~~0001081316us-gaap:AccumulatedOtherComprehensiveIncomeMemberbhe:PacificorpMember2020-01-012020-09-30~~FALSE2022Q1000108131612/31000007559412/31000109829612/31000092857612/31000007118012/31000009014412/31000160329112/311111200 million0 million0 million1200001081316bhe:MidamericanEnergyCompanyAndSubsidiariesMemberbhe:RegulatedwholesaleMemberus-gaap:RegulatedOperationMember2022-01-012022-03-31

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 ~~September 30, 2021~~March 31, 2022

☐ 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

Des Moines, Iowa 50309-2580

515-242-4300

001-05152

PACIFICORP

93-0246090

(An Oregon Corporation)

825 N.E. Multnomah Street, Suite 1900

Portland, Oregon 97232

888-221-7070

333-90553

MIDAMERICAN FUNDING, LLC

47-0819200

(An Iowa Limited Liability Company)

666 Grand Avenue

Des Moines, Iowa 50309-2580

515-242-4300

333-15387

MIDAMERICAN ENERGY COMPANY

42-1425214

(An Iowa Corporation)

666 Grand Avenue

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 ~~November 4, 2021,~~April 28, 2022, 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 ~~November 4, 2021,~~April 28, 2022, 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 ~~November 4, 2021.~~April 28, 2022.

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 ~~November 4, 2021,~~April 28, 2022, 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 ~~November 4, 2021,~~April 28, 2022, 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 ~~November 4, 2021,~~April 28, 2022, 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 ~~November 4, 2021.~~April 28, 2022.

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	~~186~~159
Item 4.	Controls and Procedures	~~186~~159

PART II

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 and its subsidiaries
BHE Pipeline Group						BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
BHE GT&S						BHE GT&S, LLC and its subsidiaries
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 and its subsidiaries
AltaLink						AltaLink, L.P.
BHE U.S. Transmission						BHE U.S. Transmission, LLC and its subsidiaries
BHE Renewables						BHE Renewables, LLC and ~~CalEnergy Philippines~~its subsidiaries
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~~


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
~~CPST~~						~~Customer Price Stability Tariff~~
~~CPUC~~						~~California Public Utilities Commission~~
CSAPR						Cross-State Air Pollution Rule
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
GTA						General Tariff Application
GWh						Gigawatt Hour
~~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
~~RAC~~						~~Renewable Adjustment Clause~~
~~REC~~						~~Renewable Energy Credit~~
RFP						Request for ~~Proposal~~Proposals
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 associated 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, extreme temperature events, wind events, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, litigation, wars (including, for example, Russia's invasion of Ukraine in February 2022), terrorism, pandemics, ~~(including potentially in relation to COVID-19),~~ embargoes, and cyber security attacks, data security breaches, disruptions, or other malicious acts;

•the risks and uncertainties associated with wildfires that have occurred, are occurring or may occur in the respective Registrant's service territory, including the wildfires that began in September 2020 in Oregon and California, and any other wildfires for which the cause has yet to be determined; the damage caused by such wildfires; the extent of the respective Registrant's liability in connection with such wildfires (including the risk that the respective Registrant may be found liable for damages regardless of fault); investigations into such wildfires; the outcome of any legal proceedings initiated against the respective Registrant; the risk that the respective Registrant is not able to recover costs from insurance or through rates; and the effect on the respective Registrant's reputation of such wildfires, investigations and proceedings;

•the respective Registrant's ability to reduce wildfire threats and improve safety, including the ability to comply with the targets and metrics set forth in its wildfire mitigation plans; to retain or contract for the workforce necessary to execute its wildfire mitigation plans; the effectiveness of its system hardening; ability to achieve vegetation management targets; and the cost of these programs and the timing and outcome of any proceeding to recover such costs through rates;

•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 real and personal 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;

•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;

•the impact of supply chain disruptions and workforce availability on the respective Registrant's ongoing operations and its ability to timely complete construction projects;

•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.

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 (Los s ) 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						5846
Consolidated Balance Sheets						5947
Consolidated Statements of Operations						6149
Consolidated Statements of Changes in Shareholders' Equity						6250
Consolidated Statements of Cash Flows						6351
Notes to Consolidated Financial Statements						6452
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm						8468
Balance Sheets						8569
Statements of Operations						8771
Statements of Changes in Shareholder's Equity						8872
Statements of Cash Flows						8973
Notes to Financial Statements						9074
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm						9981
Consolidated Balance Sheets						~~100~~82
Consolidated Statements of Operations						~~102~~84
Consolidated Statements of Changes in Member's Equity						~~103~~85
Consolidated Statements of Cash Flows						~~104~~86
Notes to Consolidated Financial Statements						~~105~~87
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm						~~121~~101
Consolidated Balance Sheets						~~122~~102
Consolidated Statements of Operations						~~123~~103
Consolidated Statements of Changes in Shareholder's Equity						~~124~~104
Consolidated Statements of Cash Flows						~~125~~105
Notes to Consolidated Financial Statements						~~126~~106
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm						120
Consolidated Balance Sheets						121
Consolidated Statements of Operations						122
Consolidated Statements of Changes in Shareholder's Equity						123
Consolidated Statements of Cash Flows						124
Notes to Consolidated Financial Statements						125
Eastern Energy Gas Holdings, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm						141
Consolidated Balance Sheets						142
Consolidated Statements of Operations						~~143~~
~~Consolidated Statements of Changes in Shareholder's Equity~~						144
~~Consolidated Statements of Cash Flows~~						~~145~~
~~Notes to Consolidated Financial Statements~~						~~146~~
~~Eastern Energy Gas Holdings, LLC and its subsidiaries~~
~~Report of Independent Registered Public Accounting Firm~~						~~161~~
~~Consolidated Balance Sheets~~						~~162~~
~~Consolidated Statements of Operations~~						~~164~~
Consolidated Statements of Comprehensive Income						~~165~~145
Consolidated Statements of Changes in Equity						~~166~~146
Consolidated Statements of Cash Flows						~~167~~147
Notes to Consolidated Financial Statements						~~168~~148

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


Berkshire Hathaway Energy Company and its subsidiaries						3127
PacifiCorp and its subsidiaries						7461
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company						~~109~~91
Nevada Power Company and its subsidiaries						~~132~~113
Sierra Pacific Power Company and its subsidiaries						~~153~~133
Eastern Energy Gas Holdings, LLC and its subsidiaries						~~181~~156

Berkshire Hathaway Energy Company and its subsidiaries

Consolidated Financial Section

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Berkshire Hathaway Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of ~~September 30, 2021,~~March 31, 2022, the related consolidated statements of operations, comprehensive (loss) income, ~~and~~ changes in equity, ~~for the three-month~~ and ~~nine-month periods ended September 30, 2021 and 2020, and of~~ cash flows for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 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,~~2021, 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,~~25, 2022, 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,~~2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of the Company's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

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

/s/ Deloitte & Touche LLP

Des Moines, Iowa

~~November 5, 2021~~April 29, 2022

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


		As of					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	2,709	$	1,290	Cash and cash equivalents	$	1,432	$	1,096
Restricted cash and cash equivalents	Restricted cash and cash equivalents	216		140		Restricted cash and cash equivalents	129		127
Trade receivables, net	Trade receivables, net	2,545		2,107		Trade receivables, net	2,342		2,468

Income tax receivable						Income tax receivable	656		344
Inventories	Inventories	1,129		1,168		Inventories	1,091		1,122
Mortgage loans held for sale	Mortgage loans held for sale	1,687		2,001		Mortgage loans held for sale	975		1,263

Derivative contracts						Derivative contracts	437		188
Regulatory assets						Regulatory assets	627		544
Other current assets	Other current assets	2,142		2,741		Other current assets	815		1,096
Total current assets	Total current assets	10,428		9,447		Total current assets	8,504		8,248

Property, plant and equipment, net	Property, plant and equipment, net	88,062		86,128		Property, plant and equipment, net	90,283		89,816
Goodwill	Goodwill	11,572		11,506		Goodwill	11,649		11,650
Regulatory assets	Regulatory assets	3,372		3,157		Regulatory assets	3,458		3,419
Investments and restricted cash and cash equivalents and investments		15,218		14,320
Investments and restricted cash, cash equivalents and investments						Investments and restricted cash, cash equivalents and investments	14,394		15,788
Other assets	Other assets	2,902		2,758		Other assets	3,181		3,144

Total assets	Total assets	$	131,554	$	127,316	Total assets	$	131,469	$	132,065

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


		As of					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY					LIABILITIES AND EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	$	1,798	$	1,867	Accounts payable	$	1,820	$	2,136
Accrued interest	Accrued interest	622		555		Accrued interest	644		537
Accrued property, income and other taxes	Accrued property, income and other taxes	670		582		Accrued property, income and other taxes	606		606
Accrued employee expenses	Accrued employee expenses	556		383		Accrued employee expenses	398		372
Short-term debt	Short-term debt	1,968		2,286		Short-term debt	1,849		2,009
Current portion of long-term debt	Current portion of long-term debt	1,179		1,839		Current portion of long-term debt	1,494		1,265
Other current liabilities	Other current liabilities	2,054		1,626		Other current liabilities	1,647		1,837
Total current liabilities	Total current liabilities	8,847		9,138		Total current liabilities	8,458		8,762

BHE senior debt	BHE senior debt	13,001		12,997		BHE senior debt	12,605		13,003
BHE junior subordinated debentures	BHE junior subordinated debentures	100		100		BHE junior subordinated debentures	100		100
Subsidiary debt	Subsidiary debt	35,818		34,930		Subsidiary debt	35,706		35,394
Regulatory liabilities	Regulatory liabilities	6,958		7,221		Regulatory liabilities	7,063		6,960
Deferred income taxes	Deferred income taxes	12,910		11,775		Deferred income taxes	12,786		12,938
Other long-term liabilities	Other long-term liabilities	4,304		4,178		Other long-term liabilities	4,327		4,319
Total liabilities	Total liabilities	81,938		80,339		Total liabilities	81,045		81,476

Commitments and contingencies (Note 9)		0		0
Commitments and contingencies (Note 8)						Commitments and contingencies (Note 8)	0		0

Equity:	Equity:					Equity:
BHE shareholders' equity:	BHE shareholders' equity:					BHE shareholders' equity:
Preferred stock - 100 shares authorized, $0.01 par value, 2 and 4 shares issued and outstanding		2,300		3,750
Preferred stock - 100 shares authorized, $0.01 par value, 2 shares issued and outstanding						Preferred stock - 100 shares authorized, $0.01 par value, 2 shares issued and outstanding	1,650		1,650
Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding	Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding	—		—		Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding	—		—
Additional paid-in capital	Additional paid-in capital	6,374		6,377		Additional paid-in capital	6,374		6,374
Long-term income tax receivable	Long-term income tax receivable	(658)		(658)		Long-term income tax receivable	(744)		(744)
Retained earnings	Retained earnings	39,199		35,093		Retained earnings	40,608		40,754
Accumulated other comprehensive loss, net	Accumulated other comprehensive loss, net	(1,523)		(1,552)		Accumulated other comprehensive loss, net	(1,358)		(1,340)
Total BHE shareholders' equity	Total BHE shareholders' equity	45,692		43,010		Total BHE shareholders' equity	46,530		46,694
Noncontrolling interests	Noncontrolling interests	3,924		3,967		Noncontrolling interests	3,894		3,895
Total equity	Total equity	49,616		46,977		Total equity	50,424		50,589

Total liabilities and equity	Total liabilities and equity	$	131,554	$	127,316	Total liabilities and equity	$	131,469	$	132,065

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021
Operating revenue:	Operating revenue:									Operating revenue:
Energy	Energy	$	5,225	$	4,451	$	14,375	$	11,504	Energy		$	4,823	$	4,849
Real estate	Real estate	1,743		1,742		4,738		3,828		Real estate		1,207		1,232
Total operating revenue	Total operating revenue	6,968		6,193		19,113		15,332		Total operating revenue		6,030		6,081

Operating expenses:	Operating expenses:									Operating expenses:
Energy:	Energy:									Energy:
Cost of sales	Cost of sales	1,385		1,169		4,064		3,095		Cost of sales		1,460		1,569
Operations and maintenance	Operations and maintenance	1,001		1,033		2,972		2,564		Operations and maintenance		943		934
Depreciation and amortization	Depreciation and amortization	946		789		2,797		2,323		Depreciation and amortization		1,007		915
Property and other taxes	Property and other taxes	194		152		593		456		Property and other taxes		205		210
Real estate	Real estate	1,608		1,503		4,312		3,492		Real estate		1,179		1,120
Total operating expenses	Total operating expenses	5,134		4,646		14,738		11,930		Total operating expenses		4,794		4,748

Operating income	Operating income	1,834		1,547		4,375		3,402		Operating income		1,236		1,333

Other income (expense):	Other income (expense):									Other income (expense):
Interest expense	Interest expense	(531)		(504)		(1,593)		(1,490)		Interest expense		(532)		(530)
Capitalized interest	Capitalized interest	18		24		46		60		Capitalized interest		17		14
Allowance for equity funds	Allowance for equity funds	34		50		90		122		Allowance for equity funds		38		26
Interest and dividend income	Interest and dividend income	18		17		65		57		Interest and dividend income		23		21
Gains on marketable securities, net		294		1,797		1,142		2,407
Losses on marketable securities, net										Losses on marketable securities, net		(1,257)		(1,118)
Other, net	Other, net	8		36		64		61		Other, net		5		8
Total other income (expense)	Total other income (expense)	(159)		1,420		(186)		1,217		Total other income (expense)		(1,706)		(1,579)

Income before income tax (benefit) expense and equity loss		1,675		2,967		4,189		4,619
Income tax (benefit) expense		(355)		80		(563)		(111)
Loss before income tax benefit and equity loss										Loss before income tax benefit and equity loss		(470)		(246)
Income tax benefit										Income tax benefit		(507)		(535)
Equity loss	Equity loss	(5)		(41)		(234)		(91)		Equity loss		(57)		(179)
Net income		2,025		2,846		4,518		4,639
Net (loss) income										Net (loss) income		(20)		110
Net income attributable to noncontrolling interests	Net income attributable to noncontrolling interests	103		4		311		11		Net income attributable to noncontrolling interests		109		106
Net income attributable to BHE shareholders		1,922		2,842		4,207		4,628
Net (loss) income attributable to BHE shareholders										Net (loss) income attributable to BHE shareholders		(129)		4
Preferred dividends	Preferred dividends	26		—		101		—		Preferred dividends		16		38
Earnings on common shares		$	1,896	$	2,842	$	4,106	$	4,628
Loss on common shares										Loss on common shares		$	(145)	$	(34)

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME (Unaudited)

(Amounts in millions)

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2021 2020 2021 2020

Net income $ 2,025 $ 2,846 $ 4,518 $ 4,639

Other comprehensive (loss) income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $7, $(3), $12 and $10 22 (6) 44 38
Foreign currency translation adjustment (218) 244 (59) (195)
Unrealized gains (losses) on cash flow hedges, net of tax of $12, $2, $16 and $(5) 33 4 48 (20)
Total other comprehensive (loss) income, net of tax (163) 242 33 (177)

Comprehensive income 1,862 3,088 4,551 4,462
Comprehensive income attributable to noncontrolling interests 103 4 315 11
Comprehensive income attributable to BHE shareholders $ 1,759 $ 3,084 $ 4,236 $ 4,451


	Three-Month Periods
	Ended March 31,
		2022		2021

Net (loss) income		$	(20)	$	110

Other comprehensive (loss) income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $3 and $4		15		7
Foreign currency translation adjustment		(110)		91
Unrealized gains on cash flow hedges, net of tax of $28 and $5		77		14
Total other comprehensive (loss) income, net of tax		(18)		112

Comprehensive (loss) income		(38)		222
Comprehensive income attributable to noncontrolling interests		109		106
Comprehensive (loss) income attributable to BHE shareholders		$	(147)	$	116

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)


		BHE Shareholders' Equity																	BHE Shareholders' Equity
								Long-term				Accumulated													Long-term				Accumulated
						Additional		Income				Other											Additional		Income				Other
		Preferred		Common		Paid-in		Tax		Retained		Comprehensive		Noncontrolling		Total			Preferred		Common		Paid-in		Tax		Retained		Comprehensive		Noncontrolling		Total
		Stock		Stock		Capital		Receivable		Earnings		Loss, Net		Interests		Equity			Stock		Stock		Capital		Receivable		Earnings		Loss, Net		Interests		Equity
Balance, June 30, 2020		$	—	$	—	$	6,377	$	(530)	$	29,962	$	(2,125)	$	101	$	33,785

Balance, December 31, 2020																		Balance, December 31, 2020	$	3,750	$	—	$	6,377	$	(658)	$	35,093	$	(1,552)	$	3,967	$	46,977
Net income	Net income	—		—		—		—		2,842		—		3		2,845		Net income	—		—		—		—		4		—		106		110
Other comprehensive income	Other comprehensive income	—		—		—		—		—		242		—		242		Other comprehensive income	—		—		—		—		—		112		—		112
Preferred stock dividend																		Preferred stock dividend	—		—		—		—		(38)		—		—		(38)

Distributions	Distributions	—		—		—		—		—		—		(4)		(4)		Distributions	—		—		—		—		—		—		(113)		(113)

Other equity transactions	Other equity transactions	—		—		—		—		—		—		1		1		Other equity transactions	—		—		—		—		1		—		2		3
Balance, September 30, 2020		$	—	$	—	$	6,377	$	(530)	$	32,804	$	(1,883)	$	101	$	36,869
Balance, March 31, 2021																		Balance, March 31, 2021	$	3,750	$	—	$	6,377	$	(658)	$	35,060	$	(1,440)	$	3,962	$	47,051

Balance, December 31, 2019		$	—	$	—	$	6,389	$	(530)	$	28,296	$	(1,706)	$	129	$	32,578
Net income		—		—		—		—		4,628		—		10		4,638

Balance, December 31, 2021																		Balance, December 31, 2021	$	1,650	$	—	$	6,374	$	(744)	$	40,754	$	(1,340)	$	3,895	$	50,589
Net (loss) income																		Net (loss) income	—		—		—		—		(129)		—		109		(20)
Other comprehensive loss	Other comprehensive loss	—		—		—		—		—		(177)		—		(177)		Other comprehensive loss	—		—		—		—		—		(18)		—		(18)
Common stock purchases		—		—		(6)		—		(120)		—		—		(126)
Distributions		—		—		—		—		—		—		(11)		(11)
Purchase of noncontrolling interest		—		—		(5)		—		—		—		(28)		(33)
Other equity transactions		—		—		(1)		—		—		—		1		—
Balance, September 30, 2020		$	—	$	—	$	6,377	$	(530)	$	32,804	$	(1,883)	$	101	$	36,869

Balance, June 30, 2021		$	3,750	$	—	$	6,377	$	(658)	$	37,303	$	(1,360)	$	3,953	$	49,365
Net income		—		—		—		—		1,922		—		103		2,025
Other comprehensive loss		—		—		—		—		—		(163)		—		(163)
Preferred stock redemptions		(1,450)		—		—		—		—		—		—		(1,450)
Preferred stock dividend	Preferred stock dividend	—		—		—		—		(26)		—		—		(26)		Preferred stock dividend	—		—		—		—		(16)		—		—		(16)

Distributions	Distributions	—		—		—		—		—		—		(130)		(130)		Distributions	—		—		—		—		—		—		(116)		(116)

Purchase of noncontrolling interest		—		—		(3)		—		—		—		—		(3)

Other equity transactions	Other equity transactions	—		—		—		—		—		—		(2)		(2)		Other equity transactions	—		—		—		—		(1)		—		6		5
Balance, September 30, 2021		$	2,300	$	—	$	6,374	$	(658)	$	39,199	$	(1,523)	$	3,924	$	49,616

Balance, December 31, 2020		$	3,750	$	—	$	6,377	$	(658)	$	35,093	$	(1,552)	$	3,967	$	46,977
Net income		—		—		—		—		4,207		—		311		4,518
Other comprehensive income		—		—		—		—		—		29		4		33
Preferred stock redemptions		(1,450)		—		—		—		—		—		—		(1,450)
Preferred stock dividend		—		—		—		—		(101)		—		—		(101)

Distributions		—		—		—		—		—		—		(364)		(364)
Contributions		—		—		—		—		—		—		9		9
Purchase of noncontrolling interest		—		—		(3)		—		—		—		—		(3)
Other equity transactions		—		—		—		—		—		—		(3)		(3)
Balance, September 30, 2021		$	2,300	$	—	$	6,374	$	(658)	$	39,199	$	(1,523)	$	3,924	$	49,616
Balance, March 31, 2022																		Balance, March 31, 2022	$	1,650	$	—	$	6,374	$	(744)	$	40,608	$	(1,358)	$	3,894	$	50,424

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


		Nine-Month Periods					Three-Month Periods
		Ended September 30,					Ended March 31,
		2021		2020			2022		2021
Cash flows from operating activities:	Cash flows from operating activities:					Cash flows from operating activities:
Net income		$	4,518	$	4,639
Adjustments to reconcile net income to net cash flows from operating activities:
Gains on marketable securities, net		(1,142)		(2,407)
Net (loss) income						Net (loss) income	$	(20)	$	110
Adjustments to reconcile net (loss) income to net cash flows from operating activities:						Adjustments to reconcile net (loss) income to net cash flows from operating activities:
Losses on marketable securities, net						Losses on marketable securities, net	1,257		1,118
Depreciation and amortization	Depreciation and amortization	2,834		2,357		Depreciation and amortization	1,022		927
Allowance for equity funds	Allowance for equity funds	(90)		(122)		Allowance for equity funds	(38)		(26)
Equity loss, net of distributions	Equity loss, net of distributions	346		146		Equity loss, net of distributions	88		221
Changes in regulatory assets and liabilities	Changes in regulatory assets and liabilities	(518)		(87)		Changes in regulatory assets and liabilities	(42)		(9)
Deferred income taxes and investment tax credits, net	Deferred income taxes and investment tax credits, net	661		791		Deferred income taxes and investment tax credits, net	(203)		(135)
Other, net	Other, net	(88)		(6)		Other, net	6		9
Changes in other operating assets and liabilities, net of effects from acquisitions:	Changes in other operating assets and liabilities, net of effects from acquisitions:					Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	Trade receivables and other assets	(13)		(1,668)		Trade receivables and other assets	333		(249)
Derivative collateral, net	Derivative collateral, net	115		53		Derivative collateral, net	85		14
Pension and other postretirement benefit plans	Pension and other postretirement benefit plans	(37)		(69)		Pension and other postretirement benefit plans	(11)		(21)
Accrued property, income and other taxes, net	Accrued property, income and other taxes, net	(29)		97		Accrued property, income and other taxes, net	(347)		(453)
Accounts payable and other liabilities	Accounts payable and other liabilities	427		796		Accounts payable and other liabilities	91		19
Net cash flows from operating activities	Net cash flows from operating activities	6,984		4,520		Net cash flows from operating activities	2,221		1,525

Cash flows from investing activities:	Cash flows from investing activities:					Cash flows from investing activities:
Capital expenditures	Capital expenditures	(4,594)		(4,607)		Capital expenditures	(1,553)		(1,295)
Acquisitions, net of cash acquired		(64)		—

Purchases of marketable securities	Purchases of marketable securities	(243)		(322)		Purchases of marketable securities	(170)		(128)
Proceeds from sales of marketable securities	Proceeds from sales of marketable securities	222		308		Proceeds from sales of marketable securities	149		104
Proceeds from other investments		1,296		13

Equity method investments	Equity method investments	(54)		(2,062)		Equity method investments	(17)		(26)
Other, net	Other, net	(91)		37		Other, net	19		(29)
Net cash flows from investing activities	Net cash flows from investing activities	(3,528)		(6,633)		Net cash flows from investing activities	(1,572)		(1,374)

Cash flows from financing activities:	Cash flows from financing activities:					Cash flows from financing activities:

Preferred stock redemptions		(1,450)		—
Preferred dividends		(86)		—
Common stock purchases		—		(126)
Proceeds from BHE senior debt		—		3,231

Repayments of BHE senior debt	Repayments of BHE senior debt	(450)		(350)		Repayments of BHE senior debt	—		(450)
Proceeds from subsidiary debt	Proceeds from subsidiary debt	2,014		2,648		Proceeds from subsidiary debt	405		—
Repayments of subsidiary debt	Repayments of subsidiary debt	(1,271)		(1,558)		Repayments of subsidiary debt	(193)		(26)
Net repayments of short-term debt		(316)		(815)
Purchase of noncontrolling interest		—		(33)
Net (repayments of) proceeds from short-term debt						Net (repayments of) proceeds from short-term debt	(165)		409

Distributions to noncontrolling interests	Distributions to noncontrolling interests	(366)		(13)		Distributions to noncontrolling interests	(117)		(115)
Contributions from noncontrolling interests		9		5

Other, net	Other, net	(44)		(52)		Other, net	(240)		(9)
Net cash flows from financing activities	Net cash flows from financing activities	(1,960)		2,937		Net cash flows from financing activities	(310)		(191)

Effect of exchange rate changes	Effect of exchange rate changes	1		4		Effect of exchange rate changes	(1)		1

Net change in cash and cash equivalents and restricted cash and cash equivalents	Net change in cash and cash equivalents and restricted cash and cash equivalents	1,497		828		Net change in cash and cash equivalents and restricted cash and cash equivalents	338		(39)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	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 beginning of period	1,244		1,445
Cash and cash equivalents and restricted cash and cash equivalents at end of period	Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	2,942	$	2,096	Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	1,582	$	1,406

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

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 and operated 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 8 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 and its subsidiaries ("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 and its subsidiaries ("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 and its subsidiaries ("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, ~~LLC)~~LLC and its subsidiaries), ~~BHE Renewables (which primarily consists of~~ BHE Renewables, LLC and ~~CalEnergy Philippines)~~its subsidiaries ("BHE Renewables") and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through these locally managed and operated businesses, owns 4 utility companies in the ~~United States~~U.S. serving customers in 11 states, 2two electricity distribution companies in Great Britain, 5 interstate natural gas pipeline companies and interests in a liquefied natural gas ("LNG") export, import and storage facility in the ~~United States,~~U.S., an electric transmission business in Canada, interests in electric transmission businesses in the ~~United States,~~U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the ~~United States~~U.S. and 1 of the largest residential real estate brokerage franchise networks in the ~~United States.~~U.S.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of ~~September 30, 2021~~March 31, 2022 and for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020.~~2021. The results of operations for the ~~three- and nine-month periods~~three-month period ended ~~September 30, 2021~~March 31, 2022 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~~2021 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies during the ~~nine-month~~three-month period ended ~~September 30, 2021.~~

March 31, 2022.

(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 was included in other current assets on the Consolidated Balance Sheet as of 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 nine-month periods ended September 30, 2021, is operating revenue of $516 million and $1,563 million, respectively and net income attributable to BHE shareholders of $74 million and $247 million, respectively, as a result of including BHE GT&S from November 1, 2020.

~~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 following table summarizes the 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 nine-month period ended September 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 were subject to further revision for up to 12 months following the acquisition date until the related valuations were completed.

~~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):


	~~Nine-Month Period~~
	~~Ended September 30, 2020~~

~~Operating revenue~~	$	~~16,791~~

~~Net income attributable to BHE shareholders~~	$	~~4,468~~

~~(3)~~ Property, Plant and Equipment, Net

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


			As of						As of
		Depreciable	September 30,		December 31,			Depreciable	March 31,		December 31,
		Life	2021		2020			Life	2022		2021
Regulated assets:	Regulated assets:						Regulated assets:
Utility generation, transmission and distribution systems	Utility generation, transmission and distribution systems	5-80 years	$	89,026	$	86,730	Utility generation, transmission and distribution systems	5-80 years	$	90,560	$	90,223
Interstate natural gas pipeline assets	Interstate natural gas pipeline assets	3-80 years	17,044		16,667		Interstate natural gas pipeline assets	3-80 years	17,526		17,423
			106,070		103,397				108,086		107,646
Accumulated depreciation and amortization	Accumulated depreciation and amortization		(32,444)		(30,662)		Accumulated depreciation and amortization		(33,248)		(32,680)
Regulated assets, net	Regulated assets, net		73,626		72,735		Regulated assets, net		74,838		74,966

Nonregulated assets:	Nonregulated assets:						Nonregulated assets:
Independent power plants	Independent power plants	5-30 years	7,058		7,012		Independent power plants	2-50 years	7,932		7,665
Cove Point LNG facility							Cove Point LNG facility	40 years	3,366		3,364
Other assets	Other assets	3-40 years	5,951		5,659		Other assets	2-30 years	2,688		2,666
			13,009		12,671				13,986		13,695
Accumulated depreciation and amortization	Accumulated depreciation and amortization		(2,916)		(2,586)		Accumulated depreciation and amortization		(3,146)		(3,041)
Nonregulated assets, net	Nonregulated assets, net		10,093		10,085		Nonregulated assets, net		10,840		10,654

Net operating assets	Net operating assets		83,719		82,820		Net operating assets		85,678		85,620
Construction work-in-progress	Construction work-in-progress		4,343		3,308		Construction work-in-progress		4,605		4,196
Property, plant and equipment, net	Property, plant and equipment, net		$	88,062	$	86,128	Property, plant and equipment, net		$	90,283	$	89,816

Construction work-in-progress includes ~~$3.9~~$4.3 billion as of ~~September 30, 2021~~March 31, 2022 and ~~$3.2~~$3.8 billion as of December 31, ~~2020,~~2021, related to the construction of regulated assets.

1412

(43) 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					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
Investments:	Investments:					Investments:
BYD Company Limited common stock	BYD Company Limited common stock	$	7,023	$	5,897	BYD Company Limited common stock	$	6,446	$	7,693
Rabbi trusts	Rabbi trusts	473		440		Rabbi trusts	475		492
Other	Other	295		263		Other	315		305
Total investments	Total investments	7,791		6,600		Total investments	7,236		8,490

Equity method investments:	Equity method investments:					Equity method investments:
BHE Renewables tax equity investments	BHE Renewables tax equity investments	5,253		5,626		BHE Renewables tax equity investments	4,812		4,931
Iroquois Gas Transmission System, L.P.	Iroquois Gas Transmission System, L.P.	583		580		Iroquois Gas Transmission System, L.P.	744		735
Electric Transmission Texas, LLC	Electric Transmission Texas, LLC	578		594		Electric Transmission Texas, LLC	598		595
JAX LNG, LLC	JAX LNG, LLC	87		75		JAX LNG, LLC	93		92
Bridger Coal Company	Bridger Coal Company	60		74		Bridger Coal Company	44		45
Other	Other	163		118		Other	152		156
Total equity method investments	Total equity method investments	6,724		7,067		Total equity method investments	6,443		6,554

Restricted cash and cash equivalents and investments:
Restricted cash, cash equivalents and investments:						Restricted cash, cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds	Quad Cities Station nuclear decommissioning trust funds	727		676		Quad Cities Station nuclear decommissioning trust funds	733		768
Other restricted cash and cash equivalents	Other restricted cash and cash equivalents	233		155		Other restricted cash and cash equivalents	150		148
Total restricted cash and cash equivalents and investments		960		831
Total restricted cash, cash equivalents and investments						Total restricted cash, cash equivalents and investments	883		916

Total investments and restricted cash and cash equivalents and investments		$	15,475	$	14,498
Total investments and restricted cash, cash equivalents and investments						Total investments and restricted cash, cash equivalents and investments	$	14,562	$	15,960

Reflected as:	Reflected as:					Reflected as:
Current assets	Current assets	$	257	$	178	Current assets	$	168	$	172
Noncurrent assets	Noncurrent assets	15,218		14,320		Noncurrent assets	14,394		15,788
Total investments and restricted cash and cash equivalents and investments		$	15,475	$	14,498
Total investments and restricted cash, cash equivalents and investments						Total investments and restricted cash, cash equivalents and investments	$	14,562	$	15,960

Investments

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

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2021 2020 2021 2020
Unrealized gains recognized on marketable securities still held at the reporting date $ 294 $ 1,794 $ 1,141 $ 2,403
Net gains recognized on marketable securities sold during the period — 3 1 4
Gains on marketable securities, net $ 294 $ 1,797 $ 1,142 $ 2,407


	Three-Month Periods
	Ended March 31,
		2022		2021
Unrealized losses recognized on marketable securities still held at the reporting date		$	(1,257)	$	(1,119)
Net gains recognized on marketable securities sold during the period		—		1
Losses on marketable securities, net		$	(1,257)	$	(1,118)

1513

~~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 $353 million, or after-tax income of $123 million inclusive of production tax credits ("PTCs") of $401 million and other income tax benefits of $79 million, during the nine-month period ended September 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 September 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~~U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents ~~as of September 30, 2021 and December 31, 2020,~~ consist substantially of funds restricted for debt service obligations for certain of the Company's nonregulated renewable energy projects. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as ~~of September 30, 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					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
Cash and cash equivalents	Cash and cash equivalents	$	2,709	$	1,290	Cash and cash equivalents	$	1,432	$	1,096
Restricted cash and cash equivalents	Restricted cash and cash equivalents	216		140		Restricted cash and cash equivalents	129		127
Investments and restricted cash and cash equivalents and investments		17		15
Investments and restricted cash, cash equivalents and investments						Investments and restricted cash, cash equivalents and investments	21		21
Total cash and cash equivalents and restricted cash and cash equivalents	Total cash and cash equivalents and restricted cash and cash equivalents	$	2,942	$	1,445	Total cash and cash equivalents and restricted cash and cash equivalents	$	1,582	$	1,244

(54) Recent Financing Transactions

Long-Term Debt

In November 2021, PacifiCorp exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed $450 million of its 2.95% Series First Mortgage Bonds that was originally due February 2022.

In September 2021, HomeServices entered into a $150 million unsecured amortizing term loan due September 2026. The net proceeds were used to fund the repayment of its existing unsecured amortizing term loan due September 2022. The amortizing term loan has an underlying variable interest rate based on the London Interbank Offered Rate plus a spread that varies based on HomeServices' total net leverage ratio as of the last day of each quarter.

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~~April 2022, BHE issued $1 billion of its ~~2.90% First Mortgage Bonds~~4.6% Senior Notes due ~~June 2052. PacifiCorp used~~2053 and intends to use the net proceeds ~~to finance~~for general corporate purposes, which may include repaying 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~~BHE's outstanding commercial paper obligations and redeeming a portion of its ~~existing wind-powered generating facilities and the construction and acquisition~~4.00% Perpetual Preferred Stock issued to certain subsidiaries 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.Berkshire Hathaway.

In April ~~2021, Northern Natural Gas issued $550~~2022, Sierra Pacific purchased the following series of bonds that were held by the public: $30 million of ~~3.40% Senior~~its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due ~~October 2051.~~2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036; $75 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $20 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036; and $30 million of its variable-rate tax-exempt Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029. Sierra Pacific purchased these bonds as required by the bond indentures. Sierra Pacific is holding these bonds and can re-offer them at a future date.

In April 2022, Northern ~~Natural Gas used~~Powergrid (Northeast) plc issued £350 million of its 3.25% bonds due 2052 and intends to use 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.

~~Credit Facilities~~

In ~~September 2021, HomeServices amended and restated~~January 2022, Nevada Power entered into a $300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $200 million under the facility at an initial interest rate of 0.55%. Nevada Power may draw all or none of the remaining unused commitment through June 2022. Nevada Power used the proceeds to repay amounts outstanding under its existing ~~$600 million unsecured~~secured credit facility ~~expiring in September 2022. The amendment increased the lender commitment to $700 million~~ and ~~extended the expiration date to September 2026.~~

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.

general corporate purposes.

1714

(65) Income Taxes

The effective income tax rate for the three-month period ended March 31, 2022, is 108% and results from a $507 million income tax benefit associated with a $470 million pre-tax loss, primarily relating to a pre-tax unrealized loss of $1,247 million on the Company's investment in BYD Company Limited. The $507 million income tax benefit is primarily comprised of a $99 million benefit (21%) from the application of the statutory income tax rate to the pre-tax loss and a $339 million benefit (72%) from income tax credits.

The effective income tax rate for the three-month period ended March 31, 2021, is 217% and results from a $535 million income tax benefit associated with a $246 million pre-tax loss, primarily relating to a pre-tax unrealized loss of $1,124 million on the Company's investment in BYD Company Limited. The $535 million income tax benefit is primarily comprised of a $52 million benefit (21%) from the application of the statutory income tax rate to the pre-tax loss, a $334 million benefit (136%) from income tax credits and a $51 million benefit (21%) from state income tax benefits, net of federal income tax impacts.

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


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021

Federal statutory income tax rate	Federal statutory income tax rate	21	%	21	%	21	%	21	%	Federal statutory income tax rate		21	%	21	%
Income tax credits	Income tax credits	(31)		(20)		(29)		(23)		Income tax credits		72		136
State income tax, net of federal income tax impacts	State income tax, net of federal income tax impacts	(4)		3		—		2		State income tax, net of federal income tax impacts		(3)		21
Income tax effect of foreign income	Income tax effect of foreign income	(1)		1		2		—		Income tax effect of foreign income		3		6
Effects of ratemaking	Effects of ratemaking	(6)		(2)		(5)		(2)		Effects of ratemaking		8		10
Equity income	Equity income	—		—		(1)		—		Equity income		3		15
Noncontrolling interest	Noncontrolling interest	(1)		—		(2)		—		Noncontrolling interest		5		9
Other, net	Other, net	1		—		1		—		Other, net		(1)		(1)
Effective income tax rate	Effective income tax rate	(21)	%	3	%	(13)	%	(2)	%	Effective income tax rate		108	%	217	%

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 ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021 totaled $338 million and ~~2020 totaled $1.2 billion and $1.0 billion,~~$315 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, and a deferred income tax charge of $35 million recognized in July 2020 related to the United Kingdom's corporate income tax rate that was scheduled to decrease from 19% to 17% effective April 1, 2020; however, the rate was maintained at 19% through amended legislation enacted in July 2020.

The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated ~~United States~~U.S. federal and Iowa state income tax returns and the majority of the Company's ~~United States~~U.S. federal income tax is remitted to or received from Berkshire Hathaway. ~~For the nine-month periods ended September 30, 2021 and 2020, the~~The Company ~~received net cash~~made no payments for federal income taxes ~~from~~to Berkshire Hathaway ~~totaling $1.3 billion~~for the three-month periods ended March 31, 2022 and ~~$1.0 billion, respectively.~~2021.

1815

(76) Employee Benefit Plans

Domestic Operations

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


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021
Pension:	Pension:									Pension:
Service cost	Service cost	$	7	$	4	$	22	$	11	Service cost		$	7	$	7
Interest cost	Interest cost	21		23		59		69		Interest cost		19		20
Expected return on plan assets	Expected return on plan assets	(32)		(35)		(101)		(105)		Expected return on plan assets		(27)		(33)
Settlement	Settlement	4		—		4		—		Settlement		2		—
Net amortization	Net amortization	6		8		19		25		Net amortization		4		6
Net periodic benefit cost	Net periodic benefit cost	$	6	$	—	$	3	$	—	Net periodic benefit cost		$	5	$	—

Other postretirement:	Other postretirement:									Other postretirement:
Service cost	Service cost	$	2	$	1	$	8	$	5	Service cost		$	2	$	2
Interest cost	Interest cost	4		6		14		16		Interest cost		5		5
Expected return on plan assets	Expected return on plan assets	(5)		(9)		(16)		(25)		Expected return on plan assets		(7)		(5)
Net amortization	Net amortization	—		(1)		(2)		(5)		Net amortization		—		(1)
Net periodic benefit cost (credit)		$	1	$	(3)	$	4	$	(9)
Net periodic benefit cost										Net periodic benefit cost		$	—	$	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 domestic pension and other postretirement benefit plans are expected to be $13 million and ~~$13~~$4 million, respectively, during ~~2021.~~2022. As of ~~September 30, 2021, $9~~March 31, 2022, $4 million and ~~$10~~$3 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

Foreign Operations

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


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021

Service cost	Service cost	$	4	$	4	$	12	$	12	Service cost		$	4	$	4
Interest cost	Interest cost	8		10		23		30		Interest cost		10		8
Expected return on plan assets	Expected return on plan assets	(28)		(26)		(84)		(76)		Expected return on plan assets		(25)		(28)

Net amortization	Net amortization	14		11		42		32		Net amortization		6		14
Net periodic benefit credit	Net periodic benefit credit	$	(2)	$	(1)	$	(7)	$	(2)	Net periodic benefit credit		$	(5)	$	(2)

Amounts other than the service cost for the United Kingdom pension plan are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the United Kingdom pension plan are expected to be ~~£20~~£12 million during ~~2021.~~2022. As of ~~September 30, 2021, £17~~March 31, 2022, £3 million, or ~~$24~~$4 million, of contributions had been made to the United Kingdom pension plan.

1916

(87) Fair Value Measurements

The carrying value of the Company's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. The Company has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

•Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

•Level 3 — Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.

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


		Input Levels for Fair Value Measurements											Input Levels for Fair Value Measurements
		Level 1		Level 2		Level 3		Other(1)		Total			Level 1		Level 2		Level 3		Other(1)		Total
As of September 30, 2021
As of March 31, 2022:												As of March 31, 2022:
Assets:	Assets:											Assets:
Commodity derivatives	Commodity derivatives	$	15	$	436	$	88	$	(49)	$	490	Commodity derivatives	$	13	$	534	$	59	$	(64)	$	542
Foreign currency exchange rate derivatives		—		8		—		—		8

Interest rate derivatives	Interest rate derivatives	—		12		30		—		42		Interest rate derivatives	11		58		25		—		94
Mortgage loans held for sale	Mortgage loans held for sale	—		1,687		—		—		1,687		Mortgage loans held for sale	—		975		—		—		975
Money market mutual funds	Money market mutual funds	2,017		—		—		—		2,017		Money market mutual funds	715		—		—		—		715
Debt securities:	Debt securities:											Debt securities:
United States government obligations		228		—		—		—		228
U.S. government obligations												U.S. government obligations	225		—		—		—		225
International government obligations	International government obligations	—		2		—		—		2		International government obligations	—		1		—		—		1
Corporate obligations	Corporate obligations	—		86		—		—		86		Corporate obligations	—		79		—		—		79
Municipal obligations	Municipal obligations	—		3		—		—		3		Municipal obligations	—		3		—		—		3
Agency, asset and mortgage-backed obligations	Agency, asset and mortgage-backed obligations	—		1		—		—		1		Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:	Equity securities:											Equity securities:
United States companies		398		—		—		—		398
U.S. companies												U.S. companies	415		—		—		—		415
International companies	International companies	7,031		—		—		—		7,031		International companies	6,455		—		—		—		6,455
Investment funds	Investment funds	264		—		—		—		264		Investment funds	285		—		—		—		285
		$	9,953	$	2,235	$	118	$	(49)	$	12,257		$	8,119	$	1,651	$	84	$	(64)	$	9,790
Liabilities:	Liabilities:											Liabilities:
Commodity derivatives	Commodity derivatives	$	(2)	$	(134)	$	(56)	$	80	$	(112)	Commodity derivatives	$	(1)	$	(88)	$	(298)	$	69	$	(318)
Foreign currency exchange rate derivatives	Foreign currency exchange rate derivatives	—		(4)		—		—		(4)		Foreign currency exchange rate derivatives	—		(3)		—		—		(3)
Interest rate derivatives	Interest rate derivatives	(1)		(11)		(2)		—		(14)		Interest rate derivatives	—		—		(12)		—		(12)
		$	(3)	$	(149)	$	(58)	$	80	$	(130)		$	(1)	$	(91)	$	(310)	$	69	$	(333)

2017


		Input Levels for Fair Value Measurements											Input Levels for Fair Value Measurements
		Level 1		Level 2		Level 3		Other(1)		Total			Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2020
As of December 31, 2021:												As of December 31, 2021:
Assets:	Assets:											Assets:
Commodity derivatives	Commodity derivatives	$	1	$	73	$	135	$	(21)	$	188	Commodity derivatives	$	5	$	271	$	73	$	(47)	$	302
Foreign currency exchange rate derivatives	Foreign currency exchange rate derivatives	—		20		—		—		20		Foreign currency exchange rate derivatives	—		3		—		—		3
Interest rate derivatives	Interest rate derivatives	—		—		62		—		62		Interest rate derivatives	1		3		20		—		24
Mortgage loans held for sale	Mortgage loans held for sale	—		2,001		—		—		2,001		Mortgage loans held for sale	—		1,263		—		—		1,263
Money market mutual funds	Money market mutual funds	873		—		—		—		873		Money market mutual funds	554		—		—		—		554
Debt securities:	Debt securities:											Debt securities:
United States government obligations		200		—		—		—		200
U.S. government obligations												U.S. government obligations	232		—		—		—		232
International government obligations	International government obligations	—		5		—		—		5		International government obligations	—		2		—		—		2
Corporate obligations	Corporate obligations	—		73		—		—		73		Corporate obligations	—		90		—		—		90
Municipal obligations	Municipal obligations	—		2		—		—		2		Municipal obligations	—		3		—		—		3
Agency, asset and mortgage-backed obligations	Agency, asset and mortgage-backed obligations	—		6		—		—		6		Agency, asset and mortgage-backed obligations	—		2		—		—		2
Equity securities:	Equity securities:											Equity securities:
United States companies		381		—		—		—		381
U.S. companies												U.S. companies	428		—		—		—		428
International companies	International companies	5,906		—		—		—		5,906		International companies	7,703		—		—		—		7,703
Investment funds	Investment funds	201		—		—		—		201		Investment funds	237		—		—		—		237
		$	7,562	$	2,180	$	197	$	(21)	$	9,918		$	9,160	$	1,637	$	93	$	(47)	$	10,843
Liabilities:	Liabilities:											Liabilities:
Commodity derivatives	Commodity derivatives	$	(1)	$	(90)	$	(19)	$	56	$	(54)	Commodity derivatives	$	(2)	$	(113)	$	(224)	$	73	$	(266)
Foreign currency exchange rate derivatives	Foreign currency exchange rate derivatives	—		(2)		—		—		(2)		Foreign currency exchange rate derivatives	—		(3)		—		—		(3)
Interest rate derivatives	Interest rate derivatives	(5)		(60)		—		—		(65)		Interest rate derivatives	—		(7)		(1)		—		(8)
		$	(6)	$	(152)	$	(19)	$	56	$	(121)		$	(2)	$	(123)	$	(225)	$	73	$	(277)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of ~~$31~~$5 million and ~~$35~~$26 million as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, respectively.

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 the 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.

2118

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 financial assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
				Interest				Interest						Interest
		Commodity		Rate		Commodity		Rate				Commodity		Rate
		Derivatives		Derivatives		Derivatives		Derivatives				Derivatives		Derivatives
2021:
2022:										2022:
Beginning balance	Beginning balance	$	105	$	41	$	116	$	62	Beginning balance		$	(151)	$	19
Changes included in earnings(1)	Changes included in earnings(1)	(18)		(13)		(34)		(34)		Changes included in earnings(1)		(56)		(6)
Changes in fair value recognized in OCI	Changes in fair value recognized in OCI	(6)		—		(13)		—		Changes in fair value recognized in OCI		5		—
Changes in fair value recognized in net regulatory assets	Changes in fair value recognized in net regulatory assets	12		—		21		—		Changes in fair value recognized in net regulatory assets		(60)		—

Purchases		1		—		2		—

Settlements	Settlements	(62)		—		(60)		—		Settlements		23		—

Ending balance	Ending balance	$	32	$	28	$	32	$	28	Ending balance		$	(239)	$	13


		Three-Month Periods				Nine-Month Periods
		Ended September 30,				Ended September 30,
				Interest				Interest
		Commodity		Rate		Commodity		Rate
		Derivatives		Derivatives		Derivatives		Derivatives
2020:
2021:										2021:
Beginning balance	Beginning balance	$	44	$	78	$	97	$	14	Beginning balance	$	116	$	62
Changes included in earnings(1)	Changes included in earnings(1)	(7)		10		(11)		74		Changes included in earnings(1)	(6)		(21)
Changes in fair value recognized in OCI										Changes in fair value recognized in OCI	(1)		—
Changes in fair value recognized in net regulatory assets										Changes in fair value recognized in net regulatory assets	16		—

Changes in fair value recognized in net regulatory assets		20		—		(36)		—
Purchases		1		—		4		—

Settlements	Settlements	38		—		42		—		Settlements	(1)		—

Ending balance	Ending balance	$	96	$	88	$	96	$	88	Ending balance	$	124	$	41

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

The Company's long-term debt is carried at cost, including fair value adjustments and unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Balance Sheets. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt (in millions):

As of September 30, 2021 As of December 31, 2020
Carrying Fair Carrying Fair
Value Value Value Value

Long-term debt $ 50,098 $ 57,902 $ 49,866 $ 60,633


	As of March 31, 2022				As of December 31, 2021
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	49,905	$	52,246	$	49,762	$	57,189

(9)8) Commitments and Contingencies

~~Construction Commitments~~

During the nine-month period ended September 30, 2021, MidAmerican Energy entered into firm construction commitments totaling $405 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 nine-month period ended September 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~~real and ~~public~~personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California (the "2020 Wildfires"). 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 destroyed, including residences; 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~~Multiple 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. Additionally, several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. 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 real and personal property and natural resource damage; fire suppression costs; personal injury and loss of life damages; and interest.

~~As of September 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, real and personal property damage, personal injury damages and loss of life ~~damages.~~damages, but exclude estimated potential losses for natural resource damage as PacifiCorp is unable to reasonably estimate such losses at this time. 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 variation in those types of properties and lack of ~~specific claims for all potential claimants.~~available details. 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 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 conditionally approved the required property ~~transfer.~~transfer applications. In August 2021, PacifiCorp notified the Public Service Commission of Utah of the property transfer, however no formal approval is required in Utah. The transfer will be effective within 30 days following the issuance of a license surrender from the FERC for the project, which remains pending. In February 2022, the FERC staff issued a draft environmental impact statement for the project, concluding that dam removal is the preferred alternative. Comments on the draft were due in April 2022, and a final environmental impact statement is expected later in 2022.

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.

~~(10)~~(9) 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 1311 (in millions):


		For the Three-Month Period Ended September 30, 2021																			For the Three-Month Period Ended March 31, 2022
		PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total			PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:	Customer Revenue:																			Customer Revenue:
Regulated:	Regulated:																			Regulated:
Retail electric	Retail electric	$	1,352	$	736	$	1,008	$	—	$	—	$	—	$	—	$	—	$	3,096	Retail electric	$	1,185	$	472	$	599	$	—	$	—	$	—	$	—	$	—	$	2,256
Retail gas	Retail gas	—		84		16		—		—		—		—		—		100		Retail gas	—		337		51		—		—		—		—		—		388
Wholesale	Wholesale	58		113		19		—		14		—		—		(1)		203		Wholesale	55		161		20		—		—		—		—		—		236
Transmission and distribution	Transmission and distribution	55		15		35		241		—		175		—		—		521		Transmission and distribution	32		15		17		269		—		176		—		—		509
Interstate pipeline	Interstate pipeline	—		—		—		—		514		—		—		(28)		486		Interstate pipeline	—		—		—		—		745		—		—		(41)		704
Other	Other	26		—		—		—		(2)		—		—		—		24		Other	20		—		1		—		1		—		—		—		22
Total Regulated	Total Regulated	1,491		948		1,078		241		526		175		—		(29)		4,430		Total Regulated	1,292		985		688		269		746		176		—		(41)		4,115
Nonregulated	Nonregulated	—		2		—		8		257		12		288		141		708		Nonregulated	—		2		—		15		278		7		169		133		604
Total Customer Revenue	Total Customer Revenue	1,491		950		1,078		249		783		187		288		112		5,138		Total Customer Revenue	1,292		987		688		284		1,024		183		169		92		4,719
Other revenue	Other revenue	—		16		7		28		2		(2)		28		8		87		Other revenue	5		18		5		31		11		—		(2)		36		104
Total	Total	$	1,491	$	966	$	1,085	$	277	$	785	$	185	$	316	$	120	$	5,225	Total	$	1,297	$	1,005	$	693	$	315	$	1,035	$	183	$	167	$	128	$	4,823

For the Nine-Month Period Ended September 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 $ 3,685 $ 1,704 $ 2,227 $ — $ — $ — $ — $ (1) $ 7,615
Retail gas — 633 74 — — — — — 707
Wholesale 124 307 44 — 31 — — (2) 504
Transmission and
distribution 117 45 78 747 — 525 — — 1,512
Interstate pipeline — — — — 1,787 — — (94) 1,693
Other 80 — 1 — (1) — — — 80
Total Regulated 4,006 2,689 2,424 747 1,817 525 — (97) 12,111
Nonregulated — 13 1 26 726 27 693 452 1,938
Total Customer Revenue 4,006 2,702 2,425 773 2,543 552 693 355 14,049
Other revenue 25 24 18 84 41 (5) 80 59 326
Total $ 4,031 $ 2,726 $ 2,443 $ 857 $ 2,584 $ 547 $ 773 $ 414 $ 14,375

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


		For the Nine-Month Period Ended September 30, 2020																			For the Three-Month Period Ended March 31, 2021
		PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total			PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:	Customer Revenue:																			Customer Revenue:
Regulated:	Regulated:																			Regulated:
Retail electric	Retail electric	$	3,532	$	1,539	$	2,144	$	—	$	—	$	—	$	—	$	(1)	$	7,214	Retail electric	$	1,145	$	452	$	511	$	—	$	—	$	—	$	—	$	—	$	2,108
Retail gas	Retail gas	—		341		81		—		—		—		—		—		422		Retail gas	—		460		38		—		—		—		—		—		498
Wholesale	Wholesale	76		157		34		—		—		—		—		(1)		266		Wholesale	36		125		15		—		17		—		—		—		193
Transmission and distribution	Transmission and distribution	79		48		75		632		—		502		—		—		1,336		Transmission and distribution	25		15		21		263		—		172		—		—		496
Interstate pipeline	Interstate pipeline	—		—		—		—		885		—		—		(103)		782		Interstate pipeline	—		—		—		—		815		—		—		(41)		774
Other	Other	88		—		1		—		—		—		—		—		89		Other	23		—		—		—		2		—		—		—		25
Total Regulated	Total Regulated	3,775		2,085		2,335		632		885		502		—		(105)		10,109		Total Regulated	1,229		1,052		585		263		834		172		—		(41)		4,094
Nonregulated	Nonregulated	—		13		1		18		—		14		641		394		1,081		Nonregulated	—		10		—		10		237		8		166		187		618
Total Customer Revenue	Total Customer Revenue	3,775		2,098		2,336		650		885		516		641		289		11,190		Total Customer Revenue	1,229		1,062		585		273		1,071		180		166		146		4,712
Other revenue	Other revenue	54		16		23		83		5		—		90		43		314		Other revenue	13		5		6		27		22		—		24		40		137
Total	Total	$	3,829	$	2,114	$	2,359	$	733	$	890	$	516	$	731	$	332	$	11,504	Total	$	1,242	$	1,067	$	591	$	300	$	1,093	$	180	$	190	$	186	$	4,849

(1)The BHE and Other reportable segment represents amounts related principally to other entities, including MidAmerican Energy Services, LLC, 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										HomeServices
		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021
Customer Revenue:	Customer Revenue:									Customer Revenue:
Brokerage	Brokerage	$	1,563	$	1,449	$	4,154	$	3,183	Brokerage		$	1,092	$	1,022
Franchise	Franchise	23		23		65		54		Franchise		20		18
Total Customer Revenue	Total Customer Revenue	1,586		1,472		4,219		3,237		Total Customer Revenue		1,112		1,040
Mortgage and other revenue	Mortgage and other revenue	157		270		519		591		Mortgage and other revenue		95		192
Total	Total	$	1,743	$	1,742	$	4,738	$	3,828	Total		$	1,207	$	1,232

Remaining Performance Obligations

The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of ~~September 30, 2021,~~March 31, 2022, by reportable segment (in millions):

Performance obligations expected to be satisfied:
Less than 12 months More than 12 months Total
BHE Pipeline Group $ 2,586 $ 21,377 $ 23,963
BHE Transmission 175 — 175
Total $ 2,761 $ 21,377 $ 24,138

~~(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.


	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total
BHE Pipeline Group	$	2,878	$	22,103	$	24,981

(1210) 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			Unrecognized		Foreign		Unrealized				AOCI
		Amounts on		Currency		(Losses) Gains				Attributable			Amounts on		Currency		(Losses) Gains				Attributable
		Retirement		Translation		on Cash		Noncontrolling		To BHE			Retirement		Translation		on Cash		Noncontrolling		To BHE
		Benefits		Adjustment		Flow Hedges		Interests		Shareholders, Net			Benefits		Adjustment		Flow Hedges		Interests		Shareholders, Net

Balance, December 31, 2019		$	(417)	$	(1,296)	$	7	$	—	$	(1,706)
Balance, December 31, 2020												Balance, December 31, 2020	$	(492)	$	(1,062)	$	(8)	$	10	$	(1,552)
Other comprehensive income												Other comprehensive income	7		91		14		—		112
Balance, March 31, 2021												Balance, March 31, 2021	$	(485)	$	(971)	$	6	$	10	$	(1,440)

Balance, December 31, 2021												Balance, December 31, 2021	$	(318)	$	(1,086)	$	59	$	5	$	(1,340)
Other comprehensive income (loss)	Other comprehensive income (loss)	38		(195)		(20)		—		(177)		Other comprehensive income (loss)	15		(110)		77		—		(18)
Balance, September 30, 2020		$	(379)	$	(1,491)	$	(13)	$	—	$	(1,883)

Balance, December 31, 2020		$	(492)	$	(1,062)	$	(8)	$	10	$	(1,552)
Other comprehensive income (loss)		44		(59)		48		(4)		29
Balance, September 30, 2021		$	(448)	$	(1,121)	$	40	$	6	$	(1,523)
Balance, March 31, 2022												Balance, March 31, 2022	$	(303)	$	(1,196)	$	136	$	5	$	(1,358)

2723

(1311) Segment Information

The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, and BHE Transmission, whose business includes operations in ~~Canada, and BHE Renewables, whose business includes operations in the Philippines.~~Canada. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021
Operating revenue:	Operating revenue:									Operating revenue:
PacifiCorp	PacifiCorp	$	1,491	$	1,479	$	4,031	$	3,829	PacifiCorp		$	1,297	$	1,242
MidAmerican Funding	MidAmerican Funding	966		812		2,726		2,114		MidAmerican Funding		1,005		1,067
NV Energy	NV Energy	1,085		1,042		2,443		2,359		NV Energy		693		591
Northern Powergrid	Northern Powergrid	277		246		857		733		Northern Powergrid		315		300
BHE Pipeline Group	BHE Pipeline Group	785		264		2,584		890		BHE Pipeline Group		1,035		1,093
BHE Transmission	BHE Transmission	185		175		547		516		BHE Transmission		183		180
BHE Renewables	BHE Renewables	316		309		773		731		BHE Renewables		167		190
HomeServices	HomeServices	1,743		1,742		4,738		3,828		HomeServices		1,207		1,232
BHE and Other(1)	BHE and Other(1)	120		124		414		332		BHE and Other(1)		128		186
Total operating revenue	Total operating revenue	$	6,968	$	6,193	$	19,113	$	15,332	Total operating revenue		$	6,030	$	6,081


Depreciation and amortization:	Depreciation and amortization:									Depreciation and amortization:
PacifiCorp	PacifiCorp	$	272	$	234	$	811	$	696	PacifiCorp	$	280	$	264
MidAmerican Funding	MidAmerican Funding	218		179		634		530		MidAmerican Funding	250		207
NV Energy	NV Energy	138		128		411		377		NV Energy	140		136
Northern Powergrid	Northern Powergrid	73		69		217		195		Northern Powergrid	80		71
BHE Pipeline Group	BHE Pipeline Group	124		45		363		134		BHE Pipeline Group	131		118
BHE Transmission	BHE Transmission	59		61		177		176		BHE Transmission	58		58
BHE Renewables	BHE Renewables	61		72		182		214		BHE Renewables	65		60
HomeServices	HomeServices	14		11		37		34		HomeServices	15		11
BHE and Other(1)	BHE and Other(1)	1		1		2		1		BHE and Other(1)	3		2
Total depreciation and amortization	Total depreciation and amortization	$	960	$	800	$	2,834	$	2,357	Total depreciation and amortization	$	1,022	$	927

2824


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021
Operating income:	Operating income:									Operating income:
PacifiCorp	PacifiCorp	$	394	$	361	$	911	$	851	PacifiCorp		$	216	$	234
MidAmerican Funding	MidAmerican Funding	287		232		438		444		MidAmerican Funding		100		48
NV Energy	NV Energy	348		347		563		587		NV Energy		62		70
Northern Powergrid	Northern Powergrid	126		106		403		327		Northern Powergrid		159		151
BHE Pipeline Group	BHE Pipeline Group	303		101		1,166		442		BHE Pipeline Group		538		618
BHE Transmission	BHE Transmission	90		79		256		236		BHE Transmission		83		81
BHE Renewables	BHE Renewables	149		143		279		244		BHE Renewables		(2)		33
HomeServices	HomeServices	135		239		426		336		HomeServices		28		112
BHE and Other(1)	BHE and Other(1)	2		(61)		(67)		(65)		BHE and Other(1)		52		(14)
Total operating income	Total operating income	1,834		1,547		4,375		3,402		Total operating income		1,236		1,333
Interest expense	Interest expense	(531)		(504)		(1,593)		(1,490)		Interest expense		(532)		(530)
Capitalized interest	Capitalized interest	18		24		46		60		Capitalized interest		17		14
Allowance for equity funds	Allowance for equity funds	34		50		90		122		Allowance for equity funds		38		26
Interest and dividend income	Interest and dividend income	18		17		65		57		Interest and dividend income		23		21
Gains on marketable securities, net		294		1,797		1,142		2,407
Losses on marketable securities, net										Losses on marketable securities, net		(1,257)		(1,118)
Other, net	Other, net	8		36		64		61		Other, net		5		8
Total income before income tax (benefit) expense and equity loss		$	1,675	$	2,967	$	4,189	$	4,619
Total loss before income tax benefit and equity loss										Total loss before income tax benefit and equity loss		$	(470)	$	(246)

Interest expense:
PacifiCorp $ 110 $ 107 $ 322 $ 319
MidAmerican Funding 81 79 237 238
NV Energy 51 56 154 171
Northern Powergrid 33 34 98 97
BHE Pipeline Group 33 15 111 44
BHE Transmission 39 38 117 111
BHE Renewables 39 41 119 125
HomeServices 1 1 3 9
BHE and Other(1)
144 133 432 376
Total interest expense $ 531 $ 504 $ 1,593 $ 1,490
Earnings on common shares:
PacifiCorp $ 333 $ 286 $ 728 $ 629
MidAmerican Funding 373 337 728 695
NV Energy 282 249 416 367
Northern Powergrid 83 26 162 172
BHE Pipeline Group 144 78 627 321
BHE Transmission 65 58 184 173
BHE Renewables 163 162 360 395
HomeServices 102 177 321 246
BHE and Other(1)
351 1,469 580 1,630
Total earnings on common shares $ 1,896 $ 2,842 $ 4,106 $ 4,628





Interest expense:
PacifiCorp	$	106	$	107
MidAmerican Funding	82		78
NV Energy	51		52
Northern Powergrid	32		33
BHE Pipeline Group	37		38
BHE Transmission	38		38
BHE Renewables	41		40
HomeServices	1		1
BHE and Other(1)	144		143
Total interest expense	$	532	$	530


Loss on common shares:
PacifiCorp	$	130	$	169
MidAmerican Funding	241		144
NV Energy	29		34
Northern Powergrid	111		104
BHE Pipeline Group	322		383
BHE Transmission	62		59
BHE Renewables	104		16
HomeServices	21		84
BHE and Other(1)	(1,165)		(1,027)
Total loss on common shares	$	(145)	$	(34)

2925


		As of					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
Assets:	Assets:					Assets:
PacifiCorp	PacifiCorp	$	28,230	$	26,862	PacifiCorp	$	27,999	$	27,615
MidAmerican Funding	MidAmerican Funding	25,038		23,530		MidAmerican Funding	25,451		25,352
NV Energy	NV Energy	15,105		14,501		NV Energy	15,430		15,239
Northern Powergrid	Northern Powergrid	9,043		8,782		Northern Powergrid	9,175		9,326
BHE Pipeline Group	BHE Pipeline Group	19,993		19,541		BHE Pipeline Group	20,486		20,434
BHE Transmission	BHE Transmission	9,383		9,208		BHE Transmission	9,618		9,476
BHE Renewables	BHE Renewables	11,766		12,004		BHE Renewables	12,138		11,829
HomeServices	HomeServices	5,065		4,955		HomeServices	4,036		4,574
BHE and Other(1)	BHE and Other(1)	7,931		7,933		BHE and Other(1)	7,136		8,220
Total assets	Total assets	$	131,554	$	127,316	Total assets	$	131,469	$	132,065

(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				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021
Operating revenue by country:	Operating revenue by country:									Operating revenue by country:
United States		$	6,499	$	5,773	$	17,700	$	14,086
U.S.										U.S.		$	5,534	$	5,597
United Kingdom	United Kingdom	277		246		857		733		United Kingdom		315		300
Canada	Canada	180		174		537		512		Canada		181		177
Philippines and other		12		—		19		1
Other										Other		—		7
Total operating revenue by country	Total operating revenue by country	$	6,968	$	6,193	$	19,113	$	15,332	Total operating revenue by country		$	6,030	$	6,081

Income before income tax (benefit) expense and equity loss by country:
United States $ 1,511 $ 2,839 $ 3,699 $ 4,220
United Kingdom 107 82 343 250
Canada 49 44 134 130
Philippines and other 8 2 13 19
Total income before income tax (benefit) expense and equity loss by country $ 1,675 $ 2,967 $ 4,189 $ 4,619


Loss before income tax benefit and equity loss by country:
U.S.	$	(654)	$	(423)
United Kingdom	139		132
Canada	46		39
Other	(1)		6
Total loss before income tax benefit and equity loss by country	$	(470)	$	(246)

The following table shows the change in the carrying amount of goodwill by reportable segment for the ~~nine-month~~three-month period ended ~~September 30, 2021~~March 31, 2022 (in millions):


											BHE Pipeline Group																																			BHE Pipeline Group
		PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid					BHE Transmission				BHE Renewables				HomeServices								PacifiCorp				MidAmerican Funding			NV Energy				Northern Powergrid								BHE Transmission				BHE Renewables				HomeServices
										BHE Pipeline Group									Total															BHE Pipeline Group								Total

December 31, 2020		$	1,129	$	2,102	$	2,369	$	1,000				$	1,803			$	1,551			$	95			$	1,457	$	11,506
December 31, 2021																														December 31, 2021	$	1,129				$	2,102			$	2,369			$	992			$	1,814			$	1,563			$	95			$	1,586			$	11,650
Acquisitions	Acquisitions	—		—		—		—			11				—				—				59				70			Acquisitions	—			—				—				—				—				—				—				3				3
Foreign currency translation	Foreign currency translation	—		—		—		(10)			—				6				—				—				(4)			Foreign currency translation	—			—				—				(20)				—				16				—				—				(4)

September 30, 2021		$	1,129	$	2,102	$	2,369	$	990		$	1,814			$	1,557			$	95			$	1,516			$	11,572
March 31, 2022																														March 31, 2022	$	1,129		$	2,102			$	2,369			$	972			$	1,814			$	1,579			$	95			$	1,589			$	11,649

3026

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~~U.S. 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,~~U.S., an electric transmission business in Canada, interests in electric transmission businesses in the ~~United States,~~U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the ~~United States~~U.S. and one of the largest residential real estate brokerage franchise networks in the ~~United States.~~U.S. 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, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.

3127

Results of Operations for the ~~Third~~First Quarter of 2022 and ~~First Nine 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):


		Third Quarter								First Nine Months									First Quarter
		2021		2020		Change				2021		2020		Change					2022		2021		Change
Operating revenue:	Operating revenue:																	Operating revenue:
PacifiCorp	PacifiCorp	$	1,491	$	1,479	$	12	1	%	$	4,031	$	3,829	$	202	5	%	PacifiCorp	$	1,297	$	1,242	$	55	4	%
MidAmerican Funding	MidAmerican Funding	966		812		154		19		2,726		2,114		612		29		MidAmerican Funding	1,005		1,067		(62)		(6)
NV Energy	NV Energy	1,085		1,042		43		4		2,443		2,359		84		4		NV Energy	693		591		102		17
Northern Powergrid	Northern Powergrid	277		246		31		13		857		733		124		17		Northern Powergrid	315		300		15		5
BHE Pipeline Group	BHE Pipeline Group	785		264		521		*		2,584		890		1,694		*		BHE Pipeline Group	1,035		1,093		(58)		(5)
BHE Transmission	BHE Transmission	185		175		10		6		547		516		31		6		BHE Transmission	183		180		3		2
BHE Renewables	BHE Renewables	316		309		7		2		773		731		42		6		BHE Renewables	167		190		(23)		(12)
HomeServices	HomeServices	1,743		1,742		1		—		4,738		3,828		910		24		HomeServices	1,207		1,232		(25)		(2)
BHE and Other	BHE and Other	120		124		(4)		(3)		414		332		82		25		BHE and Other	128		186		(58)		(31)
Total operating revenue	Total operating revenue	$	6,968	$	6,193	$	775	13	%	$	19,113	$	15,332	$	3,781	25	%	Total operating revenue	$	6,030	$	6,081	$	(51)	(1)	%

Earnings on common shares:
Loss on common shares:																		Loss on common shares:
PacifiCorp	PacifiCorp	$	333	$	286	$	47	16	%	$	728	$	629	$	99	16	%	PacifiCorp	$	130	$	169	$	(39)	(23)	%
MidAmerican Funding	MidAmerican Funding	373		337		36		11		728		695		33		5		MidAmerican Funding	241		144		97		67
NV Energy	NV Energy	282		249��		33		13		416		367		49		13		NV Energy	29		34		(5)		(15)
Northern Powergrid	Northern Powergrid	83		26		57		*		162		172		(10)		(6)		Northern Powergrid	111		104		7		7
BHE Pipeline Group	BHE Pipeline Group	144		78		66		85		627		321		306		95		BHE Pipeline Group	322		383		(61)		(16)
BHE Transmission	BHE Transmission	65		58		7		12		184		173		11		6		BHE Transmission	62		59		3		5
BHE Renewables(1)	BHE Renewables(1)	163		162		1		1		360		395		(35)		(9)		BHE Renewables(1)	104		16		88		*
HomeServices	HomeServices	102		177		(75)		(42)		321		246		75		30		HomeServices	21		84		(63)		(75)
BHE and Other	BHE and Other	351		1,469		(1,118)		(76)		580		1,630		(1,050)		(64)		BHE and Other	(1,165)		(1,027)		(138)		(13)
Total earnings on common shares		$	1,896	$	2,842	$	(946)	(33)	%	$	4,106	$	4,628	$	(522)	(11)	%
Total loss on common shares																		Total loss on common shares	$	(145)	$	(34)	$	(111)	*

(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 decreased ~~$946~~$111 million for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020.~~2021. The ~~third~~first quarter of ~~2021~~2022 included a pre-tax unrealized ~~gain~~loss of ~~$296~~$1,247 million ($~~253~~985 million after-tax) compared to a pre-tax unrealized ~~gain~~loss in the third quarter of 2020 of $1,787 million ($1,299 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 thirdfirst quarter of 2021 ~~was $1,643~~of $1,124 million ~~an increase of $100 million, or 6%, compared to adjusted earnings on common shares in the third quarter of 2020 of $1,543 million.~~

~~Earnings on common shares decreased $522 million for the first nine months of 2021 compared to 2020. The first nine months of 2021 included a pre-tax unrealized gain of $1,126 million~~ ($~~855 million after-tax) compared to a pre-tax unrealized gain in the first nine months of 2020 of $2,402 million ($1,746~~818 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 ~~nine months~~quarter of ~~2021~~2022 was ~~$3,251~~$840 million, an increase of ~~$369~~$56 million, or ~~13%~~7%, compared to adjusted earnings on common shares in the first ~~nine months~~quarter of ~~2020~~2021 of ~~$2,882~~$784 million.

3228

The ~~decreases~~decrease in earnings on common shares for the ~~third~~first quarter ~~and for the first nine months~~ of ~~2021~~2022 compared to ~~2020 were~~2021 was primarily due to the following:

•The Utilities' earnings increased ~~$116 million for the third quarter and $181~~$53 million for the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~2020,~~2021, reflecting higher electric utility margin and favorable income tax expense from higher PTCs recognized, and the impacts of ratemaking, and lower operations and maintenance expense, partially offset by higher depreciation and amortization expense. Electric retail customer volumes increased 4.8% for the first nine 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 earnings increased $57 million for the third quarter and decreased $10 million for the first nine months of 2021 compared to 2020, primarily due to deferred income tax charges ($35 million in third quarter 2020 and $109 million in second quarter 2021) related to enacted increases in the United Kingdom corporate income tax rate and higher distribution revenue;

•BHE Pipeline Group's earnings increased $66 million for the third quarter and $306 million for the first nine months of 2021 compared to 2020, largely due to $74 million and $247 million, respectively, of incremental earnings from BHE GT&S, acquired in November 2020. In addition, earnings for the first nine 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' earnings decreased $35 million for the first nine months of 2021 compared to 2020, primarily due to lower tax equity investment earnings from the February 2021 polar vortex weather event, partially offset by earnings from tax equity investment projects reaching commercial operation and higher operating revenue from owned renewable energy projects;

•HomeServices' earnings decreased $75 million for the third quarter and increased $75 million for the first nine months of 2021 compared to 2020, primarily due to lower earnings from mortgage services due to a decrease in refinance activity. In addition, earnings for the first nine months was favorably impacted by higher earnings from brokerage services due to an increase in closed transaction volume and an increase in mortgage services earnings due to an unfavorable 2020 contingent earn-out remeasurement; and

•BHE and Other's earnings decreased $1,118 million for the third quarter and $1,050 million for the first nine months of 2021 compared to 2020, mainly due to $1,046 million and $891 million, respectively, of unfavorable changes in the after-tax unrealized position of the Company's investment in BYD Company Limited, and 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 $12 million for the third quarter of 2021 compared to 2020, primarily due to higher retail revenue of $8 million and higher wholesale and other revenue of $4 million. Retail revenue increased due to higher customer volumes of $28 million, partially offset by price impacts of $20 million from lower rates primarily due to certain general rate case orders. Retail customer volumes increased 2.1%, primarily due to an increase in the average number of customers and higher customer usage. Wholesale and other revenue increased primarily due to higher wheeling revenue and REC sales, partially offset by $27 million from the Oregon RAC settlement (offset in depreciation expense) recognized in 2020.

Earnings increased $47 million for the third quarter of 2021 compared to 2020, primarily due to lower operations and maintenance expense of $65 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 higher utility margin of $6 million, partially offset by higher depreciation and amortization expense of $38 million and lower allowances for equity and borrowed funds used during construction of $24 million. Utility margin increased primarily due to higher deferred net power costs in accordance with established adjustment mechanisms and the higher retail and wheeling revenue, partially offset by higher purchased power and thermal generation costs and higher ~~wheeling expenses. Operations~~operations and maintenance expense decreased primarily due to 2020 costs associated with the Klamath Hydroelectric Settlement Agreement and wildfires and lower thermal plant maintenance expense, partially offset by higher costs associated with additional wind-powered generating facilities placed in-service as well as higher distribution maintenance costs. The increase in depreciation and amortization expense was primarily due to the impacts of a depreciation study effective January 1, 2021, as well as additional assets placed in-service.

~~Operating revenue~~expense. Electric retail customer volumes increased ~~$202 million~~3.4% for the first ~~nine months~~quarter of ~~2021~~2022 compared to 2020, primarily due to higher retail revenue of $152 million and higher wholesale and other revenue of $50 million. Retail revenue increased due to higher customer volumes of $176 million, partially offset by price impacts of $24 million from lower rates primarily due to certain general rate case orders. Retail customer volumes increased 4.4%,2021, primarily due to higher customer usage, an increase in the average number of customers and the favorable impact of ~~weather.~~weather;

•BHE Pipeline Group's earnings decreased $61 million for the first quarter of 2022 compared to 2021, primarily due to lower earnings of $70 million at Northern Natural Gas from higher gross margin on gas sales and higher transportation revenue recognized in the first quarter of 2021 from the February 2021 polar vortex weather event, partially offset by favorable recurring transportation revenue due to higher volumes and rates;

•BHE Renewables' earnings increased $88 million for the first quarter of 2022 compared to 2021, primarily due to higher earnings on tax equity investments of $96 million as a result of the unfavorable impacts recognized in the first quarter of 2021 from the February 2021 polar vortex weather event;

•HomeServices' earnings decreased $63 million for the first quarter of 2022 compared to 2021, primarily due to lower earnings from mortgage services of $48 million, from a decrease in funded volume, and lower earnings from brokerage and settlement services of $16 million, largely attributable to a decrease in closed units at existing companies; and

•BHE and Other's earnings decreased $138 million for the first quarter of 2022 compared to 2021, mainly due to the $167 million unfavorable comparative change in the after-tax unrealized position of the Company's investment in BYD Company Limited, partially offset by $21 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway.

Reportable Segment Results

PacifiCorp

Operating revenue increased $55 million for the first quarter of 2022 compared to 2021, primarily due to higher retail revenue of $40 million and higher wholesale and other revenue of $15 million. Retail revenue increased primarily due to higher retail volumes of $25 million and price impacts of $15 million from higher tariffs. Retail customer volumes increased 1.9%, primarily due to an increase in the average number of customers, the favorable impact of weather and higher customer usage. Wholesale and other revenue increased primarily due to higher average wholesale prices and higher wheeling ~~revenue, wholesale volumes and REC sales, partially offset by $34 million from the Oregon RAC settlement (offset in depreciation expense) recognized in 2020.~~revenue.

Earnings ~~increased $99~~decreased $39 million for the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~2020,~~2021, primarily due to higher ~~utility margin of $131 million, favorable income tax expense, from higher PTCs recognized due to new wind-powered generating facilities placed in-service and the impacts of ratemaking, and lower~~ operations and maintenance expense of ~~$48~~$18 million, ~~partially offset by~~ higher depreciation and amortization expense of ~~$115~~$16 million, from additional assets placed in-service, and ~~lower allowances for equity~~increased income tax expense, partially offset by higher utility margin of $14 million. Operations and ~~borrowed funds used during construction of $53 million.~~maintenance expense increased mainly due to higher thermal plant maintenance and higher costs associated with additional wind-powered generating facilities placed in-service. Utility margin increased primarily due to the higher retail, wholesale and ~~wheeling~~other revenues and higher deferred net power costs in accordance with established adjustment mechanisms, partially offset by higher purchased power and thermal generation costs and higher wheeling expenses. Operations and maintenance expense decreased primarily due to 2020 costs associated with the Klamath Hydroelectric Settlement Agreement and wildfires and lower thermal plant maintenance expense, partially offset by higher costs associated with additional wind-powered generating facilities placed in-service as well as higher distribution maintenance costs. ~~The increase in depreciation and amortization expense was primarily due to the impacts of a depreciation study effective January 1, 2021, as well as additional assets placed in-service.~~

MidAmerican Funding

Operating revenue ~~increased $154~~decreased $62 million for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020,~~2021, primarily due to lower natural gas operating revenue of $116 million, partially offset by higher electric operating revenue of ~~$126 million and higher natural~~$63 million. Natural gas operating revenue decreased due to a lower average per-unit cost of ~~$30~~natural gas sold resulting in lower purchased gas adjustment recoveries of $134 million (fully offset in cost of sales), partially offset by the impacts of tax reform of $8 million, the impacts of certain regulatory recovery mechanisms of $7 million and the favorable impacts of weather of $4 million. Electric operating revenue increased due to higher ~~retail revenue of $67 million and higher~~ wholesale and other revenue of ~~$59 million. Electric~~$43 million and higher retail revenue ~~increased primarily due to higher recoveries through adjustment clauses~~ of ~~$43 million (largely offset in cost of sales) and higher customer volumes of $24~~$20 million. ~~Electric retail customer volumes increased 5.6% due to increased usage of certain industrial customers and the favorable impact of weather.~~ Electric wholesale and other revenue increased mainly due to higher wholesale volumes of $24 million and higher average wholesale per-unit prices of ~~$34~~$19 million. Electric retail revenue increased primarily due to higher customer volumes of $18 million and higher recoveries through adjustment clauses of $4 million (fully offset in expense, primarily cost of sales), partially offset by price impacts from changes in sales mix of $2 million. Electric retail customer volumes increased 5.6% due to higher customer usage and the favorable impact of weather.

Earnings increased $97 million for the first quarter of 2022 compared to 2021, primarily due to higher electric utility margin of $89 million, a favorable income tax benefit and higher natural gas utility margin of $18 million, partially offset by higher depreciation and amortization expense of $43 million and lower nonregulated utility margin of $9 million. Electric utility margin increased primarily due to the higher retail and wholesale revenues as well as lower purchased power costs. The favorable income tax benefit was largely due to higher PTCs recognized of $52 million, from new wind-powered generating facilities placed in-service, and the effects of ratemaking. Depreciation and amortization expense increased primarily from the impacts of certain regulatory mechanisms and additional assets placed in-service.

NV Energy

Operating revenue increased $102 million for the first quarter of 2022 compared to 2021, primarily due to higher electric operating revenue of $90 million and higher natural gas operating revenue of $13 million. Electric operating revenue increased primarily due to higher fully-bundled energy rates (fully offset in cost of sales) of $88 million, higher retail customer volumes of ~~$17 million.~~$4 million and higher transmission and wholesale revenue of $4 million, partially offset by lower regulatory-related revenue deferrals. Electric retail customer volumes increased 4.0%, primarily due to an increase in the average number of customers and higher customer usage, partially offset by the unfavorable 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 $24 million (offset~~(fully offset in cost of sales).

Earnings increased $36 million for the third quarter of 2021 compared to 2020, primarily due to higher electric utility margin of $78 million and lower operations and maintenance expense of $12 million, mainly due to 2020 costs associated with storm restoration activities, partially offset by higher depreciation and amortization expense of $39 million. Electric utility margin increased primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs. Depreciation and amortization expense increased primarily due to additional assets placed in-service as well as from the impacts of certain regulatory mechanisms.

~~Operating revenue increased $612~~decreased $5 million for the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~2020, primarily~~2021, mainly due to higher natural gas operating revenue of $344 million and higher electric operating revenue of $268 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 $345 million (offset in cost of sales), primarily due to the February 2021 polar vortex weather event. Electric operating revenue increased due to higher retail revenue of $157 million and higher wholesale and other revenue of $111 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $91 million (largely offset in cost of sales), higher customer volumes of $59 million and price impacts of $7 million from changes in sales mix. Electric retail customer volumes increased 6.5% due to increased usage of certain industrial customers and the favorable impact of weather. Electric wholesale and other revenue increased due to higher wholesale volumes of $64 million and higher average wholesale per-unit prices of $42 million.

Earnings increased $33 million for the first nine months of 2021 compared to 2020, primarily due to higher electric utility margin of $117 million and a favorable income tax benefit, partially offset by higher depreciation and amortization expense of $104 million, higher operations and maintenance expense of ~~$18~~$6 million ~~and lower allowances for equity and borrowed funds of $12 million. Electric utility margin~~largely from increased primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs. Operations and maintenance expense increased primarily due to higher costs associated with additional wind-powered generating facilities placed in-service as well as higher natural gas distribution costs, partially offset by 2020 costs associated with storm restoration activities. The increase in depreciation and amortization expense was primarily due to additional assets placed in-service as well as from the impacts of certain regulatory mechanisms. The favorable income tax benefit was from higher PTCs recognized due to new wind-powered generating facilities placed in-service, partially offset by the impacts of ratemaking.

On October 29, 2021, the IUB issued an order extending for three years the depreciation deferral regulatory mechanism approved by the IUB in MidAmerican Energy's 2013 electric rate case. In December 2020, the cumulative deferral reached the limit previously set by the IUB, resulting in higher depreciation expense of $13 million for the third quarter and $39 million for the first nine months of 2021. With the extension of the deferral, annual depreciation expense will be approximately $50 million lower in years 2021 through 2023 than would have been recognized absent the order. The annual amount of the deferral for 2021 will be recognized in the fourth quarter.

~~NV Energy~~

Operating revenue increased $43 million for the third 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 $80 million and an increase in the average number of customers, partially offset by lower base tariff general rates of $27 million at Nevada Power and a favorable regulatory decision in 2020. Electric retail customer volumes increased 3.9%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather.

~~Earnings increased $33 million for the third quarter of 2021 compared to 2020, primarily due to lower~~plant operations and maintenance ~~expense of $51 million, lower income tax expense from the impacts of ratemaking~~expenses and lower interest expense of $5 million, partially offset by lower electric utility margin of $39 million and higher depreciation and amortization expense of $9 million. Electric utility margin decreased primarily due to lower base tariff general rates at Nevada Power and a favorable regulatory decisionan unfavorable change in ~~2020, partially offset by an increase in the average number of customers. Operations and maintenance expense decreased primarily due to lower~~ earnings sharing at the Nevada Power and lower regulatory deferrals and amortizations. The increase in depreciation and amortization expense was mainly due to the regulatory amortization of decommissioning costs and additional assets placed in-service.

Operating revenue increased $84 million for the first nine months of 2021 compared to 2020, primarily due to higher electric operating revenue of $92 million, partially offset by lower natural gas operating revenue of $8 million. Electric operating revenue increased primarily due to higher fully-bundled energy rates (offset in cost of sales) of $153 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 $51 million at Nevada Power and a favorable regulatory decision in 2020. Electric retail customer volumes increased 4.2%, primarily due to higher customer usage 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).

Earnings increased $49 million for the first nine months of 2021 compared to 2020, primarily due to lower operations and maintenance expense of $72 million, lower income tax expense from the impacts of ratemaking, lower interest expense of $17 million, lower pension costs of $10 million, higher interest and dividend income of $8 million and favorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by lower electric utility margin of $61 million and higher depreciation and amortization expense of $34 million. Electric utility margin decreased primarily due to lower base tariff general rates at Nevada Power and a favorable regulatory decision in 2020, partially offset by higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers. Operations and maintenance expense decreased primarily due to lower regulatory deferrals and amortizations and lower earnings sharing at Nevada Power. The increase in depreciation and amortization expense was mainly due to the regulatory amortization of decommissioning costs and additional assets placed in-service.Utilities.

Northern Powergrid

Operating revenue increased ~~$31~~$15 million for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020,~~2021, primarily due to ~~$17 million from the weaker United States dollar and~~ higher distribution revenue of ~~$17~~$10 million, ~~mainly~~revenue from ~~4.1%~~a gas project reaching commercial operation in March 2022 totaling $10 million and higher smart metering revenue of $6 million, partially offset by $9 million from the stronger U.S. dollar. Distribution revenue increased from higher tariff rates of $14 million, partially offset by a 2.6% decline in units distributed of ~~$10 million and increased tariff rates of $8~~$3 million.

Earnings increased $57 million for the third quarter of 2021 compared to 2020, primarily due to a deferred income tax charge in July 2020 of $35 million related to the United Kingdom corporate income tax rate not decreasing from 19% to 17% effective April 1, 2020, as had previously been announced, and the higher distribution revenue.

~~Operating revenue increased $124~~$7 million for the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~2020,~~2021, primarily due to ~~$69 million from the weaker United States dollar and higher distribution revenue of $56 million, mainly from increased tariff rates of $27 million and 4.5% higher units distributed of $26 million.~~

Earnings decreased $10 million for the first nine months of 2021 compared to 2020, primarily due to a deferred income tax charge of $109 million related to a June 2021 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, a deferred income tax charge in July 2020 of $35 million related to the United Kingdom corporate income tax rate not decreasing from 19% to 17% effective April 1, 2020, as had previously been announced, and $11partially offset by $3 million from the ~~weaker United States~~stronger U.S. dollar.

BHE Pipeline Group

Operating revenue ~~increased $521~~decreased $58 million for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020,~~2021, primarily due to ~~$516~~lower gas sales of $41 million ~~of incremental revenue~~related to system balancing activities at ~~BHE GT&S, acquired in November 2020, and higher transportation revenue of $23 million at Kern River largely due to higher rates, partially offset by~~Northern Natural Gas, lower transportation revenue of ~~$19~~$20 million at Northern Natural Gas ~~primarily due to~~and lower ~~volumes.~~

~~Earnings increased $66~~gas sales of $17 million at EGTS used for ~~the third quarter~~operational and system balancing purposes, partially offset by higher LNG variable revenue of ~~2021 compared to 2020, primarily due to $74~~$13 million ~~of incremental earnings~~ at BHE GT&S and higher ~~earnings~~non-regulated revenue of ~~$16~~$11 million at ~~Kern River from the higher~~BHE GT&S. The variances in gas sales and transportation revenue ~~partially offset by lower earnings of $25 million~~ at Northern Natural Gas ~~primarily due to the lower transportation revenue.~~

~~Operating revenue increased $1,694 million for~~included favorable impacts recognized in the first ~~nine months~~quarter of 2021 ~~compared to 2020, primarily due to $1,563 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~~respectively, from the February 2021 polar vortex weather ~~event, higher~~event. Excluding this item, gas sales ~~at Northern Natural Gas of $33~~increased $36 million (largely offset in cost of sales) and ~~higher~~ transportation revenue ~~of $25~~increased $29 million ~~at Kern River largely~~ due to higher ~~rates, partially offset by~~volumes and rates.

Earnings decreased $61 million for the first quarter of 2022 compared to 2021, primarily due to lower ~~transportation revenue~~earnings of ~~$69~~$70 million at Northern Natural Gas ~~primarily due to lower volumes.~~

~~Earnings increased $306 million for~~as the first nine months of 2021 compared to 2020, primarily due to $247 million of incremental earnings at BHE GT&S, higher earnings of $39 million at Northern Natural Gas and favorable earnings of $18 million at Kern River from the higher transportation revenue. Northern Natural Gas' improved performance was primarily due to higher gross margin on gas sales and higher transportation revenue ~~each due to~~recognized in the ~~favorable impacts~~first quarter of 2021 from the February 2021 polar vortex weather event were partially offset by the ~~lower~~favorable transportation revenue due ~~primarily~~ to ~~lower volumes.~~higher volumes and rates.

BHE Transmission

Operating revenue increased ~~$10~~$3 million for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020, primarily~~2021, mainly due to ~~$10 million from the stronger United States dollar and~~ higher revenue at AltaLink from ~~the Montana-Alberta Tie-Line~~recovery of ~~$5 million, partially offset by the impact of a regulatory decision received in November 2020 at AltaLink.~~higher costs and from additional assets placed in-service.

Earnings increased ~~$7 million for the third quarter of 2021 compared to 2020, primarily due to higher earnings from the Montana-Alberta Tie-Line.~~

~~Operating revenue increased $31~~$3 million for the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~2020, primarily~~2021, mainly due to ~~$40 million from~~ the ~~stronger United States dollar~~additional assets placed in-service at AltaLink and ~~higher revenue from the Montana-Alberta Tie-Line of $10 million, partially offset by the impacts of regulatory decisions received in April and November 2020~~improved equity earnings at ~~AltaLink.~~Electric Transmission Texas, LLC.

Earnings increased $11 million for the first nine months of 2021 compared to 2020, primarily due to $11 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 impact of a regulatory decision received in April 2020 at AltaLink.

BHE Renewables

Operating revenue ~~increased $7~~decreased $23 million for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020,~~2021, primarily due to unfavorable changes in the valuation of certain derivative contracts totaling $43 million and lower hydro revenues of $8 million due to the transfer of the Casecnan generating facility to the National Irrigation Administration in December 2021, partially offset by higher ~~hydro, natural gas~~wind, solar and ~~solar~~geothermal revenues of $27 million from higher generation and ~~favorable market conditions, partially offset by an unfavorable change in the valuation of a power purchase agreement of $8 million and lower geothermal revenues from lower generation.~~pricing.

Earnings increased $1$88 million for the ~~third~~first quarter ~~2021~~2022 compared to ~~2020,~~2021, primarily due to higher wind earnings of $92 million and higher solar earnings of $6 million, ~~mainly from tax equity investments offset by~~largely due to the ~~unfavorable change in the valuation of a power purchase agreement, and~~ higher ~~hydro earnings of $5 million from higher generation,~~operating revenue, partially offset by lower ~~geothermal~~hydro earnings of ~~$12~~$10 million ~~primarily~~ due to ~~lower geothermal generation and natural gas margin.~~

~~Operating revenue~~the Casecnan generating facility transfer. Wind earnings increased ~~$42 million for the first nine months of 2021 compared to 2020,~~ primarily due to higher ~~natural gas, hydro and solar revenues from favorable market conditions and higher generation, partially offset by an unfavorable change in the valuation of a power purchase agreement of $22 million.~~

~~Earnings decreased $35 million for the first nine months of 2021 compared to 2020, primarily due to lower wind~~ earnings of $56 million, largely from lower tax equity investment earnings of $48 million and the unfavorable change in the valuation of a power purchase agreement, partially offset by higher solar earnings of $18 million, mainly due to higher generation and lower depreciation expense, and higher hydro earnings of $5 million from higher generation. Tax equity investment earnings decreased due to unfavorable results from existingon tax equity investments of ~~$123~~$96 million ~~primarily due to~~as a result of the unfavorable impacts recognized in the first quarter of 2021 from the February 2021 polar vortex weather ~~event, partially offset by $79 million of earnings from projects reaching commercial operation.~~event.

HomeServices

Operating revenue ~~increased $1~~decreased $25 million for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020,~~2021, primarily due to lower mortgage revenue of $97 million from a 41% decrease in funded volume due to lower refinance activity, partially offset by higher brokerage revenue of ~~$117 million, partially offset by lower mortgage revenue of $112~~$78 million from a ~~27% decrease~~9% increase in ~~funded~~closed transaction volume. The increase in brokerage ~~revenue~~volume was due to ~~$67 million from acquired companies~~acquisitions and ~~a 5% increase in closed transaction volume at existing companies, resulting from~~ an 11% increase in average sales price at existing companies offset by 12% fewer closed ~~units.~~units at existing companies.

Earnings decreased ~~$75~~$63 million for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020,~~2021, primarily due to lower earnings from mortgage services of ~~$76~~$48 million, from the decrease in funded volume, and lower earnings from brokerage and settlement services of $16 million, largely attributable to the decrease in ~~funded volume.~~

Operating revenue increased $910 million for the first nine months of 2021 compared to 2020, primarily due to higher brokerage revenue of $933 million from a 34% increase in closed transaction volume, resulting from increases in closed units ~~and average sales price, partially offset by lower mortgage revenue of $71 million from a decrease in refinance activity.~~

Earnings increased $75 million for the first nine months of 2021 compared to 2020, primarily due to higher earnings from brokerage services of $84 million, largely due to the increase in closed transaction volume, partially offset by lower earnings from mortgage services of $28 million, largely attributable to the decrease in refinance activity offset by an unfavorable 2020 contingent earn-out remeasurement.at existing companies.

BHE and Other

Operating revenue decreased $4$58 million for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020,~~2021, primarily due to lower electricity sales revenue at MidAmerican Energy Services, LLC, from ~~lower volumes offset by favorable~~unfavorable pricing.

Earnings decreased ~~$1,118~~$138 million for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020,~~2021, primarily due to the ~~$1,046~~$167 million unfavorable comparative change in the after-tax unrealized position of the Company's investment in BYD Company Limited ~~$86~~and $54 million of lower federal income tax credits recognized on a consolidated basis, $26 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 October 2020 and unfavorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by lower other corporate costs and higher earnings of $18 million at MidAmerican Energy Services, LLC, mainly due to favorable changes in unrealized positions on derivative contracts.

Operating revenue increased $82 million for the first nine 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.

Earnings decreased $1,050 million for the first nine months of 2021 compared to 2020, primarily due to the $891 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $101 million of dividends on BHE's 4.00% Perpetual Preferred Stock, $44 million of lower federal income tax credits recognized on a consolidated basis, higher BHE corporate interest expense from debt issuances in March and October 2020 and higher other corporate costs, partially offset by higher earnings of ~~$30~~$41 million at MidAmerican Energy Services, LLC, mainly due to favorable changes in unrealized positions on derivative contracts, lower corporate costs and ~~favorable changes in the cash surrender value~~$21 million of ~~corporate-owned life insurance policies.~~

lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway.

3731

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~~2021 for further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of ~~September 30, 2021,~~March 31, 2022, the Company's total net liquidity was as follows (in millions):


																																	BHE Pipeline
						MidAmerican		NV		Northern		BHE											MidAmerican		NV		Northern		BHE				Group and
		BHE		PacifiCorp		Funding		Energy		Powergrid		Canada		Other		Total			BHE		PacifiCorp		Funding		Energy		Powergrid		Canada		HomeServices		Other		Total

Cash and cash equivalents	Cash and cash equivalents	$	300	$	893	$	542	$	99	$	14	$	72	$	789	$	2,709	Cash and cash equivalents	$	163	$	335	$	132	$	40	$	75	$	60	$	363	$	264	$	1,432

Credit facilities(1)		3,500		1,200		1,509		650		204		848		3,450		11,361
Credit facilities																		Credit facilities	3,500		1,200		1,509		650		263		860		3,300		—		11,282
Less:	Less:																	Less:
Short-term debt	Short-term debt	—		—		—		(127)		(68)		(230)		(1,543)		(1,968)		Short-term debt	(110)		—		—		(161)		—		(375)		(1,203)		—		(1,849)
Tax-exempt bond support and letters of credit	Tax-exempt bond support and letters of credit	—		(218)		(370)		—		—		(1)		—		(589)		Tax-exempt bond support and letters of credit	—		(218)		(370)		—		—		(1)		—		—		(589)
Net credit facilities	Net credit facilities	3,500		982		1,139		523		136		617		1,907		8,804		Net credit facilities	3,390		982		1,139		489		263		484		2,097		—		8,844

Total net liquidity		$	3,800	$	1,875	$	1,681	$	622	$	150	$	689	$	2,696	$	11,513
Total net liquidity(1)																		Total net liquidity(1)	$	3,553	$	1,317	$	1,271	$	529	$	338	$	544	$	2,460	$	264	$	10,276
Credit facilities:	Credit facilities:																	Credit facilities:
Maturity dates	Maturity dates	2024		2024		2022, 2024		2024		2023		2022, 2025		2022, 2026				Maturity dates	2024		2024		2022, 2024		2024		2024		2022, 2026		2022, 2023, 2026

(1) ~~Includes drawn uncommitted credit facilities totaling $1~~Excludes $100 million of available liquidity under a delayed draw term loan at ~~Northern Powergrid Holdings.~~Nevada Power.

Operating Activities

Net cash flows from operating activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ were ~~$7.0~~$2.2 billion and ~~$4.5~~$1.5 billion, respectively. The increase was primarily due to ~~$886 million of incremental net cash flows from operating activities at BHE GT&S, improved operating results,~~ changes in working ~~capital and favorable income tax cash flows.~~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 selected and assumptions ~~used~~made for each payment date.

Investing Activities

Net cash flows from investing activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ were ~~$(3.5)~~$(1.6) billion and ~~$(6.6)~~$(1.4) billion, respectively. The change was primarily due to ~~lower funding~~higher capital expenditures of ~~tax equity investments and the July 2021 receipt of $1.3 billion due to the termination of the Q-Pipe Purchase Agreement.~~$258 million. Refer to "Future Uses of Cash" for a discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the ~~nine-month~~three-month period ended ~~September 30, 2021~~March 31, 2022 was $(2.0) billion. Uses of cash totaled $4.0 billion and consisted mainly of preferred stock redemptions totaling $1.5 billion, repayments of subsidiary debt totaling $1.3 billion, repayments of BHE senior debt totaling $450 million, distributions to noncontrolling interests of $366 million and net repayments of short-term debt totaling $316$(310) million. Sources of cash totaled ~~$2.0 billion~~$405 million and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $715 million and consisted mainly of repayments of subsidiary debt totaling $193 million, net repayments of short-term debt totaling $165 million and distributions to noncontrolling interests of $117 million.

For a discussion of recent financing transactions, refer to Note 54 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Net cash flows from financing activities for the ~~nine-month~~three-month period ended ~~September 30, 2020~~March 31, 2021 was ~~$2.9 billion.~~$(191) million. Sources of cash totaled ~~$5.9 billion~~$409 million and consisted of net proceeds from ~~BHE senior debt issuances totaling $3.2 billion and proceeds from subsidiary debt issuances totaling $2.6 billion.~~short-term debt. Uses of cash totaled ~~$2.9 billion~~$600 million and consisted mainly of repayments of ~~subsidiary debt totaling $1.6 billion, net repayments of short-term debt totaling $815 million, repayments of~~ BHE senior debt totaling ~~$350~~$450 million, distributions to noncontrolling interests of $115 million and ~~common stock repurchases~~repayments of subsidiary debt totaling ~~$126 million.~~

~~Debt Repurchases~~

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

~~Preferred Stock Redemptions~~

~~Common Stock Transactions~~

~~For the nine-month period ended September 30, 2020, BHE repurchased 180,358 shares of its common stock for $126~~$26 million.

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.~~

3933

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


		Nine-Month Periods				Annual			Three-Month Periods				Annual
		Ended September 30,				Forecast			Ended March 31,				Forecast
		2020		2021		2021			2021		2022		2022
Capital expenditures by business:	Capital expenditures by business:							Capital expenditures by business:
PacifiCorp	PacifiCorp	$	1,618	$	1,157	$	1,558	PacifiCorp	$	439	$	374	$	2,359
MidAmerican Funding	MidAmerican Funding	1,341		1,266		1,943		MidAmerican Funding	298		459		2,013
NV Energy	NV Energy	509		519		829		NV Energy	167		272		1,282
Northern Powergrid	Northern Powergrid	492		564		748		Northern Powergrid	179		169		652
BHE Pipeline Group	BHE Pipeline Group	428		684		1,262		BHE Pipeline Group	102		205		1,243
BHE Transmission	BHE Transmission	276		234		268		BHE Transmission	77		47		191
BHE Renewables	BHE Renewables	46		129		166		BHE Renewables	18		19		184
HomeServices	HomeServices	21		29		42		HomeServices	8		12		60
BHE and Other(1)	BHE and Other(1)	(124)		12		27		BHE and Other(1)	7		(4)		13
Total	Total	$	4,607	$	4,594	$	6,843	Total	$	1,295	$	1,553	$	7,997


Capital expenditures by type:	Capital expenditures by type:							Capital expenditures by type:
Wind generation	Wind generation	$	1,388	$	872	$	1,122	Wind generation	$	97	$	155	$	990
Electric distribution	Electric distribution	1,182		1,217		1,745		Electric distribution	427		392		1,737
Electric transmission	Electric transmission	745		539		845		Electric transmission	157		258		1,820
Natural gas transmission and storage	Natural gas transmission and storage	385		647		1,097		Natural gas transmission and storage	85		103		982
Solar generation	Solar generation	2		104		218		Solar generation	4		51		220
Other	Other	905		1,215		1,816		Other	525		594		2,248
Total	Total	$	4,607	$	4,594	$	6,843	Total	$	1,295	$	1,553	$	7,997

(1)BHE and Other represents amounts related principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.

The Company's historical and forecast capital expenditures consisted mainly of the following:

•Wind generation includes both growth and operating expenditures. Growth expenditures include spending for the following:

◦Construction ~~and acquisition~~ of wind-powered generating facilities at MidAmerican Energy totaling ~~$275 million and $676~~$3 million for the ~~nine-month periods~~three-month period ended ~~September 30, 2021 and 2020, respectively.~~March 31, 2022. Planned spending for the construction of additional wind-powered generating facilities totals ~~$73~~$142 million for the remainder of ~~2021 and includes 203 MWs of wind-powered generating facilities expected to be placed in-service in 2021.~~2022.

◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling ~~$274~~$120 million and ~~$25~~$24 million for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ respectively. Planned spending for the repowering of wind-powered generating facilities totals ~~$101~~$386 million for the remainder of ~~2021.~~2022. 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 ~~892~~812 MWs of current repowering projects not in-service as of ~~September 30, 2021, 591~~March 31, 2022, 511 MWs are currently expected to qualify for 80% of the PTCs available for 10 years following each facility's return to service and 301 MWs are expected to qualify for 60% of such credits.

◦Construction of wind-powered generating facilities at PacifiCorp totaling ~~$99~~$3 million and ~~$705~~$27 million for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ respectively. Construction includes ~~674~~516 MWs of new wind-powered generating facilities that were placed in-service in ~~2020 and 516 MWs that were placed in service in~~2021. Planned spending for the ~~first nine months~~construction of ~~2021.~~additional wind-powered generating facilities totals $109 million for the remainder of 2022. The energy production ~~for these~~from the new wind-powered generating facilities placed in-service by the end of 2024 is expected to qualify for ~~100%~~60% of the federal PTCs available for 10 years once the equipment is placed in-service. ~~Similar to PacifiCorp's 2019 IRP, the 2021 IRP identified over 1,800 MWs~~

◦Planned acquisition and repowering of ~~new~~two wind-powered generating ~~resources that~~facilities by PacifiCorp totaling $3 million and $1 million for the three-month periods ended March 31, 2022 and 2021, respectively. The repowered facilities are expected to ~~come online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will~~ be ~~a mixture of owned~~placed in-service in 2023 and ~~contracted resources.~~2024. Planned spending for ~~the construction of additional wind-powered~~acquiring and repowering generating facilities totals ~~$17~~$18 million for the remainder of ~~2021.~~2022.

◦Repowering of wind-powered generating facilities at ~~PacifiCorp~~BHE Renewables totaling ~~$9 million and $99~~$25 million for the ~~nine-month periods~~three-month period ended September 30, 2021 and 2020, respectively. Certain repowering projects for existing facilities were placed in service in 2019, 2020 and in the first nine 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.March 31, 2022. Planned spending for ~~the~~ repowering ~~of wind-powered~~ generating facilities totals $7$64 million for the remainder of ~~2021.~~

◦Construction of wind-powered generating facilities at BHE Renewables totaling $75 million for the nine-month period ended September 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 $10 million in 2021.2022.

•Electric distribution includes both growth and operating expenditures. Growth expenditures include spending for new customer connections and enhancements to existing customer connections. Operating expenditures include spending for ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, wildfire mitigation, storm damage restoration and 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 spending for the following:

◦PacifiCorp's ~~140-mile~~transmission investment primarily reflects planned costs for the 416-mile, 500-kV ~~Aeolus-Bridger/Anticline~~high-voltage transmission line ~~which is a major segment of PacifiCorp's~~between the Aeolus substation near Medicine Bow in Wyoming and the Clover substation near Mona, Utah; the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation; and the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho. Expenditures for these segments totaled $95 million and $16 million for the three-month periods ended March 31, 2022 and 2021, respectively. Planned spending for these Energy Gateway Transmission ~~expansion program,~~segments to be placed in-service in ~~November 2020,~~2024-2026 totals $814 million for the remainder of 2022.

◦Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has received approval from the PUCN 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; 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 Robinson Summit substations. Expenditures for the expansion program and ~~AltaLink's directly assigned~~other growth projects ~~from~~totaled $30 million and $19 million for the ~~Alberta Electric System Operator.~~ three-month periods ended March 31, 2022 and 2021, respectively. Planned spending for the expansion program estimated to be placed in-service in 2026-2028 and other growth projects totals $166 million for the remainder of 2022.

◦Operating expenditures include spending for 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, spending for the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, spending for 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~~spending for the ~~construction~~following:

◦Construction of solar-powered generating facilities at MidAmerican Energy totaling 141 MWs of small- and utility-scale solar generation, ~~during~~with total spend of $44 million and $3 million for the three-month periods ended March 31, 2022 and 2021, respectively and planned spending of ~~which 61 MWs are expected to be placed in-service in 2021.~~$96 million for the remainder of 2022.

◦Construction of a solar-powered generating facility at Nevada ~~Power's solar generation investment~~Power totaling $7 million for the three-month period ended March 31, 2022 and planned spending of $74 million for the remainder of 2022. Construction includes expenditures for a ~~150 MWs~~150-MW 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 ~~at Dry Lake~~ is expected by the end of 2023.

•Other capital expenditures includes both growth and operating expenditures, including spending for 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.

4135

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 ~~nine-month~~three-month period ended ~~September 30, 2021,~~March 31, 2022, and has commitments as of ~~September 30, 2021,~~March 31, 2022, subject to satisfaction of certain specified conditions, to provide equity contributions of ~~$766~~$356 million for the remainder of ~~2021 and $414 million in~~ 2022 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. However, the Company expects to assign its rights and obligations under these equity capital contribution agreements, including any related funding commitments, to an entity affiliated through common ownership. 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~~Material Cash Requirements

As of ~~September 30, 2021,~~March 31, 2022, there have been no material changes outside the normal course of business in ~~contractual obligations~~material cash requirements from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, ~~2020~~2021 other than the recent financing transactions ~~and renewable tax equity investments~~ previously discussed.

Quad Cities Generating Station Operating Status

Constellation Energy Corp. ("Constellation Energy," previously Exelon Generation Company, LLC, ("which was a subsidiary of Exelon ~~Generation")~~Corporation prior to February 1, 2022), 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")~~ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide ~~Exelon Generation~~Constellation Energy 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 state 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 expanded the breadth and scope of the PJM's MOPR, which became effective as of the PJM's capacity auction for the 2022-2023 planning year in May 2021. 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. A number of parties, including ~~Exelon,~~Constellation Energy, have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the D.C. Circuit.

As a result, the MOPR applied to Quad Cities Station in the capacity auction for the 2022-2023 planning year, which prevented Quad Cities Station from clearing in that capacity auction.

At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. The PJM filed related tariff revisions at the FERC on July 30, 2021, and, on September 29, 2021, the PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR will no longer apply to Quad Cities Station. ~~A request~~Requests for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms ~~was~~were filed onin October 5, 2021 and ~~remains pending.~~denied by operation of law on November 4, 2021. Several parties have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Third Circuit. Constellation Energy is strenuously opposing these appeals.

Assuming the continued effectiveness of the Illinois zero emission standard, ~~Exelon Generation~~Constellation Energy 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.

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~~2021 and new regulatory matters occurring in ~~2021.~~2022.

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 would result 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 with actual PTCs and net power cost savings to be trued-up in the Energy Balancing Account. A hearing has been scheduled beginning November 2021.

In August 2021, PacifiCorp filed an application with the UPSC for approval of its Electric Vehicle Infrastructure Program, as provided for by Utah House Bill 396 ("HB 396"), Electric Vehicle Charging Infrastructure Amendments. The filing details how PacifiCorp proposes to invest the $50 million authorized by HB 396 to support the development of electric vehicle infrastructure in Utah. The application also requests approval of a surcharge to collect $5 million per year for 10 years. The proposed surcharge would replace the existing Sustainable Transportation and Energy Plan cost adjustment that will expire on December 31, 2021. PacifiCorp's request would result in a decrease of $5 million, or 0.2%, compared to current rates effective January 1, 2022.

Oregon

In ~~February 2020,~~March 2022, PacifiCorp filed a general rate case ~~and in December 2020, the OPUC approved a net~~requesting an overall rate ~~decrease~~change of ~~approximately $24~~$82 million, or ~~1.8%~~6.6%, ~~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 investments in rates concurrent with when they were 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, a deferral for resources not placed in service by June 30, 2021 was filed for consideration in a future rate proceeding.

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 requests 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~~2023. A hearing in 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~~will be held 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 writtenSeptember 2022 with an order expected 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. In September 2021, the WPSC approved PacifiCorp's application to defer depreciation expense incurred from January 1, 2021 through June 30, 2021, subject to certain offsetting cost savings during the relevant period. The WPSC will address recovery of the deferred costs in a future general rate case.2022.

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 REC 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 requested an interim rate effective July 1, 2021, which was approved by the WPSC in June 2021. PacifiCorp filed an all-party stipulation in October 2021. A hearing on the stipulation was held in November 2021.

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. In November 2021, PacifiCorp reached a proposed settlement with most of the parties, which includes an agreement to adjust the PTC rate in base rates and apply a production factor and to include a net power cost update as part of the compliance filing. A hearing was held in ~~this matter is scheduled for~~ January 2022 and the WUTC issued an order approving the settlement in March 2022. A compliance filing, reflecting a $43 million, or 12.2%, increase was filed in April 2022 with rates ~~becoming~~ effective ~~after an order is issued.~~

~~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, the Pryor Mountain wind-powered generating facility, repowered 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. PacifiCorp filed an all-party settlement with the IPUC in October 2021, resolving all issues in the case. The settlement provides an $8 million, or 2.9%, overall increase, which will be offset in part by a refund of deferred income tax savings over two years, resulting in a net increase of $4 million, or 1.4%. A hearing on the settlement has been scheduled for November 2021 for rates to be effective January 1, 2022.

~~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 for which it received approval in July 2021.

In August 2020, PacifiCorp filed an application with the CPUC to address California energy costs and GHG allowance costs. The application includes a $7 million, or 6.7% decrease in energy costs, which is largely attributed to PTCs for new and repowered Energy Vision 2020 resources, and an increase of $1 million, or 0.8%, to recover costs for purchasing GHG allowances as required by the state's Cap-and-Trade program. In March 2021, the CPUC approved the rate change related to GHG allowances and in November 2021, approved updated rates for energy costs as filed.

In August 2021, PacifiCorp filed an application with the CPUC to address California energy costs and GHG allowance costs. The application includes a $5 million rate decrease associated with lower energy costs, partially offset by an increase of $3 million to recover costs for purchasing GHG allowances as required by the state's Cap-and-Trade program. PacifiCorp's application would result in a rate decrease of $2 million, or 1.9%, effective January 1, 2022. As of November 2021, the CPUC has not set a procedural schedule for this application.

~~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 Office of Enforcement staff replied in September 2021. A decision by the FERC is pending.

~~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 nine-month period ended September 30, 2021.

~~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. In July 2021, a hearing was held regarding the recovery of the 2020 costs held in a regulatory asset account and the cost recovery mechanism. In September 2021, the PUCN issued an order, approving the recovery of the 2020 costs with adjustments for vegetation management, inspections and corrections and rate structure. Certain vegetation management costs were to be removed from the NDPP rate and deemed to be recovered through the general three-year regulatory rate review process. A portion of the inspections and corrections were deferred to seek recovery in a future NDPP rate filing. Lastly, the order approved cost recovery based on a hybrid rate calculation comprised of a statewide rate for operating costs and a service territory specific rate for capital costs. In September 2021, the Nevada Utilities and one of the intervening parties filed petitions for reconsideration that were granted by the PUCN. The PUCN will reexamine the record and issue a modified order or reaffirm its original order with the outcome expected in the fourth quarter of 2021.

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. In September 2021, the Nevada Utilities filed an application for the approval of their Economic Recovery Transportation Electrification Plan to accelerate transportation electrification inwithin the state of Nevada. In ~~addition,~~September 2021, the Nevada Utilities filed an amendment to the 2021 Joint IRP for the approval of their Transmission Infrastructure for a Clean Energy Economy Plan that sets forth a plan for the construction of ~~certain~~ high-voltage transmission ~~infrastructure.~~infrastructure, Greenlink North among others, that will be placed into service no later than December 31, 2028, and requires the IRP to include at least one scenario that uses sources of supply that will achieve certain reductions in carbon dioxide emissions. In September 2021, the Nevada Utilities filed an application for the approval of their Economic Recovery Transportation Electrification Plan to accelerate transportation electrification in the state of Nevada. The plan establishes requirements for the contents of the transportation electrification investment as well as requirements for review, cost recovery and monitoring. The plan covers an initial period beginning January 1, 2022 and ending on December 31, 2024. In November 2021, the PUCN issued an order granting the application and accepting the Economic Recovery Transportation Electrification Plan with some modifications. The PUCN opened rulemakings to address ~~the~~other regulations inthat resulted from SB 448. In February 2022, the PUCN adopted regulations regarding the Economic Development Electric Rate Rider Program to revise the discounted electric rates to ease the economic burden on small businesses who take advantage of the discounted rates under the tariff. The remaining two SB 448 rulemakings are ongoing.

ON Line Temporary Rider ("ONTR")

In October 2021, Sierra Pacific filed an application with the PUCN for approval of the ONTR ~~and~~with corresponding updates to its electric rate tariffs to authorize recovery of the One Nevada Transmission Line ("ON Line") regulatory asset being accumulated as a result of the ON Line cost reallocation ~~and~~as well as the related on-going reallocated revenue requirement. Sierra Pacific's application would have, if approved by the PUCN as filed, ~~result~~resulted in a one-time rate increase of $28 million to be collected over a nine-month period starting on April 1, 2022. In March 2022, the PUCN issued an order directing Sierra Pacific to recover $14 million of the ON Line regulatory asset as a one-time rate increase collectable over a nine-month period effective April 1, 2022, with the expected remaining balance at December 31, 2022 to be included in rate base in the 2022 regulatory rate review for inclusion in the rates set in that case.

Merger Application

~~Northern Powergrid Distribution Companies~~

In ~~December 2020, GEMA, through Ofgem, published its final determinations for transmission and gas distribution networks in Great Britain. Regarding~~March 2022, the ~~allowed return on capital, Ofgem determined~~Nevada Utilities filed 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 appealsjoint application with the ~~Competition~~PUCN for authorization to merge Sierra Pacific with and ~~Markets Authority against Ofgem's determination for~~into Nevada Power, with Nevada Power being the ~~cost of equity. In August 2021,~~surviving entity. If approved by the ~~Competition~~PUCN as filed, Nevada Power will have two distinct electric service territories in northern and ~~Markets Authority published a provisional determination that proposed to uphold the 4.55% cost of equity, which was confirmed in~~southern Nevada each with their final determination 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,~~own rates and ~~prices from April 2023 to March 2028. This confirmed that Ofgem will apply many aspects of the proposals from the transmission and~~one natural 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 differencesservice territory in the ~~assumed equity ratio~~Reno and ~~the measure of inflation used, the working assumption for ED2~~Sparks area. An order 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.2022.

BHE Pipeline Group

BHE GT&S

In September 2021, ~~Eastern Gas Transmission and Storage, Inc. ("EGTS")~~EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS' previous general rate case was settled in 1998. EGTS proposed an annual cost-of-service of approximately $1.1 billion, and requested increases in various rates, including general system storage rates by 85% and general system transportation rates by 60%. In October 2021, the FERC issued an order that accepted the November 1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund and the outcome of hearing procedures. This matter is pending.

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.

BHE Transmission

AltaLink

~~Tariff Refund Application~~

In January 2021, driven by the pandemic and economic shutdown that 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 consisted 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 provided Alberta customers with immediate tariff relief in 2021. The approved 2021 tariff refund included 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 brought to bear an unprecedented need for rate relief that has not existed previously. These exceptional circumstances included 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.

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~~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.

In September 2021, AltaLink provided responses to information requests from the AUC and filed an amended application to reflect certain adjustments and forecast updates. The amended application requested the approval of transmission tariffs of C$820 million and C$843 million for 2022 and 2023, respectively. ~~Oral argument and reply argument were completed in a hearing in October 2021. A decision from~~In November 2021, the AUC ~~is expected in~~approved the 2022 interim refundable transmission tariff at C$57 million per month effective January 2022.

In January 2022, the AUC issued its decision with respect to AltaLink's 2022-2023 GTA. The AUC approved a two-year total revenue requirement of C$1.7 billion as compared to AltaLink's requested revenue requirement of C$1.8 billion. AltaLink's 2022-2023 GTA reflected its continued commitment to provide rate stability to customers by maintaining flat tariffs and providing additional tariff relief measures, including a proposed tariff refund of C$60 million of accumulated depreciation in each of 2022 and 2023. The AUC did not approve AltaLink's proposed refund due to an anticipated improvement in general economic conditions in Alberta.

In March 2022, AltaLink filed a review and variance application with the AUC. The application requested the AUC to review and vary its decision to deny AltaLink's proposed C$120 million refund of accumulated depreciation surplus, given material changes in circumstances since the decision was issued in January 2022. The existing pressures on Albertans and Alberta businesses that resulted from the COVID-19 pandemic have been compounded by cost increases due to higher inflation and global supply chain disruptions.

2023 Generic Cost of Capital Proceeding

In ~~December 2020,~~January 2022, the AUC initiated the ~~2022~~2023 generic cost of capital proceeding. ~~This~~The proceeding ~~considered~~will be conducted in two stages. The first stage will determine the ~~return on equity~~cost of capital parameters for 2023 and ~~deemed equity ratios for 2022 and one or more additional test years. Due~~the second stage will consider returning 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 was insufficient time to complete a full genericestablish cost of capital ~~proceeding~~adjustments, commencing 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.

2024. In March ~~2021,~~2022, 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~~first stage of ~~8.5% and an equity ratio~~the 2023 GCOC proceeding by approving the extension of ~~37% for~~the 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 Alberta Court of Appeal requesting permission to appeal the AUC's decision that set the~~ return on equity of 8.5% and deemed equity ratio of 37% ~~on a final basis~~ for ~~2022. In~~2023, recognizing lingering uncertainty and continued volatility of financial markets due to the ~~appeal,~~COVID-19 pandemic. With respect to the ~~Utilities Consumer Advocate alleged that~~second stage, the AUC ~~erred by failing~~plans to ~~fulfill its statutory obligation~~commence the 2024 GCOC proceeding to establish a formula-based approach in the third quarter of ~~establishing a fair return~~2022 and ~~by failing~~ to ~~apply procedural fairness. The Utilities Consumer Advocate additionally filed an application with~~conclude in the ~~AUC for review and variance~~second quarter of ~~the AUC's decision. The basis for the application was the same as the permission to appeal filed with the Alberta Court of Appeal.~~

In August 2021, the AUC denied the Utilities Consumer Advocate's application for review and variance of its decision that extended the approved 2020 and 2021 return on equity of 8.5% and equity ratio of 37% to 2022. In September 2021, the Alberta Court of Appeal heard the Utilities Consumer Advocate's permission to appeal application. In October 2021, the Alberta Court of Appeal issued its judgement dismissing the Utilities Consumer Advocate's application for leave to appeal the AUC decision setting final rates for 2022.

~~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.2023.

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,~~2021, 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.

•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 and generator of electricity in Washington.2022.

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. The 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. 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. The rule was immediately challenged by environmental and tribal groups, as wells as numerous states. In January 2021, the D.C. Circuit lifted an administrative stay and allowed the rule to take effect, finding that groups challenging the rule had not met the standard for a long-term stay. On June 30, 2021, President Biden signed into law a joint resolution of Congress, adopted under the Congressional Review Act, disapproving the August 2020 rule. The resolution has the effect of reinstating the 2012 volatile organic compounds standards and the 2016 volatile organic compounds and methane standards for the oil and natural gas transmission and storage segments, as well as the methane standards for the production and processing segments of the oil and gas sector. On November 2, 2021, the EPA released proposed rules in response to Executive Order 13990. The November 2021 proposed rule would reduce methane emissions from both new and existing sources in the oil and natural gas industry. The proposal would expand and strengthen emissions reduction requirements for new, modified and reconstructed oil and natural gas sources, and would require states to reduce methane emissions from existing sources nationwide. The EPA intends to issue a supplemental proposal in 2022 and to finalize the rule by the end of 2022. Until the rule is finalized, the relevant Registrants cannot determine the full impacts of the proposed rule.

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,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 SO~~2. 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 or the Nevada Utilities' generating facilities, the EPA's assessment of SO2 ~~area designations will continue with the deployment of additional SO~~2 ~~monitoring networks across the country. On February 25, 2019, the EPA issued a decision to retain the 2010 SO~~2 ~~NAAQS without revision.~~

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~~The Sierra Club filed a lawsuit against~~On June 4, 2018, the EPA ~~in August 2013 with respect~~published final ozone designations for much of the U.S. Relevant to the ~~one-hour SO~~2 ~~standards~~Registrants, these designations include classifying Yuma County, Arizona; Clark County, Nevada; and ~~its failure~~the Northern Wasatch Front, Southern Wasatch Front and Duchesne and Uintah counties in Utah as nonattainment-marginal with the 2015 ozone standard. These areas were required to ~~make certain attainment designations in a timely manner. In March~~meet the 2015 standard three years from the ~~United States District Court~~August 3, 2018, effective date. All other areas relevant to the Registrants were designated attainment/unclassifiable with this same action. However, on January 29, 2021, the D.C. Circuit vacated several provisions of the 2018 implementing rules for the ~~Northern District~~2015 ozone standards for contravening the Clean Air Act. The EPA and environmental groups finalized a consent decree in January 2022 that sets deadlines for the agency to approve or disapprove the "good neighbor" provisions of ~~California ("Northern District~~interstate ozone plans of ~~California") accepted as an enforceable order an agreement between~~dozens of states. Relevant to the Registrants, the EPA must, by April 30, 2022, propose to approve or disapprove the interstate ozone SIPs of Alabama, Iowa, Maryland, Michigan, Minnesota, New York, Ohio, Pennsylvania, Texas, West Virginia and ~~Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed~~Wisconsin. On February 22, 2022, the EPA published a series of proposed decisions to ~~complete designations in three phases:~~disapprove the ~~first phase by July 2, 2016;~~SIPs for interstate ozone transport of 19 states. Relevant to the ~~second phase~~Registrants, these states include Alabama, Maryland, Michigan, Minnesota, New York, Ohio, West Virginia and Wisconsin. The EPA also proposed to approve Iowa's SIP after re-analyzing the state's data. The EPA must finalize the proposed rules by December ~~31, 2017; and~~15, 2022. In addition, the ~~final phase~~EPA must, by December ~~31, 2020. The first phase~~15, 2022, approve or disapprove the interstate plans of ~~the designations require the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2010 SO~~2 ~~standard;~~Arizona, California, Nevada and ~~2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of SO~~2 ~~in 2012 or emitted more than 2,600 tons of SO~~2 ~~and had an emission rate of at least 0.45 lbs/SO~~2 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/SO~~2 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 inWyoming. On 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,~~15, 2022, the EPA issued ~~the last of~~ its final ~~designations~~rule approving Iowa's SIP as meeting the good neighbor provisions for the ~~2010 primary~~ SO22015 ozone standard. ~~Included~~Until the EPA takes final action consistent with this decree, additional impacts to the relevant Registrants cannot be determined.

Separately, on March 28, 2022, the EPA proposed determinations as to whether certain areas have achieved levels of ground-level ozone pollution that meet the 2008 and 2015 ozone NAAQS, respectively. Relevant to the Registrants, the Southern Wasatch Front in ~~this round was designation~~Utah and Yuma, Arizona are proposed to have met the 2015 ozone standard; and the Cincinnati area of ~~Converse County, Wyoming~~Ohio and Kentucky and the Northern Wasatch Front in Utah are proposed to have not met the 2015 ozone, will be reclassified as ~~an Attainment/Unclassifiable area. PacifiCorp's Dave Johnston generating facility is located in Converse County. No further~~Moderate Non-Attainment, and will have until August 3, 2024 to meet the standard. Until the EPA takes final action ~~by PacifiCorp is required.~~on the proposal and the affected states submit any required SIPs, the relevant Registrants cannot determine the impacts of the proposed rule.

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,~~U.S., 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.

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, the EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update Rule for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. The 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~~U.S. 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,~~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~~generating facilities in 12 states in the CSAPR trading program in response to the D.C. Circuit's decision to vacate the CSAPR Update ~~rule.~~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~~generating facilities 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 Rule largely as proposed. Significant new compliance obligations are not anticipated as a result of the rule. In June 2021, a new lawsuit was filed that challenges the Revised CSAPR Update Rule. Litigation is ongoing in the D.C. Circuit Court. Until litigation is exhausted, the relevant Registrants cannot determine whether additional action may be required.

In March 2022, the EPA released its Good Neighbor Rule, which contains proposed revisions to the CSAPR framework and is intended to address ozone transport for the 2015 ozone NAAQS. The rule focuses on reductions of NOx, precursors to ozone formation and covers 26 states. Relevant to the Registrants, four states are included in the cross-state program for the first time - California, Nevada, Utah and Wyoming. Iowa is not included in the proposal. In a separate but related action in February 2022, the EPA proposed to approve the good neighbor provisions of Iowa's SIP addressing ozone transport and the 2015 ozone standard. The EPA proposes to retain emissions allowance trading for generating facilities. Beginning in 2023, emissions budgets would be set at the level of reductions achievable through immediately available measures such as consistently operating existing emissions controls. Starting in 2026, emissions budgets would be set at levels achievable by the installation of SCR controls at certain generating facilities. The proposal also includes additional industries beyond the power sector for the first time, with a focus on the top NOx emitting stationary source categories. These include natural gas pipeline compressor stations, pulp and paper mills, cement production, iron and steel boilers and furnaces, glass furnaces, chemical manufacturing and petroleum and coal product manufacturing. These sources will not have access to trading and will instead be subject to rate-based limits that are assigned for each source category. The EPA is accepting comments on the proposal through June 6, 2022. Until the EPA takes final action consistent with this decree, impacts to the relevant Registrants cannot be determined.

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 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 equipment at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. The EPA's final action on the Utah regional haze SIP was effective 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 equipment at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions dispersion model. 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 generating facility enforceable under the SIP and removes the requirement to install SCR equipment 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 generating facility federally enforceable and adopts as BART the existing NOx controls and emission limits on the Hunter and Huntington generating facilities. The proposed approval withdraws the FIP requirements to install SCR equipment 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 generating facilities. 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. After review of the rule by the Biden administration, the EPA determined it would defend the rule, and briefing in the case is ongoing. A date for oral arguments has not been scheduled. The Utah Air Quality Board approved the Utah Division of Air Quality's SIP for the regional haze second planning period on April 6, 2022. The public comment period is anticipated to begin in early May 2022. The proposed plan sets mass-based emissions limits for PacifiCorp's Hunter and Huntington generating facilities to ensure reasonable visibility progress for the second planning period. The division proposes to add existing SO2 emission limits for all five Hunter and Huntington units as enforceable regional haze controls. The division also proposes new enforceable mass-based NOx emission limits for both generating facilities based on actual emissions. The state is on track to submit a final implementation plan to the EPA by July 2022.

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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, ~~United States~~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.

The ~~state~~EPA did not proceed with final approval of ~~Utah issued~~the settlement agreement for Wyodak and is currently engaged with Wyoming and PacifiCorp concerning alternative paths for resolution. On February 5, 2019, PacifiCorp submitted a ~~regional haze SIP~~reasonable progress reassessment permit application and reasonable progress determination for Jim Bridger Units 1 and 2, seeking a rescission of the December 2017 permit requiring the installation of SO2,SCR, to be replaced with a permit imposing plant-wide emission limits to achieve better modeled visibility, fewer overall environmental impacts and lower costs of compliance. In May 2020, the Wyoming Air Quality Division issued a permit approving PacifiCorp's monthly and annual NOx and ~~particulate matter~~SO2 emission limits on the four Jim Bridger units and submitted a regional haze SIP revision to the EPA. The revised SIP would grant approval of PacifiCorp's Jim Bridger reasonable progress reassessment application and incorporates PacifiCorp's proposed emission limits in lieu of the requirement to install SCR systems on Jim Bridger Units 1 and 2. On December 27, 2021, Wyoming's governor issued an emergency suspension order under Section 110(g) of the Clean Air Act, allowing the operation of Jim Bridger Unit 2 through April 30, 2022, while the state, the EPA and PacifiCorp continue settlement discussions. On January 18, 2022, the EPA proposed to reject the SIP revisions. The EPA took comment on the proposal through February 17, 2022. On February 14, 2022, the First Judicial District Court for the State of Wyoming entered a consent decree reached between the state of Wyoming and PacifiCorp under Sections 201 and 209(a) of the Wyoming Environmental Quality Act, resolving claims of threatened violations of the Clean Air Act, the Wyoming Environmental Quality Act and the Wyoming Air Quality Standards and Regulations at the Jim Bridger facility. No penalties were imposed under the consent decree. Consistent with the terms and conditions of the consent decree and as forecasted in PacifiCorp's 2021 IRP, PacifiCorp must convert both units to natural gas and begin meeting emissions limits consistent with that conversion by January 1, 2024. In addition, PacifiCorp must propose an RFP by January 1, 2023, for carbon capture technology at Jim Bridger Units 3 and 4. Wyoming issued its proposed implementation plan for second planning period reasonable progress on February 18, 2022 and accepted comments through March 23, 2022. Wyoming determined that no controls will be necessary on ~~Hunter~~any Wyoming resources to make reasonable progress for the second round of regional haze planning. It is estimated that the state will submit a final state-approved implementation plan to the EPA in May 2022.

In February 2022, NV Energy received 30-day notice letters from the Nevada Division of Environmental Protection regarding the reopening and revision of the Valmy and Tracy Generating Station's Title V air quality operating permits to add federally enforceable retirement dates of December 31, 2028 for Valmy Units 1 and 2 and ~~Huntington Units 1 and 2. In~~ December ~~2012,~~31, 2031 for Tracy Unit 4. The enforceable retirement dates will implement Nevada's SIP for the ~~EPA approved the SO~~2 ~~portion of the Utah~~ regional haze ~~SIP~~second planning period. The revised permits were received in March and ~~disapproved~~April 2022. It is anticipated that the NOx ~~and particulate matter portions. Subsequently, the Utah~~Nevada Division of ~~Air Quality completed an alternative BART analysis~~Environmental Protection will begin the public comment period for ~~Hunter Units 1~~its SIP by May 2022 and ~~2 and Huntington Units 1 and 2. In January 2016,~~submit the ~~EPA published two alternative proposals to either approve the Utah~~final SIP ~~as written or reject the Utah SIP relating to NO~~x controls and require the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. The EPA's final action on the Utah regional haze SIP was effective 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~~by 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.2022.

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~~Water Quality Standards~~

In April 2014, the EPA and the United States Army Corps of Engineers ("Corps of Engineers") issued a joint proposal to address "waters of the United States" to clarify protection under the Clean Water Act for streams and wetlands. The proposed rule came as a result of United States Supreme Court decisions in 2001 and 2006 that created confusion regarding jurisdictional waters that were subject to permitting under either nationwide or individual permitting requirements. The final rule was released in May 2015 but was appealed in multiple courts and a nationwide stay on the implementation of the rule was issued in October 2015. On January 13, 2017, the United States Supreme Court granted a petition to address jurisdictional challenges to the rule. On July 27, 2017, the EPA and the Corps of Engineers issued a proposal to repeal the final rule and recodify the pre-existing rules pending issuance of a new rule, which was finalized September 12, 2019. On January 22, 2018, the United States Supreme Court issued its decision related to the jurisdictional challenges to the rule, holding that federal district courts, rather than federal appeals courts, have proper jurisdiction to hear challenges to the rule and instructed the Sixth Circuit Court of Appeals to dismiss the petitions for review for lack of jurisdiction, clearing the way for imposition of the rule in certain states barring final action by the EPA to formalize the extension of the compliance deadline. On December 11, 2018, the EPA and the Corps of Engineers proposed a revised definition of "waters of the United States" that is intended to further clarify jurisdictional questions, eliminate case-by-case determinations and narrow Clean Water Act jurisdiction to align with Justice Scalia's 2006 opinion in ~~Rapanos v. United States~~. On January 23, 2020, the EPA and the Corps of Engineers signed the final rule narrowing the federal government's permitting authority under the Clean Water Act. The new Navigable Waters Protection Rule, redefines what waters qualify as navigable waters of the United States and are under Clean Water Act jurisdiction. Under the new rule, the Clean Water Act is considered to cover territorial seas and traditional navigable waters; tributaries that flow into jurisdictional waters; wetlands that are directly adjacent to jurisdictional waters; and lakes, ponds and impoundments of jurisdictional waters. On June 9, 2021, the EPA and the Corps of Engineers announced their intention to again revise the definition of "waters of the United States." After reviewing the Navigable Waters Protection Rule in accordance with Executive Order 13990, the agencies determined that the rule significantly reduced clean water protections. The agencies announced their intention to restore the clean water protections that were in place prior to the implementation of the "waters of the United States" rule in 2015. On August 30, 2021, the United States District Court for the District of Arizona vacated the Navigable Waters Protection Rule and the agencies quickly announced that they would no longer implement the rule nationwide. As a result, the agencies are relying on the pre-2015 regulatory definition of "waters of the United States" until they promulgate a new definition. Projects that are already permitted under the Navigable Waters Protection Rule and those that received an approved jurisdictional determination in reliance on the rule may continue to rely on those authorizations until they expire. Until the agencies take final action to update the definition of "waters of the United States," impacts to the relevant Registrants cannot be determined.

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.~~2021. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, ~~2020.~~2021.

5644

PacifiCorp and its subsidiaries

Consolidated Financial Section

5745

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PacifiCorp

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of ~~September 30, 2021,~~March 31, 2022, the related consolidated statements of operations, ~~and~~ changes in shareholders' equity, ~~for the three-month~~ and ~~nine-month periods ended September 30, 2021 and 2020, and of~~ cash flows for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 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,~~2021, 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,~~25, 2022, 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,~~2021, 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.

/s/ Deloitte & Touche LLP

Portland, Oregon

~~November 5, 2021~~April 29, 2022

5846

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


		As of					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	893	$	13	Cash and cash equivalents	$	335	$	179
Trade receivables, net	Trade receivables, net	732		703		Trade receivables, net	674		725
Other receivables, net	Other receivables, net	41		48		Other receivables, net	49		52
Inventories	Inventories	465		482		Inventories	479		474
Derivative contracts	Derivative contracts	153		27		Derivative contracts	145		76

Regulatory assets	Regulatory assets	70		116		Regulatory assets	125		65
Prepaid expenses		89		79

Other current assets	Other current assets	24		55		Other current assets	163		150
Total current assets	Total current assets	2,467		1,523		Total current assets	1,970		1,721

Property, plant and equipment, net	Property, plant and equipment, net	22,748		22,430		Property, plant and equipment, net	23,081		22,914
Regulatory assets	Regulatory assets	1,326		1,279		Regulatory assets	1,231		1,287
Other assets	Other assets	530		470		Other assets	562		534

Total assets	Total assets	$	27,071	$	25,702	Total assets	$	26,844	$	26,456

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

5947

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


		As of					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
LIABILITIES AND SHAREHOLDERS' EQUITY	LIABILITIES AND SHAREHOLDERS' EQUITY					LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	$	624	$	772	Accounts payable	$	724	$	680
Accrued interest	Accrued interest	115		127		Accrued interest	115		121
Accrued property, income and other taxes	Accrued property, income and other taxes	159		80		Accrued property, income and other taxes	113		78

Accrued employee expenses	Accrued employee expenses	117		84		Accrued employee expenses	109		89
Short-term debt		—		93

Current portion of long-term debt	Current portion of long-term debt	574		420		Current portion of long-term debt	155		155
Regulatory liabilities	Regulatory liabilities	112		115		Regulatory liabilities	114		118
Other current liabilities	Other current liabilities	241		174		Other current liabilities	196		219
Total current liabilities	Total current liabilities	1,942		1,865		Total current liabilities	1,526		1,460

Long-term debt	Long-term debt	8,625		8,192		Long-term debt	8,567		8,575
Regulatory liabilities	Regulatory liabilities	2,759		2,727		Regulatory liabilities	2,807		2,650
Deferred income taxes	Deferred income taxes	2,781		2,627		Deferred income taxes	2,886		2,847
Other long-term liabilities	Other long-term liabilities	1,064		1,118		Other long-term liabilities	1,014		1,011
Total liabilities	Total liabilities	17,171		16,529		Total liabilities	16,800		16,543

Commitments and contingencies (Note 9)		0		0
Commitments and contingencies (Note 8)						Commitments and contingencies (Note 8)	0		0

Shareholders' equity:	Shareholders' equity:					Shareholders' equity:
Preferred stock	Preferred stock	2		2		Preferred stock	2		2
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding	Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding	—		—		Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding	—		—
Additional paid-in capital	Additional paid-in capital	4,479		4,479		Additional paid-in capital	4,479		4,479
Retained earnings	Retained earnings	5,437		4,711		Retained earnings	5,579		5,449
Accumulated other comprehensive loss, net	Accumulated other comprehensive loss, net	(18)		(19)		Accumulated other comprehensive loss, net	(16)		(17)
Total shareholders' equity	Total shareholders' equity	9,900		9,173		Total shareholders' equity	10,044		9,913

Total liabilities and shareholders' equity	Total liabilities and shareholders' equity	$	27,071	$	25,702	Total liabilities and shareholders' equity	$	26,844	$	26,456

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

6048

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021

Operating revenue	Operating revenue	$	1,491	$	1,479	$	4,031	$	3,829	Operating revenue		$	1,297	$	1,242

Operating expenses:	Operating expenses:									Operating expenses:
Cost of fuel and energy	Cost of fuel and energy	505		499		1,370		1,299		Cost of fuel and energy		465		424
Operations and maintenance	Operations and maintenance	267		332		781		829		Operations and maintenance		277		259
Depreciation and amortization	Depreciation and amortization	272		234		811		696		Depreciation and amortization		280		264
Property and other taxes	Property and other taxes	54		53		158		154		Property and other taxes		59		61
Total operating expenses	Total operating expenses	1,098		1,118		3,120		2,978		Total operating expenses		1,081		1,008

Operating income	Operating income	393		361		911		851		Operating income		216		234

Other income (expense):	Other income (expense):									Other income (expense):
Interest expense	Interest expense	(110)		(107)		(322)		(319)		Interest expense		(106)		(107)
Allowance for borrowed funds	Allowance for borrowed funds	6		14		18		36		Allowance for borrowed funds		6		6
Allowance for equity funds	Allowance for equity funds	13		29		38		73		Allowance for equity funds		13		13
Interest and dividend income	Interest and dividend income	7		2		18		8		Interest and dividend income		7		6
Other, net	Other, net	(5)		5		5		9		Other, net		(4)		6
Total other income (expense)	Total other income (expense)	(89)		(57)		(243)		(193)		Total other income (expense)		(84)		(76)

Income before income tax (benefit) expense		304		304		668		658
Income tax (benefit) expense		(28)		18		(58)		30
Income before income tax expense (benefit)										Income before income tax expense (benefit)		132		158
Income tax expense (benefit)										Income tax expense (benefit)		2		(11)
Net income	Net income	$	332	$	286	$	726	$	628	Net income		$	130	$	169

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

6149

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)

(Amounts in millions)


										Accumulated													Accumulated
						Additional				Other		Total							Additional				Other		Total
		Preferred		Common		Paid-in		Retained		Comprehensive		Shareholders'			Preferred		Common		Paid-in		Retained		Comprehensive		Shareholders'
		Stock		Stock		Capital		Earnings		Loss, Net		Equity			Stock		Stock		Capital		Earnings		Loss, Net		Equity

Balance, June 30, 2020		$	2	$	—	$	4,479	$	4,314	$	(15)	$	8,780

Balance, December 31, 2020														Balance, December 31, 2020	$	2	$	—	$	4,479	$	4,711	$	(19)	$	9,173
Net income	Net income	—		—		—		286		—		286		Net income	—		—		—		169		—		169

Balance, September 30, 2020		$	2	$	—	$	4,479	$	4,600	$	(15)	$	9,066
Balance, March 31, 2021														Balance, March 31, 2021	$	2	$	—	$	4,479	$	4,880	$	(19)	$	9,342

Balance, December 31, 2019		$	2	$	—	$	4,479	$	3,972	$	(16)	$	8,437

Balance, December 31, 2021														Balance, December 31, 2021	$	2	$	—	$	4,479	$	5,449	$	(17)	$	9,913
Net income	Net income	—		—		—		628		—		628		Net income	—		—		—		130		—		130
Other comprehensive income	Other comprehensive income	—		—		—		—		1		1		Other comprehensive income	—		—		—		—		1		1

Balance, September 30, 2020		$	2	$	—	$	4,479	$	4,600	$	(15)	$	9,066

Balance, June 30, 2021		$	2	$	—	$	4,479	$	5,105	$	(19)	$	9,567
Net income		—		—		—		332		—		332
Other comprehensive income		—		—		—		—		1		1

Balance, September 30, 2021		$	2	$	—	$	4,479	$	5,437	$	(18)	$	9,900

Balance, December 31, 2020		$	2	$	—	$	4,479	$	4,711	$	(19)	$	9,173
Net income		—		—		—		726		—		726
Other comprehensive income		—		—		—		—		1		1

Balance, September 30, 2021		$	2	$	—	$	4,479	$	5,437	$	(18)	$	9,900
Balance, March 31, 2022														Balance, March 31, 2022	$	2	$	—	$	4,479	$	5,579	$	(16)	$	10,044

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

6250

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


		Nine-Month Periods					Three-Month Periods
		Ended September 30,					Ended March 31,
		2021		2020			2022		2021
Cash flows from operating activities:	Cash flows from operating activities:					Cash flows from operating activities:
Net income	Net income	$	726	$	628	Net income	$	130	$	169
Adjustments to reconcile net income to net cash flows from operating activities:	Adjustments to reconcile net income to net cash flows from operating activities:					Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	Depreciation and amortization	811		696		Depreciation and amortization	280		264
Allowance for equity funds	Allowance for equity funds	(38)		(73)		Allowance for equity funds	(13)		(13)
Changes in regulatory assets and liabilities	Changes in regulatory assets and liabilities	(185)		(17)		Changes in regulatory assets and liabilities	(9)		(4)
Deferred income taxes and amortization of investment tax credits	Deferred income taxes and amortization of investment tax credits	33		(48)		Deferred income taxes and amortization of investment tax credits	19		13
Other, net	Other, net	—		2		Other, net	4		(2)
Changes in other operating assets and liabilities:	Changes in other operating assets and liabilities:					Changes in other operating assets and liabilities:
Trade receivables, other receivables and other assets	Trade receivables, other receivables and other assets	(1)		(150)		Trade receivables, other receivables and other assets	59		61
Inventories	Inventories	17		(97)		Inventories	(5)		7
Derivative collateral, net	Derivative collateral, net	19		22		Derivative collateral, net	22		7
Prepaid expenses	Prepaid expenses	(11)		(4)		Prepaid expenses	—		6
Accrued property, income and other taxes, net	Accrued property, income and other taxes, net	96		84		Accrued property, income and other taxes, net	15		12
Accounts payable and other liabilities	Accounts payable and other liabilities	77		248		Accounts payable and other liabilities	35		(51)
Net cash flows from operating activities	Net cash flows from operating activities	1,544		1,291		Net cash flows from operating activities	537		469

Cash flows from investing activities:	Cash flows from investing activities:					Cash flows from investing activities:
Capital expenditures	Capital expenditures	(1,157)		(1,618)		Capital expenditures	(374)		(439)
Other, net	Other, net	7		31		Other, net	3		(1)
Net cash flows from investing activities	Net cash flows from investing activities	(1,150)		(1,587)		Net cash flows from investing activities	(371)		(440)

Cash flows from financing activities:	Cash flows from financing activities:					Cash flows from financing activities:
Proceeds from long-term debt		984		987

Repayments of long-term debt	Repayments of long-term debt	(400)		—		Repayments of long-term debt	(9)		—
Repayments of short-term debt		(93)		(130)
Net proceeds from short-term debt						Net proceeds from short-term debt	—		2

Other, net	Other, net	(5)		—		Other, net	(2)		(1)
Net cash flows from financing activities	Net cash flows from financing activities	486		857		Net cash flows from financing activities	(11)		1

Net change in cash and cash equivalents and restricted cash and cash equivalents	Net change in cash and cash equivalents and restricted cash and cash equivalents	880		561		Net change in cash and cash equivalents and restricted cash and cash equivalents	155		30
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	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 beginning of period	186		19
Cash and cash equivalents and restricted cash and cash equivalents at end of period	Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	899	$	597	Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	341	$	49

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

6351

PACIFICORP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

PacifiCorp, which includes PacifiCorp and its subsidiaries, is a ~~United States~~U.S. regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining services. PacifiCorp is an indirect subsidiary of Berkshire Hathaway Energy Company ("BHE"), a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of ~~September 30, 2021~~March 31, 2022 and for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020.~~2021. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020.~~2021. The results of operations for the ~~three- and nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 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~~2021 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in PacifiCorp's assumptions regarding significant accounting estimates and policies during the ~~nine-month~~three-month period ended ~~September 30, 2021.~~March 31, 2022.

(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, ~~United States~~U.S. 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 September 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					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
Cash and cash equivalents	Cash and cash equivalents	$	893	$	13	Cash and cash equivalents	$	335	$	179
Restricted cash included in other current assets		4		4
Restricted cash and cash equivalents included in other current assets						Restricted cash and cash equivalents included in other current assets	4		4
Restricted cash included in other assets	Restricted cash included in other assets	2		2		Restricted cash included in other assets	2		3
Total cash and cash equivalents and restricted cash and cash equivalents	Total cash and cash equivalents and restricted cash and cash equivalents	$	899	$	19	Total cash and cash equivalents and restricted cash and cash equivalents	$	341	$	186

6452

(3) Property, Plant and Equipment, Net

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


			As of						As of
			September 30,		December 31,				March 31,		December 31,
		Depreciable Life	2021		2020			Depreciable Life	2022		2021
Utility Plant:	Utility Plant:						Utility Plant:
Generation	Generation	15 - 59 years	$	13,635	$	12,861	Generation	15 - 59 years	$	13,688	$	13,679
Transmission	Transmission	60 - 90 years	7,833		7,632		Transmission	60 - 90 years	7,914		7,894
Distribution	Distribution	20 - 75 years	7,889		7,660		Distribution	20 - 75 years	8,125		8,044
Intangible plant(1)	Intangible plant(1)	5 - 75 years	1,083		1,054		Intangible plant(1)	5 - 75 years	1,112		1,106
Other	Other	5 - 60 years	1,535		1,510		Other	5 - 60 years	1,563		1,539
Utility plant in service			31,975		30,717
Utility plant in-service							Utility plant in-service		32,402		32,262
Accumulated depreciation and amortization	Accumulated depreciation and amortization		(10,370)		(9,838)		Accumulated depreciation and amortization		(10,704)		(10,507)
Utility plant in service, net			21,605		20,879
Utility plant in-service, net							Utility plant in-service, net		21,698		21,755
Other non-regulated, net of accumulated depreciation and amortization	Other non-regulated, net of accumulated depreciation and amortization	14 - 95 years	9		9		Other non-regulated, net of accumulated depreciation and amortization	14 - 95 years	18		18
Plant, net	Plant, net		21,614		20,888		Plant, net		21,716		21,773
Construction work-in-progress	Construction work-in-progress		1,134		1,542		Construction work-in-progress		1,365		1,141
Property, plant and equipment, net	Property, plant and equipment, net		$	22,748	$	22,430	Property, plant and equipment, net		$	23,081	$	22,914

(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 $38 million for the three-month period ended September 30, 2021 as compared to the three-month period ended September 30, 2020, and $120 million for the nine-month period ended September 30, 2021 compared to the nine-month period ended September 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~~

~~Common Shareholder's Equity~~

~~In October 2021, PacifiCorp declared a common stock dividend of $150 million, payable in November 2021, to PPW Holdings LLC.~~

~~(5)~~ Income Taxes

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


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021

Federal statutory income tax rate	Federal statutory income tax rate	21	%	21	%	21	%	21	%	Federal statutory income tax rate		21	%	21	%
State income tax, net of federal income tax benefit	State income tax, net of federal income tax benefit	4		3		4		3		State income tax, net of federal income tax benefit		3		3
Federal income tax credits	Federal income tax credits	(20)		(15)		(20)		(12)		Federal income tax credits		(20)		(20)
Effects of ratemaking(1)	Effects of ratemaking(1)	(13)		(4)		(14)		(8)		Effects of ratemaking(1)		(11)		(13)

Valuation allowance										Valuation allowance		6		—
Other	Other	(1)		1		—		1		Other		3		2
Effective income tax rate	Effective income tax rate	(9)	%	6	%	(9)	%	5	%	Effective income tax rate		2	%	(7)	%

(1)Effects of ratemaking is primarily attributable to activity associated with excess deferred income taxes.

Income tax credits relate primarily to production tax credits ("~~PTC"~~PTCs") earned by PacifiCorp's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the three-month periods ended March 31, 2022 and 2021 totaled $26 million and $31 million, respectively.

~~Effects of ratemaking for the three- and nine-month periods ended~~ ~~September 30,~~ 2021, and 2020 is primarily attributable to activity associated with excess deferred income taxes. Excess deferred income tax amortization, net of deferrals, was $89 million for the nine-month period ended September 30, 2021, including the use of $3 million to amortize certain regulatory asset balances in Wyoming, as compared to $41 million for the ~~nine-month period endedSeptember 30,~~ ~~2020, including the use of $30 million to accelerate depreciation of certain retired equipment in Oregon. Excess deferred income tax amortization, net of deferrals, was $41 million for~~For the three-month period ended ~~September 30,~~ ~~2021, as compared~~March 31, 2022 PacifiCorp recorded a valuation allowance related to ~~$6 million for the~~ ~~three-month period ended September 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 nine-month period ended September 30, ~~2021~~ ~~PacifiCorp received~~ net cash payments for federal and state income tax from BHE totaling $109 million. For the nine-month period ended September 30, 2020 PacifiCorp made net cash payments for federal and state income tax to BHE totaling $79 million.operating loss carryforwards.

6653

~~(6)~~(5) 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				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021
Pension:	Pension:									Pension:
Service cost	Service cost	$	—	$	—	$	—	$	—	Service cost		$	—	$	—
Interest cost	Interest cost	8		9		22		27		Interest cost		7		7
Expected return on plan assets	Expected return on plan assets	(12)		(14)		(39)		(42)		Expected return on plan assets		(10)		(13)
Settlement		4		—		4		—

Net amortization	Net amortization	5		4		15		13		Net amortization		4		5
Net periodic benefit cost (credit)	Net periodic benefit cost (credit)	$	5	$	(1)	$	2	$	(2)	Net periodic benefit cost (credit)		$	1	$	(1)

Other postretirement:	Other postretirement:									Other postretirement:
Service cost	Service cost	$	—	$	—	$	1	$	1	Service cost		$	—	$	—
Interest cost	Interest cost	1		2		5		7		Interest cost		2		2
Expected return on plan assets	Expected return on plan assets	(2)		(3)		(6)		(10)		Expected return on plan assets		(2)		(2)
Net amortization	Net amortization	1		—		1		—		Net amortization		—		—
Net periodic benefit (credit) cost		$	—	$	(1)	$	1	$	(2)
Net periodic benefit cost (credit)										Net periodic benefit cost (credit)		$	—	$	—

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.~~2022. As of ~~September 30, 2021, $3~~March 31, 2022, $1 million of contributions had been made to the pension plans.

The amount of lump sum pension distributions in 2021 resulted in a July 31, 2021 remeasurement of the pension plan assets and projected benefit obligation. As a result of the remeasurement, PacifiCorp recognized a settlement loss of $4 million, net of regulatory deferrals. Additionally, the pension plan's underfunded status and regulatory asset each decreased by $84 million.

~~(7)~~(6) Risk Management and Hedging Activities

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

PacifiCorp has established a risk management process that is designed to identify, assess, manage and report on 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, futures, 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 87 for additional information on derivative contracts.

The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):


		Other				Other		Other					Derivative
		Current		Other		Current		Long-term					Contracts -				Other		Other
		Assets		Assets		Liabilities		Liabilities		Total			Current		Other		Current		Long-term
As of September 30, 2021
													Assets		Assets		Liabilities		Liabilities		Total
As of March 31, 2022												As of March 31, 2022
Not designated as hedging contracts(1):	Not designated as hedging contracts(1):											Not designated as hedging contracts(1):
Commodity assets	Commodity assets	$	159	$	40	$	4	$	1	$	204	Commodity assets	$	165	$	37	$	6	$	(1)	$	207
Commodity liabilities	Commodity liabilities	—		—		(46)		(9)		(55)		Commodity liabilities	(3)		—		(9)		—		(12)
Total	Total	159		40		(42)		(8)		149		Total	162		37		(3)		(1)		195

Total derivatives	Total derivatives	159		40		(42)		(8)		149		Total derivatives	162		37		(3)		(1)		195
Cash collateral (payable) receivable		(6)		—		11		—		5
Cash collateral payable												Cash collateral payable	(17)		—		—		—		(17)
Total derivatives - net basis	Total derivatives - net basis	$	153	$	40	$	(31)	$	(8)	$	154	Total derivatives - net basis	$	145	$	37	$	(3)	$	(1)	$	178

As of December 31, 2020
As of December 31, 2021												As of December 31, 2021
Not designated as hedging contracts(1):	Not designated as hedging contracts(1):											Not designated as hedging contracts(1):
Commodity assets	Commodity assets	$	29	$	6	$	1	$	—	$	36	Commodity assets	$	81	$	21	$	2	$	—	$	104
Commodity liabilities	Commodity liabilities	(2)		—		(23)		(28)		(53)		Commodity liabilities	(5)		(1)		(38)		(7)		(51)
Total	Total	27		6		(22)		(28)		(17)		Total	76		20		(36)		(7)		53

Total derivatives	Total derivatives	27		6		(22)		(28)		(17)		Total derivatives	76		20		(36)		(7)		53
Cash collateral receivable	Cash collateral receivable	—		—		15		9		24		Cash collateral receivable	—		—		5		—		5
Total derivatives - net basis	Total derivatives - net basis	$	27	$	6	$	(7)	$	(19)	$	7	Total derivatives - net basis	$	76	$	20	$	(31)	$	(7)	$	58

(1)PacifiCorp's commodity derivatives are generally included in rates. As of ~~September 30, 2021~~March 31, 2022 a regulatory liability of ~~$149~~$195 million was recorded related to the net derivative asset of ~~$149~~$195 million. As of December 31, ~~2020~~2021 a regulatory ~~asset~~liability of ~~$17~~$53 million was recorded related to the net derivative ~~liability~~asset of ~~$17~~$53 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 Nine-Month Periods
Ended September 30, Ended September 30,
2021 2020 2021 2020
Beginning balance $ (102) $ 68 $ 17 $ 62
Changes in fair value (128) (49) (247) (21)
Net gains (losses) reclassified to operating revenue — 1 (5) 14
Net gains (losses) reclassified to cost of fuel and energy 81 (11) 86 (46)
Ending balance $ (149) $ 9 $ (149) $ 9


	Three-Month Periods
	Ended March 31,
		2022		2021

Beginning balance		$	(53)	$	17
Changes in fair value recognized in regulatory assets		(168)		(17)
Net losses reclassified to operating revenue		(3)		—
Net gains reclassified to energy costs		29		—
Ending balance		$	(195)	$	—

6855

Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):


		Unit of	September 30,	December 31,		Unit of	March 31,	December 31,
		Measure	2021	2020		Measure	2022	2021

Electricity sales, net		Megawatt hours	—	(1)
Electricity purchases, net					Electricity purchases, net	Megawatt hours	1	2
Natural gas purchases	Natural gas purchases	Decatherms	101	100	Natural gas purchases	Decatherms	105	106

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 ~~September 30, 2021,~~March 31, 2022, 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 ~~$54~~$10 million and ~~$51~~$37 million as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, respectively, for which PacifiCorp had posted collateral of ~~$11~~$— million and ~~$24~~$5 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, PacifiCorp would have been required to post ~~$36~~$2 million and ~~$25~~$23 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.

6956

~~(8)~~(7) 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 3 — Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including its own data.

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


		Input Levels for Fair Value Measurements											Input Levels for Fair Value Measurements
		Level 1		Level 2		Level 3		Other(1)		Total			Level 1		Level 2		Level 3		Other(1)		Total
As of September 30, 2021
As of March 31, 2022:												As of March 31, 2022:
Assets:	Assets:											Assets:
Commodity derivatives	Commodity derivatives	$	—	$	204	$	—	$	(11)	$	193	Commodity derivatives	$	—	$	207	$	—	$	(25)	$	182
Money market mutual funds	Money market mutual funds	876		—		—		—		876		Money market mutual funds	319		—		—		—		319
Investment funds	Investment funds	31		—		—		—		31		Investment funds	28		—		—		—		28
		$	907	$	204	$	—	$	(11)	$	1,100		$	347	$	207	$	—	$	(25)	$	529

Liabilities - Commodity derivatives	Liabilities - Commodity derivatives	$	—	$	(55)	$	—	$	16	$	(39)	Liabilities - Commodity derivatives	$	—	$	(12)	$	—	$	8	$	(4)

As of December 31, 2020
As of December 31, 2021:												As of December 31, 2021:
Assets:	Assets:											Assets:
Commodity derivatives	Commodity derivatives	$	—	$	36	$	—	$	(3)	$	33	Commodity derivatives	$	—	$	104	$	—	$	(8)	$	96
Money market mutual funds	Money market mutual funds	6		—		—		—		6		Money market mutual funds	181		—		—		—		181
Investment funds	Investment funds	25		—		—		—		25		Investment funds	27		—		—		—		27
		$	31	$	36	$	—	$	(3)	$	64		$	208	$	104	$	—	$	(8)	$	304

Liabilities - Commodity derivatives	Liabilities - Commodity derivatives	$	—	$	(53)	$	—	$	27	$	(26)	Liabilities - Commodity derivatives	$	—	$	(51)	$	—	$	13	$	(38)

(1)Represents netting under master netting arrangements and a net cash collateral payable of $17 million and a net cash collateral receivable of $5 million ~~and $24 million~~ as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, respectively.

7057

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 76 for further discussion regarding PacifiCorp's risk management and hedging activities.

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

PacifiCorp's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of PacifiCorp's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt (in millions):

As of September 30, 2021 As of December 31, 2020
Carrying Fair Carrying Fair
Value Value Value Value

Long-term debt $ 9,199 $ 11,005 $ 8,612 $ 10,995


	As of March 31, 2022				As of December 31, 2021
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	8,722	$	9,423	$	8,730	$	10,374

~~(9)~~(8) 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.

7158

California and Oregon 2020 Wildfires

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.

7259

Guarantees

PacifiCorp has entered into guarantees as part of the normal course of business and the sale or transfer of certain assets. These guarantees are not expected to have a material impact on PacifiCorp's consolidated financial results.

~~(10)~~(9) 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				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021
Customer Revenue:	Customer Revenue:									Customer Revenue:
Retail:	Retail:									Retail:
Residential	Residential	$	530	$	519	$	1,442	$	1,363	Residential		$	505	$	483
Commercial	Commercial	428		418		1,180		1,122		Commercial		370		359
Industrial	Industrial	296		293		849		838		Industrial		273		271
Other retail	Other retail	98		114		214		209		Other retail		37		32
Total retail	Total retail	1,352		1,344		3,685		3,532		Total retail		1,185		1,145
Wholesale	Wholesale	58		59		124		76		Wholesale		55		36
Transmission	Transmission	55		33		117		79		Transmission		32		25
Other Customer Revenue	Other Customer Revenue	26		42		80		88		Other Customer Revenue		20		23
Total Customer Revenue	Total Customer Revenue	1,491		1,478		4,006		3,775		Total Customer Revenue		1,292		1,229
Other revenue	Other revenue	—		1		25		54		Other revenue		5		13
Total operating revenue	Total operating revenue	$	1,491	$	1,479	$	4,031	$	3,829	Total operating revenue		$	1,297	$	1,242

7360

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

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of PacifiCorp during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with PacifiCorp's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10‑Q. PacifiCorp's actual results in the future could differ significantly from the historical results.

Results of Operations for the ~~Third~~First Quarter of 2022 and ~~First Nine Months of~~ 2021 ~~and 2020~~

Overview

Net income for the ~~third~~first quarter of ~~2021~~2022 was ~~$332~~$130 million, ~~an increase~~a decrease of ~~$46~~$39 million, or ~~16%~~23%, compared to ~~2020.~~2021. Net income ~~increased~~decreased primarily due to ~~lower~~higher operations and maintenance expense, ~~of $65 million, primarily due to prior year costs associated with the Klamath Hydroelectric Project~~and estimated losses in the prior year associated with wildfires, lower income tax expense of $46 million primarily due to the impacts of ratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service, and higher utility margin of $6 million, partially offset by higher depreciation and amortization expense, ~~of $38 million, including the impacts of the depreciation study for which rates became effective January 2021,~~higher income tax expense and ~~lower allowances for equity and borrowed funds used during construction of $24 million.~~higher other expense, partially offset by higher utility margin. Utility margin increased primarily due to higher retail ~~and wheeling~~ revenue from higher ~~deferred net power costs in accordance with established adjustment mechanisms, lower purchased electricity~~ volumes and higher ~~REC revenue,~~average prices, higher average wholesale market prices, lower coal-fueled generation volumes and higher net power cost deferrals, partially offset by higher purchased electricity prices ~~thermal~~and volumes and higher natural gas-fueled generation ~~costs,~~prices and ~~wheeling expenses.~~volumes. Retail customer volumes increased ~~2.1%~~1.9%, primarily due to an increase in the average number of customers, favorable impacts of weather and ~~higher~~an increase in customer usage. Energy generated ~~increased 9%~~was essentially flat for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020 primarily due to higher wind-powered, coal-fueled, and natural gas-fueled generation, partially offset by lower hydroelectric generation.~~2021. Wholesale electricity sales volumes ~~increased 4%~~decreased 2% and purchased electricity volumes ~~decreased 16%.~~

~~Net income for the first nine months of 2021 was $726 million, an increase of $98 million, or 16%, compared to 2020. Net income~~ increased primarily due to higher utility margin of $131 million, lower income tax expense of $118 million (excluding prior year impacts of the Oregon RAC settlement offset in depreciation expense), primarily from the impacts of ratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service, lower operations and maintenance expense of $48 million, primarily due to prior year costs associated with the Klamath Hydroelectric Project and estimated losses in the prior year associated with wildfires, partially offset by higher depreciation and amortization expense of $115 million, including the impacts of the depreciation study for which rates became effective January 2021, and lower allowances for equity and borrowed funds used during construction of $53 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, lower purchased electricity volumes and higher REC revenue, partially offset by higher purchased electricity prices, thermal generation costs and wheeling expenses. Retail customer volumes increased 4.4%, primarily due to higher customer usage, an increase in the average number of customers, and favorable impacts of weather. Energy generated increased 14% for the first nine 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 20% and purchased electricity volumes decreased 16%6%.

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):


		Third Quarter								First Nine Months									First Quarter
		2021		2020		Change				2021		2020		Change					2022		2021		Change
Utility margin:	Utility margin:																	Utility margin:
Operating revenue	Operating revenue	$	1,491	$	1,479	$	12	1	%	$	4,031	$	3,829	$	202	5	%	Operating revenue	$	1,297	$	1,242	$	55	4	%
Cost of fuel and energy	Cost of fuel and energy	505		499		6		1		1,370		1,299		71		5		Cost of fuel and energy	465		424		41		10
Utility margin	Utility margin	986		980		6		1		2,661		2,530		131		5		Utility margin	832		818		14		2
Operations and maintenance	Operations and maintenance	267		332		(65)		(20)		781		829		(48)		(6)		Operations and maintenance	277		259		18		7
Depreciation and amortization	Depreciation and amortization	272		234		38		16		811		696		115		17		Depreciation and amortization	280		264		16		6
Property and other taxes	Property and other taxes	54		53		1		2		158		154		4		3		Property and other taxes	59		61		(2)		(3)
Operating income	Operating income	$	393	$	361	$	32	9	%	$	911	$	851	$	60	7	%	Operating income	$	216	$	234	$	(18)	(8)	%

7561

Utility Margin

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


		Third Quarter								First Nine Months									First Quarter
		2021		2020		Change				2021		2020		Change					2022		2021		Change
Utility margin (in millions):	Utility margin (in millions):																	Utility margin (in millions):
Operating revenue	Operating revenue	$	1,491	$	1,479	$	12	1	%	$	4,031	$	3,829	$	202	5	%	Operating revenue	$	1,297	$	1,242	$	55	4	%
Cost of fuel and energy	Cost of fuel and energy	505		499		6		1		1,370		1,299		71		5		Cost of fuel and energy	465		424		41		10
Utility margin	Utility margin	$	986	$	980	$	6	1	%	$	2,661	$	2,530	$	131	5	%	Utility margin	$	832	$	818	$	14	2	%

Sales (GWhs):	Sales (GWhs):																	Sales (GWhs):
Residential	Residential	4,732		4,622		110		2	%	13,396		12,699		697		5	%	Residential	4,764		4,632		132		3	%
Commercial	Commercial	5,078		4,799		279		6		14,181		13,157		1,024		8		Commercial	4,550		4,470		80		2
Industrial, irrigation and other	Industrial, irrigation and other	5,375		5,446		(71)		(1)		14,976		14,907		69		—		Industrial, irrigation and other	4,523		4,474		49		1
Total retail	Total retail	15,185		14,867		318		2		42,553		40,763		1,790		4		Total retail	13,837		13,576		261		2
Wholesale	Wholesale	1,093		1,053		40		4		3,928		3,266		662		20		Wholesale	1,553		1,591		(38)		(2)
Total sales	Total sales	16,278		15,920		358		2	%	46,481		44,029		2,452		6	%	Total sales	15,390		15,167		223		1	%

Average number of retail customers (in thousands)	Average number of retail customers (in thousands)	2,006		1,971		35		2	%	1,998		1,963		35		2	%	Average number of retail customers (in thousands)	2,025		1,989		36		2	%

Average revenue per MWh:	Average revenue per MWh:																	Average revenue per MWh:
Retail	Retail	$	88.91	$	90.25	$	(1.34)	(1)	%	$	86.53	$	86.60	$	(0.07)	—	%	Retail	$	85.46	$	84.15	$	1.31	2	%
Wholesale	Wholesale	$	53.45	$	57.54	$	(4.09)	(7)	%	$	37.23	$	38.58	$	(1.35)	(3)	%	Wholesale	$	39.12	$	30.89	$	8.23	27	%

Heating degree days	Heating degree days	196		194		2		1	%	6,111		6,132		(21)		—	%	Heating degree days	4,745		4,687		58		1	%

Cooling degree days	Cooling degree days	1,681		1,658		23		1	%	2,427		2,097		330		16	%	Cooling degree days	5		—		5		N/A

Sources of energy (GWhs)(1):	Sources of energy (GWhs)(1):																	Sources of energy (GWhs)(1):
Coal	Coal	9,011		8,576		435		5	%	24,157		22,001		2,156		10	%	Coal	6,911		7,644		(733)		(10)	%
Natural gas	Natural gas	3,886		3,638		248		7		10,174		8,881		1,293		15		Natural gas	3,115		3,065		50		2
Hydroelectric(2)		380		414		(34)		(8)		1,981		2,351		(370)		(16)
Wind and other(2)		1,323		720		603		84		4,534		2,696		1,838		68
Wind(2)																		Wind(2)	2,392		1,738		654		38
Hydroelectric and other(2)																		Hydroelectric and other(2)	984		988		(4)		—
Total energy generated	Total energy generated	14,600		13,348		1,252		9		40,846		35,929		4,917		14		Total energy generated	13,402		13,435		(33)		—
Energy purchased	Energy purchased	3,058		3,621		(563)		(16)		9,407		11,245		(1,838)		(16)		Energy purchased	3,223		3,028		195		6
Total	Total	17,658		16,969		689		4	%	50,253		47,174		3,079		7	%	Total	16,625		16,463		162		1	%

Average cost of energy per MWh:	Average cost of energy per MWh:																	Average cost of energy per MWh:
Energy generated(3)	Energy generated(3)	$	18.39	$	18.65	$	(0.26)	(1)	%	$	17.98	$	17.95	$	0.03	—	%	Energy generated(3)	$	18.83	$	17.66	$	1.17	7	%
Energy purchased	Energy purchased	$	88.48	$	53.28	$	35.20	66	%	$	67.10	$	45.85	$	21.25	46	%	Energy purchased	$	55.49	$	47.13	$	8.36	18	%

(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~~Renewable Energy Credits or other environmental commodities.

(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.

7662

Quarter Ended ~~September 30, 2021~~March 31, 2022 compared to Quarter Ended ~~September 30, 2020~~March 31, 2021

Utility margin increased $6$14 million, or 1%2%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to:

•$~~103~~40 million increase in retail revenue due to higher volumes and higher average prices. Retail customer volumes increased 1.9%, primarily due to an increase in the average number of customers, favorable impacts of weather and an increase in customer usage;

•$12 million increase in wholesale revenue due to higher average market prices, partially offset by lower volumes;

•$12 million of lower coal-fueled generation costs due to lower volumes, partially offset by higher average prices;

•$8 million of higher deferred net power costs in accordance with established adjustment mechanisms;

•~~$12 million of favorable wheeling activities;~~ and

•$8 million increase in retail revenue primarily due to higher customer volumes, partially offset by lower rates driven by certain general rate case orders. Retail customer volumes increased 2.1%, primarily due to an increase in the average number of ~~customers, and higher customer usage, partially offset by the unfavorable impact of weather; and~~

•~~$6 million of higher REC, fly ash and by-product revenues.~~favorable wheeling activities.

The increases above were partially offset by:

•$8036 million of higher purchased electricity costs from higher average market prices ~~partially offset by lower~~and volumes; and

•$27 ~~million of lower other revenue due to impacts of the Oregon RAC settlement (offset in depreciation expense) in the prior year;~~

•~~$13~~ million of higher natural gas-fueled generation costs due to higher average prices and higher ~~volumes; and~~

•~~$7 million of higher coal-fueled generation costs primarily due to higher volumes, partially offset by lower average prices.~~volumes.

Operations and maintenance ~~decreased $65~~increased $18 million, or ~~20%~~7%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to ~~prior year~~higher maintenance costs, ~~associated with the Klamath Hydroelectric Project~~higher DSM amortization of regulatory balances, and ~~estimated losses in the prior year associated with wildfires and lower thermal plant maintenance expense, including overhauls,~~higher insurance premiums due to cost increases related to wildfire coverage, partially offset by ~~higher wind plant~~lower labor expenses and ~~distribution maintenance.~~lower vegetation management costs.

Depreciation and amortization increased ~~$38~~$16 million, or ~~16%~~6%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to ~~the impacts of a depreciation study effective January 1, 2021 of approximately $38 million and~~ higher plant in-service ~~balances, partially offset by prior year accelerated depreciation of $27 million (offset in other revenue) due to the prior year Oregon RAC settlement.~~

~~Allowance for borrowed and equity funds~~ ~~decreased $24 million, or 56%, for the third quarter of 2021 compared to 2020 primarily due to lower qualified construction work-in-progress~~ balances.

Other, net decreased $10 million for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to ~~the July 2021 pension settlement loss and~~ market movements related to corporate-owned life insurance ~~policies.~~policies and higher pension and postretirement costs.

Income tax expense (benefit) ~~expense~~ ~~decreased $46~~increased $13 million to an expense of $2 million for the first quarter of 2022 compared to a benefit of ~~$28~~$11 million for the ~~third~~first quarter of ~~2021 compared to expense of $18 million for the third quarter of 2020.~~2021. The effective tax rate was ~~(9)~~2% for the first quarter of 2022 and (7)% for ~~2021 and 6% for 2020.~~the first quarter of 2021. 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 Nine Months of 2021 compared to First Nine Months of 2020~~

~~Utility margin~~ ~~increased $131 million, or 5%, for the first nine months of 2021 compared to 2020 primarily due to:~~

•~~$152 million increase in retail revenue~~ primarily due to higher customer volumes, partially offset by lower rates driven by certain general rate case orders. Retail customer volumes increased 4.4%, primarily due to higher customer usage, an increase in the average number of customers, and the favorable impact of weather;

•~~$151 million of higher deferred net power costs in accordance with established adjustment mechanisms;~~

•~~$21 million of favorable wheeling activities;~~

•~~$20 million of higher wholesale revenue due to higher wholesale volumes, partially offset by lower average wholesale market prices; and~~

•~~$18 million of higher REC, fly ash and by-product revenues.~~

~~The increases above were partially offset by:~~

•~~$117 million of higher purchased electricity costs due to higher average prices, partially offset by lower volumes;~~

•~~$58 million of higher natural gas-fueled generation costs due to higher average prices and higher volumes;~~

•~~$34 million of lower other revenue due to impacts of the Oregon RAC settlement (offset in depreciation expense) in the prior year; and~~

•~~$33 million of higher coal-fueled generation costs primarily due to higher volumes, partially offset by lower average prices.~~

~~Operations and maintenance~~ decreased $48 million, or 6%, for the first nine months of 2021 compared to 2020 primarily due to prior year costs associated with the Klamath Hydroelectric Project and estimated losses in the prior year associated with wildfires, lower thermal plant maintenance expense, including overhauls, and lower employee expenses, partially offset by higher wind plant and distribution maintenance and higher vegetation management costs.

~~Depreciation and amortization~~ ~~increased $115 million, or 17%, for the first nine months of 2021 compared to 2020 primarily due to the impacts of~~ a depreciation study effective January 1, 2021 of approximately $120 million, and higher plant in-service balances, partially offset by a $71 million decrease due to the prior year Oregon RAC settlement ($3 millionvaluation allowance PacifiCorp recorded in the first quarter of ~~2021 (fully offset in other revenue) compared to $74 million in 2020 ($34 million offset in other revenue and $40 million offset in income tax expense)).~~

~~Allowance for borrowed and equity funds~~ decreased $53 million, or 49%, for the first nine months of 2021 compared to 2020 primarily due to lower qualified construction work-in-progress balances and allowance for borrowed and equity funds rates.

~~Income tax (benefit) expense~~ decreased $88 million to a benefit of $58 million for the first nine months of 2021 compared to expense of $30 million the first nine months of 2020. The effective tax rate was (9)% for 2021 and 5% for 2020. The effective tax rate decreased primarily as a result of increased PTCs from PacifiCorp's new wind-powered generating facilities and as a result of higher effects of ratemaking associated with excess deferred income tax amortization in the current year.2022 against state net operating loss carryforwards.

Liquidity and Capital Resources

As of ~~September 30, 2021,~~March 31, 2022, PacifiCorp's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	~~893~~335

Credit facilities	1,200
Less:

Tax-exempt bond support	(218)
Net credit facilities	982

Total net liquidity	$	~~1,875~~1,317

Credit facilities:
Maturity dates	2024

Operating Activities

Net cash flows from operating activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ were ~~$1,544~~$537 million and ~~$1,291~~$469 million, respectively. The change was primarily due to timing of operating payables and higher collections from retail customers, ~~and higher cash received for income taxes,~~ partially offset by higher wholesale purchases.

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.

7863

Investing Activities

Net cash flows from investing activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ were ~~$(1,150)~~$(371) million and ~~$(1,587)~~$(440) million, respectively. The change is primarily due to a decrease in capital expenditures of ~~$461 million, partially offset by prior year proceeds from the settlement of notes receivable of $25 million associated with the sale of certain Utah mining assets in 2015.~~$65 million. Refer to "Future Uses of Cash" for discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the ~~nine-month~~three-month period ended ~~September 30, 2021~~March 31, 2022 were ~~$486 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $984~~$(11) million. Uses of cash consisted substantially of ~~$400~~$9 million for the repayment of long-term ~~debt and $93 million for the repayment of short-term~~ debt.

Net cash flows from financing activities for the ~~nine-month~~three-month period ended ~~September 30, 2020~~March 31, 2021 were ~~$857~~$1 million. Sources of cash consisted of ~~net proceeds~~$2 million from the ~~issuance of long-term debt of $987 million. Uses of cash consisted of $130 million for the repayment~~borrowing of short-term debt.

Short-term Debt

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of ~~September 30,~~March 31, 2022 and December 31, 2021, PacifiCorp had no short-term debt outstanding. ~~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~~

Debt Authorizations

~~Following the July 2021 long-term debt issuance,~~ PacifiCorp currently has regulatory authority from the OPUC and the ~~IPUC~~Idaho Public Utilities Commission 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.

~~Common Shareholder's Equity~~

~~In October 2021, PacifiCorp declared a common stock dividend of $150 million, payable in November 2021, to PPW Holdings LLC.~~

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 associated with PacifiCorp and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

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

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


		Nine-Month Periods				Annual			Three-Month Periods				Annual
		Ended September 30,				Forecast			Ended March 31,				Forecast
		2020		2021		2021			2021		2022		2022

Wind generation	Wind generation	$	807	$	110	$	138	Wind generation	$	33	$	8	$	154
Electric distribution	Electric distribution	360		461		637		Electric distribution	195		142		660
Electric transmission	Electric transmission	300		212		316		Electric transmission	60		153		1,185
Other	Other	151		374		467		Other	151		71		360
Total	Total	$	1,618	$	1,157	$	1,558	Total	$	439	$	374	$	2,359

PacifiCorp's ~~2019 and~~ 2021 IRP identified a roadmap for a significant increase in renewable ~~resource~~and carbon free generation resources, coal to natural gas conversion of certain coal-fueled units, energy storage and associated transmission. PacifiCorp's 2021 IRP identified over 1,800 MWs of new wind-powered generating resources that are expected to be online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp has included an estimate for these new generation resources and associated transmission in its forecast capital expenditures for ~~2021~~2022 through ~~2023.~~2024. These estimates ~~may~~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 ~~$99~~$3 million and ~~$705~~$27 million for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ respectively. Construction includes ~~674~~516 MWs of new wind-powered generating facilities that were placed in-service in ~~2020 and 516 MWs that were placed in service in the first nine months 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. Similar to PacifiCorp's 2019 IRP, the 2021 IRP identified over 1,800 MWs of new wind-powered generating resources that are expected to come online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. Planned spending for the construction of additional wind-powered generating facilities totals ~~$17~~$109 million for the remainder of ~~2021.~~2022.

◦~~Repowering~~Planned acquisition and repowering of two wind-powered generating facilities atby PacifiCorp totaling $9$3 million and ~~$99~~$1 million for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ respectively. ~~Certain repowering projects for existing facilities were placed in service in 2019, 2020 and in the first nine months of 2021.~~ The ~~energy production from these existing~~ repowered facilities isare expected to ~~qualify for 100% of the federal renewable electricity PTCs available for 10 years following each facility's return to service.~~be placed in-service in 2023 and 2024. Planned spending for ~~the~~acquiring and repowering ~~of wind-powered~~ generating facilities totals $7$18 million for the remainder of ~~2021.~~2022.

•Electric distribution includes both growth projects and operating expenditures. Operating expenditures includes ~~planned~~ spend on wildfire mitigation and wildfire and storm damage restoration. Expenditures for these items totaled ~~$144~~$25 million and ~~$21~~$83 million for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ respectively. Planned ~~electric distribution~~ spending for wildfire mitigation and wildfire and storm damage restoration totals ~~$51~~$118 million for the remainder of ~~2021 and relates~~2022. Remaining investments relate to expenditures for new connections and ~~distribution.~~distribution operations.

•Electric transmission includes both growth projects and operating expenditures. Transmission investment ~~through 2020~~ primarily reflects planned costs for the ~~140-mile~~416-mile, 500-kV ~~Aeolus-Bridger/Anticline~~high-voltage transmission line ~~a major segment of PacifiCorp's Energy Gateway Transmission expansion program, placed in-service~~between the Aeolus substation near Medicine Bow in ~~November 2020.~~Wyoming and the Clover substation near Mona, Utah; the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation; and the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho. Expenditures for these segments totaled $95 million and $16 million for the three-month periods ended March 31, 2022 and 2021, respectively. Planned spending for ~~additional~~these Energy Gateway Transmission segments to be placed ~~in service~~in-service in 2024-2026 totals ~~$46~~$814 million ~~in 2021.~~for the remainder of 2022.

•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled ~~$69~~$45 million and ~~$53~~$13 million for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ respectively. Planned information technology spending totals ~~$47~~$127 million for the remainder of ~~2021 and relates~~2022. Remaining investments relate to operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing and expected demand.

Energy Supply Planning

As required by certain state regulations, PacifiCorp uses an IRP to develop a long-term resource plan to ensure that PacifiCorp can continue to provide reliable and cost-effective electric service to its customers while maintaining compliance with existing and evolving environmental laws and regulations.

In September 2021, PacifiCorp filed its 2021 IRP with its state ~~commissions. The~~commissions and subsequently filed its 2021 IRP ~~includes investments~~Update in ~~new renewable energy resources, new battery storage resources~~March and ~~expanded transmission investments. New renewable energy resources in~~April 2022. In March 2022, the OPUC acknowledged PacifiCorp's 2021 IRP ~~include more than 1,800 MW~~and its preferred portfolio. Reviews of ~~new wind-powered generation, over 2,100 MW of new solar-powered generation~~the 2021 IRP by the UPSC, the Wyoming Public Service Commission, the WUTC and ~~nearly 700 MW of new battery storage capacity by 2025. The IRP also outlines PacifiCorp's plan to retire or convert to natural gas all coal-fueled resources by 2042.~~the Idaho Public Utilities Commission are ongoing.

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~~

A draft of PacifiCorp's 2022 All Source RFP ("2022AS RFP") was filed for approval with the WUTC in December 2021, and with the UPSC and the OPUC in January 2022. The draft 2022AS RFP was approved by the WUTC in March 2022 and by the UPSC and the OPUC in April 2022. PacifiCorp expects to issue the 2022AS RFP to market in ~~July 2020. The 2020 All Source RFP sought bids for resources capable~~the second quarter 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 battery storage capacity being contracted resources.2022.

~~Contractual Obligations~~Material Cash Requirements

As of ~~September 30, 2021,~~March 31, 2022, there have been no material changes outside the normal course of business in ~~contractual obligations~~material cash requirements from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, ~~2020.~~2021.

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.~~2021. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, ~~2020.~~2021.

8266

MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company

Consolidated Financial Section

8367

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

MidAmerican Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of ~~September 30, 2021,~~March 31, 2022, the related statements of operations, ~~and~~ changes in shareholder's equity, ~~for the three-month~~ and ~~nine-month periods ended September 30, 2021 and 2020, and of~~ cash flows for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 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,~~2021, 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,~~25, 2022, 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,~~2021, 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.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

~~November 5, 2021~~April 29, 2022

8468

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)


		As of					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	541	$	38	Cash and cash equivalents	$	131	$	232
Trade receivables, net	Trade receivables, net	555		234		Trade receivables, net	468		526

Income tax receivable						Income tax receivable	297		79
Inventories	Inventories	244		278		Inventories	185		234
Other current assets	Other current assets	142		73		Other current assets	187		123
Total current assets	Total current assets	1,482		623		Total current assets	1,268		1,194

Property, plant and equipment, net	Property, plant and equipment, net	19,773		19,279		Property, plant and equipment, net	20,344		20,301
Regulatory assets	Regulatory assets	479		392		Regulatory assets	492		473
Investments and restricted investments	Investments and restricted investments	975		911		Investments and restricted investments	985		1,026
Other assets	Other assets	235		232		Other assets	262		263

Total assets	Total assets	$	22,944	$	21,437	Total assets	$	23,351	$	23,257

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

8569

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


		As of					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
LIABILITIES AND SHAREHOLDER'S EQUITY	LIABILITIES AND SHAREHOLDER'S EQUITY					LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	$	347	$	408	Accounts payable	$	429	$	531
Accrued interest	Accrued interest	89		78		Accrued interest	88		84
Accrued property, income and other taxes	Accrued property, income and other taxes	242		161		Accrued property, income and other taxes	144		158

Current portion of long-term debt						Current portion of long-term debt	7		—
Other current liabilities	Other current liabilities	226		183		Other current liabilities	144		145
Total current liabilities	Total current liabilities	904		830		Total current liabilities	812		918

Long-term debt	Long-term debt	7,716		7,210		Long-term debt	7,719		7,721
Regulatory liabilities	Regulatory liabilities	943		1,111		Regulatory liabilities	1,057		1,080
Deferred income taxes	Deferred income taxes	3,407		3,054		Deferred income taxes	3,373		3,389
Asset retirement obligations	Asset retirement obligations	677		709		Asset retirement obligations	723		714
Other long-term liabilities	Other long-term liabilities	495		458		Other long-term liabilities	463		475
Total liabilities	Total liabilities	14,142		13,372		Total liabilities	14,147		14,297

Commitments and contingencies (Note 9)		0		0
Commitments and contingencies (Note 7)						Commitments and contingencies (Note 7)	0		0

Shareholder's equity:	Shareholder's equity:					Shareholder's equity:
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding	Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding	—		—		Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding	—		—
Additional paid-in capital	Additional paid-in capital	561		561		Additional paid-in capital	561		561
Retained earnings	Retained earnings	8,241		7,504		Retained earnings	8,643		8,399

Total shareholder's equity	Total shareholder's equity	8,802		8,065		Total shareholder's equity	9,204		8,960

Total liabilities and shareholder's equity	Total liabilities and shareholder's equity	$	22,944	$	21,437	Total liabilities and shareholder's equity	$	23,351	$	23,257

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

8670

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021
Operating revenue:	Operating revenue:									Operating revenue:
Regulated electric	Regulated electric	$	854	$	728	$	1,985	$	1,717	Regulated electric		$	608	$	545
Regulated natural gas and other	Regulated natural gas and other	112		84		741		389		Regulated natural gas and other		397		522
Total operating revenue	Total operating revenue	966		812		2,726		2,106		Total operating revenue		1,005		1,067

Operating expenses:	Operating expenses:									Operating expenses:
Cost of fuel and energy	Cost of fuel and energy	163		115		417		266		Cost of fuel and energy		125		151
Cost of natural gas purchased for resale and other	Cost of natural gas purchased for resale and other	64		40		553		210		Cost of natural gas purchased for resale and other		298		432
Operations and maintenance	Operations and maintenance	200		212		577		559		Operations and maintenance		192		193
Depreciation and amortization	Depreciation and amortization	218		180		634		531		Depreciation and amortization		250		207
Property and other taxes	Property and other taxes	34		33		107		102		Property and other taxes		40		36
Total operating expenses	Total operating expenses	679		580		2,288		1,668		Total operating expenses		905		1,019

Operating income	Operating income	287		232		438		438		Operating income		100		48

Other income (expense):	Other income (expense):									Other income (expense):
Interest expense	Interest expense	(76)		(74)		(224)		(224)		Interest expense		(78)		(74)
Allowance for borrowed funds	Allowance for borrowed funds	4		5		8		12		Allowance for borrowed funds		4		2
Allowance for equity funds	Allowance for equity funds	11		16		25		33		Allowance for equity funds		15		6
Other, net	Other, net	8		14		34		30		Other, net		(3)		11
Total other income (expense)	Total other income (expense)	(53)		(39)		(157)		(149)		Total other income (expense)		(62)		(55)

Income before income tax benefit		234		193		281		289
Income (loss) before income tax benefit										Income (loss) before income tax benefit		38		(7)
Income tax benefit	Income tax benefit	(143)		(147)		(456)		(411)		Income tax benefit		(206)		(154)

Net income	Net income	$	377	$	340	$	737	$	700	Net income		$	244	$	147

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

8771

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions)

Common Stock Additional Paid-in Capital Retained
Earnings Total Shareholder's
Equity
Balance, June 30, 2020 $ — $ 561 $ 7,039 $ 7,600
Net income — — 340 340
Balance, September 30, 2020 $ — $ 561 $ 7,379 $ 7,940
Balance, December 31, 2019 $ — $ 561 $ 6,679 $ 7,240
Net income — — 700 700
Balance, September 30, 2020 $ — $ 561 $ 7,379 $ 7,940
Balance, June 30, 2021 $ — $ 561 $ 7,865 $ 8,426
Net income — — 377 377
Other equity transactions — — (1) (1)
Balance, September 30, 2021 $ — $ 561 $ 8,241 $ 8,802
Balance, December 31, 2020 $ — $ 561 $ 7,504 $ 8,065
Net income — — 737 737
Balance, September 30, 2021 $ — $ 561 $ 8,241 $ 8,802


	Common Stock		Additional Paid-in Capital		Retained Earnings		Total Shareholder's Equity






Balance, December 31, 2020	$	—	$	561	$	7,504	$	8,065
Net income	—		—		147		147

Balance, March 31, 2021	$	—	$	561	$	7,651	$	8,212






Balance, December 31, 2021	$	—	$	561	$	8,399	$	8,960
Net income	—		—		244		244

Balance, March 31, 2022	$	—	$	561	$	8,643	$	9,204

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

8872

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


		Nine-Month Periods					Three-Month Periods
		Ended September 30,					Ended March 31,
		2021		2020			2022		2021
Cash flows from operating activities:	Cash flows from operating activities:					Cash flows from operating activities:
Net income	Net income	$	737	$	700	Net income	$	244	$	147
Adjustments to reconcile net income to net cash flows from operating activities:	Adjustments to reconcile net income to net cash flows from operating activities:					Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	Depreciation and amortization	634		531		Depreciation and amortization	250		207
Amortization of utility plant to other operating expenses	Amortization of utility plant to other operating expenses	26		25		Amortization of utility plant to other operating expenses	9		8
Allowance for equity funds	Allowance for equity funds	(25)		(33)		Allowance for equity funds	(15)		(6)
Deferred income taxes and investment tax credits, net	Deferred income taxes and investment tax credits, net	121		76		Deferred income taxes and investment tax credits, net	16		154
Settlements of asset retirement obligations	Settlements of asset retirement obligations	(51)		(55)		Settlements of asset retirement obligations	(7)		(4)
Other, net	Other, net	42		(1)		Other, net	10		(18)
Changes in other operating assets and liabilities:	Changes in other operating assets and liabilities:					Changes in other operating assets and liabilities:
Trade receivables and other assets	Trade receivables and other assets	(331)		(15)		Trade receivables and other assets	42		(299)
Inventories	Inventories	34		(40)		Inventories	49		46

Pension and other postretirement benefit plans	Pension and other postretirement benefit plans	2		(17)		Pension and other postretirement benefit plans	3		1
Accrued property, income and other taxes, net	Accrued property, income and other taxes, net	80		(10)		Accrued property, income and other taxes, net	(244)		(331)
Accounts payable and other liabilities	Accounts payable and other liabilities	21		48		Accounts payable and other liabilities	3		10
Net cash flows from operating activities	Net cash flows from operating activities	1,290		1,209		Net cash flows from operating activities	360		(85)

Cash flows from investing activities:	Cash flows from investing activities:					Cash flows from investing activities:
Capital expenditures	Capital expenditures	(1,266)		(1,341)		Capital expenditures	(459)		(298)
Purchases of marketable securities	Purchases of marketable securities	(166)		(251)		Purchases of marketable securities	(105)		(52)
Proceeds from sales of marketable securities	Proceeds from sales of marketable securities	163		244		Proceeds from sales of marketable securities	102		47
Other, net	Other, net	(7)		9		Other, net	1		—
Net cash flows from investing activities	Net cash flows from investing activities	(1,276)		(1,339)		Net cash flows from investing activities	(461)		(303)

Cash flows from financing activities:	Cash flows from financing activities:					Cash flows from financing activities:

Proceeds from long-term debt		492		—

Repayments of long-term debt	Repayments of long-term debt	(1)		—		Repayments of long-term debt	(1)		—

Net proceeds from short-term debt						Net proceeds from short-term debt	—		387
Other, net	Other, net	(2)		(1)		Other, net	1		—
Net cash flows from financing activities	Net cash flows from financing activities	489		(1)		Net cash flows from financing activities	—		387

Net change in cash and cash equivalents and restricted cash and cash equivalents	Net change in cash and cash equivalents and restricted cash and cash equivalents	503		(131)		Net change in cash and cash equivalents and restricted cash and cash equivalents	(101)		(1)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	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 beginning of period	239		45
Cash and cash equivalents and restricted cash and cash equivalents at end of period	Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	548	$	199	Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	138	$	44

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

8973

MIDAMERICAN ENERGY COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

(1) General

MidAmerican Energy Company ("MidAmerican Energy") is a public utility with electric and natural gas operations and is the principal subsidiary of MHC Inc. ("MHC"). MHC is a holding company that conducts no business other than the ownership of its subsidiaries. MHC's nonregulated subsidiary is Midwest Capital Group, Inc. MHC is the direct, wholly owned subsidiary of MidAmerican Funding, LLC ("MidAmerican Funding"), which is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa, that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of ~~September 30, 2021,~~March 31, 2022, and for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020. The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2021 and 2020.~~2021. The results of operations for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2021,~~March 31, 2022, 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,~~2021, describes the most significant accounting policies used in the preparation of the unaudited Financial Statements. There have been no significant changes in MidAmerican Energy's assumptions regarding significant accounting estimates and policies during the ~~nine-month~~three-month period ended ~~September 30, 2021.~~March 31, 2022.

(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, ~~United States~~U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents ~~as of September 30, 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 September 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					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021

Cash and cash equivalents	Cash and cash equivalents	$	541	$	38	Cash and cash equivalents	$	131	$	232
Restricted cash and cash equivalents in other current assets	Restricted cash and cash equivalents in other current assets	7		7		Restricted cash and cash equivalents in other current assets	7		7
Total cash and cash equivalents and restricted cash and cash equivalents	Total cash and cash equivalents and restricted cash and cash equivalents	$	548	$	45	Total cash and cash equivalents and restricted cash and cash equivalents	$	138	$	239

9074

(3) Property, Plant and Equipment, Net

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


			As of						As of
			September 30,		December 31,				March 31,		December 31,
		Depreciable Life	2021		2020			Depreciable Life	2022		2021
Utility plant in service, net:
Utility plant in-service, net:							Utility plant in-service, net:
Generation	Generation	20-70 years	$	17,162	$	16,980	Generation	20-70 years	$	17,466	$	17,397
Transmission	Transmission	52-75 years	2,415		2,365		Transmission	52-75 years	2,488		2,474
Electric distribution	Electric distribution	20-75 years	4,522		4,369		Electric distribution	20-75 years	4,713		4,661
Natural gas distribution	Natural gas distribution	29-75 years	2,011		1,955		Natural gas distribution	29-75 years	2,055		2,039
Utility plant in service			26,110		25,669
Utility plant in-service							Utility plant in-service		26,722		26,571
Accumulated depreciation and amortization	Accumulated depreciation and amortization		(7,444)		(6,902)		Accumulated depreciation and amortization		(7,555)		(7,376)
Utility plant in service, net			18,666		18,767
Utility plant in-service, net							Utility plant in-service, net		19,167		19,195
Nonregulated property, net:	Nonregulated property, net:						Nonregulated property, net:
Nonregulated property gross	Nonregulated property gross	20-50 years	7		7		Nonregulated property gross	20-50 years	7		7
Accumulated depreciation and amortization	Accumulated depreciation and amortization		(1)		(1)		Accumulated depreciation and amortization		(1)		(1)
Nonregulated property, net	Nonregulated property, net		6		6		Nonregulated property, net		6		6
			18,672		18,773				19,173		19,201
Construction work-in-progress	Construction work-in-progress		1,101		506		Construction work-in-progress		1,171		1,100
Property, plant and equipment, net	Property, plant and equipment, net		$	19,773	$	19,279	Property, plant and equipment, net		$	20,344	$	20,301

(4) ~~Regulatory Matters~~Income Taxes

~~Natural Gas Purchased~~The effective income tax rate for ~~Resale~~

~~In February~~the three-month period ended March 31, 2021, ~~severe cold weather over the central United States caused disruptions in natural gas supply~~is 2,200% and results from a $154 million income tax benefit associated with a $7 million pretax loss. The $154 million income tax benefit is primarily comprised of a $2 million benefit (21%) from the ~~southern part~~application of the ~~United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale~~statutory income tax rate to ~~MidAmerican Energy's retail customers~~the pretax loss and ~~caused an approximate $245~~a $168 million ~~increase in natural gas costs above those normally expected. These increased costs are reflected in cost~~benefit (2,400%) from income tax credits, partially offset by a $13 million expense (186%) from the effects 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 nine-month period ended September 30, 2021.

~~(5) Recent Financing Transactions~~

~~Long-Term Debt~~

~~Credit Facilities~~

~~(6) Income Taxes~~ratemaking.

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


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021

Federal statutory income tax rate	Federal statutory income tax rate	21	%	21	%	21	%	21	%	Federal statutory income tax rate		21	%	21	%
Income tax credits	Income tax credits	(44)		(55)		(143)		(122)		Income tax credits		(534)		2,400
State income tax, net of federal income tax impacts	State income tax, net of federal income tax impacts	(26)		(27)		(27)		(29)		State income tax, net of federal income tax impacts		(21)		(29)
Effects of ratemaking	Effects of ratemaking	(12)		(15)		(13)		(13)		Effects of ratemaking		(8)		(186)
Other, net	Other, net	—		—		—		1		Other, net		—		(6)
Effective income tax rate	Effective income tax rate	(61)	%	(76)	%	(162)	%	(142)	%	Effective income tax rate		(542)	%	2,200	%

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 ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ totaled ~~$103~~$203 million and ~~$105 million, respectively, and for the nine-month periods ended September 30, 2021 and 2020 totaled $400 million and $352~~$151 million, respectively.

Berkshire Hathaway includes BHE and subsidiaries in its ~~United States~~U.S. 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~~made no cash payments for income tax ~~from~~to BHE ~~totaling $677 million and $500 million~~ for each of the ~~nine-month~~three-month periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020, respectively.~~

2021.

~~(7)~~(5) 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.

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


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021
Pension:	Pension:									Pension:
Service cost	Service cost	$	5	$	2	$	15	$	4	Service cost		$	5	$	5
Interest cost	Interest cost	6		7		17		19		Interest cost		5		6
Expected return on plan assets	Expected return on plan assets	(9)		(10)		(28)		(30)		Expected return on plan assets		(7)		(9)
Net amortization		—		—		1		1
Net periodic benefit cost (credit)		$	2	$	(1)	$	5	$	(6)
Settlement										Settlement		2		—

Net periodic benefit cost										Net periodic benefit cost		$	5	$	2

Other postretirement:	Other postretirement:									Other postretirement:
Service cost	Service cost	$	2	$	1	$	6	$	3	Service cost		$	2	$	2
Interest cost	Interest cost	2		2		6		5		Interest cost		2		2
Expected return on plan assets	Expected return on plan assets	(2)		(4)		(7)		(10)		Expected return on plan assets		(4)		(2)
Net amortization	Net amortization	(1)		(1)		(3)		(4)		Net amortization		—		(1)
Net periodic benefit cost (credit)		$	1	$	(2)	$	2	$	(6)
Net periodic benefit cost										Net periodic benefit cost		$	—	$	1

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $7 million and ~~$12~~$3 million, respectively, during ~~2021.~~2022. As of ~~September 30, 2021, $5~~March 31, 2022, $2 million and $9$1 million of contributions had been made to the pension and other postretirement benefit plans, respectively.

~~(8)~~(6) 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 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.

9376

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											Input Levels for Fair Value Measurements
		Level 1		Level 2		Level 3		Other(1)		Total			Level 1		Level 2		Level 3		Other(1)		Total
As of September 30, 2021:
As of March 31, 2022:												As of March 31, 2022:
Assets:	Assets:											Assets:
Commodity derivatives	Commodity derivatives	$	1	$	70	$	4	$	(7)	$	68	Commodity derivatives	$	—	$	66	$	4	$	—	$	70
Money market mutual funds	Money market mutual funds	543		—		—		—		543		Money market mutual funds	132		—		—		—		132
Debt securities:	Debt securities:											Debt securities:
United States government obligations		228		—		—		—		228
U.S. government obligations												U.S. government obligations	225		—		—		—		225
International government obligations	International government obligations	—		2		—		—		2		International government obligations	—		1		—		—		1
Corporate obligations	Corporate obligations	—		86		—		—		86		Corporate obligations	—		79		—		—		79
Municipal obligations	Municipal obligations	—		3		—		—		3		Municipal obligations	—		3		—		—		3
Agency, asset and mortgage-backed obligations	Agency, asset and mortgage-backed obligations	—		1		—		—		1		Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:	Equity securities:											Equity securities:
United States companies		398		—		—		—		398
U.S. companies												U.S. companies	415		—		—		—		415
International companies	International companies	8		—		—		—		8		International companies	9		—		—		—		9
Investment funds	Investment funds	23		—		—		—		23		Investment funds	23		—		—		—		23
		$	1,201	$	162	$	4	$	(7)	$	1,360		$	804	$	150	$	4	$	—	$	958

Liabilities - commodity derivatives	Liabilities - commodity derivatives	$	(2)	$	(5)	$	(4)	$	7	$	(4)	Liabilities - commodity derivatives	$	(1)	$	—	$	—	$	—	$	(1)


		Input Levels for Fair Value Measurements											Input Levels for Fair Value Measurements
		Level 1		Level 2		Level 3		Other(1)		Total			Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2020:
As of December 31, 2021:												As of December 31, 2021:
Assets:	Assets:											Assets:
Commodity derivatives	Commodity derivatives	$	—	$	4	$	5	$	(5)	$	4	Commodity derivatives	$	—	$	32	$	3	$	(7)	$	28
Money market mutual funds	Money market mutual funds	41		—		—		—		41		Money market mutual funds	228		—		—		—		228
Debt securities:	Debt securities:											Debt securities:
United States government obligations		200		—		—		—		200
U.S. government obligations												U.S. government obligations	232		—		—		—		232
International government obligations	International government obligations	—		5		—		—		5		International government obligations	—		2		—		—		2
Corporate obligations	Corporate obligations	—		73		—		—		73		Corporate obligations	—		90		—		—		90
Municipal obligations	Municipal obligations	—		2		—		—		2		Municipal obligations	—		3		—		—		3
Agency, asset and mortgage-backed obligations	Agency, asset and mortgage-backed obligations	—		6		—		—		6		Agency, asset and mortgage-backed obligations	—		2		—		—		2
Equity securities:	Equity securities:											Equity securities:
United States companies		381		—		—		—		381
U.S. companies												U.S. companies	428		—		—		—		428
International companies	International companies	9		—		—		—		9		International companies	10		—		—		—		10
Investment funds	Investment funds	17		—		—		—		17		Investment funds	18		—		—		—		18
		$	648	$	90	$	5	$	(5)	$	738		$	916	$	129	$	3	$	(7)	$	1,041

Liabilities - commodity derivatives	Liabilities - commodity derivatives	$	—	$	(4)	$	(3)	$	5	$	(2)	Liabilities - commodity derivatives	$	—	$	(6)	$	(8)	$	12	$	(2)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $— million and $5 million as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, respectively.

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

MidAmerican Energy's long-term debt is carried at cost on the Balance Sheets. The fair value of MidAmerican Energy's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Energy's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Energy's long-term debt (in millions):

As of September 30, 2021 As of December 31, 2020
Carrying
Value Fair
Value Carrying
Value Fair
Value
Long-term debt $ 7,716 $ 9,101 $ 7,210 $ 9,130


	As of March 31, 2022				As of December 31, 2021
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	7,726	$	8,196	$	7,721	$	9,037

~~(9)~~(7) Commitments and Contingencies

~~Construction Commitments~~

~~Easements~~

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.

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 ~~September 30, 2021,~~March 31, 2022, has accrued ~~a $9~~an $8 million liability for refunds of amounts collected under the higher ROE during the periods covered by both complaints.

9678

~~(10)~~(8) 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 119 (in millions):


		For the Three-Month Period Ended September 30, 2021								For the Nine-Month Period Ended September 30, 2021									For the Three-Month Period Ended March 31, 2022
		Electric		Natural Gas		Other		Total		Electric		Natural Gas		Other		Total				Electric		Natural Gas		Other		Total
Customer Revenue:	Customer Revenue:																	Customer Revenue:
Retail:	Retail:																	Retail:
Residential	Residential	$	255	$	52	$	—	$	307	$	586	$	419	$	—	$	1,005	Residential		$	168	$	225	$	—	$	393
Commercial	Commercial	107		17		—		124		258		164		—		422		Commercial		74		88		—		162
Industrial	Industrial	321		5		—		326		741		20		—		761		Industrial		198		9		—		207
Natural gas transportation services	Natural gas transportation services	—		9		—		9		—		28		—		28		Natural gas transportation services		—		14		—		14
Other retail(1)	Other retail(1)	53		1		—		54		119		2		—		121		Other retail(1)		32		1		—		33
Total retail	Total retail	736		84		—		820		1,704		633		—		2,337		Total retail		472		337		—		809
Wholesale	Wholesale	88		25		—		113		214		93		—		307		Wholesale		104		58		—		162
Multi-value transmission projects	Multi-value transmission projects	15		—		—		15		45		—		—		45		Multi-value transmission projects		15		—		—		15
Other Customer Revenue	Other Customer Revenue	—		—		2		2		—		—		13		13		Other Customer Revenue		—		—		1		1
Total Customer Revenue	Total Customer Revenue	839		109		2		950		1,963		726		13		2,702		Total Customer Revenue		591		395		1		987
Other revenue	Other revenue	15		1		—		16		22		2		—		24		Other revenue		17		1		—		18
Total operating revenue	Total operating revenue	$	854	$	110	$	2	$	966	$	1,985	$	728	$	13	$	2,726	Total operating revenue		$	608	$	396	$	1	$	1,005


		For the Three-Month Period Ended September 30, 2020								For the Nine-Month Period Ended September 30, 2020									For the Three-Month Period Ended March 31, 2021
		Electric		Natural Gas		Other		Total		Electric		Natural Gas		Other		Total				Electric		Natural Gas		Other		Total
Customer Revenue:	Customer Revenue:																	Customer Revenue:
Retail:	Retail:																	Retail:
Residential	Residential	$	241	$	46	$	—	$	287	$	555	$	233	$	—	$	788	Residential		$	161	$	308	$	—	$	469
Commercial	Commercial	99		13		—		112		242		71		—		313		Commercial		71		129		—		200
Industrial	Industrial	280		2		—		282		640		9		—		649		Industrial		190		12		—		202
Natural gas transportation services	Natural gas transportation services	—		8		—		8		—		26		—		26		Natural gas transportation services		—		10		—		10
Other retail(1)	Other retail(1)	42		1		—		43		103		2		—		105		Other retail(1)		30		1		—		31
Total retail	Total retail	662		70		—		732		1,540		341		—		1,881		Total retail		452		460		—		912
Wholesale	Wholesale	46		10		—		56		116		41		—		157		Wholesale		74		51		—		125
Multi-value transmission projects	Multi-value transmission projects	14		—		—		14		47		—		—		47		Multi-value transmission projects		15		—		—		15
Other Customer Revenue	Other Customer Revenue	—		—		4		4		—		—		5		5		Other Customer Revenue		—		—		10		10
Total Customer Revenue	Total Customer Revenue	722		80		4		806		1,703		382		5		2,090		Total Customer Revenue		541		511		10		1,062
Other revenue	Other revenue	6		—		—		6		14		2		—		16		Other revenue		4		1		—		5
Total operating revenue	Total operating revenue	$	728	$	80	$	4	$	812	$	1,717	$	384	$	5	$	2,106	Total operating revenue		$	545	$	512	$	10	$	1,067

(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.

9779

~~(11)~~(9) Segment Information

MidAmerican Energy has identified 2 reportable segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost.

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


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021
Operating revenue:	Operating revenue:									Operating revenue:
Regulated electric	Regulated electric	$	854	$	728	$	1,985	$	1,717	Regulated electric		$	608	$	545
Regulated natural gas	Regulated natural gas	110		80		728		384		Regulated natural gas		396		512
Other	Other	2		4		13		5		Other		1		10
Total operating revenue	Total operating revenue	$	966	$	812	$	2,726	$	2,106	Total operating revenue		$	1,005	$	1,067

Operating income:	Operating income:									Operating income:
Regulated electric	Regulated electric	$	289	$	238	$	401	$	398	Regulated electric		$	51	$	9
Regulated natural gas	Regulated natural gas	(2)		(6)		37		40		Regulated natural gas		49		39

Total operating income	Total operating income	287		232		438		438		Total operating income		100		48
Interest expense	Interest expense	(76)		(74)		(224)		(224)		Interest expense		(78)		(74)
Allowance for borrowed funds	Allowance for borrowed funds	4		5		8		12		Allowance for borrowed funds		4		2
Allowance for equity funds	Allowance for equity funds	11		16		25		33		Allowance for equity funds		15		6
Other, net	Other, net	8		14		34		30		Other, net		(3)		11
Income before income tax benefit		$	234	$	193	$	281	$	289
Income (loss) before income tax benefit										Income (loss) before income tax benefit		$	38	$	(7)


		As of					As of
		September 30, 2021		December 31, 2020			March 31, 2022		December 31, 2021
Assets:	Assets:					Assets:
Regulated electric	Regulated electric	$	21,063	$	19,892	Regulated electric	$	21,613	$	21,385
Regulated natural gas	Regulated natural gas	1,874		1,544		Regulated natural gas	1,737		1,871
Other	Other	7		1		Other	1		1
Total assets	Total assets	$	22,944	$	21,437	Total assets	$	23,351	$	23,257

9880

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers and Member of

MidAmerican Funding, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of ~~September 30, 2021,~~March 31, 2022, the related consolidated statements of operations, ~~and~~ changes in member's equity, ~~for the three-month~~ and ~~nine-month periods ended September 30, 2021 and 2020, and of~~ cash flows for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 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,~~2021, 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,~~25, 2022, 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,~~2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of MidAmerican Funding's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to MidAmerican Funding in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

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

/s/ Deloitte & Touche LLP

Des Moines, Iowa

~~November 5, 2021~~April 29, 2022

9981

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


		As of					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	542	$	39	Cash and cash equivalents	$	132	$	233
Trade receivables, net	Trade receivables, net	555		234		Trade receivables, net	468		526

Income tax receivable						Income tax receivable	299		80
Inventories	Inventories	244		278		Inventories	185		234
Other current assets	Other current assets	143		74		Other current assets	187		123
Total current assets	Total current assets	1,484		625		Total current assets	1,271		1,196

Property, plant and equipment, net	Property, plant and equipment, net	19,774		19,279		Property, plant and equipment, net	20,345		20,302
Goodwill	Goodwill	1,270		1,270		Goodwill	1,270		1,270
Regulatory assets	Regulatory assets	479		392		Regulatory assets	492		473
Investments and restricted investments	Investments and restricted investments	977		913		Investments and restricted investments	987		1,028
Other assets	Other assets	234		232		Other assets	261		262

Total assets	Total assets	$	24,218	$	22,711	Total assets	$	24,626	$	24,531

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

~~100~~82

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


		As of					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
LIABILITIES AND MEMBER'S EQUITY	LIABILITIES AND MEMBER'S EQUITY					LIABILITIES AND MEMBER'S EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	$	347	$	408	Accounts payable	$	429	$	531
Accrued interest	Accrued interest	90		83		Accrued interest	89		89
Accrued property, income and other taxes	Accrued property, income and other taxes	242		161		Accrued property, income and other taxes	144		158
Note payable to affiliate	Note payable to affiliate	190		177		Note payable to affiliate	197		189

Current portion of long-term debt						Current portion of long-term debt	7		—
Other current liabilities	Other current liabilities	226		183		Other current liabilities	145		146
Total current liabilities	Total current liabilities	1,095		1,012		Total current liabilities	1,011		1,113

Long-term debt	Long-term debt	7,956		7,450		Long-term debt	7,959		7,961
Regulatory liabilities	Regulatory liabilities	943		1,111		Regulatory liabilities	1,057		1,080
Deferred income taxes	Deferred income taxes	3,405		3,052		Deferred income taxes	3,371		3,387
Asset retirement obligations	Asset retirement obligations	677		709		Asset retirement obligations	723		714
Other long-term liabilities	Other long-term liabilities	495		458		Other long-term liabilities	463		475
Total liabilities	Total liabilities	14,571		13,792		Total liabilities	14,584		14,730

Commitments and contingencies (Note 9)		0		0
Commitments and contingencies (Note 7)						Commitments and contingencies (Note 7)	0		0

Member's equity:	Member's equity:					Member's equity:
Paid-in capital	Paid-in capital	1,679		1,679		Paid-in capital	1,679		1,679
Retained earnings	Retained earnings	7,968		7,240		Retained earnings	8,363		8,122

Total member's equity	Total member's equity	9,647		8,919		Total member's equity	10,042		9,801

Total liabilities and member's equity	Total liabilities and member's equity	$	24,218	$	22,711	Total liabilities and member's equity	$	24,626	$	24,531

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

~~101~~83

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021
Operating revenue:	Operating revenue:									Operating revenue:
Regulated electric	Regulated electric	$	854	$	728	$	1,985	$	1,717	Regulated electric		$	608	$	545
Regulated natural gas and other	Regulated natural gas and other	112		84		741		397		Regulated natural gas and other		397		522
Total operating revenue	Total operating revenue	966		812		2,726		2,114		Total operating revenue		1,005		1,067

Operating expenses:	Operating expenses:									Operating expenses:
Cost of fuel and energy	Cost of fuel and energy	163		115		417		266		Cost of fuel and energy		125		151
Cost of natural gas purchased for resale and other	Cost of natural gas purchased for resale and other	64		40		553		211		Cost of natural gas purchased for resale and other		298		432
Operations and maintenance	Operations and maintenance	200		212		577		560		Operations and maintenance		192		193
Depreciation and amortization	Depreciation and amortization	218		180		634		531		Depreciation and amortization		250		207
Property and other taxes	Property and other taxes	34		33		107		102		Property and other taxes		40		36
Total operating expenses	Total operating expenses	679		580		2,288		1,670		Total operating expenses		905		1,019

Operating income	Operating income	287		232		438		444		Operating income		100		48

Other income (expense):	Other income (expense):									Other income (expense):
Interest expense	Interest expense	(81)		(79)		(237)		(238)		Interest expense		(82)		(78)
Allowance for borrowed funds	Allowance for borrowed funds	4		5		8		12		Allowance for borrowed funds		4		2
Allowance for equity funds	Allowance for equity funds	11		16		25		33		Allowance for equity funds		15		6
Other, net	Other, net	8		15		34		30		Other, net		(4)		10
Total other income (expense)	Total other income (expense)	(58)		(43)		(170)		(163)		Total other income (expense)		(67)		(60)

Income before income tax benefit		229		189		268		281
Income (loss) before income tax benefit										Income (loss) before income tax benefit		33		(12)
Income tax benefit	Income tax benefit	(144)		(148)		(460)		(414)		Income tax benefit		(208)		(156)

Net income	Net income	$	373	$	337	$	728	$	695	Net income		$	241	$	144

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

~~102~~84

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

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

(Amounts in millions)

Paid-in
Capital Retained
Earnings Total Member's
Equity
Balance, June 30, 2020 $ 1,679 $ 6,780 $ 8,459
Net income — 337 337
Balance, September 30, 2020 $ 1,679 $ 7,117 $ 8,796
Balance, December 31, 2019 $ 1,679 $ 6,422 $ 8,101
Net income — 695 695
Balance, September 30, 2020 $ 1,679 $ 7,117 $ 8,796
Balance, June 30, 2021 $ 1,679 $ 7,594 $ 9,273
Net income — 373 373
Other equity transactions — 1 1
Balance, September 30, 2021 $ 1,679 $ 7,968 $ 9,647
Balance, December 31, 2020 $ 1,679 $ 7,240 $ 8,919
Net income — 728 728
Balance, September 30, 2021 $ 1,679 $ 7,968 $ 9,647


	Paid-in Capital		Retained Earnings		Total Member's Equity






Balance, December 31, 2020	$	1,679	$	7,240	$	8,919
Net income	—		144		144

Balance, March 31, 2021	$	1,679	$	7,384	$	9,063






Balance, December 31, 2021	$	1,679	$	8,122	$	9,801
Net income	—		241		241

Balance, March 31, 2022	$	1,679	$	8,363	$	10,042

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

~~103~~85

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


		Nine-Month Periods					Three-Month Periods
		Ended September 30,					Ended March 31,
		2021		2020			2022		2021
Cash flows from operating activities:	Cash flows from operating activities:					Cash flows from operating activities:
Net income	Net income	$	728	$	695	Net income	$	241	$	144
Adjustments to reconcile net income to net cash flows from operating activities:	Adjustments to reconcile net income to net cash flows from operating activities:					Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	Depreciation and amortization	634		531		Depreciation and amortization	250		207
Amortization of utility plant to other operating expenses	Amortization of utility plant to other operating expenses	26		25		Amortization of utility plant to other operating expenses	9		8
Allowance for equity funds	Allowance for equity funds	(25)		(33)		Allowance for equity funds	(15)		(6)
Deferred income taxes and investment tax credits, net	Deferred income taxes and investment tax credits, net	121		79		Deferred income taxes and investment tax credits, net	16		153

Settlements of asset retirement obligations	Settlements of asset retirement obligations	(51)		(55)		Settlements of asset retirement obligations	(7)		(4)
Other, net	Other, net	42		(1)		Other, net	10		(17)
Changes in other operating assets and liabilities:	Changes in other operating assets and liabilities:					Changes in other operating assets and liabilities:
Trade receivables and other assets	Trade receivables and other assets	(331)		(16)		Trade receivables and other assets	43		(298)
Inventories	Inventories	34		(40)		Inventories	49		46

Pension and other postretirement benefit plans	Pension and other postretirement benefit plans	2		(17)		Pension and other postretirement benefit plans	3		1
Accrued property, income and other taxes, net	Accrued property, income and other taxes, net	80		(13)		Accrued property, income and other taxes, net	(245)		(332)
Accounts payable and other liabilities	Accounts payable and other liabilities	16		44		Accounts payable and other liabilities	(1)		6
Net cash flows from operating activities	Net cash flows from operating activities	1,276		1,199		Net cash flows from operating activities	353		(92)

Cash flows from investing activities:	Cash flows from investing activities:					Cash flows from investing activities:
Capital expenditures	Capital expenditures	(1,266)		(1,341)		Capital expenditures	(459)		(298)
Purchases of marketable securities	Purchases of marketable securities	(166)		(251)		Purchases of marketable securities	(105)		(52)
Proceeds from sales of marketable securities	Proceeds from sales of marketable securities	163		244		Proceeds from sales of marketable securities	102		47

Other, net	Other, net	(7)		10		Other, net	1		—
Net cash flows from investing activities	Net cash flows from investing activities	(1,276)		(1,338)		Net cash flows from investing activities	(461)		(303)

Cash flows from financing activities:	Cash flows from financing activities:					Cash flows from financing activities:

Proceeds from long-term debt		492		—

Repayments of long-term debt	Repayments of long-term debt	(1)		—		Repayments of long-term debt	(1)		—
Net change in note payable to affiliate	Net change in note payable to affiliate	13		13		Net change in note payable to affiliate	8		7
Net proceeds from short-term debt						Net proceeds from short-term debt	—		387

Other, net		(1)		(1)
Net cash flows from financing activities	Net cash flows from financing activities	503		12		Net cash flows from financing activities	7		394

Net change in cash and cash equivalents and restricted cash and cash equivalents	Net change in cash and cash equivalents and restricted cash and cash equivalents	503		(127)		Net change in cash and cash equivalents and restricted cash and cash equivalents	(101)		(1)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	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 beginning of period	240		46
Cash and cash equivalents and restricted cash and cash equivalents at end of period	Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	549	$	204	Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	139	$	45

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

~~104~~86

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

MidAmerican Funding, LLC ("MidAmerican Funding") is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa, that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). MidAmerican Funding's direct, wholly owned subsidiary is MHC Inc. ("MHC"), which constitutes substantially all of MidAmerican Funding's assets, liabilities and business activities except those related to MidAmerican Funding's long-term debt securities. MHC conducts no business other than the ownership of its subsidiaries. MHC's principal subsidiary is MidAmerican Energy Company ("MidAmerican Energy"), a public utility with electric and natural gas operations, and its direct, wholly owned nonregulated subsidiary is Midwest Capital Group, Inc.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of ~~September 30, 2021,~~March 31, 2022, and for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2021~~March 31, 2022 and 2020. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and nine-month periods ended September 30, 2021 and 2020.2021. The results of operations for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2021,~~March 31, 2022, 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,~~2021, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in MidAmerican Funding's assumptions regarding significant accounting estimates and policies during the ~~nine-month~~three-month period ended ~~September 30, 2021.~~March 31, 2022.

(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, ~~United States~~U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents ~~as of September 30, 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 September 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					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021

Cash and cash equivalents	Cash and cash equivalents	$	542	$	39	Cash and cash equivalents	$	132	$	233
Restricted cash and cash equivalents in other current assets	Restricted cash and cash equivalents in other current assets	7		7		Restricted cash and cash equivalents in other current assets	7		7
Total cash and cash equivalents and restricted cash and cash equivalents	Total cash and cash equivalents and restricted cash and cash equivalents	$	549	$	46	Total cash and cash equivalents and restricted cash and cash equivalents	$	139	$	240

~~105~~87

(3) Property, Plant and Equipment, Net

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

(4) ~~Regulatory Matters~~Income Taxes

~~Refer~~The effective income tax rate for the three-month period ended March 31, 2021, is 1,300% and results from a $156 million income tax benefit associated with a $12 million pretax loss. The $156 million income tax benefit is primarily comprised of a $3 million benefit (21%) from the application of the statutory income tax rate to ~~Note 4~~the pretax loss and a $168 million benefit (1,400%) from income tax credits, partially offset by a $13 million expense (108%) from the effects 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~~ratemaking.

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


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021

Federal statutory income tax rate	Federal statutory income tax rate	21	%	21	%	21	%	21	%	Federal statutory income tax rate		21	%	21	%
Income tax credits	Income tax credits	(45)		(56)		(150)		(126)		Income tax credits		(618)		1,400
State income tax, net of federal income tax impacts	State income tax, net of federal income tax impacts	(27)		(27)		(29)		(30)		State income tax, net of federal income tax impacts		(24)		(8)
Effects of ratemaking	Effects of ratemaking	(12)		(16)		(14)		(13)		Effects of ratemaking		(9)		(108)
Other, net	Other, net	—		—		—		1		Other, net		—		(5)
Effective income tax rate	Effective income tax rate	(63)	%	(78)	%	(172)	%	(147)	%	Effective income tax rate		(630)	%	1,300	%

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 ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ totaled ~~$103~~$203 million and ~~$105 million, respectively, and for the nine-month periods ended September 30, 2021 and 2020 totaled $400 million and $352~~$151 million, respectively.

Berkshire Hathaway includes BHE and subsidiaries in its ~~United States~~U.S. 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~~made no cash payments for income tax ~~from~~to BHE ~~totaling $681 million and $504 million~~ for each of the ~~nine-month~~three-month periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020, respectively.~~2021.

~~(7)~~(5) Employee Benefit Plans

Refer to Note 75 of MidAmerican Energy's Notes to Financial Statements.

~~106~~88

~~(8)~~(6) Fair Value Measurements

Refer to Note 86 of MidAmerican Energy's Notes to Financial Statements. MidAmerican Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Funding's long-term debt (in millions):

As of September 30, 2021 As of December 31, 2020
Carrying
Value Fair
Value Carrying
Value Fair
Value
Long-term debt $ 7,956 $ 9,417 $ 7,450 $ 9,466


	As of March 31, 2022				As of December 31, 2021
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	7,966	$	8,480	$	7,961	$	9,350

~~(9)~~(7) 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 97 of MidAmerican Energy's Notes to Financial Statements.

~~(10)~~(8) Revenue from Contracts with Customers

Refer to Note 108 of MidAmerican Energy's Notes to Financial Statements. Additionally, MidAmerican Funding had other Accounting Standards Codification Topic 606 revenue of $— million for the three-month periods ended September 30, 2021 and 2020, respectively, and $— million and $8 million for the nine-month periods ended September 30, 2021 and 2020, respectively.

~~107~~89

~~(11)~~(9) Segment Information

MidAmerican Funding has identified 2 reportable segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. "Other" in the tables below consists of the financial results and assets of nonregulated operations, MHC and MidAmerican Funding.

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


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021
Operating revenue:	Operating revenue:									Operating revenue:
Regulated electric	Regulated electric	$	854	$	728	$	1,985	$	1,717	Regulated electric		$	608	$	545
Regulated natural gas	Regulated natural gas	110		80		728		384		Regulated natural gas		396		512
Other	Other	2		4		13		13		Other		1		10
Total operating revenue	Total operating revenue	$	966	$	812	$	2,726	$	2,114	Total operating revenue		$	1,005	$	1,067

Operating income:	Operating income:									Operating income:
Regulated electric	Regulated electric	$	289	$	238	$	401	$	398	Regulated electric		$	51	$	9
Regulated natural gas	Regulated natural gas	(2)		(6)		37		40		Regulated natural gas		49		39
Other		—		—		—		6

Total operating income	Total operating income	287		232		438		444		Total operating income		100		48
Interest expense	Interest expense	(81)		(79)		(237)		(238)		Interest expense		(82)		(78)
Allowance for borrowed funds	Allowance for borrowed funds	4		5		8		12		Allowance for borrowed funds		4		2
Allowance for equity funds	Allowance for equity funds	11		16		25		33		Allowance for equity funds		15		6
Other, net	Other, net	8		15		34		30		Other, net		(4)		10
Income before income tax benefit		$	229	$	189	$	268	$	281
Income (loss) before income tax benefit										Income (loss) before income tax benefit		$	33	$	(12)


		As of					As of
		September 30, 2021		December 31, 2020			March 31, 2022		December 31, 2021
Assets(1):	Assets(1):					Assets(1):
Regulated electric	Regulated electric	$	22,254	$	21,083	Regulated electric	$	22,804	$	22,576
Regulated natural gas	Regulated natural gas	1,953		1,623		Regulated natural gas	1,816		1,950
Other	Other	11		5		Other	6		5
Total assets	Total assets	$	24,218	$	22,711	Total assets	$	24,626	$	24,531


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

~~108~~90

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

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of MidAmerican Funding and its subsidiaries and MidAmerican Energy during the periods included herein. Information in Management's Discussion and Analysis related to MidAmerican Energy, whether or not segregated, also relates to MidAmerican Funding. Information related to other subsidiaries of MidAmerican Funding pertains only to the discussion of the financial condition and results of operations of MidAmerican Funding. Where necessary, discussions have been segregated under the heading "MidAmerican Funding" to allow the reader to identify information applicable only to MidAmerican Funding. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with MidAmerican Funding's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements and MidAmerican Energy's historical unaudited Financial Statements and Notes to Financial Statements in Part I, Item 1 of this Form 10-Q. MidAmerican Funding's and MidAmerican Energy's actual results in the future could differ significantly from the historical results.

Results of Operations for the ~~Third~~First Quarter of 2022 and ~~First Nine Months of~~ 2021 ~~and 2020~~

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the ~~third~~first quarter of ~~2021~~2022 was ~~$377~~$244 million, an increase of ~~$37~~$97 million, or ~~11%~~66%, compared to ~~2020~~2021, primarily due to higher electric utility margin of ~~$78~~$89 million, ~~lower operations and maintenance expenses of $12 million due to storm restoration costs in 2020 and~~ higher natural gas utility margin of $6$18 million, ~~partially~~higher income tax benefit of $52 million and higher allowances for equity and borrowed funds of $11 million, offset by higher depreciation and amortization expense of ~~$38~~$43 million, unfavorable other, net of $14 million, lower ~~allowance for equity funds used during construction~~nonregulated utility margins of $5$9 million, ~~due to lower construction work-in-progress balances, unfavorable changes in the cash surrender value~~higher property and other taxes of corporate-owned life insurance policies and lower income tax benefit due to higher pretax income. Electric utility margin increased due to higher wholesale utility margin primarily reflecting higher market prices$4 million and higher interest expense of $4 million. Electric retail ~~utility margin mainly from higher volumes. Depreciation and amortization expense~~customer volumes increased ~~due to additional assets placed in-service and the impact of regulatory mechanisms.~~

~~MidAmerican Energy's net income for the first nine months of 2021 was $737 million, an increase of $37 million, or 5%, compared to 2020,~~6% primarily due to higher ~~electric utility margin~~usage for certain industrial customers and the favorable impact of ~~$117 million,~~weather. Wholesale electricity sales volumes increased 31% due to favorable market conditions. Energy generated increased 17% primarily due to greater wind-powered generation, resulting in a ~~favorable income tax benefit of $45 million and favorable changes~~10% decrease in the ~~cash surrender value~~average per-unit cost of ~~corporate-owned life insurance policies, partially offset by higher depreciation and amortization expense of $103 million, higher operations and maintenance expenses, including~~energy generated. Natural gas retail customer volumes increased ~~costs associated with additional wind-powered generating facilities placed in-service and higher natural gas distribution costs, partially offset by lower electric distribution costs~~8% due to storm restoration costs in 2020 and lower allowances for equity and borrowed funds of $12 million. Electric utility margin increased due to higher retail utility margin, primarily from higher volumes and higher recoveries through bill riders (offset in operations and maintenance and income tax benefit), and higher wholesale utility margin from higher wholesale volumes. Thethe favorable income tax benefit was due to higher PTCs recognized from higher wind-powered generation, driven primarily by new wind projects placed in-service. Depreciation and amortization expense increased due to additional assets placed in-service and the impact of ~~regulatory mechanisms.~~

On October 29, 2021, the IUB issued an order extending for three years the depreciation deferral regulatory mechanism approved by the IUB in MidAmerican Energy's 2013 electric rate case. In December 2020, the cumulative deferral reached the limit previously set by the IUB, resulting in higher depreciation expense for the third quarter and first nine months of 2021. With the extension of the deferral, annual depreciation expense will be approximately $50 million lower in years 2021 through 2023 than would have been recognized absent the order. The annual amount of the deferral for 2021 will be recognized in the fourth quarter.weather.

MidAmerican Funding -

MidAmerican Funding's net income for the ~~third~~first quarter of ~~2021~~2022 was ~~$373~~$241 million, an increase of ~~$36~~$97 million, or ~~11%~~67%, compared to ~~2020. MidAmerican Funding's net income for the first nine months of 2021 was $728 million, an increase of $33 million, or 5%, compared to 2020.~~2021. The variances in net income were primarily due to the changes in MidAmerican Energy's earnings discussed above.

~~109~~

Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as regulated electric operating revenue less cost of fuel and energy, which are captions presented on the Statements of Operations. Natural gas utility margin is calculated as regulated natural gas operating revenue less regulated cost of natural gas purchased for resale, which are included in regulated natural gas and other and cost of natural gas purchased for resale and other, respectively, on the Statements of Operations.

MidAmerican Energy's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms, and as a result, changes in MidAmerican Energy's expense included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to MidAmerican Energy's operating income (in millions):


		Third Quarter								First Nine Months									First Quarter
		2021		2020		Change				2021		2020		Change						2022			2021			Change
Electric utility margin:	Electric utility margin:																	Electric utility margin:
Operating revenue	Operating revenue	$	854	$	728	$	126	17	%	$	1,985	$	1,717	$	268	16	%	Operating revenue			$	608		$	545		$	63	12	%
Cost of fuel and energy	Cost of fuel and energy	163		115		48		42		417		266		151		57		Cost of fuel and energy			125			151			(26)		(17)
Electric utility margin	Electric utility margin	691		613		78		13	%	1,568		1,451		117		8	%	Electric utility margin			483			394			89		23	%

Natural gas utility margin:	Natural gas utility margin:																	Natural gas utility margin:
Operating revenue	Operating revenue	110		80		30		38	%	728		384		344		*		Operating revenue			396			512			(116)		(23)	%
Natural gas purchased for resale	Natural gas purchased for resale	63		39		24		62		552		209		343		*		Natural gas purchased for resale			298			432			(134)		(31)
Natural gas utility margin	Natural gas utility margin	47		41		6		15	%	176		175		1		1	%	Natural gas utility margin			98			80			18		23	%

Utility margin	Utility margin	738		654		84		13	%	1,744		1,626		118		7	%	Utility margin			581			474			107		23	%

Other operating revenue	Other operating revenue	2		4		(2)		(50)	%	13		5		8		*		Other operating revenue			1			10			(9)		(90)	%
Other cost of sales		1		1		—		—		1		1		—		*

Operations and maintenance	Operations and maintenance	200		212		(12)		(6)		577		559		18		3		Operations and maintenance			192			193			(1)		(1)
Depreciation and amortization	Depreciation and amortization	218		180		38		21		634		531		103		19		Depreciation and amortization			250			207			43		21
Property and other taxes	Property and other taxes	34		33		1		3		107		102		5		5		Property and other taxes			40			36			4		11

Operating income	Operating income	$	287	$	232	$	55	24	%	$	438	$	438	$	—	—	%	Operating income			$	100		$	48		$	52	*

* Not meaningful.

~~110~~92

Electric Utility Margin

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

Third Quarter First Nine Months
2021 2020 Change 2021 2020 Change
Utility margin (in millions):
Operating revenue $ 854 $ 728 $ 126 17 % $ 1,985 $ 1,717 $ 268 16 %
Cost of fuel and energy 163 115 48 42 417 266 151 57
Utility margin $ 691 $ 613 $ 78 13 % $ 1,568 $ 1,451 $ 117 8 %
Sales (GWhs):
Residential 2,060 2,053 7 — % 5,284 5,226 58 1 %
Commercial 1,039 1,013 26 3 2,871 2,800 71 3
Industrial 4,106 3,758 348 9 11,981 10,884 1,097 10
Other 423 398 25 6 1,194 1,117 77 7
Total retail 7,628 7,222 406 6 21,330 20,027 1,303 7
Wholesale 3,420 2,541 879 35 11,343 7,535 3,808 51
Total sales 11,048 9,763 1,285 13 % 32,673 27,562 5,111 19 %
Average number of retail customers (in thousands) 805 796 9 1 % 803 794 9 1 %
Average revenue per MWh:
Retail $ 96.42 $ 91.62 $ 4.80 5 % $ 79.90 $ 76.92 $ 2.98 4 %
Wholesale $ 27.07 $ 17.34 $ 9.73 56 % $ 18.22 $ 14.54 $ 3.68 25 %
Heating degree days 21 96 (75) (78) % 3,820 3,698 122 3 %
Cooling degree days 870 795 75 9 % 1,296 1,155 141 12 %
Sources of energy (GWhs)(1):
Wind and other(2)
4,164 4,274 (110) (3) % 16,163 14,268 1,895 13 %
Coal 4,609 3,169 1,440 45 10,302 5,771 4,531 79
Nuclear 1,007 1,000 7 1 2,911 2,902 9 —
Natural gas 503 324 179 55 982 517 465 90
Total energy generated 10,283 8,767 1,516 17 30,358 23,458 6,900 29
Energy purchased 1,038 1,166 (128) (11) 2,898 4,592 (1,694) (37)
Total 11,321 9,933 1,388 14 % 33,256 28,050 5,206 19 %
Average cost of energy per MWh:
Energy generated(3)
$ 9.81 $ 7.34 $ 2.47 34 % $ 7.48 $ 5.53 $ 1.95 35 %
Energy purchased $ 60.32 $ 43.32 $ 17.00 39 % $ 65.60 $ 29.67 $ 35.93 *

* Not meaningful.


	First Quarter
		2022	2021		Change
Utility margin (in millions):
Operating revenue			$	608	$	545	$	63	12	%
Cost of fuel and energy			125		151		(26)		(17)
Utility margin			$	483	$	394	$	89	23	%

Sales (GWhs):
Residential			1,853		1,738		115		7	%
Commercial			1,013		938		75		8
Industrial			3,979		3,819		160		4
Other			403		370		33		9
Total retail			7,248		6,865		383		6
Wholesale			5,325		4,051		1,274		31
Total sales			12,573		10,916		1,657		15	%

Average number of retail customers (in thousands)			810		801		9		1	%

Average revenue per MWh:
Retail			$	65.10	$	65.82	$	(0.72)	(1)	%
Wholesale			$	20.65	$	16.64	$	4.01	24	%

Heating degree days			3,315		3,211		104		3	%


Sources of energy (GWhs)(1):
Wind and other(2)			8,290		6,122		2,168		35	%
Coal			2,359		2,902		(543)		(19)
Nuclear			920		895		25		3
Natural gas			234		143		91		64
Total energy generated			11,803		10,062		1,741		17
Energy purchased			962		1,018		(56)		(6)
Total			12,765		11,080		1,685		15	%

Average cost of energy per MWh:
Energy generated(3)			$	5.56	$	6.15	$	(0.59)	(10)	%
Energy purchased			$	62.04	$	87.45	$	(25.41)	(29)	%

(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~~renewable energy credits or other environmental commodities.

(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.

~~111~~93

Natural Gas Utility Margin

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


		Third Quarter								First Nine Months									First Quarter
		2021		2020		Change				2021		2020		Change						2022	2021		Change
Utility margin (in millions):	Utility margin (in millions):																	Utility margin (in millions):
Operating revenue	Operating revenue	$	110	$	80	$	30	38	%	$	728	$	384	$	344	90	%	Operating revenue			$	396	$	512	$	(116)	(23)	%
Natural gas purchased for resale	Natural gas purchased for resale	63		39		24		62		552		209		343		*		Natural gas purchased for resale			298		432		(134)		(31)
Utility margin	Utility margin	$	47	$	41	$	6	15	%	$	176	$	175	$	1	1	%	Utility margin			$	98	$	80	$	18	23	%

Throughput (000's Dths):	Throughput (000's Dths):																	Throughput (000's Dths):
Residential	Residential	2,689		3,190		(501)		(16)	%	34,243		34,146		97		—	%	Residential			27,099		25,282		1,817		7	%
Commercial	Commercial	1,511		1,671		(160)		(10)		16,255		15,634		621		4		Commercial			12,460		11,733		727		6
Industrial	Industrial	1,110		1,105		5		—		3,616		3,687		(71)		(2)		Industrial			1,844		1,437		407		28
Other	Other	4		6		(2)		(33)		52		54		(2)		(4)		Other			35		37		(2)		(5)
Total retail sales	Total retail sales	5,314		5,972		(658)		(11)		54,166		53,521		645		1		Total retail sales			41,438		38,489		2,949		8
Wholesale sales	Wholesale sales	6,365		5,622		743		13		22,955		24,391		(1,436)		(6)		Wholesale sales			12,232		10,773		1,459		14
Total sales	Total sales	11,679		11,594		85		1		77,121		77,912		(791)		(1)		Total sales			53,670		49,262		4,408		9
Natural gas transportation service	Natural gas transportation service	26,789		24,973		1,816		7		83,282		82,092		1,190		1		Natural gas transportation service			31,313		29,640		1,673		6
Total throughput	Total throughput	38,468		36,567		1,901		5	%	160,403		160,004		399		—	%	Total throughput			84,983		78,902		6,081		8	%

Average number of retail customers (in thousands)	Average number of retail customers (in thousands)	776		769		7		1	%	776		770		6		1	%	Average number of retail customers (in thousands)			785		777		8		1	%

Average revenue per retail Dth sold	Average revenue per retail Dth sold	$	14.21	$	10.43	$	3.78	36	%	$	11.20	$	5.91	$	5.29	90	%	Average revenue per retail Dth sold			$	7.84	$	11.70	$	(3.86)	(33)	%

Heating degree days	Heating degree days	28		122		(94)		(77)	%	3,954		3,899		55		1	%	Heating degree days			3,485		3,301		184		6	%

Average cost of natural gas per retail Dth sold	Average cost of natural gas per retail Dth sold	$	7.09	$	4.74	$	2.35	50	%	$	8.47	$	3.12	$	5.35	*		Average cost of natural gas per retail Dth sold			$	5.80	$	9.87	$	(4.07)	(41)	%

Combined retail and wholesale average cost of natural gas per Dth sold	Combined retail and wholesale average cost of natural gas per Dth sold	$	5.42	$	3.32	$	2.10	63	%	$	7.16	$	2.68	$	4.48	*		Combined retail and wholesale average cost of natural gas per Dth sold			$	5.55	$	8.76	$	(3.21)	(37)	%

* Not meaningful.

Quarter Ended ~~September 30, 2021~~March 31, 2022 Compared to Quarter Ended ~~September 30, 2020~~March 31, 2021

MidAmerican Energy -

Electric utility margin increased ~~$78~~$89 million, or ~~13%~~23%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020, primarily~~2021, due to:

•a ~~$41~~$64 million increase in wholesale utility margin due to higher ~~margin~~margins per unit of ~~$35~~$58 million, reflecting lower energy costs and higher market prices, and higher volumes of ~~34.6%~~31.4%; and

•a ~~$36~~$25 million increase in retail utility margin primarily due to ~~$20~~$17 million from higher ~~usage for certain industrial customers; $6 million from liquidated damages related to a wind-powered generation project; $5~~customer usage; $9 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); and $4$1 million from the favorable impact of ~~weather.~~weather; partially offset by $2 million due to price impacts from changes in sales mix. Retail customer volumes increased 5.6%.

Natural gas utility margin increased $6$18 million, or ~~15%~~23%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to:

•an $8 million increase from ~~higher average prices primarily due to the timing of recoveries through a capital tracker mechanism; partially offset by~~

•~~a $3 million decrease from the unfavorable impact of weather.~~

~~112~~

~~Operations and maintenance~~ ~~decreased $12 million, or 6%, for the third quarter of 2021 compared to 2020 primarily due to~~ lower electric distribution maintenance costs of $21 million due to storm restoration costs in 2020, partially offset by higher other generation operations expenses of $4 million due to additional wind turbines and easements and higher transmission operations costs from MISO of $3 million.

~~Depreciation and amortization~~ for the third quarter of 2021 increased $38 million, or 21%, compared to 2020 primarily due to wind-powered generating facilities and other plant placed in-service, $13 million from a regulatory mechanism deferring certain depreciation expense in 2020 and $9 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects. Refer to "Overview" above for a discussion of an IUB order extending the regulatory mechanism deferring certain depreciation expense.

~~Allowance for borrowed and equity funds~~ ~~decreased $6 million, or 29%, for the third 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 43%, for the third quarter of 2021 compared to 2020 primarily due to lower cash surrender values of corporate-owned life insurance policies.~~

~~Income tax benefit~~ decreased $4 million, or 3%, for the third quarter of 2021 compared to 2020, and the effective tax rate was (61)% for 2021 and (76)% for 2020. The change in the effective tax rates for 2021 compared to 2020 was primarily due to a higher 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 third quarter of 2021 and 2020 totaled $103 million and $105 million, respectively.

~~MidAmerican Funding -~~

~~Income tax benefit~~ decreased $4 million, or 3%, for the third quarter of 2021 compared to 2020, and the effective tax rate was (63)% for 2021 and (78)% for 2020. The changes in the effective tax rates were due to the factors discussed for MidAmerican Energy.

~~First Nine Months of 2021 compared to First Nine Months of 2020~~

~~MidAmerican Energy -~~

~~Electric utility margin~~ ~~increased $117 million, or 8%, for the first nine months of 2021 compared to 2020, due to:~~

•a $90 million increase in retail utility margin primarily due to $42 million from higher usage for certain industrial customers; $17 million from the favorable impact of weather; $17 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); $7 million due to price impacts from changes in sales mix and $6 million from liquidated damages related to a wind-powered generation project. Retail customer volumes increased 6.5%; and

•~~a $29 million increase in wholesale utility margin due to higher volumes of 50.5%, partially offset by lower margins per unit of $10 million, reflecting higher energy costs; partially offset by~~

•~~a $2 million decrease in Multi-Value Projects transmission revenue.~~

~~Natural gas utility margin~~ ~~increased $1 million, or 1%, for the first nine months of 2021 compared to 2020 primarily due to:~~

•~~a $5 million increase in natural gas energy efficiency program revenue (offset in operations and maintenance expense); and~~

•~~a $2 million increase natural gas transportation margin, reflecting higher volumes; partially offset by~~

•~~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 $5 million increase from higher average prices primarily due to the timing of recoveries through a capital tracker mechanism; and

•a $4 million increase from the favorable impact of weather.

~~113~~94

~~Operations and maintenance~~ increased $18 million, or 3%, for the first nine months of 2021 compared to 2020 primarily due to higher other generation operations and maintenance expenses of $12 million due to additional wind turbines and easements, higher energy efficiency program expense of $9 million (offset in operating revenue), higher natural gas distribution costs of $6 million and higher transmission operations costs from MISO of $3 million, partially offset by lower electric distribution costs of $15 million due to storm restoration costs in 2020.

Depreciation and amortization for the first ~~nine months~~quarter of ~~2021~~2022 increased ~~$103~~$43 million, or ~~19%~~21%, compared to ~~2020~~2021 primarily due to $42 million from higher Iowa revenue sharing accruals, $7 million from wind-powered generating facilities and other plant placed in-service and ~~$39 million from a regulatory mechanism deferring certain depreciation expense in 2020 and $18~~$6 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation ~~projects. Refer to "Overview" above for~~projects, partially offset by $12 million from a ~~discussion of an IUB order extending the~~ regulatory mechanism deferring certain depreciation ~~expense.~~expense in 2022.

Allowance for borrowed and equity funds ~~decreased $12~~increased $11 million, or ~~27%~~138%, for the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to ~~lower~~higher construction work-in-progress balances related to ~~wind-powered~~wind- and solar-powered generation.

Other, net ~~increased $4~~decreased $14 million, or ~~13%~~127%, for the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to ~~higher~~unfavorable investment earnings, largely attributable to lower cash surrender values of corporate-owned life insurance policies, ~~partially offset by~~and higher non-service costs of postretirement employee benefit plans.

Income tax benefit increased ~~$45~~$52 million, or ~~11%~~34%, for the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~2020,~~2021, and the effective tax rate was ~~(162)~~(542)% for ~~2021~~2022 and ~~(142)%~~2,200% for ~~2020.~~2021. The change in the effective tax rates for ~~2021~~2022 compared to ~~2020~~2021 was primarily due to ~~the~~ higher PTCs, the timing of state income tax benefits and ~~a lower~~the effects of ratemaking, partially offset by higher pretax income. PTCs for the first ~~nine months~~quarter of 2022 and 2021 ~~and 2020~~ totaled ~~$400~~$203 million and ~~$352~~$151 million, respectively.

MidAmerican Funding -

Income tax benefit increased ~~$46~~$52 million, or ~~11%~~33%, for the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~2020,~~2021, and the effective tax rate was ~~(172)~~(630)% for ~~2021~~2022 and ~~(147)%~~1,300% for ~~2020.~~2021. The changes in the effective tax rates were principally due to the factors discussed for MidAmerican Energy.

~~114~~

Liquidity and Capital Resources

As of ~~September 30, 2021,~~March 31, 2022, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):


MidAmerican Energy:
Cash and cash equivalents	$	~~541~~131

Credit facilities, maturing 2022 and 2024	1,505
Less:

Tax-exempt bond support	(370)
Net credit facilities	1,135

MidAmerican Energy total net liquidity	$	~~1,676~~1,266

MidAmerican Funding:
MidAmerican Energy total net liquidity	$	~~1,676~~1,266
Cash and cash equivalents	1
MHC, Inc. credit facility, maturing 2022	4
MidAmerican Funding total net liquidity	$	~~1,681~~1,271

Operating Activities

MidAmerican Energy's net cash flows from operating activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ were ~~$1,290~~$360 million and ~~$1,209~~$(85) million, respectively. MidAmerican Funding's net cash flows from operating activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ were ~~$1,276~~$353 million and ~~$1,199~~$(92) million, respectively. Cash flows from operating activities reflect higher ~~income tax receipts and lower payments for the settlement of asset retirement obligations, partially offset by lower cash~~utility margins for MidAmerican Energy's regulated electric and natural gas businesses, ~~including delayed~~lower payments to vendors and lower derivative collateral posted, partially offset by higher interest expense. Higher utility margins are largely attributable to the recovery of higher natural gas costs incaused by the February 2021 ~~discussed below, and higher payments to vendors.~~

~~In February 2021, severe cold~~polar vortex 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 nine-month period ended September 30, 2021.event.

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

Investing Activities

MidAmerican Energy's net cash flows from investing activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ were ~~$(1,276)~~$(461) million and ~~$(1,339)~~$(303) million, respectively. MidAmerican Funding's net cash flows from investing activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ were ~~$(1,276)~~$(461) million and ~~$(1,338)~~$(303) million, respectively. Net cash flows from investing activities consist almost entirely of capital ~~expenditures, which decreased primarily due~~expenditures. Refer to ~~lower wind-powered generating facility construction~~"Future Uses of Cash" for further discussion of capital 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. ~~Other, net for 2020 reflects $9 million of proceeds from corporate-owned life insurance policies.~~

~~115~~

Financing Activities

MidAmerican Energy's net cash flows from financing activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ were ~~$489~~$— million and ~~$(1)~~$387 million, respectively. MidAmerican Funding's net cash flows from financing activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ were ~~$503~~$7 million and ~~$12~~$394 million, respectively. ~~Proceeds from long-term debt reflect~~Through its commercial paper program, MidAmerican ~~Energy's issuance~~Energy received $387 million in ~~July 2021 of $500 million of its 2.70% First Mortgage Bonds due August 2052.~~2021. MidAmerican Funding received ~~$13~~$8 million and $7 million in ~~2021~~2022 and ~~2020,~~2021, respectively, through its note payable with BHE.

Debt Authorizations and Related Matters

Short-term Debt

MidAmerican Energy has authority from the FERC to issue through April 2, ~~2022,~~2024, 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.

Long-term Debt and Preferred Stock

MidAmerican Energy currently has an effective automatic registration statement with the SEC to issue an indeterminate amount of long-term debt securities and preferred stock 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. Additionally, MidAmerican Energy has authority from the Illinois Commerce Commission through October 15, 2024, to issue $750 million of long-term debt securities for the purpose of refinancing $250 million of its 3.70% Senior notes due September 2023 and $500 million of its 2.40% Senior notes due October 2024.

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):


		Nine-Month Periods				Annual			Three-Month Periods				Annual
		Ended September 30,				Forecast			Ended March 31,				Forecast
		2020		2021		2021			2021		2022		2022

Wind generation	Wind generation	$	713	$	605	$	807	Wind generation	$	32	$	133	$	762
Electric distribution	Electric distribution	189		154		260		Electric distribution	46		54		260
Electric transmission	Electric transmission	132		105		194		Electric transmission	23		21		171
Solar generation	Solar generation	2		97		180		Solar generation	3		44		139
Other	Other	305		305		502		Other	194		207		681
Total	Total	$	1,341	$	1,266	$	1,943	Total	$	298	$	459	$	2,013

~~116~~

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 $275 million and $676~~totaling $3 million for the ~~nine-month periods~~three-month period ended ~~September 30, 2021 and 2020, respectively.~~March 31, 2022. Planned spending for the construction of additional wind-powered generating facilities totals ~~$73~~$142 million for the remainder of ~~2021 and includes 203 MWs of wind-powered generating facilities expected to be placed in-service in 2021.~~2022.

◦Repowering of wind-powered generating facilities ~~totaled $274~~totaling $120 million and ~~$25~~$24 million for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ respectively. Planned spending for the repowering of wind-powered generating facilities totals ~~$101~~$386 million for the remainder of ~~2021.~~2022. 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 ~~892~~812 MWs of current repowering projects not in-service as of ~~September 30, 2021, 591~~March 31, 2022, 511 MWs are currently expected to qualify for 80% of the PTCs available for 10 years following each facility's return to service and 301 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~~generation includes the construction of solar-powered generating facilities totaling 141 MWs of small- and utility-scale solar generation, ~~during~~with total spend of $44 million and $3 million for the three-month periods ended March 31, 2022 and 2021, respectively and planned spending of ~~which 61 MWs are expected to be placed in-service in 2021.~~$96 million for the remainder of 2022.

•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~~Material Cash Requirements

As of ~~September 30, 2021,~~March 31, 2022, there have been no material changes outside the normal course of business in MidAmerican Energy's and MidAmerican Funding's ~~contractual obligations~~material cash requirements from the information provided in Item 7 of their Annual Report on Form 10-K for the year ended December 31, ~~2020.~~

2021.

~~117~~

Quad Cities Generating Station Operating Status

As a result, the MOPR applied to Quad Cities Station in the capacity auction for the 2022-2023 planning year, which prevented Quad Cities Station from clearing in that capacity auction.

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.

~~118~~

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~~MidAmerican Energy'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 federal, state and local agencies. ~~All such~~MidAmerican Energy believes it is in material compliance with all applicable laws and regulations, although many are subject to ~~a range of~~ interpretation ~~which~~that 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.~~2021. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, ~~2020.~~2021.

~~119~~99

Nevada Power Company and its subsidiaries

Consolidated Financial Section

~~120~~100

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Nevada Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of ~~September 30, 2021,~~March 31, 2022, the related consolidated statements of operations, ~~and~~ changes in shareholder's equity, ~~for the three-month~~ and ~~nine-month periods ended September 30, 2021 and 2020, and of~~ cash flows for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 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,~~2021, 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,~~25, 2022, 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,~~2021, 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.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

~~November 5, 2021~~April 29, 2022

~~121~~101

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)


		As of					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	85	$	25	Cash and cash equivalents	$	47	$	33
Trade receivables, net	Trade receivables, net	353		234		Trade receivables, net	187		227
Inventories	Inventories	66		69		Inventories	61		64
Derivative contracts		3		26

Regulatory assets	Regulatory assets	217		48		Regulatory assets	327		291
Prepayments	Prepayments	37		38		Prepayments	48		33

Other current assets	Other current assets	36		26		Other current assets	59		53
Total current assets	Total current assets	797		466		Total current assets	729		701

Property, plant and equipment, net	Property, plant and equipment, net	6,829		6,701		Property, plant and equipment, net	6,992		6,891
Finance lease right of use assets, net		330		351

Regulatory assets	Regulatory assets	686		746		Regulatory assets	759		728
Other assets	Other assets	73		72		Other assets	431		432

Total assets	Total assets	$	8,715	$	8,336	Total assets	$	8,911	$	8,752

LIABILITIES AND SHAREHOLDER'S EQUITY	LIABILITIES AND SHAREHOLDER'S EQUITY					LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	$	249	$	181	Accounts payable	$	224	$	242
Accrued interest	Accrued interest	38		32		Accrued interest	38		32
Accrued property, income and other taxes	Accrued property, income and other taxes	60		25		Accrued property, income and other taxes	30		29

Current portion of finance lease obligations		26		27

Short-term debt						Short-term debt	104		180
Regulatory liabilities	Regulatory liabilities	54		50		Regulatory liabilities	49		49
Customer deposits	Customer deposits	44		47		Customer deposits	45		44
Asset retirement obligation		16		25

Derivative contracts						Derivative contracts	88		55
Other current liabilities	Other current liabilities	38		22		Other current liabilities	59		62
Total current liabilities	Total current liabilities	525		409		Total current liabilities	637		693

Long-term debt	Long-term debt	2,498		2,496		Long-term debt	2,700		2,499
Finance lease obligations	Finance lease obligations	313		334		Finance lease obligations	306		310
Regulatory liabilities	Regulatory liabilities	1,118		1,163		Regulatory liabilities	1,083		1,100
Deferred income taxes	Deferred income taxes	753		738		Deferred income taxes	799		782
Other long-term liabilities	Other long-term liabilities	281		257		Other long-term liabilities	358		338
Total liabilities	Total liabilities	5,488		5,397		Total liabilities	5,883		5,722

Commitments and contingencies (Note 8)	Commitments and contingencies (Note 8)	0		0		Commitments and contingencies (Note 8)	0		0

Shareholder's equity:	Shareholder's equity:					Shareholder's equity:
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding	Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding	—		—		Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding	—		—
Additional paid-in capital	Additional paid-in capital	2,308		2,308		Additional paid-in capital	2,308		2,308
Retained earnings	Retained earnings	922		634		Retained earnings	722		724
Accumulated other comprehensive loss, net	Accumulated other comprehensive loss, net	(3)		(3)		Accumulated other comprehensive loss, net	(2)		(2)
Total shareholder's equity	Total shareholder's equity	3,227		2,939		Total shareholder's equity	3,028		3,030

Total liabilities and shareholder's equity	Total liabilities and shareholder's equity	$	8,715	$	8,336	Total liabilities and shareholder's equity	$	8,911	$	8,752

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

~~122~~102

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020			2022		2021

Operating revenue	Operating revenue	$	802	$	808	$	1,731	$	1,706	Operating revenue	$	415	$	370

Operating expenses:	Operating expenses:									Operating expenses:
Cost of fuel and energy	Cost of fuel and energy	328		287		745		654		Cost of fuel and energy	212		165
Operations and maintenance	Operations and maintenance	88		139		228		295		Operations and maintenance	65		63
Depreciation and amortization	Depreciation and amortization	103		92		304		273		Depreciation and amortization	103		101
Property and other taxes	Property and other taxes	12		12		36		35		Property and other taxes	13		12
Total operating expenses	Total operating expenses	531		530		1,313		1,257		Total operating expenses	393		341

Operating income	Operating income	271		278		418		449		Operating income	22		29

Other income (expense):	Other income (expense):									Other income (expense):
Interest expense	Interest expense	(38)		(40)		(115)		(122)		Interest expense	(38)		(38)
Allowance for borrowed funds	Allowance for borrowed funds	—		1		2		3		Allowance for borrowed funds	1		1
Allowance for equity funds	Allowance for equity funds	2		1		5		5		Allowance for equity funds	3		1
Interest and dividend income	Interest and dividend income	5		3		13		8		Interest and dividend income	9		5
Other, net	Other, net	4		3		14		4		Other, net	1		4
Total other income (expense)	Total other income (expense)	(27)		(32)		(81)		(102)		Total other income (expense)	(24)		(27)

Income before income tax expense		244		246		337		347
Income tax expense		27		52		36		74
Net income		$	217	$	194	$	301	$	273

Net (loss) income										Net (loss) income	$	(2)	$	2

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

~~123~~103

NEVADA POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)

Accumulated
Additional Other Total
Common Stock Paid-in Retained Comprehensive Shareholder's
Shares Amount Capital Earnings Loss, Net Equity
Balance, June 30, 2020 1,000 $ — $ 2,308 $ 488 $ (4) $ 2,792
Net income — — — 194 — 194
Balance, September 30, 2020 1,000 $ — $ 2,308 $ 682 $ (4) $ 2,986
Balance, December 31, 2019 1,000 $ — $ 2,308 $ 493 $ (4) $ 2,797
Net income — — — 273 — 273
Dividends declared — — — (85) — (85)
Other equity transactions — — — 1 — 1
Balance, September 30, 2020 1,000 $ — $ 2,308 $ 682 $ (4) $ 2,986
Balance, June 30, 2021 1,000 $ — $ 2,308 $ 705 $ (3) $ 3,010
Net income — — — 217 — 217
Balance, September 30, 2021 1,000 $ — $ 2,308 $ 922 $ (3) $ 3,227
Balance, December 31, 2020 1,000 $ — $ 2,308 $ 634 $ (3) $ 2,939
Net income — — — 301 — 301
Dividends declared — — — (13) — (13)
Balance, September 30, 2021 1,000 $ — $ 2,308 $ 922 $ (3) $ 3,227
The accompanying notes are an integral part of these consolidated financial statements.


								Accumulated
				Additional				Other		Total
	Common Stock			Paid-in		Retained		Comprehensive		Shareholder's
	Shares	Amount		Capital		Earnings		Loss, Net		Equity







Balance, December 31, 2020	1,000	$	—	$	2,308	$	634	$	(3)	$	2,939
Net income	—	—		—		2		—		2


Balance, March 31, 2021	1,000	$	—	$	2,308	$	636	$	(3)	$	2,941







Balance, December 31, 2021	1,000	$	—	$	2,308	$	724	$	(2)	$	3,030
Net loss	—	—		—		(2)		—		(2)


Balance, March 31, 2022	1,000	$	—	$	2,308	$	722	$	(2)	$	3,028

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

~~124~~104

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


		Nine-Month Periods					Three-Month Periods
		Ended September 30,					Ended March 31,
		2021		2020			2022		2021
Cash flows from operating activities:	Cash flows from operating activities:					Cash flows from operating activities:
Net income		$	301	$	273
Net (loss) income						Net (loss) income	$	(2)	$	2
Adjustments to reconcile net income to net cash flows from operating activities:	Adjustments to reconcile net income to net cash flows from operating activities:					Adjustments to reconcile net income to net cash flows from operating activities:

Depreciation and amortization	Depreciation and amortization	304		273		Depreciation and amortization	103		101
Allowance for equity funds	Allowance for equity funds	(5)		(5)		Allowance for equity funds	(3)		(1)
Changes in regulatory assets and liabilities	Changes in regulatory assets and liabilities	(11)		38		Changes in regulatory assets and liabilities	(8)		(15)
Deferred income taxes and amortization of investment tax credits	Deferred income taxes and amortization of investment tax credits	(19)		(3)		Deferred income taxes and amortization of investment tax credits	5		(10)
Deferred energy	Deferred energy	(154)		(38)		Deferred energy	(51)		41
Amortization of deferred energy	Amortization of deferred energy	(7)		(30)		Amortization of deferred energy	13		—
Other, net	Other, net	1		5		Other, net	4		(1)
Changes in other operating assets and liabilities:	Changes in other operating assets and liabilities:					Changes in other operating assets and liabilities:
Trade receivables and other assets	Trade receivables and other assets	(133)		(112)		Trade receivables and other assets	33		41
Inventories	Inventories	3		(4)		Inventories	3		4
Accrued property, income and other taxes	Accrued property, income and other taxes	28		48		Accrued property, income and other taxes	(15)		3
Accounts payable and other liabilities	Accounts payable and other liabilities	97		(39)		Accounts payable and other liabilities	3		14
Net cash flows from operating activities	Net cash flows from operating activities	405		406		Net cash flows from operating activities	85		179

Cash flows from investing activities:	Cash flows from investing activities:					Cash flows from investing activities:
Capital expenditures	Capital expenditures	(323)		(343)		Capital expenditures	(189)		(106)

Proceeds from sale of assets		—		26
Other, net		1		—

Net cash flows from investing activities	Net cash flows from investing activities	(322)		(317)		Net cash flows from investing activities	(189)		(106)

Cash flows from financing activities:	Cash flows from financing activities:					Cash flows from financing activities:
Proceeds from long-term debt	Proceeds from long-term debt	—		718		Proceeds from long-term debt	200		—
Repayments of long-term debt		—		(575)

Net repayment of short-term debt						Net repayment of short-term debt	(76)		—

Dividends paid		(13)		(85)
Other, net	Other, net	(12)		(12)		Other, net	(4)		(5)
Net cash flows from financing activities	Net cash flows from financing activities	(25)		46		Net cash flows from financing activities	120		(5)

Net change in cash and cash equivalents and restricted cash and cash equivalents	Net change in cash and cash equivalents and restricted cash and cash equivalents	58		135		Net change in cash and cash equivalents and restricted cash and cash equivalents	16		68
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	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 beginning of period	45		36
Cash and cash equivalents and restricted cash and cash equivalents at end of period	Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	94	$	160	Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	61	$	104

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

~~125~~105

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~~U.S. regulated electric utility company serving retail customers, including residential, commercial and industrial customers, primarily in the Las Vegas, North Las Vegas, Henderson and adjoining areas. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of ~~September 30, 2021~~March 31, 2022 and for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020.~~2021. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020.~~2021. The results of operations for the ~~three- and nine-month periods~~three-month period ended ~~September 30, 2021~~March 31, 2022 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~~2021 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Nevada Power's assumptions regarding significant accounting estimates and policies during the ~~nine-month~~three-month period ended ~~September 30, 2021.~~March 31, 2022.

(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, ~~United States~~U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents ~~as of September 30, 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 September 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					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
Cash and cash equivalents	Cash and cash equivalents	$	85	$	25	Cash and cash equivalents	$	47	$	33
Restricted cash and cash equivalents included in other current assets	Restricted cash and cash equivalents included in other current assets	9		11		Restricted cash and cash equivalents included in other current assets	14		12
Total cash and cash equivalents and restricted cash and cash equivalents	Total cash and cash equivalents and restricted cash and cash equivalents	$	94	$	36	Total cash and cash equivalents and restricted cash and cash equivalents	$	61	$	45

~~126~~106

(3) Property, Plant and Equipment, Net

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


				As of									As of
		Depreciable Life		September 30,			December 31,			Depreciable Life			March 31,			December 31,
			2021			2020						2022			2021
Utility plant:	Utility plant:										Utility plant:
Generation	Generation	30 - 55 years		$	3,780		$	3,690	Generation	30 - 55 years			$	3,810		$	3,793
Transmission	Transmission	45 - 70 years		1,493			1,468		Transmission	45 - 70 years			1,508			1,503
Distribution	Distribution	20 - 65 years		3,878			3,771		Distribution	20 - 65 years			3,979			3,920
General and intangible plant	General and intangible plant	5 - 65 years		810			791		General and intangible plant	5 - 65 years			831			836
Utility plant	Utility plant			9,961			9,720		Utility plant				10,128			10,052
Accumulated depreciation and amortization	Accumulated depreciation and amortization			(3,350)			(3,162)		Accumulated depreciation and amortization				(3,478)			(3,406)
Utility plant, net	Utility plant, net			6,611			6,558		Utility plant, net				6,650			6,646
Other non-regulated, net of accumulated depreciation and amortization	Other non-regulated, net of accumulated depreciation and amortization	45 years		1			1		Other non-regulated, net of accumulated depreciation and amortization	45 years			1			1
Plant, net	Plant, net			6,612			6,559		Plant, net				6,651			6,647
Construction work-in-progress	Construction work-in-progress			217			142		Construction work-in-progress				341			244
Property, plant and equipment, net	Property, plant and equipment, net			$	6,829		$	6,701	Property, plant and equipment, net				$	6,992		$	6,891

(4) Recent Financing Transactions

~~Credit Facilities~~Long-Term Debt

In ~~June 2021,~~January 2022, Nevada Power ~~amended and restated~~entered into a $300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $200 million under the facility at an initial interest rate of 0.55%. Nevada Power may draw all or none of the remaining unused commitment through June 2022. Nevada Power used the proceeds to repay amounts outstanding under 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.~~for general corporate purposes.

(5)~~Income Taxes~~

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

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2021 2020 2021 2020
Federal statutory income tax rate 21 % 21 % 21 % 21 %
Effects of ratemaking (10) — (10) —
Effective income tax rate 11 % 21 % 11 % 21 %

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.

~~127~~

~~(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.

107

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


		As of					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
Qualified Pension Plan:	Qualified Pension Plan:					Qualified Pension Plan:
Other non-current assets	Other non-current assets	$	11	$	8	Other non-current assets	$	42	$	42

Non-Qualified Pension Plans:	Non-Qualified Pension Plans:					Non-Qualified Pension Plans:

Other current liabilities	Other current liabilities	(1)		(1)		Other current liabilities	(1)		(1)
Other long-term liabilities	Other long-term liabilities	(9)		(9)		Other long-term liabilities	(8)		(8)

Other Postretirement Plans:	Other Postretirement Plans:					Other Postretirement Plans:
Other non-current assets	Other non-current assets	4		4		Other non-current assets	8		8

(6)Risk Management and Hedging Activities

Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity, natural gas and coal market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities.

Nevada Power has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power 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, Nevada Power may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Nevada Power's exposure to interest rate risk. Nevada Power 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 Nevada Power's accounting policies related to derivatives. Refer to Note 7 for additional information on derivative contracts.

108

The following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value of Nevada Power's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):


			Derivative
	Other		Contracts -		Other
	Current		Current		Long-term
	Assets		Liabilities		Liabilities		Total

As of March 31, 2022
Not designated as hedging contracts (1):

Commodity liabilities	$	—	$	(88)	$	(80)	$	(168)





Total derivative - net basis	$	—	$	(88)	$	(80)	$	(168)

As of December 31, 2021
Not designated as hedging contracts(1):
Commodity assets	$	4	$	—	$	—	$	4
Commodity liabilities	—		(55)		(62)		(117)




Total derivative - net basis	$	4	$	(55)	$	(62)	$	(113)

(1)Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates. As of March 31, 2022 a regulatory asset of $168 million was recorded related to the net derivative liability of $168 million. As of December 31, 2021 a regulatory asset of $113 million was recorded related to the net derivative liability of $113 million.

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	March 31,	December 31,
	Measure	2022	2021

Electricity purchases	Megawatt hours	3	1
Natural gas purchases	Decatherms	138	119

Credit Risk

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

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 Nevada Power's creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2022, Nevada Power'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.

109

The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $7 million and $6 million as of March 31, 2022 and December 31, 2021, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.

(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 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.

~~128~~

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									Input Levels for Fair Value Measurements
		Level 1		Level 2		Level 3		Total			Level 1		Level 2		Level 3		Total
As of September 30, 2021
As of March 31, 2022:										As of March 31, 2022:
Assets:										Assets:

Money market mutual funds										Money market mutual funds	$	43	$	—	$	—	$	43
Investment funds										Investment funds	3		—		—		3
											$	46	$	—	$	—	$	46

Liabilities - commodity derivatives										Liabilities - commodity derivatives	$	—	$	—	$	(168)	$	(168)

As of December 31, 2021:										As of December 31, 2021:
Assets:	Assets:									Assets:
Commodity derivatives	Commodity derivatives	$	—	$	—	$	4	$	4	Commodity derivatives	$	—	$	—	$	4	$	4
Money market mutual funds	Money market mutual funds	74		—		—		74		Money market mutual funds	34		—		—		34
Investment funds	Investment funds	3		—		—		3		Investment funds	3		—		—		3
		$	77	$	—	$	4	$	81		$	37	$	—	$	4	$	41

Liabilities - commodity derivatives	Liabilities - commodity derivatives	$	—	$	—	$	(18)	$	(18)	Liabilities - commodity derivatives	$	—	$	—	$	(117)	$	(117)

As of December 31, 2020
Assets:
Commodity derivatives		$	—	$	—	$	26	$	26
Money market mutual funds		21		—		—		21
Investment funds		2		—		—		2
		$	23	$	—	$	26	$	49

Liabilities - commodity derivatives		$	—	$	—	$	(11)	$	(11)

110

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, 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.

~~129~~

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


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020			2022		2021

Beginning balance	Beginning balance	$	25	$	(44)	$	15	$	(8)	Beginning balance	$	(113)	$	15
Changes in fair value recognized in regulatory assets	Changes in fair value recognized in regulatory assets	6		13		11		(31)		Changes in fair value recognized in regulatory assets	(56)		11

Settlements	Settlements	(45)		31		(40)		39		Settlements	1		1
Ending balance	Ending balance	$	(14)	$	—	$	(14)	$	—	Ending balance	$	(168)	$	27

Nevada Power's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Nevada Power's long‑term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Nevada Power's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Nevada Power's long‑term debt (in millions):

As of September 30, 2021 As of December 31, 2020
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $ 2,498 $ 3,122 $ 2,496 $ 3,245


	As of March 31, 2022				As of December 31, 2021
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	2,700	$	2,985	$	2,499	$	3,067

111

(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.

~~130~~

(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				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020			2022		2021
Customer Revenue:	Customer Revenue:									Customer Revenue:
Retail:	Retail:									Retail:
Residential	Residential	$	477	$	495	$	998	$	993	Residential	$	214	$	196
Commercial	Commercial	129		127		323		317		Commercial	96		84
Industrial	Industrial	152		147		310		300		Industrial	78		63
Other	Other	4		3		10		8		Other	1		3
Total fully bundled	Total fully bundled	762		772		1,641		1,618		Total fully bundled	389		346
Distribution only service	Distribution only service	6		8		17		20		Distribution only service	5		5
Total retail	Total retail	768		780		1,658		1,638		Total retail	394		351
Wholesale, transmission and other	Wholesale, transmission and other	28		21		57		48		Wholesale, transmission and other	16		14
Total Customer Revenue	Total Customer Revenue	796		801		1,715		1,686		Total Customer Revenue	410		365
Other revenue	Other revenue	6		7		16		20		Other revenue	5		5
Total revenue	Total revenue	$	802	$	808	$	1,731	$	1,706	Total revenue	$	415	$	370

~~131~~112

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

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Nevada Power during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Nevada Power's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Nevada Power's actual results in the future could differ significantly from the historical results.

Results of Operations for the ~~Third~~First Quarter of 2022 and ~~First Nine Months of~~ 2021 ~~and 2020~~

Overview

Net ~~income~~loss for the ~~third~~first quarter of ~~2021~~2022 was ~~$217~~$2 million, ~~an increase~~a decrease of ~~$23~~$4 million ~~or 12%,~~ compared to ~~2020~~2021 primarily due to $51 million of lower operations and maintenance expenses, primarily due to lower earnings sharing and lower net regulatory instructed deferrals and amortizations, $25 million of lower income tax expenses primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021 and $5$3 million of lower other, ~~expense. These increases are offset by $47~~net, mainly due to lower cash surrender value of corporate-owned life insurance policies, $2 million of lower utility margin, ~~primarily~~$2 million of higher operations and maintenance expenses, mainly due to ~~lower retail rates from the 2020 regulatory rate review with new rates effective January 2021, lower revenue recognized due to a favorable regulatory decision, partially offset by~~ higher ~~transmission revenue,~~plant operations and ~~$11~~maintenance expenses and higher earnings sharing, and $2 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.~~

~~Net income for the first nine months of 2021 was $301 million, an increase of $28 million, or 10%, compared to 2020 primarily due to $67 million of lower operations and maintenance expenses,~~in-service. Utility margin decreased primarily due to lower net regulatory instructed deferrals and amortizations, lower earnings sharing and costs recognized in 2020 for a bill credit paid as a result of the 2020 regulatory rate review stipulation, $38 million of lower income tax expense primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021, $10 million of higher other, net, mainly due to lower pension expense and higher cash surrender value of corporate-owned life insurance policies, lower interest expense of $7 million and higher interest and dividend income of $5 million. These increases are offset by $66 million of lower utility margin, primarily due to lower retail rates from the 2020 regulatory rate review with new rates effective January 2021, lower revenue recognized due to a favorable regulatory decision and an adjustment to regulatory-related revenue deferrals and lower other retail revenue, partially offset by ~~price impacts from changes in sales mix,~~ an increase in the average number of customers and ~~higher transmission revenue, and $31~~favorable changes in customer usage patterns. These decreases are offset by $4 million of higher ~~depreciation~~interest and ~~amortization,~~dividend income, mainly from carrying charges on regulatory balances. Energy generated decreased 6% for the first quarter of 2022 compared to 2021 primarily due to ~~regulatory amortizations approved in the 2020 regulatory rate review effective January 2021~~lower natural gas-fueled generation. Wholesale electricity sales volumes increased 49% and ~~higher plant placed in service.~~purchased electricity volumes increased 30%.

~~132~~

Non-GAAP Financial Measure

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

Nevada Power's cost of fuel and energy are directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in Nevada Power's expenses result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):


		Third Quarter								First Nine Months									First Quarter
		2021		2020		Change				2021		2020		Change					2022		2021		Change
Utility margin:	Utility margin:																	Utility margin:
Operating revenue	Operating revenue	$	802	$	808	$	(6)	(1)	%	$	1,731	$	1,706	$	25	1	%	Operating revenue	$	415	$	370	$	45	12	%
Cost of fuel and energy	Cost of fuel and energy	328		287		41		14		745		654		91		14		Cost of fuel and energy	212		165		47		28
Utility margin	Utility margin	474		521		(47)		(9)		986		1,052		(66)		(6)		Utility margin	203		205		(2)		(1)
Operations and maintenance	Operations and maintenance	88		139		(51)		(37)		228		295		(67)		(23)		Operations and maintenance	65		63		2		3
Depreciation and amortization	Depreciation and amortization	103		92		11		12		304		273		31		11		Depreciation and amortization	103		101		2		2
Property and other taxes	Property and other taxes	12		12		—		—		36		35		1		3		Property and other taxes	13		12		1		8
Operating income	Operating income	$	271	$	278	$	(7)	(3)	%	$	418	$	449	$	(31)	(7)	%	Operating income	$	22	$	29	$	(7)	(24)	%

~~133~~113

Utility Margin

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


		Third Quarter								First Nine Months									First Quarter
		2021		2020		Change				2021		2020		Change					2022		2021		Change
Utility margin (in millions):	Utility margin (in millions):																	Utility margin (in millions):
Operating revenue	Operating revenue	$	802	$	808	$	(6)	(1)	%	$	1,731	$	1,706	$	25	1	%	Operating revenue	$	415	$	370	$	45	12	%
Cost of fuel and energy	Cost of fuel and energy	328		287		41		14		745		654		91		14		Cost of fuel and energy	212		165		47		28
Utility margin	Utility margin	$	474	$	521	$	(47)	(9)	%	$	986	$	1,052	$	(66)	(6)	%	Utility margin	$	203	$	205	$	(2)	(1)	%

Sales (GWhs):	Sales (GWhs):																	Sales (GWhs):
Residential	Residential	4,343		4,378		(35)		(1)	%	8,737		8,557		180		2	%	Residential	1,585		1,587		(2)		—	%
Commercial	Commercial	1,568		1,471		97		7		3,793		3,553		240		7		Commercial	998		954		44		5
Industrial	Industrial	1,611		1,477		134		9		3,978		3,735		243		7		Industrial	1,175		1,057		118		11
Other	Other	52		48		4		8		144		142		2		1		Other	46		47		(1)		(2)
Total fully bundled(1)	Total fully bundled(1)	7,574		7,374		200		3		16,652		15,987		665		4		Total fully bundled(1)	3,804		3,645		159		4
Distribution only service	Distribution only service	787		664		123		19		1,923		1,776		147		8		Distribution only service	569		516		53		10
Total retail	Total retail	8,361		8,038		323		4		18,575		17,763		812		5		Total retail	4,373		4,161		212		5
Wholesale	Wholesale	93		82		11		13		266		316		(50)		(16)		Wholesale	125		84		41		49
Total GWhs sold	Total GWhs sold	8,454		8,120		334		4	%	18,841		18,079		762		4	%	Total GWhs sold	4,498		4,245		253		6	%

Average number of retail customers (in thousands)	Average number of retail customers (in thousands)	988		970		18		2	%	983		966		17		2	%	Average number of retail customers (in thousands)	995		978		17		2	%

Average revenue per MWh:	Average revenue per MWh:																	Average revenue per MWh:
Retail - fully bundled(1)	Retail - fully bundled(1)	$	100.56	$	104.72	$	(4.16)	(4)	%	$	98.54	$	101.21	$	(2.67)	(3)	%	Retail - fully bundled(1)	$	102.11	$	95.01	$	7.10	7	%

Wholesale	Wholesale	$	90.60	$	78.36	$	12.24	16	%	$	61.65	$	41.28	$	20.37	49	%	Wholesale	$	42.91	$	49.42	$	(6.51)	(13)	%

Heating degree days	Heating degree days	—		—		—		—		1,008		984		24		2	%	Heating degree days	954		994		(40)		(4)	%
Cooling degree days	Cooling degree days	2,447		2,537		(90)		(4)	%	3,930		3,847		83		2	%	Cooling degree days	49		6		43		*

Sources of energy (GWhs)(2)(3):	Sources of energy (GWhs)(2)(3):																	Sources of energy (GWhs)(2)(3):
Natural gas	Natural gas	4,776		4,888		(112)		(2)	%	10,857		10,628		229		2	%	Natural gas	2,378		2,534		(156)		(6)	%

Renewables	Renewables	19		18		1		6		55		54		1		2		Renewables	14		16		(2)		(13)
Total energy generated	Total energy generated	4,795		4,906		(111)		(2)		10,912		10,682		230		2		Total energy generated	2,392		2,550		(158)		(6)
Energy purchased	Energy purchased	2,727		2,366		361		15		6,186		5,532		654		12		Energy purchased	1,761		1,355		406		30
Total	Total	7,522		7,272		250		3	%	17,098		16,214		884		5	%	Total	4,153		3,905		248		6	%

Average cost of energy per MWh(4):	Average cost of energy per MWh(4):																	Average cost of energy per MWh(4):
Energy generated	Energy generated	$	24.71	$	11.83	$	12.88	*		$	21.49	$	16.00	$	5.49	34	%	Energy generated	$	41.92	$	14.96	$	26.96	*
Energy purchased	Energy purchased	$	76.77	$	96.51	$	(19.74)	(20)	%	$	82.53	$	87.27	$	(4.74)	(5)	%	Energy purchased	$	63.27	$	93.84	$	(30.57)	(33)	%

* Not meaningful

(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 ~~163~~424 GWhs and 152 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2021 and 2020, respectively. The average cost of energy per MWh and sources of energy excludes 1,095 GWhs and 1,180683 GWhs of gas generated energy that is purchased at cost by related parties for the first ~~nine months~~quarter of ~~2021~~2022 and ~~2020,~~2021, respectively.

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

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

~~134~~114

Quarter Ended ~~September 30, 2021~~March 31, 2022 Compared to Quarter Ended ~~September 30, 2020~~March 31, 2021

Utility margin decreased ~~$47~~$2 million, or 9%1%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to:

•$272 million of lower ~~retail~~energy efficiency program rates ~~due to the 2020 regulatory rate review with new rates effective January 2021,~~(offset in operations and maintenance expense);

•$202 million of lower regulatory-related revenue ~~recognized due to a favorable regulatory decision~~deferrals; and

•$2 million of lower other retail revenue.

The decrease in ~~2020,~~utility margin was offset by:

•$3 million of higher electric retail utility margin primarily due to ~~price impacts from changes in sales mix.~~higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased ~~4.0%~~5.1% primarily due to an increase in the average number of customers and favorable changes in customer usage patterns, offset by the unfavorable impact of ~~weather,~~

•~~$3 million due to lower energy efficiency program rates (offset in operations and maintenance expense)~~weather; 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:~~

•~~$5 million of~~ higher transmission ~~revenue~~ and

•~~$3 million due to an increase in the average number of customers, primarily from the residential customer class.~~ wholesale revenue.

Operations and maintenance ~~decreased $51~~increased $2 million, or ~~37%~~3%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to ~~lower~~higher plant operations and maintenance expenses and higher earnings sharing, lower net regulatory instructed deferrals and amortizations, 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, costs recognized in 2020 for a bill credit paid as a result of the 2020 regulatory rate review stipulation andpartially offset by lower energy efficiency program costs (offset in operating revenue).

Depreciation and amortization increased ~~$11~~$2 million, or ~~12%~~2%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to ~~regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and~~ higher plant placed ~~in service.~~

~~Interest expense~~ ~~decreased $2 million, or 5%, for the third quarter of 2021 compared to 2020 primarily due to lower carrying charges on regulatory balances.~~in-service.

Interest and dividend income increased $2$4 million, or ~~67%~~80%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to higher interest income, mainly from carrying charges on regulatory balances.

Other, net ~~increased $1~~decreased $3 million, or ~~33%~~75%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to ~~lower pension expense, partially offset by~~ lower cash surrender value of corporate-owned life insurance policies.

~~Income tax expense~~ decreased $25 million, or 48%, for the third quarter of 2021 compared to 2020. The effective tax rate was 11% in 2021 and 21% in 2020 and decreased primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021.

~~135~~

~~First Nine Months Ended September 30, 2021 Compared to First Nine Months Ended September 30, 2020~~

~~Utility margin~~ ~~decreased $66 million, or 6%, for the first nine months of 2021 compared to 2020 primarily due to:~~

•~~$51 million of lower retail rates due to the 2020 regulatory rate review with new rates effective January 2021,~~

•~~$20 million of lower revenue recognized due to a favorable regulatory decision in 2020,~~

•~~$7 million due to lower energy efficiency program rates (offset in operations and maintenance expense),~~

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

•~~$3 million due to a regulatory amortization of an impact fee that ended December 2020.~~

~~The decrease in utility margin was offset by:~~

•$11 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 4.6% primarily due to favorable changes in customer usage patterns and the favorable impact of weather,

•~~$5 million due to an increase in the average number of customers, primarily from the residential customer class and~~

•~~$5 million of higher transmission revenue.~~

~~Operations and maintenance~~ decreased $67 million, or 23%, for the first nine months of 2021 compared to 2020 primarily due to lower net regulatory instructed deferrals and amortizations, 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, lower earnings sharing, lower energy efficiency program costs (offset in operating revenue) and costs recognized in 2020 for a bill credit paid as a result of the 2020 regulatory rate review stipulation.

~~Depreciation and amortization~~ increased $31 million, or 11%, for the first nine 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 $7 million, or 6%, for the first nine months of 2021 compared to 2020 primarily due to lower carrying charges on regulatory balances of $5 million and lower interest expense on long-term debt.

~~Interest and dividend income~~ ~~increased $5 million, or 63%, for the first nine months of 2021 compared to 2020 primarily due to higher interest income, mainly from carrying charges on regulatory balances.~~

~~Other, net~~ increased $10 million for the first nine months of 2021 compared to 2020 primarily due to lower pension expense of $6 million and higher cash surrender value of corporate-owned life insurance policies.

~~Income tax expense~~ decreased $38 million, or (51)%, for the first nine months of 2021 compared to 2020. The effective tax rate was 11% in 2021 and 21% in 2020 and decreased primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021.

~~136~~

Liquidity and Capital Resources

As of ~~September 30, 2021,~~March 31, 2022, Nevada Power's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	8547
Credit facility	400
Less -
Short-term debt	(104)
Net credit facility	296

Delayed draw term loan facility	$	300
Less -
Long-term debt	(200)
Net delayed draw term loan facility	100

Total net liquidity	$	~~485~~443
Credit facility and delayed draw term loan facility:
Maturity date	2024

~~Operating Activities~~

115

Operating Activities

Net cash flows from operating activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ were ~~$405~~$85 million and ~~$406~~$179 million, respectively. The change was primarily due to higher payments related to fuel and energy costs and the timing of payments for ~~fuel and energy~~operating costs, ~~and higher payments for income taxes,~~ partially offset by higher collections from ~~customers, timing of payments for operating costs, increased collections of customer advances and lower inventory purchases.~~customers.

Investing Activities

Net cash flows from investing activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ were ~~$(322)~~$(189) million and ~~$(317)~~$(106) 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 ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ were ~~$(25)~~$120 million and ~~$46~~$(5) million, respectively. The change was primarily due to ~~lower~~higher proceeds from the issuance of long-term debt, partially offset by ~~lower~~higher repayments of ~~long-term debt~~short-term debt.

Long-Term Debt

In January 2022, Nevada Power entered into a $300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $200 million under the facility at an initial interest rate of 0.55%. Nevada Power may draw all or none of the remaining unused commitment through June 2022. Nevada Power used the proceeds to repay amounts outstanding under its existing secured credit facility and ~~lower dividends paid to NV Energy, Inc.~~for general corporate purposes.

Debt Authorizations

Nevada Power currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of ~~$3.2~~$3.8 billion (excluding borrowings under Nevada Power's $400 million secured credit facility); and (2) maintain a revolving credit facility of up to $1.3 billion. Nevada Power currently has an effective automatic shelf registration statement with the SEC to issue an indeterminate amount of general and refunding mortgage securities through October 2022.

Future Uses of Cash

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

116

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.~~

~~137~~

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


		Nine-Month Periods				Annual			Three-Month Periods				Annual
		Ended September 30,				Forecast			Ended March 31,				Forecast
		2020		2021		2021			2021		2022		2022

Electric distribution	Electric distribution	$	182	$	137	$	194	Electric distribution	$	41	$	51	$	223
Electric transmission	Electric transmission	27		38		67		Electric transmission	13		21		168
Solar generation	Solar generation	—		7		21		Solar generation	1		7		80
Other	Other	134		141		208		Other	51		110		386
Total	Total	$	343	$	323	$	490	Total	$	106	$	189	$	857

Nevada ~~Power's approved Fourth Amendment to the 2018 Joint~~Power received PUCN approval through its recent IRP ~~included~~filings for 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.~~2022. These estimates may change as a result of the RFP process. 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 of which costs are split 70% to Nevada Power and 30% to Sierra Pacific.~~program. In this project, the company ~~proposed~~has received approval from the PUCN to build a 350-mile, ~~525 kV~~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 was approved by the PUCN in the Fourth Amendment to the 2018 Joint IRP with the exception of the Northwest substation to Harry Allen substation segment for which approval was limited to design, permitting and land acquisition only. In addition, and as instructed in Senate Bill 448 and submitted in the company's amendment to the 2021 Joint IRP, the company proposed to buildsubstation; a 235-mile, ~~525 kV~~525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, ~~345 kV~~345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, ~~345 kV~~345-kV transmission line from the new Ft. Churchill substation to the ~~Comstock Meadows substations and the Northwest substation to Harry Allen substation segment of Greenlink West.~~Robinson Summit substations. 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~~150-MW 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~~includes both growth projects and operating expenditures consisting of turbine upgrades at several generating facilities, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.

~~Contractual Obligations~~Material Cash Requirements

As of ~~September 30, 2021,~~March 31, 2022, there have been no material changes outside the normal course of business in ~~contractual obligations~~material cash requirements from the information provided in Item 7 of Nevada Power's Annual Report on Form 10-K for the year ended December 31, ~~2020.~~

2021.

~~138~~117

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 federal, state and local agencies. ~~All such~~Nevada Power believes it is in material compliance with all applicable laws and regulations, although many are subject to ~~a range of~~ interpretation ~~which~~that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and 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.~~2021. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, ~~2020.~~2021.

~~139~~118

Sierra Pacific Power Company and its subsidiaries

Consolidated Financial Section

~~140~~119

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 ~~September 30, 2021,~~March 31, 2022, the related consolidated statements of operations, ~~and~~ changes in shareholder's equity, ~~for the three-month~~ and ~~nine-month periods ended September 30, 2021 and 2020, and of~~ cash flows for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 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,~~2021, 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,~~25, 2022, 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,~~2021, 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.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

~~November 5, 2021~~April 29, 2022

~~141~~120

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)


		As of					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	14	$	19	Cash and cash equivalents	$	15	$	10
Trade receivables, net	Trade receivables, net	118		97		Trade receivables, net	120		128

Inventories	Inventories	68		77		Inventories	71		65

Regulatory assets	Regulatory assets	168		67		Regulatory assets	164		177

Other current assets	Other current assets	48		45		Other current assets	36		35
Total current assets	Total current assets	416		305		Total current assets	406		415

Property, plant and equipment, net	Property, plant and equipment, net	3,265		3,164		Property, plant and equipment, net	3,386		3,340

Regulatory assets	Regulatory assets	265		267		Regulatory assets	282		263
Other assets	Other assets	184		183		Other assets	205		205

Total assets	Total assets	$	4,130	$	3,919	Total assets	$	4,279	$	4,223

LIABILITIES AND SHAREHOLDER'S EQUITY	LIABILITIES AND SHAREHOLDER'S EQUITY					LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	$	121	$	108	Accounts payable	$	125	$	147
Accrued interest		11		14

Accrued property, income and other taxes	Accrued property, income and other taxes	18		14		Accrued property, income and other taxes	28		16
Short-term debt	Short-term debt	127		45		Short-term debt	57		159

Regulatory liabilities	Regulatory liabilities	23		34		Regulatory liabilities	20		19
Customer deposits	Customer deposits	15		15		Customer deposits	16		15
Derivative contracts						Derivative contracts	28		16
Other current liabilities	Other current liabilities	31		25		Other current liabilities	39		42
Total current liabilities	Total current liabilities	346		255		Total current liabilities	313		414

Long-term debt	Long-term debt	1,164		1,164		Long-term debt	1,164		1,164
Finance lease obligations		116		121

Regulatory liabilities	Regulatory liabilities	446		463		Regulatory liabilities	440		444
Deferred income taxes	Deferred income taxes	396		374		Deferred income taxes	401		402
Other long-term liabilities	Other long-term liabilities	144		131		Other long-term liabilities	268		264
Total liabilities	Total liabilities	2,612		2,508		Total liabilities	2,586		2,688

Commitments and contingencies (Note 8)		0		0
Commitments and contingencies (Note 9)						Commitments and contingencies (Note 9)	0		0

Shareholder's equity:	Shareholder's equity:					Shareholder's equity:
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding	Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding	—		—		Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding	—		—
Additional paid-in capital	Additional paid-in capital	1,111		1,111		Additional paid-in capital	1,241		1,111
Retained earnings	Retained earnings	408		301		Retained earnings	453		425
Accumulated other comprehensive loss, net	Accumulated other comprehensive loss, net	(1)		(1)		Accumulated other comprehensive loss, net	(1)		(1)
Total shareholder's equity	Total shareholder's equity	1,518		1,411		Total shareholder's equity	1,693		1,535

Total liabilities and shareholder's equity	Total liabilities and shareholder's equity	$	4,130	$	3,919	Total liabilities and shareholder's equity	$	4,279	$	4,223

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

~~142~~121

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021
Operating revenue:	Operating revenue:									Operating revenue:
Regulated electric	Regulated electric	$	266	$	220	$	636	$	569	Regulated electric		$	227	$	181
Regulated natural gas	Regulated natural gas	16		15		75		83		Regulated natural gas		52		39
Total operating revenue	Total operating revenue	282		235		711		652		Total operating revenue		279		220

Operating expenses:	Operating expenses:									Operating expenses:
Cost of fuel and energy	Cost of fuel and energy	120		81		295		233		Cost of fuel and energy		124		82
Cost of natural gas purchased for resale	Cost of natural gas purchased for resale	6		4		35		44		Cost of natural gas purchased for resale		34		21
Operations and maintenance	Operations and maintenance	40		40		117		123		Operations and maintenance		41		36
Depreciation and amortization	Depreciation and amortization	35		36		107		104		Depreciation and amortization		36		36
Property and other taxes	Property and other taxes	6		6		18		17		Property and other taxes		6		6
Total operating expenses	Total operating expenses	207		167		572		521		Total operating expenses		241		181

Operating income	Operating income	75		68		139		131		Operating income		38		39

Other income (expense):	Other income (expense):									Other income (expense):
Interest expense	Interest expense	(14)		(14)		(41)		(42)		Interest expense		(13)		(14)
Allowance for borrowed funds	Allowance for borrowed funds	1		—		2		1		Allowance for borrowed funds		1		—
Allowance for equity funds	Allowance for equity funds	2		1		5		3		Allowance for equity funds		2		1
Interest and dividend income	Interest and dividend income	3		1		6		3		Interest and dividend income		3		2
Other, net	Other, net	3		2		9		4		Other, net		2		4
Total other income (expense)	Total other income (expense)	(5)		(10)		(19)		(31)		Total other income (expense)		(5)		(7)

Income before income tax expense	Income before income tax expense	70		58		120		100		Income before income tax expense		33		32
Income tax expense	Income tax expense	8		6		13		10		Income tax expense		5		4
Net income	Net income	$	62	$	52	$	107	$	90	Net income		$	28	$	28

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

~~143~~122

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, June 30, 2020 1,000 $ — $ 1,111 $ 228 $ (1) $ 1,338
Net income — — — 52 — 52
Balance, September 30, 2020 1,000 $ — $ 1,111 $ 280 $ (1) $ 1,390
Balance, December 31, 2019 1,000 $ — $ 1,111 $ 210 $ (1) $ 1,320
Net income — — — 90 — 90
Dividends declared — — — (20) — (20)
Balance, September 30, 2020 1,000 $ — $ 1,111 $ 280 $ (1) $ 1,390
Balance, June 30, 2021 1,000 $ — $ 1,111 $ 346 $ (1) $ 1,456
Net income — — — 62 — 62
Balance, September 30, 2021 1,000 $ — $ 1,111 $ 408 $ (1) $ 1,518
Balance, December 31, 2020 1,000 $ — $ 1,111 $ 301 $ (1) $ 1,411
Net income — — — 107 — 107
Balance, September 30, 2021 1,000 $ — $ 1,111 $ 408 $ (1) $ 1,518
The accompanying notes are an integral part of these consolidated financial statements.


								Accumulated
				Additional				Other		Total
	Common Stock			Paid-in		Retained		Comprehensive		Shareholder's
	Shares	Amount		Capital		Earnings		Loss, Net		Equity







Balance, December 31, 2020	1,000	$	—	$	1,111	$	301	$	(1)	$	1,411
Net income	—	—		—		28		—		28


Balance, March 31, 2021	1,000	$	—	$	1,111	$	329	$	(1)	$	1,439







Balance, December 31, 2021	1,000	$	—	$	1,111	$	425	$	(1)	$	1,535
Net income	—	—		—		28		—		28

Contributions	—	—		130		—		—		130

Balance, March 31, 2022	1,000	$	—	$	1,241	$	453	$	(1)	$	1,693

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

~~144~~123

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


		Nine-Month Periods					Three-Month Periods
		Ended September 30,					Ended March 31,
		2021		2020			2022		2021
Cash flows from operating activities:	Cash flows from operating activities:					Cash flows from operating activities:
Net income	Net income	$	107	$	90	Net income	$	28	$	28
Adjustments to reconcile net income to net cash flows from operating activities:	Adjustments to reconcile net income to net cash flows from operating activities:					Adjustments to reconcile net income to net cash flows from operating activities:

Depreciation and amortization	Depreciation and amortization	107		104		Depreciation and amortization	36		36
Allowance for equity funds	Allowance for equity funds	(5)		(3)		Allowance for equity funds	(2)		(1)
Changes in regulatory assets and liabilities	Changes in regulatory assets and liabilities	(30)		(30)		Changes in regulatory assets and liabilities	(4)		(13)
Deferred income taxes and amortization of investment tax credits	Deferred income taxes and amortization of investment tax credits	10		3		Deferred income taxes and amortization of investment tax credits	(3)		4
Deferred energy	Deferred energy	(95)		(5)		Deferred energy	(7)		(18)
Amortization of deferred energy	Amortization of deferred energy	12		(6)		Amortization of deferred energy	23		(3)
Other, net		(1)		—

Changes in other operating assets and liabilities:	Changes in other operating assets and liabilities:					Changes in other operating assets and liabilities:
Trade receivables and other assets	Trade receivables and other assets	(25)		(83)		Trade receivables and other assets	12		8
Inventories	Inventories	9		(18)		Inventories	(6)		3
Accrued property, income and other taxes	Accrued property, income and other taxes	3		8		Accrued property, income and other taxes	7		(3)
Accounts payable and other liabilities	Accounts payable and other liabilities	21		119		Accounts payable and other liabilities	(21)		1
Net cash flows from operating activities	Net cash flows from operating activities	113		179		Net cash flows from operating activities	63		42

Cash flows from investing activities:	Cash flows from investing activities:					Cash flows from investing activities:
Capital expenditures	Capital expenditures	(196)		(192)		Capital expenditures	(83)		(61)

Net cash flows from investing activities	Net cash flows from investing activities	(196)		(192)		Net cash flows from investing activities	(83)		(61)

Cash flows from financing activities:	Cash flows from financing activities:					Cash flows from financing activities:
Proceeds from long-term debt		—		30
Net proceeds from short-term debt		82		—

Dividends paid		—		(20)
Net (repayment of) proceeds from short-term debt						Net (repayment of) proceeds from short-term debt	(102)		10

Contributions from parent						Contributions from parent	130		—
Other, net	Other, net	(5)		(3)		Other, net	(2)		(2)
Net cash flows from financing activities	Net cash flows from financing activities	77		7		Net cash flows from financing activities	26		8

Net change in cash and cash equivalents and restricted cash and cash equivalents	Net change in cash and cash equivalents and restricted cash and cash equivalents	(6)		(6)		Net change in cash and cash equivalents and restricted cash and cash equivalents	6		(11)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	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 beginning of period	16		26
Cash and cash equivalents and restricted cash and cash equivalents at end of period	Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	20	$	26	Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	22	$	15

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

~~145~~124

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~~U.S. 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 ~~September 30, 2021~~March 31, 2022 and for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020.~~2021. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2021~~March 31, 2022 and ~~2020.~~2021. The results of operations for the ~~three- and nine-month periods~~three-month period ended ~~September 30, 2021~~March 31, 2022 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~~2021 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 ~~nine-month~~three-month period ended ~~September 30, 2021.~~March 31, 2022.

(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, ~~United States~~U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents ~~as of September 30, 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 September 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					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
Cash and cash equivalents	Cash and cash equivalents	$	14	$	19	Cash and cash equivalents	$	15	$	10
Restricted cash and cash equivalents included in other current assets	Restricted cash and cash equivalents included in other current assets	6		7		Restricted cash and cash equivalents included in other current assets	7		6
Total cash and cash equivalents and restricted cash and cash equivalents	Total cash and cash equivalents and restricted cash and cash equivalents	$	20	$	26	Total cash and cash equivalents and restricted cash and cash equivalents	$	22	$	16

~~146~~125

(3) Property, Plant and Equipment, Net

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


				As of									As of
		Depreciable Life		September 30,			December 31,			Depreciable Life			March 31,			December 31,
			2021			2020						2022			2021
Utility plant:	Utility plant:										Utility plant:
Electric generation	Electric generation	25 - 60 years		$	1,140		$	1,130	Electric generation	25 - 60 years			$	1,169		$	1,163
Electric transmission	Electric transmission	50 - 100 years		914			908		Electric transmission	50 - 100 years			937			940
Electric distribution	Electric distribution	20 - 100 years		1,806			1,754		Electric distribution	20 - 100 years			1,885			1,846
Electric general and intangible plant	Electric general and intangible plant	5 - 70 years		199			189		Electric general and intangible plant	5 - 70 years			206			204
Natural gas distribution	Natural gas distribution	35 - 70 years		433			429		Natural gas distribution	35 - 70 years			445			438
Natural gas general and intangible plant	Natural gas general and intangible plant	5 - 70 years		15			15		Natural gas general and intangible plant	5 - 70 years			14			14
Common general	Common general	5 - 70 years		361			355		Common general	5 - 70 years			370			370
Utility plant	Utility plant			4,868			4,780		Utility plant				5,026			4,975
Accumulated depreciation and amortization	Accumulated depreciation and amortization			(1,834)			(1,755)		Accumulated depreciation and amortization				(1,878)			(1,854)
Utility plant, net	Utility plant, net			3,034			3,025		Utility plant, net				3,148			3,121
Other non-regulated, net of accumulated depreciation and amortization		70 years		—			2
Plant, net				3,034			3,027

Construction work-in-progress	Construction work-in-progress			231			137		Construction work-in-progress				238			219
Property, plant and equipment, net	Property, plant and equipment, net			$	3,265		$	3,164	Property, plant and equipment, net				$	3,386		$	3,340

(4) Recent Financing Transactions

~~Credit Facilities~~Long-Term Debt

In ~~June 2021,~~April 2022, Sierra Pacific ~~amended and restated its existing $250~~entered into a $200 million ~~secured credit facility expiring in June 2022~~unsecured loan with ~~no remaining one-year extension options.~~NV Energy payable upon demand. The ~~amendment extended the expiration date~~net proceeds were used to ~~June 2024 and increased the available maturity extension options to an unlimited number,~~purchase certain tax-exempt refunding revenue bond obligations that were subject to ~~lender consent.~~mandatory purchase by Sierra Pacific in April 2022. The loan has an underlying variable interest rate based on 30-day U.S. dollar deposits offered on the London Interbank Offer Rate market plus a spread of 0.75%.

In April 2022, Sierra Pacific purchased the following series of bonds that were held by the public: $30 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036; $75 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $20 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036; and $30 million of its variable-rate tax-exempt Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029. Sierra Pacific purchased these bonds as required by the bond indentures. Sierra Pacific is holding these bonds and can re-offer them at a future date.

(5) Income Taxes

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


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020			2022		2021

Federal statutory income tax rate	Federal statutory income tax rate	21	%	21	%	21	%	21	%	Federal statutory income tax rate	21	%	21	%
Effects of ratemaking	Effects of ratemaking	(10)		(11)		(10)		(10)		Effects of ratemaking	(7)		(10)

Other	Other	—		—		—		(1)		Other	1		2
Effective income tax rate	Effective income tax rate	11	%	10	%	11	%	10	%	Effective income tax rate	15	%	13	%

126

~~147~~

(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. Sierra Pacific contributed $1$2 million to the Other Postretirement Plans for the ~~nine-month~~three-month period ended ~~September 30, 2021.~~March 31, 2022. 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					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
Qualified Pension Plan:	Qualified Pension Plan:					Qualified Pension Plan:

Other non-current assets	Other non-current assets	$	31	$	26	Other non-current assets	$	63	$	62

Non-Qualified Pension Plans:	Non-Qualified Pension Plans:					Non-Qualified Pension Plans:

Other current liabilities	Other current liabilities	(1)		(1)		Other current liabilities	(1)		(1)
Other long-term liabilities	Other long-term liabilities	(8)		(8)		Other long-term liabilities	(7)		(7)

Other Postretirement Plans:	Other Postretirement Plans:					Other Postretirement Plans:

Other long-term liabilities	Other long-term liabilities	(13)		(13)		Other long-term liabilities	(8)		(10)

(7)Risk Management and Hedging Activities

Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail customer load in its regulated service territory. Sierra Pacific's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Sierra Pacific does not engage in proprietary trading activities.

Sierra Pacific has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific 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, Sierra Pacific may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Sierra Pacific's exposure to interest rate risk. Sierra Pacific 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 Sierra Pacific's accounting policies related to derivatives. Refer to Note 8 for additional information on derivative contracts.

127

The following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value of Sierra Pacific's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):


			Derivative
	Other		Contracts -		Other
	Current		Current		Long-term
	Assets		Liabilities		Liabilities		Total

As of March 31, 2022
Not designated as hedging contracts (1):
Commodity assets	$	1	$	—	$	—	$	1
Commodity liabilities	—		(28)		(25)		(53)




Total derivative - net basis	$	1	$	(28)	$	(25)	$	(52)

As of December 31, 2021
Not designated as hedging contracts(1):
Commodity assets	$	2	$	—	$	—	$	2
Commodity liabilities	—		(16)		(19)		(35)




Total derivative - net basis	$	2	$	(16)	$	(19)	$	(33)

(1)Sierra Pacific's commodity derivatives not designated as hedging contracts are included in regulated rates. As of March 31, 2022 a net regulatory asset of $52 million was recorded related to the net derivative liability of $52 million. As of December 31, 2021 a net regulatory asset of $33 million was recorded related to the net derivative liability of $33 million.

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	March 31,	December 31,
	Measure	2022	2021

Electricity purchases	Megawatt hours	1	1
Natural gas purchases	Decatherms	60	53

Credit Risk

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

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 Sierra Pacific's creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2022, Sierra Pacific'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.

128

The aggregate fair value of Sierra Pacific's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $2 million and $— million as of March 31, 2022 and December 31, 2021, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Sierra Pacific's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.

(8) Fair Value Measurements

The carrying value of Sierra Pacific's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Sierra Pacific has various financial assets and liabilities that are measured at fair value on the 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 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.

~~148~~

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									Input Levels for Fair Value Measurements
		Level 1		Level 2		Level 3		Total			Level 1		Level 2		Level 3		Total
As of September 30, 2021
As of March 31, 2022:										As of March 31, 2022:
Assets:	Assets:									Assets:
Commodity derivatives	Commodity derivatives	$	—	$	—	$	2	$	2	Commodity derivatives	$	—	$	—	$	1	$	1
Money market mutual funds	Money market mutual funds	11		—		—		11		Money market mutual funds	13		—		—		13
Investment funds	Investment funds	1		—		—		1		Investment funds	1		—		—		1
		$	12	$	—	$	2	$	14		$	14	$	—	$	1	$	15

Liabilities - commodity derivatives	Liabilities - commodity derivatives	$	—	$	—	$	(2)	$	(2)	Liabilities - commodity derivatives	$	—	$	—	$	(53)	$	(53)

As of December 31, 2020
As of December 31, 2021:										As of December 31, 2021:
Assets:	Assets:									Assets:
Commodity derivatives	Commodity derivatives	$	—	$	—	$	9	$	9	Commodity derivatives	$	—	$	—	$	2	$	2
Money market mutual funds	Money market mutual funds	17		—		—		17		Money market mutual funds	10		—		—		10

Investment funds										Investment funds	1		—		—		1
		$	17	$	—	$	9	$	26		$	11	$	—	$	2	$	13

Liabilities - commodity derivatives	Liabilities - commodity derivatives	$	—	$	—	$	(2)	$	(2)	Liabilities - commodity derivatives	$	—	$	—	$	(35)	$	(35)

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.

129

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


	Three-Month Periods
	Ended March 31,
	2022		2021

Beginning balance	$	(33)	$	7
Changes in fair value recognized in regulatory assets	(19)		5


Ending balance	$	(52)	$	12

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 September 30, 2021 As of December 31, 2020
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $ 1,164 $ 1,328 $ 1,164 $ 1,358


	As of March 31, 2022				As of December 31, 2021
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	1,164	$	1,261	$	1,164	$	1,316

~~149~~

~~(8)~~(9) Commitments and Contingencies

Legal Matters

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

130

~~(9)~~

(10) 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 1011 (in millions):


		Three-Month Periods													Three-Month Periods
		Ended September 30,													Ended March 31,
		2021						2020							2022						2021
		Electric		Natural Gas		Total		Electric		Natural Gas		Total			Electric		Natural Gas		Total		Electric		Natural Gas		Total
Customer Revenue:	Customer Revenue:													Customer Revenue:
Retail:	Retail:													Retail:
Residential	Residential	$	91	$	11	$	102	$	76	$	11	$	87	Residential	$	85	$	32	$	117	$	71	$	25	$	96
Commercial	Commercial	84		3		87		71		3		74		Commercial	70		15		85		54		10		64
Industrial	Industrial	71		2		73		57		1		58		Industrial	49		4		53		39		3		42
Other	Other	1		—		1		1		—		1		Other	1		—		1		1		—		1
Total fully bundled	Total fully bundled	247		16		263		205		15		220		Total fully bundled	205		51		256		165		38		203
Distribution only service	Distribution only service	1		—		1		1		—		1		Distribution only service	1		—		1		1		—		1
Total retail	Total retail	248		16		264		206		15		221		Total retail	206		51		257		166		38		204
Wholesale, transmission and other	Wholesale, transmission and other	18		—		18		13		—		13		Wholesale, transmission and other	21		—		21		15		—		15
Total Customer Revenue	Total Customer Revenue	266		16		282		219		15		234		Total Customer Revenue	227		51		278		181		38		219
Other revenue	Other revenue	—		—		—		1		—		1		Other revenue	—		1		1		—		1		1
Total revenue	Total revenue	$	266	$	16	$	282	$	220	$	15	$	235	Total revenue	$	227	$	52	$	279	$	181	$	39	$	220

~~150~~

Nine-Month Periods
Ended September 30,
2021 2020
Electric Natural Gas Total Electric Natural Gas Total
Customer Revenue:
Retail:
Residential $ 229 $ 50 $ 279 $ 208 $ 54 $ 262
Commercial 202 18 220 183 20 203
Industrial 151 6 157 132 8 140
Other 4 — 4 3 — 3
Total fully bundled 586 74 660 526 82 608
Distribution only service 2 — 2 3 — 3
Total retail 588 74 662 529 82 611
Wholesale, transmission and other 46 — 46 37 — 37
Total Customer Revenue 634 74 708 566 82 648
Other revenue 2 1 3 3 1 4
Total revenue $ 636 $ 75 $ 711 $ 569 $ 83 $ 652

~~151~~131

~~(10)~~(11) Segment Information

Sierra Pacific has identified 2 reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by the PUCN; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance.

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


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020			2022		2021
Operating revenue:	Operating revenue:									Operating revenue:
Regulated electric	Regulated electric	$	266	$	220	$	636	$	569	Regulated electric	$	227	$	181
Regulated natural gas	Regulated natural gas	16		15		75		83		Regulated natural gas	52		39
Total operating revenue	Total operating revenue	$	282	$	235	$	711	$	652	Total operating revenue	$	279	$	220

Operating income:	Operating income:									Operating income:
Regulated electric	Regulated electric	$	74	$	66	$	126	$	119	Regulated electric	$	30	$	31
Regulated natural gas	Regulated natural gas	1		2		13		12		Regulated natural gas	8		8
Total operating income	Total operating income	75		68		139		131		Total operating income	38		39
Interest expense	Interest expense	(14)		(14)		(41)		(42)		Interest expense	(13)		(14)
Allowance for borrowed funds	Allowance for borrowed funds	1		—		2		1		Allowance for borrowed funds	1		—
Allowance for equity funds	Allowance for equity funds	2		1		5		3		Allowance for equity funds	2		1
Interest and dividend income	Interest and dividend income	3		1		6		3		Interest and dividend income	3		2
Other, net	Other, net	3		2		9		4		Other, net	2		4
Income before income tax expense	Income before income tax expense	$	70	$	58	$	120	$	100	Income before income tax expense	$	33	$	32


		As of						As of
			September 30,		December 31,				March 31,		December 31,
			2021		2020				2022		2021
Assets:	Assets:						Assets:
Regulated electric	Regulated electric		$	3,744	$	3,540	Regulated electric		$	3,869	$	3,829
Regulated natural gas	Regulated natural gas		354		342		Regulated natural gas		375		365
Other(1)	Other(1)		32		37		Other(1)		35		29
Total assets	Total assets		$	4,130	$	3,919	Total assets		$	4,279	$	4,223

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

~~152~~132

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 ~~Third~~First Quarter ~~and First Nine Months~~ of ~~2021~~2022 and ~~2020~~2021

Overview

Net income for the ~~third~~first quarter of ~~2021~~2022 was ~~$62~~$28 million, ~~an increase of $10 million, or 19%,~~consistent when compared to ~~2020~~2021 primarily due to $7$5 million of higher operations and maintenance expenses, mainly due to higher plant operations and maintenance expenses and higher earnings sharing, and $2 million of lower other, net, mainly due to lower cash surrender value of corporate-owned life insurance policies, partially offset by $4 million of higher electric utility margin, mainly from ~~price impacts from changes in sales mix and~~ higher transmission and wholesale revenue, partially offset by lower regulatory-related revenue deferrals, higher allowance for equity funds, mainly due to higher construction work-in-progress, and ~~$2 million of~~ higher interest and dividend income, mainly from carrying charges on regulatory balances.

~~Net income~~ Energy generated increased 3% for the first ~~nine months~~quarter of ~~2021 was $107 million, an increase of $17 million, or 19%,~~2022 compared to ~~2020~~2021 primarily due to ~~$6 million of lower operations and maintenance expenses, mainly due to lower plant operations and maintenance expenses and lower earnings sharing, $5 million of~~ higher ~~electric utility margin, mainly from price impacts from changes in sales mix and an increase in the average number of customer, primarily from the residential customer class,~~coal-fueled generation, partially offset by lower ~~revenue recognized due to a favorable regulatory decision~~natural gas-fueled generation. Wholesale electricity sales volumes increased 66% and an adjustment to regulatory-related revenue deferrals, $5 million of higher other, net, mainly due to lower pension costs and higher cash surrender value of corporate-owned life insurance policies, and $3 million of higher interest and dividend income, mainly from carrying charges on regulatory balances, partially offset by $3 million of higher depreciation and amortization, mainly from regulatory amortizations and higher plant in service, and $3 million of higher income tax expense primarily due to higher pretax income.purchased electricity volumes decreased 25%.

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.

~~153~~133

Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):


		Third Quarter								First Nine Months									First Quarter
		2021		2020		Change				2021		2020		Change					2022		2021		Change
Electric utility margin:	Electric utility margin:																	Electric utility margin:
Operating revenue	Operating revenue	$	266	$	220	$	46	21	%	$	636	$	569	$	67	12	%	Operating revenue	$	227	$	181	$	46	25	%
Cost of fuel and energy	Cost of fuel and energy	120		81		39		48		295		233		62		27		Cost of fuel and energy	124		82		42		51
Electric utility margin	Electric utility margin	146		139		7		5		341		336		5		1		Electric utility margin	103		99		4		4

Natural gas utility margin:	Natural gas utility margin:																	Natural gas utility margin:
Operating revenue	Operating revenue	16		15		1		7	%	75		83		(8)		(10)	%	Operating revenue	52		39		13		33	%
Natural gas purchased for resale	Natural gas purchased for resale	6		4		2		50		35		44		(9)		(20)		Natural gas purchased for resale	34		21		13		62
Natural gas utility margin	Natural gas utility margin	10		11		(1)		(9)		40		39		1		3		Natural gas utility margin	18		18		—		—

Utility margin	Utility margin	156		150		6		4	%	381		375		6		2	%	Utility margin	121		117		4		3	%

Operations and maintenance	Operations and maintenance	40		40		—		—	%	117		123		(6)		(5)	%	Operations and maintenance	41		36		5		14	%
Depreciation and amortization	Depreciation and amortization	35		36		(1)		(3)		107		104		3		3		Depreciation and amortization	36		36		—		—
Property and other taxes	Property and other taxes	6		6		—		—		18		17		1		6		Property and other taxes	6		6		—		—
Operating income	Operating income	$	75	$	68	$	7	10	%	$	139	$	131	$	8	6	%	Operating income	$	38	$	39	$	(1)	(3)	%

~~154~~134

Electric Utility Margin

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


		Third Quarter								First Nine Months									First Quarter
		2021		2020		Change				2021		2020		Change					2022		2021		Change
Utility margin (in millions):	Utility margin (in millions):																	Utility margin (in millions):
Operating revenue	Operating revenue	$	266	$	220	$	46	21	%	$	636	$	569	$	67	12	%	Operating revenue	$	227	$	181	$	46	25	%
Cost of fuel and energy	Cost of fuel and energy	120		81		39		48		295		233		62		27		Cost of fuel and energy	124		82		42		51
Utility margin	Utility margin	$	146	$	139	$	7	5	%	$	341	$	336	$	5	1	%	Utility margin	$	103	$	99	$	4	4	%

Sales (GWhs):	Sales (GWhs):																	Sales (GWhs):
Residential	Residential	828		796		32		4	%	2,125		2,016		109		5	%	Residential	663		671		(8)		(1)	%
Commercial	Commercial	897		865		32		4		2,362		2,288		74		3		Commercial	700		677		23		3
Industrial	Industrial	989		923		66		7		2,786		2,643		143		5		Industrial	755		897		(142)		(16)
Other	Other	4		4		—		—		11		12		(1)		(8)		Other	4		4		—		—
Total fully bundled(1)	Total fully bundled(1)	2,718		2,588		130		5		7,284		6,959		325		5		Total fully bundled(1)	2,122		2,249		(127)		(6)
Distribution only service	Distribution only service	403		422		(19)		(5)		1,220		1,259		(39)		(3)		Distribution only service	585		397		188		47
Total retail	Total retail	3,121		3,010		111		4		8,504		8,218		286		3		Total retail	2,707		2,646		61		2
Wholesale	Wholesale	204		87		117		*		504		376		128		34		Wholesale	291		175		116		66
Total GWhs sold	Total GWhs sold	3,325		3,097		228		7	%	9,008		8,594		414		5	%	Total GWhs sold	2,998		2,821		177		6	%

Average number of retail customers (in thousands)	Average number of retail customers (in thousands)	366		359		7		2	%	365		358		7		2	%	Average number of retail customers (in thousands)	369		363		6		2	%

Average revenue per MWh:	Average revenue per MWh:																	Average revenue per MWh:
Retail - fully bundled(1)	Retail - fully bundled(1)	$	91.05	$	79.22	$	11.83	15	%	$	80.56	$	75.65	$	4.91	6	%	Retail - fully bundled(1)	$	96.40	$	73.17	$	23.23	32	%

Wholesale	Wholesale	$	48.32	$	79.72	$	(31.40)	(39)	%	$	53.39	$	54.54	$	(1.15)	(2)	%	Wholesale	$	51.14	$	60.18	$	(9.04)	(15)	%

Heating degree days	Heating degree days	41		15		26		*		2,737		2,672		65		2	%	Heating degree days	2,037		2,198		(161)		(7)	%
Cooling degree days		997		946		51		5	%	1,366		1,166		200		17	%

Sources of energy (GWhs)(2)(3):

Sources of energy (GWhs)(2):																		Sources of energy (GWhs)(2):
Natural gas	Natural gas	1,463		1,587		(124)		(8)	%	3,678		3,967		(289)		(7)	%	Natural gas	990		1,082		(92)		(9)	%
Coal	Coal	373		496		(123)		(25)	%	838		716		122		17	%	Coal	153		29		124		*
Renewables~~(4)~~(3)	Renewables~~(4)~~(3)	8		12		(4)		(33)		27		31		(4)		(13)		Renewables~~(4)~~(3)	5		6		(1)		(17)
Total energy generated	Total energy generated	1,844		2,095		(251)		(12)		4,543		4,714		(171)		(4)		Total energy generated	1,148		1,117		31		3
Energy purchased	Energy purchased	1,383		1,173		210		18		3,905		3,625		280		8		Energy purchased	1,033		1,373		(340)		(25)
Total	Total	3,227		3,268		(41)		(1)	%	8,448		8,339		109		1	%	Total	2,181		2,490		(309)		(12)	%

Average cost of energy per MWh(5):
Average cost of energy per MWh(4):																		Average cost of energy per MWh(4):
Energy generated	Energy generated	$	23.64	$	13.75	$	9.89	72	%	$	24.11	$	21.13	$	2.98	14	%	Energy generated	$	59.86	$	25.23	$	34.63	*
Energy purchased	Energy purchased	$	55.46	$	44.97	$	10.49	23	%	$	47.52	$	36.83	$	10.69	29	%	Energy purchased	$	53.19	$	38.93	$	14.26	37	%

* Not meaningful

(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 2 GWhs and 3 GWhs of coal and 6 GWhs and 7 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2021 and 2020, respectively. The average cost of energy per MWh and sources of energy excludes 2 GWhs and 3 GWhs of coal and 6 GWhs and 7 GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 2021 and 2020, respectively.

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

~~(4)~~(3) Includes the Fort Churchill Solar Array which iswas under lease by Sierra ~~Pacific.~~Pacific until it was acquired in December 2021.

~~(5)~~(4) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and ~~deferrals and does not include other costs.~~deferrals.

~~155~~135

Natural Gas Utility Margin

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

Third Quarter First Nine Months
2021 2020 Change 2021 2020 Change
Utility margin (in millions):
Operating revenue $ 16 $ 15 $ 1 7 % $ 75 $ 83 $ (8) (10) %
Natural gas purchased for resale 6 4 2 50 35 44 (9) (20)
Utility margin $ 10 $ 11 $ (1) (9) % $ 40 $ 39 $ 1 3 %
Sold (000's Dths):
Residential 774 786 (12) (2) % 6,882 6,724 158 2 %
Commercial 471 424 47 11 3,550 3,309 241 7
Industrial 274 249 25 10 1,414 1,244 170 14
Total retail 1,519 1,459 60 4 % 11,846 11,277 569 5 %
Average number of retail customers (in thousands) 177 174 3 2 % 177 174 3 2 %
Average revenue per retail Dth sold $ 10.51 $ 9.89 $ 0.62 6 % $ 6.30 $ 7.33 $ (1.03) (14) %
Heating degree days 41 15 26 * 2,737 2,672 65 2 %
Average cost of natural gas per retail Dth sold $ 3.78 $ 3.01 $ 0.77 26 % $ 2.97 $ 3.93 $ (0.96) (24) %

* Not meaningful


	First Quarter
	2022		2021		Change
Utility margin (in millions):
Operating revenue	$	52	$	39	$	13	33	%
Natural gas purchased for resale	34		21		13		62
Utility margin	$	18	$	18	$	—	—	%

Sold (000's Dths):
Residential	4,552		4,658		(106)		(2)	%
Commercial	2,512		2,304		208		9
Industrial	653		745		(92)		(12)
Total retail	7,717		7,707		10		—	%

Average number of retail customers (in thousands)	179		176		3		2	%

Average revenue per retail Dth sold	$	6.69	$	5.03	$	1.66	33	%

Heating degree days	2,037		2,198		(161)		(7)	%

Average cost of natural gas per retail Dth sold	$	4.36	$	2.73	$	1.63	60	%

Quarter Ended ~~September 30, 2021~~March 31, 2022 Compared to Quarter Ended ~~September 30, 2020~~March 31, 2021

Electric utility margin increased $74 million, or 5%4%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to:

•$53 million of higher transmission and wholesale revenue;

•$2 million of higher energy efficiency implementation rates; and

•$1 million of higher electric retail utility margin primarily due to ~~price impacts from changes in sales mix.~~higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased ~~3.7%~~2.3% primarily ~~due to favorable changes in customer usage patterns and the favorable impact of weather,~~

•~~$2 million of higher transmission and wholesale revenue and~~

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

~~Interest and dividend income~~ ~~increased $2 million for the third quarter of 2021 compared to 2020 primarily due to higher interest income, mainly from carrying charges on regulatory balances.~~

~~Income tax expense~~ ~~increased $2 million, or 33%, for the third quarter of 2021 compared to 2020, primarily due to higher pretax income. The effective tax rate was 11% in 2021 and 10% in 2020.~~

~~156~~

~~First Nine Months Ended September 30, 2021 Compared to First Nine Months Ended September 30, 2020~~

~~Electric utility margin~~ ~~increased$5 million~~, ~~or 1%~~, ~~for the first nine months of 2021 compared to 2020 primarily due to:~~

•$9 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 3.5% primarily due to favorable changes in customer usage patterns and the favorableunfavorable impact of ~~weather,~~

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

•~~$2 million of higher transmission and wholesale revenue.~~weather.

The increase in utility margin was offset by:

•$31 million inof lower ~~revenue recognized due to a favorable regulatory decision in 2020,~~

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

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

Operations and maintenance ~~decreased $6~~increased $5 million, or 5%14%, for the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to ~~lower~~higher plant operations and maintenance expenses ~~lower~~and higher earnings sharing, ~~and~~partially offset by lower energy efficiency program costs (offset in operating revenue).

~~Depreciation and amortization~~Allowance for equity funds increased $3$1 million ~~or 3%,~~ for the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to ~~regulatory amortizations and~~ higher ~~plant in service.~~construction work-in progress.

Interest and dividend income increased $3$1 million for the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to higher interest income, mainly from carrying charges on regulatory balances.

Other, net ~~increased $5~~decreased $2 million, or 50%, for the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~2020~~2021 primarily due to lower ~~pension costs and higher~~ cash surrender value of corporate-owned life insurance policies.

Income tax expense increased $3$1 million, or ~~30%~~25%, for the first ~~nine months~~quarter of ~~2021~~2022 compared to ~~2020,~~2021 primarily due to higher pretax income. The effective tax rate was ~~11%~~15% in ~~2021~~2022 and ~~10%~~13% in ~~2020.~~2021.

136

Liquidity and Capital Resources

As of ~~September 30, 2021,~~March 31, 2022, Sierra Pacific's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	1415

Credit facility	250
Less -

Short-term debt	~~(127)~~(57)
Net credit facility	~~123~~193

Total net liquidity	$	~~137~~208
Credit facility:
Maturity date	2024

Operating Activities

Net cash flows from operating activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ were ~~$113~~$63 million and ~~$179~~$42 million, respectively. The change was primarily due to higher collections from customers, partially offset by higher payments related to fuel and energy costs, higher inventory purchases and the timing of payments for ~~fuel and energy costs, partially offset by higher collections from customers, lower inventory purchases and increased collections of customer advances.~~operating costs.

~~157~~

Investing Activities

Net cash flows from investing activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ were ~~$(196)~~$(83) million and ~~$(192)~~$(61) 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 ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ were ~~$77~~$26 million and $7$8 million, respectively. The change was primarily due to ~~higher proceeds~~contributions from ~~short-term debt and lower dividends paid to~~ NV Energy, Inc., partially offset by ~~lower~~higher repayments of short-term debt.

Long-Term Debt

In April 2022, Sierra Pacific entered into a $200 million unsecured loan with NV Energy payable upon demand. The net proceeds ~~from~~were used to purchase certain tax-exempt refunding revenue bond obligations that were subject to mandatory purchase by Sierra Pacific in April 2022. The loan has an underlying variable interest rate based on 30-day U.S. dollar deposits offered on the ~~issuance~~London Interbank Offer Rate market plus a spread of ~~long-term debt.~~0.75%.

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~~$1.9 billion (excluding borrowings under Sierra Pacific's $250 million secured credit facility); and (2) maintain a revolving credit facility of up to $600 million.

137

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):


		Nine-Month Periods				Annual			Three-Month Periods				Annual
		Ended September 30,				Forecast			Ended March 31,				Forecast
		2020		2021		2021			2021		2022		2022

Electric distribution	Electric distribution	$	101	$	66	$	113	Electric distribution	$	20	$	20	$	125
Electric transmission	Electric transmission	51		50		90		Electric transmission	16		20		128
Solar generation	Solar generation	—		—		18		Solar generation	—		—		1
Other	Other	40		80		118		Other	25		43		171
Total	Total	$	192	$	196	$	339	Total	$	61	$	83	$	425

Sierra ~~Pacific's approved Fourth Amendment to the 2018 Joint~~Pacific received PUCN approval through its recent IRP ~~included~~filings for an increase in solar generation and electric transmission. Sierra Pacific has included estimates from its latest IRP filing in its forecast capital expenditures for ~~2021.~~2022. These estimates may change as a result of the RFP process. 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.

~~158~~

•Other ~~investments include~~includes both growth projects and operating expenditures consisting of turbine upgrades at the Tracy generating facility, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.

~~Contractual Obligations~~Material Cash Requirements

As of ~~September 30, 2021,~~March 31, 2022, there have been no material changes outside the normal course of business in ~~contractual obligations~~material cash requirements from the information provided in Item 7 of Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, ~~2020.~~2021.

138

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 federal, state and local agencies. ~~All such~~Sierra Pacific believes it is in material compliance with all applicable laws and regulations, although many are subject to ~~a range of~~ interpretation ~~which~~that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and 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.~~2021. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, ~~2020.~~2021.

~~159~~139

Eastern Energy Gas Holdings, LLC and its subsidiaries

Consolidated Financial Section

~~160~~140

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 ~~September 30, 2021,~~March 31, 2022, the related consolidated statements of operations, comprehensive income, ~~and~~ changes in equity ~~for the three-month~~ and ~~nine-month periods ended September 30, 2021 and 2020, and of~~ cash flows for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 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,~~2021, 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,~~25, 2022, 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,~~2021, 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.

/s/ Deloitte & Touche LLP

Richmond, Virginia

~~November 5, 2021~~April 29, 2022

~~161~~141

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


		As of					As of
		September 30, 2021		December 31, 2020			March 31, 2022		December 31, 2021
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	90	$	35	Cash and cash equivalents	$	54	$	22
Restricted cash and cash equivalents		17		13

Trade receivables, net	Trade receivables, net	143		177		Trade receivables, net	154		183
Receivables from affiliates	Receivables from affiliates	70		139		Receivables from affiliates	32		47
Income taxes receivable		52		20

Notes receivable from affiliates						Notes receivable from affiliates	122		7
Other receivables	Other receivables	7		51		Other receivables	3		9
Inventories	Inventories	127		119		Inventories	124		122
Prepayments		90		60

Natural gas imbalances	Natural gas imbalances	69		26		Natural gas imbalances	105		100
Other current assets	Other current assets	19		16		Other current assets	132		131
Total current assets	Total current assets	684		656		Total current assets	726		621

Property, plant and equipment, net	Property, plant and equipment, net	10,195		10,144		Property, plant and equipment, net	10,183		10,200
Goodwill	Goodwill	1,286		1,286		Goodwill	1,286		1,286

Investments	Investments	259		244		Investments	423		412

Other assets	Other assets	167		291		Other assets	122		129

Total assets	Total assets	$	12,591	$	12,621	Total assets	$	12,740	$	12,648

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

~~162~~142

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


		As of					As of
		September 30, 2021		December 31, 2020			March 31, 2022		December 31, 2021
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY					LIABILITIES AND EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	$	71	$	71	Accounts payable	$	42	$	79
Accounts payable to affiliates	Accounts payable to affiliates	35		39		Accounts payable to affiliates	13		38
Accrued interest	Accrued interest	49		19		Accrued interest	54		19
Accrued property, income and other taxes	Accrued property, income and other taxes	73		29		Accrued property, income and other taxes	59		89
Accrued employee expenses						Accrued employee expenses	21		13

Notes payable		—		9
Regulatory liabilities						Regulatory liabilities	44		40

Current portion of long-term debt		—		500
Other current liabilities	Other current liabilities	178		147		Other current liabilities	110		87
Total current liabilities	Total current liabilities	406		814		Total current liabilities	343		365

Long-term debt	Long-term debt	3,910		3,925		Long-term debt	3,899		3,906

Regulatory liabilities	Regulatory liabilities	646		669		Regulatory liabilities	645		645

Other long-term liabilities	Other long-term liabilities	239		218		Other long-term liabilities	263		238
Total liabilities	Total liabilities	5,201		5,626		Total liabilities	5,150		5,154

Commitments and contingencies (Note 9)		0		0
Commitments and contingencies (Note 8)						Commitments and contingencies (Note 8)	0		0

Equity:	Equity:					Equity:
Member's equity:	Member's equity:					Member's equity:

Membership interests	Membership interests	3,388		2,957		Membership interests	3,595		3,501

Accumulated other comprehensive loss, net	Accumulated other comprehensive loss, net	(42)		(53)		Accumulated other comprehensive loss, net	(38)		(43)
Total member's equity	Total member's equity	3,346		2,904		Total member's equity	3,557		3,458
Noncontrolling interests	Noncontrolling interests	4,044		4,091		Noncontrolling interests	4,033		4,036
Total equity	Total equity	7,390		6,995		Total equity	7,590		7,494

Total liabilities and equity	Total liabilities and equity	$	12,591	$	12,621	Total liabilities and equity	$	12,740	$	12,648

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

~~163~~143

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020			2022		2021

Operating revenue	Operating revenue	$	456	$	531	$	1,379	$	1,597	Operating revenue	$	482	$	486

Operating expenses:	Operating expenses:									Operating expenses:

(Excess) cost of gas		(3)		14		(13)		23
Excess gas										Excess gas	(1)		—
Operations and maintenance	Operations and maintenance	125		119		362		922		Operations and maintenance	118		124
Depreciation and amortization	Depreciation and amortization	83		95		244		282		Depreciation and amortization	85		80
Property and other taxes	Property and other taxes	38		38		115		109		Property and other taxes	29		39

Total operating expenses	Total operating expenses	243		266		708		1,336		Total operating expenses	231		243

Operating income	Operating income	213		265		671		261		Operating income	251		243

Other income (expense):	Other income (expense):									Other income (expense):
Interest expense	Interest expense	(32)		(186)		(118)		(294)		Interest expense	(36)		(44)

Allowance for equity funds	Allowance for equity funds	2		1		5		11		Allowance for equity funds	2		2
Interest and dividend income		—		10		—		67

Other, net	Other, net	(1)		11		1		39		Other, net	(1)		1
Total other income (expense)	Total other income (expense)	(31)		(164)		(112)		(177)		Total other income (expense)	(35)		(41)

Income before income tax expense (benefit) and equity income		182		101		559		84
Income tax expense (benefit)		21		(10)		70		(40)
Income before income tax expense and equity income										Income before income tax expense and equity income	216		202
Income tax expense										Income tax expense	30		27
Equity income	Equity income	8		7		31		30		Equity income	19		16

Net income	Net income	169		118		520		154		Net income	205		191
Net income attributable to noncontrolling interests	Net income attributable to noncontrolling interests	100		32		302		97		Net income attributable to noncontrolling interests	111		102
Net income attributable to Eastern Energy Gas	Net income attributable to Eastern Energy Gas	$	69	$	86	$	218	$	57	Net income attributable to Eastern Energy Gas	$	94	$	89

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

~~164~~144

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)


		Three-Month Periods				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020			2022		2021

Net income	Net income	$	169	$	118	$	520	$	154	Net income	$	205	$	191

Other comprehensive (loss) income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $—, $(1), $— and $—		—		(4)		4		(1)
Other comprehensive income, net of tax:										Other comprehensive income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $— and $—										Unrecognized amounts on retirement benefits, net of tax of $— and $—	1		2

Unrealized (losses) gains on cash flow hedges, net of tax of $(1), $37, $2 and $8		(2)		111		11		24
Total other comprehensive (loss) income, net of tax		(2)		107		15		23
Unrealized gains on cash flow hedges, net of tax of $1 and $3										Unrealized gains on cash flow hedges, net of tax of $1 and $3	4		10
Total other comprehensive income, net of tax										Total other comprehensive income, net of tax	5		12

Comprehensive income	Comprehensive income	167		225		535		177		Comprehensive income	210		203
Comprehensive income attributable to noncontrolling interests	Comprehensive income attributable to noncontrolling interests	100		32		306		97		Comprehensive income attributable to noncontrolling interests	111		106
Comprehensive income attributable to Eastern Energy Gas	Comprehensive income attributable to Eastern Energy Gas	$	67	$	193	$	229	$	80	Comprehensive income attributable to Eastern Energy Gas	$	99	$	97

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

~~165~~145

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)


				Accumulated									Accumulated
				Other									Other
		Membership		Comprehensive		Noncontrolling		Total			Membership		Comprehensive		Noncontrolling		Total
		Interests		Loss, Net		Interests		Equity			Interests		Loss, Net		Interests		Equity

Balance, June 30, 2020		$	7,352	$	(271)	$	1,375	$	8,456
Net income		86		—		32		118
Other comprehensive income		—		107		—		107
Contributions		299		—		—		299
Distributions		(2,394)		—		(36)		(2,430)
Balance, September 30, 2020		$	5,343	$	(164)	$	1,371	$	6,550

Balance, December 31, 2019		$	9,031	$	(187)	$	1,385	$	10,229

Balance, December 31, 2020										Balance, December 31, 2020	$	2,957	$	(53)	$	4,091	$	6,995
Net income	Net income	57		—		97		154		Net income	89		—		102		191
Other comprehensive income	Other comprehensive income	—		23		—		23		Other comprehensive income	—		8		4		12

Contributions	Contributions	299		—		—		299		Contributions	11		—		—		11
Distributions	Distributions	(4,044)		—		(111)		(4,155)		Distributions	(22)		—		(109)		(131)

Balance, September 30, 2020		$	5,343	$	(164)	$	1,371	$	6,550
Balance, March 31, 2021										Balance, March 31, 2021	$	3,035	$	(45)	$	4,088	$	7,078

Balance, June 30, 2021		$	3,366	$	(40)	$	4,072	$	7,398
Net income		69		—		100		169
Other comprehensive loss		—		(2)		—		(2)
Contributions		2		—		—		2
Distributions		(49)		—		(128)		(177)
Balance, September 30, 2021		$	3,388	$	(42)	$	4,044	$	7,390

Balance, December 31, 2020		$	2,957	$	(53)	$	4,091	$	6,995

Balance, December 31, 2021										Balance, December 31, 2021	$	3,501	$	(43)	$	4,036	$	7,494
Net income	Net income	218		—		302		520		Net income	94		—		111		205
Other comprehensive income	Other comprehensive income	—		11		4		15		Other comprehensive income	—		5		—		5
Contributions		284		—		—		284

Distributions	Distributions	(71)		—		(353)		(424)		Distributions	—		—		(114)		(114)

Balance, September 30, 2021		$	3,388	$	(42)	$	4,044	$	7,390
Balance, March 31, 2022										Balance, March 31, 2022	$	3,595	$	(38)	$	4,033	$	7,590

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

~~166~~146

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


		Nine-Month Periods					Three-Month Periods
		Ended September 30,					Ended March 31,
		2021		2020			2022		2021
Cash flows from operating activities:	Cash flows from operating activities:					Cash flows from operating activities:
Net income	Net income	$	520	$	154	Net income	$	205	$	191
Adjustments to reconcile net income to net cash flows from operating activities:	Adjustments to reconcile net income to net cash flows from operating activities:					Adjustments to reconcile net income to net cash flows from operating activities:

(Gains) losses on other items, net		(9)		463
Losses on other items, net						Losses on other items, net	1		—
Depreciation and amortization	Depreciation and amortization	244		282		Depreciation and amortization	85		80
Allowance for equity funds	Allowance for equity funds	(5)		(11)		Allowance for equity funds	(2)		(2)
Equity (income) loss, net of distributions		(1)		33
Equity income, net of distributions						Equity income, net of distributions	(8)		(5)
Changes in regulatory assets and liabilities	Changes in regulatory assets and liabilities	(2)		19		Changes in regulatory assets and liabilities	(14)		6
Deferred income taxes	Deferred income taxes	135		(103)		Deferred income taxes	27		30
Other, net	Other, net	(11)		8		Other, net	2		—
Changes in other operating assets and liabilities:	Changes in other operating assets and liabilities:					Changes in other operating assets and liabilities:
Trade receivables and other assets	Trade receivables and other assets	13		271		Trade receivables and other assets	44		(56)
Derivative collateral, net	Derivative collateral, net	7		148		Derivative collateral, net	2		2
Pension and other postretirement benefit plans		—		(46)

Accrued property, income and other taxes	Accrued property, income and other taxes	(61)		36		Accrued property, income and other taxes	(29)		(25)
Accounts payable and other liabilities	Accounts payable and other liabilities	37		5		Accounts payable and other liabilities	28		20
Net cash flows from operating activities	Net cash flows from operating activities	867		1,259		Net cash flows from operating activities	341��		241

Cash flows from investing activities:	Cash flows from investing activities:					Cash flows from investing activities:
Capital expenditures	Capital expenditures	(291)		(258)		Capital expenditures	(75)		(55)

Repayment of loans by affiliates	Repayment of loans by affiliates	269		3,422		Repayment of loans by affiliates	3		—
Loans to affiliates	Loans to affiliates	(170)		(225)		Loans to affiliates	(117)		—

Other, net	Other, net	(9)		(9)		Other, net	(5)		(1)
Net cash flows from investing activities	Net cash flows from investing activities	(201)		2,930		Net cash flows from investing activities	(194)		(56)

Cash flows from financing activities:	Cash flows from financing activities:					Cash flows from financing activities:

Repayments of long-term debt		(500)		—
Net repayments of short-term debt		—		(62)

Repayment of notes payable, net	Repayment of notes payable, net	(9)		(253)		Repayment of notes payable, net	—		(9)

Proceeds from equity contributions		256		299

Distributions	Distributions	(353)		(4,155)		Distributions	(114)		(109)

Other, net		(1)		(1)

Net cash flows from financing activities	Net cash flows from financing activities	(607)		(4,172)		Net cash flows from financing activities	(114)		(118)

Net change in cash and cash equivalents and restricted cash and cash equivalents	Net change in cash and cash equivalents and restricted cash and cash equivalents	59		17		Net change in cash and cash equivalents and restricted cash and cash equivalents	33		67
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	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 beginning of period	39		48
Cash and cash equivalents and restricted cash and cash equivalents at end of period	Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	107	$	56	Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	72	$	115

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

~~167~~147

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

Eastern Energy Gas Holdings, LLC is a holding company, and together with 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~~U.S. 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~~is an indirect wholly owned subsidiary of 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 ("Dominion Questar"), 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 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 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~~2021 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 ~~nine-month~~three-month period ended ~~September 30, 2021.~~March 31, 2022.

~~168~~148

(2) Property, Plant and Equipment, Net

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


			As of						As of
			September 30,		December 31,				March 31,		December 31,
		Depreciable Life	2021		2020			Depreciable Life	2022		2021
Utility Plant:	Utility Plant:						Utility Plant:

Interstate natural gas pipeline assets	Interstate natural gas pipeline assets	24 - 43 years	$	8,555	$	8,382	Interstate natural gas pipeline assets	21 - 44 years	$	8,776	$	8,675
Intangible plant	Intangible plant	5 - 10 years	111		115		Intangible plant	5 - 10 years	110		110
Utility plant in service			8,666		8,497
Utility plant in-service							Utility plant in-service		8,886		8,785
Accumulated depreciation and amortization	Accumulated depreciation and amortization		(2,859)		(2,759)		Accumulated depreciation and amortization		(2,936)		(2,901)
Utility plant in service, net			5,807		5,738
Utility plant in-service, net							Utility plant in-service, net		5,950		5,884

Nonutility Plant:	Nonutility Plant:						Nonutility Plant:

LNG facility	LNG facility	40 years	4,466		4,454		LNG facility	40 years	4,477		4,475
Intangible plant	Intangible plant	14 years	25		25		Intangible plant	14 years	25		25
Nonutility plant in service			4,491		4,479
Nonutility plant in-service							Nonutility plant in-service		4,502		4,500
Accumulated depreciation and amortization	Accumulated depreciation and amortization		(396)		(283)		Accumulated depreciation and amortization		(454)		(423)
Nonutility plant in service, net			4,095		4,196

Nonutility plant in-service, net							Nonutility plant in-service, net		4,048		4,077
Plant, net	Plant, net		9,902		9,934		Plant, net		9,998		9,961
Construction work-in-progress	Construction work-in-progress		293		210		Construction work-in-progress		185		239
Property, plant and equipment, net	Property, plant and equipment, net		$	10,195	$	10,144	Property, plant and equipment, net		$	10,183	$	10,200

Construction work-in-progress includes ~~$266~~$151 million and ~~$196~~$209 million as of ~~September 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, respectively, related to the construction of utility plant.

~~169~~149

(3) Investments and Restricted Cash and Cash Equivalents

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


		As of					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021
Investments:	Investments:					Investments:
Investment funds	Investment funds	$	13	$	—	Investment funds	$	15	$	13

Equity method investments:	Equity method investments:					Equity method investments:
Iroquois	Iroquois	246		244		Iroquois	408		399

Total investments	Total investments	259		244		Total investments	423		412

Restricted cash and cash equivalents:	Restricted cash and cash equivalents:					Restricted cash and cash equivalents:
Customer deposits	Customer deposits	17		13		Customer deposits	18		17
Total restricted cash and cash equivalents	Total restricted cash and cash equivalents	17		13		Total restricted cash and cash equivalents	18		17

Total investments and restricted cash and cash equivalents	Total investments and restricted cash and cash equivalents	$	276	$	257	Total investments and restricted cash and cash equivalents	$	441	$	429

Reflected as:	Reflected as:					Reflected as:
Current assets	Current assets	$	17	$	13	Current assets	$	18	$	17
Noncurrent assets	Noncurrent assets	259		244		Noncurrent assets	423		412
Total investments and restricted cash and cash equivalents	Total investments and restricted cash and cash equivalents	$	276	$	257	Total investments and restricted cash and cash equivalents	$	441	$	429

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 ~~September 30, 2021~~both March 31, 2022 and December 31, ~~2020,~~2021, 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 ~~$30~~$11 million and ~~$63~~$10 million for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021, ~~and 2020,~~ respectively.

~~170~~150

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, ~~United States~~U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents ~~as of September 30, 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 September 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					As of
		September 30,		December 31,			March 31,		December 31,
		2021		2020			2022		2021

Cash and cash equivalents	Cash and cash equivalents	$	90	$	35	Cash and cash equivalents	$	54	$	22
Restricted cash and cash equivalents		17		13
Restricted cash and cash equivalents included in other current assets						Restricted cash and cash equivalents included in other current assets	18		17
Total cash and cash equivalents and restricted cash and cash equivalents	Total cash and cash equivalents and restricted cash and cash equivalents	$	107	$	48	Total cash and cash equivalents and restricted cash and cash equivalents	$	72	$	39

(4) Regulatory Matters

~~Eastern Gas Transmission and Storage, Inc.~~

In September 2021, Eastern Gas Transmission and Storage, Inc. ("EGTS") filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS' previous general rate case was settled in 1998. EGTS proposed an annual cost-of-service of approximately $1.1 ~~billion. EGTS has~~billion, and requested increases in various rates, including general system storage rates by 85% and general system transportation rates by 60%. In October 2021, the FERC issued an order that accepted the November 1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund and the outcome of hearing procedures. This matter is pending.

In July 2017, the FERC audit staff communicated to 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 September 2021, the FERC approved EGTS' accounting entries and supporting documentation.

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. In the third quarter of 2020, Eastern Energy Gas recorded an additional charge of $10 million ($7 million after-tax) associated with the probable abandonment of a significant portion of the project and a $29 million ($20 million after-tax) benefit from a revision to the previously established asset retirement obligation, both of which were recorded in operations and maintenance expense in Eastern Energy Gas' Consolidated Statements of Operations. As EGTS evaluates its future use, approximately $40 million remains within property, plant and equipment for a potential modified project.

~~171~~

~~Cove Point~~

(5) ~~Recent Financing Transactions~~

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

~~172~~

~~(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				Nine-Month Periods					Three-Month Periods
		Ended September 30,				Ended September 30,					Ended March 31,
		2021		2020		2021		2020				2022		2021

Federal statutory income tax rate	Federal statutory income tax rate	21	%	21	%	21	%	21	%	Federal statutory income tax rate		21	%	21	%
State income tax, net of federal income tax benefit	State income tax, net of federal income tax benefit	2		(3)		2		(29)		State income tax, net of federal income tax benefit		5		3

Equity interest	Equity interest	1		—		1		8		Equity interest		2		2
Effects of ratemaking	Effects of ratemaking	(1)		(2)		(1)		(6)		Effects of ratemaking		(4)		(1)

Change in tax status		—		(18)		—		(24)

AFUDC-equity		—		—		—		(2)

Noncontrolling interest	Noncontrolling interest	(11)		(6)		(11)		(24)		Noncontrolling interest		(11)		(11)
Write-off of regulatory assets		—		—		—		9

Other, net	Other, net	—		(2)		1		(1)		Other, net		1		(1)
Effective income tax rate	Effective income tax rate	12	%	(10)	%	13	%	(48)	%	Effective income tax rate		14	%	13	%

~~Noncontrolling interest is attributable to~~For the period ended March 31, 2022, Eastern Energy Gas' ~~ownership in Cove Point. The GT&S Transaction resulted in a change~~reconciliation of ~~noncontrolling interest to 75% as of September 30, 2021 from 25% as of September 30, 2020. Additionally, Eastern Energy Gas' effective~~the federal statutory income tax rate ~~for~~to the ~~periods ended September 30, 2020~~effective income tax rate is driven primarily ~~a function~~by an absence of ~~the impacts associated with the cancellation of the Atlantic Coast Pipeline project, the nominal year-to-date pre-tax~~tax on income ~~driven by charges associated with the Supply Header Project and the finalization of the effects from the change in tax status of certain Eastern Energy Gas subsidiaries.~~attributable to Cove Point's 75% noncontrolling interest.

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~~U.S. 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 ~~received net~~made no cash payments for income tax ~~from~~to BHE ~~totaling $34 million~~ for the ~~nine-month period~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021.

151

~~(7)~~

(6) 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,~~is a ~~defined~~participant in benefit ~~pension plan~~plans 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~~, an affiliate. The MidAmerican Energy Company Retirement Plan ~~similar to the DEI plan.~~

~~Prior to the GT&S Transaction,~~includes a qualified pension plan that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain ~~retiree healthcare~~postretirement health care and life insurance benefits for eligible retirees on behalf of Eastern Energy Gas. 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 priorcontributed $3 million to the ~~GT&S Transaction, retiree health~~MidAmerican Energy Company Retirement Plan and ~~life insurance benefits~~$1 million to the MidAmerican Energy Company Welfare Benefit Plan for the three-month period ended March 31, 2022. Amounts attributable to Eastern Energy Gas ~~employees represented by collective bargaining units~~ were ~~covered by a separate other postretirement benefit plan that provides benefits to both EGTS~~allocated from MidAmerican Energy in accordance with the intercompany administrative service agreement. Offsetting regulatory assets and ~~Hope. Subsequent~~liabilities have been recorded related 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.~~

~~173~~

amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit ~~credit for~~costs not included in regulated rates are included in accumulated other comprehensive loss, net. As of both March 31, 2022 and December 31, 2021, Eastern Energy Gas' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the ~~pension and other postretirement benefit plans included the following components (in millions):~~

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2021 2020 2021 2020
Pension:
Service cost $ — $ 2 $ — $ 5
Interest cost — 3 — 8
Expected return on plan assets — (14) — (42)
Net amortization — 1 — 5
Net periodic benefit credit $ — $ (8) $ — $ (24)
Other Postretirement:
Service cost $ — $ — $ — $ 1
Interest cost — 1 — 3
Expected return on plan assets — (4) — (14)
Net amortization — (1) — (2)
Net periodic benefit credit $ — $ (4) $ — $ (12)
Consolidated Balance Sheets was $95 million.

~~(8)~~(7) 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.

~~174~~152

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									Input Levels for Fair Value Measurements
		Level 1		Level 2		Level 3		Total			Level 1		Level 2		Level 3		Total
As of September 30, 2021
As of March 31, 2022:										As of March 31, 2022:
Assets:	Assets:									Assets:

Foreign currency exchange rate derivatives		$	—	$	8	$	—	$	8

Money market mutual funds	Money market mutual funds	75		—		—		75		Money market mutual funds	$	28	$	—	$	—	$	28
Equity securities:										Equity securities:
Investment funds	Investment funds	13		—		—		13		Investment funds	15		—		—		15
		$	88	$	8	$	—	$	96		$	43	$	—	$	—	$	43

Liabilities:	Liabilities:									Liabilities:
Commodity derivatives	Commodity derivatives	$	—	$	(1)	$	—	$	(1)	Commodity derivatives	$	—	$	(2)	$	—	$	(2)
Foreign currency exchange rate derivatives	Foreign currency exchange rate derivatives	—		(4)		—		(4)		Foreign currency exchange rate derivatives	—		(3)		—		(3)

		$	—	$	(5)	$	—	$	(5)		$	—	$	(5)	$	—	$	(5)

As of December 31, 2020
As of December 31, 2021:										As of December 31, 2021:
Assets:	Assets:									Assets:

Foreign currency exchange rate derivatives										Foreign currency exchange rate derivatives	$	—	$	3	$	—	$	3
Equity securities:										Equity securities:
Investment funds										Investment funds	13		—		—		13
											$	13	$	3	$	—	$	16

Liabilities:										Liabilities:

Foreign currency exchange rate derivatives	Foreign currency exchange rate derivatives	$	—	$	20	$	—	$	20	Foreign currency exchange rate derivatives	$	—	$	(3)	$	—	$	(3)

		$	—	$	20	$	—	$	20		$	—	$	(3)	$	—	$	(3)

Liabilities:
Commodity derivatives		$	—	$	(1)	$	—	$	(1)
Foreign currency exchange rate derivatives		—		(2)		—		(2)
Interest rate derivatives		—		(6)		—		(6)
		$	—	$	(9)	$	—	$	(9)

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.

~~175~~153

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.~~Financial Statements. 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 September 30, 2021 As of December 31, 2020
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $ 3,910 $ 4,327 $ 4,425 $ 5,012


	As of March 31, 2022				As of December 31, 2021
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	3,899	$	3,911	$	3,906	$	4,266

~~(9)~~(8) 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, renewable portfolio standards, air and water quality, emissions performance standards, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact ~~its~~Eastern Energy Gas' current and future operations. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations.

~~(10)~~(9) 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 Nine-Month Periods
Ended September 30, Ended September 30,
2021 2020 2021 2020
Customer Revenue:
Regulated:
Gas transportation and storage $ 249 $ 311 $ 774 $ 957
Wholesale 14 25 31 27
Other 1 1 (1) 4
Total regulated 264 337 804 988
Nonregulated 193 193 573 606
Total Customer Revenue 457 530 1,377 1,594
Other revenue (1) 1 2 3
Total operating revenue $ 456 $ 531 $ 1,379 $ 1,597


	Three-Month Periods
	Ended March 31,
		2022		2021
Customer Revenue:
Regulated:
Gas transportation and storage		$	285	$	279
Wholesale		—		17

Total regulated		285		296




Nonregulated		203		190
Total Customer Revenue		488		486
Other revenue		(6)		—
Total operating revenue		$	482	$	486

~~176~~154

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 ~~September 30, 2021~~March 31, 2022 (in millions):

Performance obligations expected to be satisfied
Less than 12 months More than 12 months Total
Eastern Energy Gas $ 1,574 $ 16,413 $ 17,987


	Performance obligations expected to be satisfied
	Less than 12 months		More than 12 months		Total
Eastern Energy Gas	$	1,832	$	17,061	$	18,893

~~(11)~~(10) 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 (loss) income (1) 24 — 23
Balance, September 30, 2020 $ (107) $ (57) $ — $ (164)
Balance, December 31, 2020 $ (12) $ (51) $ 10 $ (53)
Other comprehensive income (loss) 4 11 (4) 11
Balance, September 30, 2021 $ (8) $ (40) $ 6 $ (42)

In July 2020, Eastern Energy Gas recorded a loss of $141 million ($105 million after-tax) in interest expense in the Consolidated Statement of Operations, for cash flow hedges of debt-related items that were probable of not occurring as a result of the GT&S Transaction.

~~(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.


	Unrecognized						Accumulated
	Amounts On		Unrealized				Other
	Retirement		Losses on Cash		Noncontrolling		Comprehensive
	Benefits		Flow Hedges		Interests		Loss, Net
Balance, December 31, 2020	$	(12)	$	(51)	$	10	$	(53)
Other comprehensive income (loss)	2		10		(4)		8
Balance, March 31, 2021	$	(10)	$	(41)	$	6	$	(45)

Balance, December 31, 2021	$	(6)	$	(42)	$	5	$	(43)
Other comprehensive income	1		4		—		5
Balance, March 31, 2022	$	(5)	$	(38)	$	5	$	(38)

~~177~~

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 September 30, 2021 and 2020, and $9 million and $10 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Eastern Energy Gas' Consolidated Balance Sheets included amounts due to Carolina Gas Services of $31 million and $22 million as of September 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.

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 $21 million for the three- and nine-month periods ended September 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 $22 million and $80 million for the three- and nine-month periods ended September 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 nine-month periods ended September 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.~~

~~178~~

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

Three-Month Period Nine-Month Period
Ended September 30, 2020 Ended September 30, 2020
Sales of natural gas and transportation and storage services $ 60 $ 188
Purchases of natural gas and transportation and storage services 3 9
Services provided by related parties(1)
34 114
Services provided to related parties(2)
17 78

~~(1) Includes capitalized expenditures of $5 million and $12 million for the three- and nine-month periods ended September 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 the affiliated notes receivable under the DEI money pool was $3 million for the nine-month period ended September 30, 2020.~~

~~Interest income related to Eastern Energy Gas' affiliated notes receivable from DEI was $9 million and $32 million for the three- and nine-month periods ended September 30, 2020, respectively.~~

~~Interest income related to Eastern Energy Gas' affiliated notes receivable from East Ohio Gas Company was $33 million for the nine-month period ended September 30, 2020.~~

~~Interest charges related to Eastern Energy Gas' total borrowings under an intercompany revolving credit agreement with DEI were $3 million for the nine-month period ended September 30, 2020.~~

~~Interest charges related to CPMLP Holdings Company, LLC's total borrowings from DES were $3 million for the nine-month period ended September 30, 2020.~~

~~For the nine-month period ended September 30, 2020, Eastern Energy Gas distributed $4.2 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 $31 million and $20 million as of September 30, 2021 and December 31, 2020, respectively.

~~Other assets included amounts due from an affiliate of $4 million and $7 million as of September 30, 2021 and December 31, 2020, respectively.~~

~~As of September 30, 2021, Eastern Energy Gas had $3 million of natural gas imbalances payable to affiliates, presented in other current liabilities on the Consolidated Balance Sheet.~~

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

Three-Month Period Nine-Month Period
Ended September 30, 2021 Ended September 30, 2021
Sales of natural gas and transportation and storage services $ 7 $ 21
Purchases of natural gas and transportation and storage services 1 4
Services provided by related parties 16 31
Services provided to related parties 8 24

~~179~~

Eastern Energy Gas has a $400 million intercompany revolving credit agreement from its parent, BHE GT&S, LLC ("BHE GT&S") expiring in November 2022. The credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on London Interbank Offered Rate ("LIBOR") plus a fixed spread. As of September 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 2022. 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 September 30, 2021 and December 31, 2020, $28 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 September 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.

~~180~~155

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 ~~Third~~First Quarter of 2022 and ~~First Nine Months of~~ 2021 ~~and 2020~~

Overview

Net income attributable to Eastern Energy Gas for the ~~third~~first quarter of ~~2021~~2022 was $69 million, a decrease of $17 million compared to 2020. Net income decreased primarily due to an increase in net income attributable 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 $26 million and a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI of $14 million, all of which were a result of the GT&S Transaction, and income tax expense of $21 million in 2021 versus income tax benefit of $10 million in 2020, primarily due to higher pre-tax income. These decreases were partially offset by a 2020 charge of $141 million for cash flow hedges of debt-related items that were probable of not occurring as a result of the GT&S Transaction.

~~Net income attributable to Eastern Energy Gas for the first nine months of 2021 was $218~~$94 million, an increase of ~~$161~~$5 million compared to ~~2020.~~2021. Net income increased primarily due to ~~a 2020 charge~~lower than estimated 2021 tax assessments of ~~$463~~$10 million ~~associated with the probable abandonment~~and lower interest expense 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"), a 2020 charge of $141$8 million ~~for cash flow hedges of debt-related items that were probable of not occurring as a result of the GT&S Transaction and higher margins of $39 million~~primarily due to ~~favorable natural gas prices.~~the repayment of long-term debt in the second quarter of 2021. These increases were partially offset by ~~a decrease in net income~~lower margins from regulated gas transportation and storage operations of $16 million due to an increase in net income attributable to DEI's 50% noncontrolling interest in Cove Point of $205 million, the November 2020 disposition of Questar Pipeline Group of $68 million, interest income from DEIunfavorable natural gas prices and its affiliates recognized in 2020 of $65 million and a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI of $42 million, all of which were a result of the GT&S Transaction, and income tax expense of $70 million in 2021 versus income tax benefit of $40 million in 2020, primarily due to higher pre-tax income.volumes.

Quarter Ended ~~September 30, 2021~~March 31, 2022 Compared to Quarter Ended ~~September 30, 2020~~March 31, 2021

Operating revenue decreased ~~$75~~$4 million, or ~~14%~~1%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020,~~2021, primarily due to ~~the November 2020 disposition of Questar Pipeline Group of $58 million and~~ a decrease in regulated gas ~~sales~~revenues for operational and system balancing purposes ~~primarily~~ due to decreased ~~prices~~volumes of ~~$11~~$17 million, partially offset by an increase in Cove Point liquefied natural gas variable revenue of $13 million.

~~(Excess) cost of~~Excess gaswas a credit of $3$1 million for the ~~third~~first quarter of ~~2021 compared to an expense of $14 million for the third quarter of 2020. The change in (excess) cost of gas is~~2022, primarily due to a ~~favorable~~decrease in volumes sold of $14 million, partially offset by an unfavorable change in natural gas ~~prices.~~prices of $9 million and increased volumes of $4 million.

Operations and maintenance ~~increased~~decreased $6 million, or 5%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020,~~2021, primarily due to a ~~2020~~decrease in postretirement benefit associated with the probable abandonment of a significant portion of the Supply Header Project of $19 million, partially offset by the November 2020 disposition of Questar Pipeline Group of $13 million.costs.

Depreciation and amortization ~~decreased $12~~increased $5 million, or ~~13%~~6%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020,~~2021, primarily due to higher plant placed in-service.

Property and other taxes decreased $10 million, or 26%, for the ~~November 2020 disposition~~first quarter of ~~Questar Pipeline Group.~~2022 compared to 2021, primarily due to lower than estimated 2021 tax assessments.

Interest expense decreased $~~154~~8 million, or ~~83%~~18%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020,~~2021, primarily due to a charge in 2020 for cash flow hedges of $141 million of debt-related items that were probable of not occurring as a result of the GT&S Transaction, the November 2020 disposition of Questar Pipeline Group of $5 million and lower interest expense of $5 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020 and $4 million from the repayment of $500 million of long-term debt in the second quarter of 2021.

~~Interest and dividend income~~Income tax expense ~~decreased $10~~increased $3 million, or 11%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020,~~2021 primarily due to ~~interest income from DEI recognized in 2020 as a result of the GT&S Transaction.~~

~~181~~

~~Other, net~~ ~~was an expense of $1 million for the third quarter of 2021 compared to income of $11 million for the third quarter of 2020.~~higher pre-tax income. The ~~change in other, net is 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 $21 million for the third quarter of 2021 compared to a benefit of $10 million for the third quarter of 2020 and the~~ effective tax rate was ~~12%~~14% for the ~~third~~first quarter of ~~2021~~2022 and ~~(10)%~~13% for the ~~third~~first quarter of 2020. The effective tax rate increased primarily due to the change in the noncontrolling interest of Cove Point as a result of the GT&S Transaction, lower pre-tax income driven by charges associated with the Supply Header Project and the finalization of the effects from the change in tax status of certain Eastern Energy Gas subsidiaries in 2020.2021.

Net income attributable to noncontrolling interests increased ~~$68~~$9 million, or 9%, for the ~~third~~first quarter of ~~2021~~2022 compared to ~~2020~~2021, primarily due to ~~DEI's 50% noncontrolling interest~~an increase in Cove Point ~~effective with the GT&S Transaction.~~liquefied natural gas variable revenue.

~~First Nine Months Ended September 30, 2021 Compared to First Nine Months Ended September 30, 2020~~

156

~~Operating revenue~~ decreased $218 million, or 14%, for the first nine months of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group of $178 million and a decrease in services performed for Atlantic Coast Pipeline, LLC of $40 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 prices of $6 million.

~~(Excess) cost of gas~~ was a credit of $13 million for the first nine months of 2021 compared to an expense of $23 million for the first nine months of 2020. The change in (excess) cost of gas is primarily due to a favorable change in natural gas prices of $48 million and the November 2020 disposition of Questar Pipeline Group of $3 million, partially offset by an increase in prices of natural gas sold of $15 million.

~~Operations and maintenance~~ decreased $560 million, or 61%, for the first nine 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 $463 million, a decrease in services performed for Atlantic Coast Pipeline, LLC of $41 million and the November 2020 disposition of Questar Pipeline Group of $39 million.

~~Depreciation and amortization~~ ~~decreased $38 million, or 13%, for the first nine 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 6%, for the first nine months of 2021 compared to 2020, primarily due to higher tax assessments.~~

~~Interest expense~~ decreased $176 million, or 60%, for the first nine months of 2021 compared to 2020, primarily due to a charge in 2020 for cash flow hedges of $141 million of debt-related items that were probable of not occurring as a result of the GT&S Transaction, the November 2020 disposition of Questar Pipeline Group of $15 million and lower interest expense of $15 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020 and $4 million from the repayment of $500 million of long-term debt in the second quarter of 2021.

~~Allowance for equity funds~~ decreased $6 million, or 55%, for the first nine 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 $67 million for the first nine months of 2021 compared to 2020, primarily due to interest income from the East Ohio Gas Company of $33 million and DEI of $32 million recognized in 2020 as a result of the GT&S Transaction.

~~Other, net~~ decreased $38 million, or 97%, for the first nine 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 $70 million for the first nine months of 2021 compared to a benefit of $40 million for the first nine months of 2020 and the effective tax rate was 13% for the first nine months of 2021 and (48)% for the first nine months of 2020. The effective tax rate increased primarily due to the change in the noncontrolling interest of Cove Point as a result of the GT&S Transaction, lower pre-tax income driven by charges associated with the Supply Header Project and the finalization of the effects from the change in tax status of certain Eastern Energy Gas subsidiaries in 2020.

~~182~~

~~Net income attributable to noncontrolling interests~~ ~~increased $205 million for the first nine months of 2021 compared to 2020 primarily due to DEI's 50% noncontrolling interest in Cove Point effective with the GT&S Transaction.~~

Liquidity and Capital Resources

As of ~~September 30, 2021,~~March 31, 2022, Eastern Energy Gas' total net liquidity was ~~$490~~$454 million as follows (in millions):


Cash and cash equivalents	$	9054

Intercompany revolving credit agreement~~(1)~~	400





Total net liquidity	$	~~490~~454

Intercompany revolving credit agreement:
Maturity date	2022

~~(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 ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ were ~~$867~~$341 million and ~~$1.3 billion,~~$241 million, respectively. The change was primarily due to ~~lower collections~~increased cash receipts from ~~affiliates, lower income tax receipts, lower distributions from equity method investments~~receivables and ~~the timing of payments of operating costs.~~other working capital adjustments.

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 ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2022 and 2021 ~~and 2020~~ were ~~$(201)~~$(194) million and ~~$2.9 billion,~~$(56) million, respectively. The change was primarily due to ~~a decrease in repayments of loans by affiliates of $3.2 billion, partially offset by a decrease in~~ loans to ~~affiliates~~its parent under an intercompany revolving credit agreement of ~~$55~~$117 million and an increase in capital expenditures of $20 million.

Financing Activities

Net cash flows from financing activities for the ~~nine-month~~three-month period ended ~~September 30, 2021~~March 31, 2022 were ~~$(607)~~$(114) 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 ~~$863~~$114 million and consisted ~~mainly~~ of ~~repayments of long-term debt of $500 million,~~ distributions to noncontrolling interests from Cove ~~Point of $353 million and repayment of notes to affiliates of $9 million.~~Point.

Net cash flows from financing activities for the ~~nine-month~~three-month period ended ~~September 30, 2020~~March 31, 2021 were ~~$(4.2) billion. Sources of cash totaled $299 million and consisted of equity contributions.~~$(118) million. Uses of cash totaled ~~$4.5 billion~~$118 million and consisted ~~mainly~~primarily of distributions to ~~DEI~~noncontrolling interests from Cove Point of ~~$4.2 billion, repayment of notes to affiliates of $253 million and repayments of short-term debt of $62~~$109 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.

~~183~~

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.~~

157

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):


		Nine-Month Periods				Annual			Three-Month Periods				Annual
		Ended September 30,				Forecast			Ended March 31,				Forecast
		2020		2021		2021			2021		2022		2022

Natural gas transmission and storage	Natural gas transmission and storage	$	89	$	15	$	22	Natural gas transmission and storage	$	8	$	7	$	57
Other	Other	169		276		454		Other	47		68		319
Total	Total	$	258	$	291	$	476	Total	$	55	$	75	$	376

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~~Material Cash Requirements

As of ~~September 30, 2021,~~March 31, 2022, there have been no material changes outside the normal course of business in ~~contractual obligations~~material cash requirements from the information provided in Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, ~~2020.~~

2021.

~~184~~

Regulatory Matters

Eastern Energy Gas is subject to comprehensive regulation. Refer to ~~Note 4 of Notes to Consolidated Financial Statements~~"Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 12 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, RPS, air and water quality, emissions performance standards, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact ~~its~~Eastern Energy Gas' 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. Environmental laws and regulations continue to evolve, and Eastern Energy Gas is unable to predict the impact of the changing laws and regulations on its operations and consolidated 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, 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.~~2021. There have been no significant changes in Eastern Energy Gas' assumptions regarding critical accounting estimates since December 31, ~~2020.~~2021.

~~185~~158

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.~~2021. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, ~~2020.~~2021. Refer to Note 6 of the Notes to Consolidated Financial Statements of PacifiCorp, Note 6 of the Notes to Consolidated Financial Statements of Nevada Power and Note 7 of the Notes to Consolidated Financial Statements of ~~PacifiCorp~~Sierra Pacific in Part I, Item 1 of this Form 10-Q for disclosure of the respective Registrant's derivative positions as of ~~September 30, 2021.~~March 31, 2022.

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 ~~September 30, 2021~~March 31, 2022 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

~~186~~159

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. On November 3, 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Echo Mountain, South Obenchain, Two Four Two and Santiam Canyon (also known as Beachie Creek) fires, as well as to add claims for noneconomic damages. The amended 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 amended complaint seeks the following damages for the plaintiffs and the putative class: (i) noneconomic damages, including mental suffering, emotional distress, inconvenience and interference with normal and usual activities, in excess of $1 billion; (ii) damages for real and personal property and other economic losses of not less than $600 million; (iii) double the amount of property and economic damages; (iv) treble damages for specific costs associated with loss of timber, trees and shrubbery; (v) double the damages for the costs of litigation and reforestation; (vi) prejudgment interest; and (vii) reasonable attorney fees, investigation costs and expert witness fees. The plaintiffs demand a trial by jury and have reserved their right to further amend the complaint to allege claims for punitive damages.

On August 20, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter et al. v. PacifiCorp, Case No. 21cv33595, Multnomah County, Oregon, in which two complaints, Case No. 21cv09339 and Case No. 21cv09520, previously filed in Circuit Court, Marion County, Oregon, were combined. The plaintiffs voluntarily dismissed the previously filed complaints in Marion County, Oregon. The refiled 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 related to real and personal property in an amount determined by the jury to be fair and reasonable, estimated not to exceed $75 million; (ii) other economic losses in an amount determined by the jury to be fair and reasonable, but not to exceed $75 million; (iii) noneconomic damages in the amount determined by the jury to be fair and reasonable, but not to exceed $500 million; (iv) double the damages for economic and property damages under specified Oregon statutes; (v) alternatively, treble the damages under specified Oregon statutes; (vi) attorneys' fees and other costs; and (vii) pre- and post-judgment interest. The plaintiffs demand a trial by jury and have reserved their right to amend the complaint with an intent to add a claim for punitive damages.

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 98 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 98 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q.

PacifiCorp

On March 17, 2022, a complaint against PacifiCorp was filed, captioned Roseburg Resources Co et al. v. PacifiCorp, Case No. 22CV09346, Circuit Court, Douglas County, Oregon. The complaint was filed by nine businesses and public pension plans that own and/or operate timberlands or possess property in Douglas County who allege damages, losses and injuries associated with their timberlands as a result of the French Creek Fire, the Archie Creek Fire, the Susan Creek Fire and the Smith Springs Road Fire in Douglas County in September 2020. The complaint alleges (i) PacifiCorp's conduct constituted not only common law negligence but also gross negligence and that such conduct contributed to or caused the ignition and spread of the aforementioned fires; (ii) PacifiCorp violated certain Oregon rules and regulations; and (iii) as an alternative to negligence, inverse condemnation. The complaint seeks the following damages: (i) economic and property damages in excess of $175 million under a determination of negligence or inverse condemnation; (ii) doubling of those economic damages to in excess of $350 million under a determination of gross negligence pursuant to Oregon statutes; (iii) all costs of the lawsuit; (iv) prejudgment and post-judgment interest as allowed by law; and (v) attorneys' fees and other costs.

160

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.~~2021, except as disclosed below.

Potential terrorist activities and the impact of military or other actions, including sanctions, export controls and similar measures, could adversely affect each Registrant's financial results.

The ongoing threat of terrorism and the impact of military or other actions by nations or politically, ethnically or religiously motivated organizations regionally or globally may create increased political, economic, social and financial market instability, which could subject each Registrant's operations to increased risks. Additionally, the U.S. government has issued warnings that energy assets, specifically pipeline, nuclear generation, transmission and other electric utility infrastructure, are potential targets for terrorist attacks. Further, the potential or actual outbreak of war or other hostilities, such as Russia's invasion of Ukraine in February 2022 and the resulting economic sanctions on Russia and the sale of Russian natural gas and petroleum, as well as the existing and potential further responses from Russia or other countries to such sanctions and military actions, could adversely affect global and regional economies and financial markets. For instance, the current ban on imports of Russian oil, liquefied natural gas and coal to the U.S. could contribute to increases in prices for such commodities in the U.S. and elsewhere which could adversely affect each Registrant's business. Further, each Registrant's business must be conducted in compliance with applicable economic and trade sanctions laws and regulations, including those administered and enforced by the U.S. Department of Treasury's Office of Foreign Assets Control, the U.S. Department of State, the U.S. Department of Commerce, the United Nations Security Council and other relevant governmental authorities in the U.S., Canada, the United Kingdom and European Union, which include sanctions that could potentially restrict or prohibit each Registrant's relationships with certain suppliers and customers. Political, economic, social or financial market instability or damage to or interference with the operating assets of the Registrants, customers or suppliers, or continued increases in the price of natural gas and other petroleum commodities may result in business interruptions, lost revenue, higher costs, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to electricity and natural gas, and increased security, repair or other costs, any of which may materially adversely affect each Registrant in ways that cannot be predicted at this time. Any of these risks could materially affect its consolidated financial results. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect each Registrant's ability to raise capital.

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

Not applicable.

Item 3.Defaults Upon Senior Securities

Not applicable.

~~187~~

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.

~~188~~161


Exhibit No.			Description

BERKSHIRE HATHAWAY ENERGY


4.1			~~Fiscal Agency Agreement,~~Seventeenth Supplemental Indenture, dated as of April ~~9, 2021,~~21, 2022, by and between ~~Northern Natural Gas~~Berkshire Hathaway Energy Company and The Bank of New York Mellon Trust Company, N.A., ~~Fiscal Agent,~~as trustee, relating to the ~~$550,000,000 in principal amount of the 3.40%~~4.600% Senior Notes due ~~2051~~2053 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company ~~Quarterly~~Current Report on Form ~~10-Q for the quarter ended March 31, 2021)~~8-K dated April 25, 2022).

~~10.1~~4.2			~~$3,500,000,000 Second Amended and Restated Credit Agreement,~~Trust Deed, dated as of ~~June 30, 2021,~~April 1, 2022, among ~~Berkshire Hathaway Energy~~Northern Powergrid (Northeast) plc and HSBC Corporate Trustee 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 (incorporated by reference to Exhibit 10.1(UK) Limited, relating to the ~~Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for~~£350,000,000 in principal amount of the ~~quarter ended June 30, 2021).~~3.250% Bonds due 2052.

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 (incorporated by reference to Exhibit 10.2 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).

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.

~~189~~


~~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 (incorporated by reference to Exhibit 10.3 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).

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.

162


Exhibit No.			Description

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~~SIERRA PACIFIC


~~10.4~~10.1			$~~400,000,000 Fourth Amended and Restated Credit Agreement,~~200,000,000 Demand Promissory Note , dated as of ~~June 30, 2021,~~April 14, 2022, among ~~Nevada~~Sierra Pacific Power Company, as ~~Borrower,~~ the ~~Banks, Financial Institutions~~Maker, and ~~Other Institutional Lenders,~~NV Energy Inc., as ~~Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and~~ the ~~LC Issuing Banks (incorporated by reference to Exhibit 10.4 to the Nevada Power Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).~~Holder.

~~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.

~~190~~


~~Exhibit No.~~			~~Description~~

~~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 ~~(incorporated by reference to Exhibit 10.5 to the Sierra Pacific Power~~ ~~Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2021)~~.

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 (incorporated by reference to Exhibit 4.6 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).

~~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 (incorporated by reference to Exhibit 4.7 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).

~~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 (incorporated by reference to Exhibit 4.8 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).

~~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 (incorporated by reference to Exhibit 4.9 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).

~~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 (incorporated by reference to Exhibit 4.10 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).

~~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 (incorporated by reference to Exhibit 4.11 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).

~~191~~


~~Exhibit No.~~			~~Description~~

ALL REGISTRANTS


101			The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended ~~September 30, 2021,~~March 31, 2022, 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.

~~192~~163

SIGNATURES

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


			BERKSHIRE HATHAWAY ENERGY COMPANY

Date: ~~November 5, 2021~~April 29, 2022			/s/ Calvin D. Haack
			Calvin D. Haack
			Senior Vice President and Chief Financial Officer
			(principal financial and accounting officer)

			PACIFICORP

Date: ~~November 5, 2021~~April 29, 2022			/s/ Nikki L. Kobliha
			Nikki L. Kobliha
			Vice President, Chief Financial Officer and Treasurer
			(principal financial and accounting officer)

			MIDAMERICAN FUNDING, LLC
			MIDAMERICAN ENERGY COMPANY

Date: ~~November 5, 2021~~April 29, 2022			/s/ Thomas B. Specketer
			Thomas B. Specketer
			Vice President and Controller
			of MidAmerican Funding, LLC and
			Vice President and Chief Financial Officer
			of MidAmerican Energy Company
			(principal financial and accounting officer)

			NEVADA POWER COMPANY

Date: ~~November 5, 2021~~April 29, 2022			/s/ Michael E. Cole
			Michael E. Cole
			Senior Vice President, Chief Financial Officer and Treasurer
			(principal financial and accounting officer)

			SIERRA PACIFIC POWER COMPANY

Date: ~~November 5, 2021~~April 29, 2022			/s/ Michael E. Cole
			Michael E. Cole
			Senior Vice President, Chief Financial Officer and Treasurer
			(principal financial and accounting officer)

			EASTERN ENERGY GAS HOLDINGS, LLC

Date: ~~November 5, 2021~~April 29, 2022			/s/ Scott C. Miller
			Scott C. Miller
			Vice President, Chief Financial Officer and Treasurer
			(principal financial and accounting officer)

~~193~~164


Item 1.	Legal Proceedings	~~187~~160
Item 1A.	Risk Factors	~~187~~161
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~187~~161
Item 3.	Defaults Upon Senior Securities	~~187~~161
Item 4.	Mine Safety Disclosures	~~188~~161
Item 5.	Other Information	~~188~~161
Item 6.	Exhibits	~~188~~161
Signatures		~~193~~164


	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


	Three-Month Period		Nine-Month Period
	Ended September 30, 2020		Ended September 30, 2020
Sales of natural gas and transportation and storage services	$	60	$	188
Purchases of natural gas and transportation and storage services	3		9
Services provided by related parties(1)	34		114
Services provided to related parties(2)	17		78


	Three-Month Period		Nine-Month Period
	Ended September 30, 2021		Ended September 30, 2021
Sales of natural gas and transportation and storage services	$	7	$	21
Purchases of natural gas and transportation and storage services	1		4
Services provided by related parties	16		31
Services provided to related parties	8		24