables	11,134				9,961
HomeServices	4,703				3,846
BHE and Other(1)	1,996				1,330
Total assets	$	104,417			$	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 six-month period ended June 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	—				—				—				(45		)		—				(65		)		—				—				(110		)
June 30, 2020	$	1,129			$	2,102			$	2,369			$	933			$	73			$	1,455			$	95			$	1,456			$	9,612

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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 Second Quarter and First Six Months of 2020 and 2019

Overview

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

	Second Quarter															First Six Months
	2020				2019				Change							2020				2019				Change
Net income attributable to BHE shareholders:
PacifiCorp	$	167			$	168			$	(1	)		(1	)%		$	343			$	348			$	(5	)		(1	)%
MidAmerican Funding	208				153				55				36			358				343				15				4
NV Energy	98				81				17				21			118				110				8				7
Northern Powergrid	59				64				(5		)		(8	)		146				144				2				1
BHE Pipeline Group	64				48				16				33			243				229				14				6
BHE Transmission	60				51				9				18			115				107				8				7
BHE Renewables	138				120				18				15			233				168				65				39
HomeServices	59				90				(31		)		(34	)		69				68				1				1
BHE and Other	263				(91		)		354				*			161				(211		)		372				*
Total net income attributable to BHE shareholders	$	1,116			$	684			$	432			63	%		$	1,786			$	1,306			$	480			37	%

*    Not meaningful

Net income attributable to BHE shareholders increased $432 million for the second quarter of 2020 compared to 2019. The second quarter of 2020 included a pre-tax unrealized gain of $562 million ($408 million after-tax) compared to a pre-tax unrealized gain in the second quarter of 2019 of $2 million ($2 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 second quarter of 2020 was $708 million, an increase of $26 million, or 4%, compared to adjusted net income attributable to BHE shareholders in the second quarter of 2019 of $682 million.

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Net income attributable to BHE shareholders increased $480 million for the first six months of 2020 compared to 2019. The first six months of 2020 included a pre-tax unrealized gain of $615 million ($447 million after-tax) compared to a pre-tax unrealized loss in the first six months of 2019 of $77 million ($56 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 six months of 2020 was $1,339 million, a decrease of $23 million, or 2%, compared to adjusted net income attributable to BHE shareholders in the first six months of 2019 of $1,362 million.

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

•

PacifiCorp's net income decreased $1 million, primarily due to lower utility margin of $22 million, higher interest expense of $8 million, higher pension and post-retirement costs of $4 million and lower interest and dividend income of $4 million, partially offset by lower operations and maintenance expense of $12 million, primarily due to lower labor and benefits costs and the timing of maintenance, higher allowances for equity and borrowed funds used during construction of $11 million and higher PTCs recognized of $9 million, primarily due to repowering certain wind-powered generating facilities. Utility margin decreased primarily due to unfavorable retail customer volumes, partially offset by price impacts from changes in sales mix. Retail customer volumes decreased 4.2%, 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.

•

MidAmerican Funding's net income increased $55 million, primarily due to higher PTCs recognized of $35 million from higher wind generation, which was driven by repowering and new wind projects placed in-service, higher electric utility margin, lower operations and maintenance expense and higher cash surrender value of corporate-owned life insurance policies, partially offset by lower allowances for equity and borrowed funds used during construction of $11 million and higher interest expense of $4 million. Electric utility margin increased primarily due to higher retail customer volumes and lower generation and purchased power costs, partially offset by lower wholesale revenue. Electric retail customer volumes increased 1.8%, primarily due to the favorable impact of weather and 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 $17 million, primarily due to higher electric utility margin of $11 million, higher cash surrender value of corporate-owned life insurance policies and lower income tax expense from the favorable impacts of ratemaking. Electric utility margin increased primarily due to price impacts from changes in sales mix, partially offset by unfavorable retail customer volumes. Electric retail customer volumes, including distribution only service customers, decreased 1.9%, primarily due to the impacts of COVID-19, which resulted in lower industrial, distribution only service and commercial customer usage and higher residential customer usage, partially offset by the favorable impact of weather.

•	Northern Powergrid's net income decreased $5 million, primarily due to lower distribution revenue of $11 million from 12.8 % lower units distributed, largely due to the impacts of COVID-19, offset by increased tariff rates.

•	BHE Pipeline Group's net income increased $16 million due to higher transportation revenue of $11 million and the favorable, after-tax, impact of a rate case settlement at Northern Natural Gas of $11 million, partially offset by higher depreciation and amortization expense of $3 million from higher plant placed in-service.

•	BHE Transmission's net income increased $9 million, primarily due to a favorable regulatory decision received in April 2020 at AltaLink and lower non-regulated interest expense at BHE Canada.

•

BHE Renewables' net income increased $18 million due to higher wind earnings of $27 million and higher solar earnings of $5 million due to higher generation, partially offset by lower geothermal earnings of $8 million, primarily due to higher operations and maintenance expense and lower generation, and lower natural gas earnings of $6 million, primarily due to lower margins. Wind earnings were higher due to favorable tax equity investment earnings of $26 million, which improved due to $35 million of earnings from projects reaching commercial operation, partially offset by lower commitment fee income of $8 million.

•

HomeServices' net income decreased $31 million, primarily due to an unfavorable contingent earn-out remeasurement and lower earnings at brokerage due to a 21% decrease in closed units, in large part from the impacts of COVID-19, offset by lower operating expenses, partially offset by higher earnings at mortgage primarily due to higher refinance activity from the favorable interest rate environment.

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•

BHE and Other's net loss improved $354 million, primarily due to the change in the after-tax unrealized position of the Company's investment in BYD Company Limited of $406 million, higher margin of $19 million from favorable changes in unrealized positions on derivative contracts at MidAmerican Energy Services, LLC and higher cash surrender value of corporate-owned life insurance policies, partially offset by $55 million of lower federal income tax credits recognized on a consolidated basis and higher interest expense.

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

•

PacifiCorp's net income decreased $5 million, primarily due to lower utility margin, higher interest expense of $14 million, higher pension and post-retirement costs of $7 million and lower interest and dividend income of $6 million, partially offset by higher allowances for equity and borrowed funds used during construction of $21 million, higher PTCs recognized of $17 million, primarily due to repowering certain wind-powered generating facilities, and lower operations and maintenance expense of $14 million, primarily due to lower labor and benefits costs. Utility margin decreased due to unfavorable retail customer volumes, lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms, lower wholesale volumes and price impacts from changes in sales mix, partially offset by lower coal-fueled and natural gas-fueled generation costs. Retail customer volumes decreased 2.9%, primarily due to the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, and the unfavorable impact of weather, partially offset by an increase in the average number of customers.

•

MidAmerican Funding's net income increased $15 million, primarily due to higher PTCs recognized of $57 million from higher wind generation, which was driven by repowering and new wind projects placed in-service, and lower operations and maintenance expense, partially offset by lower electric and natural gas utility margins, lower allowances for equity and borrowed funds used during construction of $21 million, lower cash surrender value of corporate-owned life insurance policies and higher interest expense of $10 million. Electric utility margin decreased due to lower wholesale revenue and price impacts from changes in sales mix, partially offset by lower generation and purchased power costs and higher retail customer volumes. Electric retail customer volumes increased 0.5% 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 12.9% lower retail customer volumes primarily due to the unfavorable impact of weather.

•

NV Energy's net income increased $8 million, primarily due to higher electric utility margin of $12 million and lower income tax expense from the favorable impacts of ratemaking, partially offset by higher depreciation and amortization expense of $9 million, from higher plant placed in-service, and lower cash surrender value of corporate-owned life insurance policies. Electric utility margin increased due to price impacts from changes in sales mix, partially offset by unfavorable retail customer volumes. Electric retail customer volumes, including distribution only service customers, decreased 0.9%, primarily due to the impacts of COVID-19, which resulted in lower industrial and distribution only service customer usage and higher residential customer usage, partially offset by the favorable impact of weather.

•	Northern Powergrid's net income increased $2 million, primarily due to lower interest expense of $5 million and favorable pension costs, partially offset by lower distribution revenues of $3 million from 7.0% lower units distributed, largely due to the impacts of COVID-19, offset by increased tariff rates.

•	BHE Pipeline Group's net income increased $14 million due to higher transportation revenue of $24 million and the favorable, after-tax, impact of a rate case settlement at Northern Natural Gas of $10 million, partially offset by higher depreciation and amortization expense of $6 million, higher interest expense of $5 million and lower storage revenue of $4 million.

•	BHE Transmission's net income increased $8 million due to lower non-regulated interest expense at BHE Canada, a favorable regulatory decision received in April 2020 at AltaLink and $3 million of higher net income at BHE U.S. Transmission mainly due to improved equity earnings from the Electric Transmission Texas, LLC investment.

•

BHE Renewables' net income increased $65 million due to higher wind earnings of $77 million and higher solar earnings of $14 million due to higher generation and pricing and lower operations and maintenance expense, partially offset by lower geothermal earnings of $16 million, primarily due to higher operations and maintenance expense and lower generation, and lower natural gas earnings of $9 million, primarily due to lower margins. Wind earnings were higher primarily due to favorable tax equity investment earnings of $73 million, which improved due to $72 million of earnings from projects reaching commercial operation.

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•	HomeServices' net income increased $1 million, primarily due to higher earnings at mortgage largely due to higher refinance activity from the favorable interest rate environment, partially offset by an unfavorable contingent earn-out remeasurement and lower earnings at brokerage due to an 11% decrease in closed units, in large part from the impacts of COVID-19, offset by lower operating expenses.

•

BHE and Other's net loss improved $372 million, primarily due to the change in the after-tax unrealized position of the Company's investment in BYD Company Limited of $503 million and higher margin of $15 million from favorable changes in unrealized positions on derivative contracts at MidAmerican Energy Services, LLC, partially offset by consolidated state income tax benefits recognized in 2019, $42 million of lower federal income tax credits recognized on a consolidated basis, higher interest expense and lower cash surrender value of corporate-owned life insurance policies.

Reportable Segment Results

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

	Second Quarter															First Six Months
	2020				2019				Change							2020				2019				Change
Operating revenue:
PacifiCorp	$	1,144			$	1,167			$	(23	)		(2	)%		$	2,350			$	2,426			$	(76	)		(3	)%
MidAmerican Funding	616				660				(44		)		(7	)		1,302				1,502				(200		)		(13	)
NV Energy	695				721				(26		)		(4	)		1,317				1,335				(18		)		(1	)
Northern Powergrid	221				243				(22		)		(9	)		487				506				(19		)		(4	)
BHE Pipeline Group	225				212				13				6			626				583				43				7
BHE Transmission	169				175				(6		)		(3	)		341				343				(2		)		(1	)
BHE Renewables	244				249				(5		)		(2	)		422				416				6				1
HomeServices	1,193				1,327				(134		)		(10	)		2,086				2,112				(26		)		(1	)
BHE and Other	105				140				(35		)		(25	)		208				281				(73		)		(26	)
Total operating revenue	$	4,612			$	4,894			$	(282	)		(6	)%		$	9,139			$	9,504			$	(365	)		(4	)%

 

Operating income:
PacifiCorp	$	256			$	268			$	(12	)		(4	)%		$	490			$	552			$	(62	)		(11	)%
MidAmerican Funding	110				94				16				17			212				210				2				1
NV Energy	161				150				11				7			240				234				6				3
Northern Powergrid	89				110				(21		)		(19	)		221				239				(18		)		(8	)
BHE Pipeline Group	92				68				24				35			341				311				30				10
BHE Transmission	81				77				4				5			157				153				4				3
BHE Renewables	84				97				(13		)		(13	)		101				115				(14		)		(12	)
HomeServices	77				117				(40		)		(34	)		97				96				1				1
BHE and Other	(14		)		(22		)		8				(36	)		(4		)		(32		)		28				(88	)
Total operating income	$	936			$	959			$	(23	)		(2	)%		$	1,855			$	1,878			$	(23	)		(1	)%

PacifiCorp

Operating revenue decreased $23 million for the second quarter of 2020 compared to 2019 due to lower retail revenue of $18 million and lower wholesale and other revenue of $5 million. Retail revenue decreased due to unfavorable retail customer volumes of $27 million, partially offset by price impacts of $9 million from changes in sales mix. Retail customer volumes decreased 4.2%, 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.

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Operating income decreased $12 million for the second quarter of 2020 compared to 2019, primarily due to lower utility margin of $22 million, partially offset by lower operations and maintenance expense of $12 million largely due to lower labor and benefits costs and the timing of maintenance. Utility margin decreased primarily due to unfavorable retail customer volumes, partially offset by price impacts from changes in sales mix.

Operating revenue decreased $76 million for the first six months of 2020 compared to 2019 due to lower retail revenue of $66 million and lower wholesale and other revenue of $10 million, primarily due to lower wholesale volumes. Retail revenue decreased due to unfavorable retail customer volumes of $51 million and price impacts of $16 million from changes in sales mix. Retail customer volumes decreased 2.9%, primarily due to the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, and the unfavorable impact of weather, partially offset by an increase in the average number of customers.

Operating income decreased $62 million for the first six months of 2020 compared to 2019, primarily due to an increase in depreciation and amortization expense of $48 million and lower utility margin, partially offset by lower operations and maintenance expense of $14 million largely due to lower labor and benefits costs. The increase in depreciation and amortization expense reflects accelerated depreciation of Oregon's share of certain retired wind equipment due to repowering projects that were placed into service in 2020 of $47 million (offset in income tax expense) as ordered by the OPUC. Utility margin decreased primarily due to unfavorable retail customer volumes, lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms, lower wholesale volumes and price impacts from changes in sales mix, partially offset by lower coal-fueled and natural gas-fueled generation costs.

MidAmerican Funding

Operating revenue decreased $44 million for the second quarter of 2020 compared to 2019 due to lower electric and natural gas energy efficiency program revenue of $20 million (offset in operations and maintenance expense), lower natural gas operating revenue of $10 million, lower other revenue of $8 million, primarily from nonregulated utility construction services, and lower electric operating revenue of $6 million. Natural gas operating revenue decreased primarily due to lower recoveries through the purchased gas adjustment clause from a lower average per-unit cost of natural gas sold of $12 million (offset in cost of sales). Electric operating revenue decreased due to lower wholesale and other revenue of $22 million, partially offset by higher retail revenue of $16 million, mainly due to the favorable impact of weather. Electric wholesale and other revenue decreased due to $29 million from lower average wholesale per-unit prices, partially offset by a 10.0% increase in wholesale volumes. Electric retail customer volumes increased 1.8%, primarily due to the favorable impact of weather and 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.

Operating income increased $16 million for the second quarter of 2020 compared to 2019, primarily due to higher electric utility margin, excluding energy efficiency program revenue, and lower operations and maintenance expense not recovered through energy efficiency programs. Electric utility margin increased primarily due to higher retail customer volumes and lower generation and purchased power costs, partially offset by lower wholesale revenue. Operations and maintenance expense decreased mainly due to lower electric and natural gas distribution costs and lower fossil-fueled generating facility maintenance, partially offset by higher wind-powered generation costs due to new and repowered generating facilities. Depreciation and amortization expense reflects lower Iowa revenue sharing accruals of $27 million, substantially offset by an increase related to new wind-powered generating facilities and other plant placed in-service.

Operating revenue decreased $200 million for the first six months of 2020 compared to 2019 due to lower natural gas operating revenue of $86 million, lower electric operating revenue of $58 million, lower electric and natural gas energy efficiency program revenue of $49 million (offset in operations and maintenance expense) and lower other revenue of $7 million, primarily from nonregulated utility construction services. Natural gas operating revenue decreased primarily due to lower recoveries through the purchased gas adjustment clause from a lower average per-unit cost of natural gas sold of $77 million (offset in cost of sales) and a 12.9% 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 $62 million, partially offset by higher retail revenue of $4 million. Electric wholesale and other revenue decreased due to $46 million from lower average wholesale per-unit prices and a 10.9% decrease in wholesale volumes. Electric retail revenue increased primarily due to higher customer usage of $16 million, partially offset by price impacts of $14 million from changes in sales mix. Electric retail customer volumes increased 0.5% 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.

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Operating income increased $2 million for the first six months of 2020 compared to 2019, primarily due to lower operations and maintenance expense not recovered through energy efficiency programs, partially offset by lower electric and natural gas utility margins, excluding energy efficiency program revenue. Operations and maintenance expense decreased mainly due to lower electric and natural gas distribution costs and lower fossil-fueled generating facility maintenance, partially offset by higher wind-powered generation costs due to new and repowered generating facilities. Electric utility margin decreased primarily due to lower wholesale revenue and price impacts from changes in sales mix, partially offset by lower generation and purchased power costs and higher retail customer volumes. Natural gas utility margin decreased due to lower retail customer volumes. Depreciation and amortization expense reflects lower Iowa revenue sharing accruals of $54 million, substantially offset by an increase related to new wind-powered generating facilities and other plant placed in-service.

NV Energy

Operating revenue decreased $26 million for the second quarter of 2020 compared to 2019 due to lower electric operating revenue, which decreased primarily due to lower energy rates (offset in cost of sales) and lower retail customer volumes, partially offset by price impacts from changes in sales mix. Electric retail customer volumes, including distribution only service customers, decreased 1.9%, primarily due to the impacts of COVID-19, which resulted in lower industrial, distribution only service and commercial customer usage and higher residential customer usage, partially offset by the favorable impact of weather.

Operating income increased $11 million for the second quarter of 2020 compared to 2019 due to higher electric utility margin, which increased primarily due to price impacts from changes in sales mix, partially offset by lower retail customer volumes.

Operating revenue decreased $18 million for the first six months of 2020 compared to 2019, primarily due to lower electric operating revenue of $30 million, partially offset by higher natural gas operating revenue of $10 million, mainly due to a higher average per-unit cost of natural gas sold of $11 million (offset in cost of sales). Electric operating revenue decreased primarily due to lower energy rates (offset in cost of sales) and lower retail customer volumes, partially offset by price impacts from changes in sales mix. Electric retail customer volumes, including distribution only service customers, decreased 0.9%, primarily due to the impacts of COVID-19, which resulted in lower industrial and distribution only service customer usage and higher residential customer usage, partially offset by the favorable impact of weather.

Operating income increased $6 million for the first six months of 2020 compared to 2019, primarily due to higher electric utility margin of $12 million, partially offset by higher depreciation and amortization expense of $9 million from higher plant placed in-service. Electric utility margin increased primarily due to price impacts from changes in sales mix, partially offset by lower retail customer volumes.

Northern Powergrid

Operating revenue decreased $22 million for the second quarter of 2020 compared to 2019, primarily due to lower distribution revenue of $11 million and the stronger United States dollar of $8 million. Distribution revenue decreased $20 million due to 12.8% lower units distributed, largely due to the impacts of COVID-19, partially offset by increased tariff rates of $10 million. Operating income decreased $21 million for the second quarter of 2020 compared to 2019, primarily due to the lower distribution revenue, higher operations and maintenance expense and the stronger United States dollar of $3 million.

Operating revenue decreased $19 million for the first six months of 2020 compared to 2019, mainly due to the stronger United States dollar of $12 million and lower distribution revenue of $2 million. Distribution revenue decreased $22 million due to 7.0% lower units distributed, largely due to the impacts of COVID-19, partially offset by increased tariff rates of $20 million. Operating income decreased $18 million for the first six months of 2020 compared to 2019, primarily due to higher operations and maintenance expense, the stronger United States dollar of $5 million and the lower distribution revenue.

BHE Pipeline Group

Operating revenue increased $13 million for the second quarter of 2020 compared to 2019 due to the favorable impact of a rate case settlement at Northern Natural Gas of $15 million and higher transportation revenue of $11 million from expansion projects at Northern Natural Gas, partially offset by lower gas sales of $12 million at Northern Natural Gas related to system balancing activities (largely offset in cost of sales). Operating income increased $24 million for the second quarter of 2020 compared to 2019, primarily due to the favorable impact of a rate case settlement at Northern Natural Gas of $16 million and the higher transportation revenue, partially offset by higher depreciation expense of $3 million from higher plant placed in-service.

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Operating revenue increased $43 million for the first six months of 2020 compared to 2019 due to the favorable impact of a rate case settlement at Northern Natural Gas of $48 million and higher transportation revenue of $24 million from expansion projects at Northern Natural Gas, partially offset by lower gas sales of $26 million at Northern Natural Gas related to system balancing activities (largely offset in cost of sales) and lower storage revenue of $4 million. Operating income increased $30 million for the first six months of 2020 compared to 2019, primarily due to the higher transportation revenue and the favorable impact of a rate case settlement at Northern Natural Gas of $15 million, partially offset by higher depreciation expense of $6 million from higher plant placed in-service and the lower storage revenue.

BHE Transmission

Operating revenue decreased $6 million for the second quarter of 2020 compared to 2019, primarily due to the stronger United States dollar of $6 million and lower cost recoveries from other utilities for mutual assistance activities, partially offset by a favorable regulatory decision received in April 2020 at AltaLink. Operating income increased $4 million for the second quarter of 2020 compared to 2019, mainly due to a favorable regulatory decision received in April 2020 at AltaLink, partially offset by the stronger United States dollar of $3 million.

Operating revenue decreased $2 million for the first six months of 2020 compared to 2019, primarily due to the stronger United States dollar of $8 million and lower cost recoveries from other utilities for mutual assistance activities, partially offset a favorable regulatory decision received in April 2020 at AltaLink. Operating income increased $4 million for the first six months of 2020 compared to 2019, mainly due to a favorable regulatory decision received in April 2020 at AltaLink, partially offset by the stronger United States dollar of $4 million.

BHE Renewables

Operating revenue decreased $5 million for the second quarter of 2020 compared to 2019, primarily due to lower natural gas revenues of $5 million, largely due to decreased capacity revenue, an unfavorable change in the valuation of a power purchase agreement of $3 million and lower geothermal revenues of $2 million, partially offset by higher solar revenues of $5 million from favorable generation. Operating income decreased $13 million for the second quarter of 2020 compared to 2019, primarily due to higher operations and maintenance expense of $6 million at the geothermal projects, the lower operating revenue and higher fuel costs of $3 million at the natural gas facilities.

Operating revenue increased $6 million for the first six months of 2020 compared to 2019, primarily due to higher solar revenues of $11 million and wind revenues of $5 million, each from favorable generation, partially offset by an unfavorable change in the valuation of a power purchase agreement of $6 million and lower geothermal revenues of $4 million. Operating income decreased $14 million for the first six months of 2020 compared to 2019, primarily due to higher fuel costs of $14 million at the natural gas facilities and higher operations and maintenance expense of $12 million at the geothermal projects, partially offset by the higher operating revenue and lower operations and maintenance expense of $5 million at the solar projects.

HomeServices

Operating revenue decreased $134 million for the second quarter of 2020 compared to 2019, primarily due to a decrease in brokerage revenue of $248 million due to a 21% decrease in closed units in large part from the impacts of COVID-19, partially offset by increased mortgage revenue of $118 million from a 61% increase in closed mortgage volume due to higher refinance activity from the favorable interest rate environment. Operating income decreased $40 million for the second quarter of 2020 compared to 2019, primarily due to unfavorable operating performance at brokerage from the decrease in closed units, partially offset by lower operating expenses. Improved operating performance at mortgage from the favorable interest rate environment was offset by an unfavorable contingent earn-out remeasurement.

Operating revenue decreased $26 million for the first six months of 2020 compared to 2019, primarily due to a decrease in brokerage revenue of $192 million due to an 11% decrease in closed units in large part from the impacts of COVID-19, partially offset by increased mortgage revenue of $157 million from a 66% increase in closed mortgage volume due to higher refinance activity from the favorable interest rate environment. Operating income increased $1 million for the first six months of 2020 compared to 2019 as improved operating performance at mortgage was offset by the unfavorable contingent earn-out remeasurement and lower operating performance at brokerage.

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BHE and Other

Operating revenue decreased $35 million for the second quarter of 2020 compared to 2019 and $73 million for the first six months of 2020 compared to 2019, primarily due to lower electricity and natural gas volumes at MidAmerican Energy Services, LLC. Operating loss improved $8 million for the second quarter of 2020 compared to 2019, primarily due to higher margin of $19 million from favorable changes in unrealized positions on derivative contracts at MidAmerican Energy Services, LLC, partially offset by higher operations and maintenance expense. Operating loss improved $28 million for the first six months of 2020 compared to 2019, primarily due to higher margin of $15 million at MidAmerican Energy Services, LLC and lower operations and maintenance expense.

Consolidated Other Income and Expense Items

Interest expense

Interest expense is summarized as follows (in millions):

	Second Quarter															First Six Months
	2020				2019				Change							2020				2019				Change
Subsidiary debt	$	371			$	368			$	3			1	%		$	742			$	736			$	6			1	%
BHE senior debt and other	130				106				24				23			241				214				27				13
BHE junior subordinated debentures	2				2				—				—			3				3				—				—
Total interest expense	$	503			$	476			$	27			6	%		$	986			$	953			$	33			3	%

Interest expense increased $27 million for the second quarter of 2020 compared to 2019 and $33 million for the first six 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 and the impact of foreign exchange rate movements.

Capitalized interest

Capitalized interest increased $2 million for the second quarter of 2020 compared to 2019 and $3 million for the first six months of 2020 compared to 2019, primarily due to higher construction work-in-progress balances at PacifiCorp, largely offset by lower construction work-in-progress balances at MidAmerican Energy.

Allowance for equity funds

Allowance for equity funds increased $2 million for the first six months of 2020 compared to 2019, primarily due to higher construction work-in-progress balances at PacifiCorp, largely offset by lower construction work-in-progress balances at MidAmerican Energy.

Interest and dividend income

Interest and dividend income decreased $16 million for the second quarter of 2020 compared to 2019 and $26 million for the first six 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 $577 million for the second quarter of 2020 compared to 2019 and $672 million for the first six 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 $560 million and $692 million, respectively.

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Other, net

Other, net increased $22 million for the second quarter of 2020 compared to 2019, primarily due to higher cash surrender value of corporate-owned life insurance policies.

Other, net decreased $40 million for the first six months 2020 compared to 2019, primarily due to lower cash surrender value of corporate-owned life insurance policies.

Income tax benefit

Income tax benefit decreased $69 million for the second quarter of 2020 compared to 2019 and the effective tax rate was (1)% for the second quarter of 2020 and (12)% for the second quarter of 2019. The effective tax rate increased primarily due to higher income before taxes from the Company's investment in BYD Company Limited, partially offset by higher PTCs recognized of $48 million and the favorable impacts of ratemaking of $22 million.

Income tax benefit decreased $33 million for the first six months 2020 compared to 2019 and the effective tax rate was (12)% for the first six months 2020 and (20)% first six months of 2019. The effective tax rate increased primarily due to higher income before taxes from the Company's investment in BYD Company Limited and consolidated state income tax benefits recognized in 2019, partially offset by higher PTCs recognized of $144 million and the favorable impacts of ratemaking of $34 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 $454 million, or $144 million higher than 2019, while PTCs earned in 2020 were $565 million, or $206 million higher than 2019. The difference between PTCs recognized and earned of $111 million as of June 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, will result in a deferred income tax charge of approximately $35 million to be recognized in the third quarter of 2020 related to the remeasurement of Northern Powergrid's net deferred income tax liabilities.

Equity (loss) income

Equity (loss) income was unfavorable $34 million for the second quarter of 2020 compared to 2019 and $42 million for the first six 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.

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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 June 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	$	284			$	711			$	8			$	114			$	319			$	85			$	294			$	1,815
Credit facilities	3,500				1,200				1,509				650				186				865				2,432				10,342
Less:
Short-term debt	—				—				(195		)		—				—				(336		)		(1,758		)		(2,289		)
Tax-exempt bond support and letters of credit	—				(256		)		(370		)		—				—				(2		)		—				(628		)
Net credit facilities	3,500				944				944				650				186				527				674				7,425
Total net liquidity	$	3,784			$	1,655			$	952			$	764			$	505			$	612			$	968			$	9,240
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 six-month periods ended June 30, 2020 and 2019 were $1.9 billion and $2.1 billion, respectively. The decrease was primarily due to unfavorable 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 six-month periods ended June 30, 2020 and 2019 were $(3.8) billion and $(3.0) billion, respectively. The change was primarily due to higher funding of tax equity investments and higher capital expenditures of $43 million, partially offset by lower cash paid for acquisitions, net of cash acquired, of $29 million. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

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Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2020 was $2.8 billion. Sources of cash totaled $5.7 billion and consisted of proceeds from BHE senior debt issuances totaling $3.2 billion and proceeds from subsidiary debt issuances totaling $2.4 billion. Uses of cash totaled $2.9 billion and consisted mainly of repayments of subsidiary debt totaling $1.4 billion, net repayments of short-term debt totaling $920 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 six-month period ended June 30, 2019 was $1.4 billion. Sources of cash totaled $3.5 billion and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $2.1 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.

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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):

	Six-Month Periods								Annual
	Ended June 30,								Forecast
	2019				2020				2020
Capital expenditures by business:
PacifiCorp	$	817			$	973			$	2,505
MidAmerican Funding	1,017				824				1,987
NV Energy	290				366				661
Northern Powergrid	252				312				668
BHE Pipeline Group	173				196				607
BHE Transmission	104				222				637
BHE Renewables	70				26				89
HomeServices	24				14				30
BHE and Other(1)	3				(140		)		(129		)
Total	$	2,750			$	2,793			$	7,055

Capital expenditures by type:
Wind generation	$	958			$	707			$	2,242
Electric transmission	263				336				850
Other growth	305				339				722
Operating	1,224				1,411				3,241
Total	$	2,750			$	2,793			$	7,055

(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 $388 million and $473 million for the six-month periods ended June 30, 2020 and 2019, respectively. MidAmerican Energy anticipates costs associated with the construction of wind-powered generating facilities will total an additional $457 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 202 MWs placed in-service as of June 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.

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Repowering certain existing wind-powered generating facilities at MidAmerican Energy totaling $19 million and $118 million for the six-month periods ended June 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 $138 million for the remainder of 2020. Of the 998 MWs of current repowering projects not in-service as of June 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.

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◦

Construction of wind-powered generating facilities at PacifiCorp totaling $395 million and $138 million for the six-month periods ended June 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 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 $802 million for 2020.

◦

Repowering certain existing wind-powered generating facilities at PacifiCorp totaling $46 million and $215 million for the six-month periods ended June 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 $107 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 July 3, 2020, BHE entered into a Purchase and Sale Agreement with Dominion Energy, Inc. ("DEI") and Dominion Energy Questar Corporation ("Dominion Questar") to purchase substantially all of the natural gas transmission and storage business of DEI and Dominion Questar (the "Transaction"). The Transaction is valued at approximately $9.7 billion, consisting of a cash purchase price of approximately $4.0 billion, subject to adjustment for cash and indebtedness as of the closing, and the assumption of approximately $5.7 billion of existing indebtedness for borrowed money. BHE expects to fund the purchase price, net of cash acquired, with capital from its shareholders. Subject to certain closing conditions, the Transaction is expected to close in the fourth quarter of 2020.

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 $1.1 billion for the six-month period ended June 30, 2020, and has commitments as of June 30, 2020, subject to satisfaction of certain specified conditions, to provide equity contributions of $1.4 billion 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.

Contractual Obligations

As of June 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.

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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 June 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 June 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 June 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. A reduction in residential property transactions may continue to occur 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.

BHE Renewables' Counterparty Risk

On January 29, 2019, PG&E Corporation and Pacific Gas and Electric Company (the "PG&E Utility") (together "PG&E") filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Northern District of California ("PG&E Bankruptcy Filing"). The Company owns 100% of Topaz and owns a 49% interest in Agua Caliente. Topaz is a 550-MW solar photovoltaic electric power generating facility located in California. Topaz sells 100% of its energy, capacity and RECs generated from the facility to PG&E Utility under a 25-year wholesale 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 is 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 also expects to begin receiving distributions from Topaz and Agua Caliente in the second half of 2020 in accordance with the provisions of each respective debt agreement.

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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.

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 proposes 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 it submitted on June 1, 2020. On May 21, 2020, the FERC issued an order involving reforms to the PJM's day-ahead and real-time reserves markets and directing the PJM to submit no later than August 5, 2020, a new methodology for estimating revenues that resources will receive for sales of energy and related services, which could impact MOPR levels. The FERC has no deadline for acting on the compliance filings and could accept, reject or direct further revisions to all or part of the PJM's proposed tariff revisions, auction schedule and revenue projection methodology. The PJM cannot resume activities related to its capacity auctions until the FERC acts on these compliance filings.

Exelon Generation is currently working with the PJM and other stakeholders to pursue the FRR option prior to the next capacity auction in the PJM. 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 such legislative and regulatory changes can be implemented prior to the next capacity auction in the PJM or their potential impact on the continued operation of Quad Cities Station.

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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 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.

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 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 is subject to the WPSC's approval and a hearing is scheduled to begin in August 2020.

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. PacifiCorp reached a separate agreement with parties to defer the incremental depreciation expense from the 2018 depreciation study for one year, which will allow PacifiCorp to postpone filing a general rate case in Idaho until 2021.

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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.

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. 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 2020, the IPUC approved PacifiCorp's application to defer costs associated with COVID‑19 and required 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 regulatory review is expected to be concluded by the end of September 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.

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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.

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 repowerings would be depreciated and offset with excess deferred income taxes resulting from 2017 Tax Reform. During the six-month period ended June 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 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. A final rate change is expected to be effective October 15, 2020, after the repowered Dunlap wind facility is placed in service. As a result of the settlement, accelerated depreciation of $7 million and offsetting amortization of PacifiCorp's OATT deferral was recognized during the six-month period ended June 30, 2020, associated with undepreciated equipment replaced as a result of the repowering of the Glenrock III wind facility. The settlement provides for accelerated depreciation of the equipment replaced at the Dunlap wind facility to also be offset with PacifiCorp's OATT deferral once placed in-service.

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.

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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.

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 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.

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 will go 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.

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.

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. The settlement is subject to approval by the WUTC.

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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 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.

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.

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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.

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 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 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.

In June 2020, Nevada Power filed a regulatory rate review with the PUCN. The filing requested an annual revenue reduction of $120 million. An order is expected by the end of 2020 and, if approved, would be effective January 1, 2021.

In June 2020, Sierra Pacific filed with the PUCN a petition 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.

 

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.

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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 and a hearing is scheduled for September 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 is expected in late August 2020.

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 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 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.

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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. FERC approval of the settlement is expected before the end of 2020.

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. The forecast revenue requirement is based on an 8.5% return on equity and 37% deemed equity as approved by the AUC for 2019 and 2020.

In July 2019, AltaLink filed a 2019-2021 partial negotiated settlement application with the AUC. The application consisted of negotiated reductions totaling a C$38 million net decrease to the three-year total revenue requirement applied for in AltaLink's 2019-2021 GTA updated in April 2019. However, this may be partially offset by AltaLink's request for an additional C$20 million of forecast transmission line clearance capital as part of an excluded matter. The 2019-2021 negotiated settlement agreement excluded certain matters related to the new salvage study and salvage recovery approach, additional capital spending and incremental asset retirements. AltaLink's salvage proposal is estimated to save customers C$267 million between 2019 and 2023. Excluded matters were examined by the AUC in a hearing held in November 2019. In November 2019, a 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.

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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. In July 2020, after the AUC closed the generic proceeding, AltaLink filed an application requesting that the AUC review and vary its decision on AltaLink's 2019-2021 GTA and approve AltaLink's proposed salvage methodology. Reverting the salvage method back to the traditional pre-collection approach will increase 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 will further review 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 a further C$31 million of capital subject to further review 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$895 million for 2020 and C$899 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 to December 2020 and a final monthly tariff of C$74 million for 2021.

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.

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.

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In March 2020, the AUC issued a letter indicating that it will provide further process steps after AltaLink submits 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. The AUC has not yet determined if an oral hearing is required.

Alberta Electric System Operator Tariff Decision

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

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

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 has set a further process of information requests and responses and written submissions which are scheduled to be completed in September 2020.

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.

Clean Air Act Regulations

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

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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 July 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.

Numerous lawsuits have been filed in the District of Columbia Circuit ("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.

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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 United States Court of Appeals for 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 United States Court of Appeals for 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.

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 selective catalytic reduction ("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 best available retrofit technology alternative into Utah's regional haze SIP. The best available retrofit technology alternative makes the shutdown of PacifiCorp's Carbon plant enforceable under the SIP and removes the requirement to install selective catalytic reduction technology on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of Air Quality submitted the 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.

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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 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 selective catalytic reduction systems on Jim Bridger Units 1 and 2. PacifiCorp anticipates the EPA will initiate a public comment process in August 2020 as part of the federal review and approval process.

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 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 Army Corps of Engineers signed the final rule narrowing the federal government's permitting authority under the Clean Water Act. The new Navigable Waters Protection Rule, which took effect in June 2020, redefines what waters qualify as navigable waters of the U.S. and are under Clean Water Act jurisdiction. Under the new rule, the Clean Water Act will be considered to cover territorial seas and traditional navigable waters; tributaries that flow into jurisdictional waters; wetlands that are directly adjacent to jurisdictional waters; and lakes, ponds and impoundments of jurisdictional waters. The agency and corps originally proposed six categories, but in the final version they collapsed ditches and impoundments into other categories. There are also 12 categories of waters that the agencies highlighted as being excluded from coverage, including groundwater, ephemeral streams and pools, prior converted cropland and waste treatment systems.

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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 RCRA. 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 RCRA 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.

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.

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Multiple parties filed challenges over various aspects of the final rule in the D.C. Circuit in 2015, resulting in settlement of some of the issues and subsequent regulatory action by the EPA, including subjecting inactive surface impoundments to regulation. Oral argument was held by the D.C. Circuit 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.

In December 2019, the EPA proposed additional changes to the CCR rule in its Holistic Approach to Closure: Part A rule. This proposal addressed the D.C. Circuit's revocation of the provisions that allow unlined impoundments to continue receiving ash and establishes a new deadline in August 2020, by which all unlined surface impoundments (including clay lined impoundments that do not otherwise meet the definition of "lined") must initiate closure. The proposal also identifies and clarifies several opportunities to extend the closure deadlines for lack of alternative capacity or closure of the coal-fueled operating unit by a certain date. Comments on the proposal were accepted through January 2020. In March 2020, the EPA proposed the Holistic Approach to Closure: Part B rule, which sets forth procedures for owners and operators of unlined ash ponds to demonstrate that the liner systems or underlying soils for these units perform as well as the liner criteria in the CCR rule and to request approval to continue operating such units. The proposal also includes revisions of the rule's closure provisions, including options that would allow the use of CCR for purposes of closing a CCR unit subject to forced closure; an additional closure option for units that are closing by removal of CCR but cannot complete groundwater corrective action within the rule's prescribed closure timeframes; and a new requirement for annual closure progress reports. The EPA accepted comment on the proposal through April 2020.

In February 2020, the EPA proposed a federal CCR permit program as required by the Water Infrastructure Improvements for the Nation Act of 2016. The proposal would require permits for all CCR units in nonparticipating states and in Indian country. The proposal would establish three types of permits (individual, general and permit-by-rule); establish a tiered schedule for permit application deadlines, beginning with facilities that have at least one existing CCR impoundment that is classified as having "high hazard potential;" and postpone timelines for permit application deadlines for all other CCR facilities to be established at a later date. All CCR units would remain subject to the federal self-implementing rule until a state or federal permit is issued. The EPA accepted comments on this proposal through July 2020. Until the proposals are finalized and fully litigated, the Registrants cannot determine whether additional action may be required.

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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.

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PacifiCorp and its subsidiaries

Consolidated Financial Section

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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 June 30, 2020, the related consolidated statements of operations and changes in shareholders' equity for the three-month and six-month periods ended June 30, 2020 and 2019, and of cash flows for the six-month periods ended June 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

August 7, 2020

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

		As of
		June 30,				December 31,
		2020				2019
ASSETS
Current assets:
Cash and cash equivalents		$	711			$	30
Trade receivables, net		615				644
Other receivables, net		37				70
Inventories		474				394
Other current assets		170				152
Total current assets		2,007				1,290
Property, plant and equipment, net		21,553				20,973
Regulatory assets		1,052				1,060
Other assets		355				374
Total assets		$	24,967			$	23,697

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

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

		As of
		June 30,				December 31,
		2020				2019
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable		$	685			$	679
Accrued interest		126				116
Accrued property, income and other taxes		131				96
Accrued employee expenses		103				75
Short-term debt		—				130
Current portion of long-term debt		438				38
Other current liabilities		261				226
Total current liabilities		1,744				1,360
Long-term debt		8,210				7,620
Regulatory liabilities		2,854				2,913
Deferred income taxes		2,593				2,563
Other long-term liabilities		786				804
Total liabilities		16,187				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		4,314				3,972
Accumulated other comprehensive loss, net		(15		)		(16		)
Total shareholders' equity		8,780				8,437
Total liabilities and shareholders' equity		$	24,967			$	23,697

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

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Operating revenue	$	1,144			$	1,167			$	2,350			$	2,426
Operating expenses:
Cost of fuel and energy	383				384				800				849
Operations and maintenance	243				255				497				511
Depreciation and amortization	210				209				462				414
Property and other taxes	52				51				101				100
Total operating expenses	888				899				1,860				1,874
Operating income	256				268				490				552
Other income (expense):
Interest expense	(110		)		(102		)		(212		)		(198		)
Allowance for borrowed funds	12				8				22				15
Allowance for equity funds	23				16				44				30
Interest and dividend income	3				7				6				12
Other, net	8				9				4				16
Total other income (expense)	(64		)		(62		)		(136		)		(125		)
Income before income tax (benefit) expense	192				206				354				427
Income tax expense	26				38				12				80
Net income	$	166			$	168			$	342			$	347

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

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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, March 31, 2019		$	2			$	—			$	4,479			$	3,381			$	(12	)		$	7,850
Net income		—				—				—				168				—				168
Other comprehensive loss		—				—				—				(1		)		—				(1		)
Balance, June 30, 2019		$	2			$	—			$	4,479			$	3,548			$	(12	)		$	8,017
Balance, December 31, 2018		$	2			$	—			$	4,479			$	3,377			$	(13	)		$	7,845
Net income		—				—				—				347				—				347
Other comprehensive (loss) income		—				—				—				(1		)		1				—
Common stock dividends declared		—				—				—				(175		)		—				(175		)
Balance, June 30, 2019		$	2			$	—			$	4,479			$	3,548			$	(12	)		$	8,017
Balance, March 31, 2020		$	2			$	—			$	4,479			$	4,148			$	(15	)		$	8,614
Net income		—				—				—				166				—				166
Balance, June 30, 2020		$	2			$	—			$	4,479			$	4,314			$	(15	)		$	8,780
Balance, December 31, 2019		$	2			$	—			$	4,479			$	3,972			$	(16	)		$	8,437
Net income		—				—				—				342				—				342
Other comprehensive income		—				—				—				—				1				1
Balance, June 30, 2020		$	2			$	—			$	4,479			$	4,314			$	(15	)		$	8,780

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

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2020				2019
Cash flows from operating activities:
Net income	$	342			$	347
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	462				414
Allowance for equity funds	(44		)		(30		)
Changes in regulatory assets and liabilities	(12		)		(22		)
Deferred income taxes and amortization of investment tax credits	(24		)		(8		)
Other, net	1				(5		)
Changes in other operating assets and liabilities:
Trade receivables, other receivables and other assets	45				64
Inventories	(80		)		(23		)
Derivative collateral, net	7				4
Accrued property, income and other taxes, net	38				115
Accounts payable and other liabilities	35				(14		)
Net cash flows from operating activities	770				842
Cash flows from investing activities:
Capital expenditures	(973		)		(817		)
Other, net	29				4
Net cash flows from investing activities	(944		)		(813		)
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	683				462
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	$	719			$	554

 

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

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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 June 30, 2020 and for the three- and six-month periods ended June 30, 2020 and 2019. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and six-month periods ended June 30, 2020 and 2019. The results of operations for the three- and six-month periods ended June 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 six-month period ended June 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 June 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 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 across PacifiCorp's service territory and suspension of late payment fees in certain jurisdictions implemented to assist customers. Other impacts may include increased retirement plan contributions due to reductions in the market value of retirement plan assets. The duration and extent of COVID‑19 and its future impact on PacifiCorp's business cannot be reasonably estimated at this time. 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.

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In March and April 2020, PacifiCorp filed applications requesting authorization to defer costs associated with COVID‑19 with the Utah Public Service Commission, the Oregon Public Utility Commission, 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. 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 2020, the IPUC approved PacifiCorp's application to defer costs associated with COVID‑19 and required 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 June 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
	June 30,				December 31,
	2020				2019
Cash and cash equivalents	$	711			$	30
Restricted cash included in other current assets	5				4
Restricted cash included in other assets	3				2
Total cash and cash equivalents and restricted cash and cash equivalents	$	719			$	36

(3)	Property, Plant and Equipment, Net

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

			As of
			June 30,				December 31,
	Depreciable Life		2020				2019
Utility Plant:
Generation	14 - 67 years		$	12,463			$	12,509
Transmission	58 - 75 years		6,564				6,482
Distribution	20 - 70 years		7,439				7,307
Intangible plant(1)	5 - 75 years		1,026				1,016
Other	5 - 60 years		1,468				1,449
Utility plant in service			28,960				28,763
Accumulated depreciation and amortization			(9,863		)		(9,803		)
Utility plant in-service, net			19,097				18,960
Other non-regulated, net of accumulated depreciation and amortization	59 years		9				10
Plant, net			19,106				18,970
Construction work-in-progress			2,447				2,003
Property, plant and equipment, net			$	21,553			$	20,973

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

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For the six-month period ended June 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.

(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						Six-Month Periods
	Ended June 30,						Ended June 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	(9	)		(4	)		(10	)		(4	)
Effects of ratemaking	(1	)		(1	)		(1	)		(1	)
Amortization of excess deferred income taxes	(1	)		—			(10	)		—
Other	1			(1	)		—			—
Effective income tax rate	14	%		18	%		3	%		19	%

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 is primarily attributable to the amortization of $30 million of Oregon allocated excess deferred income taxes pursuant to the Oregon Renewable Adjustment Clause settlement, whereby a portion of Oregon allocated excess deferred income taxes was used to accelerate depreciation on Oregon's share of certain repowered wind facilities.

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 six-month periods ended June 30, 2020 and 2019, PacifiCorp made net cash payments for federal and state income tax to BHE totaling $42 million and $11 million, respectively.

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(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								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Pension:
Service cost	$	—			$	—			$	—			$	—
Interest cost	9				11				18				22
Expected return on plan assets	(14		)		(16		)		(28		)		(33		)
Net amortization	4				3				9				6
Net periodic benefit credit	$	(1	)		$	(2	)		(1		)		(5		)
Other postretirement:
Service cost	$	1			$	1			$	1			$	1
Interest cost	2				3				5				6
Expected return on plan assets	(3		)		(5		)		(7		)		(10		)
Net amortization	—				—				—				—
Net periodic benefit credit	$	—			$	(1	)		(1		)		(3		)

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 June 30, 2020, $2 million and $- million of contributions had been made to the pension and other postretirement benefit plans, respectively.

(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.

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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 June 30, 2020
Not designated as hedging contracts(1):
Commodity assets	$	9			$	7			$	6			$	—			$	22
Commodity liabilities	(4		)		—				(44		)		(42		)		(90		)
Total	5				7				(38		)		(42		)		(68		)
Total derivatives	5				7				(38		)		(42		)		(68		)
Cash collateral receivable	—				—				19				21				40
Total derivatives - net basis	$	5			$	7			$	(19	)		$	(21	)		$	(28	)
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 June 30, 2020 and December 31, 2019, a regulatory asset of $68 million and $62 million, respectively, was recorded related to the net derivative liability of $68 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								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Beginning balance	$	84			$	78			$	62			$	96
Changes in fair value	(6		)		26				28				(28		)
Net gains (losses) reclassified to operating revenue	5				6				13				(16		)
Net (losses) gains reclassified to cost of fuel and energy	(15		)		(9		)		(35		)		49
Ending balance	$	68			$	101			$	68			$	101

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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		June 30,			December 31,
	Measure		2020			2019
Electricity sales, net	Megawatt hours		(1	)		(2	)
Natural gas purchases	Decatherms		116			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 June 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 $84 million and $80 million as of June 30, 2020 and December 31, 2019, respectively, for which PacifiCorp had posted collateral of $40 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 June 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.

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(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 June 30, 2020
Assets:
Commodity derivatives		$	—			$	22			$	—			$	(10	)		$	12
Money market mutual funds(2)		450				—				—				—				450
Investment funds		26				—				—				—				26
		$	476			$	22			$	—			$	(10	)		$	488
Liabilities - Commodity derivatives		$	—			$	(90	)		$	—			$	50			$	(40	)
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 $40 million and $47 million as of June 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.

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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 June 30, 2020								As of December 31, 2019
		Carrying				Fair				Carrying				Fair
		Value				Value				Value				Value
Long-term debt		$	8,648			$	10,870			$	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.

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.

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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 evaluating the order in coordination with its settlement partners, including continued implementation of the agreement. Requests for rehearing are due on August 17, 2020.

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

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								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Customer Revenue:
Retail:
Residential	$	384			$	349			$	844			$	838
Commercial	346				373				704				733
Industrial	268				289				545				581
Other retail	68				74				95				103
Total retail	1,066				1,085				2,188				2,255
Wholesale	17				11				17				39
Transmission	24				25				46				50
Other Customer Revenue	20				22				46				38
Total Customer Revenue	1,127				1,143				2,297				2,382
Other revenue	17				24				53				44
Total operating revenue	$	1,144			$	1,167			$	2,350			$	2,426

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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 Second Quarter and First Six Months of 2020 and 2019

Overview

Net income for the second quarter of 2020 was $166 million, a decrease of $2 million, or 1%, compared to 2019. Net income decreased primarily due to lower utility margin of $22 million, higher interest expense of $8 million, higher pension and post retirement costs of $4 million and lower interest and dividend income of $4 million, partially offset by lower operations and maintenance expense of $12 million primarily due to lower labor and benefits costs, higher allowances for equity and borrowed funds of $11 million and higher PTCs of $9 million primarily due to repowering of certain of PacifiCorp's wind-powered generating facilities. Utility margin decreased primarily due to lower retail customer volumes and higher coal costs, partially offset by price impacts from changes in sales mix and lower natural gas costs. Retail customer volumes decreased 4.2% primarily due to the impacts of COVID‑19, resulting in lower commercial and industrial customer usage and higher residential customer usage, partially offset by favorable impacts of weather, primarily in Utah and Oregon, and an increase in the average number of customers. Energy generated was relatively flat for the second quarter of 2020 compared to 2019. Wholesale electricity sales volumes were also relatively flat while purchased electricity volumes decreased 5%.

Net income for the first six months of 2020 was $342 million, a decrease of $5 million, or 1%, compared to 2019. Net income decreased primarily due to lower utility margin of $27 million and higher interest expense of $14 million, higher pension and post retirement costs of $7 million and lower interest and dividend income of $6 million, partially offset by higher allowances for equity and borrowed funds of $21 million, higher PTCs of $17 million primarily due to repowering of certain of PacifiCorp's wind-powered generating facilities and lower operations and maintenance expense of $14 million primarily due to lower labor and benefits costs. Utility margin decreased primarily due to lower retail revenue from lower volumes and price impacts from changes in sales mix, lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms and lower wholesale revenue primarily due to lower volumes, partially offset by lower coal-fueled and natural gas-fueled generation costs. Retail customer volumes decreased 2.9% primarily due to the impacts of COVID‑19, resulting in lower commercial and industrial customer usage and higher residential customer usage, and unfavorable impacts of weather primarily in Oregon and Washington, partially offset by an increase in the average number of customers. Energy generated decreased 6% for the first six 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 21% and purchased electricity volumes increased 5%.

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.

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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):

	Second Quarter															First Six Months
	2020				2019				Change							2020				2019				Change
Utility margin:
Operating revenue	$	1,144			$	1,167			$	(23	)		(2	)%		$	2,350			$	2,426			$	(76	)		(3	)%
Cost of fuel and energy	383				384				(1		)		—			800				849				(49		)		(6	)
Utility margin	761				783				(22		)		(3	)		1,550				1,577				(27		)		(2	)
Operations and maintenance	243				255				(12		)		(5	)		497				511				(14		)		(3	)
Depreciation and amortization	210				209				1				—			462				414				48				12
Property and other taxes	52				51				1				2			101				100				1				1
Operating income	$	256			$	268			$	(12	)		(4	)%		$	490			$	552			$	(62	)		(11	)%

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

	Second Quarter															First Six Months
	2020				2019				Change							2020				2019				Change
Utility margin (in millions):
Operating revenue	$	1,144			$	1,167			$	(23	)		(2	)%		$	2,350			$	2,426			$	(76	)		(3	)%
Cost of fuel and energy	383				384				(1		)		—			800				849				(49		)		(6	)
Utility margin	$	761			$	783			$	(22	)		(3	)%		$	1,550			$	1,577			$	(27	)		(2	)%
Sales (GWhs):
Residential	3,656				3,307				349				11	%		8,077				7,915				162				2	%
Commercial	3,948				4,300				(352		)		(8	)		8,358				8,745				(387		)		(4	)
Industrial, irrigation and other	4,759				5,297				(538		)		(10	)		9,461				10,007				(546		)		(5	)
Total retail	12,363				12,904				(541		)		(4	)		25,896				26,667				(771		)		(3	)
Wholesale	932				929				3				—			2,213				2,816				(603		)		(21	)
Total sales	13,295				13,833				(538		)		(4	)%		28,109				29,483				(1,374		)		(5	)%
Average number of retail customers  (in thousands)	1,964				1,928				36				2	%		1,959				1,924				35				2	%
Average revenue per MWh:
Retail	$	86.19			$	83.96			$	2.23			3	%		$	84.51			$	84.54			$	(0.03	)		—	%
Wholesale	$	33.97			$	36.96			$	(2.99	)		(8	)%		$	29.56			$	28.45			$	1.11			4	%
Heating degree days	1,333				1,376				(43		)		(3	)%		5,938				6,468				(530		)		(8	)%
Cooling degree days	439				311				128				41	%		439				311				128				41	%
Sources of energy (GWhs)(1):
Coal	6,197				6,182				15				—	%		13,425				15,668				(2,243		)		(14	)%
Natural gas	2,202				2,315				(113		)		(5	)		5,243				5,376				(133		)		(2	)
Hydroelectric(2)	891				1,014				(123		)		(12	)		1,937				1,731				206				12
Wind and other(2)	864				597				267				45			1,976				1,357				619				46
Total energy generated	10,154				10,108				46				—			22,581				24,132				(1,551		)		(6	)
Energy purchased	4,233				4,450				(217		)		(5	)		7,624				7,286				338				5
Total	14,387				14,558				(171		)		(1	)%		30,205				31,418				(1,213		)		(4	)%
Average cost of energy per MWh:
Energy generated(3)	$	17.19			$	17.41			$	(0.22	)		(1	)%		$	17.53			$	19.55			$	(2.02	)		(10	)%
Energy purchased	$	38.25			$	36.24			$	2.01			6	%		$	42.33			$	44.67			$	(2.34	)		(5	)%

(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.

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Utility margin decreased $22 million for the second quarter of 2020 compared to 2019 primarily due to:

•

$18 million of lower retail revenue due to lower volumes, partially offset by price impacts from changes in sales mix. Retail customer volumes decreased 4.2% primarily due to the impacts of COVID‑19, resulting in lower commercial and industrial customer usage and higher residential customer usage, partially offset by favorable impacts of weather, primarily in Utah and Oregon, and an increase in the average number of customers;

•	$4 million of higher coal-fueled generation costs primarily due to higher average prices;

•	$4 million of lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms; and

•	$3 million of lower wholesale revenue primarily due to lower average market prices.

The decreases above were partially offset by:

•	$5 million of lower natural gas-fueled generation costs due to lower natural gas prices and lower volumes; and

•	$4 million of lower wheeling expenses.

Operations and maintenance decreased $12 million, or 5%, for the second quarter of 2020 compared to 2019 primarily due to lower labor and other employee related expenses and timing of maintenance, partially offset by higher bad debt expense.

Interest expense increased $8 million, or 8% for the second quarter of 2020 compared to 2019 primarily due to higher average long-term debt, partially offset by lower weighted average long-term debt interest rate.

Allowance for borrowed and equity funds increased $11 million, or 46%, for the second quarter of 2020 compared to 2019 primarily due to higher qualified construction work-in-progress balances.

Interest and dividend income decreased $4 million, or 57%, for the second quarter of 2020 compared to 2019 primarily due to lower interest rates in the current year.

Other, net decreased $1 million, or 11%, for the second quarter of 2020 compared to 2019 primarily due to higher pension and post retirement costs of $4 million, partially offset by higher cash surrender value of corporate-owned life insurance policies.

Income tax expense decreased $12 million, or 32% for the second quarter of 2020 compared to the second quarter of 2019. The effective tax rate was 14% for 2020 and 18% for 2019. The effective tax rate decreased primarily due to increased PTCs from PacifiCorp's wind-powered generating facilities.

Utility margin decreased $27 million for the first six months of 2020 compared to 2019 primarily due to:

•

$66 million of lower retail revenue from lower volumes and price impacts from changes in sales mix. Retail customer volumes decreased 2.9% primarily due to the impacts of COVID‑19, resulting in lower commercial and industrial customer usage and higher residential customer usage, and unfavorable impacts of weather primarily in Oregon and Washington, partially offset by an increase in the average number of customers;

•	$35 million of lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms; and

•	$15 million of lower wholesale revenue due to lower volumes, partially offset by the impact of higher average market prices.

The decreases above were partially offset by:

•	$59 million of lower coal-fueled generation costs due to lower volumes, partially offset by higher coal prices;

•	$19 million of lower natural gas-fueled generation costs due to lower natural gas prices and lower volumes;

•	$7 million of higher other revenue due to impacts of the Oregon RAC settlement (offset in depreciation expense); and

•	$3 million of lower purchased electricity costs due to lower average market prices, partially offset by higher volumes.

Operations and maintenance decreased $14 million, or 3%, for the first six months of 2020 compared to 2019 primarily due to lower labor and other employee related expenses and timing of maintenance, partially offset by higher bad debt expense.

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Depreciation and amortization increased $48 million, or 12%, for the first six months of 2020 compared to 2019, primarily due to accelerated depreciation of $47 million ($7 million offset in other revenue and $40 million offset in income tax expense) for Oregon's share of certain retired wind equipment due to repowering.

Interest expense increased $14 million, or 7% for the first six months of 2020 compared to 2019 primarily due to higher average long-term debt, partially offset by lower weighted average long-term debt interest rate.

Allowance for borrowed and equity funds increased $21 million, or 47%, for the first six months of 2020 compared to 2019 primarily due to higher qualified construction work-in-progress balances.

Interest and dividend income decreased $6 million, or 50%, for the first six months of 2020 compared to 2019 primarily due to lower interest rates in the current year.

Other, net decreased $12 million, or 75% for the first six months of 2020 compared to 2019 primarily due to higher pension and post-retirement costs of $7 million and lower cash surrender value of corporate-owned life insurance policies.

Income tax expense decreased $68 million, or 85%, for the first six months of 2020 compared to 2019. The effective tax rate was 3% for 2020 and 19% for 2019. The effective tax rate decreased primarily due to the 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 and due to increased PTCs from PacifiCorp's wind-powered generating facilities.

Liquidity and Capital Resources

 

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

Cash and cash equivalents		$	711
Credit facilities		1,200
Less:
Tax-exempt bond support		(256		)
Net credit facilities		944
Total net liquidity		$	1,655
Credit facilities:
Maturity dates		2022

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2020 and 2019 were $770 million and $842 million, respectively. The change was primarily due to lower collections from retail customers primarily due to lower commercial and industrial customer volumes due to COVID‑19, lower collections from wholesale customers and higher cash paid for income taxes, partially offset by lower wholesale and wheeling purchases and cost of fuel related payments.

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 six-month periods ended June 30, 2020 and 2019 were $(944) million and $(813) million, respectively. The change is primarily due to an increase in capital expenditures of $156 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.

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Financing Activities

Net cash flows from financing activities for the six-month period ended June 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 six-month period ended June 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 June 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.

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):

	Six-Month Periods								Annual
	Ended June 30,								Forecast
	2019				2020				2020
Transmission system investment	$	206			$	115			$	305
Wind investment	354				441				1,350
Operating and other	257				417				850
Total	$	817			$	973			$	2,505

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PacifiCorp's historical and forecast capital expenditures include the following:

•

Transmission system investment primarily reflects initial costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, a major segment of PacifiCorp's Energy Gateway Transmission expansion program expected to be placed in-service in 2020 and investment in additional Energy Gateway Transmission segments expected to be placed in service in 2023. Forecast spending for the Aeolus-Bridger/Anticline line totals $158 million in 2020.

•	Wind investment includes the following:

◦

Construction of wind-powered generating facilities at PacifiCorp totaling $395 million and $138 million for the six-month periods ended June 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 the energy production is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. PacifiCorp anticipates costs associated with the construction of wind-powered generating facilities will total an additional $802 million for 2020.

◦

Repowering existing wind-powered generating facilities at PacifiCorp totaling $46 million and $216 million for the six-month periods ended June 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 10 years following each facility's return to service. PacifiCorp anticipates costs for these activities will total an additional $107 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 May 2020, the OPUC acknowledged the 2019 IRP with conditions. The UPSC also acknowledged the 2019 IRP in May 2020. The IPUC and the WPSC review of the 2019 IRP is ongoing.

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 PacifiCorp's 2020 All Source RFP ("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. 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. The 2020AS RFP schedule calls for bids to be submitted by August 10, 2020.

Contractual Obligations

As of June 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.

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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 June 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 June 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 June 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.

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.

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MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company

Consolidated Financial Section

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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 June 30, 2020, the related statements of operations and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2020 and 2019, and of cash flows for the six-month periods ended June 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

August 7, 2020

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MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,				December 31,
	2020				2019
ASSETS
Current assets:
Cash and cash equivalents	$	5			$	287
Trade receivables, net	291				291
Income tax receivable	331				—
Inventories	257				226
Other current assets	77				90
Total current assets	961				894
Property, plant and equipment, net	18,756				18,375
Regulatory assets	315				289
Investments and restricted investments	817				818
Other assets	199				188
Total assets	$	21,048			$	20,564

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

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MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	June 30,				December 31,
	2020				2019
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	405			$	519
Accrued interest	78				78
Accrued property, income and other taxes	148				225
Short-term debt	195				—
Other current liabilities	189				219
Total current liabilities	1,015				1,041
Long-term debt	7,209				7,208
Regulatory liabilities	1,353				1,406
Deferred income taxes	2,779				2,626
Asset retirement obligations	759				704
Other long-term liabilities	333				339
Total liabilities	13,448				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	7,039				6,679
Total shareholder's equity	7,600				7,240
Total liabilities and shareholder's equity	$	21,048			$	20,564

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

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MIDAMERICAN ENERGY COMPANY

STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Operating revenue:
Regulated electric	$	518			$	538			$	989			$	1,080
Regulated natural gas and other	95				121				305				421
Total operating revenue	613				659				1,294				1,501
Operating expenses:
Cost of fuel and energy	71				91				151				205
Cost of natural gas purchased for resale and other	42				62				170				257
Operations and maintenance	182				204				347				411
Depreciation and amortization	175				179				351				356
Property and other taxes	35				29				69				63
Total operating expenses	505				565				1,088				1,292
Operating income	108				94				206				209
Other income (expense):
Interest expense	(74		)		(70		)		(150		)		(139		)
Allowance for borrowed funds	4				7				7				13
Allowance for equity funds	9				17				17				32
Other, net	21				10				16				30
Total other income (expense)	(40		)		(36		)		(110		)		(64		)
Income before income tax benefit	68				58				96				145
Income tax benefit	(141		)		(98		)		(264		)		(204		)
Net income	$	209			$	156			$	360			$	349

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

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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, March 31, 2019	$	—			$	561			$	6,078			$	6,639
Net income	—				—				156				156
Balance, June 30, 2019	$	—			$	561			$	6,234			$	6,795
Balance, December 31, 2018	$	—			$	561			$	5,885			$	6,446
Net income	—				—				349				349
Balance, June 30, 2019	$	—			$	561			$	6,234			$	6,795
Balance, March 31, 2020	$	—			$	561			$	6,830			$	7,391
Net income	—				—				209				209
Balance, June 30, 2020	$	—			$	561			$	7,039			$	7,600
Balance, December 31, 2019	$	—			$	561			$	6,679			$	7,240
Net income	—				—				360				360
Balance, June 30, 2020	$	—			$	561			$	7,039			$	7,600

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

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MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2020				2019
Cash flows from operating activities:
Net income	$	360			$	349
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	351				356
Amortization of utility plant to other operating expenses	17				17
Allowance for equity funds	(17		)		(32		)
Deferred income taxes and amortization of investment tax credits	131				52
Other, net	(17		)		6
Changes in other operating assets and liabilities:
Trade receivables and other assets	(1		)		(2		)
Inventories	(31		)		20
Pension and other postretirement benefit plans	(11		)		(6		)
Accrued property, income and other taxes, net	(409		)		(263		)
Accounts payable and other liabilities	(47		)		(34		)
Net cash flows from operating activities	326				463
Cash flows from investing activities:
Capital expenditures	(824		)		(1,017		)
Purchases of marketable securities	(210		)		(99		)
Proceeds from sales of marketable securities	202				95
Other, net	14				13
Net cash flows from investing activities	(818		)		(1,008		)
Cash flows from financing activities:
Proceeds from long-term debt	—				1,460
Repayments of long-term debt	—				(500		)
Net proceeds from (repayments of) short-term debt	195				(240		)
Other, net	(1		)		—
Net cash flows from financing activities	194				720
Net change in cash and cash equivalents and restricted cash and cash equivalents	(298		)		175
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	$	32			$	231

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

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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 June 30, 2020, and for the three- and six-month periods ended June 30, 2020 and 2019. The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and six-month periods ended June 30, 2020 and 2019. The results of operations for the three- and six-month periods ended June 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 six-month period ended June 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 June 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.

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(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 June 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 for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of June 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
	June 30,				December 31
	2020				2019
Cash and cash equivalents	$	5			$	287
Restricted cash and cash equivalents in other current assets	27				43
Total cash and cash equivalents and restricted cash and cash equivalents	$	32			$	330

(3)	Property, Plant and Equipment, Net

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

			As of
			June 30,				December 31,
	Depreciable Life		2020				2019
Utility plant in service, net:
Generation	20-70 years		$	15,800			$	15,687
Transmission	52-75 years		2,208				2,124
Electric distribution	20-75 years		4,186				4,095
Natural gas distribution	29-75 years		1,844				1,820
Utility plant in service			24,038				23,726
Accumulated depreciation and amortization			(6,388		)		(6,139		)
Utility plant in service, net			17,650				17,587
Nonregulated property, net:
Nonregulated property gross	20-50 years		7				7
Accumulated depreciation and amortization			(1		)		(1		)
Nonregulated property, net			6				6
			17,656				17,593
Construction work-in-progress			1,100				782
Property, plant and equipment, net			$	18,756			$	18,375

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(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						Six-Month Periods
	Ended June 30,						Ended June 30,
	2020			2019			2020			2019
Federal statutory income tax rate	21	%		21	%		21	%		21	%
Income tax credits	(186	)		(158	)		(257	)		(131	)
State income tax, net of federal income tax benefit	(35	)		(22	)		(33	)		(21	)
Effects of ratemaking	(9	)		(10	)		(7	)		(9	)
Other, net	2			—			1			(1	)
Effective income tax rate	(207	)%		(169	)%		(275	)%		(141	)%

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. MidAmerican Energy made net cash payments for income tax to BHE totaling $19 million and $9 million for the six-month periods ended June 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.

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

	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Pension:
Service cost	$	1			$	1			$	2			$	3
Interest cost	6				8				12				15
Expected return on plan assets	(10		)		(11		)		(20		)		(21		)
Net amortization	1				—				1				—
Net periodic benefit credit	$	(2	)		$	(2	)		$	(5	)		$	(3	)
Other postretirement:
Service cost	$	1			$	2			$	2			$	3
Interest cost	1				3				3				5
Expected return on plan assets	(3		)		(3		)		(6		)		(6		)
Net amortization	(2		)		(1		)		(3		)		(2		)
Net periodic benefit (credit) cost	$	(3	)		$	1			$	(4	)		$	—

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 June 30, 2020, $3 million and $- 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.

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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 June 30, 2020:
Assets:
Commodity derivatives		$	1			$	3			$	4			$	(3	)		$	5
Money market mutual funds(2)		12				—				—				—				12
Debt securities:
United States government obligations		176				—				—				—				176
International government obligations		—				4				—				—				4
Corporate obligations		—				73				—				—				73
Municipal obligations		—				3				—				—				3
Agency, asset and mortgage-backed obligations		—				5				—				—				5
Equity securities:
United States companies		336				—				—				—				336
International companies		8				—				—				—				8
Investment funds		20				—				—				—				20
		$	553			$	88			$	4			$	(3	)		$	642
Liabilities - commodity derivatives		$	—			$	(6	)		$	(2	)		$	3			$	(5	)

		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 $- million and $1 million as of June 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.

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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 June 30, 2020								As of December 31, 2019
	Carrying Value				Fair Value				Carrying Value				Fair Value
Long-term debt	$	7,209			$	9,019			$	7,208			$	8,283

(8)	Commitments and Contingencies

Construction Commitments

During the six-month period ended June 30, 2020, MidAmerican Energy entered into firm construction commitments totaling $269 million for the remainder of 2020 through 2021 related to the construction of wind-powered generating facilities in Iowa.

Easements

During the six-month period ended June 30, 2020, MidAmerican Energy entered into non-cancelable easements with minimum payment commitments totaling $98 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 six-month period ended June 30, 2020, MidAmerican Energy entered into non-cancelable maintenance and service contracts related to wind-powered generating facilities with minimum payment commitments totaling $72 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 ("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. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.

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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 June 30, 2020, has accrued a $12 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 June 30, 2020																For the Six-Month Period Ended June 30, 2020
	Electric				Natural Gas				Other				Total				Electric				Natural Gas				Other				Total
Customer Revenue:
Retail:
Residential	$	166			$	59			$	—			$	225			$	314			$	187			$	—			$	501
Commercial	73				15				—				88				143				58				—				201
Industrial	197				3				—				200				360				7				—				367
Natural gas transportation services	—				7				—				7				—				18				—				18
Other retail(1)	32				1				—				33				61				1				—				62
Total retail	468				85				—				553				878				271				—				1,149
Wholesale	28				9				—				37				70				31				—				101
Multi-value transmission projects	17				—				—				17				33				—				—				33
Other Customer Revenue	—				—				—				—				—				—				1				1
Total Customer Revenue	513				94				—				607				981				302				1				1,284
Other revenue	5				1				—				6				8				2				—				10
Total operating revenue	$	518			$	95			$	—			$	613			$	989			$	304			$	1			$	1,294

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	For the Three-Month Period Ended June 30, 2019																For the Six-Month Period Ended June 30, 2019
	Electric				Natural Gas				Other				Total				Electric				Natural Gas				Other				Total
Customer Revenue:
Retail:
Residential	$	148			$	66			$	—			$	214			$	319			$	241			$	—			$	560
Commercial	79				19				—				98				154				85				—				239
Industrial	204				3				—				207				367				9				—				376
Natural gas transportation services	—				8				—				8				—				20				—				20
Other retail(1)	35				(1		)		—				34				70				—				—				70
Total retail	466				95				—				561				910				355				—				1,265
Wholesale	51				15				—				66				127				49				—				176
Multi-value transmission projects	14				—				—				14				30				—				—				30
Other Customer Revenue	—				—				10				10				—				—				15				15
Total Customer Revenue	531				110				10				651				1,067				404				15				1,486
Other revenue	7				1				—				8				13				2				—				15
Total operating revenue	$	538			$	111			$	10			$	659			$	1,080			$	406			$	15			$	1,501

(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.

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(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								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Operating revenue:
Regulated electric	$	518			$	538			$	989			$	1,080
Regulated natural gas	95				111				304				406
Other	—				10				1				15
Total operating revenue	$	613			$	659			$	1,294			$	1,501
Operating income:
Regulated electric	$	101			$	87			$	160			$	153
Regulated natural gas	7				5				46				53
Other	—				2				—				3
Total operating income	108				94				206				209
Interest expense	(74		)		(70		)		(150		)		(139		)
Allowance for borrowed funds	4				7				7				13
Allowance for equity funds	9				17				17				32
Other, net	21				10				16				30
Income before income tax benefit	$	68			$	58			$	96			$	145

	As of
	June 30, 2020				December 31, 2019
Assets:
Regulated electric	$	19,661			$	19,093
Regulated natural gas	1,386				1,468
Other	1				3
Total assets	$	21,048			$	20,564

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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 June 30, 2020, the related consolidated statements of operations and changes in member's equity for the three-month and six-month periods ended June 30, 2020 and 2019, and cash flows for the six-month periods ended June 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

August 7, 2020

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MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,				December 31,
	2020				2019
ASSETS
Current assets:
Cash and cash equivalents	$	8			$	288
Trade receivables, net	291				291
Income tax receivable	335				—
Inventories	257				226
Other current assets	77				91
Total current assets	968				896
Property, plant and equipment, net	18,756				18,377
Goodwill	1,270				1,270
Regulatory assets	315				289
Investments and restricted investments	820				820
Other assets	198				188
Total assets	$	22,327			$	21,840

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

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MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	June 30,				December 31,
	2020				2019
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	405			$	520
Accrued interest	83				84
Accrued property, income and other taxes	148				226
Note payable to affiliate	176				171
Short-term debt	195				—
Other current liabilities	189				219
Total current liabilities	1,196				1,220
Long-term debt	7,449				7,448
Regulatory liabilities	1,353				1,406
Deferred income taxes	2,777				2,621
Asset retirement obligations	759				704
Other long-term liabilities	334				340
Total liabilities	13,868				13,739
Commitments and contingencies (Note 8)
Member's equity:
Paid-in capital	1,679				1,679
Retained earnings	6,780				6,422
Total member's equity	8,459				8,101
Total liabilities and member's equity	$	22,327			$	21,840

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

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MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Operating revenue:
Regulated electric	$	518			$	538			$	989			$	1,080
Regulated natural gas and other	98				122				313				422
Total operating revenue	616				660				1,302				1,502
Operating expenses:
Cost of fuel and energy	71				91				151				205
Cost of natural gas purchased for resale and other	42				62				171				256
Operations and maintenance	183				205				348				412
Depreciation and amortization	175				179				351				356
Property and other taxes	35				29				69				63
Total operating expenses	506				566				1,090				1,292
Operating income	110				94				212				210
Other income (expense):
Interest expense	(78		)		(74		)		(159		)		(149		)
Allowance for borrowed funds	4				7				7				13
Allowance for equity funds	9				17				17				32
Other, net	21				10				15				31
Total other income (expense)	(44		)		(40		)		(120		)		(73		)
Income before income tax benefit	66				54				92				137
Income tax benefit	(142		)		(99		)		(266		)		(206		)
Net income	$	208			$	153			$	358			$	343

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

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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, March 31, 2019	$	1,679			$	5,840			$	7,519
Net income	—				153				153
Balance, June 30, 2019	$	1,679			$	5,993			$	7,672
Balance, December 31, 2018	$	1,679			$	5,650			$	7,329
Net income	—				343				343
Balance, June 30, 2019	$	1,679			$	5,993			$	7,672
Balance, March 31, 2020	$	1,679			$	6,572			$	8,251
Net income	—				208				208
Balance, June 30, 2020	$	1,679			$	6,780			$	8,459
Balance, December 31, 2019	$	1,679			$	6,422			$	8,101
Net income	—				358				358
Balance, June 30, 2020	$	1,679			$	6,780			$	8,459

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

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MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2020				2019
Cash flows from operating activities:
Net income	$	358			$	343
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	351				356
Amortization of utility plant to other operating expenses	17				17
Allowance for equity funds	(17		)		(32		)
Deferred income taxes and amortization of investment tax credits	134				52
Other, net	(17		)		8
Changes in other operating assets and liabilities:
Trade receivables and other assets	—				(5		)
Inventories	(31		)		20
Pension and other postretirement benefit plans	(11		)		(6		)
Accrued property, income and other taxes, net	(414		)		(265		)
Accounts payable and other liabilities	(47		)		(34		)
Net cash flows from operating activities	323				454
Cash flows from investing activities:
Capital expenditures	(824		)		(1,017		)
Purchases of marketable securities	(210		)		(99		)
Proceeds from sales of marketable securities	202				95
Other, net	15				13
Net cash flows from investing activities	(817		)		(1,008		)
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	4				10
Net proceeds from (repayments of) short-term debt	195				(240		)
Other, net	(1		)		(1		)
Net cash flows from financing activities	198				729
Net change in cash and cash equivalents and restricted cash and cash equivalents	(296		)		175
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	$	35			$	232

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

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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 June 30, 2020, and for the three- and six-month periods ended June 30, 2020 and 2019. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and six-month periods ended June 30, 2020 and 2019. The results of operations for the three- and six-month periods ended June 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 six-month period ended June 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 June 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.

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(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 June 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 for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of June 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
	June 30				December 31
	2020				2019
Cash and cash equivalents	$	8			$	288
Restricted cash and cash equivalents in other current assets	27				43
Total cash and cash equivalents and restricted cash and cash equivalents	$	35			$	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 June 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						Six-Month Periods
	Ended June 30,						Ended June 30,
	2020			2019			2020			2019
Federal statutory income tax rate	21	%		21	%		21	%		21	%
Income tax credits	(192	)		(171	)		(269	)		(139	)
State income tax, net of federal income tax benefit	(37	)		(25	)		(35	)		(23	)
Effects of ratemaking	(9	)		(11	)		(7	)		(9	)
Other, net	2			3			1			—
Effective income tax rate	(215	)%		(183	)%		(289	)%		(150	)%

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.

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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. MidAmerican Funding made net cash payments for income tax to BHE totaling $19 million and $8 million for the six-month period ended June 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 June 30, 2020								As of December 31, 2019
	Carrying Value				Fair Value				Carrying Value				Fair Value
Long-term debt	$	7,449			$	9,357			$	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 $3 million and $1 million for the three-month periods ended June 30, 2020 and 2019, respectively, and $8 million and $1 million for the six-month periods ended June 30, 2020 and 2019, respectively.

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(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								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Operating revenue:
Regulated electric	$	518			$	538			$	989			$	1,080
Regulated natural gas	95				111				304				406
Other	3				11				9				16
Total operating revenue	$	616			$	660			$	1,302			$	1,502
Operating income:
Regulated electric	$	101			$	87			$	160			$	153
Regulated natural gas	7				5				46				53
Other	2				2				6				4
Total operating income	110				94				212				210
Interest expense	(78		)		(74		)		(159		)		(149		)
Allowance for borrowed funds	4				7				7				13
Allowance for equity funds	9				17				17				32
Other, net	21				10				15				31
Income before income tax benefit	$	66			$	54			$	92			$	137

	As of
	June 30, 2020				December 31, 2019
Assets(1):
Regulated electric	$	20,852			$	20,284
Regulated natural gas	1,465				1,547
Other	10				9
Total assets	$	22,327			$	21,840

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

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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 Second Quarter and First Six Months of 2020 and 2019

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the second quarter of 2020 was $209 million, an increase of $53 million, or 34%, compared to 2019 primarily due to higher PTCs recognized of $35 million from higher wind generation, which was driven by repowering and new wind projects placed in-service, lower operations and maintenance expense and higher cash surrender value of corporate-owned life insurance policies of $8 million, partially offset by lower allowances for equity and borrowed funds used during construction of $11 million and higher interest expense of $4 million. Electric utility margin was unchanged due to higher retail customer volumes, lower generation and purchased power costs and higher transmission revenue, partially offset by lower wholesale revenue and lower recoveries through bill riders. Electric retail customer volumes increased 1.8%, primarily due to the favorable impact of weather, 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.

MidAmerican Energy's net income for the first six months of 2020 was $360 million, an increase of $11 million, or 3%, compared to 2019 primarily due to higher PTCs recognized of $57 million from higher wind generation, which was driven by repowering and new wind projects placed in-service, and lower operations and maintenance expense, partially offset by lower electric and natural gas utility margins, lower allowances for equity and borrowed funds used during construction of $21 million, lower cash surrender value of corporate-owned life insurance policies of $13 million and higher interest expense of $11 million. Electric utility margin decreased due to lower wholesale revenue and price impacts from changes in sales mix, partially offset by lower generation and purchased power costs and higher retail customer volumes. Electric retail customer volumes increased 0.5% due to increased usage for certain industrial customers, partially offset by the impacts of COVID-19, which generally resulted in lower commercial and industrial customer usage and higher residential customer usage. Natural gas utility margin decreased due to 12.9% lower retail customer volumes, primarily due to the unfavorable impact of weather in the first quarter.

MidAmerican Funding -

MidAmerican Funding's net income for the second quarter of 2020 was $208 million, an increase of $55 million, or 36%, compared to 2019. MidAmerican Funding's net income for the first six months of 2020 was $358 million, an increase of $15 million, or 4%, 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.

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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):

		Second Quarter														First Six Months
		2020				2019				Change						2020				2019				Change
Electric utility margin:
Operating revenue		$	518			$	538			$	(20	)	(4	)%		$	989			$	1,080			$	(91	)	(8	)%
Cost of fuel and energy		71				91				(20		)	(22	)		151				205				(54		)	(26	)
Electric utility margin		447				447				—			—	%		838				875				(37		)	(4	)%
Natural gas utility margin:
Operating revenue		95				111				(16		)	(14	)%		304				406				(102		)	(25	)%
Natural gas purchased for resale		42				55				(13		)	(24	)		170				248				(78		)	(31	)
Natural gas utility margin		53				56				(3		)	(5	)%		134				158				(24		)	(15	)%
Utility margin		500				503				(3		)	(1	)%		972				1,033				(61		)	(6	)%
Other operating revenue		—				10				(10		)	*			1				15				(14		)	(93	)%
Other cost of sales		—				7				(7		)	*			—				9				(9		)	*
Operations and maintenance		182				204				(22		)	(11	)		347				411				(64		)	(16	)
Depreciation and amortization		175				179				(4		)	(2	)		351				356				(5		)	(1	)
Property and other taxes		35				29				6			21			69				63				6			10
Operating income		$	108			$	94			$	14		15	%		$	206			$	209			$	(3	)	(1	)%

*    Not meaningful.

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Electric Utility Margin

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

	Second Quarter															First Six Months
	2020				2019				Change							2020				2019				Change
Utility margin (in millions):
Operating revenue	$	518			$	538			$	(20	)		(4	)%		$	989			$	1,080			$	(91	)		(8	)%
Cost of fuel and energy	71				91				(20		)		(22	)		151				205				(54		)		(26	)
Utility margin	$	447			$	447			$	—			—	%		$	838			$	875			$	(37	)		(4	)%
Sales (GWhs):
Residential	1,505				1,270				235				19	%		3,173				3,155				18				1	%
Commercial	818				853				(35		)		(4	)		1,787				1,893				(106		)		(6	)
Industrial	3,602				3,644				(42		)		(1	)		7,126				6,915				211				3
Other	334				381				(47		)		(12	)		719				780				(61		)		(8	)
Total retail	6,259				6,148				111				2			12,805				12,743				62				—
Wholesale	2,560				2,328				232				10			4,994				5,604				(610		)		(11	)
Total sales	8,819				8,476				343				4	%		17,799				18,347				(548		)		(3	)%
Average number of retail customers (in thousands)	794				785				9				1	%		793				785				8				1	%
Average revenue per MWh:
Retail	$	74.77			$	76.02			$	(1.25	)		(2	)%		$	68.63			$	71.46			$	(2.83	)		(4	)%
Wholesale	$	10.64			$	21.88			$	(11.24	)		(51	)%		$	13.11			$	22.75			$	(9.64	)		(42	)%
Heating degree days	650				605				45				7	%		3,602				4,206				(604		)		(14	)%
Cooling degree days	360				280				80				29	%		360				280				80				29	%
Sources of energy (GWhs)(1):
Coal	1,029				2,434				(1,405		)		(58	)%		2,602				6,337				(3,735		)		(59	)%
Nuclear	909				968				(59		)		(6	)		1,902				1,884				18				1
Natural gas	77				46				31				67			193				64				129				*
Wind and other(2)	5,148				3,954				1,194				30			9,994				8,298				1,696				20
Total energy generated	7,163				7,402				(239		)		(3	)		14,691				16,583				(1,892		)		(11	)
Energy purchased	1,783				1,197				586				49			3,426				2,046				1,380				67
Total	8,946				8,599				347				4	%		18,117				18,629				(512		)		(3	)%
Average cost of energy per MWh:
Energy generated(3)	$	3.87			$	6.75			$	(2.88	)		(43	)%		$	4.45			$	7.75			$	(3.30	)		(43	)%
Energy purchased	$	24.50			$	33.92			$	(9.42	)		(28	)%		$	25.02			$	37.41			$	(12.39	)		(33	)%

*    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.

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Electric utility margin was unchanged for the second quarter of 2020 compared to 2019, reflecting:

(1)	Higher retail utility margin of $10 million primarily due to -

•	an increase of $12 million from the favorable impact of weather;

•	an increase of $2 million from price impacts from changes in sales mix and non-weather-related factors, 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; and

•

a decrease of $5 million from lower recoveries through bill riders, net of energy costs, due to a decrease of $14 million in electric energy efficiency program revenue (offset in operations and maintenance expense), partially offset by higher recoveries related to the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit) and transmission costs (offset in operations and maintenance expense);

(2)	Higher Multi-Value Projects ("MVP") transmission revenue of $3 million; and

(3)	Lower wholesale utility margin of $13 million due to lower margins per unit, reflecting lower market prices, net of lower energy costs, partially offset by higher sales volumes of 10.0%.

Electric utility margin decreased $37 million for the first six months of 2020 compared to 2019 primarily due to:

(1)	Lower wholesale utility margin of $23 million due to lower margins per unit, from lower market prices, partially offset by lower energy costs, and lower sales volumes of 10.9%;

(2)	Lower retail utility margin of $16 million primarily due to -

•

a decrease of $19 million from lower recoveries through bill riders, net of energy costs, primarily due to a decrease of $33 million in electric energy efficiency program revenue (offset in operations and maintenance expense), partially offset by recoveries related to the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit) and transmission costs (offset in operations and maintenance expense);

•	a decrease of $14 million from price impacts from changes in sales mix;

•	an increase of $16 million from non-weather-related factors, 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; and

•	an increase of $2 million from the favorable impact of weather; and

(3)	Higher MVP transmission revenue of $2 million.

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Natural Gas Utility Margin

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

	Second Quarter															First Six Months
	2020				2019				Change							2020				2019				Change
Utility margin (in millions):
Operating revenue	$	95			$	111			$	(16	)		(14)	%		$	304			$	406			$	(102	)		(25)	%
Natural gas purchased for resale	42				55				(13		)		(24	)		170				248				(78		)		(31	)
Utility margin	$	53			$	56			$	(3	)		(5)	%		$	134			$	158			$	(24	)		(15)	%
Throughput (000's Dths):
Residential	7,046				6,928				118				2	%		30,956				35,497				(4,541		)		(13)	%
Commercial	3,012				3,297				(285		)		(9	)		13,963				16,581				(2,618		)		(16	)
Industrial	1,070				949				121				13			2,582				2,495				87				3
Other	13				13				—				—			48				48				—				—
Total retail sales	11,141				11,187				(46		)		—			47,549				54,621				(7,072		)		(13	)
Wholesale sales	5,859				7,050				(1,191		)		(17	)		18,769				18,605				164				1
Total sales	17,000				18,237				(1,237		)		(7	)		66,318				73,226				(6,908		)		(9	)
Natural gas transportation service	22,165				23,824				(1,659		)		(7	)		57,119				54,367				2,752				5
Total throughput	39,165				42,061				(2,896		)		(7)	%		123,437				127,593				(4,156		)		(3)	%
Average number of retail customers (in thousands)	770				761				9				1	%		770				762				8				1	%
Average revenue per retail Dth sold	$	6.97			$	7.89			$	(0.92	)		(12)	%		$	5.34			$	6.16			$	(0.82	)		(13)	%
Heating degree days	710				663				47				7	%		3,777				4,389				(612		)		(14)	%
Average cost of natural gas per retail Dth sold	$	2.96			$	3.56			$	(0.60	)		(17)	%		$	2.92			$	3.63			$	(0.71	)		(20)	%
Combined retail and wholesale average cost of natural gas per Dth sold	$	2.49			$	3.01			$	(0.52	)		(17)	%		$	2.57			$	3.38			$	(0.81	)		(24)	%

Natural gas utility margin decreased $3 million for the second quarter of 2020 compared to 2019 primarily due to:

(1)	A decrease of $6 million from lower natural gas energy efficiency program revenue (offset in operations and maintenance expense);

(2)	An increase of $1 million from the favorable impact of weather; and

(3)	An increase of $1 million from rider recoveries related to the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit).

Natural gas utility margin decreased $24 million for the first six months of 2020 compared to 2019 primarily due to:

(1)	A decrease of $16 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; and

(3)	A decrease of $2 million from non-weather rate and usage variances, in part due to sales mix; and

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

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Operating Expenses

MidAmerican Energy -

Operations and maintenance decreased $22 million for the second quarter of 2020 compared to 2019 primarily due to lower energy efficiency program expense of $18 million (offset in operating revenue), lower electric and natural gas distribution expenses of $9 million and lower fossil-fueled generating facility maintenance of $8 million, partially offset by higher wind-powered generation operations and maintenance of $8 million due to additional and repowered wind turbines and easements.

Operations and maintenance decreased $64 million for the first six months of 2020 compared to 2019 primarily due to lower energy efficiency program expense of $47 million (offset in operating revenue), lower electric and natural gas distribution expenses of $13 million, lower fossil-fueled generating facility maintenance of $10 million, a nuclear property insurance premium refund of $5 million and lower nonregulated operations expenses of $5 million, partially offset by higher wind-powered generation operations and maintenance of $16 million due to additional wind turbines and easements and higher transmission operations costs from the Midcontinent Independent System Operator, Inc. of $4 million (offset in operating revenue).

Depreciation and amortization for the second quarter and first six months of 2020 decreased $4 million and $5 million, respectively, compared to 2019 primarily due to lower Iowa revenue sharing accruals of $27 million and $54 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 $6 million for the second quarter and first six months, respectively, of 2020 compared to 2019 due to higher retail sales and wind-powered generating facility increases.

Other Income (Expense)

MidAmerican Energy -

Interest expense increased $4 million and $11 million for the second quarter and first six months, respectively, of 2020 compared to 2019 due to higher average long-term debt balances.

Allowance for borrowed and equity funds decreased $11 million and $21 million for the second quarter and first six months, respectively, of 2020 compared to 2019 primarily due to lower construction work-in-progress balances related to wind-powered generation.

Other, net increased $11 million for the second quarter of 2020 compared to 2019 primarily due to higher cash surrender values of corporate-owned life insurance policies of $8 million and lower non-service costs of postretirement employee benefit plans.

Other, net decreased $14 million for the first six months of 2020 compared to 2019 primarily due to lower cash surrender values of corporate-owned life insurance policies of $13 million and lower interest income of $5 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 $43 million for the second quarter of 2020 compared to 2019, and the effective tax rate was (207)% for 2020 and (169)% for 2019. For the first six months of 2020 compared to 2019, MidAmerican Energy's income tax benefit increased $60 million, and the effective tax rate was (275)% for 2020 and (141)% for 2019. The change in the effective tax rates for 2020 compared to 2019 was due to the higher PTCs, state income tax and, for the first six-months' comparison, a lower pretax income in 2020, partially offset by the effects of ratemaking.

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 six-month periods ended June 30, 2020 and 2019 totaled $247 million and $190 million, respectively.

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MidAmerican Funding -

MidAmerican Funding's income tax benefit increased $43 million for the second quarter of 2020 compared to 2019, and the effective tax rate was (215)% for 2020 and (183)% for 2019. For the first six months of 2020 compared to 2019, MidAmerican Funding's income tax benefit increased $60 million, and the effective tax rate was (289)% for 2020 and (150)% 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 June 30, 2020, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):

MidAmerican Energy:
Cash and cash equivalents		$	5
Credit facilities, maturing 2021 and 2022		1,505
Less:
Short-term debt outstanding		(195		)
Tax-exempt bond support		(370		)
Net credit facilities		940
MidAmerican Energy total net liquidity		$	945
MidAmerican Funding:
MidAmerican Energy total net liquidity		$	945
Cash and cash equivalents		3
MHC, Inc. credit facility, maturing 2021		4
MidAmerican Funding total net liquidity		$	952

Operating Activities

MidAmerican Energy's net cash flows from operating activities for the six-month periods ended June 30, 2020 and 2019, were $326 million and $463 million, respectively. MidAmerican Funding's net cash flows from operating activities for the six-month periods ended June 30, 2020 and 2019, were $323 million and $454 million, respectively. Cash flows from operating activities decreased primarily due to 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 and higher settlement payments for asset retirement obligations, partially offset by lower 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 six-month periods ended June 30, 2020 and 2019, were $(818) million and $(1,008) million, respectively. MidAmerican Funding's net cash flows from investing activities for the six-month periods ended June 30, 2020 and 2019, were $(817) million and $(1,008) 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.

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Financing Activities

MidAmerican Energy's net cash flows from financing activities for the six-month periods ended June 30, 2020 and 2019 were $194 million and $720 million, respectively. MidAmerican Funding's net cash flows from financing activities for the six-month periods ended June 30, 2020 and 2019, were $198 million and $729 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 received $195 million in 2020 and paid $240 million in 2019. MidAmerican Funding received $4 million and $10 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, and preferred stock up to an aggregate of $500 million through November 1, 2020.

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.

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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):

	Six-Month Periods								Annual
	Ended June 30,								Forecast
	2019				2020				2020
Wind-powered generation under ratemaking principles	$	473			$	165			$	390
Renewable generation not under ratemaking principles	—				225				457
Wind-powered generation repowering	118				19				157
Other	426				415				983
Total	$	1,017			$	824			$	1,987

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 202 MWs placed in-service as of June 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 six-month period ended June 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 June 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 June 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.

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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 June 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 June 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 June 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.

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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 proposes 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 it submitted on June 1, 2020. On May 21, 2020, the FERC issued an order involving reforms to the PJM's day-ahead and real-time reserves markets and directing the PJM to submit no later than August 5, 2020, a new methodology for estimating revenues that resources will receive for sales of energy and related services, which could impact MOPR levels. The FERC has no deadline for acting on the compliance filings and could accept, reject or direct further revisions to all or part of the PJM's proposed tariff revisions, auction schedule and revenue projection methodology. The PJM cannot resume activities related to its capacity auctions until the FERC acts on these compliance filings.

Exelon Generation is currently working with the PJM and other stakeholders to pursue the FRR option prior to the next capacity auction in the PJM. 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 such legislative and regulatory changes can be implemented prior to the next capacity auction in the PJM 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.

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.

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Nevada Power Company and its subsidiaries

Consolidated Financial Section

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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 June 30, 2020, the related consolidated statements of operations and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2020 and 2019, and of cash flows for the six-month periods ended June 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

August 7, 2020

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NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)

	As of
	June 30,				December 31,
	2020				2019
ASSETS
Current assets:
Cash and cash equivalents	$	16			$	15
Trade receivables, net	281				215
Inventories	60				62
Prepayments	53				42
Other current assets	27				30
Total current assets	437				364
Property, plant and equipment, net	6,649				6,538
Finance lease right of use assets, net	433				441
Regulatory assets	812				800
Other assets	64				59
Total assets	$	8,395			$	8,202
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	187			$	194
Accrued interest	33				30
Accrued property, income and other taxes	47				25
Current portion of long-term debt	—				575
Regulatory liabilities	93				93
Customer deposits	50				62
Derivative contracts	37				5
Other current liabilities	66				53
Total current liabilities	513				1,037
Long-term debt	2,495				1,776
Finance lease obligations	426				430
Regulatory liabilities	1,176				1,163
Deferred income taxes	708				714
Other long-term liabilities	285				285
Total liabilities	5,603				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	488				493
Accumulated other comprehensive loss, net	(4		)		(4		)
Total shareholder's equity	2,792				2,797
Total liabilities and shareholder's equity	$	8,395			$	8,202
The accompanying notes are an integral part of the consolidated financial statements.

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CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Operating revenue	$	509			$	527			$	898			$	922
Operating expenses:
Cost of fuel and energy	197				226				367				399
Operations and maintenance	74				78				156				154
Depreciation and amortization	91				89				181				178
Property and other taxes	11				11				23				23
Total operating expenses	373				404				727				754
Operating income	136				123				171				168
Other income (expense):
Interest expense	(40		)		(41		)		(82		)		(88		)
Allowance for borrowed funds	1				—				2				1
Allowance for equity funds	2				1				4				2
Other, net	7				5				6				13
Total other income (expense)	(30		)		(35		)		(70		)		(72		)
Income before income tax expense	106				88				101				96
Income tax expense	23				19				22				21
Net income	$	83			$	69			$	79			$	75
The accompanying notes are an integral part of these consolidated financial statements.

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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, March 31, 2019		1,000			$	—			$	2,308			$	531			$	(4	)		$	2,835
Net income		—			—				—				69				—				69
Dividends declared		—			—				—				(20		)		—				(20		)
Balance, June 30, 2019		1,000			$	—			$	2,308			$	580			$	(4	)		$	2,884
Balance, December 31, 2018		1,000			$	—			$	2,308			$	600			$	(4	)		$	2,904
Net income		—			—				—				75				—				75
Dividends declared		—			—				—				(95		)		—				(95		)
Balance, June 30, 2019		1,000			$	—			$	2,308			$	580			$	(4	)		$	2,884
Balance, March 31, 2020		1,000			$	—			$	2,308			$	490			$	(4	)		$	2,794
Net income		—			—				—				83				—				83
Dividends declared		—			—				—				(85		)		—				(85		)
Balance, June 30, 2020		1,000			$	—			$	2,308			$	488			$	(4	)		$	2,792
Balance, December 31, 2019		1,000			$	—			$	2,308			$	493			$	(4	)		$	2,797
Net income		—			—				—				79				—				79
Dividends declared		—			—				—				(85		)		—				(85		)
Other equity transactions		—			—				—				1				—				1
Balance, June 30, 2020		1,000			$	—			$	2,308			$	488			$	(4	)		$	2,792
The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2020				2019
Cash flows from operating activities:
Net income	$	79			$	75
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	181				178
Allowance for equity funds	(4		)		(2		)
Changes in regulatory assets and liabilities	1				3
Deferred income taxes and amortization of investment tax credits	(7		)		(9		)
Deferred energy	15				13
Amortization of deferred energy	(11		)		12
Other, net	6				(6		)
Changes in other operating assets and liabilities:
Trade receivables and other assets	(80		)		(47		)
Inventories	2				(3		)
Accrued property, income and other taxes	28				21
Accounts payable and other liabilities	(3		)		30
Net cash flows from operating activities	207				265
Cash flows from investing activities:
Capital expenditures	(257		)		(191		)
Other, net	—				2
Net cash flows from investing activities	(257		)		(189		)
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	(8		)		(7		)
Net cash flows from financing activities	50				(107		)
Net change in cash and cash equivalents and restricted cash and cash equivalents	—				(31		)
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	$	25			$	90
The accompanying notes are an integral part of these consolidated financial statements.

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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 June 30, 2020 and for the three- and six-month periods ended June 30, 2020 and 2019. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and six-month periods ended June 30, 2020 and 2019. The results of operations for the three- and six-month periods ended June 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 six-month period ended June 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 June 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 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.

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(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 June 30, 2020 and December 31, 2019, consist of funds restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of June 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
	June 30,				December 31,
	2020				2019
Cash and cash equivalents	$	16			$	15
Restricted cash and cash equivalents included in other current assets	9				10
Total cash and cash equivalents and restricted cash and cash equivalents	$	25			$	25

(3)	Property, Plant and Equipment, Net

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

			As of
	Depreciable Life		June 30,				December 31,
			2020				2019
Utility plant:
Generation	30 - 55 years		$	3,617			$	3,541
Transmission	45 - 70 years		1,485				1,444
Distribution	20 - 65 years		3,683				3,567
General and intangible plant	5 - 65 years		786				741
Utility plant			9,571				9,293
Accumulated depreciation and amortization			(3,079		)		(2,951		)
Utility plant, net			6,492				6,342
Other non-regulated, net of accumulated depreciation and amortization	45 years		1				1
Plant, net			6,493				6,343
Construction work-in-progress			156				195
Property, plant and equipment, net			$	6,649			$	6,538

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(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.

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.

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 is expected in late August 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.

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(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
	June 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.

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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 June 30, 2020
Assets:
Money market mutual funds(1)	$	8			$	—			$	—			$	8
Investment funds	2				—				—				2
	$	10			$	—			$	—			$	10
Liabilities - commodity derivatives	$	—			$	—			$	(44	)		$	(44	)
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 June 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 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.

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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								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Beginning balance	$	(38	)		(5		)		$	(8	)		$	3
Changes in fair value recognized in regulatory assets	(13		)		(8		)		(44		)		(17		)
Settlements	7				2				8				3
Ending balance	$	(44	)		$	(11	)		$	(44	)		$	(11	)

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 June 30, 2020								As of December 31, 2019
	Carrying				Fair				Carrying				Fair
	Value				Value				Value				Value
Long-term debt	$	2,495			$	3,187			$	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 ("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. Nevada Power believes it is in material compliance with all applicable laws and regulations.

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(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								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Customer Revenue:
Retail:
Residential	$	304			$	266			$	497			$	466
Commercial	96				114				190				204
Industrial	83				112				154				182
Other	2				6				5				11
Total fully bundled	485				498				846				863
Distribution only service	6				8				13				15
Total retail	491				506				859				878
Wholesale, transmission and other	12				14				27				31
Total Customer Revenue	503				520				886				909
Other revenue	6				7				12				13
Total revenue	$	509			$	527			$	898			$	922

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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 Second Quarter and First Six Months of 2020 and 2019

Overview

Net income for the second quarter of 2020 was $83 million, an increase of $14 million, or 20%, compared to 2019 primarily due to $11 million of higher utility margin and $5 million of favorable other income (expense), primarily due to lower pension costs of $2 million and higher cash surrender value of corporate-owned life insurance policies of $2 million, partially offset by $4 million of higher income tax expense due to higher pre-tax income.

Net income for the first six months of 2020 was $79 million, an increase of $4 million, or 5%, compared to 2019 primarily due to $8 million of higher utility margin, partially offset by $3 million of higher depreciation and amortization, primarily due to higher plant placed in service.

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):

		Second Quarter														First Six Months
		2020				2019				Change						2020				2019				Change
Utility margin:
Operating revenue		$	509			$	527			$	(18	)	(3	)%		$	898			$	922			$	(24	)	(3	)%
Cost of fuel and energy		197				226				(29		)	(13	)		367				399				(32		)	(8	)
Utility margin		312				301				11			4			531				523				8			2
Operations and maintenance		74				78				(4		)	(5	)		156				154				2			1
Depreciation and amortization		91				89				2			2			181				178				3			2
Property and other taxes		11				11				—			—			23				23				—			—
Operating income		$	136			$	123			$	13		11	%		$	171			$	168			$	3		2	%

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

		Second Quarter														First Six Months
		2020				2019				Change						2020				2019				Change
Utility margin (in millions):
Operating revenue		$	509			$	527			$	(18	)	(3	)%		$	898			$	922			$	(24	)	(3	)%
Cost of fuel and energy		197				226				(29		)	(13	)		367				399				(32		)	(8	)
Utility margin		$	312			$	301			$	11		4	%		$	531			$	523			$	8		2	%
Sales (GWhs):
Residential		2,635				2,176				459			21	%		4,179				3,784				395			10	%
Commercial		1,071				1,137				(66		)	(6	)		2,082				2,129				(47		)	(2	)
Industrial		1,107				1,380				(273		)	(20	)		2,258				2,540				(282		)	(11	)
Other		46				47				(1		)	(2	)		94				94				—			—
Total fully bundled(1)		4,859				4,740				119			3			8,613				8,547				66			1
Distribution only service		501				692				(191		)	(28	)		1,112				1,220				(108		)	(9	)
Total retail		5,360				5,432				(72		)	(1	)		9,725				9,767				(42		)	—
Wholesale		81				120				(39		)	(33	)		234				264				(30		)	(11	)
Total GWhs sold		5,441				5,552				(111		)	(2	)%		9,959				10,031				(72		)	(1	)%
Average number of retail customers (in thousands)		965				950				15			2	%		963				948				15			2	%
Average revenue per MWh:
Retail - fully bundled(1)		$	99.89			$	105.05			$	(5.16	)	(5	)%		$	98.20			$	100.96			$	(2.76	)	(3	)%
Wholesale		$	22.07			$	27.27			$	(5.20	)	(19	)%		$	28.29			$	35.45			$	(7.16	)	(20	)%
Heating degree days		42				25				17			68	%		984				1,108				(124		)	(11	)%
Cooling degree days		1,308				1,107				201			18	%		1,310				1,119				191			17	%
Sources of energy (GWhs)(2)(3):
Natural gas		3,118				3,085				33			1	%		5,740				5,254				486			9	%
Coal		—				249				(249		)	*			—				591				(591		)	*
Renewables		20				18				2			11			36				30				6			20
Total energy generated		3,138				3,352				(214		)	(6	)		5,776				5,875				(99		)	(2	)
Energy purchased		1,926				1,696				230			14			3,166				3,171				(5		)	—
Total		5,064				5,048				16			—	%		8,942				9,046				(104		)	(1	)%
Average total cost of energy per MWh(4)		$	38.93			$	44.92			$	(5.99	)	(13	)%		$	41.08			$	44.21			$	(3.13	)	(7	)%

*    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 37 GWhs of coal and 318 GWhs and 426 GWhs of gas generated energy that is purchased at cost by related parties for the second quarter of 2020 and 2019, respectively. The average total cost of energy per MWh and sources of energy excludes - GWhs and 118 GWhs of coal and 1,028 GWhs and 923 GWhs of gas generated energy that is purchased at cost by related parties for the first six 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.

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Utility margin increased $11 million, or 4%, for the second quarter of 2020 compared to 2019 primarily due to:

•

$12 million due to price impacts from changes in sales mix, partially offset by lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 1.3%, primarily due to the impacts of COVID-19, which resulted in lower industrial, distribution only service and commercial customer usage and higher residential customer usage, partially offset by the favorable impact of weather and

•	$5 million due to higher energy efficiency program rates (offset in operations and maintenance expense).

The increase in utility margin was offset by:

•	$4 million of lower wholesale revenue and

•	$2 million of higher revenue reductions related to customer service agreements.

Operations and maintenance decreased $4 million, or 5%, for the second quarter of 2020 compared to 2019 primarily due to lower plant operation and maintenance costs of $8 million and a lower accrual for earnings sharing of $5 million, partially offset by higher energy efficiency program costs (offset in operating revenue) of $5 million and higher regulatory-directed debits relating to the deferral of costs for the ON Line lease to be returned to customers (offset in other income (expense)) of $3 million.

Depreciation and amortization increased $2 million, or 2%, for the second quarter of 2020 compared to 2019 primarily due to higher plant placed in service.

Other income (expense) is favorable $5 million, or 14%, for the second quarter of 2020 compared to 2019 primarily due to lower interest 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) of $3 million, lower pension costs of $2 million and higher cash surrender value of corporate-owned life insurance policies of $2 million.

Income tax expense increased $4 million, or 21%, for the second quarter of 2020 compared to 2019 due to higher pre-tax income. The effective tax rate was 22% in 2020 and 21% in 2019.

Utility margin increased $8 million, or 2%, for the first six months of 2020 compared to 2019 primarily due to:

•

$9 million due to price impacts from changes in sales mix, partially offset by lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 0.4%, primarily due to the impacts of COVID-19, which resulted in lower industrial and distribution only service customer usage and higher residential customer usage, partially offset by the favorable impact of weather and

•	$5 million due to higher energy efficiency program rates (offset in operations and maintenance expense).

The increase in utility margin was offset by:

•	$4 million of higher revenue reductions related to customer service agreements and

•	$2 million of lower wholesale revenue.

Operations and maintenance increased $2 million, or 1%, for the first six months of 2020 compared to 2019 primarily due to higher regulatory-directed debits relating to the deferral of the non-labor cost saving from the Navajo generating station retirement in 2019 of $6 million, higher regulatory-directed debits relating to the deferral of costs for the ON Line lease to be returned to customers (offset in other income (expense)) of $5 million and higher energy efficiency program costs (offset in operating revenue) of $5 million, partially offset by lower plant operation and maintenance costs of $8 million and a lower accrual for earnings sharing of $6 million.

Depreciation and amortization increased $3 million, or 2%, for the first six months of 2020 compared to 2019 primarily due to higher plant placed in service.

Other income (expense) is favorable $2 million, or 3%, for the first six months of 2020 compared to 2019 primarily due to lower interest 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) of $4 million, lower interest expense on long-term debt of $3 million due to lower interest rates and lower pension costs of $2 million, offset by lower cash surrender value of corporate-owned life insurance policies of $5 million and lower other income due to a licensing agreement with a third party in 2019 of $2 million.

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Income tax expense increased $1 million, or 5%, for the first six months of 2020 compared to 2019 due to higher pre-tax income. The effective tax rate was 22% in 2020 and 21% in 2019.

Liquidity and Capital Resources

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

Cash and cash equivalents		$	16
Credit facility		400
Total net liquidity		$	416
Credit facility:
Maturity date		2022

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2020 and 2019 were $207 million and $265 million, respectively. The change was primarily due to decreased collections of customer advances, lower collections from customers, the timing of payments for operating costs, higher payments for generation long-term service agreements and lower proceeds from a licensing agreement with a third party in 2019, partially offset by 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 six-month periods ended June 30, 2020 and 2019 were $(257) million and $(189) million, respectively. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the six-month periods ended June 30, 2020 and 2019 were $50 million and $(107) 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.

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.

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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):

	Six-Month Periods								Annual
	Ended June 30,								Forecast
	2019				2020				2020
Generation development	$	—			$	14			$	20
Distribution	96				128				194
Transmission system investment	10				11				23
Other	85				104				207
Total	$	191			$	257			$	444

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 June 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.

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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 June 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 consumption due to COVID-19 through June 2020 compared to the same period in 2019. The state of Nevada has since moved to the second phase of its recovery plan with most businesses, including casinos, 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 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 June 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.

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.

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Sierra Pacific Power Company

Financial Section

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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 June 30, 2020, the related statements of operations and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2020 and 2019, and of cash flows for the six-month periods ended June 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

August 7, 2020

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SIERRA PACIFIC POWER COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)

	As of
	June 30,				December 31,
	2020				2019
ASSETS
Current assets:
Cash and cash equivalents	$	12			$	27
Trade receivables, net	87				109
Income taxes receivable	4				14
Inventories	76				57
Regulatory assets	32				12
Other current assets	23				20
Total current assets	234				239
Property, plant and equipment, net	3,099				3,075
Regulatory assets	298				283
Other assets	80				74
Total assets	$	3,711			$	3,671
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	119			$	103
Accrued interest	14				14
Accrued property, income and other taxes	11				12
Regulatory liabilities	69				49
Customer deposits	17				21
Other current liabilities	34				21
Total current liabilities	264				220
Long-term debt	1,135				1,135
Regulatory liabilities	460				489
Deferred income taxes	349				347
Other long-term liabilities	165				160
Total liabilities	2,373				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	228				210
Accumulated other comprehensive loss, net	(1		)		(1		)
Total shareholder's equity	1,338				1,320
Total liabilities and shareholder's equity	$	3,711			$	3,671
The accompanying notes are an integral part of the financial statements.

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SIERRA PACIFIC POWER COMPANY

STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Operating revenue:
Regulated electric	$	165			$	172			$	349			$	354
Regulated natural gas	20				22				68				59
Total operating revenue	185				194				417				413
Operating expenses:
Cost of fuel and energy	72				79				152				161
Cost of natural gas purchased for resale	10				10				40				29
Operations and maintenance	41				40				83				84
Depreciation and amortization	34				32				68				63
Property and other taxes	5				6				11				12
Total operating expenses	162				167				354				349
Operating income	23				27				63				64
Other income (expense):
Interest expense	(14		)		(12		)		(28		)		(24		)
Allowance for borrowed funds	1				1				1				1
Allowance for equity funds	1				1				2				2
Other, net	3				1				4				3
Total other income (expense)	(9		)		(9		)		(21		)		(18		)
Income before income tax expense	14				18				42				46
Income tax expense	1				4				4				10
Net income	$	13			$	14			$	38			$	36
The accompanying notes are an integral part of these financial statements.

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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, March 31, 2019		1,000			$	—			$	1,111			$	175			$	—			$	1,286
Net income		—			—				—				14				—				14
Dividends declared		—			—				—				(46		)		—				(46		)
Balance, June 30, 2019		1,000			$	—			$	1,111			$	143			$	—			$	1,254
Balance, December 31, 2018		1,000			$	—			$	1,111			$	153			$	—			$	1,264
Net income		—			—				—				36				—				36
Dividends declared		—			—				—				(46		)		—				(46		)
Balance, June 30, 2019		1,000			$	—			$	1,111			$	143			$	—			$	1,254
Balance, March 31, 2020		1,000			$	—			$	1,111			$	235			$	(1	)		$	1,345
Net income		—			—				—				13				—				13
Dividends declared		—			—				—				(20		)		—				(20		)
Balance, June 30, 2020		1,000			$	—			$	1,111			$	228			$	(1	)		$	1,338
Balance, December 31, 2019		1,000			$	—			$	1,111			$	210			$	(1	)		$	1,320
Net income		—			—				—				38				—				38
Dividends declared		—			—				—				(20		)		—				(20		)
Balance, June 30, 2020		1,000			$	—			$	1,111			$	228			$	(1	)		$	1,338
The accompanying notes are an integral part of these financial statements.

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SIERRA PACIFIC POWER COMPANY

STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2020				2019
Cash flows from operating activities:
Net income	$	38			$	36
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	68				63
Allowance for equity funds	(2		)		(1		)
Changes in regulatory assets and liabilities	(24		)		20
Deferred income taxes and amortization of investment tax credits	(6		)		2
Deferred energy	21				(13		)
Amortization of deferred energy	1				(6		)
Other, net	1				(1		)
Changes in other operating assets and liabilities:
Trade receivables and other assets	11				12
Inventories	(19		)		(8		)
Accrued property, income and other taxes	10				7
Accounts payable and other liabilities	18				(23		)
Net cash flows from operating activities	117				88
Cash flows from investing activities:
Capital expenditures	(110		)		(99		)
Net cash flows from investing activities	(110		)		(99		)
Cash flows from financing activities:
Proceeds from long-term debt	—				125
Repayments of long-term debt	—				(109		)
Dividends paid	(20		)		(46		)
Other, net	(2		)		(2		)
Net cash flows from financing activities	(22		)		(32		)
Net change in cash and cash equivalents and restricted cash and cash equivalents	(15		)		(43		)
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	$	17			$	33
The accompanying notes are an integral part of these financial statements.

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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 June 30, 2020 and for the three- and six-month periods ended June 30, 2020 and 2019. The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and six-month periods ended June 30, 2020 and 2019. The results of operations for the three- and six-month periods ended June 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 six-month period ended June 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 June 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 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.

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(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 June 30, 2020 and December 31, 2019, consist of funds restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of June 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
	June 30,				December 31,
	2020				2019
Cash and cash equivalents	$	12			$	27
Restricted cash and cash equivalents included in other current assets	5				5
Total cash and cash equivalents and restricted cash and cash equivalents	$	17			$	32

(3)	Property, Plant and Equipment, Net

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

			As of
	Depreciable Life		June 30,				December 31,
			2020				2019
Utility plant:
Electric generation	25 - 60 years		$	1,130			$	1,133
Electric transmission	50 - 100 years		879				840
Electric distribution	20 - 100 years		1,700				1,669
Electric general and intangible plant	5 - 70 years		184				178
Natural gas distribution	35 - 70 years		422				417
Natural gas general and intangible plant	5 - 70 years		14				14
Common general	5 - 70 years		344				338
Utility plant			4,673				4,589
Accumulated depreciation and amortization			(1,699		)		(1,629		)
Utility plant, net			2,974				2,960
Other non-regulated, net of accumulated depreciation and amortization	70 years		2				2
Plant, net			2,976				2,962
Construction work-in-progress			123				113
Property, plant and equipment, net			$	3,099			$	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.

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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 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.

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.

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 is expected in late August 2020.

(5)	Recent Financing Transactions

Long-Term Debt

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 these bonds and they could be issued at a future date if deemed necessary.

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(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						Six-Month Periods
	Ended June 30,						Ended June 30,
	2020			2019			2020			2019
Federal statutory income tax rate	21	%		21	%		21	%		21	%
Effects of ratemaking	(14	)		1			(10	)		1
Other	—			—			(1	)		—
Effective income tax rate	7	%		22	%		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
	June 30,				December 31,
	2020				2019
Qualified Pension Plan:
Other long-term liabilities	$	3			$	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

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(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 June 30, 2020
Assets:
Money market mutual funds(1)	$	9			$	—			$	—			$	9
Investment funds	1				—				—				1
	$	10			$	—			$	—			$	10
Liabilities - commodity derivatives	$	—			$	—			$	(12	)		$	(12	)
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 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.

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 June 30, 2020								As of December 31, 2019
	Carrying				Fair				Carrying				Fair
	Value				Value				Value				Value
Long-term debt	$	1,135			$	1,324			$	1,135			$	1,258

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(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 ("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. 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 June 30,
	2020												2019
	Electric				Natural Gas				Total				Electric				Natural Gas				Total
Customer Revenue:
Retail:
Residential	$	63			$	14			$	77			$	58			$	14			$	72
Commercial	56				4				60				54				5				59
Industrial	34				2				36				46				2				48
Other	1				—				1				1				—				1
Total fully bundled	154				20				174				159				21				180
Distribution only service	1				—				1				1				—				1
Total retail	155				20				175				160				21				181
Wholesale, transmission and other	9				—				9				11				—				11
Total Customer Revenue	164				20				184				171				21				192
Other revenue	1				—				1				1				1				2
Total revenue	$	165			$	20			$	185			$	172			$	22			$	194

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	Six-Month Periods
	Ended June 30,
	2020												2019
	Electric				Gas				Total				Electric				Gas				Total
Customer Revenue:
Retail:
Residential	$	132			$	44			$	176			$	126			$	38			$	164
Commercial	112				17				129				108				15				123
Industrial	75				6				81				85				5				90
Other	2				—				2				3				—				3
Total fully bundled	321				67				388				322				58				380
Distribution only service	2				—				2				2				—				2
Total retail	323				67				390				324				58				382
Wholesale, transmission and other	24				—				24				28				—				28
Total Customer Revenue	347				67				414				352				58				410
Other revenue	2				1				3				2				1				3
Total revenue	$	349			$	68			$	417			$	354			$	59			$	413

(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								Six-Month Periods
	Ended June 30,								Ended June 30,
	2020				2019				2020				2019
Operating revenue:
Regulated electric	$	165			$	172			$	349			$	354
Regulated natural gas	20				22				68				59
Total operating revenue	$	185			$	194			$	417			$	413
Operating income:
Regulated electric	$	20			$	23			$	53			$	52
Regulated natural gas	3				4				10				12
Total operating income	23				27				63				64
Interest expense	(14		)		(12		)		(28		)		(24		)
Allowance for borrowed funds	1				1				1				1
Allowance for equity funds	1				1				2				2
Other, net	3				1				4				3
Income before income tax expense	$	14			$	18			$	42			$	46

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	As of
	June 30,				December 31,
	2020				2019
Assets:
Regulated electric	$	3,375			$	3,319
Regulated natural gas	309				308
Other(1)	27				44
Total assets	$	3,711			$	3,671

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

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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 Second Quarter and First Six Months of 2020 and 2019

Overview

Net income for the second quarter of 2020 was $13 million, a decrease of $1 million, or 7%, compared to 2019 primarily due to $2 million of lower natural gas utility margin, primarily due to lower customer volumes, and $2 million of higher depreciation and amortization mainly due to higher plant in service, partially offset by $3 million of lower income tax expense.

Net income for the first six months of 2020 was $38 million, an increase of $2 million, or 6%, compared to 2019 primarily due to $6 million of lower income tax expense and $4 million of higher electric utility margin, partially offset by $5 million of higher depreciation and amortization mainly due to higher plant in service and $2 million of lower natural gas utility margin, primarily due to lower customer volumes.

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.

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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):

		Second Quarter														First Six Months
		2020				2019				Change						2020				2019				Change
Electric utility margin:
Operating revenue		$	165			$	172			$	(7	)	(4	)%		$	349			$	354			$	(5	)	(1	)%
Cost of fuel and energy		72				79				(7		)	(9	)		152				161				(9		)	(6	)
Electric utility margin		93				93				—			—			197				193				4			2
Natural gas utility margin:
Operating revenue		20				22				(2		)	(9	)%		68				59				9			15	%
Natural gas purchased for resale		10				10				—			—			40				29				11			38
Natural gas utility margin		10				12				(2		)	(17	)		28				30				(2		)	(7	)
Utility margin		103				105				(2		)	(2	)%		225				223				2			1	%
Operations and maintenance		41				40				1			3	%		83				84				(1		)	(1	)%
Depreciation and amortization		34				32				2			6			68				63				5			8
Property and other taxes		5				6				(1		)	(17	)		11				12				(1		)	(8	)
Operating income		$	23			$	27			$	(4	)	(15	)%		$	63			$	64			$	(1	)	(2	)%

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Electric Utility Margin

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

		Second Quarter														First Six Months
		2020				2019				Change						2020				2019				Change
Electric utility margin (in millions):
Electric operating revenue		$	165			$	172			$	(7	)	(4	)%		$	349			$	354			$	(5	)	(1	)%
Cost of fuel and energy		72				79				(7		)	(9	)		152				161				(9		)	(6	)
Electric utility margin		$	93			$	93			$	—		—	%		$	197			$	193			$	4		2	%
Sales (GWhs):
Residential		585				530				55			10	%		1,220				1,185				35			3	%
Commercial		722				678				44			6			1,423				1,378				45			3
Industrial		811				1,005				(194		)	(19	)		1,720				1,929				(209		)	(11	)
Other		4				4				—			—			8				8				—			—
Total fully bundled(1)		2,122				2,217				(95		)	(4	)		4,371				4,500				(129		)	(3	)
Distribution only service		425				405				20			5			837				796				41			5
Total retail		2,547				2,622				(75		)	(3	)		5,208				5,296				(88		)	(2	)
Wholesale		96				139				(43		)	(31	)		289				358				(69		)	(19	)
Total GWhs sold		2,643				2,761				(118		)	(4	)%		5,497				5,654				(157		)	(3	)%
Average number of retail customers (in thousands)		358				351				7			2	%		357				351				6			2	%
Average revenue per MWh:
Retail - fully bundled(1)		$	72.25			$	71.87			$	0.38		1	%		$	73.54			$	71.68			$	1.86		3	%
Wholesale		$	42.75			$	48.51			$	(5.76	)	(12	)%		$	46.96			$	50.97			$	(4.01	)	(8	)%
Heating degree days		591				519				72			14	%		2,657				2,763				(106		)	(4	)%
Cooling degree days		220				216				4			2	%		220				216				4			2	%
Sources of energy (GWhs)(2):
Natural gas		1,165				1,152				13			1	%		2,380				2,246				134			6	%
Coal		154				212				(58		)	(27	)		220				552				(332		)	(60	)
Renewables(3)		13				12				1			8			19				17				2			12
Total energy generated		1,332				1,376				(44		)	(3	)		2,619				2,815				(196		)	(7	)
Energy purchased		1,127				1,127				—			—			2,452				2,306				146			6
Total		2,459				2,503				(44		)	(2	)%		5,071				5,121				(50		)	(1	)%
Average total cost of energy per MWh(4)		$	28.92			$	31.34			$	(2.42	)	(8	)%		$	29.89			$	31.42			$	(1.53	)	(5	)%

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

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

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

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

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Natural Gas Utility Margin

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

		Second Quarter														First Six Months
		2020				2019				Change						2020				2019				Change
Utility margin (in millions):
Operating revenue		$	20			$	22			$	(2	)	(9	)%		$	68			$	59			$	9		15	%
Natural gas purchased for resale		10				10				—			—			40				29				11			38
Natural gas utility margin		$	10			$	12			$	(2	)	(17	)%		$	28			$	30			$	(2	)	(7	)%
Sold (000's Dths):
Residential		1,552				1,627				(75		)	(5	)%		5,938				6,640				(702		)	(11	)%
Commercial		718				890				(172		)	(19	)		2,885				3,387				(502		)	(15	)
Industrial		342				409				(67		)	(16	)		995				1,079				(84		)	(8	)
Total retail		2,612				2,926				(314		)	(11	)%		9,818				11,106				(1,288		)	(12	)%
Average number of retail customers (in thousands)		174				170				4			2	%		173				170				3			2	%
Average revenue per retail Dth sold		$	7.98			$	7.52			$	0.46		6	%		$	6.95			$	5.31			$	1.64		31	%
Heating degree days		591				519				72			14	%		2,657				2,763				(106		)	(4	)%
Average cost of natural gas per retail Dth sold		$	3.66			$	3.42			$	0.24		7	%		$	4.07			$	2.61			$	1.46		56	%

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

•	$2 million due to higher energy efficiency program rates (offset in operations and maintenance expense).

The increase in utility margin was offset by:

•	$2 million of lower wholesale revenue.

Natural gas utility margin decreased $2 million, or 17%, for the second quarter of 2020 compared to 2019 primarily due to lower customer volumes primarily from the unfavorable impacts of weather.

Operations and maintenance increased $1 million, or 3%, for the second quarter of 2020 compared to 2019 primarily due to higher energy efficiency program costs (offset in operating revenue) of $2 million and lower regulatory-directed credits relating to the amortization of an excess reserve balance that ended in 2019 of $2 million, partially offset by higher regulatory-directed credits relating to the deferral of costs for the ON Line lease to be collected from customers (offset in other income (expense)) of $2 million and lower plant operations and maintenance costs of $1 million.

Depreciation and amortization increased $2 million, or 6%, for the second quarter of 2020 compared to 2019 primarily due to higher plant placed in service.

Other income (expense) remained consistent for the second quarter of 2020 compared to 2019 primarily due to lower pension costs of $1 million and higher cash surrender value of corporate-owned life insurance policies of $1 million, offset by higher interest 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) of $2 million.

Income tax expense decreased $3 million, or 75%, for the second quarter of 2020 compared to 2019. The effective tax rate was 7% 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.

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Electric utility margin increased $4 million, or 2%, for the first six months of 2020 compared to 2019 primarily due:

•	$2 million due to price impacts from changes in sales mix, partially offset by lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 1.7%, 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,

•	$2 million due to higher energy efficiency program rates (offset in operations and maintenance expense) and

•	$1 million of residential customer growth.

The increase in utility margin was offset by:

•	$1 million of lower wholesale revenue.

Natural gas utility margin decreased $2 million, or 7%, for the first six months of 2020 compared to 2019 primarily due to lower customer volumes primarily from the unfavorable impacts of weather.

Operations and maintenance decreased $1 million, or 1%, for the first six 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 (offset in other income (expense)) of $4 million and lower plant operations and maintenance costs of $1 million, offset by higher energy efficiency program costs (offset in operating revenue) of $2 million and lower regulatory-directed credits relating to the amortization of an excess reserve balance that ended in 2019 of $2 million.

Depreciation and amortization increased $5 million, or 8%, for the first six months of 2020 compared to 2019 primarily due to higher plant placed in service.

Other income (expense) is unfavorable $3 million, or 17%, for the first six months of 2020 compared to 2019 primarily due to higher interest 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) of $4 million and lower cash surrender value of corporate-owned life insurance policies of $1 million, offset by lower pension costs of $2 million.

Income tax expense decreased $6 million, or 60%, for the first six 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 June 30, 2020, Sierra Pacific's total net liquidity was as follows (in millions):

Cash and cash equivalents		$	12
Credit facility		250
Total net liquidity		$	262
Credit facility:
Maturity date		2022

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2020 and 2019 were $117 million and $88 million, respectively. The change was primarily due to a decrease in payments for fuel costs and the timing of payments for operating costs, partially offset by lower collections from customers, higher inventory purchases and decreased collections of customer advances.

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2020 and 2019 were $(110) million and $(99) million, respectively. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

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Financing Activities

Net cash flows from financing activities for the six-month periods ended June 30, 2020 and 2019 were $(22) million and $(32) 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 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 these 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.

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):

	Six-Month Periods								Annual
	Ended June 30,								Forecast
	2019				2020				2020
Distribution	$	79			$	72			$	135
Transmission system investment	6				15				26
Other	14				23				56
Total	$	99			$	110			$	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.

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Contractual Obligations

As of June 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 June 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 as evidenced by a reduction in consumption due to COVID-19 through June 2020 compared to the same period in 2019. The state of Nevada has since moved to the second phase of its recovery plan with most businesses, including casinos, 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 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 June 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.

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.

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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.

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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 June 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 June 30, 2020 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

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PART II

Item 1.	Legal Proceedings

Not applicable.

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.

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

Not applicable.

Item 3.	Defaults Upon Senior Securities

Not applicable.

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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.

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Exhibit No.	Description

BERKSHIRE HATHAWAY ENERGY

4.1	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).

4.2	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).

4.3	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.

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.

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.

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.

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

4.4	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.

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Exhibit No.	Description

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.

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.

ALL REGISTRANTS

101

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

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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: August 7, 2020	/s/ Calvin D. Haack
	Calvin D. Haack
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)
	PACIFICORP
Date: August 7, 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: August 7, 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: August 7, 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: August 7, 2020	/s/ Michael E. Cole
	Michael E. Cole
	Vice President, Chief Financial Officer and Treasurer
	(principal financial and accounting officer)