UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2021

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
001-37591	EASTERN ENERGY GAS HOLDINGS, LLC	46-3639580
	(A Virginia Limited Liability Company)
	6603 West Broad Street
	Richmond, Virginia 23230
	804-613-5100
	N/A
	(Former name or former address, if changed from last report)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Registrant	Yes	No
BERKSHIRE HATHAWAY ENERGY COMPANY	☒
PACIFICORP	☒
MIDAMERICAN FUNDING, LLC		☒
MIDAMERICAN ENERGY COMPANY	☒
NEVADA POWER COMPANY	☒
SIERRA PACIFIC POWER COMPANY	☒
EASTERN ENERGY GAS HOLDINGS, LLC	☒

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Registrant	Large accelerated filer	Accelerated filer	Non-accelerated filer	Smaller reporting company	Emerging growth company
BERKSHIRE HATHAWAY ENERGY COMPANY	☐	☐	☒	☐	☐
PACIFICORP	☐	☐	☒	☐	☐
MIDAMERICAN FUNDING, LLC	☐	☐	☒	☐	☐
MIDAMERICAN ENERGY COMPANY	☐	☐	☒	☐	☐
NEVADA POWER COMPANY	☐	☐	☒	☐	☐
SIERRA PACIFIC POWER COMPANY	☐	☐	☒	☐	☐
EASTERN ENERGY GAS HOLDINGS, LLC	☐	☐	☒	☐	☐

If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  o

Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes  ☐  No  x

All shares of outstanding common stock of Berkshire Hathaway Energy Company are privately held by a limited group of investors. As of August 5, 2021, 76,368,874 shares of common stock, no par value, were outstanding.

All shares of outstanding common stock of PacifiCorp are indirectly owned by Berkshire Hathaway Energy Company. As of August 5, 2021, 357,060,915 shares of common stock, no par value, were outstanding.

All of the member's equity of MidAmerican Funding, LLC is held by its parent company, Berkshire Hathaway Energy Company, as of August 5, 2021.

All shares of outstanding common stock of MidAmerican Energy Company are owned by its parent company, MHC Inc., which is a direct, wholly owned subsidiary of MidAmerican Funding, LLC. As of August 5, 2021, 70,980,203 shares of common stock, no par value, were outstanding.

All shares of outstanding common stock of Nevada Power Company are owned by its parent company, NV Energy, Inc., which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of August 5, 2021, 1,000 shares of common stock, $1.00 stated value, were outstanding.

All shares of outstanding common stock of Sierra Pacific Power Company are owned by its parent company, NV Energy, Inc. As of August 5, 2021, 1,000 shares of common stock, $3.75 par value, were outstanding.

All of the member's equity of Eastern Energy Gas Holdings, LLC is held indirectly by its parent company, Berkshire Hathaway Energy Company, as of August 5, 2021.

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

TABLE OF CONTENTS

PART I

Item 1.	Financial Statements	1
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	180
Item 4.	Controls and Procedures	180

PART II

Item 1.	Legal Proceedings	181
Item 1A.	Risk Factors	181
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	181
Item 3.	Defaults Upon Senior Securities	181
Item 4.	Mine Safety Disclosures	182
Item 5.	Other Information	182
Item 6.	Exhibits	182
Signatures		186

i

Definition of Abbreviations and Industry Terms

When used in Forward-Looking Statements, Part I - Items 2 through 3, and Part II - Items 1 through 6, the following terms have the definitions indicated.

Berkshire Hathaway Energy Company and Related Entities
BHE	Berkshire Hathaway Energy Company
Berkshire Hathaway	Berkshire Hathaway Inc.
Berkshire Hathaway Energy or the Company	Berkshire Hathaway Energy Company and its subsidiaries
PacifiCorp	PacifiCorp and its subsidiaries
MidAmerican Funding	MidAmerican Funding, LLC and its subsidiaries
MidAmerican Energy	MidAmerican Energy Company
NV Energy	NV Energy, Inc. and its subsidiaries
Nevada Power	Nevada Power Company and its subsidiaries
Sierra Pacific	Sierra Pacific Power Company and its subsidiaries
Nevada Utilities	Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
Eastern Energy Gas	Eastern Energy Gas Holdings, LLC and its subsidiaries
Registrants	Berkshire Hathaway Energy Company, PacifiCorp and its subsidiaries, MidAmerican Funding, LLC and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries and Eastern Energy Gas Holdings, LLC and its subsidiaries
Northern Powergrid	Northern Powergrid Holdings Company
BHE Pipeline Group	BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
BHE GT&S	BHE GT&S, LLC
Northern Natural Gas	Northern Natural Gas Company
Kern River	Kern River Gas Transmission Company
BHE Transmission	BHE Canada Holdings Corporation and BHE U.S. Transmission, LLC
BHE Canada	BHE Canada Holdings Corporation
AltaLink	AltaLink, L.P.
BHE U.S. Transmission	BHE U.S. Transmission, LLC
BHE Renewables	BHE Renewables, LLC and CalEnergy Philippines
HomeServices	HomeServices of America, Inc. and its subsidiaries
Utilities	PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
Domestic Regulated Businesses	PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries, BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
EGTS	Eastern Gas Transmission and Storage, Inc.
GT&S Transaction	The acquisition of substantially all of the natural gas transmission and storage business of Dominion Energy and Dominion Questar, exclusive of the Questar Pipeline Group on November 1, 2020
DEI	Dominion Energy, Inc.
Questar Pipeline Group	Dominion Energy Questar Pipeline, LLC and related entities

ii

Certain Industry Terms
2017 Tax Reform	The Tax Cuts and Jobs Act enacted on December 22, 2017, effective January 1, 2018
AFUDC	Allowance for Funds Used During Construction
AUC	Alberta Utilities Commission
BART	Best Available Retrofit Technology
COVID-19	Coronavirus Disease 2019
CSAPR	Cross-State Air Pollution Rule
CPST	Customer Price Stability Tariff
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
Dth	Decatherm
ECAM	Energy Cost Adjustment Mechanism
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
FIP	Federal Implementation Plan
GAAP	Accounting principles generally accepted in the United States of America
GEMA	Gas and Electricity Markets Authority
GHG	Greenhouse Gases
GWh	Gigawatt Hour
GTA	General Tariff Application
IPUC	Idaho Public Utilities Commission
IRP	Integrated Resource Plan
IUB	Iowa Utilities Board
kV	Kilovolt
MW	Megawatt
MWh	Megawatt Hour
NAAQS	National Ambient Air Quality Standards
NOx	Nitrogen Oxides
Ofgem	Office of Gas and Electric Markets
OPUC	Oregon Public Utility Commission
PTC	Production Tax Credit
PUCN	Public Utilities Commission of Nevada
REC	Renewable Energy Credit
RFP	Request for Proposal
RPS	Renewable Portfolio Standards
SCR	Selective Catalytic Reduction
SEC	United States Securities and Exchange Commission
SIP	State Implementation Plan
SO2	Sulfur Dioxide
UPSC	Utah Public Service Commission
WPSC	Wyoming Public Service Commission
WUTC	Washington Utilities and Transportation Commission

iii

Forward-Looking Statements

This report contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon the relevant Registrant's current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control of each Registrant and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:

•general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including income tax reform, initiatives regarding deregulation and restructuring of the utility industry, and reliability and safety standards, affecting the respective Registrant's operations or related industries;

•changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce facility output, accelerate facility retirements or delay facility construction or acquisition;

•the outcome of regulatory rate reviews and other proceedings conducted by regulatory agencies or other governmental and legal bodies and the respective Registrant's ability to recover costs through rates in a timely manner;

•changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and private generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply or the respective Registrant's ability to obtain long-term contracts with customers and suppliers;

•performance, availability and ongoing operation of the respective Registrant's facilities, including facilities not operated by the Registrants, due to the impacts of market conditions, outages and repairs, transmission constraints, weather, including wind, solar and hydroelectric conditions, and operating conditions;

•the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the control of each respective Registrant or by a breakdown or failure of the Registrants' operating assets, including severe storms, floods, fires, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, litigation, wars, terrorism, pandemics (including potentially in relation to COVID-19), embargoes, and cyber security attacks, data security breaches, disruptions, or other malicious acts;

•the ability to economically obtain insurance coverage, or any insurance coverage at all, sufficient to cover losses arising from catastrophic events, such as wildfires where the Registrants may be found liable for property damages regardless of fault;

•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;

iv

•increases in employee healthcare costs;

•the impact of investment performance, certain participant elections such as lump sum distributions and changes in interest rates, legislation, healthcare cost trends, mortality, morbidity on pension and other postretirement benefits expense and funding requirements;

•changes in the residential real estate brokerage, mortgage and franchising industries and regulations that could affect brokerage, mortgage and franchising transactions;

•the ability to successfully integrate the portion of the natural gas transmission and storage business acquired from DEI on November 1, 2020, and future acquired operations into a Registrant's business;

•unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future facilities and infrastructure additions;

•the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;

•the impact of new accounting guidance or changes in current accounting estimates and assumptions on the financial results of the respective Registrants; and

•other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the SEC or in other publicly disseminated written documents.

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

v

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	56
Consolidated Balance Sheets	57
Consolidated Statements of Operations	59
Consolidated Statements of Changes in Shareholders' Equity	60
Consolidated Statements of Cash Flows	61
Notes to Consolidated Financial Statements	62
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm	81
Balance Sheets	82
Statements of Operations	84
Statements of Changes in Shareholder's Equity	85
Statements of Cash Flows	86
Notes to Financial Statements	87
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm	96
Consolidated Balance Sheets	97
Consolidated Statements of Operations	99
Consolidated Statements of Changes in Member's Equity	100
Consolidated Statements of Cash Flows	101
Notes to Consolidated Financial Statements	102
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm	118
Consolidated Balance Sheets	119
Consolidated Statements of Operations	120
Consolidated Statements of Changes in Shareholder's Equity	121
Consolidated Statements of Cash Flows	122
Notes to Consolidated Financial Statements	123
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm	137
Consolidated Balance Sheets	138
Consolidated Statements of Operations	139
Consolidated Statements of Changes in Shareholder's Equity	140
Consolidated Statements of Cash Flows	141
Notes to Consolidated Financial Statements	142
Eastern Energy Gas Holdings, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm	157
Consolidated Balance Sheets	158
Consolidated Statements of Operations	160
Consolidated Statements of Comprehensive Income	161
Consolidated Statements of Changes in Equity	162
Consolidated Statements of Cash Flows	163
Notes to Consolidated Financial Statements	164

1

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

Berkshire Hathaway Energy Company and its subsidiaries	31
PacifiCorp and its subsidiaries	72
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company	106
Nevada Power Company and its subsidiaries	129
Sierra Pacific Power Company and its subsidiaries	149
Eastern Energy Gas Holdings, LLC and its subsidiaries	176

2

Berkshire Hathaway Energy Company and its subsidiaries

Consolidated Financial Section

3

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Berkshire Hathaway Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of June 30, 2021, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and six-month periods ended June 30, 2021 and 2020, and of cash flows for the six-month periods ended June 30, 2021 and 2020, 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, 2020, 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 26, 2021, 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, 2020, 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 6, 2021

4

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,		December 31,
	2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	1,331	$	1,290
Restricted cash and cash equivalents	154		140
Trade receivables, net	2,479		2,107
Inventories	1,113		1,168
Mortgage loans held for sale	2,082		2,001
Amounts held in trust	587		318
Other current assets	2,496		2,423
Total current assets	10,242		9,447
Property, plant and equipment, net	87,622		86,128
Goodwill	11,570		11,506
Regulatory assets	3,344		3,157
Investments and restricted cash and cash equivalents and investments	14,960		14,320
Other assets	2,823		2,758
Total assets	$	130,561	$	127,316

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

5

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	June 30,		December 31,
	2021		2020
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,802	$	1,867
Accrued interest	549		555
Accrued property, income and other taxes	711		582
Accrued employee expenses	457		383
Short-term debt	2,536		2,286
Current portion of long-term debt	918		1,839
Other current liabilities	2,107		1,626
Total current liabilities	9,080		9,138
BHE senior debt	13,000		12,997
BHE junior subordinated debentures	100		100
Subsidiary debt	34,855		34,930
Regulatory liabilities	7,344		7,221
Deferred income taxes	12,464		11,775
Other long-term liabilities	4,353		4,178
Total liabilities	81,196		80,339
Commitments and contingencies (Note 9)
Equity:
BHE shareholders' equity:
Preferred stock - 100 shares authorized, $0.01 par value, 4 shares issued and outstanding	3,750		3,750
Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding	—		—
Additional paid-in capital	6,377		6,377
Long-term income tax receivable	(658)		(658)
Retained earnings	37,303		35,093
Accumulated other comprehensive loss, net	(1,360)		(1,552)
Total BHE shareholders' equity	45,412		43,010
Noncontrolling interests	3,953		3,967
Total equity	49,365		46,977
Total liabilities and equity	$	130,561	$	127,316

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

6

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2021		2020		2021		2020
Operating revenue:
Energy	$	4,301	$	3,419	$	9,150	$	7,053
Real estate	1,763		1,193		2,995		2,086
Total operating revenue	6,064		4,612		12,145		9,139
Operating expenses:
Energy:
Cost of sales	1,110		888		2,679		1,926
Operations and maintenance	1,037		794		1,971		1,531
Depreciation and amortization	936		725		1,851		1,534
Property and other taxes	189		153		399		304
Real estate	1,584		1,116		2,704		1,989
Total operating expenses	4,856		3,676		9,604		7,284
Operating income	1,208		936		2,541		1,855
Other income (expense):
Interest expense	(532)		(503)		(1,062)		(986)
Capitalized interest	14		19		28		36
Allowance for equity funds	30		38		56		72
Interest and dividend income	26		20		47		40
Gains on marketable securities, net	1,966		583		848		610
Other, net	48		52		56		25
Total other income (expense)	1,552		209		(27)		(203)
Income before income tax expense (benefit) and equity loss	2,760		1,145		2,514		1,652
Income tax expense (benefit)	327		(7)		(208)		(191)
Equity loss	(50)		(32)		(229)		(50)
Net income	2,383		1,120		2,493		1,793
Net income attributable to noncontrolling interests	102		4		208		7
Net income attributable to BHE shareholders	2,281		1,116		2,285		1,786
Preferred dividends	37		—		75		—
Earnings on common shares	$	2,244	$	1,116	$	2,210	$	1,786

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

7

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2021		2020		2021		2020
Net income	$	2,383	$	1,120	$	2,493	$	1,793
Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $1, $2, $5 and $13	15		10		22		44
Foreign currency translation adjustment	68		109		159		(439)
Unrealized gains (losses) on cash flow hedges, net of tax of $(1), $3, $4 and $(7)	1		9		15		(24)
Total other comprehensive income (loss), net of tax	84		128		196		(419)
Comprehensive income	2,467		1,248		2,689		1,374
Comprehensive income attributable to noncontrolling interests	106		4		212		7
Comprehensive income attributable to BHE shareholders	$	2,361	$	1,244	$	2,477	$	1,367

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

8

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)

	BHE Shareholders' Equity
							Long-term				Accumulated
					Additional		Income				Other
	Preferred		Common		Paid-in		Tax		Retained		Comprehensive		Noncontrolling		Total
	Stock		Stock		Capital		Receivable		Earnings		Loss, Net		Interests		Equity
Balance, March 31, 2020	$	—	$	—	$	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	$	—	$	—	$	6,377	$	(530)	$	29,962	$	(2,125)	$	101	$	33,785
Balance, December 31, 2019	$	—	$	—	$	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	—		—		(6)		—		(120)		—		—		(126)
Distributions	—		—		—		—		—		—		(7)		(7)
Purchase of noncontrolling interest	—		—		(5)		—		—		—		(28)		(33)
Other equity transactions	—		—		(1)		—		—		—		—		(1)
Balance, June 30, 2020	$	—	$	—	$	6,377	$	(530)	$	29,962	$	(2,125)	$	101	$	33,785
Balance, March 31, 2021	$	3,750	$	—	$	6,377	$	(658)	$	35,060	$	(1,440)	$	3,962	$	47,051
Net income	—		—		—		—		2,281		—		102		2,383
Other comprehensive income	—		—		—		—		—		80		4		84
Preferred stock dividend	—		—		—		—		(37)		—		—		(37)
Distributions	—		—		—		—		—		—		(121)		(121)
Contributions	—		—		—		—		—		—		9		9
Other equity transactions	—		—		—		—		(1)		—		(3)		(4)
Balance, June 30, 2021	$	3,750	$	—	$	6,377	$	(658)	$	37,303	$	(1,360)	$	3,953	$	49,365
Balance, December 31, 2020	$	3,750	$	—	$	6,377	$	(658)	$	35,093	$	(1,552)	$	3,967	$	46,977
Net income	—		—		—		—		2,285		—		208		2,493
Other comprehensive income	—		—		—		—		—		192		4		196
Preferred stock dividend	—		—		—		—		(75)		—		—		(75)
Distributions	—		—		—		—		—		—		(234)		(234)
Contributions	—		—		—		—		—		—		9		9
Other equity transactions	—		—		—		—		—		—		(1)		(1)
Balance, June 30, 2021	$	3,750	$	—	$	6,377	$	(658)	$	37,303	$	(1,360)	$	3,953	$	49,365

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

9

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2021		2020
Cash flows from operating activities:
Net income	$	2,493	$	1,793
Adjustments to reconcile net income to net cash flows from operating activities:
Gains on marketable securities, net	(848)		(610)
Depreciation and amortization	1,874		1,557
Allowance for equity funds	(56)		(72)
Equity loss, net of distributions	313		64
Changes in regulatory assets and liabilities	(199)		(7)
Deferred income taxes and amortization of investment tax credits	613		288
Other, net	(26)		18
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(254)		(783)
Derivative collateral, net	92		16
Pension and other postretirement benefit plans	(33)		(45)
Accrued property, income and other taxes, net	76		(605)
Accounts payable and other liabilities	187		240
Net cash flows from operating activities	4,232		1,854
Cash flows from investing activities:
Capital expenditures	(2,848)		(2,793)
Purchases of marketable securities	(185)		(272)
Proceeds from sales of marketable securities	163		256
Equity method investments	(52)		(1,087)
Other, net	(53)		58
Net cash flows from investing activities	(2,975)		(3,838)
Cash flows from financing activities:
Proceeds from BHE senior debt	—		3,231
Repayments of BHE senior debt	(450)		(350)
Preferred dividends	(75)		—
Common stock purchases	—		(126)
Proceeds from subsidiary debt	539		2,448
Repayments of subsidiary debt	(1,210)		(1,410)
Net proceeds from (repayments of) short-term debt	245		(920)
Purchase of noncontrolling interest	—		(33)
Distributions to noncontrolling interests	(234)		(8)
Contributions from noncontrolling interests	9		5
Other, net	(28)		(39)
Net cash flows from financing activities	(1,204)		2,798
Effect of exchange rate changes	2		(12)
Net change in cash and cash equivalents and restricted cash and cash equivalents	55		802
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	1,445		1,268
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	1,500	$	2,070

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

10

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    General

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

The Company's operations are organized as eight business segments: PacifiCorp and its subsidiaries ("PacifiCorp"), MidAmerican Funding, LLC and its subsidiaries ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. and its subsidiaries ("NV Energy") (which primarily consists of Nevada Power Company and its subsidiaries ("Nevada Power") and Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific")), Northern Powergrid Holdings Company ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group, LLC and its subsidiaries (which primarily consists of BHE GT&S, LLC ("BHE GT&S"), 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. and 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, five interstate natural gas pipeline companies and interests in a liquefied natural gas ("LNG") export, import and storage facility 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, 2021 and for the three- and six-month periods ended June 30, 2021 and 2020. The results of operations for the three- and six-month periods ended June 30, 2021 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, 2020 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, 2021.

11

(2)    Business Acquisition

BHE GT&S Acquisition

Transaction Description

On November 1, 2020, BHE completed its acquisition of substantially all of the natural gas transmission and storage business of Dominion Energy, Inc. ("DEI") and Dominion Energy Questar Corporation ("Dominion Questar"), exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "Questar Pipeline Group") (the "GT&S Transaction"). Under the terms of the Purchase and Sale Agreement, dated July 3, 2020 (the "GT&S Purchase Agreement"), BHE paid approximately $2.5 billion in cash, after post-closing adjustments (the "GT&S Cash Consideration"), and assumed approximately $5.6 billion of existing indebtedness for borrowed money, including fair value adjustments, for 100% of the equity interests of Eastern Gas Transmission and Storage, Inc. ("EGTS") (formerly known as Dominion Energy Transmission, Inc.) and Carolina Gas Transmission, LLC (formerly known as Dominion Energy Carolina Gas Transmission, LLC); 50% of the equity interests of Iroquois Gas Transmission System L.P. ("Iroquois"); and a 25% economic interest in Cove Point LNG, LP ("Cove Point") (formerly known as Dominion Energy Cove Point LNG, LP), consisting of 100% of the general partnership interest and 25% of the total limited partnership interests. BHE became the operator of Cove Point after the GT&S Transaction. The GT&S Transaction received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended ("HSR Approval") in October 2020, and approval by the Department of Energy with respect to a change in control of Cove Point and the Federal Communications Commission with respect to the transfer of certain licenses earlier in 2020.

The assets acquired in the GT&S Transaction include (i) approximately 5,400 miles of operated natural gas transmission, gathering and storage pipelines with approximately 12.5 billion cubic feet ("Bcf") per day of design capacity; (ii) 420 Bcf of operated natural gas storage design capacity, of which 306 Bcf is owned by BHE GT&S; and (iii) an LNG export, import and storage facility with LNG storage capacity of approximately 14.6 billions of cubic feet equivalent.

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

Under the Q-Pipe Purchase Agreement, BHE delivered the Q-Pipe Cash Consideration of approximately $1.3 billion, which is included in other current assets on the Consolidated Balance Sheet as of June 30, 2021 and December 31, 2020, to Dominion Questar on November 2, 2020. Pursuant to the Q-Pipe Purchase Agreement, Dominion Questar agreed that, if the Q-Pipe Transaction did not close, it would repay all or (depending upon the repayment date) substantially all of the Q-Pipe Cash Consideration (the "Purchase Price Repayment Amount") to BHE on or prior to December 31, 2021.

On July 9, 2021, Dominion Questar and DEI delivered a written notice to BHE stating that BHE and Dominion Questar have mutually elected to terminate the Q-Pipe Purchase Agreement. On July 14, 2021, BHE received the Purchase Price Repayment Amount of approximately $1.3 billion in cash.

Included in BHE's Consolidated Statement of Operations within the BHE Pipeline Group reportable segment for the three- and six-month periods ended June 30, 2021, is operating revenue of $487 million and $1,047 million, respectively and net income attributable to BHE shareholders of $66 million and $173 million, respectively, as a result of including BHE GT&S from November 1, 2020.

12

Preliminary Allocation of Purchase Price

BHE GT&S' assets acquired and liabilities assumed were measured at estimated fair value at closing. The majority of BHE GT&S' operations are subject to the rate-setting authority of the Federal Energy Regulatory Commission ("FERC") and are accounted for pursuant to GAAP, including the authoritative guidance for regulated operations. The rate-setting and cost-recovery provisions provide for revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of BHE GT&S' assets acquired and liabilities assumed subject to these rate-setting provisions are assumed to approximate their carrying values and, therefore, no fair value adjustments have been reflected related to these amounts.

The fair value of BHE GT&S' assets acquired and liabilities assumed not subject to the rate-setting provisions discussed above was determined using an income and cost approach. The income approach is based on significant estimates and assumptions, including Level 3 inputs, which are judgmental in nature. The estimates and assumptions include the projected timing and amount of future cash flows, discount rates reflecting the risk inherent in the future cash flows and future market prices. Additionally, the fair value of long-term debt assumed was determined based on quoted market prices, which is considered a Level 2 fair value measurement.

The fair value of certain contracts and property, plant and equipment related to non-regulated operations, certain regulatory assets and other items included in rate base, an equity method investment and deferred income tax amounts are provisional and are subject to revision for up to 12 months following the acquisition date until the related valuations are completed. These items may be adjusted through regulatory assets or liabilities, to the extent recoverable in rates, or goodwill provided additional information is obtained about the facts and circumstances that existed as of the acquisition date. Such information includes, but is not limited to, the receipt of further information regarding the fair value of the contracts and property, plant and equipment related to non-regulated operations, the equity method investment and any associated deferred income tax amounts as well as the evolution of the rate-making process for regulated operations.

The following table summarizes the preliminary fair values of the assets acquired and liabilities assumed as of the acquisition date (in millions):

	Fair Value
Current assets, including cash and cash equivalents of $104	$	582
Property, plant and equipment	9,264
Goodwill	1,741
Regulatory assets	108
Deferred income taxes	284
Other long-term assets	1,424
Total assets	13,403
Current liabilities, including current portion of long-term debt of $1,200	1,616
Long-term debt, less current portion	4,415
Regulatory liabilities	650
Other long-term liabilities	292
Total liabilities	6,973
Noncontrolling interest	3,916
Net assets acquired	$	2,514

During the six-month period ended June 30, 2021, the Company made revisions to certain contracts and property, plant and equipment related to non-regulated operations, the equity method investment and associated deferred income tax amounts based upon the receipt of additional information about the facts and circumstances that existed as of the acquisition date. Provisional amounts are subject to further revision for up to 12 months following the acquisition date until the related valuations are completed.

13

Goodwill

The excess of the purchase price paid over the estimated fair values of the identifiable assets acquired and liabilities assumed totaled $1.7 billion and is reflected as goodwill in the BHE Pipeline Group reportable segment. The goodwill reflects the value paid primarily for the long-term opportunity to improve operating results through the efficient management of operating expenses and the deployment of capital. Goodwill is not amortized, but rather is reviewed annually for impairment or more frequently if indicators of impairment exist. For income tax purposes, the GT&S Acquisition is treated as a deemed asset acquisition resulting from tax elections being made, therefore all tax goodwill is deductible. Due to book and tax basis differences of certain items, book and tax goodwill will differ. The amount of tax goodwill is approximately $0.9 billion and will be amortized over 15 years.

Pro Forma Financial Information

The following unaudited pro forma financial information reflects the consolidated results of operations of BHE and the amortization of the purchase price adjustments assuming the acquisition had taken place on January 1, 2019, excluding non-recurring transaction costs incurred by BHE during 2020 (in millions):

	Six-Month Period
	Ended June 30, 2020
Operating revenue	$	10,120
Net income attributable to BHE shareholders	$	1,616

(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	2021		2020
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	88,748	$	86,730
Interstate natural gas pipeline assets	3-80 years	16,772		16,667
		105,520		103,397
Accumulated depreciation and amortization		(31,935)		(30,662)
Regulated assets, net		73,585		72,735
Nonregulated assets:
Independent power plants	5-30 years	7,058		7,012
Other assets	3-40 years	5,911		5,659
		12,969		12,671
Accumulated depreciation and amortization		(2,819)		(2,586)
Nonregulated assets, net		10,150		10,085
Net operating assets		83,735		82,820
Construction work-in-progress		3,887		3,308
Property, plant and equipment, net		$	87,622	$	86,128

Construction work-in-progress includes $3.5 billion as of June 30, 2021 and $3.2 billion as of December 31, 2020, related to the construction of regulated assets.

14

(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,
	2021		2020
Investments:
BYD Company Limited common stock	$	6,727	$	5,897
Rabbi trusts	472		440
Other	299		263
Total investments	7,498		6,600
Equity method investments:
BHE Renewables tax equity investments	5,302		5,626
Iroquois Gas Transmission System, L.P.	584		580
Electric Transmission Texas, LLC	571		594
JAX LNG, LLC	86		75
Bridger Coal Company	71		74
Other	145		118
Total equity method investments	6,759		7,067
Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds	728		676
Other restricted cash and cash equivalents	169		155
Total restricted cash and cash equivalents and investments	897		831
Total investments and restricted cash and cash equivalents and investments	$	15,154	$	14,498
Reflected as:
Current assets	$	194	$	178
Noncurrent assets	14,960		14,320
Total investments and restricted cash and cash equivalents and investments	$	15,154	$	14,498

Investments

Gains 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,
	2021		2020		2021		2020
Unrealized gains recognized on marketable securities still held at the reporting date	$	1,966	$	584	$	847	$	609
Net (losses) gains recognized on marketable securities sold during the period	—		(1)		1		1
Gains on marketable securities, net	$	1,966	$	583	$	848	$	610

15

Equity Method Investments

The Company has invested in projects sponsored by third parties, commonly referred to as tax equity investments. 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. Certain of the Company's tax equity investments are located in Texas and have physical settlement hedge obligations that were negatively impacted due to production shortfalls during periods of extreme market pricing volatility as a result of the February 2021 polar vortex weather event. The Company recognized pre-tax equity losses of $305 million, or after-tax income of $70 million inclusive of production tax credits ("PTCs") of $306 million and other income tax benefits of $67 million, during the six-month period ended June 30, 2021, on its tax equity investments, largely due to the February 2021 polar vortex weather event. The losses for the impacted tax equity investments were based upon the terms of each partnership agreement, as amended, and are subject to change as project-by-project discussions are ongoing among the Company and the respective hedge provider and project sponsor. As of June 30, 2021, the carrying value of the impacted tax equity investments totaled $2.8 billion.

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, 2021 and December 31, 2020, 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, 2021 and December 31, 2020, 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,
	2021		2020
Cash and cash equivalents	$	1,331	$	1,290
Restricted cash and cash equivalents	154		140
Investments and restricted cash and cash equivalents and investments	15		15
Total cash and cash equivalents and restricted cash and cash equivalents	$	1,500	$	1,445

(5)    Recent Financing Transactions

Long-Term Debt

In July 2021, MidAmerican Energy issued $500 million of its 2.70% First Mortgage Bonds due August 2052. MidAmerican Energy used the net proceeds to finance a portion of the capital expenditures, disbursed during the period from July 22, 2019 to September 27, 2019, with respect to investments in its 2,000-megawatt Wind XI project, its 592-megawatt Wind XII project, its 207-megawatt Wind XII Expansion project and the repowering of certain of its existing wind-powered generating facilities, which were previously financed with MidAmerican Energy's general funds.

In July 2021, PacifiCorp issued $1 billion of its 2.90% First Mortgage Bonds due June 2052. PacifiCorp used the net proceeds to finance a portion of the capital expenditures disbursed during the period from July 1, 2019 to May 31, 2021 with respect to investments, primarily from the Energy Vision 2020 initiative, in the repowering of certain of its existing wind-powered generating facilities and the construction and acquisition of new wind-powered generating facilities, which were previously financed with PacifiCorp's general funds.

On June 30, 2021, as part of an intercompany transaction with its wholly owned subsidiary EGTS, Eastern Energy Gas exchanged a total of $1.6 billion of its issued and outstanding third party notes, making EGTS the primary obligor of the exchanged notes. The intercompany debt exchange was a common control transaction accounted for as a debt modification with no gain or loss recognized in the Consolidated Financial Statements.

In April 2021, Northern Natural Gas issued $550 million of 3.40% Senior Bonds due October 2051. Northern Natural Gas used the net proceeds to early redeem in April 2021 all of its $200 million, 4.25% Senior Notes originally due June 2021 and for general corporate purposes.

16

Credit Facilities

In June 2021, BHE amended and restated its existing $3.5 billion unsecured credit facility expiring in June 2022 with one remaining one-year extension option. The amendment extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.

In June 2021, PacifiCorp terminated, upon lender consent, its existing $600 million unsecured credit facility expiring in June 2022. In June 2021, PacifiCorp amended and restated its other existing $600 million unsecured credit facility expiring in June 2022 with one remaining one-year extension option. The amendment increased the lender commitment to $1.2 billion, extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.

In June 2021, MidAmerican Energy amended and restated its existing $900 million unsecured credit facility expiring in June 2022. The amendment increased the commitment of the lenders to $1.5 billion, extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to consent of the lenders. Additionally, in June 2021, MidAmerican Energy terminated its existing $600 million unsecured credit facility expiring in August 2021.

In June 2021, Nevada Power and Sierra Pacific each amended and restated its existing $400 million and $250 million secured credit facilities, respectively, expiring in June 2022 with no remaining one-year extension options. The amendments extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.

In May 2021, AltaLink, L.P. extended, with lender consent, the expiration date for its existing C$75 million and C$500 million secured credit facilities to December 2025 by exercising an available one-year extension option.

In May 2021, AltaLink Investments, L.P. extended, with lender consent, the expiration date for its existing C$300 million unsecured credit facility to December 2025 by exercising an available one-year extension option.

In April 2021, AltaLink Investments, L.P. extended, with lender consent, the expiration date for its existing C$200 million one-year revolving credit facility to April 2022, by exercising a one-year extension option.

(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 (benefit) is as follows:

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2021		2020		2021		2020
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Income tax credits	(13)		(20)		(27)		(28)
State income tax, net of federal income tax impacts	4		2		2		1
Income tax effect of foreign income	3		(2)		3		(2)
Effects of ratemaking	(2)		(1)		(4)		(3)
Equity income	—		(1)		(2)		(1)
Noncontrolling interest	(1)		—		(2)		—
Other, net	—		—		1		—
Effective income tax rate	12	%	(1)	%	(8)	%	(12)	%

17

Income tax credits relate primarily to 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. PTCs for the six-month periods ended June 30, 2021 and 2020 totaled $678 million and $454 million, respectively.

Income tax effect on foreign income includes, among other items, a deferred income tax charge of $109 million recognized in June 2021 upon the enactment of an increase in the United Kingdom's corporate income tax rate from 19% to 25% effective April 1, 2023.

The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated United States federal and Iowa state income tax returns and the majority of the Company's United States federal income tax is remitted to or received from Berkshire Hathaway. The Company received net cash payments for federal income taxes from Berkshire Hathaway totaling $943 million for the six-month period ended June 30, 2021 and made payments for federal income taxes to Berkshire Hathaway totaling $100 million for the six-month period ended June 30, 2020.

(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,
	2021		2020		2021		2020
Pension:
Service cost	$	8	$	4	$	15	$	7
Interest cost	18		23		38		46
Expected return on plan assets	(36)		(35)		(69)		(70)
Net amortization	7		8		13		17
Net periodic benefit credit	$	(3)	$	—	$	(3)	$	—
Other postretirement:
Service cost	$	4	$	3	$	6	$	4
Interest cost	5		4		10		10
Expected return on plan assets	(6)		(7)		(11)		(16)
Net amortization	(1)		(3)		(2)		(4)
Net periodic benefit cost (credit)	$	2	$	(3)	$	3	$	(6)

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 $13 million, respectively, during 2021. As of June 30, 2021, $7 million and $6 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

18

Foreign Operations

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2021		2020		2021		2020
Service cost	$	4	$	4	$	8	$	8
Interest cost	7		10		15		20
Expected return on plan assets	(28)		(25)		(56)		(50)
Net amortization	14		11		28		21
Net periodic benefit credit	$	(3)	$	—	$	(5)	$	(1)

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 £50 million during 2021. As of June 30, 2021, £14 million, or $19 million, of contributions had been made to the United Kingdom pension plan.

(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.

19

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, 2021
Assets:
Commodity derivatives	$	5	$	232	$	158	$	(40)	$	355
Foreign currency exchange rate derivatives	—		16		—		—		16
Interest rate derivatives	—		1		42		—		43
Mortgage loans held for sale	—		2,082		—		—		2,082
Money market mutual funds(2)	795		—		—		—		795
Debt securities:
United States government obligations	222		—		—		—		222
International government obligations	—		5		—		—		5
Corporate obligations	—		78		—		—		78
Municipal obligations	—		2		—		—		2
Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:
United States companies	412		—		—		—		412
International companies	6,735		—		—		—		6,735
Investment funds	266		—		—		—		266
	$	8,435	$	2,417	$	200	$	(40)	$	11,012
Liabilities:
Commodity derivatives	$	(1)	$	(100)	$	(53)	$	34	$	(120)
Foreign currency exchange rate derivatives	—		(5)		—		—		(5)
Interest rate derivatives	(3)		(16)		(1)		4		(16)
	$	(4)	$	(121)	$	(54)	$	38	$	(141)

20

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2020
Assets:
Commodity derivatives	$	1	$	73	$	135	$	(21)	$	188
Foreign currency exchange rate derivatives	—		20		—		—		20
Interest rate derivatives	—		—		62		—		62
Mortgage loans held for sale	—		2,001		—		—		2,001
Money market mutual funds(2)	873		—		—		—		873
Debt securities:
United States government obligations	200		—		—		—		200
International government obligations	—		5		—		—		5
Corporate obligations	—		73		—		—		73
Municipal obligations	—		2		—		—		2
Agency, asset and mortgage-backed obligations	—		6		—		—		6
Equity securities:
United States companies	381		—		—		—		381
International companies	5,906		—		—		—		5,906
Investment funds	201		—		—		—		201
	$	7,562	$	2,180	$	197	$	(21)	$	9,918
Liabilities:
Commodity derivatives	$	(1)	$	(90)	$	(19)	$	56	$	(54)
Foreign currency exchange rate derivatives	—		(2)		—		—		(2)
Interest rate derivatives	(5)		(60)		—		—		(65)
	$	(6)	$	(152)	$	(19)	$	56	$	(121)

(1)Represents netting under master netting arrangements and a net cash collateral payable of $2 million as of June 30, 2021 and a net cash collateral receivable of $35 million as of December 31, 2020.

(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.

21

The Company's investments in money market mutual funds and debt and equity securities are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
			Interest				Interest
	Commodity		Rate		Commodity		Rate
	Derivatives		Derivatives		Derivatives		Derivatives
2021:
Beginning balance	$	124	$	41	$	116	$	62
Changes included in earnings(1)	(10)		—		(16)		(21)
Changes in fair value recognized in OCI	(6)		—		(7)		—
Changes in fair value recognized in net regulatory assets	(7)		—		9		—
Purchases	1		—		1		—
Settlements	3		—		2		—
Ending balance	$	105	$	41	$	105	$	41

	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)	(1)		33		(4)		64
Changes in fair value recognized in net regulatory assets	(16)		—		(56)		—
Purchases	1		—		3		—
Settlements	8		—		4		—
Ending balance	$	44	$	78	$	44	$	78

(1)Changes included in earnings for interest rate derivatives are reported net of amounts related to the satisfaction of the associated loan commitment.

22

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, 2021				As of December 31, 2020
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	48,873	$	57,059	$	49,866	$	60,633

(9)    Commitments and Contingencies

Construction Commitments

During the six-month period ended June 30, 2021, MidAmerican Energy entered into firm construction commitments totaling $558 million through the remainder of 2021 and 2022 related to the repowering and construction of wind-powered generating facilities and the construction of solar-powered generating facilities.

Easements

During the six-month period ended June 30, 2021, MidAmerican Energy entered into non-cancelable easements with minimum payment commitments totaling $87 million through 2061 for land in Iowa on which some of its wind- and solar-powered generating facilities will be located.

Legal Matters

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

California and Oregon 2020 Wildfires

In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon burning over 500,000 acres in aggregate. Third party reports for these wildfires indicate over 2,000 structures, including residences, destroyed; several structures damaged; multiple individuals injured; and several fatalities. Fire suppression costs estimated by various agencies total approximately $150 million. Investigations into the cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the United States Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.

Several lawsuits have been filed in Oregon and California, including a putative class action complaint in Oregon, on behalf of citizens and businesses who suffered damages from fires allegedly caused by PacifiCorp. The final determinations of liability, however, will only be made following comprehensive investigations and litigation processes.

23

In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages without the utility being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could nevertheless be found liable for all damages proximately caused by negligence, including property and natural resource damage; fire suppression costs; personal injury and loss of life damages; and interest.

As of June 30, 2021, PacifiCorp has accrued $136 million as its best estimate of the potential losses net of expected insurance recoveries associated with the 2020 Wildfires that are considered probable of being incurred. These accruals include estimated losses for fire suppression costs, property damage, personal injury damages and loss of life damages. It is reasonably possible that PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved and the lack of specific claims for all potential claimants. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover at least a portion of the losses.

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 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 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 mainstem Klamath dams from PacifiCorp to the KRRC. The FERC approved partial transfer of the Klamath license in a July 2020 order, 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. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer application by January 16, 2021 to remove PacifiCorp from the license for the Klamath Hydroelectric Project and add the States and KRRC as co-licensees for the purposes of surrender. On January 13, 2021, the new license transfer application was filed with the FERC, notifying it that PacifiCorp and the KRRC are not accepting co-licensee status under FERC's July 2020 order, and instead are seeking the license transfer outcome described in the new license transfer application. In addition, the MOA provides for additional contingency funding of $45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In June 2021, the FERC approved transfer of the four mainstem Klamath dams from PacifiCorp to the KRRC, the Karuk Tribe, the Yurok Tribe and the States as co-licensees. The transfer will be effective after PacifiCorp secures property transfer approvals from its state public utility commissions and 30 days following the issuance of a license surrender order from the FERC for the project. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions approved the property transfer.

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.

24

(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 and nonregulated, with further disaggregation of regulated 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, 2021
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	1,188	$	516	$	708	$	—	$	—	$	—	$	—	$	(1)	$	2,411
Retail gas	—		89		20		—		—		—		—		—		109
Wholesale	30		69		10		—		—		—		—		(1)		108
Transmission and    distribution	37		15		22		243		—		178		—		—		495
Interstate pipeline	—		—		—		—		458		—		—		(25)		433
Other	31		—		1		—		(1)		—		—		—		31
Total Regulated	1,286		689		761		243		457		178		—		(27)		3,587
Nonregulated	—		1		1		8		232		7		239		124		612
Total Customer Revenue	1,286		690		762		251		689		185		239		97		4,199
Other revenue	12		3		5		29		17		(3)		28		11		102
Total	$	1,298	$	693	$	767	$	280	$	706	$	182	$	267	$	108	$	4,301

	For the Six-Month Period Ended June 30, 2021
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	2,333	$	968	$	1,219	$	—	$	—	$	—	$	—	$	(1)	$	4,519
Retail gas	—		549		58		—		—		—		—		—		607
Wholesale	66		194		25		—		17		—		—		(1)		301
Transmission and    distribution	62		30		43		506		—		350		—		—		991
Interstate pipeline	—		—		—		—		1,273		—		—		(66)		1,207
Other	54		—		1		—		1		—		—		—		56
Total Regulated	2,515		1,741		1,346		506		1,291		350		—		(68)		7,681
Nonregulated	—		11		1		18		469		15		405		311		1,230
Total Customer Revenue	2,515		1,752		1,347		524		1,760		365		405		243		8,911
Other revenue	25		8		11		56		39		(3)		52		51		239
Total	$	2,540	$	1,760	$	1,358	$	580	$	1,799	$	362	$	457	$	294	$	9,150

25

	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

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

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,
	2021		2020		2021		2020
Customer Revenue:
Brokerage	$	1,569	$	957	$	2,591	$	1,734
Franchise	24		15		42		31
Total Customer Revenue	1,593		972		2,633		1,765
Mortgage and other revenue	170		221		362		321
Total	$	1,763	$	1,193	$	2,995	$	2,086

26

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, 2021, by reportable segment (in millions):

	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total
BHE Pipeline Group	$	2,562	$	21,728	$	24,290
BHE Transmission	350		—		350
Total	$	2,912	$	21,728	$	24,640

(11)    BHE Shareholders' Equity

On July 22, 2021, BHE redeemed at par 1,450,003 shares of its 4.00% Perpetual Preferred Stock from certain subsidiaries of Berkshire Hathaway Inc. for $1.45 billion, plus an additional amount equal to the accrued dividends on the pro rata shares redeemed.

For the six-month period ended June 30, 2020, BHE repurchased 180,358 shares of its common stock for $126 million.

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

The following table shows the change in accumulated other comprehensive income (loss) by each component of other comprehensive income (loss), net of applicable income tax (in millions):

	Unrecognized		Foreign		Unrealized				AOCI
	Amounts on		Currency		(Losses) Gains				Attributable
	Retirement		Translation		on Cash		Noncontrolling		To BHE
	Benefits		Adjustment		Flow Hedges		Interests		Shareholders, Net
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)
Balance, December 31, 2020	$	(492)	$	(1,062)	$	(8)	$	10	$	(1,552)
Other comprehensive income (loss)	22		159		15		(4)		192
Balance, June 30, 2021	$	(470)	$	(903)	$	7	$	6	$	(1,360)

27

(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,
	2021		2020		2021		2020
Operating revenue:
PacifiCorp	$	1,298	$	1,144	$	2,540	$	2,350
MidAmerican Funding	693		616		1,760		1,302
NV Energy	767		695		1,358		1,317
Northern Powergrid	280		221		580		487
BHE Pipeline Group	706		225		1,799		626
BHE Transmission	182		169		362		341
BHE Renewables	267		244		457		422
HomeServices	1,763		1,193		2,995		2,086
BHE and Other(1)	108		105		294		208
Total operating revenue	$	6,064	$	4,612	$	12,145	$	9,139

Depreciation and amortization:
PacifiCorp	$	275	$	210	$	539	$	462
MidAmerican Funding	209		175		416		351
NV Energy	137		125		273		249
Northern Powergrid	73		63		144		126
BHE Pipeline Group	121		25		239		89
BHE Transmission	60		55		118		115
BHE Renewables	61		71		121		142
HomeServices	12		12		23		23
BHE and Other(1)	(1)		—		1		—
Total depreciation and amortization	$	947	$	736	$	1,874	$	1,557

28

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2021		2020		2021		2020
Operating income:
PacifiCorp	$	283	$	256	$	517	$	490
MidAmerican Funding	103		110		151		212
NV Energy	145		161		215		240
Northern Powergrid	126		89		277		221
BHE Pipeline Group	245		92		863		341
BHE Transmission	85		81		166		157
BHE Renewables	97		84		130		101
HomeServices	179		77		291		97
BHE and Other(1)	(55)		(14)		(69)		(4)
Total operating income	1,208		936		2,541		1,855
Interest expense	(532)		(503)		(1,062)		(986)
Capitalized interest	14		19		28		36
Allowance for equity funds	30		38		56		72
Interest and dividend income	26		20		47		40
Gains on marketable securities, net	1,966		583		848		610
Other, net	48		52		56		25
Total income before income tax expense (benefit) and equity loss	$	2,760	$	1,145	$	2,514	$	1,652

Interest expense:
PacifiCorp	$	105	$	110	$	212	$	212
MidAmerican Funding	78		78		156		159
NV Energy	51		57		103		115
Northern Powergrid	32		31		65		63
BHE Pipeline Group	40		15		78		29
BHE Transmission	40		35		78		73
BHE Renewables	40		42		80		84
HomeServices	1		3		2		8
BHE and Other(1)	145		132		288		243
Total interest expense	$	532	$	503	$	1,062	$	986

Earnings on common shares:
PacifiCorp	$	226	$	167	$	395	$	343
MidAmerican Funding	211		208		355		358
NV Energy	100		98		134		118
Northern Powergrid	(25)		59		79		146
BHE Pipeline Group	100		64		483		243
BHE Transmission	60		60		119		115
BHE Renewables	181		138		197		233
HomeServices	135		59		219		69
BHE and Other	1,256		263		229		161
Earnings on common shares	$	2,244	$	1,116	$	2,210	$	1,786

29

	As of
	June 30,		December 31,
	2021		2020
Assets:
PacifiCorp	$	27,235	$	26,862
MidAmerican Funding	24,156		23,530
NV Energy	14,839		14,501
Northern Powergrid	9,071		8,782
BHE Pipeline Group	19,739		19,541
BHE Transmission	9,516		9,208
BHE Renewables	11,754		12,004
HomeServices	5,410		4,955
BHE and Other(1)	8,841		7,933
Total assets	$	130,561	$	127,316

(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.

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2021		2020		2021		2020
Operating revenue by country:
United States	$	5,604	$	4,224	$	11,201	$	8,313
United Kingdom	280		221		580		487
Canada	180		167		357		338
Philippines and other	—		—		7		1
Total operating revenue by country	$	6,064	$	4,612	$	12,145	$	9,139

Income before income tax expense (benefit) and equity loss by country:
United States	$	2,611	$	1,027	$	2,188	$	1,381
United Kingdom	104		59		236		168
Canada	46		46		85		86
Philippines and other	(1)		13		5		17
Total income before income tax expense (benefit) and equity loss by country	$	2,760	$	1,145	$	2,514	$	1,652

The following table shows the change in the carrying amount of goodwill by reportable segment for the six-month period ended June 30, 2021 (in millions):

									BHE Pipeline Group
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid				BHE Transmission		BHE Renewables		HomeServices
																	Total
December 31, 2020	$	1,129	$	2,102	$	2,369	$	1,000	$	1,803	$	1,551	$	95	$	1,457	$	11,506
Acquisitions	—		—		—		—		11		—		—		2		13
Foreign currency translation	—		—		—		9		—		42		—		—		51
June 30, 2021	$	1,129	$	2,102	$	2,369	$	1,009	$	1,814	$	1,593	$	95	$	1,459	$	11,570

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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) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which primarily consists of BHE GT&S, 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, five interstate natural gas pipeline companies, one of which owns a liquefied natural gas ("LNG") export, import and storage facility, 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.

31

Results of Operations for the Second Quarter and First Six Months of 2021 and 2020

Overview

Operating revenue and earnings on common shares for the Company's reportable segments are summarized as follows (in millions):

	Second Quarter								First Six Months
	2021		2020		Change				2021		2020		Change
Operating revenue:
PacifiCorp	$	1,298	$	1,144	$	154	13	%	$	2,540	$	2,350	$	190	8	%
MidAmerican Funding	693		616		77		13		1,760		1,302		458		35
NV Energy	767		695		72		10		1,358		1,317		41		3
Northern Powergrid	280		221		59		27		580		487		93		19
BHE Pipeline Group	706		225		481		*		1,799		626		1,173		*
BHE Transmission	182		169		13		8		362		341		21		6
BHE Renewables	267		244		23		9		457		422		35		8
HomeServices	1,763		1,193		570		48		2,995		2,086		909		44
BHE and Other	108		105		3		3		294		208		86		41
Total operating revenue	$	6,064	$	4,612	$	1,452	31	%	$	12,145	$	9,139	$	3,006	33	%
Earnings on common shares:
PacifiCorp	$	226	$	167	$	59	35	%	$	395	$	343	$	52	15	%
MidAmerican Funding	211		208		3		1		355		358		(3)		(1)
NV Energy	100		98		2		2		134		118		16		14
Northern Powergrid	(25)		59		(84)		*		79		146		(67)		(46)
BHE Pipeline Group	100		64		36		56		483		243		240		99
BHE Transmission	60		60		—		—		119		115		4		3
BHE Renewables(1)	181		138		43		31		197		233		(36)		(15)
HomeServices	135		59		76		*		219		69		150		*
BHE and Other	1,256		263		993		*		229		161		68		42
Earnings on common shares	$	2,244	$	1,116	$	1,128	*		$	2,210	$	1,786	$	424	24	%

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

*    Not meaningful

Earnings on common shares increased $1,128 million for the second quarter of 2021 compared to 2020. The second quarter of 2021 included a pre-tax unrealized gain of $1,954 million ($1,420 million after-tax) compared to a pre-tax unrealized gain in the second quarter of 2020 of $562 million ($408 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the second quarter of 2021 was $824 million, an increase of $116 million, or 16%, compared to adjusted earnings on common shares in the second quarter of 2020 of $708 million.

Earnings on common shares increased $424 million for the first six months of 2021 compared to 2020. The first six months of 2021 included a pre-tax unrealized gain of $830 million ($602 million after-tax) compared to a pre-tax unrealized gain in the first six months of 2020 of $615 million ($447 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the first six months of 2021 was $1,608 million, an increase of $269 million, or 20%, compared to adjusted earnings on common shares in the first six months of 2020 of $1,339 million.

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The increases in earnings on common shares for the second quarter and for the first six months of 2021 compared to 2020 were primarily due to the following:

•The Utilities' net income increased $64 million for the second quarter and $65 million for the first six months of 2021 compared to 2020, reflecting higher electric utility margin and favorable income tax expense from higher PTCs recognized and the impacts of ratemaking, partially offset by higher depreciation and amortization expense and higher operations and maintenance expense. Electric retail customer volumes increased 5.7% for the first six months of 2021 compared to 2020, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers;

•Northern Powergrid's net income decreased $84 million for the second quarter and $67 million for the first six months of 2021 compared to 2020, primarily due to a deferred income tax charge of $109 million related to the enactment in the second quarter of 2021 of an increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, partially offset by higher distribution revenue;

•BHE Pipeline Group's net income increased $36 million for the second quarter and $240 million for the first six months of 2021 compared to 2020, largely due to $66 million and $173 million, respectively, of incremental net income from BHE GT&S, acquired in November 2020. In addition, net income for the first six months increased from the effects of higher margins on natural gas sales and higher transportation revenue at Northern Natural Gas, largely due to the favorable impacts of the February 2021 polar vortex weather event;

•BHE Renewables' net income increased $43 million for the second quarter and decreased $36 million for the first six months of 2021 compared to 2020. The changes were primarily due to earnings from tax equity investment projects reaching commercial operation and higher operating revenue from owned renewable energy projects, with the first six months being negatively impacted by lower tax equity investment earnings from the February 2021 polar vortex weather event;

•HomeServices' net income increased $76 million for the second quarter and $150 million for the first six months of 2021 compared to 2020, reflecting higher earnings from brokerage services due to comparative increases in closed transaction volumes and higher earnings from mortgage services from an unfavorable 2020 contingent earn-out remeasurement and higher funded mortgage volume for the first six months; and

•BHE and Other's net income increased $993 million for the second quarter and $68 million for the first six months of 2021 compared to 2020, mainly due to $1,012 million and $155 million, respectively, of favorable changes in the after-tax unrealized position of the Company's investment in BYD Company Limited, partially offset by dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020.

Reportable Segment Results

PacifiCorp

Operating revenue increased $154 million for the second quarter of 2021 compared to 2020, primarily due to higher retail revenue of $124 million and higher wholesale and other revenue of $30 million. Retail revenue increased due to higher customer volumes of $132 million, partially offset by price impacts of $8 million from lower rates due to certain general rate case orders. Retail customer volumes increased 11.6%, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers. Wholesale and other revenue increased primarily due to higher wheeling revenue and wholesale volumes, partially offset by lower average wholesale market prices.

Net income increased $59 million for the second quarter of 2021 compared to 2020, primarily due to higher utility margin of $96 million, favorable income tax expense, from the impacts of ratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service, and lower property taxes of $9 million, partially offset by higher depreciation and amortization expense of $65 million, including the impacts of a depreciation study effective January 1, 2021, lower allowances for equity and borrowed funds used during construction of $17 million and higher operations and maintenance expense of $12 million. Utility margin increased primarily due to the higher retail, wheeling and wholesale revenues and higher deferred net power costs in accordance with established adjustment mechanisms, partially offset by higher purchased power costs and higher thermal generation costs.

Operating revenue increased $190 million for the first six months of 2021 compared to 2020, primarily due to higher retail revenue of $144 million and higher wholesale and other revenue of $46 million. Retail revenue increased due to higher customer volumes of $148 million, partially offset by price impacts of $4 million from lower rates due to certain general rate case orders. Retail customer volumes increased 5.7%, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers. Wholesale and other revenue increased primarily due to higher wholesale volumes, higher wheeling revenue and higher average wholesale market prices.

33

Net income increased $52 million for the first six months of 2021 compared to 2020, primarily due to higher utility margin of $125 million and favorable income tax expense from higher PTCs recognized due to new wind-powered generating facilities placed in-service and the impacts of ratemaking, partially offset by higher depreciation and amortization expense of $77 million, including the impacts of a depreciation study effective January 1, 2021, lower allowances for equity and borrowed funds used during construction of $29 million and higher operations and maintenance expense of $17 million. Utility margin increased primarily due to the higher retail, wholesale and wheeling revenues and higher deferred net power costs in accordance with established adjustment mechanisms, partially offset by higher thermal generation costs and higher purchased power costs.

MidAmerican Funding

Operating revenue increased $77 million for the second quarter of 2021 compared to 2020, primarily due to higher electric operating revenue of $68 million and higher natural gas operating revenue of $11 million. Electric operating revenue increased due to higher retail revenue of $48 million and higher wholesale and other revenue of $20 million mainly from higher wholesale volumes. Electric retail revenue increased primarily due to higher customer volumes of $30 million, higher recoveries through adjustment clauses of $16 million (largely offset in cost of sales), and price impacts of $2 million from changes in sales mix. Electric retail customer volumes increased 9.2% due to increased usage of certain industrial customers and the favorable impact of weather. Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold resulting in higher purchased gas adjustment recoveries of $17 million (offset in cost of sales), partially offset by a 4.8% decrease in customer volumes.

Net income increased $3 million for the second quarter of 2021 compared to 2020, primarily due to higher electric utility margin of $36 million and a favorable income tax benefit, partially offset by higher depreciation and amortization expense of $34 million, from additional assets placed in-service and a regulatory mechanism deferring certain depreciation expense in 2020, and unfavorable changes in the cash surrender value of corporate-owned life insurance policies. The favorable income tax benefit was mainly due to higher PTCs recognized from higher wind-powered generation, driven primarily by new wind projects placed in-service, partially offset by the impacts of ratemaking. Electric utility margin increased primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs.

Operating revenue increased $458 million for the first six months of 2021 compared to 2020, primarily due to higher natural gas operating revenue of $314 million and higher electric operating revenue of $142 million. Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold resulting in higher purchased gas adjustment recoveries of $321 million (offset in cost of sales), primarily due to the February 2021 polar vortex weather event, partially offset by a 1.3% decrease in customer volumes. Electric operating revenue increased due to higher retail revenue of $90 million and higher wholesale and other revenue of $52 million mainly from higher wholesale volumes. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $48 million (largely offset in cost of sales), higher customer volumes of $35 million and price impacts of $7 million from changes in sales mix. Electric retail customer volumes increased 7.0% due to increased usage of certain industrial customers and the favorable impact of weather.

Net income decreased $3 million for the first six months of 2021 compared to 2020, primarily due to higher depreciation and amortization expense of $65 million, from additional assets placed in-service and a regulatory mechanism deferring certain depreciation expense in 2020, and $30 million higher operations and maintenance expenses, partially offset by higher electric utility margin of $39 million, a favorable income tax benefit and favorable changes in the cash surrender value of corporate-owned life insurance policies. Higher operations and maintenance expenses included increased costs associated with additional wind-powered generating facilities placed in-service as well as higher electric and natural gas distribution costs. The favorable income tax benefit was mainly due to higher PTCs recognized from higher wind-powered generation, driven primarily by new wind projects placed in-service, partially offset by the impacts of ratemaking. Electric utility margin increased primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs.

NV Energy

Operating revenue increased $72 million for the second quarter of 2021 compared to 2020 due to higher electric operating revenue, which increased primarily due to higher fully-bundled energy rates (offset in cost of sales) of $77 million, higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers, partially offset by lower base tariff general rates of $15 million at Nevada Power. Electric retail customer volumes increased 11.2%, primarily due to the impacts from COVID-19 recovery and the favorable impact of weather.

34

Net income increased $2 million for the second quarter of 2021 compared to 2020, primarily due to lower income tax expense from the impacts of ratemaking and lower interest expense of $6 million, partially offset by higher depreciation and amortization expense of $12 million, mainly from the regulatory amortization of decommissioning costs and higher plant placed in-service, and lower electric utility margin of $4 million. Electric utility margin decreased primarily due to lower base tariff general rates at Nevada Power, partially offset by higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers.

Operating revenue increased $41 million for the first six months of 2021 compared to 2020, primarily due to higher electric operating revenue of $51 million, partially offset by lower natural gas operating revenue of $10 million. Electric operating revenue increased primarily due to higher fully-bundled energy rates (offset in cost of sales) of $73 million, higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers, partially offset by lower base tariff general rates of $24 million at Nevada Power. Electric retail customer volumes increased 4.4%, primarily due to the impacts from COVID-19 recovery and the favorable impact of weather. Natural gas operating revenue decreased primarily due to a lower average per-unit cost of natural gas sold (offset in cost of sales).

Net income increased $16 million for the first six months of 2021 compared to 2020, primarily due to lower operations and maintenance expense of $21 million, primarily from lower regulatory instructed deferrals and amortizations, lower income tax expense from the impacts of ratemaking, lower interest expense of $12 million, lower pension costs and favorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by higher depreciation and amortization expense of $24 million, mainly from the regulatory amortization of decommissioning costs and higher plant placed in-service, and lower electric utility margin of $22 million. Electric utility margin decreased primarily due to lower base tariff general rates at Nevada Power, partially offset by higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers.

Northern Powergrid

Operating revenue increased $59 million for the second quarter of 2021 compared to 2020, primarily due to $31 million from the weaker United States dollar and higher distribution revenue of $26 million, mainly from 10.9% higher units distributed of $16 million and increased tariff rates of $9 million.

Net income decreased $84 million for the second quarter of 2021 compared to 2020, primarily due to a deferred income tax charge of $109 million related to an enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, partially offset by the higher distribution revenue.

Operating revenue increased $93 million for the first six months of 2021 compared to 2020, primarily due to $52 million from the weaker United States dollar and higher distribution revenue of $39 million, mainly from increased tariff rates of $19 million and 4.7% higher units distributed of $16 million.

Net income decreased $67 million for the first six months of 2021 compared to 2020, primarily due to a deferred income tax charge of $109 million related to an enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, partially offset by the higher distribution revenue and $6 million from the weaker United States dollar.

BHE Pipeline Group

Operating revenue increased $481 million for the second quarter of 2021 compared to 2020, primarily due to $487 million of incremental revenue at BHE GT&S, acquired in November 2020, and higher gas sales at Northern Natural Gas of $14 million (largely offset in cost of sales), partially offset by lower transportation revenue of $27 million at Northern Natural Gas, primarily due to lower volumes and rates.

Net income increased $36 million for the second quarter of 2021 compared to 2020, primarily due to $66 million of incremental net income at BHE GT&S, partially offset by lower earnings of $34 million at Northern Natural Gas, largely due to the lower transportation revenue and a favorable adjustment in 2020 from a rate case settlement.

Operating revenue increased $1,173 million for the first six months of 2021 compared to 2020, primarily due to $1,047 million of incremental revenue at BHE GT&S, higher gas sales of $77 million and higher transportation revenue of $49 million at Northern Natural Gas, each due to the favorable impacts of the February 2021 polar vortex weather event, and higher gas sales at Northern Natural Gas of $28 million (largely offset in cost of sales), partially offset by lower transportation revenue of $50 million at Northern Natural Gas, primarily due to lower volumes and rates.

35

Net income increased $240 million for the first six months of 2021 compared to 2020, primarily due to $173 million of incremental net income at BHE GT&S and higher earnings of $64 million at Northern Natural Gas. Northern Natural Gas' improved performance was primarily due to higher gross margin on gas sales and higher transportation revenue, each due to the favorable impacts of the February 2021 polar vortex weather event, partially offset by the lower transportation revenue due to lower volumes and rates.

BHE Transmission

Operating revenue increased $13 million for the second quarter of 2021 compared to 2020, primarily due to $20 million from the stronger United States dollar, partially offset by the impacts of favorable regulatory decisions received in April and November 2020 at AltaLink.

Operating revenue increased by $21 million for the first six months of 2021 compared to 2020, primarily due to $31 million from the stronger United States dollar and higher revenue from the Montana-Alberta Tie-Line, acquired in May 2020, partially offset by the impacts of favorable regulatory decisions received in April and November 2020 at AltaLink.

Net income increased $4 million for the first six months of 2021 compared to 2020, primarily due to $8 million from the stronger United States dollar, higher earnings from the Montana-Alberta Tie-Line and lower non-regulated interest expense at BHE Canada, partially offset by the impacts of favorable regulatory decisions received in April and November 2020 at AltaLink.

BHE Renewables

Operating revenue increased $23 million for the second quarter of 2021 compared to 2020, primarily due to higher natural gas, solar, geothermal and wind revenues from higher generation as well as higher capacity payments at a natural gas facility, partially offset by an unfavorable change in the valuation of a power purchase agreement of $12 million.

Net income increased $43 million for the second quarter 2021 compared to 2020, primarily due to higher wind earnings of $32 million, largely from tax equity investment projects reaching commercial operation, and higher solar earnings of $9 million, mainly due to the higher operating revenue and lower depreciation expense.

Operating revenue increased $35 million for the first six months of 2021 compared to 2020, primarily due to higher natural gas, solar, geothermal, hydro and wind revenues from higher generation, as well higher capacity payments at a natural gas facility and favorable pricing at the geothermal facilities, partially offset by an unfavorable change in the valuation of a power purchase agreement of $14 million.

Net income decreased $36 million for the first six months of 2021 compared to 2020, primarily due to lower wind earnings of $62 million, largely from lower tax equity investment earnings of $58 million, partially offset by higher solar earnings of $16 million, mainly due to the higher operating revenue and lower depreciation expense, and higher geothermal earnings of $11 million. Tax equity investment earnings decreased due to unfavorable results from existing tax equity investments of $134 million, primarily due to the February 2021 polar vortex weather event, partially offset by $78 million of earnings from projects reaching commercial operation. Geothermal earnings increased primarily due to higher natural gas margins and the higher geothermal revenue, partially offset by higher operations and maintenance expense.

HomeServices

Operating revenue increased $570 million for the second quarter of 2021 compared to 2020, primarily due to higher brokerage revenue of $589 million from a 72% increase in closed transaction volume resulting from increases in closed units and average sales price, partially offset by lower mortgage revenue of $51 million due to a 62% decrease in refinance activity.

Net income increased $76 million for the second quarter of 2021 compared to 2020, primarily due to higher earnings from brokerage services of $54 million, largely due to the increase in closed transaction volume, and mortgage services of $12 million, largely attributable to an unfavorable 2020 contingent earn-out remeasurement offset by the decrease in refinancing activity.

Operating revenue increased $909 million for the first six months of 2021 compared to 2020, primarily due to higher brokerage revenue of $816 million from a 56% increase in closed transaction volume, resulting from increases in closed units and average sales price, and higher mortgage revenue of $41 million from a 26% increase in funded mortgage volume.

36

Net income increased $150 million for the first six months of 2021 compared to 2020, primarily due to higher earnings from brokerage services of $79 million, largely due to the increase in closed transaction volume, and mortgage services of $48 million, largely attributable to an unfavorable 2020 contingent earn-out remeasurement and the increase in funded mortgage volume.

BHE and Other

Operating revenue increased $3 million for the second quarter of 2021 compared to 2020, primarily due to higher electricity sales revenue at MidAmerican Energy Services, LLC, from higher volumes offset by unfavorable pricing.

Net income increased $993 million for the second quarter of 2021 compared to 2020, primarily due to the $1,012 million favorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $48 million of higher federal income tax credits recognized on a consolidated basis and higher net income of $8 million at MidAmerican Energy Services, LLC, partially offset by higher other corporate costs, $38 million of dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020, higher BHE corporate interest expense from debt issuances in March and October 2020 and unfavorable changes in the cash surrender value of corporate-owned life insurance policies.

Operating revenue increased $86 million for the first six months of 2021 compared to 2020, primarily due to higher electricity and natural gas sales revenue at MidAmerican Energy Services, LLC, from favorable pricing offset by lower volumes.

Net income increased $68 million for the first six months of 2021 compared to 2020, primarily due to the $155 million favorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $42 million of higher federal income tax credits recognized on a consolidated basis, favorable changes in the cash surrender value of corporate-owned life insurance policies and higher net income of $12 million at MidAmerican Energy Services, LLC, partially offset by $75 million of dividends on BHE's 4.00% Perpetual Preferred Stock, higher other corporate costs and higher BHE corporate interest expense.

37

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, 2020 for further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of June 30, 2021, 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	$	526	$	44	$	31	$	79	$	17	$	57	$	577	$	1,331
Credit facilities	3,500		1,200		1,509		650		222		867		3,541		11,489
Less:
Short-term debt	—		(301)		—		(74)		(15)		(262)		(1,884)		(2,536)
Tax-exempt bond support and letters of credit	—		(218)		(370)		—		—		(1)		—		(589)
Net credit facilities	3,500		681		1,139		576		207		604		1,657		8,364
Total net liquidity	$	4,026	$	725	$	1,170	$	655	$	224	$	661	$	2,234	$	9,695
Credit facilities:
Maturity dates	2024		2024		2022, 2024		2024		2023		2022, 2025		2021, 2022

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Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2021 and 2020 were $4.2 billion and $1.9 billion, respectively. The increase was primarily due to favorable income tax cash flows, improved operating results and changes in working capital.

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, 2021 and 2020 were $(3.0) billion and $(3.8) billion, respectively. The change was primarily due to lower funding of tax equity investments, partially offset by higher capital expenditures of $55 million. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2021 was $(1.2) billion. Uses of cash totaled $2.0 billion and consisted mainly of repayments of subsidiary debt totaling $1.2 billion, repayments of BHE senior debt totaling $450 million and distributions to noncontrolling interests of $234 million. Sources of cash totaled $793 million and consisted primarily of proceeds from subsidiary debt issuances totaling $539 million and net proceeds from short-term debt totaling $245 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, 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.

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
	2020		2021		2021
Capital expenditures by business:
PacifiCorp	$	973	$	819	$	1,782
MidAmerican Funding	824		720		2,170
NV Energy	366		365		842
Northern Powergrid	312		369		760
BHE Pipeline Group	196		308		1,225
BHE Transmission	222		156		269
BHE Renewables	26		80		181
HomeServices	14		18		37
BHE and Other(1)	(140)		13		78
Total	$	2,793	$	2,848	$	7,344

Capital expenditures by type:
Wind generation	$	718	$	483	$	1,156
Electric distribution	743		817		1,842
Electric transmission	527		339		919
Natural gas transmission and storage	178		308		1,099
Solar generation	1		67		288
Other	626		834		2,040
Total	$	2,793	$	2,848	$	7,344

(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 expenditures include the following:

◦Construction and acquisition of wind-powered generating facilities at MidAmerican Energy totaling $172 million for 2021 and $388 million for 2020. Planned spending for the construction of additional wind-powered generating facilities totals $198 million for the remainder of 2021 and includes 203 MWs of wind-powered generating facilities expected to be placed in-service in 2021.

◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $82 million for 2021 and $19 million for 2020. Planned spending for repowering generating facilities totals $284 million for the remainder of 2021. MidAmerican Energy expects its repowered facilities to meet Internal Revenue Service guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service. The rate at which PTCs are re-established for a facility depends upon the date construction begins. Of the 1,078 MWs of current repowering projects not in-service as of June 30, 2021, 80 MWs are currently expected to qualify for 100% of the PTCs available for 10 years following each facility's return to service, 591 MWs are expected to qualify for 80% of such credits 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 $79 million and $395 million for the six-month periods ended June 30, 2021 and 2020, respectively, and includes the 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs expected to be placed in-service in 2021. The energy production from the new wind-powered generating facilities is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. PacifiCorp's 2019 IRP identified 1,920 MWs of new wind-powered generating resources that are expected to come online in 2024. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp anticipates costs associated with the construction of wind-powered generating facilities will total an additional $39 million for 2021.

◦Repowering of wind-powered generating facilities at PacifiCorp totaling $3 million and $46 million for the six-month periods ended June 30, 2021 and 2020, respectively. The repowering projects entail the replacement of significant components of older turbines. Certain repowering projects for existing facilities were placed in service in 2019, 2020 and in the first six months of 2021. The energy production from these existing repowered facilities is expected to qualify for 100% of the federal PTCs available for 10 years following each facility's return to service. Planned additional spending for repowering of wind-powered generating facilities totals $47 million for 2021.

◦Construction of wind-powered generating facilities at BHE Renewables totaling $55 million for the six-month period ended June 30, 2021. In May 2021, BHE Renewables completed the asset acquisition of a 54 MW wind-powered generating facility located in Iowa. BHE Renewables anticipates costs to complete construction of this facility will total an additional $30 million in 2021.

•Electric distribution includes both growth and operating expenditures. Growth expenditures include new customer connections and enhancements to existing customer connections. Operating expenditures include ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, wildfire mitigation, damage restoration and storm damage repairs and investments in routine expenditures for distribution needed to serve existing and expected demand.

•Electric transmission includes both growth and operating expenditures. Growth expenditures include 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, placed in-service in November 2020, the Nevada Utilities' Greenlink Nevada transmission expansion program and AltaLink's directly assigned projects from the Alberta Electric System Operator. Operating expenditures include system reinforcement, upgrades and replacements of facilities to maintain system reliability and investments in routine expenditures for transmission needed to serve existing and expected demand.

•Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, asset modernization, pipeline integrity projects and natural gas transmission, storage and liquefied natural gas terminalling infrastructure needs to serve existing and expected demand.

•Solar generation includes growth expenditures, including MidAmerican Energy's current plan for the construction of 141 MWs of small- and utility-scale solar generation during 2021, of which 61 MWs are expected to be placed in-service in 2021. Nevada Power's solar generation investment includes expenditures for a 150 MWs solar photovoltaic facility with an additional 100 MWs capacity of co-located battery storage, known as the Dry Lake generating facility. Commercial operation at Dry Lake is expected by the end of 2023.

•Other capital expenditures includes both growth and operating expenditures, including routine expenditures for generation and other infrastructure needed to serve existing and expected demand, natural gas distribution, technology, and environmental spending relating to emissions control equipment and the management of coal combustion residuals.

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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 no contributions for the six-month period ended June 30, 2021, and has commitments as of June 30, 2021, subject to satisfaction of certain specified conditions, to provide equity contributions of $766 million for the remainder of 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, 2021, 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, 2020 other than the recent financing transactions and renewable tax equity investments previously discussed.

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 proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. On October 15, 2020, the FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting the PJM's two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, the FERC also accepted the PJM's proposal to condense the schedule of activities leading up to the next capacity auction but did not specify when that schedule would commence given that a key element of the MOPR level computation remains pending before the FERC in another proceeding.

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

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

In May 2021, the PJM conducted its capacity auction as scheduled, and because Illinois has not implemented an FRR program, the MOPR applied to Quad Cities Station in the capacity auction. The MOPR prevented Quad Cities Station from clearing in the auction.

Assuming the continued effectiveness of the Illinois zero emission standard, Exelon Generation no longer considers Quad Cities Station to be at heightened risk for early retirement. However, to the extent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement. The FERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the Illinois zero emission standard unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism under which Quad Cities Station would be removed from the PJM's capacity auction. At the direction of the PJM Board of Managers, the PJM and its stakeholders are considering MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs, which the PJM filed at the FERC on July 30, 2021.

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, 2020 and new regulatory matters occurring in 2021.

PacifiCorp

Utah

In March 2020, PacifiCorp filed its annual Energy Balancing Account application with the UPSC requesting recovery of $37 million 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. This reflected a 1.0% increase compared to current rates. The UPSC approved the request in February 2021 for rates effective March 1, 2021.

In March 2021, PacifiCorp filed its annual Energy Balancing Account application with the UPSC requesting recovery of $2 million of deferred net power costs from customers for the period January 1, 2020 through December 31, 2020, reflecting the difference between base and actual net power costs in the 2020 deferral period. This reflected a $36 million reduction or 1.7% decrease compared to current rates. In June 2021, PacifiCorp updated the requested recovery to $7 million to correct certain load related data reflected in the initial application. The updated recovery request reflects a $31 million reduction, or 1.5% decrease compared to current rates.

In August 2021, PacifiCorp filed an application with the UPSC for alternative cost recovery of a major plant addition to recover the incremental revenue requirement related to the delayed portions of the Pryor Mountain and TB Flats wind-powered generating facilities that are not currently reflected in rates from the last general rate case. PacifiCorp's request results in a net decrease of $4 million, or 0.2%, in base rates effective January 1, 2022. Requested recovery of $7 million for the capital-related cost is offset by $7 million related to forecast PTCs and $4 million in net power cost savings. Actual PTCs and net power cost will be trued-up in the Energy Balancing Account.

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Oregon

In February 2020, PacifiCorp filed a general rate case, and in December 2020, the OPUC approved a net rate decrease of approximately $24 million, or 1.8%, effective January 1, 2021, accepting PacifiCorp's proposed annual credit to customers of the remaining 2017 Tax Reform benefits over a two-year period. PacifiCorp's compliance filing to reset base rates effective January 1, 2021 in response to the OPUC's order reflected a rate decrease of approximately $67 million, or 5.1%, due to the exclusion of the impacts of repowered wind-powered generating facilities, new wind-powered generating facilities and certain other new investments that had not been placed in service at the time of the filing. Additional compliance filings have been made to include these investments in rates concurrent with when they are placed in service. In January 2021, the OPUC approved the second compliance filing to add the remainder of the Ekola Flats wind-powered generating facility to rates, resulting in a rate increase of approximately $7 million, or 0.5%, effective January 12, 2021. In April 2021, the OPUC approved the third compliance filing to add the Foote Creek repowered wind-powered generating facility and the Pryor Mountain new wind-powered generating facility to rates, resulting in a rate increase of $14 million, or 1.2%, effective April 9, 2021.

In July 2021, in accordance with the OPUC's December 2020 general rate case order, PacifiCorp filed an application with the OPUC to initiate the review of PacifiCorp's estimated decommissioning and other closure costs per third-party studies associated with its coal-fueled generating facilities. The application requested an initial rate increase of $35 million, or 2.8%, effective January 1, 2022, to recover the incremental costs from those approved in the last general rate case.

Wyoming

In September 2018, PacifiCorp filed an application for depreciation rate changes with the WPSC based on PacifiCorp's 2018 depreciation rate study, requesting the rates become effective January 1, 2021. 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 and removal of Cholla Unit 4. 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, including depreciation for coal-fueled generating facilities and associated incremental decommissioning costs reflected in decommissioning studies and certain matters related to the repowering of PacifiCorp's wind-powered generating facilities. The stipulation was approved by the WPSC during a hearing in August 2020 and a subsequent written order in December 2020. The general rate case hearing was rescheduled for February 2021. As a result of the hearing date change, PacifiCorp filed an application in October 2020 with the WPSC requesting authorization to defer costs associated with impacts of the depreciation study. A hearing for this deferral application was held in July 2021. Public deliberations are expected in August 2021.

In March 2020, PacifiCorp filed a general rate case with the WPSC which reflected recovery of Energy Vision 2020 investments, updated depreciation rates, incremental decommissioning costs associated with coal-fueled facilities and rate design modernization proposals. The application also requested a revision to the ECAM to eliminate the sharing band and requested authorization to discontinue operations and recover costs associated with the early retirement of Cholla Unit 4. The proposed increase reflects several rate mitigation measures that include use of the remaining 2017 Tax Reform benefits to buy down plant balances, including Cholla Unit 4, and spreading the recovery of the depreciation of certain coal-fueled generation units over time periods that extend beyond the depreciable lives proposed in the depreciation rate study. In September 2020, PacifiCorp filed its rebuttal testimony that modified its requested increase in base rates from $7 million to $9 million, or 1.3%, and reflected an update to the rate mitigation measures for using the 2017 Tax Reform benefits. The WPSC determined that the rebuttal testimony filed constituted a material and substantial change to the original application and vacated the hearing that was scheduled for October 2020. The WPSC re-noticed PacifiCorp's case and rescheduled the hearings. The hearings began February 2021 and were completed in March 2021. In May 2021, the WPSC approved a $7 million base revenue requirement increase that includes the Energy Vision 2020 investments, updated depreciation rates, incremental decommissioning costs and rate design proposals to be offset by returning the remaining 2017 Tax Reform benefits to customers over the next three years. The WPSC also approved revisions to the ECAM to adjust the sharing band from 70/30 to 80/20 and to include PTCs within the mechanism. PacifiCorp's proposals for extended recovery of the depreciation of certain coal-fueled generation units and use of remaining 2017 Tax Reform benefits to buy down certain plant balances were denied. The WPSC decision results in an overall net decrease of 3.5% with a rate effective date of July 1, 2021. A final written order was issued in July 2021.

In April 2021, PacifiCorp filed its annual ECAM and Renewable Energy Credit and Sulfur Dioxide Revenue Adjustment Mechanism application with the WPSC requesting to refund $15 million of deferred net power costs and RECs to customers for the period January 1, 2020 through December 31, 2020, reflecting the difference between base and actual net power costs in the 2020 deferral period. This reflects a 2.4% decrease compared to current rates. PacifiCorp has requested an interim rate effective date of July 1, 2021, which was approved by the WPSC in June 2021. A hearing has been scheduled for November 2021.

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Washington

In June 2021, PacifiCorp filed a power cost only rate case to update baseline net power costs for 2022. The proposed $13 million, or 3.7%, rate increase has a requested effective date of January 1, 2022.

Idaho

In March 2021, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $14 million for deferred costs in 2020, a 1.1% decrease compared to current rates. 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 new wind and wind repowering projects until they are reflected in base rates. In May 2021, PacifiCorp updated the requested recovery to correct for certain load related data reflected in the initial application, and the IPUC approved recovery of $10 million for deferred costs, a 2.5% decrease compared to current rates, effective June 1, 2021.

In May 2021, PacifiCorp filed a general rate case with the IPUC requesting a $19 million, or 7.0%, revenue requirement increase effective January 1, 2022. This is the first general rate case PacifiCorp has filed in Idaho since 2011. The rate case includes recovery of Energy Vision 2020 investments, Pryor Mountain wind-powered generating facilities, repowering Foote Creek, new investment in transmission, updated depreciation rates, incremental decommissioning costs associated with coal-fueled facilities and rate design modernization proposals. The application also requested recovery of the decommissioning and closure costs associated with the early retirement of Cholla Unit 4.

California

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. PacifiCorp submitted its 2021 California Wildfire Mitigation Plan Update in March 2021.

FERC Show Cause Order

On April 15, 2021, the FERC issued an order to show cause and notice of proposed penalty related to allegations made by FERC Office of Enforcement staff that PacifiCorp failed to comply with certain North American Electric Reliability Corporation (the "NERC") reliability standards associated with facility ratings on PacifiCorp's bulk electric system. The order directs PacifiCorp to show cause as to why it should not be assessed a civil penalty of $42 million as a result of the alleged violations. The allegations are related to PacifiCorp's response to a 2010 industry-wide effort directed by the NERC to identify and remediate certain discrepancies resulting from transmission facility design and actual field conditions, including transmission line clearances. In July 2021, PacifiCorp filed its answer to the FERC's show cause order denying the alleged violation of certain NERC reliability standards. The FERC's reply is due in September 2021.

MidAmerican Energy

Natural Gas Purchased for Resale

In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. To mitigate the impact to customers, the IUB ordered the recovery of these higher costs to be applied to customer bills over the period April 2021 through April 2022 based on a customer's monthly natural gas usage. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the six-month period ended June 30, 2021.

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Renewable Subscription Program

In December 2020, MidAmerican Energy filed with the IUB a proposed Renewable Subscription Program ("RSP") tariff. As proposed, the program would provide qualified industrial customers with the opportunity to meet their future energy growth above baseline levels with renewable energy from specific MidAmerican Energy wind-powered generation additions and 100 MWs of planned solar generation for 20 years at fixed prices based on the cost of such facilities. Under the program, MidAmerican Energy would own the facilities, retain PTCs and other tax benefits associated with the facilities and include all revenues and costs from the program in its Iowa-jurisdictional results of operation, but renewable attributes from the project would be specifically assigned to subscribing customers. In June 2021, the IUB rejected the proposed RSP tariff. In a separate docket, the IUB ordered the exclusion from MidAmerican Energy's energy adjustment clause all PTCs and energy benefits associated with projects addressed in the RSP, resulting in MidAmerican Energy retaining such benefits.

NV Energy (Nevada Power and Sierra Pacific)

Price Stability Tariff

In November 2018, the Nevada Utilities made filings with the PUCN to implement the 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 Deferred Energy Accounting Adjustment. The goal is to have an energy rate that yields an all-in effective rate that is competitive with market options available to such customers. In February 2019, the PUCN granted several intervenors the ability to participate in the proceeding. In June 2019, the Nevada Utilities withdrew their filings. In May 2020, the Nevada Utilities refiled the CPST incorporating the considerations raised by the PUCN and other intervenors and a hearing was held in September 2020. In November 2020, the PUCN issued an order approving the tariff with modified pricing and directing the Nevada Utilities to develop a methodology by which all eligible participants may have the opportunity to participate in the CPST program up to a limit with the same proportion of governmental entities' and non-governmental entities' MWh reserved for potentially interested customers as filed. In December 2020, the Nevada Utilities filed a petition for reconsideration of the pricing ordered by the PUCN. In January 2021, the PUCN issued an order reaffirming its order from November 2020 and denying the petition for a rehearing. In the first quarter of 2021, the Nevada Utilities filed an update to the CPST program per the November 2020 order and an updated CPST with the PUCN. The enrollment period for the tariff has ended with no customers having enrolled. A final order has not been issued but because no customers have enrolled the order may be dismissed or withdrawn and the tariff will not go into effect. A final order is expected in 2021.

Natural Disaster Protection Plan

The Nevada Utilities submitted their initial natural disaster protection plan to the PUCN and filed their first application seeking recovery of 2019 expenditures in February 2020. In June 2020, a hearing was held and an order was issued in August 2020 that granted the joint application, made minor adjustments to the budget and approved the 2019 costs for recovery starting in October 2020. In October 2020, intervening parties filed petitions for reconsideration. Intervenors have filed a petition for judicial review with the District Court in November 2020. In December 2020, the PUCN issued a second modified final order approving the natural disaster protection plan, as modified, and reopened its investigation and rulemaking on Senate Bill 329 to address rate design issues raised by intervenors. The comment period for the reopened investigation and rulemaking ended in early February 2021 and an order is expected in 2021. In March 2021, the Nevada Utilities filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial natural disaster protection plan that was ordered by the PUCN and filed their first amendment to the 2020 natural disaster protection plan. A hearing related to the application for approval of the first amendment to the 2020 natural disaster protection plan was held in June 2021. The Nevada Utilities filed a partial party stipulation resolving all issues. One of the intervening parties filed an opposition to the partial party stipulation and other intervenors filed legal briefs. The partial party stipulation was approved by the PUCN in June 2021 with the lone dissenting party retaining the right to argue a single issue in future proceedings with the primary issue being a single statewide rate for cost recovery. A separate docket remains open regarding the regulatory asset account and the cost recovery mechanism. Parties have submitted testimony and a hearing occurred in July 2021.

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Senate Bill 448 ("SB 448")

SB 448 was signed into law on June 10, 2021. The legislation is intended to accelerate transmission development, renewable energy and storage within the state of Nevada and requires the Nevada Utilities to submit a plan to accelerate transportation electrification in the state and file a plan for certain high-voltage transmission infrastructure projects. SB 448 requires the Nevada Utilities to amend its most recently filed resource plan to include a plan for certain high-voltage transmission infrastructure construction projects that will be placed into service not later than December 31, 2028 and requires the IRP to include at least one scenario of low carbon dioxide emissions that uses sources of supply that will achieve certain reductions in carbon dioxide emissions. SB 448 also requires the Nevada Utilities, on or before September 1, 2021, to file a plan to invest in certain transportation electrification programs during the period beginning January 1, 2022, and ending on December 31, 2024, and establishes requirements for the contents of the transportation electrification investment plan for that period. It also establishes requirements for the review and the acceptance or modification of the transportation electrification investment plan by the PUCN. The PUCN has not yet addressed the regulations in SB 448.

Northern Powergrid Distribution Companies

In December 2020, GEMA, through Ofgem, published its final determinations for transmission and gas distribution networks in Great Britain. Regarding the allowed return on capital, Ofgem determined a cost of equity of 4.55% (plus inflation calculated using the United Kingdom's consumer price index including owner occupiers' housing costs ("CPIH")). In March 2021, all the transmission and gas distribution networks lodged appeals with the Competition and Markets Authority against Ofgem's determination for the cost of equity, with an outcome expected in October 2021. These determinations do not apply directly to Northern Powergrid, but aspects of the proposals are capable of application at Northern Powergrid's next price control, ("ED2"), which will begin in April 2023.

In December 2020, GEMA published its decision on the methodology it will use to set the next electricity distribution price control, ED2, and prices from April 2023 to March 2028. This confirmed that Ofgem will apply many aspects of the proposals from the transmission and gas distribution price controls to electricity distribution, and that the financial aspects in respect of electricity distribution would broadly follow the transmission and gas distribution methodology, setting a working assumption for a cost of equity at 4.65% (plus CPIH), ahead of the final determinations in late 2022. When placed on a comparable footing, by adjusting for differences in the assumed equity ratio and the measure of inflation used, the working assumption for ED2 is approximately 150 basis points lower than the current cost of equity.

In July 2021, Northern Powergrid submitted and published its draft business plan for April 2023 to March 2028. If adopted, this plan would involve annual capital and operating expenditures of £642 million, an increase relative to the £471 million average annual capital and operating expenditures expected over the current price control period (April 2015 to March 2023). A final business plan submission for 2023-2028 will be submitted in December 2021, ahead of GEMA's draft and final determinations which are expected around June and December 2022, respectively. A new price control can be implemented by GEMA without the consent of the licensee but, if a licensee disagrees with the decision, it can appeal the matter to the United Kingdom’s Competition and Markets Authority. In general terms, an appeal may also be sought by another licensee whose interests are materially affected by the decision, a trade association that represents a licensee and Citizens Advice, as the representative of consumers whose interests are materially affected by the decision.

BHE Pipeline Group

BHE GT&S

In January 2020, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective March 1, 2020. Cove Point proposed an annual cost-of-service of $182 million. In February 2020, the FERC approved suspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund. In November 2020, Cove Point reached an agreement in principle with the active participants in the general rate case proceeding. Under the terms of the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual revenues of $4 million and a decrease in annual depreciation expense of $1 million, compared to the rates in effect prior to August 1, 2020. The interim settlement rates were implemented November 1, 2020, and Cove Point's provision for rate refunds for August 2020 through October 2020 totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC in January 2021. In March 2021, the FERC approved the stipulation and agreement and the rate refunds to customers were processed in late April.

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BHE Transmission

AltaLink

Tariff Refund Application

In January 2021, driven by the pandemic and economic shutdown that has negatively impacted all Albertans, AltaLink filed an application with the AUC that requested approval of tariff relief measures totaling C$350 million over the three-year period, 2021 to 2023. The tariff relief measures consist of a proposed refund to customers of C$150 million of previously collected future income taxes and C$200 million of surplus accumulated depreciation.

In March 2021, the AUC issued a decision on AltaLink's Tariff Refund Application and approved a 2021 customer tariff refund in the amount of C$230 million and a net 2021 tariff reduction of C$224 million, which provides Alberta customers with immediate tariff relief in 2021. The approved 2021 tariff refund includes a refund of C$150 million of previously collected future income tax and a refund of C$80 million of accumulated depreciation surplus. Tariff relief measures for years 2022 and 2023 were proposed in AltaLink's 2022-2023 GTA.

In April 2021, the AUC confirmed its approval of AltaLink's customer tariff refund as provided in the decision issued in March 2021 and detailed its reasons for the decision. Specifically, the AUC found that the exceptional circumstances faced by Alberta customers in 2021 have brought to bear an unprecedented need for rate relief that has not existed previously. These exceptional circumstances include the current economic downturn due to COVID-19, the collapse in the world price of oil and the resulting significant negative impact to Albertans and businesses. As a result, immediate and temporary relief was warranted.

2019-2021 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 proposed to provide a further tariff reduction over the three year period 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 Accounts Reconciliation Application. The application requested the approval of revised revenue requirements of C$879 million, C$882 million and C$885 million for 2019, 2020 and 2021, respectively.

In July 2019, AltaLink filed a 2019-2021 partial negotiated settlement application with the AUC. The application consisted of negotiated reductions that resulted in a net decrease of C$38 million to the three year total revenue requirement applied for in AltaLink's 2019-2021 GTA updated in April 2019. However, this was offset by AltaLink's request for an additional C$20 million of forecast transmission line clearance capital as part of an excluded matter. The 2019-2021 negotiated settlement agreement excluded certain matters related to the new salvage study and salvage recovery approach, additional capital spending and incremental asset retirements. AltaLink's salvage proposal is estimated to save customers C$267 million between 2019 and 2023. Excluded matters were examined by the AUC in a hearing held in November 2019, with written arguments filed in January 2020.

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. The AUC approved, on a placeholder basis, C$13 million of the additional C$20 million AltaLink requested for forecast transmission line clearance capital. The remaining C$7 million of capital investment was reviewed in AltaLink's subsequent compliance filing. Also, C$3 million of forecast operating expenses and C$4 million of forecast capital expenditures related to fire risk mitigation were approved, with an additional C$31 million of capital expenditures reviewed in the compliance filing. Finally, the AUC approved C$6 million of retirements for towers and fixtures.

In July 2020, the AUC approved AltaLink's compliance filing establishing revised revenue requirements of C$895 million for 2019, C$894 million for 2020 and C$898 million for 2021, exclusive of the assets transferred to the PiikaniLink Limited Partnership and the KainaiLink Limited Partnership.

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The AUC deferred its decision on AltaLink's proposed salvage methodology included in AltaLink's 2019-2021 GTA, pending a generic proceeding to consider the broader implications. This generic proceeding was closed and in July 2020, AltaLink filed an application with the AUC for the review and variance of the AUC's decision with respect to AltaLink's proposed salvage methodology. In September 2020, the AUC granted this review on the basis that there were changed circumstances that could lead the AUC to materially vary or rescind the majority hearing panel's findings on AltaLink's proposed salvage methodology. In October 2020, AltaLink filed responses to information requests from the AUC, written argument was filed by intervening parties and written reply argument was filed by AltaLink. In November 2020, the AUC issued its decision on AltaLink's review and variance application. The AUC decided to vary the original decision and approve AltaLink's proposed net salvage method and the revised transmission tariffs as filed, effective December 2020. The new salvage methodology decreased the amount of salvage pre-collection resulting in reductions to AltaLink's revenue requirement from customers by C$24 million, C$27 million and C$31 million for the years 2019, 2020 and 2021, respectively. AltaLink delivered on the first three years of its commitment to customers to keep rates flat for five years by obtaining the necessary AUC approvals. AltaLink's approved 2019-2021 GTA maintains customer rates below the 2018 level of C$904 million from 2019 to 2021.

In March 2021, the AUC approved AltaLink's Tariff Refund Application resulting in a revised revenue requirement of C$873 million and revised transmission tariff of C$633 million for 2021.

2022-2023 General Tariff Application    

In April 2021, AltaLink filed its 2022-2023 GTA delivering on the last two years of its commitment to keep rates flat for customers at or below the 2018 level of C$904 million for the five-year period from 2019 to 2023. The two-year application achieves flat tariffs by continuing to transition to the AUC-approved salvage recovery method and continuing the use of the flow-through income tax method, with an overall year over year increase of approximately 2% in 2022 and 2023 revenue requirements. In addition, similar to the C$80 million refund of the previously collected accumulated depreciation surplus approved by the AUC for 2021, AltaLink proposed to provide further similar tariff reductions over the two years by refunding an additional C$60 million per year. The application requested the approval of transmission tariffs of C$824 million and C$847 million for 2022 and 2023, respectively.

2022 Generic Cost of Capital Proceeding

In December 2020, the AUC initiated the 2022 generic cost of capital proceeding. This proceeding considered the return on equity and deemed equity ratios for 2022 and one or more additional test years. Due to the uncertainty as a result of the ongoing COVID-19 pandemic, before establishing a process schedule, the commission requested participants to submit comments that addressed the following: (i) the continuation of the currently approved return on equity and deemed equity ratios for a further period of time; (ii) the appropriate test period for the proceeding; (iii) the scope of the proceeding, including whether a formula-based approach to return on equity should be utilized; (iv) the considerations to take into account when establishing the process for the proceeding; and (v) the avoidance of duplicative evidence and greater coordination and collaboration between parties.

In January 2021, AltaLink submitted a letter to the AUC stating that due to ongoing capital market volatility and other COVID-19 related uncertainties there are reasonable grounds for extending the currently approved 2021 return on equity and deemed equity ratio on a final basis for 2022. AltaLink further stated there is insufficient time to complete a full generic cost of capital proceeding in 2021, in order to issue a decision prior to the beginning of 2022 and a formula-based approach should not be considered at this time. AltaLink suggested that a proceeding could be restarted in the third quarter of 2021, for 2023 and subsequent years.

In March 2021, the AUC issued its decision with respect to setting the return on equity and deemed equity ratios for AltaLink. The AUC approved an equity return of 8.5% and an equity ratio of 37% for 2022, based on continuing economic and market uncertainties, the unsettled nature of capital markets, and the need for certainty and stability for Alberta customers.

In April 2021, the Utilities Consumer Advocate filed an application with the Court of Appeal of Alberta requesting permission to appeal the AUC's decision that set the return on equity of 8.5% and equity ratio of 37% on a final basis for 2022. In the appeal, the Utilities Consumer Advocate alleged that the AUC erred by failing to fulfil its statutory obligation of establishing a fair return and by failing to apply procedural fairness. The Utilities Consumer Advocate additionally filed an application with the AUC for review and variance of the AUC's decision. The basis for the application was the same as the permission to appeal filed with the Court of Appeal.

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2019 Deferral Accounts Reconciliation Application

In October 2020, AltaLink filed its application with the AUC, which includes 10 projects with total gross capital additions of C$129 million, including applicable AFUDC. In December 2020, AltaLink provided responses to AUC information requests, interveners filed written argument and AltaLink filed reply argument.

In March 2021, the AUC issued its decision on AltaLink's 2019 Deferral Accounts Reconciliation Application. The AUC approved C$128 million of the C$128.5 million of gross capital project additions, disallowing C$0.5 million of capital costs. The AUC also approved the other deferral accounts for taxes other than income taxes, long-term debt and annual structure payments as filed. AltaLink filed its compliance filing in April 2021. In May 2021, the AUC issued its decision approving the compliance filing application as filed.

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, 2020, and new environmental matters occurring in 2021.

Climate Change

In December 2015, an international agreement was negotiated by 195 nations to create a universal framework for coordinated action on climate change in what is referred to as the Paris Agreement. The Paris Agreement reaffirms the goals of limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius and reaching a global peak of greenhouse gas emissions as soon as possible to achieve climate neutrality by mid-century; establishes commitments by all parties to make nationally determined contributions and pursue domestic measures aimed at achieving the commitments; commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the United States agreed to reduce GHG emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global GHG emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. On June 1, 2017, President Trump announced the United States would begin the process of withdrawing from the Paris Agreement. The United States completed its withdrawal from the Paris Agreement on November 4, 2020. President Biden accepted the terms of the climate agreement January 20, 2021, and the United States completed its reentry February 19, 2021. At a Climate Leaders Summit held April 22 through April 23, 2021, President Biden announced new climate goals to cut GHG 50%-52% economy-wide by 2030 compared to 2005 levels, and to reach 100% carbon pollution-free electricity by 2035. Additional details on how the United States will implement these goals is anticipated to be released through fall 2021.

Regional and State Activities

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

•On July 27, 2021, the governor of Oregon signed House Bill 2021, which requires utilities to reduce GHG emissions to meet certain clean energy targets. The bill sets a baseline of the average of 2010, 2011, and 2012 emissions and requires utilities to meet the following reductions from that baseline: 80% by 2030, 90% by 2035 and 100% by 2040. No earlier than January 1, 2022, PacifiCorp must file a clean energy plan with the OPUC showing how it will meet the clean energy targets.

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•On May 17, 2021, the state of Washington passed the Climate Commitment Act (Senate Bill 5126), which creates an economy-wide cap-and-trade program to reduce GHG emissions. Under the Climate Commitment Act, the Washington Department of Ecology must establish progressively declining annual allowance budgets for emissions of GHG beginning January 1, 2023. PacifiCorp is subject to the Climate Commitment Act as an importer of electricity into Washington.

Clean Air Act Regulations

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

GHG Performance Standards

Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilities with the "Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the D.C. Circuit and oral argument was scheduled for April 17, 2017. However, oral argument was deferred and the court held the case in abeyance for an indefinite period of time. On December 6, 2018, the EPA announced revisions to new source performance standards for new and reconstructed coal-fueled units. EPA proposes to revise carbon dioxide emission limits for new coal-fueled facilities to 1,900 pounds per MWh for small units and 2,000 pounds per MWh for large units. The EPA would define the best system of emission reduction for new and modified units as the most efficient demonstrated steam cycle, combined with best operating practices. On January 12, 2021, EPA finalized a rule focused solely on a significant contribution finding for purposes of regulating source categories' GHG emissions. The final rule sets no specific regulatory standards and contains no regulatory text, nor does it address what constitutes the best system of emission reduction for new, modified and reconstructed electric generating units. EPA confirms in the "significant contribution" rule that electric generating units remain a listed source category under Clean Air Act Section 111(b), reaching that conclusion through the introduction of an emissions threshold framework by which a source category is deemed to contribute significantly to dangerous air pollution due to their GHG emissions if the amount of those emissions exceeds 3% of total GHG emissions in the United States. Under this methodology, no other source category would qualify for regulation. The significant contribution rule will take effect 60 days after publication in the Federal Register but is expected to be quickly revisited by the Biden administration. Because the significant contribution rule did not alter the emission limits or technology requirements of the 2015 rule, any new fossil-fueled generating facilities will be required to meet the GHG new source performance standards. The D.C. Circuit vacated the significant contribution rule April 5, 2021, remanding it for further proceedings.

New Source Performance Standards for Methane Emissions

In August 2020, the EPA finalized regulations to rescind standards for methane emissions from the oil and gas sector. The changes eliminate requirements to regulate methane emissions from the production, processing, transmission and storage of oil and gas. On June 30, 2021, President Biden signed into law a resolution that rescinded the August 2020 rule and reinstated a rule promulgated in 2016. The primary effect of the resolution is that the 2020 rule is treated as never having taken effect. The EPA is developing guidance for stakeholders to comply with the 2016 rule. In addition, reinstating methane rules for new sources imposes a requirement for EPA to also issue rules for existing sources. Until such time as additional regulatory action is taken and litigation is exhausted, the relevant Registrants cannot determine whether additional action may be required.

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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, NOx, 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. 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 June 2010, the EPA finalized a new NAAQS for SO2. Under the 2010 rule, areas must meet a one-hour standard of 75 parts per billion utilizing a three-year average. The rule utilizes source modeling in addition to the installation of ambient monitors where SO2 emissions impact populated areas. Attainment designations were due by June 2012; however, citing a lack of sufficient information to make the designations, the EPA did not issue its final designations until July 2013 and determined, at that date, that a portion of Muscatine County, Iowa was in nonattainment for the one-hour SO2 standard. MidAmerican Energy's Louisa coal-fueled generating facility is located just outside of Muscatine County, south of the violating monitor. In its final designation, the EPA indicated that it was not yet prepared to conclude that the emissions from the Louisa coal-fueled generating facility contribute to the monitored violation or to other possible violations, and that in a subsequent round of designations, the EPA will make decisions for areas and sources outside Muscatine County. MidAmerican Energy does not believe a subsequent nonattainment designation will have a material impact on the Louisa coal-fueled generating facility. Although the EPA's July 2013 designations did not impact PacifiCorp's nor the Nevada Utilities' generating facilities, the EPA's assessment of SO2 area designations will continue with the deployment of additional SO2 monitoring networks across the country. On February 25, 2019, the EPA issued a decision to retain the 2010 SO2 NAAQS without revision.

The Sierra Club filed a lawsuit against the EPA in August 2013 with respect to the one-hour SO2 standards and its failure to make certain attainment designations in a timely manner. In March 2015, the United States District Court for the Northern District of California ("Northern District of California") accepted as an enforceable order an agreement between the EPA and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed the EPA to complete designations in three phases: the first phase by July 2, 2016; the second phase by December 31, 2017; and the final phase by December 31, 2020. The first phase of the designations require the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2010 SO2 standard; and 2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of SO2 in 2012 or emitted more than 2,600 tons of SO2 and had an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012 and, as of March 2, 2015, had not been announced for retirement. MidAmerican Energy's George Neal Unit 4 and the Ottumwa Generating Station (in which MidAmerican Energy has a majority ownership interest, but does not operate), are included as units subject to the first phase of the designations, having emitted more than 2,600 tons of SO2 and having an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012. States may submit to the EPA updated recommendations and supporting information for the EPA to consider in making its determinations. Iowa submitted documentation to the EPA in April 2016 supporting its recommendation that Des Moines, Wapello and Woodbury Counties be designated as being in attainment of the standard. In July 2016, the EPA's final designations were published in the Federal Register indicating portions of Muscatine County, Iowa were in nonattainment with the 2010 SO2 standard, Woodbury County, Iowa was unclassifiable, and Des Moines and Wapello Counties were unclassifiable/attainment. On March 26, 2021, the EPA issued the last of its final designations for the 2010 primary SO2 standard. Included in this round was designation of Converse County, Wyoming as an Attainment/Unclassifiable area. PacifiCorp's Dave Johnston generating facility is located in Converse County. No further action by PacifiCorp is required.

Cross-State Air Pollution Rule

The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate matter, from down-wind sources in the eastern United States, including Iowa, to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate transport of SO2 and NOx emissions in 27 eastern and Midwestern states.

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The first phase of the rule was implemented January 1, 2015. In November 2015, the EPA released a proposed rule that would further reduce NOx emissions in 2017. The final "CSAPR Update Rule" was published in the Federal Register in October 2016 and required additional reductions in NOx emissions beginning in May 2017. On December 6, 2018, EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. EPA determined that 2023 is an appropriate future analytic year to evaluate remaining good neighbor obligations and that there will be no remaining nonattainment or maintenance receptors with respect to the 2008 ozone NAAQS in the eastern United States in that year. Accordingly, the 20 CSAPR Update-affected states would not contribute significantly to nonattainment in, or interfere with maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the CSAPR Update and the CSAPR Close-Out rules were challenged in the D.C. Circuit. The D.C. Circuit ruled September 13, 2019, that because the EPA allowed upwind States to continue to significantly contribute to downwind air quality problems beyond statutory deadlines, the CSAPR Update Rule provided only a partial remedy that did not fully address interstate ozone transport, and remanded the CSAPR Update Rule back to the EPA. The D.C. Circuit issued an opinion October 1, 2019, finding that because the CSAPR Close-Out Rule relied on the same faulty reasoning as the CSAPR Update rule, the CSAPR Close-Out Rule must be vacated. On October 15, 2020, the EPA proposed to tighten caps on emissions of NOx from power plants in 12 states in the CSAPR trading program in response to the D.C. Circuit's decision to vacate the CSAPR Update rule. The rule is intended to fully resolve 21 upwind states' remaining good neighbor obligations under the 2008 ozone NAAQS. Additional emissions reductions are required at power plants in 12 states, including Illinois; the EPA predicts that emissions from the remaining nine states, including Iowa and Texas, will not significantly contribute to downwind states' ability to attain or maintain the ozone standard. The EPA accepted comment on the proposal through December 15, 2020. On March 15, 2021, the EPA finalized the Revised CSAPR Update largely as proposed. Significant new compliance obligations are not anticipated as a result of the rule.

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 BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.

The state of Wyoming issued two regional haze SIPs requiring the installation of SO2, NOx 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 Court of Appeals ("Tenth Circuit") in October 2014. In addition, the EPA initially proposed in June 2012 to disapprove portions of the NOx and particulate matter SIP and instead issue a FIP. The EPA withdrew its initial proposed actions on the NOx 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-NOx 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-NOx burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility, requiring the installation of SCR controls within five years (i.e., by 2019). The EPA action became final on March 3, 2014. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming also filed an appeal of the EPA's final action, as did the Powder River Basin Resource Council, National Parks Conservation Association and Sierra Club. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit in the appeal. The EPA, U.S. Department of Justice, state of Wyoming and PacifiCorp executed a settlement agreement December 16, 2020, removing the requirement to install SCR in lieu of monthly and annual NOx emissions limits. The settlement agreement was subject to a comment period which ended July 6, 2021. Litigation in the Tenth Circuit remains stayed pending finalization of the settlement agreement.

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The state of Utah issued a regional haze SIP requiring the installation of SO2, NOx 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 NOx 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 NOx controls and require the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a 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 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. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. On June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporates a BART alternative into Utah's regional haze SIP. The BART alternative makes the shutdown of PacifiCorp's Carbon plant enforceable under the SIP and removes the requirement to install SCR technology on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of Air Quality submitted the SIP revision to the EPA for approval at 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 NOx controls and emission limits on the Hunter and Huntington plants. The proposed approval withdraws the FIP requirements to install SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With the approval, the EPA also finalized its withdrawal of the FIP requirements for the Hunter and Huntington plants. The Utah Regional Haze SIP Alternative took effect December 28, 2020. As a result of these actions, the Tenth Circuit dismissed the Utah regional haze petitions on January 11, 2021. On January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. PacifiCorp and the state of Utah moved to intervene in the litigation, which has been stayed pending the Biden administration's review of the rule.

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, 2020. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2020.

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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, 2021, the related consolidated statements of operations and changes in shareholders' equity for the three-month and six-month periods ended June 30, 2021 and 2020, and of cash flows for the six-month periods ended June 30, 2021 and 2020, 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, 2020, 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 26, 2021, 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, 2020, 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 6, 2021

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,		December 31,
	2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	44	$	13
Trade receivables, net	714		703
Other receivables, net	62		48
Inventories	474		482
Derivative contracts	99		27
Regulatory assets	86		116
Prepaid expenses	66		79
Other current assets	18		55
Total current assets	1,563		1,523
Property, plant and equipment, net	22,675		22,430
Regulatory assets	1,339		1,279
Other assets	506		470
Total assets	$	26,083	$	25,702

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,
	2021		2020
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	667	$	772
Accrued interest	125		127
Accrued property, income and other taxes	136		80
Accrued employee expenses	106		84
Short-term debt	301		93
Current portion of long-term debt	479		420
Regulatory liabilities	124		115
Other current liabilities	221		174
Total current liabilities	2,159		1,865
Long-term debt	7,735		8,192
Regulatory liabilities	2,753		2,727
Deferred income taxes	2,715		2,627
Other long-term liabilities	1,154		1,118
Total liabilities	16,516		16,529
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	5,105		4,711
Accumulated other comprehensive loss, net	(19)		(19)
Total shareholders' equity	9,567		9,173
Total liabilities and shareholders' equity	$	26,083	$	25,702

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

58

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2021		2020		2021		2020
Operating revenue	$	1,298	$	1,144	$	2,540	$	2,350
Operating expenses:
Cost of fuel and energy	441		383		865		800
Operations and maintenance	255		243		514		497
Depreciation and amortization	275		210		539		462
Property and other taxes	43		52		104		101
Total operating expenses	1,014		888		2,022		1,860
Operating income	284		256		518		490
Other income (expense):
Interest expense	(105)		(110)		(212)		(212)
Allowance for borrowed funds	6		12		12		22
Allowance for equity funds	12		23		25		44
Interest and dividend income	5		3		11		6
Other, net	4		8		10		4
Total other income (expense)	(78)		(64)		(154)		(136)
Income before income tax (benefit) expense	206		192		364		354
Income tax (benefit) expense	(19)		26		(30)		12
Net income	$	225	$	166	$	394	$	342

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, 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
Balance, March 31, 2021	$	2	$	—	$	4,479	$	4,880	$	(19)	$	9,342
Net income	—		—		—		225		—		225
Balance, June 30, 2021	$	2	$	—	$	4,479	$	5,105	$	(19)	$	9,567
Balance, December 31, 2020	$	2	$	—	$	4,479	$	4,711	$	(19)	$	9,173
Net income	—		—		—		394		—		394
Balance, June 30, 2021	$	2	$	—	$	4,479	$	5,105	$	(19)	$	9,567

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,
	2021		2020
Cash flows from operating activities:
Net income	$	394	$	342
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	539		462
Allowance for equity funds	(25)		(44)
Changes in regulatory assets and liabilities	(98)		(12)
Deferred income taxes and amortization of investment tax credits	22		(24)
Other, net	(1)		1
Changes in other operating assets and liabilities:
Trade receivables, other receivables and other assets	(10)		46
Inventories	8		(80)
Derivative collateral, net	35		7
Prepaid expenses	12		(1)
Accrued property, income and other taxes, net	79		38
Accounts payable and other liabilities	91		35
Net cash flows from operating activities	1,046		770
Cash flows from investing activities:
Capital expenditures	(819)		(973)
Other, net	—		29
Net cash flows from investing activities	(819)		(944)
Cash flows from financing activities:
Proceeds from long-term debt	—		987
Repayments of long-term debt	(400)		—
Net proceeds from (repayments of) short-term debt	208		(130)
Other, net	(4)		—
Net cash flows from financing activities	(196)		857
Net change in cash and cash equivalents and restricted cash and cash equivalents	31		683
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	19		36
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	50	$	719

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, 2021 and for the three- and six-month periods ended June 30, 2021 and 2020. 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, 2021 and 2020. The results of operations for the three- and six-month periods ended June 30, 2021 and 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 PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2020 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, 2021.

(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 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, 2021 and December 31, 2020, 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,
	2021		2020
Cash and cash equivalents	$	44	$	13
Restricted cash included in other current assets	3		4
Restricted cash included in other assets	3		2
Total cash and cash equivalents and restricted cash and cash equivalents	$	50	$	19

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(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	2021		2020
Utility Plant:
Generation	15 - 59 years	$	13,592	$	12,861
Transmission	60 - 90 years	7,740		7,632
Distribution	20 - 75 years	7,815		7,660
Intangible plant(1)	5 - 75 years	1,081		1,054
Other	5 - 60 years	1,529		1,510
Utility plant in service		31,757		30,717
Accumulated depreciation and amortization		(10,180)		(9,838)
Utility plant in service, net		21,577		20,879
Other non-regulated, net of accumulated depreciation and amortization	14 - 95 years	9		9
Plant, net		21,586		20,888
Construction work-in-progress		1,089		1,542
Property, plant and equipment, net		$	22,675	$	22,430

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

Effective January 1, 2021, PacifiCorp revised its depreciation rates based on its recent depreciation study that was approved by its state regulatory commissions, other than in California. The approved depreciation rates resulted in an increase in depreciation expense of approximately $44 million for the three-month period ended June 30, 2021 as compared to the three-month period ended June 30, 2020, and $81 million for the six-month period ended June 30, 2021 compared to the six-month period ended June 30, 2020 based on historical property, plant and equipment balances and including depreciation of certain coal-fueled generating units in Washington over accelerated periods.

(4)    Recent Financing Transactions

Long-term Debt

In July 2021, PacifiCorp issued $1 billion of its 2.90% First Mortgage Bonds due June 2052. PacifiCorp used the net proceeds to finance a portion of the capital expenditures disbursed during the period from July 1, 2019 to May 31, 2021 with respect to investments, primarily from the Energy Vision 2020 initiative, in the repowering of certain of its existing wind-powered generating facilities and the construction and acquisition of new wind-powered generating facilities, which were previously financed with PacifiCorp's general funds.

Credit Facilities

In June 2021, PacifiCorp terminated, upon lender consent, its existing $600 million unsecured credit facility expiring in June 2022. In June 2021, PacifiCorp amended and restated its other existing $600 million unsecured credit facility expiring in June 2022 with one remaining one-year extension option. The amendment increased the lender commitment to $1.2 billion, extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.

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(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,
	2021		2020		2021		2020
Federal statutory income tax rate	21	%	21	%	21	%	21	%
State income tax, net of federal income tax benefit	4		3		4		3
Federal income tax credits	(19)		(9)		(19)		(10)
Effects of ratemaking	(15)		(2)		(14)		(11)
Other	—		1		—		—
Effective income tax rate	(9)	%	14	%	(8)	%	3	%

Income tax credits relate primarily to production tax credits ("PTC") earned by PacifiCorp's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.

Effects of ratemaking for the three- and six-month periods ended June 30, 2021 and 2020 is primarily attributable to the activity associated with excess deferred income taxes, including the use of excess deferred income taxes of $3 million to amortize certain regulatory asset balances in Wyoming during the six-month period ended June 30, 2021 and $30 million to accelerate depreciation of certain retired wind equipment in Oregon during the six-month period ended June 30, 2020.

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 period ended June 30, 2021 PacifiCorp received net cash payments for federal and state income tax from BHE totaling $93 million. For the six-month period ended June 30, 2020 PacifiCorp made net cash payments for federal and state income tax to BHE totaling $42 million.

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(6)    Employee Benefit Plans

Net periodic benefit cost (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,
	2021		2020		2021		2020
Pension:
Service cost	$	—	$	—	$	—	$	—
Interest cost	7		9		14		18
Expected return on plan assets	(14)		(14)		(27)		(28)
Net amortization	5		4		10		9
Net periodic benefit credit	$	(2)	$	(1)	$	(3)	$	(1)
Other postretirement:
Service cost	$	1	$	1	$	1	$	1
Interest cost	2		2		4		5
Expected return on plan assets	(2)		(3)		(4)		(7)
Net amortization	—		—		—		—
Net periodic benefit cost (credit)	$	1	$	—	$	1	$	(1)

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 $1 million, respectively, during 2021. As of June 30, 2021, $2 million of contributions had been made to the pension plans.

(7)    Risk Management and Hedging Activities

PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.

PacifiCorp has established a risk management process that is designed to identify, 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.

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):

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	Other				Other		Other
	Current		Other		Current		Long-term
	Assets		Assets		Liabilities		Liabilities		Total
As of June 30, 2021
Not designated as hedging contracts(1):
Commodity assets	$	118	$	23	$	7	$	—	$	148
Commodity liabilities	(3)		(1)		(26)		(16)		(46)
Total	115		22		(19)		(16)		102
Total derivatives	115		22		(19)		(16)		102
Cash collateral (payable) receivable	(16)		—		5		—		(11)
Total derivatives - net basis	$	99	$	22	$	(14)	$	(16)	$	91
As of December 31, 2020
Not designated as hedging contracts(1):
Commodity assets	$	29	$	6	$	1	$	—	$	36
Commodity liabilities	(2)		—		(23)		(28)		(53)
Total	27		6		(22)		(28)		(17)
Total derivatives	27		6		(22)		(28)		(17)
Cash collateral receivable	—		—		15		9		24
Total derivatives - net basis	$	27	$	6	$	(7)	$	(19)	$	7

(1)PacifiCorp's commodity derivatives are generally included in rates. As of June 30, 2021 a regulatory liability of $102 million was recorded related to the net derivative asset of $102 million. As of December 31, 2020 a regulatory asset of $17 million was recorded related to the net derivative liability of $17 million.

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,
	2021		2020		2021		2020
Beginning balance	$	—	$	84	$	17	$	62
Changes in fair value	(102)		(6)		(119)		28
Net (losses) gains reclassified to operating revenue	(5)		5		(5)		13
Net gains (losses) reclassified to cost of fuel and energy	5		(15)		5		(35)
Ending balance	$	(102)	$	68	$	(102)	$	68

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	2021	2020
Electricity sales, net	Megawatt hours	—	(1)
Natural gas purchases	Decatherms	121	100

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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 recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of June 30, 2021, PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.

The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $42 million and $51 million as of June 30, 2021 and December 31, 2020, respectively, for which PacifiCorp had posted collateral of $5 million and $24 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, 2021 and December 31, 2020, PacifiCorp would have been required to post $27 million and $25 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.

(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.

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The following table presents PacifiCorp's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of June 30, 2021
Assets:
Commodity derivatives	$	—	$	148	$	—	$	(27)	$	121
Money market mutual funds(2)	36		—		—		—		36
Investment funds	31		—		—		—		31
	$	67	$	148	$	—	$	(27)	$	188
Liabilities - Commodity derivatives	$	—	$	(46)	$	—	$	16	$	(30)
As of December 31, 2020
Assets:
Commodity derivatives	$	—	$	36	$	—	$	(3)	$	33
Money market mutual funds(2)	6		—		—		—		6
Investment funds	25		—		—		—		25
	$	31	$	36	$	—	$	(3)	$	64
Liabilities - Commodity derivatives	$	—	$	(53)	$	—	$	27	$	(26)

(1)Represents netting under master netting arrangements and a net cash collateral payable of $11 million and a net cash collateral receivable of $24 million as of June 30, 2021 and December 31, 2020, 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.

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.

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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, 2021				As of December 31, 2020
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	8,214	$	10,133	$	8,612	$	10,995

(9)    Commitments and Contingencies

Legal Matters

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

    California and Oregon 2020 Wildfires

In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon burning over 500,000 acres in aggregate. Third party reports for these wildfires indicate over 2,000 structures, including residences, destroyed; several structures damaged; multiple individuals injured; and several fatalities. Fire suppression costs estimated by various agencies total approximately $150 million. Investigations into the cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the United States Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.

Several lawsuits have been filed in Oregon and California, including a putative class action complaint in Oregon, on behalf of citizens and businesses who suffered damages from fires allegedly caused by PacifiCorp. The final determinations of liability, however, will only be made following comprehensive investigations and litigation processes.

In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages without the utility being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could nevertheless be found liable for all damages proximately caused by negligence, including property and natural resource damage; fire suppression costs; personal injury and loss of life damages; and interest.

As of June 30, 2021, PacifiCorp has accrued $136 million as its best estimate of the potential losses net of expected insurance recoveries associated with the 2020 Wildfires that are considered probable of being incurred. These accruals include estimated losses for fire suppression costs, property damage, personal injury damages and loss of life damages. It is reasonably possible that PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved and the lack of specific claims for all potential claimants. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover at least a portion of the losses.

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Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.

    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 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 mainstem Klamath dams from PacifiCorp to the KRRC. The FERC approved partial transfer of the Klamath license in a July 2020 order, 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. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer application by January 16, 2021 to remove PacifiCorp from the license for the Klamath Hydroelectric Project and add the States and KRRC as co-licensees for the purposes of surrender. On January 13, 2021, the new license transfer application was filed with the FERC, notifying it that PacifiCorp and the KRRC are not accepting co-licensee status under FERC's July 2020 order, and instead are seeking the license transfer outcome described in the new license transfer application. In addition, the MOA provides for additional contingency funding of $45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In June 2021, the FERC approved transfer of the four mainstem Klamath dams from PacifiCorp to the KRRC, the Karuk Tribe, the Yurok Tribe and the States as co-licensees. The transfer will be effective after PacifiCorp secures property transfer approvals from its state public utility commissions and 30 days following the issuance of a license surrender order from the FERC for the project. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions approved the property transfer.

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.

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(10)    Revenue from Contracts with Customers

The following table summarizes PacifiCorp's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2021		2020		2021		2020
Customer Revenue:
Retail:
Residential	$	429	$	384	$	912	$	844
Commercial	393		346		752		704
Industrial	282		268		553		545
Other retail	84		68		116		95
Total retail	1,188		1,066		2,333		2,188
Wholesale (1)	30		17		66		17
Transmission	37		24		62		46
Other Customer Revenue	31		20		54		46
Total Customer Revenue	1,286		1,127		2,515		2,297
Other revenue	12		17		25		53
Total operating revenue	$	1,298	$	1,144	$	2,540	$	2,350

(1)Includes net payments to counterparties for the financial settlement of certain non-derivative forward contracts for energy sales.

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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 2021 and 2020

Overview

Net income for the second quarter of 2021 was $225 million, an increase of $59 million, or 36%, compared to 2020. Net income increased primarily due to higher utility margin of $96 million, favorable income tax expense primarily due to the impacts of ratemaking of $27 million and higher PTCs recognized due to new wind-powered generating facilities placed in-service of $23 million, and lower property taxes of $9 million, partially offset by higher depreciation and amortization expense of $65 million, including the impacts of the depreciation study for which rates became effective January 2021, lower allowances for equity and borrowed funds used during construction of $17 million and higher operations and maintenance expense of $12 million. Utility margin increased primarily due to the higher retail, wheeling, and wholesale revenue, higher deferred net power costs in accordance with established adjustment mechanisms and lower purchased electricity volumes, partially offset by higher purchased electricity prices and higher thermal generation costs. Retail customer volumes increased 11.6%, primarily due to higher customer usage, favorable impacts of weather and an increase in the average number of customers. Energy generated increased 26% for the second quarter of 2021 compared to 2020 primarily due to higher coal-fueled, natural gas-fueled and wind-powered generation, partially offset by lower hydroelectric generation. Wholesale electricity sales volumes increased 33% and purchased electricity volumes decreased 22%.

Net income for the first six months of 2021 was $394 million, an increase of $52 million, or 15%, compared to 2020. Net income increased primarily due to higher utility margin of $125 million, favorable income tax expense primarily from higher PTCs recognized due to new wind-powered generating facilities placed in-service of $37 million, partially offset by higher depreciation and amortization expense of $77 million, including the impacts of the depreciation study for which rates became effective January 2021, lower allowances for equity and borrowed funds used during construction of $29 million, and higher operations and maintenance expense of $17 million. Utility margin increased primarily due to the higher retail, wholesale, and wheeling revenue, higher deferred net power costs in accordance with established adjustment mechanisms and lower purchased electricity volumes, partially offset by higher purchased electricity prices and higher thermal generation costs. Retail customer volumes increased 5.7%, primarily due to higher customer usage, favorable impacts of weather and an increase in the average number of customers. Energy generated increased 16% for the first six months of 2021 compared to 2020 primarily due to higher coal-fueled, wind-powered, and natural gas-fueled generation, partially offset by lower hydroelectric generation. Wholesale electricity sales volumes increased 28% and purchased electricity volumes decreased 17%.

Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as utility margin, to help evaluate results of operations. Utility margin is calculated as operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.

PacifiCorp's cost of fuel and energy is generally recovered from its 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.

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):

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	Second Quarter								First Six Months
	2021		2020		Change				2021		2020		Change
Utility margin:
Operating revenue	$	1,298	$	1,144	$	154	13	%	$	2,540	$	2,350	$	190	8	%
Cost of fuel and energy	441		383		58		15		865		800		65		8
Utility margin	857		761		96		13		1,675		1,550		125		8
Operations and maintenance	255		243		12		5		514		497		17		3
Depreciation and amortization	275		210		65		31		539		462		77		17
Property and other taxes	43		52		(9)		(17)		104		101		3		3
Operating income	$	284	$	256	$	28	11	%	$	518	$	490	$	28	6	%

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Utility Margin

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

	Second Quarter								First Six Months
	2021		2020		Change				2021		2020		Change
Utility margin (in millions):
Operating revenue	$	1,298	$	1,144	$	154	13	%	$	2,540	$	2,350	$	190	8	%
Cost of fuel and energy	441		383		58		15		865		800		65		8
Utility margin	$	857	$	761	$	96	13	%	$	1,675	$	1,550	$	125	8	%
Sales (GWhs):
Residential	4,032		3,656		376		10	%	8,664		8,077		587		7	%
Commercial	4,633		3,948		685		17		9,103		8,358		745		9
Industrial, irrigation and other	5,127		4,759		368		8		9,601		9,461		140		1
Total retail	13,792		12,363		1,429		12		27,368		25,896		1,472		6
Wholesale	1,244		932		312		33		2,835		2,213		622		28
Total sales	15,036		13,295		1,741		13	%	30,203		28,109		2,094		7	%
Average number of retail customers  (in thousands)	1,998		1,964		34		2	%	1,994		1,959		35		2	%
Average revenue per MWh:
Retail	$	86.26	$	86.19	$	0.07	—	%	$	85.21	$	84.51	$	0.70	1	%
Wholesale	$	31.08	$	33.97	$	(2.89)	(9)	%	$	30.97	$	29.56	$	1.41	5	%
Heating degree days	1,228		1,333		(105)		(8)	%	5,915		5,938		(23)		—	%
Cooling degree days	746		439		307		70	%	746		439		307		70	%
Sources of energy (GWhs)(1):
Coal	7,502		6,197		1,305		21	%	15,146		13,425		1,721		13	%
Natural gas	3,223		2,202		1,021		46		6,288		5,243		1,045		20
Hydroelectric(2)	678		891		(213)		(24)		1,601		1,937		(336)		(17)
Wind and other(2)	1,408		864		544		63		3,211		1,976		1,235		63
Total energy generated	12,811		10,154		2,657		26		26,246		22,581		3,665		16
Energy purchased	3,321		4,233		(912)		(22)		6,349		7,624		(1,275)		(17)
Total	16,132		14,387		1,745		12	%	32,595		30,205		2,390		8	%
Average cost of energy per MWh:
Energy generated(3)	$	17.84	$	17.19	$	0.65	4	%	$	17.75	$	17.53	$	0.22	1	%
Energy purchased	$	65.62	$	38.25	$	27.37	72	%	$	56.80	$	42.33	$	14.47	34	%

(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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Quarter Ended June 30, 2021 compared to Quarter Ended June 30, 2020

Utility margin increased $96 million, or 13%, for the second quarter of 2021 compared to 2020 primarily due to:

•$124 million increase in retail revenue primarily due to higher customer volumes, partially offset by lower rates due to certain general rate case orders. Retail customer volumes increased 11.6%, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers;

•$56 million of higher deferred net power costs in accordance with established adjustment mechanisms;

•$14 million of higher wheeling revenue; and

•$7 million of higher wholesale revenue from higher wholesale volumes, partially offset by lower average wholesale market prices.

The increases above were partially offset by:

•$55 million of higher purchased electricity costs from higher average market prices, partially offset by lower volumes;

•$34 million of higher natural gas-fueled generation costs due to higher average prices and higher volumes; and

•$20 million of higher coal-fueled generation costs primarily due to higher volumes, partially offset by lower average prices.

Operations and maintenance increased $12 million, or 5%, for the second quarter of 2021 compared to 2020 primarily due to higher plant maintenance costs, partially offset by lower employee related expenses and bad debt expense.

Depreciation and amortization increased $65 million, or 31%, for the second quarter of 2021 compared to 2020 primarily due to the impacts of a depreciation study effective January 1, 2021 of approximately $44 million, including accelerated depreciation on coal-fueled units in Washington, incremental decommissioning as a result of general rate case orders, and higher plant-in-service balances.

Property and other taxes decreased $9 million, or 17%, for the second quarter of 2021 compared to 2020 primarily due to lower property taxes from lower assessed property values.

Allowance for borrowed and equity funds decreased $17 million, or 49%, for the second quarter of 2021 compared to 2020 primarily due to lower qualified construction work-in-progress balances.

Income tax (benefit) expense decreased $45 million to a benefit of $19 million for the second quarter of 2021 compared to expense of $26 million for the second quarter of 2020. The effective tax rate was (9)% for 2021 and 14% for 2020. The effective tax rate decreased primarily as a result of higher effects of ratemaking associated with excess deferred income tax amortization in the current year and increased PTCs from PacifiCorp's new wind-powered generating facilities.

First Six Months of 2021 compared to First Six Months of 2020

Utility margin increased $125 million, or 8%, for the first six months of 2021 compared to 2020 primarily due to:

•$144 million increase in retail revenue primarily due to higher customer volumes, partially offset by lower rates due to certain general rate case orders. Retail customer volumes increased 5.7%, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers;

•$48 million of higher deferred net power costs in accordance with established adjustment mechanisms;

•$22 million of higher wholesale revenue due to higher wholesale volumes and higher average wholesale market prices; and

•$17 million of higher wheeling revenue.

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The increases above were partially offset by:

•$46 million of higher natural gas-fueled generation costs due to higher average prices and higher volumes;

•$37 million of higher purchased electricity costs due to higher average prices, partially offset by lower volumes; and

•$26 million of higher coal-fueled generation costs primarily due to higher volumes, partially offset by lower average prices.

Operations and maintenance increased $17 million, or 3%, for the first six months of 2021 compared to 2020 primarily due to higher vegetation management costs and higher plant maintenance costs, partially offset by lower bad debt expense.

Depreciation and amortization increased $77 million, or 17%, for the first six months of 2021 compared to 2020 primarily due to the impacts of a depreciation study effective January 1, 2021 of approximately $81 million, including accelerated depreciation on coal-fueled units in Washington, incremental decommissioning as a result of general rate case orders and higher placed-in-service balances, partially offset by a $44 million decrease resulting from lower accelerated depreciation for Oregon's share of certain retired wind equipment due to repowering ($3 million in the first quarter of 2021 (fully offset in other revenue) compared to $47 million in the first quarter of 2020 ($7 million offset in other revenue and $40 million offset in income tax expense)).

Allowance for borrowed and equity funds decreased $29 million, or 44%, for the first six months of 2021 compared to 2020 primarily due to lower qualified construction work-in-progress balances.

Other, net increased $6 million for the first six months of 2021 compared to 2020 primarily due to market movements related to corporate-owned life insurance policies.

Income tax (benefit) expense decreased $42 million to a benefit of $30 million for the first six months of 2021 compared to expense of $12 million the first six months of 2020. The effective tax rate was (8)% for 2021 and 3% for 2020. The effective tax rate decreased primarily as a result of increased PTCs from PacifiCorp's new wind-powered generating facilities.

Liquidity and Capital Resources

As of June 30, 2021, PacifiCorp's total net liquidity was as follows (in millions):

Cash and cash equivalents	$	44
Credit facilities	1,200
Less:
Short-term debt	(301)
Tax-exempt bond support	(218)
Net credit facilities	681
Total net liquidity	$	725
Credit facilities:
Maturity dates	2024

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2021 and 2020 were $1,046 million and $770 million, respectively. The change was primarily due to higher cash received for income taxes, higher collections from retail customers, and higher collateral received related to natural gas swaps, partially offset by higher operating expense 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.

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Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2021 and 2020 were $(819) million and $(944) million, respectively. The change is primarily due to an increase in capital expenditures of $154 million and prior year proceeds from the settlement of notes receivable of $25 million associated with the sale of certain Utah mining assets in 2015. Refer to "Future Uses of Cash" for discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2021 was $(196) million. Sources of cash consisted of $208 million from the borrowing of short-term debt. Uses of cash consisted substantially of $400 million for the repayment of long-term debt.

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.

Short-term Debt

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of June 30, 2021, PacifiCorp had $301 million of short-term debt outstanding at a weighted average interest rate of 0.17%. As of December 31, 2020, PacifiCorp had $93 million of short-term debt outstanding at a weighted average interest rate of 0.16%.    

Long-term Debt

In July 2021, PacifiCorp issued $1 billion of its 2.90% First Mortgage Bonds due June 2052. PacifiCorp used the net proceeds to finance a portion of the capital expenditures disbursed during the period from July 1, 2019 to May 31, 2021 with respect to investments, primarily from the Energy Vision 2020 initiative, in the repowering of certain of its existing wind-powered generating facilities and the construction and acquisition of new wind-powered generating facilities, which were previously financed with PacifiCorp's general funds.

Debt Authorizations

Following the July 2021 long-term debt issuance, PacifiCorp has regulatory authority from the OPUC and the IPUC to issue an additional $2 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement with the SEC to issue an indeterminate amount of first mortgage bonds through September 2023.

Future Uses of Cash

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

Capital Expenditures

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

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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
	2020		2021		2021
Wind generation	$	443	$	82	$	180
Electric distribution	215		326		711
Electric transmission	192		136		347
Other	123		275		544
Total	$	973	$	819	$	1,782

PacifiCorp's 2019 IRP identified a significant increase in renewable resource generation and associated transmission. PacifiCorp has included an estimate of the 2019 IRP resources in its forecast capital expenditures for 2021 through 2023. These estimates are likely to change as a result of the RFP process. PacifiCorp's historical and forecast capital expenditures include the following:

•Wind generation includes both growth projects and operating expenditures. Growth projects include:

◦Construction of wind-powered generating facilities at PacifiCorp totaling $79 million and $395 million for the six-month periods ended June 30, 2021 and 2020, respectively. Construction includes 674 MWs of new wind-powered generating facilities that were placed in-service in 2020, 476 MWs that were placed in service in the first six months of 2021 and an additional 40 MWs expected to be placed in-service in the second half of 2021. The energy production for these new facilities is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. PacifiCorp's 2019 IRP identified 1,920 MWs of new wind-powered generating resources that are expected to come online in 2024. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp anticipates costs associated with the construction of wind-powered generating facilities will total an additional $39 million for 2021.

◦Repowering of wind-powered generating facilities at PacifiCorp totaling $3 million and $46 million for the six-month periods ended June 30, 2021 and 2020, respectively. Certain repowering projects for existing facilities were placed in service in 2019, 2020 and in the first six months of 2021. The energy production from these existing repowered facilities is expected to qualify for 100% of the federal renewable electricity PTCs available for 10 years following each facility's return to service. Planned additional spending for repowering of wind-powered generating facilities totals $47 million for 2021.

•Electric distribution includes both growth projects and operating expenditures. Operating expenditures includes planned spend on wildfire mitigation, wildfire damage restoration and storm damage repairs. Expenditures for these items totaled $117 million and $12 million for the six-month periods ended June 30, 2021 and 2020, respectively. PacifiCorp anticipates costs associated with these activities will total an additional $90 million in the second half of 2021. Remaining investments relate to expenditures for new connections and distribution.

•Electric transmission includes both growth projects and operating expenditures. Transmission investment through 2020 primarily reflects costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, a major segment of PacifiCorp's Energy Gateway Transmission expansion program, placed in-service in November 2020. Planned spending for additional Energy Gateway Transmission segments to be placed in service in 2024-2026 totals $112 million in 2021.

•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $47 million and $31 million for the six-month periods ended June 30, 2021 and 2020, respectively. PacifiCorp anticipates costs associated with information technology will total an additional $100 million for 2021. Remaining investments relate to operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing and expected demand.

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Requests for Proposals

PacifiCorp issues individual RFPs 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.

PacifiCorp issued the 2020 All Source RFP to the market in July 2020. The 2020 All Source RFP sought bids for resources capable of coming online by the end of 2024 up to the level of resources identified in PacifiCorp's 2019 IRP. An initial shortlist was identified in October 2020. The final shortlist of winning bids was submitted to OPUC in June 2021. PacifiCorp will initiate negotiations with shortlisted bids that include approximately 1,792 MWs of new wind capacity, 1,306 MWs of solar capacity and 697 MWs of battery storage to its portfolio by 2024. PacifiCorp expects that 590 MWs of the 1,792 MWs of new wind capacity will be owned with the remainder of the wind, solar and storage capacity being contracted resources.

Contractual Obligations

As of June 30, 2021, 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, 2020.

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 laws and regulations regarding climate change, wildfire prevention and mitigation, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. PacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and financial results.

Refer to "Environmental Laws and Regulations" in 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, 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, 2020. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2020.

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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, 2021, the related statements of operations and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2021 and 2020, and of cash flows for the six-month periods ended June 30, 2021 and 2020, 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, 2020, 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 26, 2021, 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, 2020, 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 6, 2021

81

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,		December 31,
	2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	30	$	38
Trade receivables, net	508		234
Income tax receivable	49		—
Inventories	237		278
Other current assets	91		73
Total current assets	915		623
Property, plant and equipment, net	19,473		19,279
Regulatory assets	455		392
Investments and restricted investments	977		911
Other assets	237		232
Total assets	$	22,057	$	21,437

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,
	2021		2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	288	$	408
Accrued interest	78		78
Accrued property, income and other taxes	267		161
Other current liabilities	188		183
Total current liabilities	821		830
Long-term debt	7,224		7,210
Regulatory liabilities	1,254		1,111
Deferred income taxes	3,164		3,054
Asset retirement obligations	709		709
Other long-term liabilities	459		458
Total liabilities	13,631		13,372
Commitments and contingencies (Note 9)
Shareholder's equity:
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding	—		—
Additional paid-in capital	561		561
Retained earnings	7,865		7,504
Total shareholder's equity	8,426		8,065
Total liabilities and shareholder's equity	$	22,057	$	21,437

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,
	2021		2020		2021		2020
Operating revenue:
Regulated electric	$	586	$	518	$	1,131	$	989
Regulated natural gas and other	107		95		629		305
Total operating revenue	693		613		1,760		1,294
Operating expenses:
Cost of fuel and energy	103		71		254		151
Cost of natural gas purchased for resale and other	57		42		489		170
Operations and maintenance	184		182		377		347
Depreciation and amortization	209		175		416		351
Property and other taxes	37		35		73		69
Total operating expenses	590		505		1,609		1,088
Operating income	103		108		151		206
Other income (expense):
Interest expense	(74)		(74)		(148)		(150)
Allowance for borrowed funds	2		4		4		7
Allowance for equity funds	8		9		14		17
Other, net	15		21		26		16
Total other income (expense)	(49)		(40)		(104)		(110)
Income before income tax benefit	54		68		47		96
Income tax benefit	(159)		(141)		(313)		(264)
Net income	$	213	$	209	$	360	$	360

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, 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
Balance, March 31, 2021	$	—	$	561	$	7,651	$	8,212
Net income	—		—		213		213
Other equity transactions	—		—		1		1
Balance, June 30, 2021	$	—	$	561	$	7,865	$	8,426
Balance, December 31, 2020	$	—	$	561	$	7,504	$	8,065
Net income	—		—		360		360
Other equity transactions	—		—		1		1
Balance, June 30, 2021	$	—	$	561	$	7,865	$	8,426

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,
	2021		2020
Cash flows from operating activities:
Net income	$	360	$	360
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	416		351
Amortization of utility plant to other operating expenses	17		17
Allowance for equity funds	(14)		(17)
Deferred income taxes and amortization of investment tax credits	196		131
Settlements of asset retirement obligations	(19)		(25)
Other, net	11		8
Changes in other operating assets and liabilities:
Trade receivables and other assets	(275)		(1)
Inventories	41		(31)
Pension and other postretirement benefit plans	—		(11)
Accrued property, income and other taxes, net	56		(409)
Accounts payable and other liabilities	(68)		(47)
Net cash flows from operating activities	721		326
Cash flows from investing activities:
Capital expenditures	(720)		(824)
Purchases of marketable securities	(109)		(210)
Proceeds from sales of marketable securities	105		202
Other, net	(2)		14
Net cash flows from investing activities	(726)		(818)
Cash flows from financing activities:
Net proceeds from short-term debt	—		195
Other, net	(2)		(1)
Net cash flows from financing activities	(2)		194
Net change in cash and cash equivalents and restricted cash and cash equivalents	(7)		(298)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	45		330
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	38	$	32

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, 2021, and for the three- and six-month periods ended June 30, 2021 and 2020. The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and six-month periods ended June 30, 2021 and 2020. The results of operations for the three- and six-month periods ended June 30, 2021, 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, 2020, 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, 2021.

(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, 2021 and December 31, 2020, consist substantially of funds restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of June 30, 2021 and December 31, 2020, 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,
	2021		2020
Cash and cash equivalents	$	30	$	38
Restricted cash and cash equivalents in other current assets	8		7
Total cash and cash equivalents and restricted cash and cash equivalents	$	38	$	45

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(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	2021		2020
Utility plant in service, net:
Generation	20-70 years	$	17,083	$	16,980
Transmission	52-75 years	2,364		2,365
Electric distribution	20-75 years	4,468		4,369
Natural gas distribution	29-75 years	1,988		1,955
Utility plant in service		25,903		25,669
Accumulated depreciation and amortization		(7,241)		(6,902)
Utility plant in service, net		18,662		18,767
Nonregulated property, net:
Nonregulated property gross	20-50 years	7		7
Accumulated depreciation and amortization		(1)		(1)
Nonregulated property, net		6		6
		18,668		18,773
Construction work-in-progress		805		506
Property, plant and equipment, net		$	19,473	$	19,279

(4)    Regulatory Matters

Natural Gas Purchased for Resale

In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. These increased costs are reflected in cost of natural gas purchased for resale and other on the Statement of Operations and their recovery through the Purchased Gas Adjustment Clause is reflected in regulated natural gas and other revenue.

To mitigate the impact to MidAmerican Energy's customers, the Iowa Utilities Board ordered the recovery of these higher costs to be applied to customer bills over the period April 2021 through April 2022 based on a customer's monthly natural gas usage. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the six-month period ended June 30, 2021.

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(5)    Recent Financing Transactions

Long-Term Debt

In July 2021, MidAmerican Energy issued $500 million of its 2.70% First Mortgage Bonds due August 2052. MidAmerican Energy used the net proceeds to finance a portion of the capital expenditures, disbursed during the period from July 22, 2019 to September 27, 2019, with respect to investments in its 2,000-megawatt Wind XI project, its 592-megawatt Wind XII project, its 207-megawatt Wind XII Expansion project and the repowering of certain of its existing wind-powered generating facilities, which were previously financed with MidAmerican Energy's general funds.

Credit Facilities

In June 2021, MidAmerican Energy amended and restated its existing $900 million unsecured credit facility expiring in June 2022. The amendment increased the commitment of the lenders to $1.5 billion, extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to consent of the lenders. Additionally, in June 2021, MidAmerican Energy terminated its existing $600 million unsecured credit facility expiring in August 2021.

(6)    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,
	2021		2020		2021		2020
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Income tax credits	(271)		(186)		(634)		(257)
State income tax, net of federal income tax impacts	(31)		(35)		(32)		(33)
Effects of ratemaking	(15)		(9)		(21)		(7)
Other, net	2		2		—		1
Effective income tax rate	(294)	%	(207)	%	(666)	%	(275)	%

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. PTCs for the three-month periods ended June 30, 2021 and 2020 totaled $146 million and $127 million, respectively, and for the six-month periods ended June 30, 2021 and 2020 totaled $297 million and $247 million, respectively.

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 received net cash payments for income tax from BHE totaling $558 million for the six-month period ended June 30, 2021, and made net cash payments for income tax to BHE totaling $19 million for the six-month period ended June 30, 2020.

(7)    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 cost (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,
	2021		2020		2021		2020
Pension:
Service cost	$	5	$	1	$	10	$	2
Interest cost	5		6		11		12
Expected return on plan assets	(10)		(10)		(19)		(20)
Net amortization	1		1		1		1
Net periodic benefit cost (credit)	$	1	$	(2)	$	3	$	(5)
Other postretirement:
Service cost	$	2	$	1	$	4	$	2
Interest cost	2		1		4		3
Expected return on plan assets	(3)		(3)		(5)		(6)
Net amortization	(1)		(2)		(2)		(3)
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 $12 million, respectively, during 2021. As of June 30, 2021, $4 million and $6 million of contributions had been made to the pension and other postretirement benefit plans, respectively.

(8)    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, 2021:
Assets:
Commodity derivatives	$	—	$	20	$	4	$	(4)	$	20
Money market mutual funds(2)	7		—		—		—		7
Debt securities:
United States government obligations	222		—		—		—		222
International government obligations	—		5		—		—		5
Corporate obligations	—		78		—		—		78
Municipal obligations	—		2		—		—		2
Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:
United States companies	412		—		—		—		412
International companies	8		—		—		—		8
Investment funds	24		—		—		—		24
	$	673	$	106	$	4	$	(4)	$	779
Liabilities - commodity derivatives	$	(1)	$	(2)	$	(5)	$	7	$	(1)

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2020:
Assets:
Commodity derivatives	$	—	$	4	$	5	$	(5)	$	4
Money market mutual funds(2)	41		—		—		—		41
Debt securities:
United States government obligations	200		—		—		—		200
International government obligations	—		5		—		—		5
Corporate obligations	—		73		—		—		73
Municipal obligations	—		2		—		—		2
Agency, asset and mortgage-backed obligations	—		6		—		—		6
Equity securities:
United States companies	381		—		—		—		381
International companies	9		—		—		—		9
Investment funds	17		—		—		—		17
	$	648	$	90	$	5	$	(5)	$	738
Liabilities - commodity derivatives	$	—	$	(4)	$	(3)	$	5	$	(2)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $3 million and $— million as of June 30, 2021 and December 31, 2020, 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, 2021				As of December 31, 2020
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	7,224	$	8,698	$	7,210	$	9,130

(9)    Commitments and Contingencies

Construction Commitments

During the six-month period ended June 30, 2021, MidAmerican Energy entered into firm construction commitments totaling $558 million through the remainder of 2021 and 2022 related to the repowering and construction of wind-powered generating facilities and the construction of solar-powered generating facilities.

Easements

During the six-month period ended June 30, 2021, MidAmerican Energy entered into non-cancelable easements with minimum payment commitments totaling $87 million through 2061 for land in Iowa on which some of its wind- and solar-powered generating facilities will be located.

Legal Matters

MidAmerican Energy is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Energy does not believe that such normal and routine litigation will have a material impact on its financial results.

Environmental Laws and Regulations

MidAmerican Energy is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.

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Transmission Rates

MidAmerican Energy's wholesale transmission rates are set annually using Federal Energy Regulatory Commission ("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, 2021, has accrued a $10 million liability for refunds of amounts collected under the higher ROE during the periods covered by both complaints.

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(10)    Revenue from Contracts with Customers

The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 11, (in millions):

	For the Three-Month Period Ended June 30, 2021								For the Six-Month Period Ended June 30, 2021
	Electric		Natural Gas		Other		Total		Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential	$	170	$	59	$	—	$	229	$	331	$	367	$	—	$	698
Commercial	80		18		—		98		151		147		—		298
Industrial	230		3		—		233		420		15		—		435
Natural gas transportation services	—		9		—		9		—		19		—		19
Other retail(1)	36		—		—		36		66		1		—		67
Total retail	516		89		—		605		968		549		—		1,517
Wholesale	52		17		—		69		126		68		—		194
Multi-value transmission projects	15		—		—		15		30		—		—		30
Other Customer Revenue	—		—		1		1		—		—		11		11
Total Customer Revenue	583		106		1		690		1,124		617		11		1,752
Other revenue	3		—		—		3		7		1		—		8
Total operating revenue	$	586	$	106	$	1	$	693	$	1,131	$	618	$	11	$	1,760

	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

(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.

94

(11)    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,
	2021		2020		2021		2020
Operating revenue:
Regulated electric	$	586	$	518	$	1,131	$	989
Regulated natural gas	106		95		618		304
Other	1		—		11		1
Total operating revenue	$	693	$	613	$	1,760	$	1,294
Operating income:
Regulated electric	$	103	$	101	$	112	$	160
Regulated natural gas	—		7		39		46
Other	—		—		—		—
Total operating income	103		108		151		206
Interest expense	(74)		(74)		(148)		(150)
Allowance for borrowed funds	2		4		4		7
Allowance for equity funds	8		9		14		17
Other, net	15		21		26		16
Income before income tax benefit	$	54	$	68	$	47	$	96

	As of
	June 30, 2021		December 31, 2020
Assets:
Regulated electric	$	20,349	$	19,892
Regulated natural gas	1,708		1,544
Other	—		1
Total assets	$	22,057	$	21,437

95

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, 2021, the related consolidated statements of operations and changes in member's equity for the three-month and six-month periods ended June 30, 2021 and 2020, and of cash flows for the six-month periods ended June 30, 2021 and 2020, 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, 2020, 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 26, 2021, 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, 2020, 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 6, 2021

96

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,		December 31,
	2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	31	$	39
Trade receivables, net	508		234
Income tax receivable	49		—
Inventories	237		278
Other current assets	92		74
Total current assets	917		625
Property, plant and equipment, net	19,474		19,279
Goodwill	1,270		1,270
Regulatory assets	455		392
Investments and restricted investments	979		913
Other assets	236		232
Total assets	$	23,331	$	22,711

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

97

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	June 30,		December 31,
	2021		2020
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	288	$	408
Accrued interest	84		83
Accrued property, income and other taxes	267		161
Note payable to affiliate	183		177
Other current liabilities	188		183
Total current liabilities	1,010		1,012
Long-term debt	7,464		7,450
Regulatory liabilities	1,254		1,111
Deferred income taxes	3,162		3,052
Asset retirement obligations	709		709
Other long-term liabilities	459		458
Total liabilities	14,058		13,792
Commitments and contingencies (Note 9)
Member's equity:
Paid-in capital	1,679		1,679
Retained earnings	7,594		7,240
Total member's equity	9,273		8,919
Total liabilities and member's equity	$	23,331	$	22,711

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

98

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,
	2021		2020		2021		2020
Operating revenue:
Regulated electric	$	586	$	518	$	1,131	$	989
Regulated natural gas and other	107		98		629		313
Total operating revenue	693		616		1,760		1,302
Operating expenses:
Cost of fuel and energy	103		71		254		151
Cost of natural gas purchased for resale and other	57		42		489		171
Operations and maintenance	184		183		377		348
Depreciation and amortization	209		175		416		351
Property and other taxes	37		35		73		69
Total operating expenses	590		506		1,609		1,090
Operating income	103		110		151		212
Other income (expense):
Interest expense	(78)		(78)		(156)		(159)
Allowance for borrowed funds	2		4		4		7
Allowance for equity funds	8		9		14		17
Other, net	16		21		26		15
Total other income (expense)	(52)		(44)		(112)		(120)
Income before income tax benefit	51		66		39		92
Income tax benefit	(160)		(142)		(316)		(266)
Net income	$	211	$	208	$	355	$	358

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

99

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, 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
Balance, March 31, 2021	$	1,679	$	7,384	$	9,063
Net income	—		211		211
Other equity transactions	—		(1)		(1)
Balance, June 30, 2021	$	1,679	$	7,594	$	9,273
Balance, December 31, 2020	$	1,679	$	7,240	$	8,919
Net income	—		355		355
Other equity transactions	—		(1)		(1)
Balance, June 30, 2021	$	1,679	$	7,594	$	9,273

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

100

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2021		2020
Cash flows from operating activities:
Net income	$	355	$	358
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	416		351
Amortization of utility plant to other operating expenses	17		17
Allowance for equity funds	(14)		(17)
Deferred income taxes and amortization of investment tax credits	195		134
Settlements of asset retirement obligations	(19)		(25)
Other, net	11		8
Changes in other operating assets and liabilities:
Trade receivables and other assets	(275)		—
Inventories	41		(31)
Pension and other postretirement benefit plans	—		(11)
Accrued property, income and other taxes, net	56		(414)
Accounts payable and other liabilities	(68)		(47)
Net cash flows from operating activities	715		323
Cash flows from investing activities:
Capital expenditures	(721)		(824)
Purchases of marketable securities	(109)		(210)
Proceeds from sales of marketable securities	105		202
Other, net	(1)		15
Net cash flows from investing activities	(726)		(817)
Cash flows from financing activities:
Net change in note payable to affiliate	6		4
Net proceeds from short-term debt	—		195
Other, net	(2)		(1)
Net cash flows from financing activities	4		198
Net change in cash and cash equivalents and restricted cash and cash equivalents	(7)		(296)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	46		331
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	39	$	35

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

101

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, 2021, and for the three- and six-month periods ended June 30, 2021 and 2020. 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, 2021 and 2020. The results of operations for the three- and six-month periods ended June 30, 2021, 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, 2020, 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, 2021.

(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, 2021 and December 31, 2020, consist substantially of funds restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of June 30, 2021 and December 31, 2020, 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,
	2021		2020
Cash and cash equivalents	$	31	$	39
Restricted cash and cash equivalents in other current assets	8		7
Total cash and cash equivalents and restricted cash and cash equivalents	$	39	$	46

102

(3)    Property, Plant and Equipment, Net

Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements.

(4)    Regulatory Matters

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

(5)    Recent Financing Transactions

Refer to Note 5 of MidAmerican Energy's Notes to Financial Statements.

(6)    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,
	2021		2020		2021		2020
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Income tax credits	(286)		(192)		(764)		(269)
State income tax, net of federal income tax impacts	(33)		(37)		(41)		(35)
Effects of ratemaking	(16)		(9)		(26)		(7)
Other, net	—		2		—		1
Effective income tax rate	(314)	%	(215)	%	(810)	%	(289)	%

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 Funding 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. PTCs for the three-month periods ended June 30, 2021 and 2020 totaled $146 million and $127 million, respectively, and for the six-month periods ended June 30, 2021 and 2020 totaled $297 million and $247 million, respectively.

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 received net cash payments for income tax from BHE totaling $560 million for the six-month period ended June 30, 2021, and made net cash payments for income tax to BHE totaling $19 million for the six-month period ended June 30, 2020.

(7)    Employee Benefit Plans

Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements.

103

(8)    Fair Value Measurements

Refer to Note 8 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, 2021				As of December 31, 2020
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	7,464	$	9,020	$	7,450	$	9,466

(9)    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 9 of MidAmerican Energy's Notes to Financial Statements.

(10)    Revenue from Contracts with Customers

Refer to Note 10 of MidAmerican Energy's Notes to Financial Statements. Additionally, MidAmerican Funding had other Accounting Standards Codification Topic 606 revenue of $— million and $3 million for the three-month periods ended June 30, 2021 and 2020, respectively, and $— million and $8 million for the six-month periods ended June 30, 2021 and 2020, respectively.

104

(11)    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,
	2021		2020		2021		2020
Operating revenue:
Regulated electric	$	586	$	518	$	1,131	$	989
Regulated natural gas	106		95		618		304
Other	1		3		11		9
Total operating revenue	$	693	$	616	$	1,760	$	1,302
Operating income:
Regulated electric	$	103	$	101	$	112	$	160
Regulated natural gas	—		7		39		46
Other	—		2		—		6
Total operating income	103		110		151		212
Interest expense	(78)		(78)		(156)		(159)
Allowance for borrowed funds	2		4		4		7
Allowance for equity funds	8		9		14		17
Other, net	16		21		26		15
Income before income tax benefit	$	51	$	66	$	39	$	92

	As of
	June 30, 2021		December 31, 2020
Assets(1):
Regulated electric	$	21,540	$	21,083
Regulated natural gas	1,787		1,623
Other	4		5
Total assets	$	23,331	$	22,711

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

105

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 2021 and 2020

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the second quarter of 2021 was $213 million, an increase of $4 million, or 2%, compared to 2020 primarily due to higher electric utility margin of $36 million and a favorable income tax benefit of $18 million, partially offset by higher depreciation and amortization expense of $34 million from additional assets placed in-service and a regulatory mechanism deferring certain depreciation expense in 2020, lower natural gas utility margin from lower customer volumes and unfavorable changes in the cash surrender value of corporate-owned life insurance policies. The favorable income tax benefit was mainly due to higher PTCs recognized from higher wind-powered generation, driven primarily by new wind projects placed in-service. Electric utility margin increased primarily due to higher retail customer volumes.

MidAmerican Energy's net income for the first six months of 2021 was $360 million, unchanged from 2020, primarily due to higher depreciation and amortization expense of $65 million from additional assets placed in-service and a regulatory mechanism deferring certain depreciation expense in 2020 and $30 million higher operations and maintenance expenses, partially offset by a favorable income tax benefit of $49 million and higher electric utility margin of $39 million. Higher operations and maintenance expenses included increased costs associated with additional wind-powered generating facilities placed in-service as well as higher electric and natural gas distribution costs. The favorable income tax benefit was mainly due to higher PTCs recognized from higher wind-powered generation, driven primarily by new wind projects placed in-service. Electric utility margin increased primarily due to higher retail customer volumes, partially offset by lower wholesale utility margin from a lower average per-unit margin due to higher thermal generation and purchased power costs.

MidAmerican Funding -

MidAmerican Funding's net income for the second quarter of 2021 was $211 million, an increase of $3 million, or 1%, compared to 2020. MidAmerican Funding's net income for the first six months of 2021 was $355 million, a decrease of $3 million, or 1%, compared to 2020. The variances in net income 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.

106

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
	2021		2020		Change				2021		2020		Change
Electric utility margin:
Operating revenue	$	586	$	518	$	68	13	%	$	1,131	$	989	$	142	14	%
Cost of fuel and energy	103		71		32		45		254		151		103		68
Electric utility margin	483		447		36		8	%	877		838		39		5	%
Natural gas utility margin:
Operating revenue	106		95		11		12	%	618		304		314		*
Natural gas purchased for resale	57		42		15		36		489		170		319		*
Natural gas utility margin	49		53		(4)		(8)	%	129		134		(5)		(4)	%
Utility margin	532		500		32		6	%	1,006		972		34		3	%
Other operating revenue	1		—		1		*		11		1		10		*
Operations and maintenance	184		182		2		1		377		347		30		9
Depreciation and amortization	209		175		34		19		416		351		65		19
Property and other taxes	37		35		2		6		73		69		4		6
Operating income	$	103	$	108	$	(5)	(5)	%	$	151	$	206	$	(55)	(27)	%

*    Not meaningful.

107

Electric Utility Margin

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

	Second Quarter								First Six Months
	2021		2020		Change				2021		2020		Change
Utility margin (in millions):
Operating revenue	$	586	$	518	$	68	13	%	$	1,131	$	989	$	142	14	%
Cost of fuel and energy	103		71		32		45		254		151		103		68
Utility margin	$	483	$	447	$	36	8	%	$	877	$	838	$	39	5	%
Sales (GWhs):
Residential	1,486		1,505		(19)		(1)	%	3,224		3,173		51		2	%
Commercial	894		818		76		9		1,832		1,787		45		3
Industrial	4,056		3,602		454		13		7,875		7,126		749		11
Other	401		334		67		20		771		719		52		7
Total retail	6,837		6,259		578		9		13,702		12,805		897		7
Wholesale	3,872		2,560		1,312		51		7,923		4,994		2,929		59
Total sales	10,709		8,819		1,890		21	%	21,625		17,799		3,826		21	%
Average number of retail customers (in thousands)	803		794		9		1	%	802		793		9		1	%
Average revenue per MWh:
Retail	$	75.62	$	74.77	$	0.85	1	%	$	70.71	$	68.63	$	2.08	3	%
Wholesale	$	12.06	$	10.64	$	1.42	13	%	$	14.40	$	13.11	$	1.29	10	%
Heating degree days	588		650		(62)		(10)	%	3,799		3,602		197		5	%
Cooling degree days	426		360		66		18	%	426		360		66		18	%
Sources of energy (GWhs)(1):
Wind and other(2)	5,877		5,148		729		14	%	11,999		9,994		2,005		20	%
Coal	2,791		1,029		1,762		*		5,693		2,602		3,091		*
Nuclear	1,009		909		100		11		1,904		1,902		2		—
Natural gas	336		77		259		*		479		193		286		*
Total energy generated	10,013		7,163		2,850		40		20,075		14,691		5,384		37
Energy purchased	842		1,783		(941)		(53)		1,860		3,426		(1,566)		(46)
Total	10,855		8,946		1,909		21	%	21,935		18,117		3,818		21	%
Average cost of energy per MWh:
Energy generated(3)	$	6.43	$	3.87	$	2.56	66	%	$	6.29	$	4.45	$	1.84	41	%
Energy purchased	$	45.70	$	24.50	$	21.20	87	%	$	68.55	$	25.02	$	43.53	*

*    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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Natural Gas Utility Margin

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

	Second Quarter								First Six Months
	2021		2020		Change				2021		2020		Change
Utility margin (in millions):
Operating revenue	$	106	$	95	$	11	12	%	$	618	$	304	$	314	*
Natural gas purchased for resale	57		42		15		36		489		170		319		*
Utility margin	$	49	$	53	$	(4)	(8)	%	$	129	$	134	$	(5)	(4)	%
Throughput (000's Dths):
Residential	6,272		7,046		(774)		(11)	%	31,554		30,956		598		2	%
Commercial	3,011		3,012		(1)		—		14,744		13,963		781		6
Industrial	1,069		1,070		(1)		—		2,506		2,582		(76)		(3)
Other	11		13		(2)		(15)		48		48		—		—
Total retail sales	10,363		11,141		(778)		(7)		48,852		47,549		1,303		3
Wholesale sales	5,817		5,859		(42)		(1)		16,590		18,769		(2,179)		(12)
Total sales	16,180		17,000		(820)		(5)		65,442		66,318		(876)		(1)
Natural gas transportation service	26,853		22,165		4,688		21		56,493		57,119		(626)		(1)
Total throughput	43,033		39,165		3,868		10	%	121,935		123,437		(1,502)		(1)	%
Average number of retail customers (in thousands)	776		770		6		1	%	777		770		7		1	%
Average revenue per retail Dth sold	$	7.81	$	6.97	$	0.84	12	%	$	10.88	$	5.34	$	5.54	*
Heating degree days	625		710		(85)		(12)	%	3,926		3,777		149		4	%
Average cost of natural gas per retail Dth sold	$	3.99	$	2.96	$	1.03	35	%	$	8.62	$	2.92	$	5.70	*
Combined retail and wholesale average cost of natural gas per Dth sold	$	3.54	$	2.49	$	1.05	42	%	$	7.47	$	2.57	$	4.90	*

*    Not meaningful.

Quarter Ended June 30, 2021 Compared to Quarter Ended June 30, 2020

MidAmerican Energy -

Electric utility margin increased $36 million, or 8%, for the second quarter of 2021 compared to 2020, due to:

•a $39 million increase in retail utility margin primarily due to $23 million from higher usage for certain industrial customers; $7 million from the favorable impact of weather; $6 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); and $2 million due to price impacts from changes in sales mix; partially offset by

•a $3 million decrease in Multi-Value Projects ("MVP") transmission revenue; as

•wholesale utility margin was unchanged due to the increase in sales volumes being offset by lower margins per unit, reflecting higher energy costs.

Natural gas utility margin decreased $4 million, or 8%, for the second quarter of 2021 compared to 2020 primarily due to:

•a $6 million decrease from lower average prices primarily due to the timing of recoveries through a capital tracker mechanism; and

•a $1 million decrease from the unfavorable impact of weather; partially offset by

109

•a $3 million increase from higher natural gas energy efficiency program revenue (offset in operations and maintenance expense).

Operations and maintenance increased $2 million, or 1%, for the second quarter of 2021 compared to 2020 primarily due to higher energy efficiency program expense of $5 million (offset in operating revenue) and higher electric and natural gas distribution costs of $3 million, partially offset by lower employee-related expenses.

Depreciation and amortization for the second quarter of 2021 increased $34 million, or 19%, compared to 2020 primarily due to wind-powered generating facilities and other plant placed in-service and $13 million from a regulatory mechanism deferring certain depreciation expense in 2020.

Allowance for borrowed and equity funds decreased $3 million, or 23%, for the second quarter of 2021 compared to 2020 primarily due to lower construction work-in-progress balances related to wind-powered generation.

Other, net decreased $6 million, or 29%, for the second quarter of 2021 compared to 2020 primarily due to lower cash surrender values of corporate-owned life insurance policies.

Income tax benefit increased $18 million, or 13%, for the second quarter of 2021 compared to 2020, and the effective tax rate was (294)% for 2021 and (207)% for 2020. The change in the effective tax rates for 2021 compared to 2020 was primarily due to the higher PTCs and a lower pretax income.

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 second quarter of 2021 and 2020 totaled $146 million and $127 million, respectively.

MidAmerican Funding -

Income tax benefit increased $18 million, or 13%, for the second quarter of 2021 compared to 2020, and the effective tax rate was (314)% for 2021 and (215)% for 2020. The changes in the effective tax rates were due to the factors discussed for MidAmerican Energy.

First Six Months of 2021 compared to First Six Months of 2020

MidAmerican Energy -

Electric utility margin increased $39 million, or 5%, for the first six months of 2021 compared to 2020, due to:

•a $54 million increase in retail utility margin primarily due to $22 million from higher usage for certain industrial customers; $13 million from the favorable impact of weather; $12 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); and $7 million due to price impacts from changes in sales mix; partially offset by

•a $12 million decrease in wholesale utility margin due to lower margins per unit, reflecting higher energy costs, partially offset by higher sales volumes of 58.7%; and

•a $3 million decrease in MVP transmission revenue.

Natural gas utility margin decreased $5 million, or 4%, for the first six months of 2021 compared to 2020 primarily due to:

•a $7 million decrease from higher refunds related to amortization of excess accumulated deferred income taxes arising from 2017 Tax Reform (offset in income tax benefit);

•a $6 million decrease from lower average prices primarily due to the timing of a capital cost tracking mechanism; partially offset by

•a $6 million increase in natural gas energy efficiency program revenue (offset in operations and maintenance expense); and

•a $1 million increase from the favorable impact of weather.

110

Operations and maintenance increased $30 million, or 9%, for the first six months of 2021 compared to 2020 primarily due to higher energy efficiency program expense of $10 million (offset in operating revenue), higher generation operations and maintenance expenses of $9 million due to additional wind turbines and easements and higher electric and natural gas distribution costs of $8 million.

Depreciation and amortization for the first six months of 2021 increased $65 million, or 19%, compared to 2020 primarily due to wind-powered generating facilities and other plant placed in-service and $26 million from a regulatory mechanism deferring certain depreciation expense in 2020.

Interest expense decreased $2 million, or 1%, for the first six months of 2021 compared to 2020 due to lower average interest rates on variable rate long-term debt.

Allowance for borrowed and equity funds decreased $6 million, or 25%, for the first six months of 2021 compared to 2020 primarily due to lower construction work-in-progress balances related to wind-powered generation.

Other, net increased $10 million, or 63%, for the first six months of 2021 compared to 2020 primarily due to higher cash surrender values of corporate-owned life insurance policies.

Income tax benefit increased $49 million, or 19%, for the first six months of 2021 compared to 2020, and the effective tax rate was (666)% for 2021 and (275)% for 2020. The change in the effective tax rates for 2021 compared to 2020 was primarily due to the higher PTCs and a lower pretax income, partially offset by the effects of ratemaking. PTCs for the first six months of 2021 and 2020 totaled $297 million and $247 million, respectively.

MidAmerican Funding -

Income tax benefit increased $50 million, or 19%, for the first six months of 2021 compared to 2020, and the effective tax rate was (810)% for 2021 and (289)% for 2020. The changes in the effective tax rates were principally due to the factors discussed for MidAmerican Energy.

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Liquidity and Capital Resources

As of June 30, 2021, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):

MidAmerican Energy:
Cash and cash equivalents	$	30
Credit facilities, maturing 2022 and 2024	1,505
Less:
Tax-exempt bond support	(370)
Net credit facilities	1,135
MidAmerican Energy total net liquidity	$	1,165
MidAmerican Funding:
MidAmerican Energy total net liquidity	$	1,165
Cash and cash equivalents	1
MHC, Inc. credit facility, maturing 2022	4
MidAmerican Funding total net liquidity	$	1,170

Operating Activities

MidAmerican Energy's net cash flows from operating activities for the six-month periods ended June 30, 2021 and 2020, were $721 million and $326 million, respectively. MidAmerican Funding's net cash flows from operating activities for the six-month periods ended June 30, 2021 and 2020, were $715 million and $323 million, respectively. Cash flows from operating activities reflect higher income tax receipts, partially offset by lower cash margins for MidAmerican Energy's regulated electric and natural gas businesses, including delayed recovery of higher natural gas costs in February 2021, discussed below, and higher payments to vendors.

In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. To mitigate the impact to MidAmerican Energy's customers, the IUB ordered the recovery of these higher costs to be applied to customer bills over the period April 2021 through April 2022. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the six-month period ended June 30, 2021.

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, 2021 and 2020, were $(726) million and $(818) million, respectively. MidAmerican Funding's net cash flows from investing activities for the six-month periods ended June 30, 2021 and 2020, were $(726) million and $(817) million, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures, which decreased primarily due to lower wind-powered generating facility construction 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.

112

Financing Activities

MidAmerican Energy's net cash flows from financing activities for the six-month periods ended June 30, 2021 and 2020 were $(2) million and $194 million, respectively. MidAmerican Funding's net cash flows from financing activities for the six-month periods ended June 30, 2021 and 2020, were $4 million and $198 million, respectively. Through its commercial paper program, MidAmerican Energy received $— million in 2021 and $195 million in 2020. MidAmerican Funding received $6 million and $4 million in 2021 and 2020, respectively, through its note payable with BHE.

Debt Authorizations

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 $1.5 billion unsecured credit facility expiring in June 2024. 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. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.

MidAmerican Energy currently has an effective automatic registration statement with the SEC to issue an indeterminate amount of long-term debt securities through June 13, 2024. Additionally, following the July 2021 issuance of $500 million of first mortgage bonds, MidAmerican Energy has authorization from the FERC to issue, through June 30, 2023, long-term debt securities up to an aggregate of $2.0 billion and preferred stock up to an aggregate of $500 million and from the Illinois Commerce Commission to issue long-term debt securities up to an aggregate of $350 million through August 20, 2022.

Future Uses of Cash

MidAmerican Energy and MidAmerican Funding have available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which MidAmerican Energy and MidAmerican Funding have access to external financing depends on a variety of factors, including regulatory approvals, their credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

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

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
	2020		2021		2021
Wind generation	$	419	$	286	$	802
Electric distribution	104		96		282
Electric transmission	97		54		214
Solar generation	1		63		238
Other	203		221		634
Total	$	824	$	720	$	2,170

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MidAmerican Energy's capital expenditures provided above consist of the following:

•Wind generation includes the construction, acquisition, repowering and operation of wind-powered generating facilities in Iowa.

◦Construction and acquisition of wind-powered generating facilities totaled $172 million for 2021 and $388 million for 2020. Planned spending for the construction of additional wind-powered generating facilities totals $198 million for the remainder of 2021 and includes 203 MWs of wind-powered generating facilities expected to be placed in-service in 2021.

◦Repowering of wind-powered generating facilities totaled $82 million for 2021 and $19 million for 2020. Planned spending for repowering generating facilities totals $284 million for the remainder of 2021. MidAmerican Energy expects its repowered facilities to meet Internal Revenue Service guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service. The rate at which PTCs are re-established for a facility depends upon the date construction begins. Of the 1,078 MWs of current repowering projects not in-service as of June 30, 2021, 80 MWs are currently expected to qualify for 100% of the PTCs available for 10 years following each facility's return to service, 591 MWs are expected to qualify for 80% of such credits and 407 MWs are expected to qualify for 60% of such credits.

•Electric distribution includes expenditures for new facilities to meet retail demand growth and for replacement of existing facilities to maintain system reliability.

•Electric transmission includes expenditures to meet retail demand growth, upgrades to accommodate third-party generator requirements and replacement of existing facilities to maintain system reliability.

•Solar reflects MidAmerican Energy's current plan for the construction of 141 MWs of small- and utility-scale solar generation during 2021, of which 61 MWs are expected to be placed in-service in 2021.

•Remaining expenditures primarily relate to routine expenditures for other generation, natural gas distribution, technology, facilities and other operational needs to serve existing and expected demand.

Contractual Obligations

As of June 30, 2021, 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, 2020.

114

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 proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. On October 15, 2020, the FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting the PJM's two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, the FERC also accepted the PJM's proposal to condense the schedule of activities leading up to the next capacity auction but did not specify when that schedule would commence given that a key element of the MOPR level computation remains pending before the FERC in another proceeding.

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

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

In May 2021, the PJM conducted its capacity auction as scheduled, and because Illinois has not implemented an FRR program, the MOPR applied to Quad Cities Station in the capacity auction. The MOPR prevented Quad Cities Station from clearing in the auction.

115

Assuming the continued effectiveness of the Illinois zero emission standard, Exelon Generation no longer considers Quad Cities Station to be at heightened risk for early retirement. However, to the extent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement. The FERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the Illinois zero emission standard unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism under which Quad Cities Station would be removed from the PJM's capacity auction. At the direction of the PJM Board of Managers, the PJM and its stakeholders are considering MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs, which the PJM filed at the FERC on July 30, 2021.

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, 2020. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2020.

116

Nevada Power Company and its subsidiaries

Consolidated Financial Section

117

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, 2021, the related consolidated statements of operations and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2021 and 2020, and of cash flows for the six-month periods ended June 30, 2021 and 2020, 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, 2020, 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 26, 2021, 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, 2020, 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 6, 2021

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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,
	2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	79	$	25
Trade receivables, net	318		234
Inventories	64		69
Derivative contracts	51		26
Regulatory assets	47		48
Prepayments	36		38
Other current assets	21		26
Total current assets	616		466
Property, plant and equipment, net	6,813		6,701
Finance lease right of use assets, net	344		351
Regulatory assets	717		746
Other assets	73		72
Total assets	$	8,563	$	8,336
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	296	$	181
Accrued interest	32		32
Accrued property, income and other taxes	44		25
Current portion of finance lease obligations	33		27
Regulatory liabilities	49		50
Customer deposits	42		47
Asset retirement obligation	14		25
Other current liabilities	38		22
Total current liabilities	548		409
Long-term debt	2,498		2,496
Finance lease obligations	321		334
Regulatory liabilities	1,163		1,163
Deferred income taxes	742		738
Other long-term liabilities	281		257
Total liabilities	5,553		5,397
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	705		634
Accumulated other comprehensive loss, net	(3)		(3)
Total shareholder's equity	3,010		2,939
Total liabilities and shareholder's equity	$	8,563	$	8,336
The accompanying notes are an integral part of the consolidated financial statements.

119

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2021		2020		2021		2020
Operating revenue	$	559	$	509	$	929	$	898
Operating expenses:
Cost of fuel and energy	252		197		417		367
Operations and maintenance	77		74		140		156
Depreciation and amortization	100		91		201		181
Property and other taxes	12		11		24		23
Total operating expenses	441		373		782		727
Operating income	118		136		147		171
Other income (expense):
Interest expense	(39)		(40)		(77)		(82)
Allowance for borrowed funds	1		1		2		2
Allowance for equity funds	2		2		3		4
Other, net	9		7		18		6
Total other income (expense)	(27)		(30)		(54)		(70)
Income before income tax expense	91		106		93		101
Income tax expense	9		23		9		22
Net income	$	82	$	83	$	84	$	79
The accompanying notes are an integral part of these consolidated financial statements.

120

NEVADA POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)

								Accumulated
				Additional				Other		Total
	Common Stock			Paid-in		Retained		Comprehensive		Shareholder's
	Shares	Amount		Capital		Earnings		Loss, Net		Equity
Balance, 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
Balance, March 31, 2021	1,000	$	—	$	2,308	$	636	$	(3)	$	2,941
Net income	—	—		—		82		—		82
Dividends declared	—	—		—		(13)		—		(13)
Balance, June 30, 2021	1,000	$	—	$	2,308	$	705	$	(3)	$	3,010
Balance, December 31, 2020	1,000	$	—	$	2,308	$	634	$	(3)	$	2,939
Net income	—	—		—		84		—		84
Dividends declared	—	—		—		(13)		—		(13)
Balance, June 30, 2021	1,000	$	—	$	2,308	$	705	$	(3)	$	3,010
The accompanying notes are an integral part of these consolidated financial statements.

121

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2021		2020
Cash flows from operating activities:
Net income	$	84	$	79
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	201		181
Allowance for equity funds	(3)		(4)
Changes in regulatory assets and liabilities	(17)		1
Deferred income taxes and amortization of investment tax credits	(20)		(7)
Deferred energy	(1)		15
Amortization of deferred energy	7		(11)
Other, net	—		6
Changes in other operating assets and liabilities:
Trade receivables and other assets	(83)		(80)
Inventories	5		2
Accrued property, income and other taxes	21		28
Accounts payable and other liabilities	116		(3)
Net cash flows from operating activities	310		207
Cash flows from investing activities:
Capital expenditures	(237)		(257)
Net cash flows from investing activities	(237)		(257)
Cash flows from financing activities:
Proceeds from long-term debt	—		718
Repayments of long-term debt	—		(575)
Dividends paid	(13)		(85)
Other, net	(8)		(8)
Net cash flows from financing activities	(21)		50
Net change in cash and cash equivalents and restricted cash and cash equivalents	52		—
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	36		25
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	88	$	25
The accompanying notes are an integral part of these consolidated financial statements.

122

NEVADA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    General

Nevada Power Company, together with its subsidiaries ("Nevada Power"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company and its subsidiaries ("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, 2021 and for the three- and six-month periods ended June 30, 2021 and 2020. 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, 2021 and 2020. The results of operations for the three- and six-month periods ended June 30, 2021 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, 2020 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, 2021.

(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, 2021 and December 31, 2020, 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, 2021 and December 31, 2020, 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,
	2021		2020
Cash and cash equivalents	$	79	$	25
Restricted cash and cash equivalents included in other current assets	9		11
Total cash and cash equivalents and restricted cash and cash equivalents	$	88	$	36

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(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,
		2021		2020
Utility plant:
Generation	30 - 55 years	$	3,776	$	3,690
Transmission	45 - 70 years	1,483		1,468
Distribution	20 - 65 years	3,836		3,771
General and intangible plant	5 - 65 years	800		791
Utility plant		9,895		9,720
Accumulated depreciation and amortization		(3,285)		(3,162)
Utility plant, net		6,610		6,558
Other non-regulated, net of accumulated depreciation and amortization	45 years	1		1
Plant, net		6,611		6,559
Construction work-in-progress		202		142
Property, plant and equipment, net		$	6,813	$	6,701

(4)    Recent Financing Transactions

Credit Facilities

In June 2021, Nevada Power amended and restated its existing $400 million secured credit facility expiring in June 2022 with no remaining one-year extension options. The amendment extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.

(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,
	2021		2020		2021		2020
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Effects of ratemaking	(11)		1		(11)		1
Effective income tax rate	10	%	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, 2021.

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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 receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):

	As of
	June 30,		December 31,
	2021		2020
Qualified Pension Plan:
Other non-current assets	$	10	$	8
Non-Qualified Pension Plans:
Other current liabilities	(1)		(1)
Other long-term liabilities	(9)		(9)
Other Postretirement Plans:
Other non-current assets	4		4

(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, 2021
Assets:
Commodity derivatives	$	—	$	—	$	52	$	52
Money market mutual funds(1)	70		—		—		70
Investment funds	2		—		—		2
	$	72	$	—	$	52	$	124
Liabilities - commodity derivatives	$	—	$	—	$	(27)	$	(27)
As of December 31, 2020
Assets:
Commodity derivatives	$	—	$	—	$	26	$	26
Money market mutual funds(1)	21		—		—		21
Investment funds	2		—		—		2
	$	23	$	—	$	26	$	49
Liabilities - commodity derivatives	$	—	$	—	$	(11)	$	(11)

(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, 2021 and December 31, 2020, had an immaterial impact to the fair value of its derivative contracts. As such, Nevada Power considers its derivative contracts to be valued using Level 3 inputs.

Nevada Power's investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.

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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,
	2021		2020		2021		2020
Beginning balance	$	27	$	(38)	$	15	$	(8)
Changes in fair value recognized in regulatory assets	(6)		(13)		5		(44)
Settlements	4		7		5		8
Ending balance	$	25	$	(44)	$	25	$	(44)

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, 2021				As of December 31, 2020
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	2,498	$	3,105	$	2,496	$	3,245

(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.

Environmental Laws and Regulations

Nevada Power is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.

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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 line of business, with further disaggregation of retail by customer class (in millions):

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2021		2020		2021		2020
Customer Revenue:
Retail:
Residential	$	326	$	304	$	521	$	497
Commercial	110		96		194		190
Industrial	95		83		158		154
Other	3		2		6		5
Total fully bundled	534		485		879		846
Distribution only service	5		6		10		13
Total retail	539		491		889		859
Wholesale, transmission and other	15		12		29		27
Total Customer Revenue	554		503		918		886
Other revenue	5		6		11		12
Total revenue	$	559	$	509	$	929	$	898

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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 2021 and 2020

Overview

Net income for the second quarter of 2021 was $82 million, a decrease of $1 million, or 1%, compared to 2020 primarily due to $5 million of lower utility margin, primarily due to lower retail rates from the 2020 regulatory rate review with new rates effective January 2021 and an adjustment to regulatory-related revenue deferrals, partially offset by price impacts from changes in sales mix, $9 million of higher depreciation and amortization, mainly due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in service, and $3 million of higher operations and maintenance expenses, primarily due to a higher accrual for earnings sharing and higher plant operations and maintenance costs, partially offset by lower net regulatory instructed deferrals and amortizations. These decreases are offset by $14 million of lower income tax expense primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021.

Net income for the first six months of 2021 was $84 million, an increase of $5 million, or 6%, compared to 2020 primarily due to $16 million of lower operations and maintenance expenses, primarily due to lower net regulatory instructed deferrals and amortizations of $17 million, partially offset by a higher accrual for earnings sharing, $13 million of lower income tax expense primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021, $12 million of higher other, net, mainly due to higher cash surrender value of corporate-owned life insurance policies of $7 million, lower pension expense and higher interest income, and lower interest expense of $5 million. These increases are offset by $20 million of higher depreciation and amortization, mainly due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in service, and $19 million of lower utility margin, primarily due to lower retail rates from the 2020 regulatory rate review with new rates effective January 2021 and an adjustment to regulatory-related revenue deferrals, partially offset by price impacts from changes in sales mix.

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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
	2021		2020		Change				2021		2020		Change
Utility margin:
Operating revenue	$	559	$	509	$	50	10	%	$	929	$	898	$	31	3	%
Cost of fuel and energy	252		197		55		28		417		367		50		14
Utility margin	307		312		(5)		(2)		512		531		(19)		(4)
Operations and maintenance	77		74		3		4		140		156		(16)		(10)
Depreciation and amortization	100		91		9		10		201		181		20		11
Property and other taxes	12		11		1		9		24		23		1		4
Operating income	$	118	$	136	$	(18)	(13)	%	$	147	$	171	$	(24)	(14)	%

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Utility Margin

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

	Second Quarter								First Six Months
	2021		2020		Change				2021		2020		Change
Utility margin (in millions):
Operating revenue	$	559	$	509	$	50	10	%	$	929	$	898	$	31	3	%
Cost of fuel and energy	252		197		55		28		417		367		50		14
Utility margin	$	307	$	312	$	(5)	(2)	%	$	512	$	531	$	(19)	(4)	%
Sales (GWhs):
Residential	2,807		2,635		172		7	%	4,394		4,179		215		5	%
Commercial	1,271		1,071		200		19		2,225		2,082		143		7
Industrial	1,310		1,107		203		18		2,367		2,258		109		5
Other	45		46		(1)		(2)		92		94		(2)		(2)
Total fully bundled(1)	5,433		4,859		574		12		9,078		8,613		465		5
Distribution only service	620		501		119		24		1,136		1,112		24		2
Total retail	6,053		5,360		693		13		10,214		9,725		489		5
Wholesale	89		81		8		10		173		234		(61)		(26)
Total GWhs sold	6,142		5,441		701		13	%	10,387		9,959		428		4	%
Average number of retail customers (in thousands)	982		965		17		2	%	980		963		17		2	%
Average revenue per MWh:
Retail - fully bundled(1)	$	98.10	$	99.89	$	(1.79)	(2)	%	$	96.86	$	98.20	$	(1.34)	(1)	%
Wholesale	$	42.94	$	22.07	$	20.87	95	%	$	46.09	$	28.29	$	17.80	63	%
Heating degree days	14		42		(28)		(67)	%	1,008		984		24		2	%
Cooling degree days	1,477		1,308		169		13	%	1,483		1,310		173		13	%
Sources of energy (GWhs)(2)(3):
Natural gas	3,547		3,118		429		14	%	6,081		5,740		341		6	%
Renewables	20		20		—		—		36		36		—		—
Total energy generated	3,567		3,138		429		14		6,117		5,776		341		6
Energy purchased	2,104		1,926		178		9		3,459		3,166		293		9
Total	5,671		5,064		607		12	%	9,576		8,942		634		7	%
Average cost of energy per MWh(4):
Energy generated	$	21.82	$	17.53	$	4.29	24	%	$	18.96	$	19.55	$	(0.59)	(3)	%
Energy purchased	$	82.70	$	73.80	$	8.90	12	%	$	87.07	$	80.36	$	6.71	8	%

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

(2)    The average cost of energy per MWh and sources of energy excludes 249 GWhs and 318 GWhs of gas generated energy that is purchased at cost by related parties for the second quarter of 2021 and 2020, respectively. The average cost of energy per MWh and sources of energy excludes 932 GWhs and 1,028 GWhs of gas generated energy that is purchased at cost by related parties for the first six months of 2021 and 2020, respectively.

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

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

131

Quarter Ended June 30, 2021 Compared to Quarter Ended June 30, 2020

Utility margin decreased $5 million, or 2%, for the second quarter of 2021 compared to 2020 primarily due to:

•$15 million of lower retail rates due to the 2020 regulatory rate review with new rates effective January 2021,

•$6 million due to an adjustment to regulatory-related revenue deferrals,

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

•$1 million of lower other revenue due to a regulatory amortization of an impact fee that ended December 2020.

The decrease in utility margin was offset by:

•$15 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 12.9% primarily due to the impacts from COVID-19 recovery, which resulted in higher industrial, commercial and distribution only service customer usage, and higher residential customer usage, mainly from the favorable impact of weather and

•$2 million due to an increase in the average number of customers, primarily from the residential customer class.

Operations and maintenance increased $3 million, or 4%, for the second quarter of 2021 compared to 2020 primarily due to a higher accrual for earnings sharing of $6 million and higher plant operations and maintenance costs, partially offset by lower net regulatory instructed deferrals and amortizations of $6 million, mainly relating to deferrals in 2020 of the non-labor cost savings from the Navajo generating station retirement which was approved for amortization in the 2020 regulatory rate review with new rates effective January 2021, and timing of the regulatory impacts for the ON Line lease cost reallocation and lower energy efficiency program costs (offset in operating revenue).

Depreciation and amortization increased $9 million, or 10%, for the second quarter of 2021 compared to 2020 primarily due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in service.

Interest expense decreased $1 million, or 3%, for the second quarter of 2021 compared to 2020 primarily due to lower carrying charges on regulatory items.

Other, net increased $2 million, or 29%, for the second quarter of 2021 compared to 2020 primarily due to lower pension expense and higher interest income, mainly from carrying charges on regulatory items, partially offset by lower cash surrender value of corporate-owned life insurance policies.

Income tax expense decreased $14 million, or 61%, for the second quarter of 2021 compared to 2020. The effective tax rate was 10% in 2021 and 22% in 2020 and decreased primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021.

First Six Months Ended June 30, 2021 Compared to First Six Months Ended June 30, 2020

Utility margin decreased $19 million, or 4%, for the first six months of 2021 compared to 2020 primarily due to:

•$24 million of lower retail rates due to the 2020 regulatory rate review with new rates effective January 2021,

•$6 million due to an adjustment to regulatory-related revenue deferrals,

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

•$2 million of lower other revenue due to a regulatory amortization of an impact fee that ended December 2020.

The decrease in utility margin was offset by:

•$14 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 5.0% primarily due to the impacts from COVID-19 recovery, which resulted in higher commercial, industrial and distribution only service customer usage, and higher residential customer usage, mainly from the favorable impact of weather and

•$2 million due to an increase in the average number of customers, mainly residential.

132

Operations and maintenance decreased $16 million, or 10%, for the first six months of 2021 compared to 2020 primarily due to lower net regulatory instructed deferrals and amortizations of $17 million, mainly relating to deferrals in 2020 of the non-labor cost savings from the Navajo generating station retirement which was approved for amortization in the 2020 regulatory rate review with new rates effective January 2021, and timing of the regulatory impacts for the ON Line lease cost reallocation and lower energy efficiency program costs (offset in operating revenue), partially offset by a higher accrual for earnings sharing.

Depreciation and amortization increased $20 million, or 11%, for the first six months of 2021 compared to 2020 primarily due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in service.

Interest expense decreased $5 million, or 6%, for the first six months of 2021 compared to 2020 primarily due to lower carrying charges on regulatory items and lower interest expense on long-term debt.

Other, net increased $12 million for the first six months of 2021 compared to 2020 primarily due to higher cash surrender value of corporate-owned life insurance policies of $5 million, lower pension expense and higher interest income, mainly from carrying charges on regulatory items.

Income tax expense decreased $13 million, or 59%, for the first six months of 2021 compared to 2020. The effective tax rate was 10% in 2021 and 22% in 2020 and decreased primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021.

Liquidity and Capital Resources

As of June 30, 2021, Nevada Power's total net liquidity was as follows (in millions):

Cash and cash equivalents	$	79
Credit facility	400
Total net liquidity	$	479
Credit facility:
Maturity date	2024

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2021 and 2020 were $310 million and $207 million, respectively. The change was primarily due to the timing of payments for operating costs, higher collections from customers, increased collections of customer advances, timing of payments for fuel and energy costs and lower inventory purchases, partially offset by higher payments for income taxes.

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2021 and 2020 were $(237) million and $(257) million, respectively. The change was primarily due to decreased capital expenditures. 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, 2021 and 2020 were $(21) million and $50 million, respectively. The change was primarily due to lower proceeds from the issuance of long-term debt, partially offset by lower repayments of long-term debt and lower dividends paid to NV Energy, Inc.

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.

133

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
	2020		2021		2021
Electric distribution	$	128	$	87	$	184
Electric transmission	22		25		76
Solar generation	—		5		32
Other	107		120		197
Total	$	257	$	237	$	489

Nevada Power's Fourth Amendment to the 2018 Joint IRP proposed an increase in solar generation and electric transmission. Nevada Power has included estimates from its latest IRP filing in its forecast capital expenditures for 2021. These estimates are likely to change as a result of the RFP process and some are still pending PUCN approval. Nevada Power's historical and forecast capital expenditures include the following:

•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.

•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has proposed to build a 350-mile, 525 kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation. Construction of the project has been approved by the PUCN with the exception of the Northwest substation to Harry Allen substation segment for which approval was limited to design, permitting and land acquisition only. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.

•Solar generation investment includes expenditures for a 150 MWs solar photovoltaic facility with an additional 100 MWs capacity of co-located battery storage, known as the Dry Lake generating facility, that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023.

•Other investments include both growth projects and operating expenditures consisting of routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.

134

Contractual Obligations

As of June 30, 2021, 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, 2020.

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, 2020. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2020.

135

Sierra Pacific Power Company and its subsidiaries

Consolidated Financial Section

136

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 consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of June 30, 2021, the related consolidated statements of operations and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2021 and 2020, and of cash flows for the six-month periods ended June 30, 2021 and 2020, 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 Sierra Pacific as of December 31, 2020, 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 26, 2021, 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, 2020, 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 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 6, 2021

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SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)

	As of
	June 30,		December 31,
	2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	9	$	19
Trade receivables, net	100		97
Inventories	67		77
Derivative contracts	17		9
Regulatory assets	121		67
Other current assets	42		36
Total current assets	356		305
Property, plant and equipment, net	3,232		3,164
Regulatory assets	269		267
Other assets	185		183
Total assets	$	4,042	$	3,919
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	135	$	108
Accrued interest	14		14
Accrued property, income and other taxes	16		14
Short-term debt	74		45
Regulatory liabilities	24		34
Customer deposits	15		15
Other current liabilities	31		25
Total current liabilities	309		255
Long-term debt	1,164		1,164
Finance lease obligations	118		121
Regulatory liabilities	464		463
Deferred income taxes	390		374
Other long-term liabilities	141		131
Total liabilities	2,586		2,508
Commitments and contingencies (Note 8)
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	346		301
Accumulated other comprehensive loss, net	(1)		(1)
Total shareholder's equity	1,456		1,411
Total liabilities and shareholder's equity	$	4,042	$	3,919
The accompanying notes are an integral part of the consolidated financial statements.

138

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2021		2020		2021		2020
Operating revenue:
Regulated electric	$	189	$	165	$	370	$	349
Regulated natural gas	20		20		59		68
Total operating revenue	209		185		429		417
Operating expenses:
Cost of fuel and energy	93		72		175		152
Cost of natural gas purchased for resale	8		10		29		40
Operations and maintenance	41		41		77		83
Depreciation and amortization	36		34		72		68
Property and other taxes	6		5		12		11
Total operating expenses	184		162		365		354
Operating income	25		23		64		63
Other income (expense):
Interest expense	(13)		(14)		(27)		(28)
Allowance for borrowed funds	1		1		1		1
Allowance for equity funds	2		1		3		2
Other, net	3		3		9		4
Total other income (expense)	(7)		(9)		(14)		(21)
Income before income tax expense	18		14		50		42
Income tax expense	1		1		5		4
Net income	$	17	$	13	$	45	$	38
The accompanying notes are an integral part of these consolidated financial statements.

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SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)

								Accumulated
				Additional				Other		Total
	Common Stock			Paid-in		Retained		Comprehensive		Shareholder's
	Shares	Amount		Capital		Earnings		Loss, Net		Equity
Balance, 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
Balance, March 31, 2021	1,000	$	—	$	1,111	$	329	$	(1)	$	1,439
Net income	—	—		—		17		—		17
Balance, June 30, 2021	1,000	$	—	$	1,111	$	346	$	(1)	$	1,456
Balance, December 31, 2020	1,000	$	—	$	1,111	$	301	$	(1)	$	1,411
Net income	—	—		—		45		—		45
Balance, June 30, 2021	1,000	$	—	$	1,111	$	346	$	(1)	$	1,456
The accompanying notes are an integral part of these consolidated financial statements.

140

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2021		2020
Cash flows from operating activities:
Net income	$	45	$	38
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	72		68
Allowance for equity funds	(3)		(2)
Changes in regulatory assets and liabilities	(20)		(24)
Deferred income taxes and amortization of investment tax credits	8		(6)
Deferred energy	(47)		21
Amortization of deferred energy	2		1
Other, net	(2)		1
Changes in other operating assets and liabilities:
Trade receivables and other assets	(1)		11
Inventories	10		(19)
Accrued property, income and other taxes	(1)		10
Accounts payable and other liabilities	29		18
Net cash flows from operating activities	92		117
Cash flows from investing activities:
Capital expenditures	(128)		(110)
Net cash flows from investing activities	(128)		(110)
Cash flows from financing activities:
Net proceeds from short-term debt	29		—
Dividends paid	—		(20)
Other, net	(4)		(2)
Net cash flows from financing activities	25		(22)
Net change in cash and cash equivalents and restricted cash and cash equivalents	(11)		(15)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	26		32
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	15	$	17
The accompanying notes are an integral part of these consolidated financial statements.

141

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    General

Sierra Pacific Power Company, together with its subsidiaries ("Sierra Pacific"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company and its subsidiaries ("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 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, 2021 and for the three- and six-month periods ended June 30, 2021 and 2020. 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, 2021 and 2020. The results of operations for the three- and six-month periods ended June 30, 2021 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 Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2020 describes the most significant accounting policies used in the preparation of the unaudited Consolidated 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, 2021.

(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, 2021 and December 31, 2020, 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, 2021 and December 31, 2020, 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,
	2021		2020
Cash and cash equivalents	$	9	$	19
Restricted cash and cash equivalents included in other current assets	6		7
Total cash and cash equivalents and restricted cash and cash equivalents	$	15	$	26

142

(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,
		2021		2020
Utility plant:
Electric generation	25 - 60 years	$	1,140	$	1,130
Electric transmission	50 - 100 years	917		908
Electric distribution	20 - 100 years	1,774		1,754
Electric general and intangible plant	5 - 70 years	191		189
Natural gas distribution	35 - 70 years	432		429
Natural gas general and intangible plant	5 - 70 years	15		15
Common general	5 - 70 years	357		355
Utility plant		4,826		4,780
Accumulated depreciation and amortization		(1,806)		(1,755)
Utility plant, net		3,020		3,025
Other non-regulated, net of accumulated depreciation and amortization	70 years	2		2
Plant, net		3,022		3,027
Construction work-in-progress		210		137
Property, plant and equipment, net		$	3,232	$	3,164

(4)    Recent Financing Transactions

Credit Facilities

In June 2021, Sierra Pacific amended and restated its existing $250 million secured credit facility expiring in June 2022 with no remaining one-year extension options. The amendment extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.

(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,
	2021		2020		2021		2020
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Effects of ratemaking	(11)		(14)		(9)		(10)
Income tax credits	(1)		—		—		—
Other	(3)		—		(2)		(1)
Effective income tax rate	6	%	7	%	10	%	10	%

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.

143

(6)    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 receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):

	As of
	June 30,		December 31,
	2021		2020
Qualified Pension Plan:
Other non-current assets	$	29	$	26
Non-Qualified Pension Plans:
Other current liabilities	(1)		(1)
Other long-term liabilities	(8)		(8)
Other Postretirement Plans:
Other long-term liabilities	(14)		(13)

(7)    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 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 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.

144

The following table presents Sierra Pacific'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, 2021
Assets:
Commodity derivatives	$	—	$	—	$	18	$	18
Money market mutual funds(1)	8		—		—		8
	$	8	$	—	$	18	$	26
Liabilities - commodity derivatives	$	—	$	—	$	(6)	$	(6)
As of December 31, 2020
Assets:
Commodity derivatives	$	—	$	—	$	9	$	9
Money market mutual funds(1)	17		—		—		17
	$	17	$	—	$	9	$	26
Liabilities - commodity derivatives	$	—	$	—	$	(2)	$	(2)

(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.

Sierra Pacific's investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.

Sierra Pacific's long-term debt is carried at cost on the Consolidated 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, 2021				As of December 31, 2020
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	1,164	$	1,324	$	1,164	$	1,358

145

(8)    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 consolidated financial results.

Environmental Laws and Regulations

Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.

(9)    Revenue from Contracts with Customers

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

	Three-Month Periods
	Ended June 30,
	2021						2020
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Customer Revenue:
Retail:
Residential	$	68	$	13	$	81	$	63	$	14	$	77
Commercial	64		5		69		56		4		60
Industrial	42		2		44		34		2		36
Other	1		—		1		1		—		1
Total fully bundled	175		20		195		154		20		174
Distribution only service	1		—		1		1		—		1
Total retail	176		20		196		155		20		175
Wholesale, transmission and other	12		—		12		9		—		9
Total Customer Revenue	188		20		208		164		20		184
Other revenue	1		—		1		1		—		1
Total revenue	$	189	$	20	$	209	$	165	$	20	$	185

146

	Six-Month Periods
	Ended June 30,
	2021						2020
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Customer Revenue:
Retail:
Residential	$	138	$	38	$	176	$	132	$	44	$	176
Commercial	117		15		132		112		17		129
Industrial	81		5		86		75		6		81
Other	3		—		3		2		—		2
Total fully bundled	339		58		397		321		67		388
Distribution only service	2		—		2		2		—		2
Total retail	341		58		399		323		67		390
Wholesale, transmission and other	28		—		28		24		—		24
Total Customer Revenue	369		58		427		347		67		414
Other revenue	1		1		2		2		1		3
Total revenue	$	370	$	59	$	429	$	349	$	68	$	417

147

(10)    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,
	2021		2020		2021		2020
Operating revenue:
Regulated electric	$	189	$	165	$	370	$	349
Regulated natural gas	20		20		59		68
Total operating revenue	$	209	$	185	$	429	$	417
Operating income:
Regulated electric	$	21	$	20	$	52	$	53
Regulated natural gas	4		3		12		10
Total operating income	25		23		64		63
Interest expense	(13)		(14)		(27)		(28)
Allowance for borrowed funds	1		1		1		1
Allowance for equity funds	2		1		3		2
Other, net	3		3		9		4
Income before income tax expense	$	18	$	14	$	50	$	42

	As of
	June 30,		December 31,
	2021		2020
Assets:
Regulated electric	$	3,665	$	3,540
Regulated natural gas	350		342
Other(1)	27		37
Total assets	$	4,042	$	3,919

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

148

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 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 Consolidated Financial Statements and Notes to Consolidated 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 2021 and 2020

Overview

Net income for the second quarter of 2021 was $17 million, an increase of $4 million, or 31%, compared to 2020 primarily due to $3 million of higher electric utility margin, mainly from price impacts from changes in sales mix, partially offset by lower revenue recognized due to a favorable regulatory decision and an adjustment to regulatory-related revenue deferrals, and $2 million of higher natural gas utility margin, mainly from higher commercial usage due to the impacts from COVID-19 recovery.

Net income for the first six months of 2021 was $45 million, an increase of $7 million, or 18%, compared to 2020 primarily due to $6 million of lower operations and maintenance expenses, mainly due to lower plant operations and maintenance expenses, a lower accrual for earnings sharing and lower regulatory amortizations, and $5 million of higher other, net, mainly due to lower pension costs, higher cash surrender value of corporate-owned life insurance policies and higher interest income, partially offset by $4 million of higher depreciation and amortization, mainly from regulatory amortizations and higher plant 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, 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 Consolidated 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.

149

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
	2021		2020		Change				2021		2020		Change
Electric utility margin:
Operating revenue	$	189	$	165	$	24	15	%	$	370	$	349	$	21	6	%
Cost of fuel and energy	93		72		21		29		175		152		23		15
Electric utility margin	96		93		3		3		195		197		(2)		(1)
Natural gas utility margin:
Operating revenue	20		20		—		—	%	59		68		(9)		(13)	%
Natural gas purchased for resale	8		10		(2)		(20)		29		40		(11)		(28)
Natural gas utility margin	12		10		2		20		30		28		2		7
Utility margin	108		103		5		5	%	225		225		—		—	%
Operations and maintenance	41		41		—		—	%	77		83		(6)		(7)	%
Depreciation and amortization	36		34		2		6		72		68		4		6
Property and other taxes	6		5		1		20		12		11		1		9
Operating income	$	25	$	23	$	2	9	%	$	64	$	63	$	1	2	%

150

Electric Utility Margin

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

	Second Quarter								First Six Months
	2021		2020		Change				2021		2020		Change
Utility margin (in millions):
Operating revenue	$	189	$	165	$	24	15	%	$	370	$	349	$	21	6	%
Cost of fuel and energy	93		72		21		29		175		152		23		15
Utility margin	$	96	$	93	$	3	3	%	$	195	$	197	$	(2)	(1)	%
Sales (GWhs):
Residential	626		585		41		7	%	1,297		1,220		77		6	%
Commercial	788		722		66		9		1,465		1,423		42		3
Industrial	900		811		89		11		1,797		1,720		77		4
Other	3		4		(1)		(25)		7		8		(1)		(13)
Total fully bundled(1)	2,317		2,122		195		9		4,566		4,371		195		4
Distribution only service	420		425		(5)		(1)		817		837		(20)		(2)
Total retail	2,737		2,547		190		7		5,383		5,208		175		3
Wholesale	125		96		29		30		300		289		11		4
Total GWhs sold	2,862		2,643		219		8	%	5,683		5,497		186		3	%
Average number of retail customers (in thousands)	365		358		7		2	%	364		357		7		2	%
Average revenue per MWh:
Retail - fully bundled(1)	$	75.42	$	72.25	$	3.17	4	%	$	74.31	$	73.54	$	0.77	1	%
Wholesale	$	52.18	$	42.75	$	9.43	22	%	$	56.84	$	46.96	$	9.88	21	%
Heating degree days	498		591		(93)		(16)	%	2,696		2,657		39		1	%
Cooling degree days	369		220		149		68	%	369		220		149		68	%
Sources of energy (GWhs)(2):
Natural gas	1,133		1,165		(32)		(3)	%	2,215		2,380		(165)		(7)	%
Coal	436		154		282		*		465		220		245		*
Renewables(3)	13		13		—		—		19		19		—		—
Total energy generated	1,582		1,332		250		19		2,699		2,619		80		3
Energy purchased	1,149		1,127		22		2		2,522		2,452		70		3
Total	2,731		2,459		272		11	%	5,221		5,071		150		3	%
Average cost of energy per MWh(4):
Energy generated	$	23.88	$	27.52	$	(3.64)	(13)	%	$	24.44	$	27.04	$	(2.60)	(10)	%
Energy purchased	$	48.21	$	30.57	$	17.64	58	%	$	43.16	$	32.94	$	10.22	31	%

*    Not meaningful

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

151

Natural Gas Utility Margin

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

	Second Quarter								First Six Months
	2021		2020		Change				2021		2020		Change
Utility margin (in millions):
Operating revenue	$	20	$	20	$	—	—	%	$	59	$	68	$	(9)	(13)	%
Natural gas purchased for resale	8		10		(2)		(20)		29		40		(11)		(28)
Utility margin	$	12	$	10	$	2	20	%	$	30	$	28	$	2	7	%
Sold (000's Dths):
Residential	1,450		1,552		(102)		(7)	%	6,108		5,938		170		3	%
Commercial	775		718		57		8		3,079		2,885		194		7
Industrial	395		342		53		15		1,140		995		145		15
Total retail	2,620		2,612		8		—	%	10,327		9,818		509		5	%
Average number of retail customers (in thousands)	177		174		3		2	%	176		173		3		2	%
Average revenue per retail Dth sold	$	7.62	$	7.98	$	(0.36)	(5)	%	$	5.69	$	6.95	$	(1.26)	(18)	%
Heating degree days	498		591		(93)		(16)	%	2,696		2,657		39		1	%
Average cost of natural gas per retail Dth sold	$	3.21	$	3.66	$	(0.45)	(12)	%	$	2.86	$	4.07	$	(1.22)	(30)	%

Quarter Ended June 30, 2021 Compared to Quarter Ended June 30, 2020

Electric utility margin increased $3 million, or 3%, for the second quarter of 2021 compared to 2020 primarily due to:

•$5 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 7.4% primarily due to the impacts from COVID-19 recovery, which resulted in higher industrial and commercial usage, and higher residential customer usage, mainly from the favorable impact of weather and

•$1 million due to an increase in the average number of customers, primarily from the residential customer class.

The increase in utility margin was offset by:

•$3 million due to an adjustment to regulatory-related revenue deferrals and

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

Natural gas utility margin increased $2 million, or 20%, for the second quarter of 2021 compared to 2020 primarily due to higher commercial usage due to the impacts from COVID-19 recovery.

Depreciation and amortization increased $2 million, or 6%, for the second quarter of 2021 compared to 2020 primarily due to regulatory amortizations.

152

First Six Months Ended June 30, 2021 Compared to First Six Months Ended June 30, 2020

Electric utility margin decreased $2 million, or 1%, for the first six months of 2021 compared to 2020 primarily due to:

•$3 million in lower revenue recognized due to a favorable regulatory decision,

•$3 million due to an adjustment to regulatory-related revenue deferrals and

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

The decrease in utility margin was offset by:

•$4 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 3.4% primarily due to the impacts from COVID-19 recovery, which resulted in higher industrial and commercial usage and consistent distribution only service usage and higher residential customer usage, mainly from the favorable impact of weather and

•$1 million due to an increase in the average number of customers, mainly residential.

Natural gas utility margin increased $2 million, or 7%, for the first six months of 2021 compared to 2020 primarily due to higher commercial usage due to the impacts from COVID-19 recovery.

Operations and maintenance decreased $6 million, or 7%, for the first six months of 2021 compared to 2020 primarily due to lower plant operations and maintenance expenses, a lower accrual for earnings sharing and lower regulatory amortizations.

Depreciation and amortization increased $4 million, or 6%, for the first six months of 2021 compared to 2020 primarily due to regulatory amortizations and higher plant in service.

Other, net increased $5 million for the first six months of 2021 compared to 2020 primarily due to lower pension costs, higher cash surrender value of corporate-owned life insurance policies and higher interest income, mainly from carrying charges on regulatory items.

Income tax expense increased $1 million, or 25%, for the first six months of 2021 compared to 2020. The effective tax rate was 10% in 2021 and 2020.

Liquidity and Capital Resources

As of June 30, 2021, Sierra Pacific's total net liquidity was as follows (in millions):

Cash and cash equivalents	$	9
Credit facility	250
Less -
Short-term debt	(74)
Net credit facility	176
Total net liquidity	$	185
Credit facility:
Maturity date	2024

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2021 and 2020 were $92 million and $117 million, respectively. The change was primarily due to the timing of payments for fuel and energy costs and lower collections from customers partially offset by lower inventory purchases, increased collections of customer advances and the timing of payments for operating costs.

153

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2021 and 2020 were $(128) million and $(110) million, respectively. The change was primarily due to increased capital expenditures. 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, 2021 and 2020 were $25 million and $(22) million, respectively. The change was primarily due to higher proceeds from short-term debt and lower dividends paid to NV Energy, Inc.

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
	2020		2021		2021
Electric distribution	$	68	$	42	$	118
Electric transmission	17		31		103
Solar generation	—		—		18
Other	25		55		114
Total	$	110	$	128	$	353

Sierra Pacific's Fourth Amendment to the 2018 Joint IRP proposed an increase in electric transmission. Sierra Pacific has included estimates from its latest IRP filing in its forecast capital expenditures for 2021. These estimates are likely to change as a result of the RFP process and some are still pending PUCN approval. Sierra Pacific's historical and forecast capital expenditures include the following:

•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.

154

•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has proposed to build a 235-mile, 525 kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345 kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345 kV transmission line from the new Ft. Churchill substation to the Comstock Meadows substations. Construction of the project has been approved by the PUCN with the exception of the Ft. Churchill substation to the Robinson Summit substation segment for which conditional approval was limited to design, permitting and land acquisition only. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.

•Other investments include both growth projects and operating expenditures consisting of routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.

Contractual Obligations

As of June 30, 2021, 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, 2020.

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 consolidated financial results. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.

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

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the 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 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, 2020. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2020.

155

Eastern Energy Gas Holdings, LLC and its subsidiaries

Consolidated Financial Section

156

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Eastern Energy Gas Holdings, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Eastern Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of June 30, 2021, the related consolidated statements of operations, comprehensive income and changes in equity for the three-month and six-month periods ended June 30, 2021 and 2020, and of cash flows for the six-month periods ended June 30, 2021 and 2020, 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 Eastern Energy Gas as of December 31, 2020, 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 26, 2021, 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, 2020, 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 Eastern Energy Gas' management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Eastern Energy Gas 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

Richmond, Virginia

August 6, 2021

157

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30, 2021		December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents	$	86	$	35
Restricted cash and cash equivalents	11		13
Trade receivables, net	147		177
Receivables from affiliates	55		139
Income taxes receivable	96		20
Other receivables	39		51
Inventories	123		119
Other current assets	108		102
Total current assets	665		656
Property, plant and equipment, net	10,135		10,144
Goodwill	1,286		1,286
Investments	260		244
Other assets	184		291
Total assets	$	12,530	$	12,621

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

158

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	June 30, 2021		December 31, 2020
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	59	$	71
Accounts payable to affiliates	34		39
Accrued interest	14		19
Accrued property, income and other taxes	71		29
Notes payable	—		9
Current portion of long-term debt	—		500
Other current liabilities	155		147
Total current liabilities	333		814
Long-term debt	3,916		3,925
Regulatory liabilities	650		669
Other long-term liabilities	233		218
Total liabilities	5,132		5,626
Commitments and contingencies (Note 9)
Equity:
Member's equity:
Membership interests	3,366		2,957
Accumulated other comprehensive loss, net	(40)		(53)
Total member's equity	3,326		2,904
Noncontrolling interests	4,072		4,091
Total equity	7,398		6,995
Total liabilities and equity	$	12,530	$	12,621

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

159

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2021		2020		2021		2020
Operating revenue	$	437	$	510	$	923	$	1,066
Operating expenses:
(Excess) cost of gas	(10)		1		(10)		9
Operations and maintenance	113		635		237		803
Depreciation and amortization	81		94		161		187
Property and other taxes	38		32		77		71
Total operating expenses	222		762		465		1,070
Operating income (loss)	215		(252)		458		(4)
Other income (expense):
Interest expense	(42)		(50)		(86)		(108)
Allowance for equity funds	1		5		3		10
Interest and dividend income	—		27		—		57
Other, net	1		14		2		28
Total other income (expense)	(40)		(4)		(81)		(13)
Income (loss) before income tax expense (benefit) and equity income	175		(256)		377		(17)
Income tax expense (benefit)	22		(82)		49		(30)
Equity income	7		8		23		23
Net income (loss)	160		(166)		351		36
Net income attributable to noncontrolling interests	100		32		202		65
Net income (loss) attributable to Eastern Energy Gas	$	60	$	(198)	$	149	$	(29)

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

160

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2021		2020		2021		2020
Net income (loss)	$	160	$	(166)	$	351	$	36
Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $—, $—, $— and $1	2		2		4		3
Unrealized gains (losses) on cash flow hedges, net of tax of $—, $1, $3 and $(29)	3		(2)		13		(87)
Total other comprehensive income (loss), net of tax	5		—		17		(84)
Comprehensive income (loss)	165		(166)		368		(48)
Comprehensive income attributable to noncontrolling interests	100		32		206		65
Comprehensive income (loss) attributable to Eastern Energy Gas	$	65	$	(198)	$	162	$	(113)

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

161

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)

			Accumulated
			Other
	Membership		Comprehensive		Noncontrolling		Total
	Interests		Loss, Net		Interests		Equity
Balance, March 31, 2020	$	8,968	$	(271)	$	1,381	$	10,078
Net (loss) income	(198)		—		32		(166)
Distributions	(1,418)		—		(38)		(1,456)
Balance, June 30, 2020	$	7,352	$	(271)	$	1,375	$	8,456
Balance, December 31, 2019	$	9,031	$	(187)	$	1,385	$	10,229
Net (loss) income	(29)		—		65		36
Other comprehensive loss	—		(84)		—		(84)
Distributions	(1,650)		—		(75)		(1,725)
Balance, June 30, 2020	$	7,352	$	(271)	$	1,375	$	8,456
Balance, March 31, 2021	$	3,035	$	(45)	$	4,088	$	7,078
Net income	60		—		100		160
Other comprehensive income	—		5		—		5
Contributions	271		—		—		271
Distributions	—		—		(116)		(116)
Balance, June 30, 2021	$	3,366	$	(40)	$	4,072	$	7,398
Balance, December 31, 2020	$	2,957	$	(53)	$	4,091	$	6,995
Net income	149		—		202		351
Other comprehensive income	—		13		4		17
Contributions	282		—		—		282
Distributions	(22)		—		(225)		(247)
Balance, June 30, 2021	$	3,366	$	(40)	$	4,072	$	7,398

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

162

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2021		2020
Cash flows from operating activities:
Net income	$	351	$	36
Adjustments to reconcile net income to net cash flows from operating activities:
Losses on other items, net	3		482
Depreciation and amortization	161		187
Allowance for equity funds	(3)		(10)
Equity (income) loss, net of distributions	(3)		2
Changes in regulatory assets and liabilities	1		12
Deferred income taxes	118		(97)
Other, net	(9)		7
Changes in other operating assets and liabilities:
Trade receivables and other assets	65		429
Derivative collateral, net	(1)		11
Pension and other postretirement benefit plans	—		(35)
Accrued property, income and other taxes	(63)		(7)
Accounts payable and other liabilities	(39)		(9)
Net cash flows from operating activities	581		1,008
Cash flows from investing activities:
Capital expenditures	(150)		(147)
Repayment of loans by affiliates	268		1,165
Loans to affiliates	(158)		(263)
Other, net	(12)		(4)
Net cash flows from investing activities	(52)		751
Cash flows from financing activities:
Repayments of long-term debt	(500)		—
Net repayments of short-term debt	—		(62)
(Repayment) issuance of notes payable, net	(9)		54
Proceeds from equity contributions	256		—
Distributions	(225)		(1,725)
Other, net	(2)		(1)
Net cash flows from financing activities	(480)		(1,734)
Net change in cash and cash equivalents and restricted cash and cash equivalents	49		25
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	48		39
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	97	$	64

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

163

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    General

Eastern Energy Gas Holdings, LLC and its subsidiaries ("Eastern Energy Gas") is a holding company that conducts business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transportation pipeline and underground storage operations in the eastern region of the United States and operates Cove Point LNG, LP ("Cove Point"), a liquefied natural gas ("LNG") export, import and storage facility. Eastern Energy Gas owns 100% of the general partner interest and 25% of the limited partnership interest in Cove Point. In addition, Eastern Energy Gas owns a 50% noncontrolling interest in Iroquois Gas Transmission System, L.P. ("Iroquois"), a 416-mile FERC-regulated interstate natural gas transportation pipeline.

In July 2020, Dominion Energy, Inc. ("DEI") entered into an agreement to sell substantially all of its gas transmission and storage operations, including Eastern Energy Gas and a 25% limited partnership interest in Cove Point, to Berkshire Hathaway Energy Company ("BHE"). Approval of the transaction under the Hart-Scott-Rodino Act was not obtained within 75 days and DEI and BHE mutually agreed to a dual-phase closing consisting of two separate disposal groups identified as the acquisition of substantially all of the natural gas transmission and storage business of DEI and Dominion Energy Questar Corporation, exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "Questar Pipeline Group") (the "GT&S Transaction") and the proposed sale of the Questar Pipeline Group by DEI to BHE pursuant to a purchase and sale agreement entered into on October 5, 2020 ("Q-Pipe Transaction"). In July 2021, Dominion Energy Questar Corporation ("Dominion Questar") and DEI delivered a written notice to BHE stating that BHE and Dominion Questar have mutually elected to terminate the Q-Pipe Transaction. Prior to the completion of the GT&S Transaction, Eastern Energy Gas finalized a restructuring whereby Eastern Energy Gas distributed the Questar Pipeline Group and a 50% noncontrolling interest in Cove Point to DEI. This restructuring was accounted for by Eastern Energy Gas as a reorganization of entities under common control and the disposition was reflected as an equity transaction. The disposition was not reported as a discontinued operation as the disposal did not represent a strategic shift in the way management had intended to run the business. On November 1, 2020, BHE completed the GT&S Transaction. As a result of the GT&S Transaction, Eastern Energy Gas became an indirect wholly owned subsidiary of BHE. BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in the energy industry. 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, 2021 and for the three- and six-month periods ended June 30, 2021 and 2020. The results of operations for the three- and six-month periods ended June 30, 2021 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 Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2020 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Eastern Energy Gas' assumptions regarding significant accounting estimates and policies during the six-month period ended June 30, 2021.

164

(2)    Property, Plant and Equipment, Net

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

		As of
		June 30,		December 31,
	Depreciable Life	2021		2020
Utility Plant:
Interstate natural gas pipeline assets	24 - 43 years	$	8,457	$	8,382
Intangible plant	5 - 10 years	111		115
Utility plant in service		8,568		8,497
Accumulated depreciation and amortization		(2,816)		(2,759)
Utility plant in service, net		5,752		5,738
Nonutility Plant:
LNG facility	40 years	4,465		4,454
Intangible plant	14 years	25		25
Nonutility plant in service		4,490		4,479
Accumulated depreciation and amortization		(366)		(283)
Nonutility plant in service, net		4,124		4,196
Plant, net		9,876		9,934
Construction work-in-progress		259		210
Property, plant and equipment, net		$	10,135	$	10,144

Construction work-in-progress includes $246 million and $196 million as of June 30, 2021 and December 31, 2020, respectively, related to the construction of utility plant.

165

(3)    Investments and Restricted Cash and Cash Equivalents

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

	As of
	June 30,		December 31,
	2021		2020
Investments:
Investment funds	$	13	$	—
Equity method investments:
Iroquois	247		244
Total investments	260		244
Restricted cash and cash equivalents:
Customer deposits	11		13
Total restricted cash and cash equivalents	11		13
Total investments and restricted cash and cash equivalents	$	271	$	257
Reflected as:
Current assets	$	11	$	13
Noncurrent assets	260		244
Total investments and restricted cash and cash equivalents	$	271	$	257

Equity Method Investments

Eastern Energy Gas, through a subsidiary, owns 50% of Iroquois, which owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut. Prior to the GT&S Transaction, Eastern Energy Gas, through the Questar Pipeline Group, owned 50% of White River Hub, which owns and operates a natural gas pipeline in northwest Colorado.

As of June 30, 2021 and December 31, 2020, the carrying amount of Eastern Energy Gas' investments exceeded its share of underlying equity in net assets by $130 million. The difference reflects equity method goodwill and is not being amortized. Eastern Energy Gas received distributions from its investments of $20 million and $25 million for the six-month periods ended June 30, 2021 and 2020, respectively.

166

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, 2021 and December 31, 2020 consist of customer deposits as allowed under the FERC gas tariffs. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of June 30, 2021 and December 31, 2020, 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,
	2021		2020
Cash and cash equivalents	$	86	$	35
Restricted cash and cash equivalents	11		13
Total cash and cash equivalents and restricted cash and cash equivalents	$	97	$	48

(4)    Regulatory Matters

Eastern Gas Transmission and Storage, Inc.

In July 2017, the FERC audit staff communicated to Eastern Gas Transmission and Storage, Inc. ("EGTS") that it had substantially completed an audit of EGTS' compliance with the accounting and reporting requirements of the FERC's Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report. In December 2017, EGTS provided its response to the audit report. EGTS requested FERC review of the contested findings and submitted its plan for compliance with the uncontested portions of the report. EGTS reached resolution of certain matters with the FERC in the fourth quarter of 2018. EGTS recognized a charge of $129 million ($94 million after-tax) for the year ended December 31, 2018 for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with the FERC. In December 2020, the FERC issued a final ruling on the remaining matter, which resulted in a $43 million ($31 million after-tax) estimated charge for disallowance of capitalized allowance for funds used during construction. As a condition of the December 2020 ruling, EGTS filed its proposed accounting entries and supporting documentation with the FERC during the second quarter of 2021. During the finalization of these entries, EGTS refined the estimated charge for disallowance of capitalized allowance for funds used during construction, which resulted in a reduction to the estimated charge of $11 million ($8 million after-tax) that was recorded in operations and maintenance expense in its Consolidated Statements of Operations in the second quarter of 2021.

In December 2014, EGTS entered into a precedent agreement with Atlantic Coast Pipeline, LLC ("Atlantic Coast Pipeline") for the project previously intended for EGTS to provide approximately 1,500,000 decatherms ("Dth") of firm transportation service to various customers in connection with the Atlantic Coast Pipeline project ("Supply Header Project"). As a result of the cancellation of the Atlantic Coast Pipeline project, in the second quarter of 2020 Eastern Energy Gas recorded a charge of $482 million ($359 million after-tax) in operations and maintenance expense in its Consolidated Statements of Operations associated with the probable abandonment of a significant portion of the project as well as the establishment of a $75 million asset retirement obligation. As EGTS evaluates its future use, approximately $40 million remains within property, plant and equipment for a potential modified project.

167

Cove Point

In January 2020, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective March 1, 2020. Cove Point proposed an annual cost-of-service of $182 million. In February 2020, the FERC approved suspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund. In November 2020, Cove Point reached an agreement in principle with the active participants in the general rate case proceeding. Under the terms of the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual revenues of $4 million and a decrease in annual depreciation expense of $1 million, compared to the rates in effect prior to August 1, 2020. The interim settlement rates were implemented November 1, 2020, and Cove Point's provision for rate refunds for August 2020 through October 2020 totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC in January 2021. In March 2021, the FERC approved the stipulation and agreement and the rate refunds to customers were processed in late April 2021.

(5)    Recent Financing Transactions

On June 30, 2021, as part of an intercompany transaction with its wholly owned subsidiary EGTS, Eastern Energy Gas exchanged a total of $1.6 billion of its issued and outstanding third party notes, making EGTS the primary obligor of the exchanged notes. The intercompany debt exchange was a common control transaction accounted for as a debt modification with no gain or loss recognized in the Consolidated Financial Statements. The following table details the exchanged notes prior to, and subsequent to, the transaction (in millions):

	Prior to Exchange		Subsequent to Exchange
	Eastern Energy Gas Par Value		Eastern Energy Gas Par Value		EGTS Par Value
3.6% Senior Notes due 2024	$	450	$	339	$	111
3.0% Senior Notes due 2029	600		174		426
4.8% Senior Notes due 2043	400		54		346
4.6% Senior Notes due 2044	500		56		444
3.9% Senior Notes due 2049	300		27		273
	$	2,250	$	650	$	1,600

168

(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,
	2021		2020		2021		2020
Federal statutory income tax rate	21	%	21	%	21	%	21	%
State income tax, net of federal income tax benefit	2		11		3		114
Equity interest	1		(1)		1		(27)
Effects of ratemaking	(1)		1		(1)		17
AFUDC-equity	—		—		—		11
Noncontrolling interest	(12)		3		(11)		78
Write-off of regulatory assets	—		(3)		—		(39)
Other, net	2		—		—		1
Effective income tax rate	13	%	32	%	13	%	176	%

Noncontrolling interest is attributable to Eastern Energy Gas' ownership in Cove Point. The GT&S Transaction resulted in a change of noncontrolling interest to 75% as of June 30, 2021 from 25% as of June 30, 2020. Additionally, Eastern Energy Gas' effective tax rate for the period ended June 30, 2020 is primarily a function of the impacts associated with the cancellation of the Atlantic Coast Pipeline project and the nominal year-to date pre-tax income driven by charges associated with the Supply Header Project.

Through October 31, 2020, Eastern Energy Gas was included in DEI's consolidated federal income tax return and, where applicable, combined state income tax returns. All affiliate payables or receivables were settled with DEI prior to the closing date of the GT&S Transaction. Subsequent to the GT&S Transaction, Eastern Energy Gas, as a subsidiary of BHE, is included in Berkshire Hathaway's United States federal income tax return. Consistent with established regulatory practice, Eastern Energy Gas' provisions for income tax have 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. Eastern Energy Gas made net cash payments for income tax to BHE totaling $5 million for the six-month period ended June 30, 2021.

(7)    Employee Benefit Plans

Prior to the GT&S Transaction, certain Eastern Energy Gas employees not represented by collective bargaining units were covered by the Dominion Energy Pension Plan, a defined benefit pension plan sponsored by DEI that provides benefits to multiple DEI subsidiaries. As participating employers, Eastern Energy Gas was subject to DEI's funding policy, which was to contribute annually an amount that is in accordance with the Employee Retirement Income Security Act of 1974. Also prior to the GT&S Transaction, pension benefits for Eastern Energy Gas employees represented by collective bargaining units were provided by a separate plan that provides benefits to employees of both EGTS and Hope Gas, Inc. ("Hope"). Subsequent to the GT&S Transaction, Eastern Energy Gas employees are covered by the MidAmerican Energy Company ("MidAmerican Energy") Pension Plan, similar to the DEI plan.

Prior to the GT&S Transaction, certain retiree healthcare and life insurance benefits for Eastern Energy Gas employees not represented by collective bargaining units were covered by the Dominion Energy Retiree Health and Welfare Plan, a plan sponsored by DEI that provides certain retiree healthcare and life insurance benefits to multiple DEI subsidiaries. Also prior to the GT&S Transaction, retiree health and life insurance benefits for Eastern Energy Gas employees represented by collective bargaining units were covered by a separate other postretirement benefit plan that provides benefits to both EGTS and Hope. Subsequent to the GT&S Transaction, Eastern Energy Gas employees are covered by the MidAmerican Energy Retiree Health and Welfare plan, similar to the DEI plan.

169

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,
	2021		2020		2021		2020
Pension:
Service cost	$	—	$	2	$	—	$	3
Interest cost	—		2		—		5
Expected return on plan assets	—		(14)		—		(28)
Net amortization	—		2		—		4
Net periodic benefit credit	$	—	$	(8)	$	—	$	(16)
Other Postretirement:
Service cost	$	—	$	—	$	—	$	1
Interest cost	—		1		—		2
Expected return on plan assets	—		(5)		—		(10)
Net amortization	—		—		—		(1)
Net periodic benefit credit	$	—	$	(4)	$	—	$	(8)

(8)    Fair Value Measurements

The carrying value of Eastern Energy Gas' cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Eastern Energy Gas 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 Eastern Energy Gas 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 Eastern Energy Gas' judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Eastern Energy Gas develops these inputs based on the best information available, including its own data.

170

The following table presents Eastern Energy Gas' 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		Total
As of June 30, 2021
Assets:
Foreign currency exchange rate derivatives	$	—	$	16	$	—	$	16
Money market mutual funds(1)	45		—		—		45
Investment funds	13		—		—		13
	$	58	$	16	$	—	$	74
Liabilities:
Foreign currency exchange rate derivatives	$	—	$	(5)	$	—	$	(5)
	$	—	$	(5)	$	—	$	(5)
As of December 31, 2020
Assets:
Foreign currency exchange rate derivatives	$	—	$	20	$	—	$	20
	$	—	$	20	$	—	$	20
Liabilities:
Commodity derivatives	$	—	$	(1)	$	—	$	(1)
Foreign currency exchange rate derivatives	—		(2)		—		(2)
Interest rate derivatives	—		(6)		—		(6)
	$	—	$	(9)	$	—	$	(9)

(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 purchase 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 Eastern Energy Gas transacts. When quoted prices for identical contracts are not available, Eastern Energy Gas uses forward price curves. Forward price curves represent Eastern Energy Gas' estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Eastern Energy Gas 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 Eastern Energy Gas. Market price quotations are generally readily obtainable for the applicable term of Eastern Energy Gas' outstanding derivative contracts; therefore, Eastern Energy Gas' forward price curves reflect observable market quotes. Market price quotations for certain natural gas trading hubs are not as readily obtainable due to the length of the contracts. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, Eastern Energy Gas 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.

171

Eastern Energy Gas' long-term debt is carried at cost, including unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Balance Sheets. The fair value of Eastern Energy Gas' 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 Eastern Energy Gas' 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 Eastern Energy Gas' long-term debt (in millions):

	As of June 30, 2021				As of December 31, 2020
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	3,916	$	4,298	$	4,425	$	5,012

(9)    Commitments and Contingencies

Legal Matters

Eastern Energy Gas is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Eastern Energy Gas does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

Environmental Laws and Regulations

Eastern Energy Gas is subject to federal, state and local laws and regulations regarding climate change, air and water quality, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations.

(10)    Revenue from Contracts with Customers

The following table summarizes Eastern Energy Gas' revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business (in millions):

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2021		2020		2021		2020
Customer Revenue:
Regulated:
Gas transportation and storage	$	246	$	302	$	525	$	646
Wholesale	—		—		17		2
Other	(2)		2		(2)		3
Total regulated	244		304		540		651
Nonregulated	190		205		380		413
Total Customer Revenue	434		509		920		1,064
Other revenue	3		1		3		2
Total operating revenue	$	437	$	510	$	923	$	1,066

172

Remaining Performance Obligations

The following table summarizes Eastern Energy Gas' 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, 2021 (in millions):

	Performance obligations expected to be satisfied
	Less than 12 months		More than 12 months		Total
Eastern Energy Gas	$	1,571	$	16,779	$	18,350

(11)    Components of Accumulated Other Comprehensive Loss, Net

The following table shows the change in accumulated other comprehensive loss by each component of other comprehensive income (loss), net of applicable income tax (in millions):

	Unrecognized						Accumulated
	Amounts On		Unrealized				Other
	Retirement		Losses on Cash		Noncontrolling		Comprehensive
	Benefits		Flow Hedges		Interests		Loss, Net
Balance, December 31, 2019	$	(106)	$	(81)	$	—	$	(187)
Other comprehensive income (loss)	3		(87)		—		(84)
Balance, June 30, 2020	$	(103)	$	(168)	$	—	$	(271)
Balance, December 31, 2020	$	(12)	$	(51)	$	10	$	(53)
Other comprehensive income (loss)	4		13		(4)		13
Balance, June 30, 2021	$	(8)	$	(38)	$	6	$	(40)

(12)    Variable Interest Entities

The primary beneficiary of a variable interest entity ("VIE") is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity's economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.

In November 2019, DEI contributed to Eastern Energy Gas a 75% controlling limited partner interest in Cove Point. In December 2019, DEI sold its retained 25% noncontrolling limited partner interest in Cove Point. As part of the GT&S Transaction, Eastern Energy Gas finalized a restructuring which included the disposition of a 50% noncontrolling interest in Cove Point to DEI, which resulted in Eastern Energy Gas owning 100% of the general partner interest and 25% of the limited partnership interest in Cove Point. Eastern Energy Gas concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. Eastern Energy Gas is the primary beneficiary of Cove Point as it has the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it.

Eastern Energy Gas purchased shared services from Carolina Gas Services, Inc. ("Carolina Gas Services") an affiliated VIE, of $3 million for each of the three-month periods ended June 30, 2021 and 2020, and $6 million and $7 million for the six-month periods ended June 30, 2021 and 2020, respectively. Eastern Energy Gas' Consolidated Balance Sheets included amounts due to Carolina Gas Services of $28 million and $22 million as of June 30, 2021 and December 31, 2020, respectively. Eastern Energy Gas determined that neither it nor any of its consolidated entities is the primary beneficiary of Carolina Gas Services as neither it nor any of its consolidated entities has both the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to them. Carolina Gas Services provides marketing and operational services. Neither Eastern Energy Gas nor any of its consolidated entities has any obligation to absorb more than its allocated share of Carolina Gas Services costs.

173

Prior to the GT&S Transaction, Eastern Energy Gas purchased shared services from Dominion Energy Questar Pipeline Services, Inc. ("DEQPS"), an affiliated VIE, of $7 million and $14 million for the three- and six-month periods ended June 30, 2020, respectively. Eastern Energy Gas determined that neither it nor any of its consolidated entities was the primary beneficiary of DEQPS, as neither it nor any of its consolidated entities has both the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. DEQPS provided marketing and operational services. Neither Eastern Energy Gas nor any of its consolidated entities had any obligation to absorb more than its allocated share of DEQPS costs.

Prior to the GT&S Transaction, Eastern Energy Gas purchased shared services from Dominion Energy Services, Inc. ("DES"), an affiliated VIE, of $27 million and $58 million for the three- and six-month periods ended June 30, 2020, respectively. Eastern Energy Gas determined that neither it nor any of its consolidated entities was the primary beneficiary of DES as neither it nor any of its consolidated entities had both the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. DES provided accounting, legal, finance and certain administrative and technical services. Neither Eastern Energy Gas nor any of its consolidated entities had any obligation to absorb more than its allocated share of DES costs.

(13)    Related Party Transactions

Transactions Prior to the GT&S Transaction

Prior to the GT&S Transaction, Eastern Energy Gas engaged in related party transactions primarily with other DEI subsidiaries (affiliates). Eastern Energy Gas' receivable and payable balances with affiliates were settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Through October 31, 2020, Eastern Energy Gas was included in DEI's consolidated federal income tax return and, where applicable, combined state income tax returns. All affiliate payables or receivables were settled with DEI prior to the closing of the GT&S Transaction.

Eastern Energy Gas transacted with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Eastern Energy Gas provided transportation and storage services to affiliates. Eastern Energy Gas also entered into certain other contracts with affiliates, and related parties, including construction services, which were presented separately from contracts involving commodities or services. Eastern Energy Gas participated in certain DEI benefit plans as described in Note 7.

DES, Carolina Gas Services, DEQPS and other affiliates provided accounting, legal, finance and certain administrative and technical services to Eastern Energy Gas. Eastern Energy Gas provided certain services to related parties, including technical services.

The financial statements for the three-month and six-month periods ended June 30, 2020 include costs for certain general, administrative and corporate expenses assigned by DES, Carolina Gas Services and DEQPS to Eastern Energy Gas on the basis of direct and allocated methods in accordance with Eastern Energy Gas' services agreements with DES, Carolina Gas Services and DEQPS. Where costs incurred cannot be determined by specific identification, the costs were allocated based on the proportional level of effort devoted by DES, Carolina Gas Services and DEQPS resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.

Subsequent to the GT&S Transaction, and with the exception of Cove Point, Eastern Energy Gas' transactions with other DEI subsidiaries are no longer related-party transactions.

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Presented below are Eastern Energy Gas' significant transactions with DES, Carolina Gas Services, DEQPS and other affiliated and related parties for the three- and six-month periods ended June 30, 2020 (in millions):

	Three-Month Period		Six-Month Period
	Ended June 30, 2020		Ended June 30, 2020
Sales of natural gas and transportation and storage services	$	60	$	128
Purchases of natural gas and transportation and storage services	3		6
Services provided by related parties(1)	37		80
Services provided to related parties(2)	29		61

(1)    Includes capitalized expenditures of $4 million and $7 million for the three- and six-month periods ended June 30, 2020, respectively.

(2)    Amounts primarily attributable to Atlantic Coast Pipeline, LLC, a related-party VIE prior to the GT&S Transaction.

Interest income related to Eastern Energy Gas' affiliated notes receivable from DEI was $12 million and $23 million for the three- and six-month periods ended June 30, 2020, respectively.

Interest income related to Eastern Energy Gas' affiliated notes receivable from East Ohio Gas Company was $15 million and $33 million for the three- and six-month periods ended June 30, 2020, respectively.

For the six-month period ended June 30, 2020, Eastern Energy Gas distributed $1.7 billion to DEI.

Transactions Subsequent to the GT&S Transaction

Eastern Energy Gas is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated United States federal income tax return. For current federal and state income taxes, Eastern Energy Gas had a receivable from BHE of $76 million and $20 million as of June 30, 2021 and December 31, 2020, respectively.

Presented below are Eastern Energy Gas' significant transactions with affiliated and related parties for the three- and six-month periods ended June 30, 2021 (in millions):

	Three-Month Period		Six-Month Period
	Ended June 30, 2021		Ended June 30, 2021
Sales of natural gas and transportation and storage services	$	7	$	14
Services provided by related parties	8		15
Services provided to related parties	7		16

Other assets included amounts due from an affiliate of $5 million and $7 million as of June 30, 2021 and December 31, 2020, respectively.

Eastern Energy Gas has a $400 million intercompany revolving credit agreement from its parent, BHE GT&S, LLC ("BHE GT&S") expiring in November 2021. The credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on London Interbank Offered Rate ("LIBOR") plus a fixed spread. As of June 30, 2021 and December 31, 2020, $— million and $9 million, respectively, was outstanding under the credit agreement.

BHE GT&S has an intercompany revolving credit agreement from Eastern Energy Gas expiring in December 2021. In March 2021, BHE GT&S increased its credit facility limit from $200 million to $400 million. The credit agreement has a variable interest rate based on LIBOR plus a fixed spread. As of June 30, 2021 and December 31, 2020, $16 million and $124 million, respectively, was outstanding under the credit agreement.

Eastern Energy Gas participates in certain MidAmerican Energy benefit plans as described in Note 7. As of June 30, 2021 and December 31, 2020, Eastern Energy Gas' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets was $110 million and $115 million, respectively.

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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 Eastern Energy Gas during the periods included herein. This discussion should be read in conjunction with Eastern Energy Gas' historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Eastern Energy Gas' actual results in the future could differ significantly from the historical results.

Results of Operations for the Second Quarter and First Six Months of 2021 and 2020

Overview

Net income attributable to Eastern Energy Gas for the second quarter of 2021 was $60 million, an increase of $258 million compared to 2020. Net income increased primarily due to a 2020 after-tax charge of $359 million associated with the probable abandonment of a significant portion of a project previously intended for EGTS to provide approximately 1,500,000 Dths of firm transportation service to various customers in connection with the Atlantic Coast Pipeline project ("Supply Header Project"). This increase is partially offset by an increase in net income attributable to noncontrolling interests due to DEI's 50% noncontrolling interest in Cove Point LNG, LP ("Cove Point") of $68 million, the November 2020 disposition of Questar Pipeline Group of $19 million and interest income from DEI and its affiliates recognized in 2020 of $27 million, all of which were a result of the GT&S Transaction.

Net income attributable to Eastern Energy Gas for the first six months of 2021 was $149 million, an increase of $178 million compared to 2020. Net income increased primarily due to a 2020 after-tax charge of $359 million associated with the probable abandonment of a significant portion of the Supply Header Project. This increase is partially offset by an increase in net income attributable to noncontrolling interests due to DEI's 50% noncontrolling interest in Cove Point of $137 million, the November 2020 disposition of Questar Pipeline Group of $42 million, and interest income from DEI and its affiliates recognized in 2020 of $56 million, all of which were a result of the GT&S Transaction.

Quarter Ended June 30, 2021 Compared to Quarter Ended June 30, 2020

Operating revenue decreased $73 million, or 14%, for the second quarter of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group of $56 million and a decrease in services performed for Atlantic Coast Pipeline, LLC of $16 million, which is offset in operations and maintenance expense.

(Excess) cost of gas was a credit of $10 million for the second quarter of 2021 compared to an expense of $1 million for the second quarter of 2020. The change in (excess) cost of gas is primarily due to a favorable change in natural gas prices.

Operations and maintenance decreased $522 million, or 82%, for the second quarter of 2021 compared to 2020, primarily due to a 2020 charge associated with the probable abandonment of a significant portion of the Supply Header Project of $482 million, a decrease in services performed for Atlantic Coast Pipeline, LLC of $17 million and the November 2020 disposition of Questar Pipeline Group of $11 million.

Depreciation and amortization decreased $13 million, or 14%, for the second quarter of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group.

Property and other taxes increased $6 million, or 19%, for the second quarter of 2021 compared to 2020, primarily due to higher tax assessments.

Interest expense decreased $8 million, or 16%, for the second quarter of 2021 compared to 2020, primarily due to lower interest expense of $3 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020 and the November 2020 disposition of Questar Pipeline Group of $5 million.

Allowance for equity funds decreased $4 million, or 80%, for the second quarter of 2021 compared to 2020, primarily due to lower capital expenditures related to the Supply Header Project as a result of the abandonment of the project.

Interest and dividend income decreased $27 million for the second quarter of 2021 compared to 2020, due to interest income from the East Ohio Gas Company of $15 million and DEI of $12 million recognized in 2020 as a result of the GT&S Transaction.

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Other, net decreased $13 million, or 93%, for the second quarter of 2021 compared to 2020, primarily due to a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI as a result of the GT&S Transaction.

Income tax expense (benefit) was an expense of $22 million for the second quarter of 2021 compared to a benefit of $82 million for the second quarter of 2020 and the effective tax rate was 13% for the second quarter of 2021 and 32% for the second quarter of 2020. The effective tax rate decreased primarily due to the change in the noncontrolling interest of Cove Point as a result of the GT&S Transaction and lower pre-tax income driven by charges associated with the Supply Header Project.

Net income attributable to noncontrolling interests increased $68 million for the second quarter of 2021 compared to 2020 primarily due to DEI's 50% noncontrolling interest in Cove Point effective with the GT&S Transaction.

First Six Months Ended June 30, 2021 Compared to First Six Months Ended June 30, 2020

Operating revenue decreased $143 million, or 13%, for the first six months of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group of $120 million and a decrease in services performed for Atlantic Coast Pipeline, LLC of $33 million, which is offset in operations and maintenance expense. This decrease in operating revenue was partially offset by an increase in regulated gas sales for operational and system balancing purposes primarily due to increased volumes of $17 million.

(Excess) cost of gas was a credit of $10 million for the first six months of 2021 compared to an expense of $9 million for the first six months of 2020. The change in (excess) cost of gas is primarily due to a favorable change in natural gas prices of $30 million and the November 2020 disposition of Questar Pipeline Group of $2 million, partially offset by an increase in volumes sold of $14 million.

Operations and maintenance decreased $566 million, or 70%, for the first six months of 2021 compared to 2020, primarily due to a 2020 charge associated with the probable abandonment of a significant portion of the Supply Header Project of $482 million, a decrease in services performed for Atlantic Coast Pipeline, LLC of $34 million and the November 2020 disposition of Questar Pipeline Group of $26 million.

Depreciation and amortization decreased $26 million, or 14%, for the first six months of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group.

Property and other taxes increased $6 million, or 8%, for the first six months of 2021 compared to 2020, primarily due to higher tax assessments.

Interest expense decreased $22 million, or 20%, for the first six months of 2021 compared to 2020, primarily due to lower interest expense of $10 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020 and the November 2020 disposition of Questar Pipeline Group of $10 million.

Allowance for equity funds decreased $7 million, or 70%, for the first six months of 2021 compared to 2020, primarily due to lower capital expenditures related to the Supply Header Project as a result of the abandonment of the project.

Interest and dividend income decreased $57 million for the first six months of 2021 compared to 2020, primarily due to interest income from the East Ohio Gas Company of $33 million and DEI of $23 million recognized in 2020 as a result of the GT&S Transaction.

Other, net decreased $26 million, or 93%, for the first six months of 2021 compared to 2020, primarily due to a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI as a result of the GT&S Transaction.

Income tax expense (benefit) was an expense of $49 million for the first six months of 2021 compared to a benefit of $30 million for the first six months of 2020 and the effective tax rate was 13% for the first six months of 2021 and 176% for the first six months of 2020. The effective tax rate decreased primarily due to the change in the noncontrolling interest of Cove Point as a result of the GT&S Transaction and lower pre-tax income driven by charges associated with the Supply Header Project.

Net income attributable to noncontrolling interests increased $137 million for the first six months of 2021 compared to 2020 primarily due to DEI's 50% noncontrolling interest in Cove Point effective with the GT&S Transaction.

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Liquidity and Capital Resources

As of June 30, 2021, Eastern Energy Gas' total net liquidity was $486 million as follows (in millions):

Cash and cash equivalents	$	86
Intercompany credit agreement(1)	400
Less:
Notes payable	—
Net intercompany credit agreement	400
Total net liquidity	$	486
Intercompany credit agreement:
Maturity date	2021

(1)Refer to Note 13 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for further discussion regarding Eastern Energy Gas' intercompany credit agreement.

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2021 and 2020 were $581 million and $1.0 billion, respectively. The change was primarily due to lower collections from affiliates, lower income tax receipts and the timing of payments of operating costs.

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

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2021 and 2020 were $(52) million and $751 million, respectively. The change was primarily due to a decrease in repayments of loans by affiliates of $897 million, partially offset by a decrease in loans to affiliates of $105 million.

Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2021 were $(480) million. Sources of cash totaled $256 million and consisted of proceeds from equity contributions, that primarily included a contribution from its indirect parent, BHE, to Eastern Energy Gas to assist in the repayment of $500 million of debt. Uses of cash totaled $736 million and consisted mainly of repayments of long-term debt of $500 million, distributions to noncontrolling interests from Cove Point of $225 million and repayment of notes to affiliates of $9 million.

Net cash flows from financing activities for the six-month period ended June 30, 2020 were $(1.7) billion. Sources of cash consisted of $54 million from the net issuances of affiliated current borrowings. Uses of cash totaled $1.8 billion and consisted mainly of distributions to DEI of $1.7 billion and repayments of short-term debt of $62 million.

Future Uses of Cash

Eastern Energy Gas 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 credit agreements, capital contributions 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 Eastern Energy Gas and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, Eastern Energy Gas' credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

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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; 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 acquisition of existing assets.

Eastern Energy Gas' historical and forecasted 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
	2020		2021		2021
Natural gas transmission and storage	$	49	$	11	$	22
Other	98		139		448
Total	$	147	$	150	$	470

Eastern Energy Gas' natural gas transmission and storage capital expenditures primarily include growth capital expenditures related to planned regulated projects. Eastern Energy Gas' other capital expenditures consist primarily of non-regulated and routine capital expenditures for natural gas transmission, storage and liquefied natural gas terminalling infrastructure needed to serve existing and expected demand.

Contractual Obligations

As of June 30, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2020.

Regulatory Matters

Eastern Energy Gas is subject to comprehensive regulation. Refer to Note 4 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for discussion regarding Eastern Energy Gas' current regulatory matters.

Environmental Laws and Regulations

Eastern Energy Gas is subject to federal, state and local laws and regulations regarding climate change, air and water quality, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts.

Refer to "Environmental Laws and Regulations" in 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, impairment of goodwill and long-lived assets and income taxes. For additional discussion of Eastern Energy Gas' critical accounting estimates, see Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2020. There have been no significant changes in Eastern Energy Gas' assumptions regarding critical accounting estimates since December 31, 2020.

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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, 2020. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2020. 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, 2021.

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, Sierra Pacific Power Company and Eastern Energy Gas Holdings, LLC 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, 2021 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

Berkshire Hathaway Energy and PacifiCorp

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

On March 12, 2021, a complaint against PacifiCorp was filed, captioned Shyla Zeober et al. v. PacifiCorp, Case No. 21cv09339, Circuit Court, Marion County, Oregon. The complaint was filed by Oregon residents and businesses who allege that they were injured by the Beachie Creek Fire, which the plaintiffs allege began on or around September 7, 2020, but which government reports indicate began on or around August 16, 2020. The complaint alleges that PacifiCorp's assets contributed to the Beachie Creek Fire and that PacifiCorp acted with gross negligence, among other things. The complaint seeks the following damages: (i) damages for real and personal property and other economic losses in an amount determined by the jury to be fair and reasonable, but not to exceed $150 million; and (ii) noneconomic damages in the amount determined by the jury to be fair and reasonable, but not to exceed $500 million. The plaintiffs demand a trial by jury and have reserved their right to amend the complaint.

On March 15, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter et al. v. PacifiCorp, Case No. 21cv09520, Circuit Court, Marion County, Oregon. The complaint was filed by Oregon residents and businesses who allege that they were injured by the Beachie Creek Fire, which the plaintiffs allege began on or around September 7, 2020, but which government reports indicate began on or around August 16, 2020. The complaint alleges that PacifiCorp's assets contributed to the Beachie Creek Fire and that PacifiCorp acted with gross negligence, among other things. The complaint seeks the following damages: (i) damages for real and personal property and other economic losses in an amount determined by the jury to be fair and reasonable, but not to exceed $150 million; and (ii) noneconomic damages in the amount determined by the jury to be fair and reasonable, but not to exceed $500 million. The plaintiffs demand a trial by jury and have reserved their right to amend the complaint.

Other individual lawsuits alleging similar claims have been filed in Oregon and California related to the 2020 Wildfires. Investigations into the causes and origins of those wildfires are ongoing. For more information regarding certain legal proceedings affecting Berkshire Hathaway Energy, refer to Note 9 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q, and PacifiCorp, refer to Note 9 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q.

Item 1A.Risk Factors

There has been no material change to each Registrant's risk factors from those disclosed in Item 1A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2020.

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	Fiscal Agency Agreement, dated as of April 9, 2021, by and between Northern Natural Gas Company and The Bank of New York Mellon Trust Company, N.A., Fiscal Agent, relating to the $550,000,000 in principal amount of the 3.40% Senior Notes due 2051 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2021).
10.1	$3,500,000,000 Second Amended and Restated Credit Agreement, dated as of June 30, 2021, among Berkshire Hathaway Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, MUFG Union Bank, N.A, as Administrative Agent and the LC Issuing Banks.
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

4.2	Thirty-Second Supplemental Indenture, dated as of July 1, 2021, to the Mortgage and Deed of Trust dated as of January 9, 1989 between PacifiCorp and the Bank of New York Mellon Trust Company, N.A., as successor Trustee (incorporated by reference to Exhibit 4.1 to the PacifiCorp Current Report on Form 8-K dated July 9, 2021).
10.2	$1,200,000,000 Second Amended and Restated Credit Agreement dated as of June 30, 2021, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, JP Morgan Chase Bank, N.A. as Administrative Agent and the LC Issuing Banks.
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.

183

Exhibit No. Description

BERKSHIRE HATHAWAY ENERGY AND MIDAMERICAN ENERGY

4.3	Tenth Supplemental Indenture, dated as of July 22, 2021, by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Company Current Report on Form 8-K dated July 22, 2021).
4.4	Specimen of the 2.70% First Mortgage Bonds due 2052 (incorporated by reference to Exhibit 4.4 to the MidAmerican Energy Company Current Report on Form 8-K dated July 22, 2021).
10.3	$1,500,000,000 Second Amended and Restated Credit Agreement, dated as of June 30, 2021, among MidAmerican Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Mizuho Bank, Ltd., as Administrative Agent and the LC Issuing Banks.

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.

BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER

10.4 $400,000,000 Fourth Amended and Restated Credit Agreement, dated as of June 30, 2021, among Nevada Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks.

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.

BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC

10.5 $250,000,000 Fourth Amended and Restated Credit Agreement, dated as of June 30, 2021, among Sierra Pacific Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks.

184

Exhibit No. Description

EASTERN ENERGY GAS

31.13	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.14	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.13	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.14	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND EASTERN ENERGY GAS

4.5	Fifteenth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as trustee, to the Indenture dated as of October 1, 2013, by and between Eastern Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas (incorporated by reference to Exhibit 4.1 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated July 1, 2021).
4.6	Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee.
4.7	First Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.900% Senior Notes due 2049.
4.8	Second Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 4.600% Senior Notes due 2044.
4.9	Third Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 4.800% Senior Notes due 2043.
4.10	Fourth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.000% Senior Notes due 2029.
4.11	Fifth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.600% Senior Notes due 2024.

ALL REGISTRANTS

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The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, is formatted in iXBRL (Inline 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.

104

Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101.

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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 6, 2021	/s/ Calvin D. Haack
	Calvin D. Haack
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)
	PACIFICORP
Date: August 6, 2021	/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 6, 2021	/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 6, 2021	/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 6, 2021	/s/ Michael E. Cole
	Michael E. Cole
	Vice President, Chief Financial Officer and Treasurer
	(principal financial and accounting officer)
	EASTERN ENERGY GAS HOLDINGS, LLC
Date: August 6, 2021	/s/ Scott C. Miller
	Scott C. Miller
	Vice President, Chief Financial Officer and Treasurer
	(principal financial and accounting officer)

186