UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2023

or

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

For the transition period from ______ to _______

	Exact name of registrant as specified in its charter
	State or other jurisdiction of incorporation or organization
Commission	Address of principal executive offices	IRS Employer
File Number	Registrant's telephone number, including area code	Identification No.
001-14881	BERKSHIRE HATHAWAY ENERGY COMPANY	94-2213782
	(An Iowa Corporation)
	666 Grand Avenue
	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
333-266049	EASTERN GAS TRANSMISSION AND STORAGE, INC.	55-0629203
	(A Delaware Corporation)
	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
EASTERN GAS TRANSMISSION AND STORAGE, INC.	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
EASTERN GAS TRANSMISSION AND STORAGE, INC.	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	☒
EASTERN GAS TRANSMISSION AND STORAGE, INC.	☒

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	☐	☐	☒	☐	☐
EASTERN GAS TRANSMISSION AND STORAGE, INC.	☐	☐	☒	☐	☐

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

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

Yes  ☐  No  x

All shares of outstanding common stock of Berkshire Hathaway Energy Company are privately held by a limited group of investors. As of August 3, 2023, 75,627,913 shares of common stock, no par value, were outstanding.

All shares of outstanding common stock of PacifiCorp are indirectly owned by Berkshire Hathaway Energy Company. As of August 3, 2023, 357,060,915 shares of common stock, no par value, were outstanding.

All of the member's equity of MidAmerican Funding, LLC is held by its parent company, Berkshire Hathaway Energy Company, as of August 3, 2023.

All shares of outstanding common stock of MidAmerican Energy Company are owned by its parent company, MHC Inc., which is a direct, wholly owned subsidiary of MidAmerican Funding, LLC. As of August 3, 2023, 70,980,203 shares of common stock, no par value, were outstanding.

All shares of outstanding common stock of Nevada Power Company are owned by its parent company, NV Energy, Inc., which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of August 3, 2023, 1,000 shares of common stock, $1.00 stated value, were outstanding.

All shares of outstanding common stock of Sierra Pacific Power Company are owned by its parent company, NV Energy, Inc. As of August 3, 2023, 1,000 shares of common stock, $3.75 par value, were outstanding.

All of the member's equity of Eastern Energy Gas Holdings, LLC is held indirectly by its parent company, Berkshire Hathaway Energy Company, as of August 3, 2023.

All shares of outstanding common stock of Eastern Gas Transmission and Storage, Inc. are owned by its parent company, Eastern Energy Gas Holdings, LLC, which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of August 3, 2023, 60,101 shares of common stock, $10,000 par value, were outstanding.

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, Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. 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	194
Item 4.	Controls and Procedures	194

PART II

Item 1.	Legal Proceedings	195
Item 1A.	Risk Factors	199
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	199
Item 3.	Defaults Upon Senior Securities	199
Item 4.	Mine Safety Disclosures	199
Item 5.	Other Information	200
Item 6.	Exhibits	200
Signatures		204

i

Definition of Abbreviations and Industry Terms

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

Berkshire Hathaway Energy Company and Related Entities
BHE	Berkshire Hathaway Energy Company
Berkshire Hathaway	Berkshire Hathaway Inc.
Berkshire Hathaway Energy or the Company	Berkshire Hathaway Energy Company and its subsidiaries
PacifiCorp	PacifiCorp and its subsidiaries
MidAmerican Funding	MidAmerican Funding, LLC and its subsidiaries
MidAmerican Energy	MidAmerican Energy Company
NV Energy	NV Energy, Inc. and its subsidiaries
Nevada Power	Nevada Power Company and its subsidiaries
Sierra Pacific	Sierra Pacific Power Company and its subsidiaries
Nevada Utilities	Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
Eastern Energy Gas	Eastern Energy Gas Holdings, LLC and its subsidiaries
EGTS	Eastern Gas Transmission and Storage, Inc. 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, Eastern Energy Gas Holdings, LLC and its subsidiaries and Eastern Gas Transmission and Storage, Inc. 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 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

ii

Certain Industry Terms
2020 Wildfires	Wildfires in Oregon and Northern California that occurred September of 2020
AFUDC	Allowance for Funds Used During Construction
AUC	Alberta Utilities Commission
BART	Best Available Retrofit Technology
CCR	Coal Combustion Residuals
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
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
GTA	General Tariff Application
GWh	Gigawatt Hour
IRP	Integrated Resource Plan
IUB	Iowa Utilities Board
kV	Kilovolt
LNG	Liquefied Natural Gas
MATS	Mercury and Air Toxics Standards
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
RFP	Request for 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
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, costly litigation, wars (including, for example, Russia's invasion of Ukraine in February 2022), terrorism, pandemics, 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; 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 outcomes 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 of such wildfires, investigations and legal proceedings on the respective Registrant's financial condition and reputation;

•the outcomes of legal actions associated with the 2020 Wildfires, which could have a material adverse effect on PacifiCorp's financial condition and could limit PacifiCorp's ability to access capital on terms commensurate with historical transactions and could impact PacifiCorp's liquidity, cash flows and capital expenditure plans;

•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;

•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;

iv

•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 and credit spreads;

•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 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.

v

Item 1.Financial Statements

Berkshire Hathaway Energy Company and its subsidiaries
Report of Independent Registered Public Accounting Firm	4
Consolidated Balance Sheets	5
Consolidated Statements of Operations	7
Consolidated Statements of Comprehensive Income	8
Consolidated Statements of Changes in Equity	9
Consolidated Statements of Cash Flows	10
Notes to Consolidated Financial Statements	11
PacifiCorp and its subsidiaries
Report of Independent Registered Public Accounting Firm	57
Consolidated Balance Sheets	58
Consolidated Statements of Operations	60
Consolidated Statements of Changes in Shareholders' Equity	61
Consolidated Statements of Cash Flows	62
Notes to Consolidated Financial Statements	63
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm	84
Balance Sheets	85
Statements of Operations	87
Statements of Changes in Shareholder's Equity	88
Statements of Cash Flows	89
Notes to Financial Statements	90
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm	98
Consolidated Balance Sheets	99
Consolidated Statements of Operations	101
Consolidated Statements of Changes in Member's Equity	102
Consolidated Statements of Cash Flows	103
Notes to Consolidated Financial Statements	104
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm	118
Consolidated Balance Sheets	119
Consolidated Statements of Operations	120
Consolidated Statements of Changes in Shareholder's Equity	121
Consolidated Statements of Cash Flows	122
Notes to Consolidated Financial Statements	123
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm	138
Consolidated Balance Sheets	139
Consolidated Statements of Operations	140
Consolidated Statements of Changes in Shareholder's Equity	141
Consolidated Statements of Cash Flows	142
Notes to Consolidated Financial Statements	143
Eastern Energy Gas Holdings, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm	159
Consolidated Balance Sheets	160
Consolidated Statements of Operations	162
Consolidated Statements of Comprehensive Income	163
Consolidated Statements of Changes in Equity	164
Consolidated Statements of Cash Flows	165
Notes to Consolidated Financial Statements	166
Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Report of Independent Registered Public Accounting Firm	178
Consolidated Balance Sheets	179
Consolidated Statements of Operations	181
Consolidated Statements of Comprehensive Income	182
Consolidated Statements of Changes in Shareholder's Equity	183
Consolidated Statements of Cash Flows	184
Notes to Consolidated Financial Statements	185

1

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

Berkshire Hathaway Energy Company and its subsidiaries	31
PacifiCorp and its subsidiaries	74
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company	108
Nevada Power Company and its subsidiaries	130
Sierra Pacific Power Company and its subsidiaries	151
Eastern Energy Gas Holdings, LLC and its subsidiaries	173
Eastern Gas Transmission and Storage, Inc. and its subsidiaries	190

2

Berkshire Hathaway Energy Company and its subsidiaries

Consolidated Financial Section

3

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Berkshire Hathaway Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of June 30, 2023, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for the six-month periods ended June 30, 2023 and 2022, 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, 2022, 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 24, 2023, 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, 2022, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Des Moines, Iowa

August 4, 2023

4

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	2,229	$	1,591
Investments and restricted cash and cash equivalents	3,484		2,141
Trade receivables, net	2,488		2,876
Inventories	1,429		1,256
Mortgage loans held for sale	834		474
Regulatory assets	1,392		1,319
Other current assets	770		1,345
Total current assets	12,626		11,002
Property, plant and equipment, net	95,541		93,043
Goodwill	11,546		11,489
Regulatory assets	4,060		3,743
Investments and restricted cash and cash equivalents and investments	10,562		11,273
Other assets	3,416		3,290
Total assets	$	137,751	$	133,840

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

5

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	June 30,		December 31,
	2023		2022
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	2,502	$	2,679
Accrued interest	563		558
Accrued property, income and other taxes	1,287		746
Accrued employee expenses	418		333
Short-term debt	2,243		1,119
Current portion of long-term debt	3,199		3,201
Other current liabilities	1,648		1,677
Total current liabilities	11,860		10,313
BHE senior debt	13,099		13,096
BHE junior subordinated debentures	100		100
Subsidiary debt	35,224		35,238
Regulatory liabilities	6,423		7,070
Deferred income taxes	12,726		12,678
Other long-term liabilities	5,359		4,706
Total liabilities	84,791		83,201
Commitments and contingencies (Note 11)
Equity:
BHE shareholders' equity:
Preferred stock - 100 shares authorized, $0.01 par value, 1 shares issued and outstanding	850		850
Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding	—		—
Additional paid-in capital	6,298		6,298
Retained earnings	43,880		41,833
Accumulated other comprehensive loss, net	(1,845)		(2,149)
Total BHE shareholders' equity	49,183		46,832
Noncontrolling interests	3,777		3,807
Total equity	52,960		50,639
Total liabilities and equity	$	137,751	$	133,840

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

6

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Operating revenue:
Energy	$	4,933	$	4,940	$	10,404	$	9,763
Real estate	1,296		1,672		2,171		2,879
Total operating revenue	6,229		6,612		12,575		12,642
Operating expenses:
Energy:
Cost of sales	1,566		1,525		3,521		2,985
Operations and maintenance	1,200		1,081		2,742		2,024
Depreciation and amortization	970		1,045		2,020		2,052
Property and other taxes	197		199		409		404
Real estate	1,250		1,555		2,170		2,734
Total operating expenses	5,183		5,405		10,862		10,199
Operating income	1,046		1,207		1,713		2,443
Other income (expense):
Interest expense	(599)		(550)		(1,185)		(1,082)
Capitalized interest	33		18		57		35
Allowance for equity funds	61		42		110		80
Interest and dividend income	127		30		213		53
Gains on marketable securities, net	303		2,528		1,002		1,271
Other, net	78		(26)		118		(21)
Total other income (expense)	3		2,042		315		336
Income (loss) before income tax expense (benefit) and equity income (loss)	1,049		3,249		2,028		2,779
Income tax expense (benefit)	(255)		149		(417)		(358)
Equity income (loss)	(99)		(83)		(137)		(140)
Net income	1,205		3,017		2,308		2,997
Net income attributable to noncontrolling interests	130		120		244		229
Net income attributable to BHE shareholders	1,075		2,897		2,064		2,768
Preferred dividends	9		13		17		29
Earnings on common shares	$	1,066	$	2,884	$	2,047	$	2,739

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

7

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Net income	$	1,205	$	3,017	$	2,308	$	2,997
Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $(4), $9, $(7) and $12	(7)		25		(11)		40
Foreign currency translation adjustment	232		(481)		331		(591)
Unrealized gains (losses) on cash flow hedges, net of tax of $13, $8, $(7) and $36	39		26		(16)		103
Total other comprehensive income (loss), net of tax	264		(430)		304		(448)
Comprehensive income	1,469		2,587		2,612		2,549
Comprehensive income attributable to noncontrolling interests	130		120		244		229
Comprehensive income attributable to BHE shareholders	$	1,339	$	2,467	$	2,368	$	2,320

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

8

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)

	BHE Shareholders' Equity
							Long-term				Accumulated
					Additional		Income				Other
	Preferred		Common		Paid-in		Tax		Retained		Comprehensive		Noncontrolling		Total
	Stock		Stock		Capital		Receivable		Earnings		Loss, Net		Interests		Equity
Balance, March 31, 2022	$	1,650	$	—	$	6,374	$	(744)	$	40,608	$	(1,358)	$	3,894	$	50,424
Net income	—		—		—		—		2,897		—		120		3,017
Other comprehensive loss	—		—		—		—		—		(430)		—		(430)
Preferred stock redemptions	(800)		—		—		—		—		—		—		(800)
Preferred stock dividend	—		—		—		—		(13)		—		—		(13)
Common stock purchases	—		—		(77)		—		(793)		—		—		(870)
Distributions	—		—		—		—		—		—		(129)		(129)
Contributions	—		—		—		—		—		—		2		2
Other equity transactions	—		—		1		—		(11)		—		—		(10)
Balance, June 30, 2022	$	850	$	—	$	6,298	$	(744)	$	42,688	$	(1,788)	$	3,887	$	51,191
Balance, December 31, 2021	$	1,650	$	—	$	6,374	$	(744)	$	40,754	$	(1,340)	$	3,895	$	50,589
Net income	—		—		—		—		2,768		—		229		2,997
Other comprehensive loss	—		—		—		—		—		(448)		—		(448)
Preferred stock redemptions	(800)		—		—		—		—		—		—		(800)
Preferred stock dividend	—		—		—		—		(29)		—		—		(29)
Common stock purchases	—		—		(77)		—		(793)		—		—		(870)
Distributions	—		—		—		—		—		—		(245)		(245)
Contributions	—		—		—		—		—		—		2		2
Other equity transactions	—		—		1		—		(12)		—		6		(5)
Balance, June 30, 2022	$	850	$	—	$	6,298	$	(744)	$	42,688	$	(1,788)	$	3,887	$	51,191
Balance, March 31, 2023	$	850	$	—	$	6,298	$	—	$	42,814	$	(2,109)	$	3,798	$	51,651
Net income	—		—		—		—		1,075		—		130		1,205
Other comprehensive income	—		—		—		—		—		264		—		264
Preferred stock dividend	—		—		—		—		(9)		—		—		(9)
Distributions	—		—		—		—		—		—		(144)		(144)
Contributions	—		—		—		—		—		—		1		1
Other equity transactions	—		—		—		—		—		—		(8)		(8)
Balance, June 30, 2023	$	850	$	—	$	6,298	$	—	$	43,880	$	(1,845)	$	3,777	$	52,960
Balance, December 31, 2022	$	850	$	—	$	6,298	$	—	$	41,833	$	(2,149)	$	3,807	$	50,639
Net income	—		—		—		—		2,064		—		244		2,308
Other comprehensive income	—		—		—		—		—		304		—		304
Preferred stock dividend	—		—		—		—		(17)		—		—		(17)
Distributions	—		—		—		—		—		—		(269)		(269)
Contributions	—		—		—		—		—		—		3		3
Other equity transactions	—		—		—		—		—		—		(8)		(8)
Balance, June 30, 2023	$	850	$	—	$	6,298	$	—	$	43,880	$	(1,845)	$	3,777	$	52,960

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

9

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2023		2022
Cash flows from operating activities:
Net income	$	2,308	$	2,997
Adjustments to reconcile net income to net cash flows from operating activities:
Gains on marketable securities, net	(1,002)		(1,271)
Depreciation and amortization	2,045		2,081
Allowance for equity funds	(110)		(80)
Equity (income) loss, net of distributions	188		202
Net power cost deferrals	(446)		(288)
Amortization of net power cost deferrals	279		119
Other changes in regulatory assets and liabilities	(66)		(57)
Deferred income taxes and investment tax credits, net	(117)		385
Other, net	(93)		37
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(60)		(156)
Derivative collateral, net	(224)		189
Pension and other postretirement benefit plans	(10)		(21)
Accrued property, income and other taxes, net	530		489
Accounts payable and other liabilities	52		457
Wildfires insurance receivable	(133)		(161)
Wildfires liability	524		225
Net cash flows from operating activities	3,665		5,147
Cash flows from investing activities:
Capital expenditures	(4,025)		(3,382)
Purchases of marketable securities	(155)		(281)
Proceeds from sales of marketable securities	1,798		257
Purchases of U.S. Treasury Bills	(3,294)		—
Proceeds from sales of U.S. Treasury Bills	231		—
Proceeds from maturities of U.S. Treasury Bills	1,775		—
Equity method investments	(20)		(28)
Other, net	16		(18)
Net cash flows from investing activities	(3,674)		(3,452)
Cash flows from financing activities:
Preferred stock redemptions	—		(800)
Preferred dividends	(17)		(33)
Common stock purchases	—		(870)
Proceeds from BHE senior debt	—		987
Repayments of BHE senior debt	(400)		—
Proceeds from subsidiary debt	1,188		1,201
Repayments of subsidiary debt	(959)		(542)
Net proceeds from (repayments of) short-term debt	1,118		(54)
Distributions to noncontrolling interests	(269)		(246)
Other, net	(36)		(248)
Net cash flows from financing activities	625		(605)
Effect of exchange rate changes	7		(33)
Net change in cash and cash equivalents and restricted cash and cash equivalents	623		1,057
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	1,817		1,244
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	2,440	$	2,301

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

10

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    General

Berkshire Hathaway Energy Company ("BHE") is a holding company that owns a highly diversified portfolio of locally managed 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 eight business segments: PacifiCorp and its subsidiaries ("PacifiCorp"), MidAmerican Funding, LLC and its subsidiaries ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. and its subsidiaries ("NV Energy") (which primarily consists of Nevada Power Company and its subsidiaries ("Nevada Power") and Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific")), Northern Powergrid Holdings Company 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 and its subsidiaries), BHE Renewables, LLC and its subsidiaries ("BHE Renewables") and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through these locally managed and operated businesses, owns four utility companies in the U.S. serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies in the U.S., interests in a liquefied natural gas ("LNG") export, import and storage facility in the U.S., an electric transmission business in Canada, interests in electric transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects and one of the largest residential real estate brokerage firms and residential real estate brokerage franchise networks in the 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 June 30, 2023, and for the three- and six-month periods ended June 30, 2023 and 2022. The results of operations for the three- and six-month periods ended June 30, 2023, 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, 2022, 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 accounting policies or its assumptions regarding significant accounting estimates during the six-month period ended June 30, 2023, other than the updates associated with the Company's estimates of loss contingencies related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") and the 2022 McKinney fire as discussed in Note 11.

11

(2)    New Accounting Pronouncements

In March 2023, the FASB issued ASU No. 2023-02, amending FASB ASC Topic 323-740, "Investments—Equity Method and Joint Ventures—Income Taxes" which set forth the conditions needed to apply the proportional amortization method. The amendments in this update permit reporting entities to elect to account for their tax equity investments, regardless of the tax credit program from which the income tax credits are received, using the proportional amortization method if certain conditions are met. This guidance is effective for interim and annual reporting periods beginning after December 15, 2023, with early adoption permitted, and is required to be adopted either using a modified retrospective approach by means of a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption or a retrospective approach by means of a cumulative-effect adjustment to retained earnings as of the beginning of the earliest fiscal year presented. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

(3)    Business Acquisitions

On July 9, 2023, BHE and Eastern MLP Holding Company II, LLC ("the Buyer"), an indirect wholly owned subsidiary of BHE, entered into a Purchase and Sale Agreement (the "Purchase Agreement") with Dominion Energy, Inc. ("DEI") and DECP Holdings, Inc. (the "Seller"), an indirect wholly owned subsidiary of DEI, to purchase (the "Transaction") Seller's 50% limited partner interests in Cove Point LNG, LP ("Cove Point") for a cash purchase price of $3.3 billion, plus the pro rata portion of any quarterly distribution made by Cove Point for the fiscal quarter in which the Transaction closes. BHE expects to fund the purchase price with cash on hand, including cash realized from the liquidation of certain investments. Upon the completion of the Transaction, the Buyer will own an aggregate of 75% of the limited partner interests, and its affiliate, Cove Point GP Holding Company, LLC, will continue to own 100% of the general partner interest, of Cove Point.

The consummation of the Transaction contemplated by the Purchase Agreement is subject to customary closing conditions, including without limitation (i) the expiration or termination of any applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (ii) the filing of a notification with the U.S. Department of Energy and the expiration of any applicable period; and (iii) the accuracy of the representations and warranties and compliance by the parties in all material respects with their respective obligations under the Purchase Agreement. The Transaction is expected to close by year-end 2023, subject to satisfaction of the foregoing conditions, among other things.

The Purchase Agreement provides that if the Seller or DEI terminates the Purchase agreement due to a breach of the Purchase Agreement by the Buyer or Buyer's failure to consummate the Transaction within three business days after all of the conditions to close have been satisfied or waived, BHE will pay to the Seller a termination fee of $150 million.

12

(4)    Property, Plant and Equipment, Net

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

		As of
	Depreciable	June 30,		December 31,
	Life	2023		2022
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	94,351	$	92,759
Interstate natural gas pipeline assets	3-80 years	18,605		18,328
		112,956		111,087
Accumulated depreciation and amortization		(36,088)		(34,599)
Regulated assets, net		76,868		76,488
Nonregulated assets:
Independent power plants	2-50 years	8,476		8,545
Cove Point LNG facility	40 years	3,417		3,412
Other assets	2-30 years	2,787		2,693
		14,680		14,650
Accumulated depreciation and amortization		(3,617)		(3,452)
Nonregulated assets, net		11,063		11,198
		87,931		87,686
Construction work-in-progress		7,610		5,357
Property, plant and equipment, net		$	95,541	$	93,043

Construction work-in-progress includes $7.1 billion as of June 30, 2023 and $4.9 billion as of December 31, 2022, related to the construction of regulated assets.

13

(5)    Investments and Restricted Cash and Cash Equivalents and Investments

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

	As of
	June 30,		December 31,
	2023		2022
Investments:
BYD Company Limited common stock	$	3,129	$	3,763
U.S. Treasury Bills	3,281		1,931
Rabbi trusts	468		433
Other	330		335
Total investments	7,208		6,462
Equity method investments:
BHE Renewables tax equity investments	4,289		4,535
Electric Transmission Texas, LLC	657		623
Iroquois Gas Transmission System, L.P.	596		600
Other	359		304
Total equity method investments	5,901		6,062
Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds	726		664
Other restricted cash and cash equivalents	211		226
Total restricted cash and cash equivalents and investments	937		890
Total investments and restricted cash and cash equivalents and investments	$	14,046	$	13,414
Reflected as:
Other current assets	$	3,484	$	2,141
Noncurrent assets	10,562		11,273
Total investments and restricted cash and cash equivalents and investments	$	14,046	$	13,414

Investments

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Unrealized gains recognized on marketable securities held at the reporting date	$	268	$	2,527	$	725	$	1,270
Net gains recognized on marketable securities sold during the period	35		1		277		1
Gains on marketable securities, net	$	303	$	2,528	$	1,002	$	1,271

14

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, 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 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 presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):

	As of
	June 30,		December 31,
	2023		2022
Cash and cash equivalents	$	2,229	$	1,591
Investments and restricted cash and cash equivalents	158		173
Investments and restricted cash and cash equivalents and investments	53		53
Total cash and cash equivalents and restricted cash and cash equivalents	$	2,440	$	1,817

(6)    Recent Financing Transactions

Long-Term Debt

In May 2023, PacifiCorp issued $1.2 billion of its 5.50% First Mortgage Bonds due May 2054. PacifiCorp intends, within 24 months of the issuance date, to allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing investments or expenditures made in one or more eligible projects in alignment with BHE's Green Financing Framework.

Credit Facilities

In June 2023, BHE amended its existing $3.5 billion unsecured credit facility expiring in June 2025. The amendment extended the expiration date to June 2026.

In June 2023, PacifiCorp amended its existing $1.2 billion unsecured credit facility expiring in June 2025. The amendment increased the lender commitment to $2.0 billion and extended the expiration date to June 2026. Additionally, in June 2023, PacifiCorp terminated its existing $800 million 364-day unsecured credit facility expiring in January 2024.

In June 2023, MidAmerican Energy amended its existing $1.5 billion unsecured credit facility expiring in June 2025. The amendment extended the expiration date to June 2026.

In June 2023, Nevada Power and Sierra Pacific each amended its existing $400 million and $250 million secured credit facilities expiring in June 2025. The amendments increased the commitment of the lenders to $600 million and $400 million, respectively, and extended the expiration date to June 2026.

In April 2023, AltaLink Investments, L.P. extended, with lender consent, the expiration date for its existing C$200 million one year revolving credit facility to April 2024, by exercising a one-year extension option.

15

(7)    Income Taxes

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Income tax credits	(34)		(13)		(35)		(28)
State income tax, net of federal income tax impacts	—		(1)		(2)		—
Income tax effect of foreign income	(3)		—		2		(1)
Effects of ratemaking	(3)		(1)		(3)		(2)
Equity income	(2)		(1)		(1)		(1)
Noncontrolling interest	(3)		(1)		(3)		(2)
Other, net	—		1		—		—
Effective income tax rate	(24)	%	5	%	(21)	%	(13)	%

Income tax credits relate primarily to production tax credits ("PTCs") from wind- and solar-powered generating facilities owned by MidAmerican Energy, PacifiCorp and BHE Renewables. Federal renewable electricity PTCs are earned as energy from qualifying wind- and solar-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- and solar-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the six-month periods ended June 30, 2023 and 2022 totaled $700 million and $734 million, respectively.

Income tax effect on foreign income includes, among other items, a deferred income tax charge of $82 million recognized in March 2023 related to the July 2022 enactment of a new Energy Profits Levy 25% income tax in the United Kingdom effective May 26, 2022, through December 31, 2025, as well as an increase in the tax rate from 25% to 35% effective January 1, 2023, through March 31, 2028, enacted in January 2023.

The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated U.S. federal and Iowa state income tax returns and the majority of the Company's U.S. federal income tax is remitted to or received from Berkshire Hathaway. The Company received net cash payments for federal income taxes from Berkshire Hathaway for the six-month periods ended June 30, 2023 and 2022 totaling $864 million and $1,249 million, respectively.

In July 2022, the Company amended its tax allocation agreement with Berkshire Hathaway, which changed how state tax attributes will be settled with respect to state income tax returns that Berkshire Hathaway includes the Company. As a result, the Company no longer expects to receive the cash benefits from the state of Iowa net operating loss carryforward previously recorded as a long-term income tax receivable from Berkshire Hathaway as a component of BHE's shareholders' equity, and recognized a noncash distribution of $744 million to retained earnings.

16

(8)    Employee Benefit Plans

Domestic Operations

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Pension:
Service cost	$	5	$	6	$	9	$	13
Interest cost	27		19		55		38
Expected return on plan assets	(31)		(27)		(62)		(54)
Settlement	—		—		(5)		2
Net amortization	3		5		7		9
Net periodic benefit cost	$	4	$	3	$	4	$	8
Other postretirement:
Service cost	$	2	$	4	$	3	$	6
Interest cost	7		5		14		10
Expected return on plan assets	(10)		(7)		(18)		(14)
Net amortization	—		(1)		(1)		(1)
Net periodic benefit (credit) cost	$	(1)	$	1	$	(2)	$	1

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in other, net on the Consolidated Statements of Operations. Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $13 million and $7 million, respectively, during 2023. As of June 30, 2023, $7 million and $3 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

Foreign Operations

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Service cost	$	1	$	3	$	3	$	7
Interest cost	14		9		28		19
Expected return on plan assets	(21)		(23)		(40)		(48)
Net amortization	7		6		13		12
Net periodic benefit cost (credit)	$	1	$	(5)	$	4	$	(10)

Amounts other than the service cost for the United Kingdom pension plan are recorded in other, net on the Consolidated Statements of Operations. Employer contributions to the United Kingdom pension plan are expected to be £11 million during 2023. As of June 30, 2023, £6 million, or $7 million, of contributions had been made to the United Kingdom pension plan.

17

(9)    Asset Retirement Obligations

MidAmerican Energy estimates its asset retirement obligation ("ARO") liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of expected work. During the six-month period ended June 30, 2023, MidAmerican Energy recorded an increase of $88 million for decommissioning its wind-generating facilities, which is a non-cash investing activity and is due to an updated decommissioning estimate reflecting changes in the projected removal costs per turbine.

(10)    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.

18

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

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of June 30, 2023:
Assets:
Commodity derivatives	$	3	$	195	$	13	$	(58)	$	153
Interest rate derivatives	53		57		12		—		122
Mortgage loans held for sale	—		834		—		—		834
Money market mutual funds	1,539		—		—		—		1,539
Debt securities:
U.S. government obligations	3,902		—		—		—		3,902
International government obligations	—		1		—		—		1
Corporate obligations	—		72		—		—		72
Municipal obligations	—		3		—		—		3
Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:
U.S. companies	405		—		—		—		405
International companies	3,138		—		—		—		3,138
Investment funds	287		—		—		—		287
	$	9,327	$	1,163	$	25	$	(58)	$	10,457
Liabilities:
Commodity derivatives	$	(6)	$	(98)	$	(187)	$	62	$	(229)
Foreign currency exchange rate derivatives	—		(11)		—		—		(11)
Interest rate derivatives	—		(1)		(1)		—		(2)
	$	(6)	$	(110)	$	(188)	$	62	$	(242)

19

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2022:
Assets:
Commodity derivatives	$	6	$	614	$	51	$	(194)	$	477
Interest rate derivatives	50		54		8		—		112
Mortgage loans held for sale	—		474		—		—		474
Money market mutual funds	1,178		—		—		—		1,178
Debt securities:
U.S. government obligations	2,146		—		—		—		2,146
International government obligations	—		1		—		—		1
Corporate obligations	—		70		—		—		70
Municipal obligations	—		3		—		—		3
Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:
U.S. companies	360		—		—		—		360
International companies	3,771		—		—		—		3,771
Investment funds	231		—		—		—		231
	$	7,742	$	1,217	$	59	$	(194)	$	8,824
Liabilities:
Commodity derivatives	$	(8)	$	(206)	$	(110)	$	106	$	(218)
Foreign currency exchange rate derivatives	—		(21)		—		—		(21)
Interest rate derivatives	—		(2)		(2)		1		(3)
	$	(8)	$	(229)	$	(112)	$	107	$	(242)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $4 million as of June 30, 2023 and payable of $87 million as of December 31, 2022.

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.

20

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). Transfers out of Level 3 occur primarily due to increased price observability.

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
			Interest				Interest
	Commodity		Rate		Commodity		Rate
	Derivatives		Derivatives		Derivatives		Derivatives
2023:
Beginning balance	$	(150)	$	15	$	(59)	$	6
Changes included in earnings(1)	1		(4)		10		5
Changes in fair value recognized in OCI	—		—		(3)		—
Changes in fair value recognized in net regulatory assets	(85)		—		(183)		—
Settlements	60		—		61		—
Ending balance	$	(174)	$	11	$	(174)	$	11

2022:
Beginning balance	$	(239)	$	13	$	(151)	$	19
Changes included in earnings(1)	(26)		8		(82)		2
Changes in fair value recognized in OCI	5		—		10		—
Changes in fair value recognized in net regulatory assets	1		—		(59)		—
Purchases	1		—		1		—
Settlements	11		—		34		—
Transfers out of Level 3 into Level 2	69		—		69		—
Ending balance	$	(178)	$	21	$	(178)	$	21

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

	As of June 30, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	51,622	$	46,124	$	51,635	$	46,906

21

(11)    Commitments and Contingencies

Commitments

The Company has the following firm commitments that are not reflected on the Consolidated Balance Sheets.

Construction Commitments

During the six-month period ended June 30, 2023, PacifiCorp entered into build transfer agreements totaling $1.2 billion through 2025 for the construction of certain wind-powered generating facilities in Wyoming.

During the six-month period ended June 30, 2023, MidAmerican Energy entered into firm construction commitments totaling $183 million for the remainder of 2023 through 2024 related to the construction of wind-powered generating facilities in Iowa.

Fuel Contracts

During the six-month period ended June 30, 2023, PacifiCorp entered into certain coal supply agreements totaling $425 million through 2025.

Environmental Laws and Regulations

The Company is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal, hazardous 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.

Lower Klamath Hydroelectric Project

In November 2022, the Federal Energy Regulatory Commission ("FERC") issued a license surrender order for the Lower Klamath Project, which was accepted by the Klamath River Renewal Corporation ("KRRC") and the states of Oregon and California ("States") in December 2022, along with the transfer of the Lower Klamath Project dams. Although PacifiCorp no longer owns the Lower Klamath Project, PacifiCorp will continue to operate the facilities under an operation and maintenance agreement with the KRRC until each facility is ready for removal. Removal of the Copco No. 2 facility began in June 2023, and removal of the remaining three dams (J.C. Boyle, Copco No. 1 and Iron Gate) is anticipated to begin in 2024. The KRRC has $450 million in funding available for dam removal and restoration; $200 million collected from PacifiCorp's Oregon and California customers and $250 million in California bond funds. PacifiCorp and the States have also agreed to equally share cost overruns that may occur above the initial $450 million in funding. Specifically, PacifiCorp and the States have agreed to equally fund an initial $45 million contingency fund and equally share any additional costs above that amount to ensure dam removal and restoration is complete.

Legal Matters

The Company is party to a variety of legal actions, including litigation, arising out of the normal course of business, some of which assert claims for damages in substantial amounts and are described below. For certain legal actions, parties at times may seek to impose fines, penalties and other costs.

Wildfire Liability Overview

A provision for a loss contingency is recorded when it is probable a liability has been incurred and the amount of loss can be reasonably estimated. The Company evaluates the related range of reasonably estimated losses and records a loss based on its best estimate within that range or the lower end of the range if there is no better estimate.

22

In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages from wildfires 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 be found liable for all damages.

2020 Wildfires

In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, which resulted in real and personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon, burning over 500,000 acres in aggregate. Third-party reports for these wildfires indicate over 2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities.

Investigations into the cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the U.S. Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.

As of the date of this filing, numerous lawsuits on behalf of plaintiffs related to the 2020 Wildfires have been filed in Oregon and California, including a class action complaint in Oregon for which the jury issued a verdict for the 17 named plaintiffs in June 2023 as described below. The plaintiffs seek damages for economic losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees. Several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. Additionally, certain governmental agencies have informed PacifiCorp that they are contemplating filing actions in connection with certain of the Oregon 2020 Wildfires. Amounts sought in the lawsuits, complaints and demands filed in Oregon total over $7 billion, excluding any doubling or trebling of damages included in the complaints. Generally, the complaints filed in California do not specify damages sought and are not included in this amount. Final determinations of liability will only be made following the completion of comprehensive investigations, litigation or similar processes, the outcome of which, if adverse, could, in the aggregate, have a material adverse effect on PacifiCorp's financial condition.

On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al, in Multnomah County Circuit Court, Oregon (the "James case"). 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. In November 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Santiam Canyon, Echo Mountain Complex, South Obenchain and Two Four Two wildfires. In May 2022, the Multnomah County Circuit Court granted issue class certification and consolidated the James case with several other cases. While PacifiCorp requested an immediate appeal of the issue class certification, the Oregon Court of Appeals denied the request. In April 2023, the jury trial for the James case with respect to 17 named plaintiffs began in Multnomah County Circuit Court. In June 2023, the jury issued its verdict finding PacifiCorp liable to the 17 individual plaintiffs and to the class with respect to the four wildfires. The jury awarded the 17 named plaintiffs $90 million of damages, including $4 million of economic and property damages, $68 million of noneconomic damages and $18 million of punitive damages based on a 0.25 multiplier of the economic and noneconomic damages. No judgment has been entered by the Multnomah County Circuit Court and no determination has been made as to the timing, process and procedures that will be used to adjudicate individual class member damages. PacifiCorp intends to vigorously appeal the jury's findings and damage awards, including whether the case can proceed as a class action. The appeals process and further actions could take several years.

Based on the facts and circumstances available to PacifiCorp as of the date of this filing, which includes the status of the verdict in the James case with respect to the 17 named plaintiffs, other litigation and recent settlements, PacifiCorp has accrued cumulative estimated probable losses associated with the 2020 Wildfires of $1,018 million through June 30, 2023. PacifiCorp's cumulative accrual includes estimates of probable losses for fire suppression costs, real and personal property damages, natural resource damages for certain areas and noneconomic damages such as personal injury damages and loss of life damages that are considered probable of being incurred and that it is reasonably able to estimate at this time. For certain aspects of the 2020 Wildfires for which loss is considered probable, information necessary to reasonably estimate the potential losses, such as those related to certain areas of natural resource damages, is not currently available.

23

It is reasonably possible PacifiCorp will incur material additional losses beyond the amounts accrued that could have a material adverse effect on PacifiCorp's financial condition; however, PacifiCorp is currently unable to reasonably estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved, including claimants in the class to the James case, the variation in those types of properties and lack of available details and the ultimate outcome of legal actions.

The following table presents changes in PacifiCorp's liability for estimated losses associated with the 2020 Wildfires (in millions):

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Beginning balance	$	824	$	252	$	424	$	252
Accrued losses	141		225		541		225
Payments	(17)		—		(17)		—
Ending balance	$	948	$	477	$	948	$	477

PacifiCorp's receivable for expected insurance recoveries associated with the probable losses was $379 million and $246 million, respectively, as of June 30, 2023 and December 31, 2022. During the three- and six-month periods ended June 30, 2023, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $49 million and $408 million, respectively. During the three- and six-month periods ended June 30, 2022, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $64 million and $64 million, respectively. The net losses are included in operations and maintenance on the Consolidated Statements of Operations. No additional insurance recoveries beyond those accrued to date are expected to be available for the 2020 Wildfires.

2022 McKinney Fire

According to the California Department of Forestry and Fire Protection, on July 29, 2022, a wildfire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California (the "2022 McKinney Fire") located in PacifiCorp's service territory. Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged, 185 structures destroyed, 12 injuries and four fatalities and consumed 60,000 acres. The cause of the 2022 McKinney Fire is undetermined and remains under investigation by the U.S. Forest Service.

Due to the preliminary nature of the investigation, PacifiCorp does not believe a loss is probable and therefore has not accrued any loss as of the date of this filing. While the loss is not probable, PacifiCorp estimates the potential loss, excluding losses for natural resource damages, to be $31 million, net of expected insurance recoveries. The loss estimate includes PacifiCorp's estimate of losses for fire suppression costs; real and personal property damages; and noneconomic damages such as personal injury damages and loss of life damages. PacifiCorp is unable to estimate the total potential loss, including losses for natural resource damages, because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PacifiCorp. PacifiCorp has insurance available and estimates the potential insurance recoveries to be $103 million, to cover potential losses.

As of the date of this filing, multiple lawsuits have been filed in California on behalf of plaintiffs related to the 2022 McKinney Fire. The plaintiffs seek damages for economic losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees, but the amount of damages sought is not specified. Final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.

Guarantees

The Company 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 the Company's consolidated financial results.

24

(12)    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 14 (in millions):

	For the Three-Month Period Ended June 30, 2023
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	1,232	$	569	$	1,043	$	—	$	—	$	—	$	—	$	—	$	2,844
Retail gas	—		90		43		—		—		—		—		—		133
Wholesale	26		52		9		—		—		—		—		2		89
Transmission and    distribution	34		13		19		244		—		166		—		—		476
Interstate pipeline	—		—		—		—		542		—		—		(27)		515
Other	24		—		—		—		(1)		—		—		—		23
Total Regulated	1,316		724		1,114		244		541		166		—		(25)		4,080
Nonregulated	—		1		—		33		270		30		376		1		711
Total Customer Revenue	1,316		725		1,114		277		811		196		376		(24)		4,791
Other revenue	11		34		5		29		7		(4)		61		(1)		142
Total	$	1,327	$	759	$	1,119	$	306	$	818	$	192	$	437	$	(25)	$	4,933

	For the Six-Month Period Ended June 30, 2023
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	2,581	$	1,060	$	1,891	$	—	$	—	$	—	$	—	$	—	$	5,532
Retail gas	—		386		139		—		—		—		—		—		525
Wholesale	87		152		40		—		—		—		—		1		280
Transmission and    distribution	72		27		37		525		—		331		—		—		992
Interstate pipeline	—		—		—		—		1,420		—		—		(83)		1,337
Other	56		—		—		—		1		—		—		—		57
Total Regulated	2,796		1,625		2,107		525		1,421		331		—		(82)		8,723
Nonregulated	—		4		1		78		536		70		681		1		1,371
Total Customer Revenue	2,796		1,629		2,108		603		1,957		401		681		(81)		10,094
Other revenue	15		50		10		57		34		(4)		149		(1)		310
Total	$	2,811	$	1,679	$	2,118	$	660	$	1,991	$	397	$	830	$	(82)	$	10,404

25

	For the Three-Month Period Ended June 30, 2022
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	1,167	$	594	$	831	$	—	$	—	$	—	$	—	$	(1)	$	2,591
Retail gas	—		136		28		—		—		—		—		—		164
Wholesale	55		119		15		—		—		—		—		(2)		187
Transmission and    distribution	45		13		18		274		—		172		—		—		522
Interstate pipeline	—		—		—		—		524		—		—		(27)		497
Other	28		—		—		—		—		—		—		—		28
Total Regulated	1,295		862		892		274		524		172		—		(30)		3,989
Nonregulated	—		—		1		42		285		15		414		(1)		756
Total Customer Revenue	1,295		862		893		316		809		187		414		(31)		4,745
Other revenue	19		35		6		29		47		(4)		32		31		195
Total	$	1,314	$	897	$	899	$	345	$	856	$	183	$	446	$	—	$	4,940

	For the Six-Month Period Ended June 30, 2022
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	2,352	$	1,066	$	1,430	$	—	$	—	$	—	$	—	$	(1)	$	4,847
Retail gas	—		473		79		—		—		—		—		—		552
Wholesale	110		280		35		—		—		—		—		(2)		423
Transmission and    distribution	77		28		35		543		—		348		—		—		1,031
Interstate pipeline	—		—		—		—		1,269		—		—		(68)		1,201
Other	48		—		1		—		1		—		—		—		50
Total Regulated	2,587		1,847		1,580		543		1,270		348		—		(71)		8,104
Nonregulated	—		2		1		57		563		22		716		(1)		1,360
Total Customer Revenue	2,587		1,849		1,581		600		1,833		370		716		(72)		9,464
Other revenue	24		53		11		60		58		(4)		98		(1)		299
Total	$	2,611	$	1,902	$	1,592	$	660	$	1,891	$	366	$	814	$	(73)	$	9,763

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

Real Estate Services

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

	HomeServices
	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Customer Revenue:
Brokerage	$	1,202	$	1,544	$	2,001	$	2,636
Franchise	15		17		27		37
Total Customer Revenue	1,217		1,561		2,028		2,673
Mortgage and other revenue	79		111		143		206
Total	$	1,296	$	1,672	$	2,171	$	2,879

26

Remaining Performance Obligations

The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of June 30, 2023, by reportable segment (in millions):

	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total
BHE Pipeline Group	$	3,007	$	20,764	$	23,771
BHE Transmission	328		—		328
Total	$	3,335	$	20,764	$	24,099

(13)    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		Foreign		Unrealized				AOCI
	Amounts on		Currency		Gains				Attributable
	Retirement		Translation		on Cash		Noncontrolling		To BHE
	Benefits		Adjustment		Flow Hedges		Interests		Shareholders, Net
Balance, December 31, 2021	$	(318)	$	(1,086)	$	59	$	5	$	(1,340)
Other comprehensive income (loss)	40		(591)		103		—		(448)
Balance, June 30, 2022	$	(278)	$	(1,677)	$	162	$	5	$	(1,788)
Balance, December 31, 2022	$	(390)	$	(1,896)	$	135	$	2	$	(2,149)
Other comprehensive (loss) income	(11)		331		(16)		—		304
Balance, June 30, 2023	$	(401)	$	(1,565)	$	119	$	2	$	(1,845)

27

(14)    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. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Effective January 1, 2023, the Company's unregulated retail energy services business was transferred to a subsidiary of BHE Renewables. Prior period amounts, which were previously reported in BHE and Other, have been changed to reflect this activity in BHE Renewables. Information related to the Company's reportable segments is shown below (in millions):

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Operating revenue:
PacifiCorp	$	1,327	$	1,314	$	2,811	$	2,611
MidAmerican Funding	759		897		1,679		1,902
NV Energy	1,119		899		2,118		1,592
Northern Powergrid	307		345		661		660
BHE Pipeline Group	818		856		1,991		1,891
BHE Transmission	192		183		397		366
BHE Renewables	437		478		830		814
HomeServices	1,296		1,672		2,171		2,879
BHE and Other(1)	(26)		(32)		(83)		(73)
Total operating revenue	$	6,229	$	6,612	$	12,575	$	12,642

Depreciation and amortization:
PacifiCorp	$	279	$	279	$	558	$	559
MidAmerican Funding	226		277		460		527
NV Energy	153		139		305		279
Northern Powergrid	85		100		170		180
BHE Pipeline Group	95		125		267		256
BHE Transmission	65		60		126		118
BHE Renewables	67		65		133		131
HomeServices	12		14		25		29
BHE and Other(1)	—		—		1		2
Total depreciation and amortization	$	982	$	1,059	$	2,045	$	2,081

28

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Operating income:
PacifiCorp	$	131	$	158	$	(36)	$	374
MidAmerican Funding	118		90		206		190
NV Energy	117		140		174		202
Northern Powergrid	121		110		267		269
BHE Pipeline Group	368		352		952		890
BHE Transmission	76		84		164		167
BHE Renewables	89		155		20		209
HomeServices	46		117		1		145
BHE and Other(1)	(20)		1		(35)		(3)
Total operating income	1,046		1,207		1,713		2,443
Interest expense	(599)		(550)		(1,185)		(1,082)
Capitalized interest	33		18		57		35
Allowance for equity funds	61		42		110		80
Interest and dividend income	127		30		213		53
Gains on marketable securities, net	303		2,528		1,002		1,271
Other, net	78		(26)		118		(21)
Total income (loss) before income tax expense (benefit) and equity income (loss)	$	1,049	$	3,249	$	2,028	$	2,779

Interest expense:
PacifiCorp	$	134	$	107	$	258	$	213
MidAmerican Funding	85		83		169		165
NV Energy	64		52		127		103
Northern Powergrid	30		34		60		66
BHE Pipeline Group	39		36		78		73
BHE Transmission	38		38		75		76
BHE Renewables	43		45		88		87
HomeServices	4		2		8		3
BHE and Other(1)	162		153		322		296
Total interest expense	$	599	$	550	$	1,185	$	1,082

Earnings on common shares:
PacifiCorp	$	107	$	83	$	(13)	$	213
MidAmerican Funding	233		204		482		445
NV Energy	90		93		124		122
Northern Powergrid	96		71		107		182
BHE Pipeline Group	187		199		556		521
BHE Transmission	58		62		122		124
BHE Renewables	206		264		285		409
HomeServices	34		84		—		105
BHE and Other(1)	55		1,824		384		618
Total earnings on common shares	$	1,066	$	2,884	$	2,047	$	2,739

29

	As of
	June 30,		December 31,
	2023		2022
Assets:
PacifiCorp	$	31,700	$	30,559
MidAmerican Funding	26,241		26,077
NV Energy	17,495		16,676
Northern Powergrid	9,531		9,005
BHE Pipeline Group	20,937		21,005
BHE Transmission	9,599		9,334
BHE Renewables	11,295		12,632
HomeServices	3,795		3,436
BHE and Other(1)	7,158		5,116
Total assets	$	137,751	$	133,840

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Operating revenue by country:
U.S.	$	5,749	$	6,087	$	11,564	$	11,621
United Kingdom	295		345		628		660
Canada	173		180		350		361
Australia	12		—		33		—
Total operating revenue by country	$	6,229	$	6,612	$	12,575	$	12,642

Income (loss) before income tax expense (benefit) and equity income (loss) by country:
U.S.	$	914	$	3,117	$	1,733	$	2,463
United Kingdom	93		87		206		226
Canada	44		46		87		92
Australia	(3)		1		2		1
Other	1		(2)		—		(3)
Total income (loss) before income tax expense (benefit) and equity income (loss) by country	$	1,049	$	3,249	$	2,028	$	2,779

The following table shows the change in the carrying amount of goodwill by reportable segment for the six-month period ended June 30, 2023 (in millions):

									BHE Pipeline Group
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid				BHE Transmission		BHE Renewables		HomeServices
																	Total
December 31, 2022	$	1,129	$	2,102	$	2,369	$	917	$	1,814	$	1,461	$	95	$	1,602	$	11,489
Acquisitions	—		—		—		—		—		—		—		1		1
Foreign currency translation	—		—		—		32		—		31		—		—		63
Other	—		—		—		—		—		—		—		(7)		(7)
June 30, 2023	$	1,129	$	2,102	$	2,369	$	949	$	1,814	$	1,492	$	95	$	1,596	$	11,546

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

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

BHE is a holding company that owns a highly diversified portfolio of locally managed and operated businesses principally engaged in the energy industry and is a consolidated subsidiary of Berkshire Hathaway that, as of August 3, 2023, owned 92% of BHE's voting common stock. The balance of BHE's voting common stock is privately held by a limited group of investors.

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 U.S. serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies in the U.S., interests in an LNG export, import and storage facility in the U.S., an electric transmission business in Canada, interests in electric transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects and one of the largest residential real estate brokerage firms and residential real estate brokerage franchise networks in the 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 corporate entities, corporate functions and intersegment eliminations. Effective January 1, 2023, the Company's unregulated retail energy services business was transferred to a subsidiary of BHE Renewables. Prior period amounts, which were previously reported in BHE and Other, have been changed to reflect this activity in BHE Renewables.

31

Results of Operations for the Second Quarter and First Six Months of 2023 and 2022

Overview

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

	Second Quarter								First Six Months
	2023		2022		Change				2023		2022		Change
Operating revenue:
PacifiCorp	$	1,327	$	1,314	$	13	1	%	$	2,811	$	2,611	$	200	8	%
MidAmerican Funding	759		897		(138)		(15)		1,679		1,902		(223)		(12)
NV Energy	1,119		899		220		24		2,118		1,592		526		33
Northern Powergrid	307		345		(38)		(11)		661		660		1		—
BHE Pipeline Group	818		856		(38)		(4)		1,991		1,891		100		5
BHE Transmission	192		183		9		5		397		366		31		8
BHE Renewables	437		478		(41)		(9)		830		814		16		2
HomeServices	1,296		1,672		(376)		(22)		2,171		2,879		(708)		(25)
BHE and Other	(26)		(32)		6		19		(83)		(73)		(10)		(14)
Total operating revenue	$	6,229	$	6,612	$	(383)	(6)	%	$	12,575	$	12,642	$	(67)	(1)	%
Earnings on common shares:
PacifiCorp	$	107	$	83	$	24	29	%	$	(13)	$	213	$	(226)	*
MidAmerican Funding	233		204		29		14		482		445		37		8
NV Energy	90		93		(3)		(3)		124		122		2		2
Northern Powergrid	96		71		25		35		107		182		(75)		(41)
BHE Pipeline Group	187		199		(12)		(6)		556		521		35		7
BHE Transmission	58		62		(4)		(6)		122		124		(2)		(2)
BHE Renewables(1)	206		264		(58)		(22)		285		409		(124)		(30)
HomeServices	34		84		(50)		(60)		—		105		(105)		(100)
BHE and Other	55		1,824		(1,769)		(97)		384		618		(234)		(38)
Total earnings on common shares	$	1,066	$	2,884	$	(1,818)	(63)	%	$	2,047	$	2,739	$	(692)	(25)	%

(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 $1,818 million for the second quarter of 2023 compared to 2022. Included in these results was a pre-tax gain in the second quarter of 2023 of $293 million ($231 million after-tax) compared to a pre-tax gain in the second quarter of 2022 of $2,557 million ($2,020 million after-tax) related to the Company's investment in BYD Company Limited ("BYD"). Excluding the impact of this item, adjusted earnings on common shares for the second quarter of 2023 was $835 million, a decrease of $29 million, or 3%, compared to adjusted earnings on common shares for the second quarter of 2022 of $864 million.

Earnings on common shares decreased $692 million for the first six months of 2023 compared to 2022. Included in these results was a pre-tax gain in the first six months of 2023 of $984 million ($777 million after-tax) compared to a pre-tax gain in the first six months of 2022 of $1,310 million ($1,035 million after-tax) related to the Company's investment in BYD. Excluding the impact of this item, adjusted earnings on common shares for the first six months of 2023 was $1,270 million, a decrease of $434 million, or 25%, compared to adjusted earnings on common shares for the first six months of 2022 of $1,704 million.

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The decreases in earnings on common shares for the second quarter and for the first six months of 2023 compared to 2022 were primarily due to the following:

•The Utilities' earnings increased $50 million for the second quarter and decreased $187 million for the first six months of 2023 compared to 2022. The changes reflected higher operations and maintenance expense, largely due to an increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfire for the first six months, and increased interest expense. These items were offset by favorable interest and dividend income, higher allowances for equity and borrowed funds used during construction, favorable changes in the cash surrender value of corporate-owned life insurance policies, lower depreciation and amortization expense and higher electric utility margin for the first six months. Electric retail customer volumes increased 0.1% for the first six months of 2023 compared to 2022;

•Northern Powergrid's earnings increased $25 million for the second quarter and decreased $75 million for the first six months of 2023 compared to 2022. The changes were primarily due to a deferred income tax charge of $82 million recognized in March 2023 related to the enactment of a new Energy Profits Levy income tax offset by favorable income tax expense from adjustments to the Energy Profits Levy income tax recognized in the second quarter of 2023. Units distributed declined 4.6% for the first six months of 2023 compared to 2022 due to the unfavorable impact of weather and lower customer usage;

•BHE Pipeline Group's earnings decreased $12 million for the second quarter and increased $35 million for the first six months of 2023 compared to 2022, largely due to the impact of a general rate case, with interim rates effective January 2023, subject to refund, at Northern Natural Gas, offset by higher operations and maintenance expense and favorable state unitary income tax adjustments recognized at BHE GT&S in the second quarter of 2022;

•BHE Renewables' earnings decreased $58 million for the second quarter and $124 million for the first six months of 2023 compared to 2022, primarily due to lower earnings from the retail energy services business, largely due to unfavorable changes in unrealized positions on derivative contracts caused by lower forward electricity price curves, lower natural gas and geothermal earnings due to maintenance outages, lower solar earnings from lower generation due to weather events in California and lower earnings from wind tax equity investments due to lower PTCs, partially offset by higher earnings from owned wind projects primarily due to favorable derivative contract valuations and gains on the extinguishment of debt;

•HomeServices' earnings decreased $50 million for the second quarter and $105 million for the first six months of 2023 compared to 2022, primarily due to lower earnings from brokerage, settlement and mortgage services, reflecting the impact of rising interest rates and a corresponding decline in home sales; and

•BHE and Other's earnings decreased $1,769 million for the second quarter and $234 million for the first six months of 2023 compared to 2022, mainly due to $1,789 million and $258 million, respectively, of unfavorable comparative changes in the Company's investment in BYD.

Reportable Segment Results

PacifiCorp

Operating revenue increased $13 million for the second quarter of 2023 compared to 2022, primarily due to higher retail revenue of $59 million, partially offset by lower wholesale and other revenue of $45 million, primarily from lower wholesale volumes and a decrease in wheeling revenue. Retail revenue increased primarily due to price impacts of $82 million from higher average retail rates largely due to tariff changes and product mix, partially offset by $23 million from lower volumes. Retail customer volumes decreased 2.2%, primarily due to lower customer usage, partially offset by an increase in the average number of customers.

Earnings increased $24 million for the second quarter of 2023 compared to 2022, primarily due to higher allowances for equity and borrowed funds used during construction of $27 million, a favorable income tax benefit from the effects of ratemaking of $11 million and higher PTCs recognized of $8 million, increased interest and dividend income of $19 million, favorable changes in the cash surrender value of corporate-owned life insurance policies of $6 million and higher utility margin of $2 million, partially offset by higher operations and maintenance expense of $28 million and increased interest expense of $27 million due to debt issuances in December 2022 and May 2023. Utility margin increased due to higher retail rates, lower thermal generation costs and favorable deferred net power costs, partially offset by higher purchased power costs, lower retail and wholesale volumes and lower wheeling revenue. Operations and maintenance expense was unfavorable largely due to higher wildfire mitigation and vegetation management costs and higher legal expenses, partially offset by a decrease in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires of $15 million.

33

Operating revenue increased $200 million for the first six months of 2023 compared to 2022, primarily due to higher retail revenue of $218 million, partially offset by lower wholesale and other revenue of $17 million, primarily from lower wholesale volumes, partially offset by higher average wholesale market prices. Retail revenue increased primarily due to price impacts of $189 million from higher average retail rates largely due to tariff changes and product mix and $29 million from higher volumes. Retail customer volumes increased 0.6%, primarily due to favorable impacts of weather and an increase in the average number of customers, partially offset by lower customer usage.

Earnings decreased $226 million for the first six months of 2023 compared to 2022, primarily due to higher operations and maintenance expense of $456 million and increased interest expense of $45 million due to debt issuances in December 2022 and May 2023, partially offset by a favorable income tax benefit, higher allowances for equity and borrowed funds used during construction of $50 million, higher utility margin of $40 million, increased interest and dividend income of $31 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $9 million. Operations and maintenance expense was unfavorable primarily due to an increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires of $344 million, higher wildfire mitigation and vegetation management costs, higher legal expenses and higher general and plant maintenance costs. The favorable income tax benefit was driven by valuation allowance changes on state net operating loss carryforwards, the effects of ratemaking of $12 million and higher PTCs recognized of $11 million. Utility margin increased due to higher retail rates and volumes, favorable deferred net power costs and higher average wholesale market prices, partially offset by higher purchased power and thermal generation costs and lower wholesale volumes.

MidAmerican Funding

Operating revenue decreased $138 million for the second quarter of 2023 compared to 2022, primarily due to lower natural gas operating revenue of $74 million from a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries (fully offset in cost of sales) and lower electric operating revenue of $64 million. Electric operating revenue decreased due to lower wholesale and other revenue of $40 million and lower retail revenue of $24 million. Electric wholesale and other revenue decreased mainly due to lower average wholesale per-unit prices of $33 million and lower wholesale volumes of $6 million. Electric retail revenue decreased primarily due to lower recoveries through adjustment clauses of $27 million (fully offset in expense, primarily cost of sales), partially offset by price impacts of $3 million from changes in sales mix. Electric retail customer volumes increased 1.5%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather.

Earnings increased $29 million for the second quarter of 2023 compared to 2022, primarily due to lower depreciation and amortization expense of $51 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $21 million, partially offset by an unfavorable income tax benefit primarily from lower PTCs recognized of $12 million, higher operations and maintenance expense of $16 million and lower electric utility margin of $3 million. Depreciation and amortization expense decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Operations and maintenance expense increased mainly due to higher general and plant maintenance costs, increased administrative and other costs and unfavorable property insurance costs. Electric utility margin decreased primarily due to the lower wholesale and retail revenues, partially offset by lower thermal generation and purchased power costs.

Operating revenue decreased $223 million for the first six months of 2023 compared to 2022, primarily due to lower natural gas operating revenue of $144 million and lower electric operating revenue of $81 million. Natural gas operating revenue decreased primarily due to a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $136 million (fully offset in cost of sales) and the unfavorable impact of weather of $9 million. Electric operating revenue decreased due to lower wholesale and other revenue of $73 million and lower retail revenue of $8 million. Electric wholesale and other revenue decreased mainly due to lower average wholesale per-unit prices of $46 million and lower wholesale volumes of $28 million. Electric retail revenue decreased primarily due to lower recoveries through adjustment clauses of $13 million (fully offset in expense, primarily cost of sales), partially offset by price impacts of $3 million from changes in sales mix. Electric retail customer volumes increased 1.3%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather.

34

Earnings increased $37 million for the first six months of 2023 compared to 2022, primarily due to lower depreciation and amortization expense of $67 million, favorable changes in the cash surrender value of corporate-owned life insurance policies of $33 million and a one-time gain on the sale of an investment of $13 million, partially offset by higher operations and maintenance expense of $29 million, an unfavorable income tax benefit primarily from lower PTCs recognized of $13 million, lower electric utility margin of $10 million, lower natural gas utility margin of $8 million and lower allowances for equity and borrowed funds used during construction of $6 million. Depreciation and amortization expense decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Operations and maintenance expense increased mainly due to higher general and plant maintenance costs, increased administrative and other costs and unfavorable property insurance costs. Electric utility margin decreased primarily due to lower wholesale and retail revenues, partially offset by lower thermal generation and purchased power costs. Natural gas utility margin decreased primarily due to the unfavorable impact of weather.

NV Energy

Operating revenue increased $220 million for the second quarter of 2023 compared to 2022, primarily due to higher electric operating revenue of $205 million and higher natural gas operating revenue of $15 million from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric operating revenue increased primarily due to higher fully bundled energy rates (fully offset in cost of sales) of $206 million and increased base tariff general rates of $19 million at Sierra Pacific, partially offset by lower customer volumes of $25 million. Electric retail customer volumes decreased 5.5%, primarily due to the unfavorable impact of weather and lower customer usage, partially offset by an increase in the average number of customers.

Earnings decreased $3 million for the second quarter of 2023 compared to 2022, primarily due to unfavorable depreciation and amortization expense of $13 million, increased interest expense of $12 million due to higher outstanding long-term debt balances, higher operations and maintenance expense of $10 million and lower electric utility margin of $1 million, partially offset by favorable interest and dividend income of $12 million, mainly from carrying charges on higher deferred energy balances, higher allowances for equity and borrowed funds used during construction of $11 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $7 million. Depreciation and amortization expense increased primarily due to additional assets placed in-service. Operations and maintenance expense increased primarily due to higher general and plant maintenance costs. Electric utility margin decreased primarily due to lower retail customer volumes largely offset by higher base tariff general rates at Sierra Pacific.

Operating revenue increased $526 million for the first six months of 2023 compared to 2022, primarily due to higher electric operating revenue of $466 million and higher natural gas operating revenue of $60 million from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric operating revenue increased primarily due to higher fully bundled energy rates (fully offset in cost of sales) of $435 million, increased base tariff general rates of $27 million at Sierra Pacific and favorable transmission and wholesale revenue of $7 million, partially offset by lower customer volumes of $17 million. Electric retail customer volumes decreased 1.7%, primarily due to the unfavorable impact of weather and lower customer usage, partially offset by an increase in the average number of customers.

Earnings increased $2 million for the first six months of 2023 compared to 2022, primarily due to higher electric utility margin of $30 million, favorable interest and dividend income of $28 million, mainly from carrying charges on higher deferred energy balances, higher allowances for equity and borrowed funds used during construction of $14 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $11 million, partially offset by higher operations and maintenance expense of $34 million, unfavorable depreciation and amortization expense of $26 million and increased interest expense of $24 million due to higher outstanding long-term debt balances. Electric utility margin increased primarily due to higher base tariff general rates at Sierra Pacific and higher transmission and wholesale revenue, partially offset by lower retail customer volumes. Operations and maintenance expense increased primarily due to higher general and plant maintenance costs and higher customer service operations costs. Depreciation and amortization expense increased primarily due to additional assets placed in-service.

Northern Powergrid

Operating revenue decreased $38 million for the second quarter of 2023 compared to 2022, primarily due to lower distribution revenue of $30 million and lower revenue at CE Gas of $16 million, partially offset by higher non-regulated contracting revenue of $7 million. Distribution revenue decreased primarily due to lower recoveries of Supplier of Last Resort payments of $29 million (fully offset in cost of sales). CE Gas revenue decreased due to lower gas production volumes and prices from a gas project that commenced commercial operation in March 2022, partially offset by a solar project that commenced commercial operation in July 2022.

35

Earnings increased $25 million for the second quarter of 2023 compared to 2022, primarily due to favorable income tax expense from adjustments to the Energy Profits Levy income tax and lower distribution-related operating and depreciation expenses of $12 million, partially offset by increased non-service benefit plan costs $9 million.

Operating revenue increased $1 million for the first six months of 2023 compared to 2022, primarily due to higher revenue at CE Gas of $12 million, higher distribution revenue of $11 million and higher non-regulated contracting revenue of $11 million, partially offset by $34 million from the stronger U.S. dollar. Distribution revenue increased primarily due to higher recoveries of Supplier of Last Resort payments of $12 million (fully offset in cost of sales) and higher tariff rates of $10 million. Also impacting distribution revenue was a 4.6% decline in units distributed, largely due to the unfavorable impact of weather and lower customer usage in the first quarter of 2023, of $11 million. CE Gas revenue increased from a gas project that commenced commercial operation in March 2022 and a solar project that commenced commercial operation in July 2022.

Earnings decreased $75 million for the first six months of 2023 compared to 2022, primarily due to a deferred income tax charge of $82 million recognized in March 2023 related to the enactment of a new Energy Profits Levy income tax, increased non-service benefit plan costs of $19 million and $5 million from the stronger U.S. dollar, partially offset by favorable income tax expense from adjustments to the Energy Profits Levy income tax and favorable operating performance at CE Gas of $8 million from the gas and solar projects that commenced commercial operations in 2022.

BHE Pipeline Group

Operating revenue decreased $38 million for the second quarter of 2023 compared to 2022, primarily due to lower operating revenue of $49 million at BHE GT&S, partially offset by higher operating revenue of $16 million at Northern Natural Gas. The decrease in operating revenue at BHE GT&S was primarily due to lower non-regulated revenue of $75 million (largely offset in cost of sales) due lower volumes and unfavorable commodity prices, partially offset by higher LNG revenue of $16 million at Cove Point, an increase in variable revenue related to park and loan activity of $10 million at EGTS and an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $8 million. The increase in operating revenue at Northern Natural Gas was largely due to higher transportation revenue of $13 million from higher rates, the impacts of a general rate case, with interim rates effective January 1, 2023, subject to refund, of $9 million, partially offset by lower gas sales of $12 million (partially offset in cost of sales) from system balancing activities.

Earnings decreased $12 million for the second quarter of 2023 compared to 2022, primarily due to lower earnings of $39 million at BHE GT&S, partially offset by higher earnings of $30 million at Northern Natural Gas. The decrease at BHE GT&S was due to favorable state unitary income tax adjustments recognized in the second quarter of 2022, increased cost of gas from the unfavorable revaluation of volumes retained at EGTS due to lower natural gas prices and lower margin from non-regulated activities, partially offset by the variable revenue increase related to park and loan activity at EGTS and increased earnings at Cove Point. The increase at Northern Natural Gas was due to the impacts of the general rate case of $35 million and the higher transportation revenue, partially offset by higher operations and maintenance expense of $13 million and unfavorable margin on gas sales from system balancing activities of $10 million.

Operating revenue increased $100 million for the first six months of 2023 compared to 2022, primarily due to higher operating revenue of $87 million at Northern Natural Gas and $5 million at BHE GT&S. The increase in operating revenue at Northern Natural Gas was largely due to the impacts of a general rate case, with interim rates effective January 1, 2023, subject to refund, of $72 million and higher transportation revenue of $46 million from higher rates, partially offset by lower gas sales of $37 million (largely offset in cost of sales) from system balancing activities. The increase in operating revenue at BHE GT&S was primarily due to an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $50 million, higher LNG revenue of $32 million at Cove Point and an increase in variable revenue related to park and loan activity of $20 million at EGTS, partially offset by lower non-regulated revenue of $97 million (largely offset in cost of sales) from lower volumes and unfavorable commodity prices.

Earnings increased $35 million for the first six months of 2023 compared to 2022, primarily due to higher earnings of $57 million at Northern Natural Gas, partially offset by lower earnings of $24 million at BHE GT&S. The increase at Northern Natural Gas was due to the impacts of the general rate case of $51 million and the higher transportation revenue, partially offset by higher operations and maintenance expense of $31 million and unfavorable margin on gas sales from system balancing activities of $11 million. The decrease at BHE GT&S was due to higher operations and maintenance expense, increased cost of gas from the unfavorable revaluation of volumes retained at EGTS due to lower natural gas prices, favorable state unitary income tax adjustments recognized in the second quarter of 2022 and lower margin from non-regulated activities, partially offset by the favorable rate case settlement at EGTS in 2022, the variable revenue increase related to park and loan activity at EGTS, increased earnings at Cove Point and higher equity earnings at Iroquois Gas Transmission System.

36

BHE Transmission

Operating revenue increased $9 million for the second quarter of 2023 compared to 2022, primarily due to $16 million of incremental revenue from non-regulated wind-powered generating facilities acquired in November 2022, partially offset by $9 million from the stronger U.S. dollar.

Earnings decreased $4 million for the second quarter of 2023 compared to 2022, primarily due to $2 million of losses from non-regulated wind-powered generating facilities acquired in November 2022 and $2 million from the stronger U.S. dollar.

Operating revenue increased $31 million for the first six months of 2023 compared to 2022, primarily due to $42 million of incremental revenue from non-regulated wind-powered generating facilities acquired in November 2022 and higher other non-regulated revenue at BHE Canada, partially offset by $21 million from the stronger U.S. dollar.

Earnings decreased $2 million for the first six months of 2023 compared to 2022, primarily due to $5 million from the stronger U.S. dollar, partially offset by $3 million of incremental earnings from non-regulated wind-powered generating facilities acquired in November 2022.

BHE Renewables

Operating revenue decreased $41 million for the second quarter of 2023 compared to 2022, primarily due to lower natural gas and electric retail energy services revenues of $22 million, mainly from unfavorable natural gas pricing, lower solar revenues of $15 million, mainly from lower generation due to weather events in California, and lower natural gas and geothermal revenues of $8 million, largely due to maintenance outages and unfavorable pricing. These items were partially offset by higher wind revenues of $7 million, which increased primarily due to favorable changes in the valuations of certain derivatives contracts offset by lower generation of $21 million.

Earnings decreased $58 million for the second quarter of 2023 compared to 2022, primarily due to lower earnings of $19 million from the retail energy services business, largely due to unfavorable changes in unrealized positions on derivative contracts caused by lower forward electricity price curves, lower natural gas and geothermal earnings of $16 million, primarily due to maintenance outages, lower wind earnings of $11 million and lower solar earnings of $10 million from the lower generation. Wind earnings decreased due to lower earnings from tax equity investments of $46 million due to lower PTCs, partially offset by higher earnings from owned projects of $35 million. Earnings from owned projects were higher primarily due to the favorable derivative contract valuations and from gains on the extinguishment of debt, partially offset by a decrease in operating revenue from lower generation.

Operating revenue increased $16 million for the first six months of 2023 compared to 2022, primarily due to higher wind revenues of $67 million, partially offset by lower solar revenues of $35 million, mainly from lower generation due to weather events in California, and lower natural gas and geothermal revenues of $8 million, mainly due to maintenance outages and unfavorable pricing. Wind revenues increased primarily due to favorable changes in the valuations of certain derivatives contracts offset by lower generation of $16 million.

Earnings decreased $124 million for the first six months of 2023 compared to 2022, primarily due to lower earnings of $98 million from the retail energy services business, largely due to unfavorable changes in unrealized positions on derivative contracts caused by lower forward electricity price curves, lower natural gas and geothermal earnings of $56 million, primarily due to maintenance outages, and lower solar earnings of $28 million from the lower generation. These items were partially offset by higher wind earnings of $62 million due to increased earnings from owned projects of $80 million, partially offset by lower earnings from tax equity investments of $18 million due to lower PTCs. Earnings from owned projects were higher primarily due to the favorable derivative contract valuations and from gains on the extinguishment of debt, partially offset by a decrease in operating revenue from lower generation.

HomeServices

Operating revenue decreased $376 million for the second quarter of 2023 compared to 2022, primarily due to lower brokerage and settlement services revenue of $344 million and lower mortgage revenue of $31 million. The decrease in brokerage and settlement services revenue resulted from a 24% decrease in closed transaction volume due to rising interest rates and a corresponding decline in home sales. The lower mortgage revenue was due to a 35% decrease in funded volume, primarily due to rising interest rates.

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Earnings decreased $50 million for the second quarter of 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services of $40 million and mortgage services of $9 million. Earnings declined due to the decrease in closed transaction and mortgage funded volumes, partially offset by favorable operating expenses primarily due to lower compensation costs.

Operating revenue decreased $708 million for the first six months of 2023 compared to 2022, primarily due to lower brokerage and settlement services revenue of $637 million and lower mortgage revenue of $65 million. The decrease in brokerage and settlement services revenue resulted from a 26% decrease in closed transaction volume due to rising interest rates and a corresponding decline in home sales. The lower mortgage revenue was due to a 38% decrease in funded volume, primarily due to rising interest rates.

Earnings decreased $105 million for the first six months of 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services of $77 million and mortgage services of $21 million. Earnings declined due to the decrease in closed transaction and mortgage funded volumes, partially offset by favorable operating expenses primarily due to lower compensation costs.

BHE and Other

Operating revenue increased $6 million for the second quarter of 2023 and decreased $10 million for the first six months of 2023 compared to 2022, due to changes in intersegment eliminations.

Earnings decreased $1,769 million for the second quarter of 2023 compared to 2022, primarily due to the $1,789 million unfavorable comparative change related to the Company's investment in BYD, $29 million of lower federal income tax credits recognized on a consolidated basis and higher BHE corporate interest expense from an April 2022 debt issuance. These items were partially offset by higher net interest and dividend income of $49 million related to the Company's investment in BYD, favorable changes in the cash surrender value of corporate-owned life insurance policies of $24 million and $4 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain insurance subsidiaries of Berkshire Hathaway.

Earnings decreased $234 million for the first six months of 2023 compared to 2022, primarily due to the $258 million unfavorable comparative change related to the Company's investment in BYD, $46 million of lower federal income tax credits recognized on a consolidated basis and higher BHE corporate interest expense from an April 2022 debt issuance. These items were partially offset by higher net interest and dividend income of $75 million related to the Company's investment in BYD, favorable changes in the cash surrender value of corporate-owned life insurance policies of $38 million and $12 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain insurance subsidiaries of Berkshire Hathaway.

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, 2022 for further discussion regarding the limitation of distributions from BHE's subsidiaries.

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As of June 30, 2023, the Company's total net liquidity was as follows (in millions):

															BHE Pipeline
					MidAmerican		NV		Northern		BHE				Group and
	BHE		PacifiCorp		Funding		Energy		Powergrid		Canada		HomeServices		Other		Total
Cash and cash equivalents	$	112	$	586	$	454	$	81	$	26	$	74	$	271	$	625	$	2,229
Credit facilities(1)	3,500		2,000		1,509		1,000		341		812		2,230		—		11,392
Less:
Short-term debt	(1,245)		—		—		—		(104)		(111)		(783)		—		(2,243)
Tax-exempt bond support and letters of credit	—		(249)		(306)		—		—		(1)		—		—		(556)
Net credit facilities	2,255		1,751		1,203		1,000		237		700		1,447		—		8,593
Total net liquidity	$	2,367	$	2,337	$	1,657	$	1,081	$	263	$	774	$	1,718	$	625	$	10,822
Credit facilities:
Maturity dates	2026		2026		2024, 2026		2026		2025		2024, 2026, 2027		2023, 2024, 2026

(1)Includes $87 million drawn on capital expenditure and other uncommitted credit facilities at Northern Powergrid.

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022, were $3.7 billion and $5.1 billion, respectively. The decrease was primarily due to unfavorable operating results, the timing of payments related to fuel and energy costs, changes in working capital and a decrease in income tax receipts.

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

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2023 and 2022, were $(3.7) billion and $(3.5) billion, respectively. The change was primarily due to higher purchases, net of proceeds from sales and maturities, of U.S. Treasury Bills totaling $1.3 billion and higher capital expenditures of $643 million, partially offset by higher proceeds from sales, net of purchases, of marketable securities of $1.7 billion. Refer to "Future Uses of Cash" for a discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2023, was $625 million. Sources of cash totaled $2.3 billion and consisted of proceeds from subsidiary debt issuances totaling $1.2 billion and net proceeds from short-term debt totaling $1.1 billion. Uses of cash totaled $1.7 billion and consisted mainly of repayments of subsidiary debt totaling $959 million, repayments of BHE senior debt totaling $400 million and distributions to noncontrolling interests of $269 million.

For a discussion of recent financing transactions, refer to Note 6 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Net cash flows from financing activities for the six-month period ended June 30, 2022, was $(605) million. Sources of cash totaled $2.2 billion and consisted of proceeds from subsidiary debt issuances totaling $1.2 billion and proceeds from BHE senior debt issuances totaling $987 million. Uses of cash totaled $2.8 billion and consisted mainly of purchases of common stock totaling $870 million, preferred stock redemptions of $800 million, repayments of subsidiary debt totaling $542 million, distributions to noncontrolling interests of $246 million and net repayments of short-term debt totaling $54 million.

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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 customer 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.

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

	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2022		2023		2023
Capital expenditures by business:
PacifiCorp	$	894	$	1,529	$	3,594
MidAmerican Funding	862		763		2,147
NV Energy	541		889		1,794
Northern Powergrid	450		249		556
BHE Pipeline Group	457		406		1,364
BHE Transmission	95		86		200
BHE Renewables	61		59		302
HomeServices	20		19		39
BHE and Other(1)	2		25		26
Total	$	3,382	$	4,025	$	10,022

Capital expenditures by type:
Wind generation	$	304	$	615	$	1,791
Electric distribution	805		1,045		2,221
Electric transmission	628		749		2,013
Natural gas transmission and storage	335		304		1,021
Solar generation	261		251		444
Electric battery and pumped hydro storage	3		45		257
Other	1,046		1,016		2,275
Total	$	3,382	$	4,025	$	10,022

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

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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 of wind-powered generating facilities at MidAmerican Energy totaling $200 million and $5 million for the six-month periods ended June 30, 2023 and 2022, respectively. The timing and amount of forecast wind generation capital expenditures may be substantially impacted by the ultimate outcome of MidAmerican Energy's Wind PRIME filing. Planned spending for the construction of additional wind-powered generating facilities totals $544 million for the remainder of 2023.

◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $19 million and $214 million for the six-month periods ended June 30, 2023 and 2022, respectively. Planned spending for the repowering of wind-powered generating facilities totals $46 million for the remainder of 2023. 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.

◦Construction of new wind-powered generating facilities and construction at existing wind-powered generating facility sites acquired from third parties at PacifiCorp totaling $366 million and $11 million for the six-month periods ended June 30, 2023 and 2022, respectively. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $444 million for the remainder of 2023 and is primarily for the Rock Creek I and Rock Creek II projects to be constructed in Wyoming totaling 590 MWs that are expected to be placed in-service in 2024 and 2025.

◦Repowering of wind-powered generating facilities at BHE Renewables totaling $45 million for the six-month period ended June 30, 2022. Planned spending for the repower of wind-powered facilities totals $50 million for the remainder of 2023.

•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 enhancements 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 transmission investments primarily reflect costs associated with Energy Gateway Transmission segments that are expected to be placed in-service in 2024 through 2028. Expenditures for these projects totaled $313 million and $297 million for the six-month periods ended June 30, 2023 and 2022, respectively. Planned spending for these Energy Gateway Transmission segments totals $667 million for the remainder of 2023.

◦Nevada Utilities' Greenlink Nevada transmission expansion program. The Nevada Utilities have received approval from the PUCN to build a 350-mile, 525-kV transmission line connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line 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 substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substation. Expenditures for the expansion program and other growth projects totaled $113 million and $60 million for the six-month periods ended June 30, 2023 and 2022, respectively. Planned spending for the expansion program estimated to be placed in-service in 2026 through 2028 and other growth projects totals $94 million for the remainder of 2023.

◦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 asset modernization and the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, spending for pipeline integrity projects, automation and controls upgrades, corrosion control, unit exchanges, compressor modifications, projects related to Pipeline and Hazardous Materials Safety Administration natural gas storage rules and natural gas transmission, storage and LNG terminalling infrastructure needs to serve existing and expected demand.

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•Solar generation includes growth expenditures, including spending for the following:

◦Construction of solar-powered generating facilities at PacifiCorp totaling 377 MWs of new generation and are expected to be placed in-service in 2026. Planned spending totals $12 million for the remainder of 2023.

◦Construction and operation of solar-powered generating facilities at MidAmerican Energy, primarily consisting of 141 MWs of small- and utility-scale solar generation, all of which were placed in-service in 2022. For the six-month periods ended June 30, 2023 and 2022, solar generation spending totaled $10 million and $77 million, respectively. Planned spending totals $14 million for the remainder of 2023.

◦Construction of a solar-powered generating facility at Nevada Power totaling $156 million and $23 million for the six-month periods ended June 30, 2023 and 2022, respectively. Planned spending totals $50 million for the remainder of 2023. Construction includes expenditures for a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023 or early 2024.

◦Construction of a solar-powered generating facility at BHE Renewables totaling $2 million for the six-month period ended June 30, 2023. Planned spending totals $56 million for the remainder of 2023. Construction includes expenditures for a 48-MW solar photovoltaic facility with an additional 48 MWs of co-located battery storage that will be developed in Rosamond, California. Commercial operations is expected by the end of 2024.

•Electric battery and pumped hydro storage includes growth expenditures, including spending for the following:

◦Construction at the Nevada Utilities of a 100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that will be developed in Clark County, Nevada and a 220-MW grid-tied battery energy storage system that will be developed on the site of the retired Reid Gardner generating station in Clark County, Nevada, both with commercial operation expected by the end of 2023 or early 2024. Also, a 200-MW battery energy storage system that will be developed on the site of the Valmy generating station in Humboldt County, Nevada with commercial operation expected by the end of 2025. Total spending for the six-month period ended June 30, 2023, was $43 million with planned spending of $200 million for the remainder of 2023.

•Other 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.

Cove Point Acquisition

On July 9, 2023, BHE and Eastern MLP Holding Company II, LLC ("the Buyer"), an indirect wholly owned subsidiary of BHE, entered into a Purchase and Sale Agreement (the "Purchase Agreement") with Dominion Energy, Inc. ("DEI") and DECP Holdings, Inc. (the "Seller"), an indirect wholly owned subsidiary of DEI, to purchase (the "Transaction") Seller's 50% limited partner interests in Cove Point LNG, LP ("Cove Point") for a cash purchase price of $3.3 billion, plus the pro rata portion of any quarterly distribution made by Cove Point for the fiscal quarter in which the Transaction closes. BHE expects to fund the purchase price with cash on hand, including cash realized from the liquidation of certain investments. Upon the completion of the Transaction, the Buyer will own an aggregate of 75% of the limited partner interests, and its affiliate, Cove Point GP Holding Company, LLC, will continue to own 100% of the general partner interest, of Cove Point. Subject to certain closing conditions, the Transaction is expected to close by year-end 2023.

Material Cash Requirements

As of June 30, 2023, there have been no material changes in 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, 2022, other than those disclosed in Note 11 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

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, 2022, and new regulatory matters occurring in 2023.

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PacifiCorp

Utah

In May 2023, PacifiCorp filed its energy balancing account application to recover deferred net power costs from 2022. The filing requested a rate increase of $98 million, or 4.6%, effective on an interim basis July 1, 2023.

Oregon

In July 2022, PacifiCorp filed an application requesting approval of an automatic adjustment clause with a balancing account to recover costs associated with implementing PacifiCorp's wildfire protection plan in Oregon. Per formal rulemaking at the OPUC, the wildfire protection plan was changed to be known as the wildfire mitigation plan, resulting in the requested automatic adjustment clause being referred to as the Wildfire Mitigation Plan Automatic Adjustment Clause ("WMP AAC"). In December 2022, a stipulation with certain parties was filed agreeing to the establishment of an automatic adjustment clause. In May 2023, the OPUC approved the stipulation, which resulted in an overall annual increase of $20 million, or 1.6%, effective May 24, 2023 for estimated 2022 incremental operation and maintenance costs in excess of those reflected in base rates as a result of the last general rate case. In June 2023, PacifiCorp filed its WMP AAC to recover remaining 2022 deferred operations and maintenance costs, projected incremental 2023 operations and maintenance costs and capital costs incremental to amounts previously included in general rate case filings. The filing requested a rate increase of $27 million over the existing amount approved in May 2023, to become effective November 5, 2023. When combined with the previously approved increase, the rate schedule would be set to recover $47 million.

In April 2023, PacifiCorp filed its transition adjustment mechanism requesting approval to update net power costs for 2024. The filing requested a rate increase of $164 million, or 9.5%, to become effective January 1, 2024.

Wyoming

In March 2023, PacifiCorp filed a general rate case requesting a rate increase of $140 million, or 21.6%, to become effective January 1, 2024. The requested rate increase includes recovery of increases in net power costs and new major capital investments in transmission and wind-powered generating facilities.

In April 2023, PacifiCorp filed its energy cost adjustment and renewable energy credit and sulfur dioxide revenue credit mechanisms to recover deferred net power costs from 2022. The combined filing requested a rate increase of $49 million, or 7.4%, to become effective on an interim basis July 1, 2023.

Washington

In March 2023, PacifiCorp filed a general rate case requesting a two-year rate plan with a rate increase of $27 million, or 6.6%, to become effective March 1, 2024, and a second rate increase of $28 million, or 6.5%, to become effective March 1, 2025. The requested rate increase includes recovery of increases in net power costs and new major capital investments in transmission and wind-powered generating facilities.

In June 2023, PacifiCorp filed its power cost adjustment mechanism to recover deferred net power costs from 2022. The filing requested recovery of over $71 million, which PacifiCorp proposed to recover over a two-year period with interest, resulting in a rate increase of $37 million, or 9.5%, to become effective January 1, 2024.

Idaho

In October 2022, PacifiCorp filed an application for authority to implement the residential rate modernization plan. The plan proposes a five-year transition to increase the monthly customer service charge from $8.00 to $29.25 per month with a corresponding reduction to the energy rate, eliminates the tiered rates, and adjusts the on-peak off-peak period for time-of-day customers. In response to concerns about the combined impact of the proposed changes, PacifiCorp proposed a modification to, rather than elimination of, the tiered rates. In May 2023, the Idaho Public Utilities Commission issued an order approving PacifiCorp's request to increase the customer service charge over five years, to adjust peak periods for time-of-day customers, and to modify the tiered rate structure. The changes to the residential rates became effective June 1, 2023.

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California

In May 2022, PacifiCorp filed a general rate case requesting an overall rate change of $28 million, or 25.7%, to become effective January 1, 2023. In November 2022, the CPUC granted the requested rate effective date and directed PacifiCorp to establish a memorandum account to track the change in rates beginning January 1, 2023, until the new rates become effective upon the issuance of a decision in late 2023. PacifiCorp filed rebuttal testimony in February 2023 with a slight adjustment of an overall rate increase of $27 million, or 25.0%. Also in February 2023, the CPUC issued a ruling requesting additional information on PacifiCorp's wildfire and risk analyses and requested additional information regarding wildfire memorandum accounts. In March 2023, the CPUC split the general rate case into two tracks. The first track addresses the general rate case with an expected decision from the CPUC in late 2023, and the second track addresses the wildfire memorandum accounts with a decision expected in the second quarter of 2024.

Deferral Accounting Treatment for Wildfire Liability

In June 2023, PacifiCorp filed deferral applications with its state commissions in all six states to track the costs associated with third-party liability from litigation due to the 2020 Wildfires. The deferred accounting applications enable PacifiCorp to preserve its ability to seek recovery in the future in the event the outcome could potentially impact its financial stability. The applications state that PacifiCorp is not seeking recovery of these costs from customers at this time and does not expect to determine if it will seek recovery until the appeals process has concluded.

MidAmerican Energy

Iowa Gas

In June 2023, MidAmerican Energy filed a request with the IUB for an increase in its Iowa retail natural gas rates, which would increase revenue by $39 million annually. If approved, the requested rates would increase retail customer's bills by an average of 6.1%. Interim rates of $31 million annually, or an average increase to customer's bills of 4.8%, were effective in June 2023.

South Dakota

In May 2022, MidAmerican Energy filed a request with the South Dakota Public Utilities Commission ("SDPUC") for a $7 million, or 6.4%, annual increase in South Dakota retail natural gas rates. In March 2023, MidAmerican Energy filed a settlement agreement between all parties allowing a total increase of $6 million, or 5.5%, annual increase in South Dakota retail natural gas rates, upon completion of the capital investment phase-in adjustment clause. On March 31, 2023, the SDPUC issued an order approving the settlement agreement with final rates effective April 1, 2023.

Wind PRIME

In January 2022, MidAmerican Energy filed an application with the IUB for advance ratemaking principles for Wind PRIME. If approved, MidAmerican Energy expects to proceed with Wind PRIME, which consists of up to 2,042 MWs of new wind generation and up to 50 MWs of solar generation. If all Wind PRIME generation is constructed, MidAmerican Energy will own over 9,300 MWs of wind generation and nearly 200 MWs of solar generation. Wind PRIME is projected to allow MidAmerican Energy to generate renewable energy greater than or equal to all of its Iowa retail customers' annual energy needs. MidAmerican Energy expects to be eligible for 100% PTCs under current tax law for the Wind PRIME projects. In December 2022, MidAmerican Energy, the Iowa Office of Consumer Advocate and the Iowa Business Energy Coalition filed a non-unanimous settlement with the IUB that included a rate of return of 11.0%. The settlement would benefit customers by providing an immediate rate decrease through lower retail fuel costs and future rate increase mitigation through accelerated depreciation of generation assets. On April 27, 2023, the IUB issued its final order regarding the application and found that MidAmerican Energy met the statutory requisites for a grant of advance ratemaking principles and granted the application, but rejected the settlement and proposed its own principles for the project. MidAmerican Energy reviewed the order and filed a motion for reconsideration or rehearing on May 17, 2023. On June 15, 2023, the IUB granted the motion for reconsideration and rehearing. On July 14, 2023 the IUB issued a new procedural schedule with rehearing set to begin on October 10, 2023. MidAmerican Energy expects the IUB to issue an order on the request for reconsideration and rehearing by the end of 2023.

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Iowa Transmission Legislation

In June 2020, Iowa enacted legislation that grants incumbent electric transmission owners the right to construct, own and maintain electric transmission lines that have been approved for construction in a federally registered planning authority's transmission plan and that connect to the incumbent electric transmission owner's facility. Also known as the Right of First Refusal, the law provides MidAmerican Energy, as an incumbent electric transmission owner, the legal right to construct, own and maintain transmission lines in MidAmerican Energy's service territory that have been approved by the MISO (or another federally registered planning authority) and are eligible to receive regional cost allocation. To exercise the legal right, MidAmerican Energy must notify the IUB within 90 days of any such approval for the construction of eligible electric transmission lines that it intends to construct, own and maintain. The law still requires an incumbent electric transmission owner to obtain a state franchise from the IUB to construct, erect, maintain or operate an electric transmission line and, upon issuance of a franchise, the incumbent electric transmission owner must provide the IUB an estimate of the cost to construct the eligible electric transmission line and, until the construction is complete, a quarterly report updating the estimated cost to construct the eligible electric transmission line. In October 2020, national transmission interests filed a lawsuit that challenged the law on state constitutional grounds. The suit argues that the law was enacted in violation of the "single-subject" provision of Iowa's state constitution because it was "log-rolled" into a late session appropriations bill and violates the equal protection provision of the Iowa constitution. The State of Iowa defended the law, and MidAmerican Energy and ITC Midwest both intervened and defended the law as well. The Iowa district court dismissed the lawsuit in March 2021 for lack of standing, and the national transmission interests appealed. In June 2022, the Iowa Court of Appeals upheld the district court's decision, after which the national transmission interests asked the Iowa Supreme Court to reconsider. In November 2022, the Iowa Supreme Court granted the motion to reconsider. On March 24, 2023, the Iowa Supreme Court issued an opinion that reversed the lower courts, held the national transmission interests had standing, and remanded the case to the district court to consider the state constitutional claims on their merits. The opinion also imposed a temporary injunction that stayed enforcement of the law pending a decision on the merits. On April 7, 2023, the State of Iowa, acting individually, and MidAmerican Energy and ITC Midwest, acting jointly, filed petitions for rehearing with the Iowa Supreme Court. On April 19, 2023, the national transmission interests filed a reply that (1) expressed its opposition to the petitions for rehearing, (2) asked the Iowa Supreme Court to hold that the injunction specifically applied to and precluded advancement of MidAmerican Energy's Long Range Transmission Projects ("LRTP") Tranche 1 projects, and (3) asked the Iowa Supreme Court to retain the matter and rule on the constitutional claims on the merits without further briefing or argument. On April 26, 2023, the Iowa Supreme Court issued an order that denied the petitions for rehearing without comment and made minor, non-substantive changes to the decision, with no changes to the injunction. On May 30, 2023, the Iowa Supreme Court remanded the case to the district court for further proceedings on the merits, where the national transmission interests have filed a motion for summary judgment. The State of Iowa, MidAmerican Energy and ITC Midwest are collaborating on a resistance to the motion and the State of Iowa is preparing a cross motion for summary judgment. A hearing on the motions for summary judgment is scheduled for September 29, 2023, with defendants' resisting documents due on August 4, 2023, plaintiffs' documents due on September 8, 2023, and reply documents due on September 18, 2023. To this point, MISO has taken no action to reverse or disrupt its approval of MidAmerican Energy's LRTP Tranche 1 projects. This matter only potentially affects the manner in which MidAmerican Energy would secure the right to construct transmission lines that are eligible for regional cost allocation and are otherwise subject to competitive bidding under the MISO tariff; it does not negatively affect or implicate MidAmerican Energy's ongoing rights to construct any other transmission lines, including lines required to serve new or expanded retail load, connect new generators or meet reliability criteria.

NV Energy (Nevada Power and Sierra Pacific)

Merger Application

In March 2022, the Nevada Utilities filed a joint application with the PUCN for authorization to merge Sierra Pacific with and into Nevada Power, with Nevada Power being the surviving entity. If approved by the PUCN as filed, Nevada Power will have two distinct electric service territories in northern and southern Nevada each with their own rates and one natural gas service territory in the Reno and Sparks area. In October 2022, all parties to the proceedings relating to the joint application entered into a Stipulation to delay the procedural schedule. The Nevada Utilities made a supplemental filing on December 30, 2022. In March 2023, the proceedings relating to the joint application were postponed to May 2023. In April 2023, the Nevada Utilities filed a notice with the PUCN requesting to withdraw the joint application to merge into a single corporate entity and vacate the current procedural schedule, and executed a termination of the related merger agreement. In May 2023, the PUCN issued an order vacating the procedural schedules and hearing.

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Transportation Electrification Plan ("TEP")

In September 2022, the Nevada Utilities filed an amendment to the 2021 Joint IRP for the approval of a Distributed Resource Plan amendment to implement the state's first TEP pursuant to Section 51 of SB 448 and approve proposed tariffs and schedules to implement the TEP. The 2022 TEP outlines programs, investments and incentives to accelerate transportation electrification across Nevada. The Nevada Utilities proposed a budget of $348 million, which represents the maximum cost over the depreciable life of the TEP's programs and assets, to deploy the TEP in 2023 through 2024. In March 2023, the PUCN issued an order approving certain programs in the TEP, authorizing a lower program budget of $70 million and ordering specific caps on the program management and contingency budget amounts. The unapproved programs have been deferred for approval in future TEP filings. The PUCN also granted regulatory asset treatment of the approved program costs. In April 2023, interveners filed a petition for reconsideration of the PUCN's March 2023 Order. In May 2023, the PUCN granted in part and denied in part the petition for reconsideration and affirmed the March 2023 Order.

Deferred Energy Accounting Adjustment ("DEAA") Rate

In May 2023, the Nevada Utilities filed an application with the PUCN for approval to adjust the DEAA rates in excess of the maximum allowable adjustment to provide a discounted rate to customers effective July 1, 2023. In June 2023, the Nevada Utilities filed a stipulation signed by interveners that resolved all matters in the dockets opened for the application. In June 2023, the PUCN accepted the stipulation and granted the application as modified. The rate reduction for customers was effective July 1, 2023.

Regulatory Rate Review

In June 2023, Nevada Power filed a regulatory rate review with the PUCN that requested an annual revenue increase of $93 million, or 3.3%. In addition, a filing was made to revise depreciation rates based on a study, the results of which are reflected in the proposed revenue requirements. An order is expected by the end of 2023 and, if approved, would be effective January 1, 2024.

Northern Powergrid Distribution Companies

Ofgem has completed the price control review that resulted in a new price control effective April 1, 2023. The license modifications that give effect to the price control were published by Ofgem on February 3, 2023, and were subject to appeal to the Competition and Markets Authority ("CMA") if an appeal was filed by March 3, 2023. On March 2, 2023, Northern Powergrid sought permission from the CMA to appeal against the license modifications that give effect to the RIIO-ED2 price control. The appeal relates to two specific areas:

•Ofgem's misallocation of allowances that is inconsistent with efficient costs; and

•Ofgem's approach to determine rewards for the Business Plan Incentive.

The permission for the appeal was granted by the CMA and the appeal is expected to conclude in the third quarter of 2023 in accordance with the timetable required of the CMA. The outcome of this appeal may increase the revenue available to the Company if the CMA amends the price control determination.

BHE Pipeline Group

BHE GT&S

In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. 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 transmission 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. In September 2022, a settlement agreement was filed with the FERC, which provided for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual firm transmission and storage services revenues of approximately $160 million and a decrease in annual depreciation expense of approximately $30 million, compared to the rates in effect prior to April 1, 2022. EGTS' provision for rate refund for April 2022 through February 2023, including accrued interest, totaled $91 million. In November 2022, the FERC approved the settlement agreement and the rate refunds to customers were processed in late February 2023.

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Northern Natural Gas

In July 2022, Northern Natural Gas filed a general rate case that proposed an overall annual cost-of-service of $1.3 billion. This is an increase of $323 million above the cost of service filed in its 2019 rate case of $1.0 billion. Depreciation on increased rate base and an increase in depreciation and negative salvage rates account for $115 million of the $323 million increase in the filed cost of service. Northern Natural Gas has requested increases in various rates, including transportation and storage reservation rates. In January 2023, the FERC approved Northern Natural Gas filing to implement its interim rates effective January 1, 2023, subject to refund and the outcome of hearing procedures. In June 2023, a settlement agreement was filed with the FERC resolving all pending issues in the rate case and providing for increased service rates and increased depreciation rates for onshore transmission plant from 2.30% to 2.49%. Market Area transportation reservation rates increased 32.5% and storage reservation rates increased 13.0% from the rates that were in effect in 2022. The settlement also provides for a Section 4 and Section 5 rate action moratorium through June 30, 2024, subject to certain exceptions. The settlement rates were implemented May 1, 2023, and the Company's provision for rate refunds for January 2023 through April 2023 totaled $88 million. FERC approval of the settlement is expected before the end of 2023.

BHE Transmission

AltaLink

2024-2025 General Tariff Application

In April 2023, AltaLink filed its 2024-2025 GTA with the AUC with total transmission tariffs of C$902.3 million and C$908.6 million for 2024 and 2025, respectively, which extends AltaLink's previous five-year commitment to maintain its tariff at or below C$904 million from 2019 to 2023 for another year. The application also requests the approval to reinstate C$98.9 million cost of removal to rate base which was not previously approved, based on additional information filed.

In July 2023, AltaLink requested the AUC to suspend the schedule for its 2024-2025 GTA until August 31, 2023. AltaLink requires the schedule delay to amend its application. The amendment is in response to the unprecedented wildfire events that AltaLink experienced in Alberta, Canada in May and June 2023. The AUC accepted AltaLink's request to refile its application on August 31, 2023, and directed AltaLink to limit its application updates to its Wildfire Mitigation Plan and related wildfire references. AltaLink plans to file an application with the AUC later this year to recover all costs incurred as a result of the recent wildfire events.

Generic Cost of Capital Proceeding

In January 2022, the AUC initiated the generic cost of capital proceeding. The proceeding will be conducted in two stages. The first stage will determine the cost of capital parameters for 2023 and the second stage will consider returning to a formula-based approach to establish cost of capital adjustments, commencing in 2024. In March 2022, the AUC issued its decision with respect to the first stage of the GCOC proceeding by approving the extension of the 2022 return on equity of 8.5% and deemed equity ratio of 37% for 2023, recognizing lingering uncertainty and continued volatility of financial markets. In June 2022, the AUC initiated the second stage to explore a formula-based approach to determine the return on equity for 2024 and future test periods.

In February 2023, AltaLink and other stakeholders filed evidence. AltaLink filed expert evidence recommending a 10.3% return on equity, on a recommended equity ratio of 40%. Other utilities filed similar recommendations. The Consumers' Coalition of Alberta, the Utilities Consumer Advocate and the Industrial Power Consumers Association of Alberta recommended returns on equity ranging from 6.75% to 7.7% and equity ratios ranging from 35% to 37%. AltaLink's expert witness, as well as all other utility experts, submitted that they are generally not in favor of implementing a formulaic adjustment mechanism for allowed return on equity due to the challenges in maintaining the Fair Return Standard through formulaic adjustments. The interveners are generally in favor of a formula. The AUC expects to conclude the second stage of the GCOC proceeding in the fourth quarter of 2023.

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Environmental Laws and Regulations

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal 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 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, 2022, and new environmental matters occurring in 2023.

Air Quality Regulations

The Clean Air Act, as well as state laws and regulations impacting air emissions, provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. These laws and regulations continue to be promulgated and implemented and will impact the operation of BHE's generating facilities and require them to reduce emissions at those facilities to comply with the requirements. In addition, the potential adoption of state or federal clean energy standards, which include low-carbon, non-carbon and renewable electricity generating resources, may also impact electricity generators and natural gas providers.

Greenhouse Gas Standards

In May 2023, the EPA proposed rules addressing greenhouse gas emissions from new and reconstructed natural gas-fueled combustion turbines (Clean Air Act Section 111(b) rule) and existing coal- and gas- or oil-fueled steam units and natural gas-fueled combustion turbines (Clean Air Act Section 111(d) rule). The proposed requirements for existing units would take effect January 1, 2030, through state implementation plans. Requirements for new combustion turbines are subcategorized based on capacity factor, where low-load units would be required to meet an emissions limit, intermediate-load units would be required to use a blend of low-emitting hydrogen and natural gas and base-load units would be required to utilize carbon capture and sequestration technology or a high-percentage blend of low-emitting hydrogen. Requirements for existing gas- and oil-fueled steam units are also subcategorized based on capacity factor, where low-load units would be subject to routine maintenance to demonstrate no increase in emissions, intermediate-load units would be subject to an emission limit of 1,500 pounds of CO2 / MWh-gross and base-load units would be subject to an emission limit of 1,300 pounds of CO2 / MWh-gross. Control equipment requirements for existing combustion turbines only apply to large, high load turbines that are greater than 300MW in capacity and operate at a greater than 50% capacity factor. These units would be required to begin utilizing carbon capture and sequestration with a 90% capture rate by 2035 or use a blend of low-emitting hydrogen starting in 2032. Requirements for existing coal-fueled units are subcategorized based on retirement date. Units with earlier retirement dates would be subject to less stringent requirements while units that commit to later retirement dates would be subject to annual capacity factor limits or natural gas co-firing requirements. Units that will continue operating after December 31, 2039, would be required to utilize carbon capture and sequestration with a 90% carbon capture rate. Clean Air Act Section 111 establishes a cooperative approach between the EPA and the states. The EPA establishes nationwide standards based on the best system of emissions reductions it identifies for a source category. States are then expected to develop plans to implement those standards at affected units. States may adopt the EPA's standards or develop state-specific standards that achieve the same air quality results. The EPA is accepting comments on the proposal through August 8, 2023. The relevant Registrants operate facilities that may be affected by these proposals. Until the EPA takes final action on the proposals, the states submit any required SIPs and litigation is exhausted, the relevant Registrants cannot determine the impacts of the proposed rule.

Mercury and Air Toxics Standards

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

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Numerous lawsuits have been filed in the D.C. Circuit challenging the MATS. In April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014, the U.S. Supreme Court agreed to hear the MATS appeal on the limited issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. In June 2015, the U.S. Supreme Court reversed and remanded the MATS rule, finding that the EPA had acted unreasonably when it deemed cost irrelevant to the decision to regulate generating facilities, and that cost, including costs of compliance, must be considered before deciding whether regulation is necessary and appropriate. In December 2018, the EPA issued a proposed revised supplemental cost finding for the MATS, as well as the required risk and technology review under Clean Air Act Section 112. The EPA proposed to determine that it is not appropriate and necessary to regulate hazardous air pollutant emissions from generating facilities under Section 112; however, the EPA proposed to retain the emission standards and other requirements of the MATS rule, because the EPA did not propose to remove coal- and oil-fueled generating facilities from the list of sources regulated under Section 112. In May 2020, the EPA published its decision to repeal the appropriate and necessary findings in the MATS rule and retain the overall emission standards. The rule took effect in July 2020. A number of petitions for review were filed in the D.C. Circuit by parties challenging and supporting the EPA's decision to rescind the appropriate and necessary finding, which were stayed pending the EPA's plans to revisit the finding. On January 31, 2022, the EPA proposed several actions relating to the MATS. The EPA proposed to restore the appropriate and necessary finding to regulate generating facilities under Clean Air Act Section 112. The EPA finalized its restoration of the MATS appropriate and necessary finding in February 2023.

On April 5, 2023, the EPA released a proposal to revise several aspects of the MATS rule following the agency's review of the 2020 Residual Risk and Technology Review. The EPA proposes two specific standard changes - one applicable to all covered units and one specific to the existing lignite subcategory. The EPA proposes a more stringent standard for emissions of filterable particulate matter, the surrogate standard for non-mercury metals for coal-fueled electric generating units. The EPA proposes to reduce the filterable particulate matter emission standard by two-thirds based on a demonstration that 91% of coal-based capacity, which has not been identified as retiring before the proposed compliance period, has an emission rate at or below the proposed limit. The EPA also proposes to require continuous emissions monitoring for filterable particulate matter to demonstrate compliance with the revised standard. Compliance would be due no later than three years after the effective date of a final rule and the EPA accepted comments on the proposal through June 23, 2023. The relevant Registrants are not included in the lignite subcategory. The relevant Registrants have identified that compliance can be achieved with existing controls. Until the EPA takes final action on the proposal, the full impacts of the rule cannot be determined.

National Ambient Air Quality Standards

Under the authority of the Clean Air Act, the EPA sets minimum NAAQS for six principal pollutants, consisting of carbon monoxide, lead, NOx, particulate matter, ozone and SO2, considered harmful to public health and the environment. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area that are determined to contribute to the nonattainment are required to reduce emissions. Currently, with the exceptions described in the following paragraphs, air quality monitoring data indicates that all counties where the relevant Registrant's major emission sources are located are in attainment of the current NAAQS.

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On June 4, 2018, the EPA published final ozone designations for much of the U.S. Relevant to the Registrants, these designations include classifying Yuma County, Arizona; Clark County, Nevada; and the Northern Wasatch Front, Southern Wasatch Front and Duchesne and Uintah counties in Utah as nonattainment-marginal with the 2015 ozone standard. These areas were required to meet the 2015 standard three years from the August 3, 2018, effective date. All other areas relevant to the Registrants were designated attainment/unclassifiable with this same action. However, on January 29, 2021, the D.C. Circuit vacated several provisions of the 2018 implementing rules for the 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 interstate ozone plans of 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 Wisconsin. On February 22, 2022, the EPA published a series of proposed decisions to disapprove the SIPs for interstate ozone transport of 19 states. Relevant to the 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. In addition, the EPA must approve or disapprove the interstate plans of Arizona, California, Nevada and Wyoming. On April 15, 2022 the EPA issued its final rule approving Iowa's SIP as meeting the good neighbor provisions for the 2015 ozone standard. On May 24, 2022, the EPA proposed to disapprove the Utah and Wyoming interstate ozone SIPs. On January 30, 2023, the EPA entered into a stipulated extension to the deadline for action on the Wyoming SIP, setting a new deadline of December 15, 2023. The EPA explained that the extra time is needed to fully consider updated air quality information and public comments. The EPA is also reevaluating SIPs for Tennessee and Arizona. On February 13, 2023, the EPA published final disapproval of the 19 SIPs proposed in April 2022, setting the stage to include those states in the federal implementation plan described under the Cross-State Air Pollution Rule. The EPA also deferred action on the SIPs for Wyoming, Tennessee and Arizona in the final rule. 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. Relevant to Registrants, the Southern Wasatch Front in Utah and Yuma, Arizona are proposed to have met the 2015 ozone standard; and the Cincinnati area of Ohio and Kentucky and the Northern Wasatch Front in Utah are proposed to have not met the 2015 ozone standard and to be reclassified as Moderate Non-Attainment, and will have until August 3, 2024 to meet the standard. Until the EPA takes final action on the proposal and the affected states submit any required SIPs, the relevant Registrants cannot determine the impacts of the proposed rule.

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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 U.S. 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. 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. In March 2023, the EPA released the final Good Neighbor Rule. The electric generation sector remains the key industry regulated by the rule and will be subject to emissions allowance trading beginning in summer 2023. The final rule shifted the maximum daily backstop rate for coal-fueled generating units, which drives the installation of new controls or curtailment, to take effect in 2030 instead of 2027. PacifiCorp's Hunter Units 1-3 and Huntington Units 1-2, which do not have SCR controls, are impacted by the rule. PacifiCorp's 2023 IRP selected the installation of SNCR on the Hunter and Huntington Units by 2026 as part of the preferred portfolio. The level of NOx allowances for the Utah units remains similar to 2021 levels, with significant reductions for the coal units beginning in 2026. The daily limit, which takes effect in 2030, will further restrict operation of coal-fueled units without SCR. NV Energy's fossil-fueled units are also covered by the final rule. North Valmy Units 1 and 2, which do not have SCR, will require additional controls or reduced operations during the ozone season if operated beyond 2025. Nevada's regional haze SIP has an enforceable retirement date for North Valmy Units 1 and 2 of December 31, 2028, and NV Energy's IRP identified a December 31, 2025, retirement date for the units. The EPA's updated modeling suggests that Arizona, Iowa and Kansas may be significantly contributing to nonattainment in downwind states. The EPA intends to undertake additional assessment of its modeling for these states and will determine if it is necessary to address obligations for these states in future actions. The EPA also deferred final action for Wyoming, pending further review of updated air quality and contribution modeling and analysis. Additional notice and comment rulemaking, such as a supplemental rule, would be required to rescind Iowa's approved SIP and incorporate additional states into the program. The states of Nevada, Utah and Wyoming challenged the EPA's denials and deferral, respectively, of their interstate ozone transport SIPs in the Ninth, Tenth and D.C. Circuit Courts of Appeals. PacifiCorp also filed petitions with the court opposing the EPA's action in Utah and Wyoming. At the time of filing, at least 11 other states have challenged the EPA's action to disapprove SIPs in different regional federal courts of appeal. Stays have been granted by four circuit courts for SIP disapprovals in eight states. Relevant to Registrants, the states of Nevada, Texas and Utah were granted stays. The final good neighbor rule was published June 5, 2023 and takes effect August 4, 2023. The EPA issued an interim final rule stating that the federal rule will not take effect in states in which the SIP disapprovals have been deferred or stayed. In addition to litigation over SIP disapprovals, there are numerous appeals of the final good neighbor rule pending in four different circuit courts, and at least four motions to stay the final rule have been filed in three different circuit courts. Additional appeals may be filed prior to the rule's August 4, 2023, effective date. Until additional rulemaking is completed and litigation is exhausted, the potential impacts to the relevant Registrants cannot be determined.

For the first time, the EPA included additional sectors beyond the electric generation sector in the 2023 expanded CSAPR program. Relevant to the Registrants, this includes the pipeline transportation of natural gas. Requirements for that sector focus on emissions reductions from reciprocating internal combustion engines involved in the transport of natural gas and take effect in 2026. There is no access to allowance trading for the non-electric generation sectors. The EPA excluded emergency engines and engines that do not operate during the ozone season, included a facility-wide averaging plan and eased requirements for monitoring in the final rule. Northern Natural Gas operates 18 affected units; BHE GT&S operates 157 affected units; and Kern River is not affected by the final rule.

Regional Haze

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

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In June 2019, the state of Utah incorporated a BART alternative into its SIP for regional haze planning period one. 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 EPA approved the SIP revision with the BART alternative in October 2020. The EPA's actions also withdrew a prior FIP that required installation of SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. 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. The EPA defended the SIP, and PacifiCorp and the state of Utah intervened in the litigation in support of the EPA. Oral arguments in HEAL Utah v. EPA were held March 21, 2023. A final decision from the court is expected by fall 2023.

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 in October 2014. The EPA's final action other parts of on the Wyoming SIP in 2014 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 by 2019. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming and several environmental groups also filed an appeal of the EPA's final action. 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 parties worked to mediate claims under the Wyoming regional haze requirements until the abatement on litigation was lifted in September 2022. Opening briefs were submitted in October 2022. In the litigation, PacifiCorp objects to the EPA's FIP requiring SCR on the Wyodak Unit. That requirement in the agency's plan remains stayed by the court. PacifiCorp has also intervened on behalf of the EPA against claims that Naughton Units 1 and 2 should have been subject to a SCR requirement. Oral argument was held May 16, 2023. PacifiCorp argued that the Naughton claims are moot but that a court ruling on the Wyodak claims is necessary because the EPA's federal plan complies with the Clean Air Act. A final decision from the court is expected by late fall 2023. Separately, 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 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, PacifiCorp must convert Jim Bridger Units 1 and 2 to natural gas and begin meeting emissions limits consistent with that conversion by January 1, 2024. The EPA and PacifiCorp executed an administrative order on consent June 9, 2022, covering compliance for Jim Bridger Units 1 and 2 under the regional haze rule. The federal order contains the same emission and operating limits as the Wyoming consent decree and adds federal approval of the compliance pathway outlined in the state consent decree, including revision of the SIP to include conversion of Jim Bridger Units 1 and 2 to natural gas. On December 30, 2022, the Wyoming Air Quality Division submitted the state-approved revised regional haze SIP requiring natural gas conversion of Jim Bridger Units 1 and 2 to the EPA for approval. The plan revision replaces a previous requirement for SCR at the units. The Wyoming Air Quality Division also issued an air permit for the natural gas conversion of Jim Bridger Units 1 and 2 on December 28, 2022. PacifiCorp submitted a notice of compliance to the EPA on March 9, 2023, to certify completion of the Jim Bridger administrative compliance order through completion of the requirements to comply with Wyoming's consent decree and revised SIP submission. PacifiCorp remains subject to the compliance terms of the Wyoming consent decree as it works to convert Jim Bridger Units 1 and 2 to natural gas. The EPA is in on-going discussions with Wyoming to finalize a determination on the SIP revisions, with a decision anticipated by fall 2023.

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

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Nevada, Utah and Wyoming each submitted regional haze SIPs for the regional haze second planning period to the EPA and received completeness determinations in August 2022. The EPA is required to make final determinations on the SIPs by August 2023. On August 25, 2022, the EPA promulgated a finding of failure to submit a SIP for the regional haze second planning period for 15 states, including Iowa. The finding establishes a two-year deadline for the agency to promulgate FIPs to address the requirements, unless prior to promulgating a FIP, the state submits, and the agency approves, a SIP meeting the requirements. The finding says the agency intends to continue to work with states in developing approvable SIP submittals in a timely manner. The Iowa Department of Natural Resources continues to work with the EPA on development of its SIP. On February 13, 2023, Iowa issued a draft SIP and accepted comment on the draft plan through March 16, 2023. Iowa proposes to require operational improvements to existing control equipment at MidAmerican Energy's Louisa Generation Station and Walter Scott Jr. Energy Center - Unit 3. Iowa anticipates submitting a final plan to the EPA in fall 2023.

Water Quality Standards

In November 2015, the EPA published final effluent limitation guidelines and standards for the steam electric power generating sector which, among other things, regulate the discharge of bottom ash transport water, fly ash transport water, combustion residual leachate and non-chemical metal cleaning wastes. In November 2019, the EPA proposed updates to the 2015 rule, specifically addressing flue gas desulfurization wastewater and bottom ash transport water. The rule took effect in December 2020. The final rule changes the technology-basis for treatment of flue gas desulfurization wastewater and bottom ash transport water, revises the voluntary incentives program for flue gas desulfurization wastewater, and adds subcategories for high-flow units, low utilization units, and those that will transition away from coal combustion by 2028. While most of the issues raised by this rule are already being addressed through the CCR rule and are not expected to impose significant additional requirements, the Dave Johnston generating facility is impacted by the rule's bottom ash handling requirements at Units 1 and 2. The generating facility submitted notice to the Wyoming Department of Environmental Quality that it will either achieve a cessation of coal combustion at Units 1 and 2 by December 31, 2028, or install bottom ash transport treatment technology by December 31, 2025. On March 8, 2023, the EPA proposed additional changes to the effluent limitations guidelines to replace the 2020 rule and provide stricter limits for bottom ash transport water, flue gas desulfurization wastewater and coal combustion residual leachate. The relevant Registrants use a combination of zero discharge, enrollment in cessation-of-coal subcategory and dry bottom ash handling to manage the affected wastestreams. As a result, significant impacts are not anticipated. However, until the EPA takes final action on the proposal, the full impacts of the rule cannot be determined. The EPA accepted public comments through May 30, 2023, and intends to finalize a rule by spring 2024.

In March 2023, the latest changes to the definition of "waters of the U.S.," a rule that determines which waters are regulated under the federal Clean Water Act, took effect. Under this rule, tributaries, many wetlands, intrastate lakes, intrastate ponds, intrastate streams and some impoundments must meet either test from the 2006 Rapanos plurality decision to be considered a water of the U.S. That is, a water must be relatively permanent and have a continuous surface connection to an included waterbody (the "relatively permanent" test) or it must significantly affect the biological, physical or chemical integrity of a traditional navigable water, territorial seas or interstate waters (the "significant nexus" test). The rule was challenged in multiple courts. On May 23, 2023, the U.S. Supreme Court issued a decision in Sackett v. EPA, a case that challenged the Clean Water Act's applicability to certain wetlands. In its decision, the Court significantly narrowed protections for wetlands and intermittent streams under the federal Clean Water Act. The Court unanimously rejected the significant nexus test as unworkable. A divided Court determined that jurisdiction applies to waters that are adjacent to traditional interstate navigable waters and that have a continuous surface connection with that traditional interstate navigable waters. In light of the Sackett decision, the EPA secured stays of litigation over its definitional rule in two of three pending challenges in order to conduct rulemaking to conform to the Court's decision. The EPA sent a new final definition rule to the White House Office of Management and Budget on July 17, 2023, and has stated it intends to issue the new rule by September 1, 2023.

Coal Ash Disposal

In April 2015, the EPA released a final rule to regulate the management and disposal of coal combustion residuals (CCR) under the RCRA. The rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the disposal of CCR. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts will need to be closed unless they can meet the more stringent regulatory requirements.

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At the time the rule was published in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, nine surface impoundments and three landfills were either closed or repurposed to no longer receive coal combustion byproducts and hence are not subject to the final rule. As PacifiCorp proceeded to implement the final coal combustion rule, it was determined that two surface impoundments located at the Dave Johnston generating facility were hydraulically connected and effectively constitute a single impoundment. In November 2017, a new surface impoundment was placed into service at the Naughton Generating Station. At the time the rule was published in April 2015, MidAmerican Energy owned or operated nine surface impoundments and four landfills that contain coal combustion byproducts. Prior to the effective date of the rule in October 2015, MidAmerican Energy closed or repurposed six surface impoundments to no longer receive coal combustion byproducts. Five of these surface impoundments were closed on or before December 21, 2017, and the sixth is undergoing closure. At the time the rule was published in April 2015, the Nevada Utilities operated 10 evaporative surface impoundments and two landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, the Nevada Utilities closed four of the surface impoundments, four impoundments discontinued receipt of coal combustion byproducts making them inactive and two surface impoundments remain active and subject to the final rule. The two landfills remain active and subject to the final rule.

Multiple parties filed challenges over various aspects of the final rule in the D.C. Circuit, resulting in settlement of some of the issues and subsequent regulatory action by the EPA. The EPA finalized the first phase of the CCR rule amendments in July 2018 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater performance standards for certain constituents, the EPA extended the deadline by which facilities must initiate closure of unlined ash ponds exceeding a groundwater protection standard and impoundments that do not meet the rule's aquifer location restrictions to October 31, 2020. Following submittal of competing motions from environmental groups and the EPA to stay or remand this deadline extension, on March 13, 2019, the D.C. Circuit granted the EPA's request to remand the rule and left the October 31, 2020, deadline in place while the agency undertakes a new rulemaking establishing a new deadline for initiating closure. On August 14, 2019, the EPA released its "Phase 2" proposal, which contains targeted amendments to the CCR rule in response to court remands and EPA settlement agreements, as well as issues raised in a rulemaking petition. The Phase 2 rule has not been finalized. In February 2020, the EPA proposed a federal CCR permit program as required by the WIIN Act of 2016. The federal permit rule has not been finalized.

In October 2020, the EPA released an advanced notice of proposed rulemaking on legacy CCR surface impoundments, seeking comment on and information related to issues relevant to development of regulations for legacy impoundments. On May 18, 2023, the EPA proposed the legacy surface impoundments rule and accepted comment on the proposal through July 17, 2023. The proposal encompasses legacy surface impoundments, which are inactive surface impoundments at inactive facilities; and CCR management units, which include CCR surface impoundments and landfills that closed prior to October 19, 2015, inactive CCR landfills, and other areas where CCR has been or is managed directly on the land. CCR management units include all units meeting that definition at active CCR facilities, as well as those at inactive facilities with one or more legacy surface impoundment. EPA proposes the impose substantially the same regulatory obligations for both legacy surface impoundments and CCR management units as are applicable to currently regulated units, including groundwater monitoring and corrective action. All legacy surface impoundments and CCR management units would be required to initiate closure, including reclosure, within one year after the rule is finalized. The EPA has indicated it intends to finalize the legacy surface impoundment rule by spring 2024.

The EPA includes lists of potential legacy surface impoundments and CCR management units in the rulemaking docket and those lists include several BHE facilities. The EPA also specifically identifies PacifiCorp's Huntington Power Plant and NV Energy's Reid Gardner Generating Station as potential CCR management unit damage cases based on the EPA's review of compliance information. BHE corrected the record in comments that: (1) The north and south ash ponds at MidAmerican's Riverside Generating Station are incorrectly classified as legacy impoundments rather than CCR management units; (2) historical impoundments, which were closed according to state requirements and no longer contain CCR or liquids, should be removed from the list of CCR management units; (3) the EPA erroneously identified NV Energy's Reid Gardner Generating Station and the Old Landfill at PacifiCorp's Huntington generating facility as potential damage cases; and (4) two impoundments at PacifiCorp's former Carbon generating facility are incorrectly included on the list of legacy impoundments because PacifiCorp never managed or disposed of CCR materials in wastewater ponds at the former Carbon generating facility.

Until the proposals are finalized and fully litigated, the Registrants cannot determine whether additional action may be required.

54

In August 2020, the EPA finalized its Holistic Approach to Closure: Part A rule ("Part A rule"). This proposal addressed the D.C. Circuit's revocation of the provisions that allow unlined impoundments to continue receiving ash. The Part A rule established a new deadline of April 11, 2021, by which all unlined surface impoundments must initiate closure. The Part A rule also identifies two extensions to that date: (1) a site-specific extension to develop alternate disposal capacity and initiate closure by October 15, 2023; and (2) a site-specific extension for facilities that agree to shut down the coal-fueled unit and complete ash pond closure activities by October 17, 2028. PacifiCorp developed a demonstration for the development of alternative capacity for the Jim Bridger facility's FGD Pond 2 and a demonstration for closure of the Naughton facility and ash pond and submitted them to the EPA in November 2020. On January 11, 2022, the EPA deemed these submittals complete but has not taken additional action on them. No other Registrants used the provisions of the Part A rule.

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

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, 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, 2022. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2022.

55

PacifiCorp and its subsidiaries

Consolidated Financial Section

56

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PacifiCorp

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of June 30, 2023, the related consolidated statements of operations, and changes in shareholders' equity for the three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for the six-month periods ended June 30, 2023 and 2022, 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, 2022, 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 24, 2023, 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, 2022, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Portland, Oregon

August 4, 2023

57

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	586	$	641
Trade receivables, net	736		825
Other receivables, net	63		72
Inventories	533		474
Derivative contracts	51		184
Regulatory assets	374		275
Other current assets	112		213
Total current assets	2,455		2,684
Property, plant and equipment, net	25,488		24,430
Regulatory assets	1,745		1,605
Other assets	864		686
Total assets	$	30,552	$	29,405

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

58

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	June 30,		December 31,
	2023		2022
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	1,036	$	1,049
Accrued interest	145		128
Accrued property, income and other taxes	161		67
Accrued employee expenses	101		86
Current portion of long-term debt	565		449
Regulatory liabilities	99		96
Other current liabilities	335		271
Total current liabilities	2,442		2,146
Long-term debt	9,984		9,217
Regulatory liabilities	2,587		2,843
Deferred income taxes	3,136		3,152
Other long-term liabilities	1,976		1,306
Total liabilities	20,125		18,664
Commitments and contingencies (Note 9)
Shareholders' equity:
Preferred stock	2		2
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding	—		—
Additional paid-in capital	4,479		4,479
Retained earnings	5,955		6,269
Accumulated other comprehensive loss, net	(9)		(9)
Total shareholders' equity	10,427		10,741
Total liabilities and shareholders' equity	$	30,552	$	29,405

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

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Operating revenue	$	1,327	$	1,314	$	2,811	$	2,611
Operating expenses:
Cost of fuel and energy	462		451		1,076		916
Operations and maintenance	403		375		1,108		652
Depreciation and amortization	279		279		558		559
Property and other taxes	52		51		105		110
Total operating expenses	1,196		1,156		2,847		2,237
Operating income (loss)	131		158		(36)		374
Other income (expense):
Interest expense	(134)		(107)		(258)		(213)
Allowance for borrowed funds	16		6		29		12
Allowance for equity funds	34		15		61		28
Interest and dividend income	26		7		45		14
Other, net	3		(5)		5		(9)
Total other income (expense)	(55)		(84)		(118)		(168)
Income (loss) before income tax expense (benefit)	76		74		(154)		206
Income tax expense (benefit)	(30)		(8)		(140)		(6)
Net income (loss)	$	106	$	82	$	(14)	$	212

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

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)

(Amounts in millions)

									Accumulated
					Additional				Other		Total
	Preferred		Common		Paid-in		Retained		Comprehensive		Shareholders'
	Stock		Stock		Capital		Earnings		Loss, Net		Equity
Balance, March 31, 2022	$	2	$	—	$	4,479	$	5,579	$	(16)	$	10,044
Net income	—		—		—		82		—		82
Common stock dividends declared	—		—		—		(100)		—		(100)
Balance, June 30, 2022	$	2	$	—	$	4,479	$	5,561	$	(16)	$	10,026
Balance, December 31, 2021	$	2	$	—	$	4,479	$	5,449	$	(17)	$	9,913
Net income	—		—		—		212		—		212
Other comprehensive income	—		—		—		—		1		1
Common stock dividends declared	—		—		—		(100)		—		(100)
Balance, June 30, 2022	$	2	$	—	$	4,479	$	5,561	$	(16)	$	10,026
Balance, March 31, 2023	$	2	$	—	$	4,479	$	5,849	$	(9)	$	10,321
Net income	—		—		—		106		—		106
Balance, June 30, 2023	$	2	$	—	$	4,479	$	5,955	$	(9)	$	10,427
Balance, December 31, 2022	$	2	$	—	$	4,479	$	6,269	$	(9)	$	10,741
Net loss	—		—		—		(14)		—		(14)
Common stock dividends declared	—		—		—		(300)		—		(300)
Balance, June 30, 2023	$	2	$	—	$	4,479	$	5,955	$	(9)	$	10,427

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

61

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2023		2022
Cash flows from operating activities:
Net (loss) income	$	(14)	$	212
Adjustments to reconcile net (loss) income to net cash flows from operating activities:
Depreciation and amortization	558		559
Allowance for equity funds	(61)		(28)
Net power cost deferrals	(255)		(62)
Amortization of net power cost deferrals	71		27
Other changes in regulatory assets and liabilities	(54)		(41)
Deferred income taxes and amortization of investment tax credits	(68)		29
Other, net	(2)		12
Changes in other operating assets and liabilities:
Trade receivables, other receivables and other assets	113		17
Inventories	(59)		(16)
Derivative collateral, net	(90)		69
Accrued property, income and other taxes, net	161		152
Accounts payable and other liabilities	216		219
Wildfires insurance receivable	(133)		(161)
Wildfires liability	524		225
Net cash flows from operating activities	907		1,213
Cash flows from investing activities:
Capital expenditures	(1,529)		(894)
Other, net	—		6
Net cash flows from investing activities	(1,529)		(888)
Cash flows from financing activities:
Proceeds from long-term debt	1,189		—
Repayments of long-term debt	(309)		(9)
Dividends paid	(300)		(100)
Other, net	(3)		(2)
Net cash flows from financing activities	577		(111)
Net change in cash and cash equivalents and restricted cash and cash equivalents	(45)		214
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	674		186
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	629	$	400

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

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PACIFICORP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    General

PacifiCorp, which includes PacifiCorp and its subsidiaries, is a 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 June 30, 2023, and for the three- and six-month periods ended June 30, 2023 and 2022. The Consolidated Statements of Comprehensive Income (Loss) have been omitted as net income (loss) materially equals comprehensive income (loss) for the three- and six-month periods ended June 30, 2023 and 2022. The results of operations for the three- and six-month periods ended June 30, 2023, 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, 2022, 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 accounting policies or its assumptions regarding significant accounting estimates during the six-month period ended June 30, 2023, other than the updates associated with PacifiCorp's estimates of loss contingencies related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") and the 2022 McKinney fire as discussed in Note 9.

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

Cash equivalents consist of funds invested in money market mutual funds, 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, nuclear decommissioning and custodial funds. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):

	As of
	June 30,		December 31,
	2023		2022
Cash and cash equivalents	$	586	$	641
Restricted cash and cash equivalents included in other current assets	9		7
Restricted cash included in other assets	34		26
Total cash and cash equivalents and restricted cash and cash equivalents	$	629	$	674

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(3)    Property, Plant and Equipment, Net

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

		As of
		June 30,		December 31,
	Depreciable Life	2023		2022
Utility plant:
Generation	15 - 59 years	$	13,766	$	13,726
Transmission	60 - 90 years	8,096		8,051
Distribution	20 - 75 years	8,689		8,477
Intangible plant(1) and other	5 - 75 years	2,783		2,755
Utility plant in-service		33,334		33,009
Accumulated depreciation and amortization		(11,446)		(11,093)
Utility plant in-service, net		21,888		21,916
Nonregulated, net of accumulated depreciation and amortization	14 - 95 years	18		18
		21,906		21,934
Construction work-in-progress		3,582		2,496
Property, plant and equipment, net		$	25,488	$	24,430

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

(4)    Recent Financing Transactions

Long-Term Debt

In May 2023, PacifiCorp issued $1.2 billion of its 5.50% First Mortgage Bonds due May 2054. PacifiCorp intends, within 24 months of the issuance date, to allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing investments or expenditures made in one or more eligible projects in alignment with BHE's Green Financing Framework.

Credit Facilities

In June 2023, PacifiCorp amended its existing $1.2 billion unsecured credit facility expiring in June 2025. The amendment increased the lender commitment to $2.0 billion and extended the expiration date to June 2026. Additionally, in June 2023, PacifiCorp terminated its existing $800 million 364-day unsecured credit facility expiring in January 2024.

Common Shareholders' Equity

In January 2023, PacifiCorp declared a common stock dividend of $300 million, paid in February 2023, to PPW Holdings LLC.

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(5)    Income Taxes

The effective income tax rate for the six-month period ended June 30, 2023 of 91% results from a $140 million income tax benefit associated with a $154 million pre-tax loss primarily resulting from the $408 million pre-tax loss associated with the 2020 Wildfires described in Note 9. The $140 million income tax benefit is primarily comprised of a $32 million benefit (21%) from the application of the federal statutory income tax rate to the pre-tax loss, a $55 million benefit (36%) from federal income tax credits and a $34 million benefit (22%) from effects of ratemaking.

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Federal statutory income tax rate	21	%	21	%	21	%	21	%
State income tax, net of federal income tax benefit	2		4		4		3
Federal income tax credits	(34)		(25)		36		(21)
Effects of ratemaking(1)	(26)		(13)		22		(11)
Valuation allowance	—		—		7		4
Other	(2)		2		1		1
Effective income tax rate	(39)	%	(11)	%	91	%	(3)	%

(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") from 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 recognized for the three-month periods ended June 30, 2023 and 2022, totaled $26 million and $18 million, respectively. PTCs recognized for the six-month periods ended June 30, 2023 and 2022, totaled $55 million and $44 million, respectively.

For the six-month period ended June 30, 2023, PacifiCorp released an $11 million valuation allowance related to state net operating loss carryforwards. For the six-month period ended June 30, 2022, PacifiCorp recorded an $8 million valuation allowance related to state net operating loss carryforwards.

Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for federal and state income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. For the six-month periods ended June 30, 2023 and 2022, PacifiCorp received net cash payments for federal and state income tax from BHE totaling $205 million and $150 million, respectively. As of June 30, 2023, net income taxes payable to BHE were $55 million. As of December 31, 2022, net income taxes receivable from BHE were $84 million.

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(6)    Employee Benefit Plans

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Pension:
Interest cost	$	9	$	7	$	19	$	14
Expected return on plan assets	(12)		(11)		(24)		(21)
Net amortization	3		4		6		8
Net periodic benefit cost	$	—	$	—	$	1	$	1
Other postretirement:
Service cost	$	1	$	1	$	1	$	1
Interest cost	2		2		5		4
Expected return on plan assets	(4)		(3)		(7)		(5)
Net amortization	—		—		(1)		—
Net periodic benefit credit	$	(1)	$	—	$	(2)	$	—

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in other, net on the Consolidated Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $— million, respectively, during 2023. As of June 30, 2023, $2 million of contributions had been made to the pension plans.

(7)    Risk Management and Hedging Activities

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

PacifiCorp has established a risk management process that is designed to identify, 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. Refer to Note 8 for additional information on derivative contracts.

66

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):

	Derivative
	Contracts -				Other		Other
	Current		Other		Current		Long-term
	Assets		Assets		Liabilities		Liabilities		Total
As of June 30, 2023
Not designated as hedging contracts(1):
Commodity assets	$	57	$	—	$	6	$	5	$	68
Commodity liabilities	(6)		—		(36)		(17)		(59)
Total	51		—		(30)		(12)		9
Total derivatives	51		—		(30)		(12)		9
Cash collateral receivable (payable)	—		—		—		—		—
Total derivatives - net basis	$	51	$	—	$	(30)	$	(12)	$	9
As of December 31, 2022
Not designated as hedging contracts(1):
Commodity assets	$	279	$	27	$	9	$	3	$	318
Commodity liabilities	(22)		(7)		(14)		(5)		(48)
Total	257		20		(5)		(2)		270
Total derivatives	257		20		(5)		(2)		270
Cash collateral payable(2)	(73)		(5)		—		—		(78)
Total derivatives - net basis	$	184	$	15	$	(5)	$	(2)	$	192

(1)PacifiCorp's commodity derivatives are generally included in rates. As of June 30, 2023, a regulatory liability of $9 million was recorded related to the net derivative asset of $9 million. As of December 31, 2022, a regulatory liability of $270 million was recorded related to the net derivative asset of $270 million.

(2)As of December 31, 2022, PacifiCorp had an additional $12 million cash collateral payable that was not required to be netted against total derivatives.

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Beginning balance	$	(109)	$	(195)	$	(270)	$	(53)
Changes in fair value recognized in regulatory (liabilities) assets	102		(49)		92		(217)
Net losses reclassified to operating revenue	(2)		(8)		(8)		(11)
Net gains reclassified to energy costs	—		29		177		58
Ending balance	$	(9)	$	(223)	$	(9)	$	(223)

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Derivative Contract Volumes

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

	Unit of	June 30,	December 31,
	Measure	2023	2022
Electricity purchases, net	Megawatt hours	2	2
Natural gas purchases	Decatherms	145	127

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 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"). These agreements and other agreements that do not refer to specified rating-dependent threshold levels may provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of June 30, 2023, PacifiCorp's issuer 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 $58 million and $48 million as of June 30, 2023 and December 31, 2022, respectively, for which PacifiCorp had posted collateral of $— million, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of June 30, 2023 and December 31, 2022, PacifiCorp would have been required to post $35 million and $3 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.

(8)    Fair Value Measurements

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

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

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

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

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

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of June 30, 2023:
Assets:
Commodity derivatives	$	—	$	68	$	—	$	(17)	$	51
Money market mutual funds	598		—		—		—		598
Investment funds	29		—		—		—		29
	$	627	$	68	$	—	$	(17)	$	678
Liabilities - Commodity derivatives	$	—	$	(59)	$	—	$	17	$	(42)
As of December 31, 2022:
Assets:
Commodity derivatives	$	—	$	318	$	—	$	(119)	$	199
Money market mutual funds	649		—		—		—		649
Investment funds	23		—		—		—		23
	$	672	$	318	$	—	$	(119)	$	871
Liabilities - Commodity derivatives	$	—	$	(48)	$	—	$	41	$	(7)

(1)Represents netting under master netting arrangements and a net cash collateral of $— million and a net cash collateral payable of $78 million as of June 30, 2023 and December 31, 2022, respectively. As of December 31, 2022, PacifiCorp had an additional $12 million cash collateral payable that was not required to be netted against total derivatives.

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. A discounted cash flow valuation method was used to estimate fair value. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. Refer to Note 7 for further discussion regarding PacifiCorp's risk management and hedging activities.

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

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

	As of June 30, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	10,549	$	9,406	$	9,666	$	9,045

(9)    Commitments and Contingencies

Commitments

PacifiCorp has the following firm commitments that are not reflected on the Consolidated Balance Sheets.

Construction Commitments

During the six-month period ended June 30, 2023, PacifiCorp entered into build transfer agreements totaling $1.2 billion through 2025 for the construction of certain wind-powered generating facilities in Wyoming.

Fuel Contracts

During the six-month period ended June 30, 2023, PacifiCorp entered into certain coal supply agreements totaling $425 million through 2025.

Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal, wildfire prevention and mitigation and other environmental matters that have the potential to impact its current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.

Lower Klamath Hydroelectric Project

In November 2022, the Federal Energy Regulatory Commission ("FERC") issued a license surrender order for the Lower Klamath Project, which was accepted by the Klamath River Renewal Corporation ("KRRC") and the states of Oregon and California ("States") in December 2022, along with the transfer of the Lower Klamath Project dams. Although PacifiCorp no longer owns the Lower Klamath Project, PacifiCorp will continue to operate the facilities under an operation and maintenance agreement with the KRRC until each facility is ready for removal. Removal of the Copco No. 2 facility began in June 2023, and removal of the remaining three dams (J.C. Boyle, Copco No. 1 and Iron Gate) is anticipated to begin in 2024. The KRRC has $450 million in funding available for dam removal and restoration; $200 million collected from PacifiCorp's Oregon and California customers and $250 million in California bond funds. PacifiCorp and the States have also agreed to equally share cost overruns that may occur above the initial $450 million in funding. Specifically, PacifiCorp and the States have agreed to equally fund an initial $45 million contingency fund and equally share any additional costs above that amount to ensure dam removal and restoration is complete.

Legal Matters

PacifiCorp is party to a variety of legal actions, including litigation, arising out of the normal course of business, some of which assert claims for damages in substantial amounts and are described below. For certain legal actions, parties at times may seek to impose fines, penalties and other costs.

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Wildfires Overview

A provision for a loss contingency is recorded when it is probable a liability has been incurred and the amount of loss can be reasonably estimated. PacifiCorp evaluates the related range of reasonably estimated losses and records a loss based on its best estimate within that range or the lower end of the range if there is no better estimate.

In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages from wildfires 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 be found liable for all damages.

2020 Wildfires

In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, which resulted in real and personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon, burning over 500,000 acres in aggregate. Third-party reports for these wildfires indicate over 2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities.

Investigations into the cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the U.S. Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.

As of the date of this filing, numerous lawsuits on behalf of plaintiffs related to the 2020 Wildfires have been filed in Oregon and California, including a class action complaint in Oregon for which the jury issued a verdict for the 17 named plaintiffs in June 2023 as described below. The plaintiffs seek damages for economic losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees. Several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. Additionally, certain governmental agencies have informed PacifiCorp that they are contemplating filing actions in connection with certain of the Oregon 2020 Wildfires. Amounts sought in the lawsuits, complaints and demands filed in Oregon total over $7 billion, excluding any doubling or trebling of damages included in the complaints. Generally, the complaints filed in California do not specify damages sought and are not included in this amount. Final determinations of liability will only be made following the completion of comprehensive investigations, litigation or similar processes, the outcome of which, if adverse, could, in the aggregate, have a material adverse effect on PacifiCorp's financial condition.

On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al, in Multnomah County Circuit Court, Oregon (the "James case"). 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. In November 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Santiam Canyon, Echo Mountain Complex, South Obenchain and Two Four Two wildfires. In May 2022, the Multnomah County Circuit Court granted issue class certification and consolidated the James case with several other cases. While PacifiCorp requested an immediate appeal of the issue class certification, the Oregon Court of Appeals denied the request. In April 2023, the jury trial for the James case with respect to 17 named plaintiffs began in Multnomah County Circuit Court. In June 2023, the jury issued its verdict finding PacifiCorp liable to the 17 individual plaintiffs and to the class with respect to the four wildfires. The jury awarded the 17 named plaintiffs $90 million of damages, including $4 million of economic and property damages, $68 million of noneconomic damages and $18 million of punitive damages based on a 0.25 multiplier of the economic and noneconomic damages. No judgment has been entered by the Multnomah County Circuit Court and no determination has been made as to the timing, process and procedures that will be used to adjudicate individual class member damages. PacifiCorp intends to vigorously appeal the jury's findings and damage awards, including whether the case can proceed as a class action. The appeals process and further actions could take several years.

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Based on the facts and circumstances available to PacifiCorp as of the date of this filing, which includes the status of the verdict in the James case with respect to the 17 named plaintiffs, other litigation and recent settlements, PacifiCorp has accrued cumulative estimated probable losses associated with the 2020 Wildfires of $1,018 million through June 30, 2023. PacifiCorp's cumulative accrual includes estimates of probable losses for fire suppression costs, real and personal property damages, natural resource damages for certain areas and noneconomic damages such as personal injury damages and loss of life damages that are considered probable of being incurred and that it is reasonably able to estimate at this time. For certain aspects of the 2020 Wildfires for which loss is considered probable, information necessary to reasonably estimate the potential losses, such as those related to certain areas of natural resource damages, is not currently available.

It is reasonably possible PacifiCorp will incur material additional losses beyond the amounts accrued that could have a material adverse effect on PacifiCorp's financial condition; however, PacifiCorp is currently unable to reasonably estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved, including claimants in the class to the James case, the variation in those types of properties and lack of available details and the ultimate outcome of legal actions.

The following table presents changes in PacifiCorp's liability for estimated losses associated with the 2020 Wildfires (in millions):

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Beginning balance	$	824	$	252	$	424	$	252
Accrued losses	141		225		541		225
Payments	(17)		—		(17)		—
Ending balance	$	948	$	477	$	948	$	477

PacifiCorp's receivable for expected insurance recoveries associated with the probable losses was $379 million and $246 million, respectively, as of June 30, 2023 and December 31, 2022. During the three- and six-month periods ended June 30, 2023, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $49 million and $408 million, respectively. During the three- and six-month periods ended June 30, 2022, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $64 million and $64 million, respectively. The net losses are included in operations and maintenance on the Consolidated Statements of Operations. No additional insurance recoveries beyond those accrued to date are expected to be available for the 2020 Wildfires.

2022 McKinney Fire

According to the California Department of Forestry and Fire Protection, on July 29, 2022, a wildfire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California (the "2022 McKinney Fire") located in PacifiCorp's service territory. Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged, 185 structures destroyed, 12 injuries and four fatalities and consumed 60,000 acres. The cause of the 2022 McKinney Fire is undetermined and remains under investigation by the U.S. Forest Service.

Due to the preliminary nature of the investigation, PacifiCorp does not believe a loss is probable and therefore has not accrued any loss as of the date of this filing. While the loss is not probable, PacifiCorp estimates the potential loss, excluding losses for natural resource damages, to be $31 million, net of expected insurance recoveries. The loss estimate includes PacifiCorp's estimate of losses for fire suppression costs; real and personal property damages; and noneconomic damages such as personal injury damages and loss of life damages. PacifiCorp is unable to estimate the total potential loss, including losses for natural resource damages, because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PacifiCorp. PacifiCorp has insurance available and estimates the potential insurance recoveries to be $103 million, to cover potential losses.

As of the date of this filing, multiple lawsuits have been filed in California on behalf of plaintiffs related to the 2022 McKinney Fire. The plaintiffs seek damages for economic losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees, but the amount of damages sought is not specified. Final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.

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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)    Revenue from Contracts with Customers

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Customer Revenue:
Retail:
Residential	$	450	$	417	$	1,035	$	922
Commercial	429		393		859		763
Industrial	270		277		560		550
Other retail	83		80		127		117
Total retail	1,232		1,167		2,581		2,352
Wholesale	26		55		87		110
Transmission	34		45		72		77
Other Customer Revenue	24		28		56		48
Total Customer Revenue	1,316		1,295		2,796		2,587
Other revenue	11		19		15		24
Total operating revenue	$	1,327	$	1,314	$	2,811	$	2,611

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

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

Results of Operations for the Second Quarter and First Six Months of 2023 and 2022

Overview

Net income for the second quarter of 2023 was $106 million, an increase of $24 million compared to 2022 net income of $82 million. The increase in net income was primarily due to lower other expense and higher income tax benefit, partially offset by increased operations and maintenance expense primarily driven by higher wildfire mitigation costs and legal fees. Utility margin was relatively flat at $2 million favorable primarily due to higher retail prices, lower coal-fueled generation volumes, higher net power costs deferrals and lower natural gas-fueled generation prices, partially offset by higher purchased electricity costs from higher volumes and prices, lower wholesale volumes, higher coal-fueled generation prices, lower retail volumes, lower wheeling revenue and higher natural gas-fueled generation volumes. Retail customer volumes decreased 2.2%, primarily due to lower customer usage, partially offset by an increase in the average number of customers. Energy generated decreased 22% for the second quarter of 2023 compared to 2022 primarily due to lower coal-fueled and wind-powered generation volumes, partially offset by higher natural gas-fueled and hydroelectric generation volumes. Wholesale electricity sales volumes decreased 52% and purchased electricity volumes increased 45%.

Net loss for the first six months of 2023 was $14 million, a decrease of $226 million compared to 2022 net income of $212 million. The decrease in net income was primarily due to increased operations and maintenance expense largely due to an increase to estimated losses associated with the 2020 Wildfires, net of expected insurance recoveries, partially offset by higher income tax benefit, lower other expense and higher utility margin. Utility margin increased primarily due to higher retail prices and volumes, higher net power cost deferrals, lower coal-fueled generation volumes and higher average wholesale market prices, partially offset by higher purchased electricity costs from higher volumes and prices, higher natural gas-fueled generation costs from higher prices and volumes, lower wholesale volumes and higher coal-fueled generation prices. Retail customer volumes increased 0.6%, primarily due to favorable impacts of weather, higher commercial and residential customer usage and an increase in the average number of customers, partially offset by lower industrial and irrigation customer usage. Energy generated decreased 14% for the first six months of 2023 compared to 2022 primarily due to lower coal-fueled, wind-powered and hydroelectric generation volumes, partially offset by higher natural gas-fueled volumes. Wholesale electricity sales volumes decreased 49% and purchased electricity volumes increased 37%.

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.

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

	Second Quarter								First Six Months
	2023		2022		Change				2023		2022		Change
Utility margin:
Operating revenue	$	1,327	$	1,314	$	13	1	%	$	2,811	$	2,611	$	200	8	%
Cost of fuel and energy	462		451		11		2		1,076		916		160		17
Utility margin	865		863		2		—		1,735		1,695		40		2
Operations and maintenance	403		375		28		7		1,108		652		456		70
Depreciation and amortization	279		279		—		—		558		559		(1)		—
Property and other taxes	52		51		1		2		105		110		(5)		(5)
Operating income (loss)	$	131	$	158	$	(27)	(17)	%	$	(36)	$	374	$	(410)	(110)	%

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Utility Margin

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

	Second Quarter								First Six Months
	2023		2022		Change				2023		2022		Change
Utility margin (in millions):
Operating revenue	$	1,327	$	1,314	$	13	1	%	$	2,811	$	2,611	$	200	8	%
Cost of fuel and energy	462		451		11		2		1,076		916		160		17
Utility margin	$	865	$	863	$	2	—	%	$	1,735	$	1,695	$	40	2	%
Sales (GWhs):
Residential	3,809		3,854		(45)		(1)	%	8,911		8,618		293		3	%
Commercial	4,794		4,633		161		3		9,777		9,183		594		6
Industrial, irrigation and other	4,444		4,849		(405)		(8)		8,653		9,372		(719)		(8)
Total retail	13,047		13,336		(289)		(2)		27,341		27,173		168		1
Wholesale	601		1,245		(644)		(52)		1,426		2,798		(1,372)		(49)
Total sales	13,648		14,581		(933)		(6)	%	28,767		29,971		(1,204)		(4)	%
Average number of retail customers  (in thousands)	2,065		2,033		32		2	%	2,061		2,029		32		2	%
Average revenue per MWh:
Retail	$	94.61	$	88.14	$	6.47	7	%	$	94.20	$	86.77	$	7.43	9	%
Wholesale	$	55.81	$	51.53	$	4.28	8	%	$	73.54	$	44.64	$	28.90	65	%
Heating degree days	1,314		1,736		(422)		(24)	%	6,519		6,481		38		1	%
Cooling degree days	456		406		50		12	%	456		411		45		11	%
Sources of energy (GWhs)(1):
Coal	3,594		6,260		(2,666)		(43)	%	9,149		13,171		(4,022)		(31)	%
Natural gas	3,108		2,747		361		13		7,063		5,862		1,201		20
Wind(2)	1,445		1,817		(372)		(20)		3,528		4,209		(681)		(16)
Hydroelectric and other(2)	1,111		1,033		78		8		1,923		2,017		(94)		(5)
Total energy generated	9,258		11,857		(2,599)		(22)		21,663		25,259		(3,596)		(14)
Energy purchased	5,382		3,717		1,665		45		9,510		6,940		2,570		37
Total	14,640		15,574		(934)		(6)	%	31,173		32,199		(1,026)		(3)	%
Average cost of energy per MWh:
Energy generated(3)	$	21.20	$	21.90	$	(0.70)	(3)	%	$	25.29	$	20.27	$	5.02	25	%
Energy purchased	$	57.49	$	48.92	$	8.57	18	%	$	66.27	$	51.97	$	14.30	28	%

(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 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.

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Quarter Ended June 30, 2023 compared to Quarter Ended June 30, 2022

Utility margin increased $2 million for the second quarter of 2023 compared to 2022 primarily due to:

•$59 million increase in retail revenue due to higher average prices, partially offset by lower volumes. Retail customer volumes decreased 2.2%, primarily due to unfavorable industrial customer usage across all states, except California, unfavorable irrigation customer usage across all states, unfavorable Oregon residential customer usage and unfavorable Utah residential weather related impacts, partially offset by favorable Oregon, Utah and Wyoming commercial customer usage, favorable increase in the average number of residential and commercial customers across all states, except California, and favorable Oregon and Washington weather related impacts;

•$51 million of higher deferred net power costs net of amortization of previous deferrals in accordance with established adjustment mechanisms;

•$35 million of lower natural gas-fueled generation costs primarily due to lower average market prices, partially offset by higher volumes; and

•$31 million of lower coal-fueled generation costs primarily due to lower volumes, partially offset by higher average prices.

The increases above were partially offset by:

•$128 million of higher purchased electricity costs from higher volumes and higher average market prices;

•$31 million decrease in wholesale revenue primarily due to lower volumes, partially offset by higher average market prices; and

•$14 million of lower other revenue primarily due to lower wheeling revenue and lower revenues associated with sales of greenhouse gas allowances.

Operations and maintenance increased $28 million, or 7% for the second quarter of 2023 compared to 2022 primarily due to $16 million of higher wildfire mitigation costs, including vegetation management and amortization of amounts previously deferred in Oregon, $12 million of higher legal fees primarily related to wildfire matters, $7 million of higher demand-side management amortization expense (offset in retail revenue), $6 million of increased bad debt expense and $4 million of higher insurance costs related to wildfire coverage, partially offset by $15 million of lower current year accruals associated with the 2020 Wildfires, net of expected insurance recoveries, and lower plant operations and maintenance costs.

Interest expense increased $27 million, or 25%, for the second quarter of 2023 compared to 2022 primarily due to higher average long-term debt balances.

Allowance for borrowed and equity funds increased $29 million for the second quarter of 2023 compared to 2022 primarily due to higher qualified construction work-in-progress balances.

Interest and dividend income increased $19 million for the second quarter of 2023 compared to 2022 primarily due to the recording of interest on higher deferred net power cost balances and higher investment income due to higher average interest rates on temporary cash investment balances.

Other, net increased $8 million for the second quarter of 2023 compared to 2022 primarily due to higher cash surrender values of Supplemental Executive Retirement Plan life insurance policies driven by market increases and a favorable change in deferred compensation and long-term incentive plan primarily due to market movements (offset in operations and maintenance expense).

Income tax benefit increased $22 million for the second quarter of 2023 compared to 2022 and the effective tax rate was (39)% for 2023 and (11)% for 2022. The effective tax rate decreased primarily as a result of increased PTCs from PacifiCorp's wind-powered generating facilities and a higher benefit from effects of ratemaking.

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First Six Months of 2023 compared to First Six Months of 2022

Utility margin increased $40 million, or 2%, for the first six months of 2023 compared to 2022 primarily due to:

•$218 million increase in retail revenue due to higher average prices and volumes. Retail customer volumes increased 0.6%, primarily due to favorable Utah and Oregon commercial customer usage, favorable weather related impacts across the western states, favorable changes in the average number of residential and commercial customers across the service territory, mainly in Utah and Oregon, and favorable Utah residential customer usage, partially offset by unfavorable industrial customer usage across all states, unfavorable irrigation customer usage across all states and unfavorable Oregon residential customer usage;

•$149 million higher deferred net power costs net of amortization of previous deferrals in accordance with established adjustment mechanisms; and

•$40 million of lower coal-fueled generation costs due to lower volumes, partially offset by higher average prices.

The increases above were partially offset by:

•$270 million of higher purchased electricity costs from higher volumes and higher average market prices;

•$74 million of higher natural gas-fueled generation costs due to higher average market prices and higher volumes; and

•$20 million decrease in wholesale revenue primarily due to lower volumes, partially offset by higher average market prices.

Operations and maintenance increased $456 million, or 70%, for the first six months of 2023 compared to 2022 primarily due to a $344 million increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires, $37 million of higher wildfire mitigation costs, including vegetation management and amortization of amounts previously deferred in Oregon, $16 million of higher legal fees primarily related to wildfire matters, $16 million of higher plant operations and maintenance costs, $15 million of higher demand-side management amortization expense (offset in retail revenue), $10 million of higher labor and benefit expenses, $6 million of increased bad debt expense and $6 million of higher insurance costs related to wildfire coverage.

Property and other taxes decreased $5 million, or 5%, for the first six months of 2023 compared to 2022 primarily due to lower property tax rates in Utah.

Interest expense increased $45 million, or 21%, for the first six months of 2023 compared to 2022 primarily due to higher average long-term debt balances.

Allowance for borrowed and equity funds increased $50 million for the first six months of 2023 compared to 2022 primarily due to higher qualified construction work-in-progress balances.

Interest and dividend income increased $31 million for the first six months of 2023 compared to 2022 primarily due to the recording of interest on higher deferred net power cost balances and higher investment income due to higher average interest rates on temporary cash investment balances.

Other, net increased $14 million for the first six months of 2023 compared to 2022 primarily due to higher cash surrender values of Supplemental Executive Retirement Plan life insurance policies driven by market increases and a favorable change in deferred compensation and long-term incentive plan primarily due to market movements (offset in operations and maintenance expense).

Income tax benefit increased $134 million for the first six months of 2023 compared to 2022 and the effective tax rate was 91% for 2023 and (3)% for 2022. The $134 million increase is primarily due to the increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires, higher PTCs from PacifiCorp's wind-powered generating facilities, higher benefit from effects of ratemaking and the release of a valuation allowance on state net operating loss carryforwards in 2023 compared to the establishment of a state valuation allowance in 2022.

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Liquidity and Capital Resources

As of June 30, 2023, PacifiCorp's total net liquidity was as follows (in millions):

Cash and cash equivalents	$	586
Credit facilities	2,000
Less:
Tax-exempt bond support and letters of credit	(249)
Net credit facilities	1,751
Total net liquidity	$	2,337
Credit facilities:
Maturity dates	2026

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022, were $907 million and $1,213 million, respectively. The decrease is primarily due to higher wholesale and fuel purchases and collateral returned to counterparties, partially offset by higher collections from retail customers.

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

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2023 and 2022, were $(1,529) million and $(888) million, respectively. The change is primarily due to an increase in capital expenditures of $635 million. Refer to "Future Uses of Cash" for discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2023, were $577 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $1.2 billion. Uses of cash consisted primarily of $309 million for the repayment of long-term debt and $300 million for common stock dividends paid to PPW Holdings LLC.

Net cash flows from financing activities for the six-month period ended June 30, 2022, were $(111) million. Uses of cash consisted primarily of $100 million for common stock dividends paid to PPW Holdings LLC and $9 million for the repayment of long-term debt.

Short-term Debt

Regulatory authorities limit PacifiCorp to $2.0 billion of short-term debt. As of June 30, 2023 and December 31, 2022, PacifiCorp had no short-term debt outstanding.

Debt Authorizations

PacifiCorp currently has regulatory authority from the OPUC and the Idaho Public Utilities Commission to issue an additional $3.8 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 Shareholders' Equity

In January 2023, PacifiCorp declared a common stock dividend of $300 million, paid in February 2023, to PPW Holdings LLC.

79

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 customer rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings, including regulatory filings for Certificates of Public Convenience and Necessity; outcomes of legal actions associated with the 2020 Wildfires; changes in income tax laws; general business conditions; new customer requests; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

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

	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2022		2023		2023
Wind generation	$	14	$	373	$	833
Electric distribution	296		421		889
Electric transmission	413		448		1,375
Solar generation	—		1		21
Electric battery and pumped hydro storage	3		2		6
Other	168		284		470
Total	$	894	$	1,529	$	3,594

PacifiCorp has included estimates for new renewable and carbon free generation resources, conversion of certain coal-fueled units to natural gas-fueled units, energy storage assets and associated transmission assets in its forecast capital expenditures based on its IRP. These estimates are likely to change as a result of the associated 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 new wind-powered generating facilities and construction at existing wind-powered generating facility sites acquired from third parties totaling $366 million and $11 million for the six-month periods ended June 30, 2023 and 2022, respectively. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $444 million for the remainder of 2023 and is primarily for the Rock Creek I and Rock Creek II projects to be constructed in Wyoming totaling 590 MWs that are expected to be placed in-service in 2024 and 2025.

•Electric distribution includes both growth projects and operating expenditures. Operating expenditures include spending on wildfire mitigation. Expenditures for wildfire mitigation totaled $96 million and $50 million for the six-month periods ended June 30, 2023 and 2022, respectively. Planned spending for wildfire mitigation totals $109 million for the remainder of 2023. The remaining investments primarily relate to expenditures for new connections and distribution operations.

•Electric transmission includes both growth projects and operating expenditures. Transmission growth investments primarily reflect costs associated with Energy Gateway Transmission segments that are expected to be placed in-service in 2024 through 2028. Expenditures for these projects totaled $313 million and $297 million for the six-month periods ended June 30, 2023 and 2022, respectively. Planned spending for these Energy Gateway Transmission segments totals $667 million for the remainder of 2023.

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•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $89 million and $77 million for the six-month periods ended June 30, 2023 and 2022, respectively. Planned information technology spending totals $119 million for the remainder of 2023. The 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. PacifiCorp files its IRP biennially with the state commissions in each of the six states where PacifiCorp operates. Five states indicate whether the IRP meets the state commission's IRP standards and guidelines, a process referred to as "acknowledgment" in some states. Acknowledgment by a state commission does not address cost recovery or prudency of resources ultimately selected.

In March 2023, PacifiCorp filed its 2023 IRP in Idaho, Oregon and Wyoming. The March 2023 filing was considered informational in Utah. A 60-day post-filing extended comment period was added to the 2023 IRP to provide opportunity for additional stakeholder feedback. Responsive to feedback from the extended comment period, PacifiCorp filed its 2023 IRP (Amended Final) report on May 31, 2023.

The 2023 IRP is off cycle with regard to Washington's four-year IRP cycle and has instead been filed in that state as the "Washington Two-Year Progress Report," aligned with the Clean Energy Transformation Act requirements.

Requests for Proposals

PacifiCorp issues individual RFPs to procure resources identified in the IRP or resources driven by customer demands and regulatory policy changes. 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's most recent RFP, the 2022 All-Source RFP, was issued to market in April 2022. In December 2022, PacifiCorp bid 12 eligible self-build (benchmark) resources and in March 2023, PacifiCorp received 302 bids from 74 developers and 93 different projects sites across six states. A final shortlist is expected by the end of 2023 with resources contracted through the first half of 2024. PacifiCorp may issue another or an expanded all-source RFP in connection with the 2023 IRP during the first half of 2024.

Material Cash Requirements

As of June 30, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2022, other than those disclosed in Note 9 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

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.

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Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal 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, pension and other postretirement benefits, income taxes, revenue recognition-unbilled revenue and wildfire loss contingencies. 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, 2022. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2022. Refer to Note 9 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for updates regarding the wildfire loss contingency estimates.

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MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company

Consolidated Financial Section

83

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

MidAmerican Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of June 30, 2023, the related statements of operations and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for the six-month periods ended June 30, 2023 and 2022, 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, 2022, 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 24, 2023, 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, 2022, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Des Moines, Iowa

August 4, 2023

84

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	454	$	258
Trade receivables, net	329		536
Income tax receivable	7		42
Inventories	320		277
Prepayments	107		91
Other current assets	30		66
Total current assets	1,247		1,270
Property, plant and equipment, net	21,145		21,091
Regulatory assets	603		550
Investments and restricted investments	980		902
Other assets	168		165
Total assets	$	24,143	$	23,978

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

85

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	June 30,		December 31,
	2023		2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	384	$	536
Accrued interest	83		85
Accrued property, income and other taxes	242		170
Current portion of long-term debt	253		317
Other current liabilities	133		93
Total current liabilities	1,095		1,201
Long-term debt	7,415		7,412
Regulatory liabilities	816		1,119
Deferred income taxes	3,503		3,433
Asset retirement obligations	782		683
Other long-term liabilities	508		485
Total liabilities	14,119		14,333
Commitments and contingencies (Note 9)
Shareholder's equity:
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding	—		—
Additional paid-in capital	561		561
Retained earnings	9,463		9,084
Total shareholder's equity	10,024		9,645
Total liabilities and shareholder's equity	$	24,143	$	23,978

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

86

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Operating revenue:
Regulated electric	$	661	$	725	$	1,252	$	1,333
Regulated natural gas and other	98		172		427		569
Total operating revenue	759		897		1,679		1,902
Operating expenses:
Cost of fuel and energy	113		174		228		299
Cost of natural gas purchased for resale and other	46		120		282		418
Operations and maintenance	216		200		421		392
Depreciation and amortization	226		277		460		527
Property and other taxes	40		36		82		76
Total operating expenses	641		807		1,473		1,712
Operating income	118		90		206		190
Other income (expense):
Interest expense	(81)		(78)		(161)		(156)
Allowance for borrowed funds	4		5		8		9
Allowance for equity funds	13		14		24		29
Other, net	15		(12)		31		(15)
Total other income (expense)	(49)		(71)		(98)		(133)
Income before income tax expense (benefit)	69		19		108		57
Income tax expense (benefit)	(167)		(188)		(370)		(394)
Net income	$	236	$	207	$	478	$	451

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

87

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions)

	Common Stock		Additional Paid-in Capital		Retained Earnings		Total Shareholder's Equity
Balance, March 31, 2022	$	—	$	561	$	8,643	$	9,204
Net income	—		—		207		207
Balance, June 30, 2022	$	—	$	561	$	8,850	$	9,411
Balance, December 31, 2021	$	—	$	561	$	8,399	$	8,960
Net income	—		—		451		451
Balance, June 30, 2022	$	—	$	561	$	8,850	$	9,411
Balance, March 31, 2023	$	—	$	561	$	9,227	$	9,788
Net income	—		—		236		236
Balance, June 30, 2023	$	—	$	561	$	9,463	$	10,024
Balance, December 31, 2022	$	—	$	561	$	9,084	$	9,645
Net income	—		—		478		478
Common stock dividend	—		—		(100)		(100)
Other equity transactions	—		—		1		1
Balance, June 30, 2023	$	—	$	561	$	9,463	$	10,024

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

88

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2023		2022
Cash flows from operating activities:
Net income	$	478	$	451
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	460		527
Amortization of utility plant to other operating expenses	16		19
Allowance for equity funds	(24)		(29)
Deferred income taxes and investment tax credits, net	46		58
Settlements of asset retirement obligations	(15)		(28)
Other, net	3		33
Changes in other operating assets and liabilities:
Trade receivables and other assets	203		2
Inventories	(43)		8
Accrued property, income and other taxes, net	107		94
Accounts payable and other liabilities	(106)		(10)
Net cash flows from operating activities	1,125		1,125
Cash flows from investing activities:
Capital expenditures	(763)		(862)
Purchases of marketable securities	(95)		(214)
Proceeds from sales of marketable securities	81		210
Other, net	10		6
Net cash flows from investing activities	(767)		(860)
Cash flows from financing activities:
Common stock dividend	(100)		—
Repayments of long-term debt	(65)		—
Other, net	(1)		(1)
Net cash flows from financing activities	(166)		(1)
Net change in cash and cash equivalents and restricted cash and cash equivalents	192		264
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	268		239
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	460	$	503

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

89

MIDAMERICAN ENERGY COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

(1)    General

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

The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of June 30, 2023, and for the three- and six-month periods ended June 30, 2023 and 2022. The results of operations for the six-month period ended June 30, 2023, 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, 2022, 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 accounting policies or its assumptions regarding significant accounting estimates during the six-month period ended June 30, 2023.

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

Cash equivalents consist of funds invested in money market mutual funds, 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 restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on the Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Balance Sheets (in millions):

	As of
	June 30,		December 31,
	2023		2022
Cash and cash equivalents	$	454	$	258
Restricted cash and cash equivalents in other current assets	6		10
Total cash and cash equivalents and restricted cash and cash equivalents	$	460	$	268

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(3)    Property, Plant and Equipment, Net

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

		As of
		June 30,		December 31,
	Depreciable Life	2023		2022
Utility plant:
Generation	20-62 years	$	18,360	$	18,582
Transmission	55-80 years	2,730		2,662
Electric distribution	15-80 years	5,072		4,931
Natural gas distribution	30-75 years	2,186		2,144
Utility plant in-service		28,348		28,319
Accumulated depreciation and amortization		(8,351)		(8,024)
Utility plant in-service, net		19,997		20,295
Nonregulated property, net of accumulated depreciation and amortization	20-50 years	6		6
		20,003		20,301
Construction work-in-progress		1,142		790
Property, plant and equipment, net		$	21,145	$	21,091

Under a revenue sharing arrangement in Iowa, MidAmerican Energy accrues throughout the year a regulatory liability based on the extent to which its anticipated annual equity return exceeds specified thresholds, with an equal amount recorded in depreciation and amortization expense. The annual regulatory liability accrual reduces utility plant upon final determination of the amount. For the six-month periods ended June 30, 2023 and 2022, $16 million and $96 million, respectively, is reflected in depreciation and amortization expense on the Statement of Operations.

(4)    Recent Financing Transactions

Credit Facilities

In June 2023, MidAmerican Energy amended its existing $1.5 billion unsecured credit facility expiring in June 2025. The amendment extended the expiration date to June 2026.

(5)    Income Taxes

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Income tax credits	(251)		(973)		(347)		(682)
State income tax, net of federal income tax impacts	(6)		(26)		(10)		(23)
Effects of ratemaking	(4)		(11)		(6)		(9)
Other, net	(2)		—		(1)		2
Effective income tax rate	(242)	%	(989)	%	(343)	%	(691)	%

91

Income tax credits relate primarily to production tax credits ("PTC") from MidAmerican Energy's wind- and solar-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind- and solar-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- and solar-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the six-month periods ended June 30, 2023 and 2022, totaled $375 million and $388 million, respectively.

Berkshire Hathaway includes BHE and subsidiaries in its 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. MidAmerican Energy received net cash payments for income tax from BHE totaling $520 million and $541 million for the six-month periods ended June 30, 2023 and 2022, respectively.

(6)    Employee Benefit Plans

MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering a majority of all employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. MidAmerican Energy also sponsors certain postretirement healthcare and life insurance benefits covering substantially all retired employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc.

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Pension:
Service cost	$	3	$	4	$	6	$	9
Interest cost	8		5		16		10
Expected return on plan assets	(8)		(7)		(16)		(14)
Settlement	—		—		(5)		2
Net amortization	—		1		—		1
Net periodic benefit cost (credit)	$	3	$	3	$	1	$	8
Other postretirement:
Service cost	$	1	$	2	$	2	$	4
Interest cost	3		2		6		4
Expected return on plan assets	(4)		(3)		(8)		(7)
Net amortization	—		(1)		—		(1)
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 Statements of Operations. Employer contributions to the pension and other postretirement benefit plans during 2023 are expected to be $7 million and $2 million, respectively. As of June 30, 2023, $4 million and $1 million of contributions had been made to the pension and other postretirement benefit plans, respectively.

92

(7)    Asset Retirement Obligations

MidAmerican Energy estimates its asset retirement obligation ("ARO") liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of expected work. During the six-month period ended June 30, 2023, MidAmerican Energy recorded an increase of $88 million for decommissioning its wind-generating facilities, which is a non-cash investing activity and is due to an updated decommissioning estimate reflecting changes in the projected removal costs per turbine.

(8)    Fair Value Measurements

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

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

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

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

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

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of June 30, 2023:
Assets:
Commodity derivatives	$	2	$	13	$	2	$	(8)	$	9
Money market mutual funds	460		—		—		—		460
Debt securities:
U.S. government obligations	233		—		—		—		233
International government obligations	—		1		—		—		1
Corporate obligations	—		72		—		—		72
Municipal obligations	—		3		—		—		3
Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:
U.S. companies	405		—		—		—		405
International companies	9		—		—		—		9
Investment funds	22		—		—		—		22
	$	1,131	$	90	$	2	$	(8)	$	1,215
Liabilities - commodity derivatives	$	—	$	(20)	$	(16)	$	18	$	(18)

93

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2022:
Assets:
Commodity derivatives	$	1	$	37	$	6	$	(10)	$	34
Money market mutual funds	225		—		—		—		225
Debt securities:
U.S. government obligations	215		—		—		—		215
International government obligations	—		1		—		—		1
Corporate obligations	—		70		—		—		70
Municipal obligations	—		3		—		—		3
Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:
U.S. companies	360		—		—		—		360
International companies	8		—		—		—		8
Investment funds	16		—		—		—		16
	$	825	$	112	$	6	$	(10)	$	933
Liabilities - commodity derivatives	$	—	$	(12)	$	(1)	$	10	$	(3)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $10 million and $— million as of June 30, 2023 and December 31, 2022, 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.

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Beginning balance	$	(5)	$	4	$	5	$	(5)
Changes in fair value recognized in net regulatory assets	(14)		31		(27)		44
Settlements	5		(9)		8		(13)
Ending balance	$	(14)	$	26	$	(14)	$	26

94

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

	As of June 30, 2023				As of December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	7,668	$	6,810	$	7,729	$	6,964

(9)    Commitments and Contingencies

Commitments

MidAmerican Energy has the following firm commitments that are not reflected on the Balance Sheets.

Construction Commitments

During the six-month period ended June 30, 2023, MidAmerican Energy entered into firm construction commitments totaling $183 million for the remainder of 2023 through 2024 related to the construction of wind-powered generating facilities in Iowa.

Environmental Laws and Regulations

MidAmerican Energy is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal 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.

Legal Matters

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

Transmission Rates

MidAmerican Energy's wholesale transmission rates are set annually using formula rates approved by the Federal Energy Regulatory Commission ("FERC") subject to true-up for actual cost of service. In November 2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the base return on equity ("ROE") used to determine rates in effect prior to September 2016 no longer be found just and reasonable and sought to reduce the base ROE. In August 2022, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion vacating all orders related to the complaints and remanding them back to the FERC. MidAmerican Energy cannot predict the ultimate outcome of these matters or the amount of refunds, if any, and accordingly, has reversed its previously accrued liability for potential refunds of amounts collected under the higher ROE during the periods covered by the complaints.

95

(10)    Revenue from Contracts with Customers

The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 12 (in millions):

	For the Three-Month Period Ended June 30, 2023								For the Six-Month Period Ended June 30, 2023
	Electric		Natural Gas		Other		Total		Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential	$	173	$	58	$	—	$	231	$	340	$	257	$	—	$	597
Commercial	86		17		—		103		161		95		—		256
Industrial	272		4		—		276		486		11		—		497
Natural gas transportation services	—		10		—		10		—		23		—		23
Other retail	38		1		—		39		73		—		—		73
Total retail	569		90		—		659		1,060		386		—		1,446
Wholesale	45		7		—		52		116		36		—		152
Multi-value transmission projects	13		—		—		13		27		—		—		27
Other Customer Revenue	—		—		1		1		—		—		4		4
Total Customer Revenue	627		97		1		725		1,203		422		4		1,629
Other revenue	34		—		—		34		49		1		—		50
Total operating revenue	$	661	$	97	$	1	$	759	$	1,252	$	423	$	4	$	1,679

	For the Three-Month Period Ended June 30, 2022								For the Six-Month Period Ended June 30, 2022
	Electric		Natural Gas		Other		Total		Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential	$	185	$	87	$	—	$	272	$	353	$	312	$	—	$	665
Commercial	91		31		—		122		165		119		—		284
Industrial	277		9		—		286		475		18		—		493
Natural gas transportation services	—		9		—		9		—		23		—		23
Other retail	41		—		—		41		73		1		—		74
Total retail	594		136		—		730		1,066		473		—		1,539
Wholesale	84		34		—		118		188		92		—		280
Multi-value transmission projects	13		—		—		13		28		—		—		28
Other Customer Revenue	—		—		1		1		—		—		2		2
Total Customer Revenue	691		170		1		862		1,282		565		2		1,849
Other revenue	34		1		—		35		51		2		—		53
Total operating revenue	$	725	$	171	$	1	$	897	$	1,333	$	567	$	2	$	1,902

(11)    Shareholder's Equity

In January 2023, MidAmerican Energy paid $100 million in cash dividends to its parent company, MHC.

96

(12)    Segment Information

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

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Operating revenue:
Regulated electric	$	661	$	725	$	1,252	$	1,333
Regulated natural gas	97		171		423		567
Other	1		1		4		2
Total operating revenue	$	759	$	897	$	1,679	$	1,902
Operating income:
Regulated electric	$	120	$	87	$	170	$	138
Regulated natural gas	(2)		3		36		52
Total operating income	118		90		206		190
Interest expense	(81)		(78)		(161)		(156)
Allowance for borrowed funds	4		5		8		9
Allowance for equity funds	13		14		24		29
Other, net	15		(12)		31		(15)
Total income before income tax expense (benefit)	$	69	$	19	$	108	$	57

	As of
	June 30, 2023		December 31, 2022
Assets:
Regulated electric	$	22,425	$	22,092
Regulated natural gas	1,717		1,885
Other	1		1
Total assets	$	24,143	$	23,978

97

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers and Member of

MidAmerican Funding, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of June 30, 2023, the related consolidated statements of operations and changes in member's equity for the three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for the six-month periods ended June 30, 2023 and 2022, 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, 2022, 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 24, 2023, 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, 2022, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Des Moines, Iowa

August 4, 2023

98

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	454	$	261
Trade receivables, net	329		536
Income tax receivable	6		43
Inventories	320		277
Prepayments	107		91
Other current assets	40		66
Total current assets	1,256		1,274
Property, plant and equipment, net	21,146		21,092
Goodwill	1,270		1,270
Regulatory assets	603		550
Investments and restricted investments	982		904
Other assets	168		164
Total assets	$	25,425	$	25,254

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

99

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	June 30,		December 31,
	2023		2022
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	384	$	536
Accrued interest	89		90
Accrued property, income and other taxes	243		170
Current portion of long-term debt	253		317
Other current liabilities	133		93
Total current liabilities	1,102		1,206
Long-term debt	7,655		7,652
Regulatory liabilities	816		1,119
Deferred income taxes	3,501		3,431
Asset retirement obligations	782		683
Other long-term liabilities	508		484
Total liabilities	14,364		14,575
Commitments and contingencies (Note 9)
Member's equity:
Paid-in capital	1,679		1,679
Retained earnings	9,382		9,000
Total member's equity	11,061		10,679
Total liabilities and member's equity	$	25,425	$	25,254

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

100

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Operating revenue:
Regulated electric	$	661	$	725	$	1,252	$	1,333
Regulated natural gas and other	98		172		427		569
Total operating revenue	759		897		1,679		1,902
Operating expenses:
Cost of fuel and energy	113		174		228		299
Cost of natural gas purchased for resale and other	46		120		282		418
Operations and maintenance	216		200		421		392
Depreciation and amortization	226		277		460		527
Property and other taxes	40		36		82		76
Total operating expenses	641		807		1,473		1,712
Operating income	118		90		206		190
Other income (expense):
Interest expense	(85)		(83)		(169)		(165)
Allowance for borrowed funds	4		5		8		9
Allowance for equity funds	13		14		24		29
Other, net	15		(10)		43		(14)
Total other income (expense)	(53)		(74)		(94)		(141)
Income before income tax expense (benefit)	65		16		112		49
Income tax expense (benefit)	(168)		(188)		(370)		(396)
Net income	$	233	$	204	$	482	$	445

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

101

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

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

(Amounts in millions)

	Paid-in Capital		Retained Earnings		Total Member's Equity
Balance, March 31, 2022	$	1,679	$	8,363	$	10,042
Net income	—		204		204
Balance, June 30, 2022	$	1,679	$	8,567	$	10,246
Balance, December 31, 2021	$	1,679	$	8,122	$	9,801
Net income	—		445		445
Balance, June 30, 2022	$	1,679	$	8,567	$	10,246
Balance, March 31, 2023	$	1,679	$	9,149	$	10,828
Net income	—		233		233
Balance, June 30, 2023	$	1,679	$	9,382	$	11,061
Balance, December 31, 2022	$	1,679	$	9,000	$	10,679
Net income	—		482		482
Distribution to member	—		(100)		(100)
Balance, June 30, 2023	$	1,679	$	9,382	$	11,061

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

102

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2023		2022
Cash flows from operating activities:
Net income	$	482	$	445
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	460		527
Amortization of utility plant to other operating expenses	16		19
Allowance for equity funds	(24)		(29)
Deferred income taxes and investment tax credits, net	46		58
Settlements of asset retirement obligations	(15)		(28)
Other, net	(10)		32
Changes in other operating assets and liabilities:
Trade receivables and other assets	194		1
Inventories	(43)		8
Accrued property, income and other taxes, net	110		95
Accounts payable and other liabilities	(106)		(10)
Net cash flows from operating activities	1,110		1,118
Cash flows from investing activities:
Capital expenditures	(763)		(862)
Purchases of marketable securities	(95)		(214)
Proceeds from sales of marketable securities	81		210
Proceeds from sale of investment	12		—
Other, net	10		6
Net cash flows from investing activities	(755)		(860)
Cash flows from financing activities:
Distribution to member	(100)		—
Repayments of long-term debt	(65)		—
Net change in note payable to affiliate	—		8
Other, net	(1)		(1)
Net cash flows from financing activities	(166)		7
Net change in cash and cash equivalents and restricted cash and cash equivalents	189		265
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	271		240
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	460	$	505

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

103

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    General

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

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of June 30, 2023, and for the three- and six-month periods ended June 30, 2023 and 2022. The results of operations for the six-month period ended June 30, 2023, 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, 2022, 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 accounting policies or its assumptions regarding significant accounting estimates during the six-month period ended June 30, 2023.

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

Cash equivalents consist of funds invested in money market mutual funds, 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 restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):

	As of
	June 30,		December 31,
	2023		2022
Cash and cash equivalents	$	454	$	261
Restricted cash and cash equivalents in other current assets	6		10
Total cash and cash equivalents and restricted cash and cash equivalents	$	460	$	271

(3)    Property, Plant and Equipment, Net

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

(4)    Recent Financing Transactions

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

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(5)    Income Taxes

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Income tax credits	(266)		(1,150)		(335)		(793)
State income tax, net of federal income tax impacts	(8)		(38)		(10)		(29)
Effects of ratemaking	(5)		(12)		(5)		(10)
Other, net	—		4		(1)		3
Effective income tax rate	(258)	%	(1,175)	%	(330)	%	(808)	%

Income tax credits relate primarily to production tax credits ("PTC") from MidAmerican Energy's wind- and solar-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind- and solar-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- and solar-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the six-month periods ended June 30, 2023 and 2022, totaled $375 million and $388 million, respectively.

Berkshire Hathaway includes BHE and subsidiaries in its 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. MidAmerican Funding received net cash payments for income tax from BHE totaling $522 million and $544 million for the six-month periods ended June 30, 2023 and 2022, respectively.

(6)    Employee Benefit Plans

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

(7)    Asset Retirement Obligations

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

(8)    Fair Value Measurements

Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements. MidAmerican Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Funding's long-term debt (in millions):

	As of June 30, 2023				As of December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	7,908	$	7,065	$	7,969	$	7,219

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(9)    Commitments and Contingencies

MidAmerican Funding is party to a variety of legal actions arising out of the normal course of business. MidAmerican Funding does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements.

(10)    Revenue from Contracts with Customers

Refer to Note 10 of MidAmerican Energy's Notes to Financial Statements.

(11)    Member's Equity

In January 2023, MidAmerican Funding paid a $100 million cash distribution to its parent company, BHE.

(12)    Segment Information

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

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Operating revenue:
Regulated electric	$	661	$	725	$	1,252	$	1,333
Regulated natural gas	97		171		423		567
Other	1		1		4		2
Total operating revenue	$	759	$	897	$	1,679	$	1,902
Operating income:
Regulated electric	$	120	$	87	$	170	$	138
Regulated natural gas	(2)		3		36		52
Total operating income	118		90		206		190
Interest expense	(85)		(83)		(169)		(165)
Allowance for borrowed funds	4		5		8		9
Allowance for equity funds	13		14		24		29
Other, net	15		(10)		43		(14)
Total income before income tax expense (benefit)	$	65	$	16	$	112	$	49

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	As of
	June 30, 2023		December 31, 2022
Assets(1):
Regulated electric	$	23,616	$	23,283
Regulated natural gas	1,796		1,963
Other	13		8
Total assets	$	25,425	$	25,254

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

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

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

Results of Operations for the Second Quarter and First Six Months of 2023 and 2022

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the second quarter of 2023 was $236 million, an increase of $29 million, or 14%, compared to 2022, primarily due to lower depreciation and amortization expense and favorable other, net, partially offset by lower income tax benefit, higher operations and maintenance expense, higher property and other taxes and higher interest expense, lower electric utility margin and lower allowance for borrowed and equity funds. Electric retail customer volumes increased 1%, primarily due to higher customer usage for certain industrial customers, partially offset by the unfavorable impact of weather. Energy generated decreased 1%, due to lower wind-powered generation partially offset by higher coal- and natural gas-fueled generation; and energy purchased decreased 3%. Wholesale electricity sales volumes decreased 5% due to unfavorable market conditions. Natural gas retail customer volumes decreased 16% due to the unfavorable impact of weather.

MidAmerican Energy's net income for the first six months of 2023 was $478 million, an increase of $27 million, or 6%, compared to 2022, primarily due to lower depreciation and amortization expense, favorable other, net and higher nonregulated utility margin, partially offset by higher operations and maintenance expense, lower income tax benefit, lower electric utility margin, lower natural gas utility margin, lower allowance for borrowed and equity funds, higher property and other taxes and higher interest expense. Electric retail customer volumes increased 1%, primarily due to higher customer usage for certain industrial customers, partially offset by the unfavorable impact of weather. Energy generated decreased 5%, due to lower wind-powered generation partially offset by higher natural gas- and coal-fueled generation; and energy purchased increased 6%. Wholesale electricity sales volumes decreased 12% due to unfavorable market conditions. Natural gas retail customer volumes decreased 11% due to the unfavorable impact of weather.

MidAmerican Funding -

MidAmerican Funding's net income for the second quarter of 2023 was $233 million, an increase of $29 million, or 14%, compared to 2022. MidAmerican Funding's net income for the first six months of 2023 was $482 million, an increase of $37 million, or 8%, compared to 2022. The variance in net income was primarily due to the changes in MidAmerican Energy's earnings discussed above and a one-time gain on the sale of an investment of $10 million.

Non-GAAP Financial Measure

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

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

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

	Second Quarter								First Six Months
	2023		2022		Change				2023		2022		Change
Electric utility margin:
Operating revenue	$	661	$	725	$	(64)	(9)	%	$	1,252	$	1,333	$	(81)	(6)	%
Cost of fuel and energy	113		174		(61)		(35)		228		299		(71)		(24)
Electric utility margin	548		551		(3)		(1)	%	1,024		1,034		(10)		(1)	%
Natural gas utility margin:
Operating revenue	97		171		(74)		(43)	%	423		567		(144)		(25)	%
Natural gas purchased for resale	46		120		(74)		(62)		282		418		(136)		(33)
Natural gas utility margin	51		51		—		—	%	141		149		(8)		(5)	%
Utility margin	599		602		(3)		—	%	1,165		1,183		(18)		(2)	%
Other operating revenue	1		1		—		—	%	4		2		2		100	%
Operations and maintenance	216		200		16		8		421		392		29		7
Depreciation and amortization	226		277		(51)		(18)		460		527		(67)		(13)
Property and other taxes	40		36		4		11		82		76		6		8
Operating income	$	118	$	90	$	28	31	%	$	206	$	190	$	16	8	%

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Electric Utility Margin

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

	Second Quarter								First Six Months
	2023		2022		Change				2023		2022		Change
Utility margin (in millions):
Operating revenue	$	661	$	725	$	(64)	(9)	%	$	1,252	$	1,333	$	(81)	(6)	%
Cost of fuel and energy	113		174		(61)		(35)		228		299		(71)		(24)
Utility margin	$	548	$	551	$	(3)	(1)	%	$	1,024	$	1,034	$	(10)	(1)	%
Sales (GWhs):
Residential	1,479		1,552		(73)		(5)	%	3,272		3,405		(133)		(4)	%
Commercial	929		953		(24)		(3)		1,947		1,966		(19)		(1)
Industrial	4,365		4,149		216		5		8,467		8,128		339		4
Other	392		406		(14)		(3)		801		809		(8)		(1)
Total retail	7,165		7,060		105		1		14,487		14,308		179		1
Wholesale	3,942		4,146		(204)		(5)		8,294		9,471		(1,177)		(12)
Total sales	11,107		11,206		(99)		(1)	%	22,781		23,779		(998)		(4)	%
Average number of retail customers (in thousands)	819		812		7		1	%	818		811		7		1	%
Average revenue per MWh:
Retail	$	79.45	$	84.18	$	(4.73)	(6)	%	$	73.17	$	74.52	$	(1.35)	(2)	%
Wholesale	$	17.63	$	25.23	$	(7.60)	(30)	%	$	17.59	$	22.65	$	(5.06)	(22)	%
Heating degree days	462		677		(215)		(32)	%	3,454		3,992		(538)		(13)	%
Cooling degree days	393		421		(28)		(7)	%	393		421		(28)		(7)	%
Sources of energy (GWhs)(1):
Wind and other(2)	6,320		7,364		(1,044)		(14)	%	13,697		15,654		(1,957)		(13)	%
Coal	2,217		1,481		736		50		4,333		3,840		493		13
Nuclear	862		863		(1)		—		1,789		1,783		6		—
Natural gas	569		397		172		43		913		631		282		45
Total energy generated	9,968		10,105		(137)		(1)		20,732		21,908		(1,176)		(5)
Energy purchased	1,282		1,315		(33)		(3)		2,405		2,277		128		6
Total	11,250		11,420		(170)		(1)	%	23,137		24,185		(1,048)		(4)	%
Average cost of energy per MWh:
Energy generated(3)	$	6.20	$	6.34	$	(0.14)	(2)	%	$	6.15	$	5.92	$	0.23	4	%
Energy purchased	$	39.75	$	83.45	$	(43.70)	(52)	%	$	41.61	$	74.41	$	(32.80)	(44)	%

(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 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.

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Natural Gas Utility Margin

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

	Second Quarter								First Six Months
	2023		2022		Change				2023		2022		Change
Utility margin (in millions):
Operating revenue	$	97	$	171	$	(74)	(43)	%	$	423	$	567	$	(144)	(25)	%
Natural gas purchased for resale	46		120		(74)		(62)		282		418		(136)		(33)
Utility margin	$	51	$	51	$	—	—	%	$	141	$	149	$	(8)	(5)	%
Throughput (000's Dths):
Residential	6,197		7,500		(1,303)		(17)	%	30,590		34,599		(4,009)		(12)	%
Commercial	3,023		3,599		(576)		(16)		14,375		16,059		(1,684)		(10)
Industrial	1,373		1,465		(92)		(6)		2,856		3,309		(453)		(14)
Other	13		16		(3)		(19)		47		51		(4)		(8)
Total retail sales	10,606		12,580		(1,974)		(16)		47,868		54,018		(6,150)		(11)
Wholesale sales	3,996		4,912		(916)		(19)		14,403		17,144		(2,741)		(16)
Total sales	14,602		17,492		(2,890)		(17)		62,271		71,162		(8,891)		(12)
Natural gas transportation service	23,830		22,491		1,339		6		53,415		53,804		(389)		(1)
Total throughput	38,432		39,983		(1,551)		(4)	%	115,686		124,966		(9,280)		(7)	%
Average number of retail customers (in thousands)	792		781		11		1	%	792		784		8		1	%
Average revenue per retail Dth sold	$	7.53	$	10.08	$	(2.55)	(25)	%	$	7.61	$	8.36	$	(0.75)	(9)	%
Heating degree days	509		734		(225)		(31)	%	3,641		4,219		(578)		(14)	%
Average cost of natural gas per retail Dth sold	$	3.61	$	6.78	$	(3.17)	(47)	%	$	5.14	$	6.03	$	(0.89)	(15)	%
Combined retail and wholesale average cost of natural gas per Dth sold	$	3.15	$	6.86	$	(3.71)	(54)	%	$	4.54	$	5.87	$	(1.33)	(23)	%

Quarter Ended June 30, 2023 Compared to Quarter Ended June 30, 2022

MidAmerican Energy -

Electric utility margin decreased $3 million, or 1%, for the second quarter of 2023 compared to 2022, primarily due to:

•a $33 million decrease in wholesale utility margin due to lower margins per unit of $29 million from lower market prices, and lower volumes of 4.9%; partially offset by

•a $29 million increase in retail utility margin primarily due to $26 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); and $3 million due to price impacts from changes in sales mix. Retail customer volumes increased 1.4%.

Natural gas utility margin for the second quarter of 2023 was equal to 2022, primarily due to:

•a $3 million increase from higher customer usage and other rate variances;

•a $1 million increase from lower refunds related to amortization of excess accumulated deferred income taxes arising from 2017 tax reform (offset in income tax benefit); offset by

•a $4 million decrease due to the unfavorable impact of weather.

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Operations and maintenance increased $16 million, or 8%, for the second quarter of 2023 compared to 2022 primarily due to higher nuclear power generation costs of $6 million, higher benefit costs of $5 million, higher technology costs of $4 million, and higher administrative and other costs of $4 million, partially offset by lower electric distribution and transmission costs of $4 million.

Depreciation and amortization decreased $51 million, or 18%, for the second quarter of 2023 compared to 2022 primarily due to $58 million from lower Iowa revenue sharing accruals, and $21 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects, partially offset by $25 million from wind-powered generating facilities and other plant placed in-service and $3 million from lower depreciation expense deferrals in 2023.

Property and other taxes increased $4 million, or 11%, for the second quarter of 2023 compared to 2022 primarily due to $2 million from higher wind turbine property taxes and $2 million from higher replacement taxes.

Interest expense increased $3 million, or 4%, for the second quarter of 2023 compared to 2022 due to higher interest rates on variable rate long-term debt.

Allowance for borrowed and equity funds decreased $2 million, or 11%, for the second quarter of 2023 compared to 2022 due to lower construction work-in-progress balances related to wind- and solar-powered generation.

Other, net increased $27 million, or 225%, for the second quarter of 2023 compared to 2022 primarily due to favorable investment earnings, largely attributable to higher cash surrender values of corporate-owned life insurance policies, and higher interest income from higher interest rates, partially offset by higher non-service costs of employee benefit plans.

Income tax benefit decreased $21 million, or 11%, for the second quarter of 2023 compared to 2022 primarily due to lower PTCs and higher pretax income. PTCs for the second quarter of 2023 and 2022 totaled $173 million and $185 million, respectively.

MidAmerican Funding -

Income tax benefit decreased $20 million, or 11%, for the second quarter of 2023 compared to 2022 principally due to the changes in MidAmerican Energy's income tax benefit discussed above.

First Six Months of 2023 Compared to First Six Months of 2022

MidAmerican Energy -

Electric utility margin decreased $10 million, or 1%, for the first six months of 2023 compared to 2022, due to:

•a $55 million decrease in wholesale utility margin due to lower margins per unit of $36 million from lower market prices, and lower volumes of 12.4%; partially offset by

•a $46 million increase in retail utility margin primarily due to $39 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); $15 million from higher customer usage; $3 million due to price impacts from changes in sales mix; and $2 million from higher wind-turbine performance settlements; partially offset by $13 million from the unfavorable impact of weather. Retail customer volumes increased 1.3%.

Natural gas utility margin decreased $8 million, or 5%, for the first six months of 2023 compared to 2022 primarily due to a $9 million decrease from the unfavorable impact of weather.

Operations and maintenance increased $29 million, or 7%, for the first six months of 2023 compared to 2022 primarily due to higher benefits costs of $8 million, higher technology costs of $7 million, higher administrative and other costs of $6 million, higher other power generation costs of $5 million, higher property insurance costs of $3 million and higher nuclear power generation costs of $2 million, partially offset by lower electric distribution and transmission costs of $4 million.

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Depreciation and amortization decreased $67 million, or 13%, for the first six months of 2023 compared to 2022 primarily due to $80 million from lower Iowa revenue sharing accruals, and $27 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects, partially offset by $34 million from new wind-powered generating facilities and other plant placed in-service and $6 million from lower depreciation expense deferrals in 2023.

Property and other taxes increased $6 million, or 8%, for the first six months of 2023 compared to 2022 primarily due to $3 million from higher wind turbine property taxes and $3 million from higher replacement taxes.

Interest expense increased $5 million, or 3%, for the first six months of 2023 compared to 2022 due to higher interest rates on variable rate long-term debt.

Allowance for borrowed and equity funds decreased $6 million, or 16%, for the first six months of 2023 compared to 2022 primarily due to lower construction work-in-progress balances related to wind- and solar-powered generation.

Other, net increased $46 million, or 307%, for the first six months of 2023 compared to 2022 primarily due to favorable investment earnings, largely attributable to higher cash surrender values of corporate-owned life insurance policies, higher interest income from higher interest rates, and lower non-service costs of employee benefit plans.

Income tax benefit decreased $24 million, or 6%, for the first six months of 2023 compared to 2022 primarily due to lower PTCs and higher pretax income. PTCs for the first six months of 2023 and 2022 totaled $375 million and $388 million, respectively.

MidAmerican Funding -

Income tax benefit decreased $26 million, or 7%, for the first six months of 2023 compared to 2022 principally due to the changes in MidAmerican Energy's income tax benefit discussed above and higher pretax income from a one-time gain on the sale of an investment.

Liquidity and Capital Resources

As of June 30, 2023, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):

MidAmerican Energy:
Cash and cash equivalents	$	454
Credit facilities, maturing 2024 and 2026	1,505
Less:
Tax-exempt bond support	(306)
Net credit facilities	1,199
MidAmerican Energy total net liquidity	$	1,653
MidAmerican Funding:
MidAmerican Energy total net liquidity	$	1,653
MHC, Inc. credit facility, maturing 2024	4
MidAmerican Funding total net liquidity	$	1,657

Operating Activities

MidAmerican Energy's net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022, were $1,125 million and $1,125 million, respectively. MidAmerican Funding's net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022, were $1,110 million and $1,118 million, respectively. Cash flows from operating activities reflect higher payments to vendors, lower income tax receipts and higher interest payments, offset by higher utility margins for MidAmerican Energy's regulated electric and natural gas businesses.

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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 made for each payment date.

Investing Activities

MidAmerican Energy's net cash flows from investing activities for the six-month periods ended June 30, 2023 and 2022, were $(767) million and $(860) million, respectively. MidAmerican Funding's net cash flows from investing activities for the six-month periods ended June 30, 2023 and 2022, were $(755) million and $(860) million, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures. Purchases and proceeds related to marketable securities substantially consist of activity within the Quad Cities Generating Station nuclear decommissioning trust and other trust investments.

Financing Activities

MidAmerican Energy's net cash flows from financing activities for the six-month periods ended June 30, 2023 and 2022 were $(166) million and $(1) million, respectively. MidAmerican Funding's net cash flows from financing activities for the six-month periods ended June 30, 2023 and 2022, were $(166) million and $7 million, respectively. In January 2023, MidAmerican Funding made a $100 million distribution to its sole member BHE. In January 2023 and May 2023, MidAmerican Energy repaid $7 million and $58 million of long-term debt, respectively. MidAmerican Funding received $— million and $8 million in 2023 and 2022, 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, 2024, commercial paper and bank notes aggregating $1.5 billion. MidAmerican Energy has a $1.5 billion unsecured credit facility expiring in June 2026. 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 Secured Overnight Financing Rate, 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 shelf registration statement with the SEC to issue up to $3.25 billion of long-term debt securities and preferred stock through March 10, 2026. MidAmerican Energy has authorization from the FERC to issue, through June 30, 2025, long-term debt securities up to an aggregate of $3.0 billion and preferred stock up to an aggregate of $500 million. MidAmerican Energy has authorization from the Illinois Commerce Commission through May 25, 2025, to issue long-term debt securities up to an aggregate of $2.2 billion and preferred stock up to an aggregate of $500 million; 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; and through January 1, 2025, to issue $48 million of long-term debt securities for the purpose of refinancing two of its variable-rate tax-exempt bond series, including $35 million due in October 2024 and $13 million due in January 2025.

Future Uses of Cash

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

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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 customer rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

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

	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2022		2023		2023
Wind generation	$	244	$	243	$	906
Electric distribution	125		167		353
Electric transmission	46		76		163
Solar generation	77		10		24
Other	370		267		701
Total	$	862	$	763	$	2,147

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 of wind-powered generating facilities totaling $200 million and $5 million for the six-month periods ended June 30, 2023 and 2022, respectively. The timing and amount of forecast wind generation capital expenditures may be substantially impacted by the ultimate outcome of MidAmerican Energy's Wind PRIME filing. Planned spending for the construction of additional wind-powered generating facilities totals $544 million for the remainder of 2023.

◦Repowering of wind-powered generating facilities totaling $19 million and $214 million for the six-month periods ended June 30, 2023 and 2022, respectively. Planned spending for the repowering of wind-powered generating facilities totals $46 million for the remainder of 2023. 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.

•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 generation includes the construction and operation of solar-powered generating facilities, primarily consisting of 141 MWs of small- and utility-scale solar generation, all of which were placed in-service in 2022. For the six-month periods ended June 30, 2023 and 2022, solar generation spending totaled $10 million and $77 million, respectively. Planned spending totals $14 million for the remainder of 2023.

•Other includes primarily routine projects for other generation, natural gas distribution, technology, facilities and other operational needs to serve existing and expected demand.

Material Cash Requirements

As of June 30, 2023, there have been no material changes in MidAmerican Energy's and MidAmerican Funding's cash requirements from the information provided in Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2022.

115

Regulatory Matters

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

Environmental Laws and Regulations

MidAmerican Energy is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact MidAmerican Energy'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. MidAmerican Energy 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 MidAmerican Energy 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 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, 2022. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2022.

116

Nevada Power Company and its subsidiaries

Consolidated Financial Section

117

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Nevada Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of June 30, 2023, the related consolidated statements of operations, and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for the six-month periods ended June 30, 2023 and 2022, 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, 2022, 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 24, 2023, 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, 2022, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

August 4, 2023

118

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)

	As of
	June 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	47	$	43
Trade receivables, net	460		388
Note receivable from affiliate	—		100
Inventories	120		93
Regulatory assets	784		666
Other current assets	68		89
Total current assets	1,479		1,379
Property, plant and equipment, net	8,054		7,406
Regulatory assets	644		628
Other assets	388		388
Total assets	$	10,565	$	9,801
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	636	$	422
Accrued interest	39		40
Accrued property, income and other taxes	35		32
Current portion of long-term debt	300		—
Regulatory liabilities	43		45
Customer deposits	54		51
Derivative contracts	104		51
Other current liabilities	63		49
Total current liabilities	1,274		690
Long-term debt	2,896		3,195
Finance lease obligations	286		295
Regulatory liabilities	1,035		1,093
Deferred income taxes	915		875
Other long-term liabilities	335		299
Total liabilities	6,741		6,447
Commitments and contingencies (Note 9)
Shareholder's equity:
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding	—		—
Additional paid-in capital	2,733		2,333
Retained earnings	1,092		1,022
Accumulated other comprehensive loss, net	(1)		(1)
Total shareholder's equity	3,824		3,354
Total liabilities and shareholder's equity	$	10,565	$	9,801
The accompanying notes are an integral part of the consolidated financial statements.

119

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Operating revenue	$	781	$	639	$	1,380	$	1,054
Operating expenses:
Cost of fuel and energy	493		336		877		548
Operations and maintenance	78		75		151		140
Depreciation and amortization	108		103		214		206
Property and other taxes	14		12		28		25
Total operating expenses	693		526		1,270		919
Operating income	88		113		110		135
Other income (expense):
Interest expense	(49)		(39)		(98)		(77)
Capitalized interest	7		2		9		3
Allowance for equity funds	4		2		8		5
Interest and dividend income	19		9		41		18
Other, net	4		(1)		8		—
Total other income (expense)	(15)		(27)		(32)		(51)
Income before income tax expense (benefit)	73		86		78		84
Income tax expense (benefit)	7		10		8		10
Net income	$	66	$	76	$	70	$	74
The accompanying notes are an integral part of these consolidated financial statements.

120

NEVADA POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)

								Accumulated
				Additional				Other		Total
	Common Stock			Paid-in		Retained		Comprehensive		Shareholder's
	Shares	Amount		Capital		Earnings		Loss, Net		Equity
Balance, March 31, 2022	1,000	$	—	$	2,308	$	722	$	(2)	$	3,028
Net income	—	—		—		76		—		76
Contributions	—	—		25		—		—		25
Balance, June 30, 2022	1,000	$	—	$	2,333	$	798	$	(2)	$	3,129
Balance, December 31, 2021	1,000	$	—	$	2,308	$	724	$	(2)	$	3,030
Net income	—	—		—		74		—		74
Contributions	—	—		25		—		—		25
Balance, June 30, 2022	1,000	$	—	$	2,333	$	798	$	(2)	$	3,129
Balance, March 31, 2023	1,000	$	—	$	2,733	$	1,026	$	(1)	$	3,758
Net income	—	—		—		66		—		66
Balance, June 30, 2023	1,000	$	—	$	2,733	$	1,092	$	(1)	$	3,824
Balance, December 31, 2022	1,000	$	—	$	2,333	$	1,022	$	(1)	$	3,354
Net income	—	—		—		70		—		70
Contributions	—	—		400		—		—		400
Balance, June 30, 2023	1,000	$	—	$	2,733	$	1,092	$	(1)	$	3,824
The accompanying notes are an integral part of these consolidated financial statements.

121

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2023		2022
Cash flows from operating activities:
Net income	$	70	$	74
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	214		206
Allowance for equity funds	(8)		(5)
Changes in regulatory assets and liabilities	(19)		(14)
Deferred income taxes and amortization of investment tax credits	9		12
Deferred energy	(252)		(159)
Amortization of deferred energy	131		46
Other, net	(1)		10
Changes in other operating assets and liabilities:
Trade receivables and other assets	(83)		(154)
Inventories	(27)		(4)
Accrued property, income and other taxes	(4)		18
Accounts payable and other liabilities	202		194
Net cash flows from operating activities	232		224
Cash flows from investing activities:
Capital expenditures	(719)		(350)
Proceeds from repayment of affiliate note receivable	100		—
Net cash flows from investing activities	(619)		(350)
Cash flows from financing activities:
Net (repayments of) proceeds from long-term debt	(1)		300
Net repayments of short-term debt	—		(180)
Contributions from parent	400		25
Other, net	(10)		(9)
Net cash flows from financing activities	389		136
Net change in cash and cash equivalents and restricted cash and cash equivalents	2		10
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	60		45
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	62	$	55
The accompanying notes are an integral part of these consolidated financial statements.

122

NEVADA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    General

Nevada Power Company, together with its subsidiaries ("Nevada Power"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific") and certain other subsidiaries. Nevada Power is a 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 June 30, 2023, and for the three- and six-month periods ended June 30, 2023 and 2022. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and six-month periods ended June 30, 2023 and 2022. The results of operations for the three- and six-month periods ended June 30, 2023, 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, 2022, 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 accounting policies or its assumptions regarding significant accounting estimates during the six-month period ended June 30, 2023.

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

Cash equivalents consist of funds invested in money market mutual funds, 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 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 presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):

	As of
	June 30,		December 31,
	2023		2022
Cash and cash equivalents	$	47	$	43
Restricted cash and cash equivalents included in other current assets	15		17
Total cash and cash equivalents and restricted cash and cash equivalents	$	62	$	60

123

(3)    Property, Plant and Equipment, Net

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

		As of
	Depreciable Life	June 30,		December 31,
		2023		2022
Utility plant:
Generation	30 - 55 years	$	4,100	$	3,977
Transmission	45 - 70 years	1,581		1,562
Distribution	20 - 65 years	4,299		4,134
General and intangible plant	5 - 65 years	898		871
Utility plant		10,878		10,544
Accumulated depreciation and amortization		(3,731)		(3,624)
Utility plant, net		7,147		6,920
Non-regulated, net of accumulated depreciation and amortization	45 years	1		1
		7,148		6,921
Construction work-in-progress		906		485
Property, plant and equipment, net		$	8,054	$	7,406

(4)    Recent Financing Transactions

Long-Term Debt

In March 2023, Nevada Power repurchased and entered into a re-offering of the following series of fixed-rate tax-exempt bonds: $40 million of its Coconino County, Arizona Pollution Control Corporation Revenue Bonds, Series 2017A, due 2032; $13 million of its Coconino County, Arizona Pollution Control Corporation Revenue Bonds, Series 2017B, due 2039; and $40 million of its Clark County, Nevada Revenue Bonds, Series 2017, due 2036. The Coconino Series 2017A bond was offered at a fixed rate of 4.125% and the Coconino Series 2017B and Clark Series 2017 bonds were offered at a fixed rate of 3.750%.

Credit Facilities

In June 2023, Nevada Power amended its existing $400 million secured credit facility expiring in June 2025. The amendment increased the commitment of the lenders to $600 million and extended the expiration date to June 2026.

(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 (benefit) is as follows:

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Effects of ratemaking	(11)		(10)		(10)		(10)
Other	—		1		(1)		1
Effective income tax rate	10	%	12	%	10	%	12	%

Effects of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to 2017 tax reform pursuant to an order issued by the PUCN effective January 1, 2021.

124

Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, Nevada Power's provision for federal income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. For the six-month period ended June 30, 2023, Nevada Power made no cash payments for federal income tax to BHE. For the six-month period ended June 30, 2022, Nevada Power received net cash payments for federal income tax from BHE totaling $21 million.

(6)    Employee Benefit Plans

Nevada Power is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.

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

	As of
	June 30,		December 31,
	2023		2022
Qualified Pension Plan:
Other non-current assets	$	26	$	27
Non-Qualified Pension Plans:
Other current liabilities	(1)		(1)
Other long-term liabilities	(6)		(6)
Other Postretirement Plans:
Other non-current assets	7		7

(7)    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 and natural gas 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 8 for additional information on derivative contracts.

125

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 June, 30 2023
Not designated as hedging contracts(1) -
Total derivatives - commodity liabilities	$	—	$	(104)	$	(22)	$	(126)
As of December 31, 2022
Not designated as hedging contracts(1):
Commodity assets	$	23	$	—	$	—	$	23
Commodity liabilities	—		(51)		(24)		(75)
Total derivatives - net basis	$	23	$	(51)	$	(24)	$	(52)

(1)Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates. As of June 30, 2023 a regulatory asset of $126 million was recorded related to the net derivative liability of $126 million. As of December 31, 2022 a regulatory asset of $52 million was recorded related to the net derivative liability of $52 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	June 30,	December 31,
	Measure	2023	2022
Electricity purchases	Megawatt hours	2	2
Natural gas purchases	Decatherms	127	109

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 June 30, 2023, 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.

126

The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $9 million and $5 million as of June 30, 2023 and December 31, 2022, 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.

(8)    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 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 Nevada Power has the ability to access at the measurement date.

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

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

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

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Total
As of June 30, 2023:
Assets:
Money market mutual funds	$	48	—		—		$	48
Investment funds	3		—		—		3
	$	51	$	—	$	—	$	51
Liabilities - commodity derivatives	$	—	$	—	$	(126)	$	(126)
As of December 31, 2022:
Assets:
Commodity derivatives	$	—	$	—	$	23	$	23
Money market mutual funds	34		—		—		34
Investment funds	3		—		—		3
	$	37	$	—	$	23	$	60
Liabilities - commodity derivatives	$	—	$	—	$	(75)	$	(75)

127

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of June 30, 2023 and December 31, 2022, 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.

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Beginning balance	$	(116)	$	(168)	$	(52)	$	(113)
Changes in fair value recognized in regulatory assets	(54)		(21)		(119)		(77)
Settlements	44		14		45		15
Ending balance	$	(126)	$	(175)	$	(126)	$	(175)

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

	As of June 30, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	3,196	$	3,086	$	3,195	$	3,114

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(9)    Commitments and Contingencies

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.

Legal Matters

Nevada Power is party to a variety of legal actions arising out of the normal course of business. Nevada Power does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

(10)    Revenue from Contracts with Customers

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Customer Revenue:
Retail:
Residential	$	404	$	353	$	697	$	566
Commercial	177		131		313		226
Industrial	173		124		311		203
Other	4		3		10		4
Total fully bundled	758		611		1,331		999
Distribution only service	4		5		7		10
Total retail	762		616		1,338		1,009
Wholesale, transmission and other	15		18		33		34
Total Customer Revenue	777		634		1,371		1,043
Other revenue	4		5		9		11
Total operating revenue	$	781	$	639	$	1,380	$	1,054

129

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

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

Results of Operations for the Second Quarter and First Six Months of 2023 and 2022

Overview

Net income for the second quarter of 2023 was $66 million, a decrease of $10 million, compared to 2022 primarily due to lower utility margin, higher interest expense, primarily due to higher long-term debt, higher operations and maintenance expenses, mainly due to increased plant operations and maintenance expenses, partially offset by lower earnings sharing, and higher depreciation and amortization, mainly due to higher plant placed in-service. The decrease is offset by favorable interest and dividend income, mainly from higher carrying charges on regulatory balances, higher capitalized interest mainly due to higher construction work-in-progress and favorable cash surrender value of corporate-owned life insurance policies. Utility margin decreased primarily due to lower retail customer volumes, partially offset by higher regulatory-related revenue deferrals. Retail customer volumes, including distribution only service customers, decreased 4.5% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers. Energy generated for the second quarter of 2023 was comparable to 2022. Wholesale electricity sales volumes decreased 68% and purchased electricity volumes decreased 11%.

Net income for the first six months of 2023 was $70 million, a decrease of $4 million, compared to 2022 primarily due to higher interest expense, mainly due to higher long-term debt, higher operations and maintenance expenses and higher depreciation and amortization, mainly due to higher plant placed in-service. The decrease is partially offset by favorable interest and dividend income, mainly from higher carrying charges on regulatory balances, higher capitalized interest mainly due to higher construction work-in-progress and favorable cash surrender value of corporate-owned life insurance policies. Operations and maintenance expenses increased primarily due to increased plant operations and maintenance expenses and higher customer service operations expenses, partially offset by lower earnings sharing. Utility margin decreased primarily due to lower retail customer volumes, partially offset by higher regulatory-related revenue deferrals and higher other retail revenue. Retail customer volumes, including distribution only service customers, decreased 1.2% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers. Energy generated increased 16% for the first six months of 2023 compared to 2022 primarily due to higher natural-gas fueled generation. Wholesale electricity sales volumes decreased 61% and purchased electricity volumes decreased 21%.

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.

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

	Second Quarter								First Six Months
	2023		2022		Change				2023		2022		Change
Utility margin:
Operating revenue	$	781	$	639	$	142	22	%	$	1,380	$	1,054	$	326	31	%
Cost of fuel and energy	493		336		157		47		877		548		329		60
Utility margin	288		303		(15)		(5)		503		506		(3)		(1)
Operations and maintenance	78		75		3		4		151		140		11		8
Depreciation and amortization	108		103		5		5		214		206		8		4
Property and other taxes	14		12		2		17		28		25		3		12
Operating income	$	88	$	113	$	(25)	(22)	%	$	110	$	135	$	(25)	(19)	%

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Utility Margin

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

	Second Quarter								First Six Months
	2023		2022		Change				2023		2022		Change
Utility margin (in millions):
Operating revenue	$	781	$	639	$	142	22	%	$	1,380	$	1,054	$	326	31	%
Cost of fuel and energy	493		336		157		47		877		548		329		60
Utility margin	$	288	$	303	$	(15)	(5)	%	$	503	$	506	$	(3)	(1)	%
Sales (GWhs):
Residential	2,268		2,612		(344)		(13)	%	3,904		4,197		(293)		(7)	%
Commercial	1,251		1,272		(21)		(2)		2,248		2,270		(22)		(1)
Industrial	1,456		1,409		47		3		2,698		2,584		114		4
Other	44		46		(2)		(4)		87		92		(5)		(5)
Total fully bundled(1)	5,019		5,339		(320)		(6)		8,937		9,143		(206)		(2)
Distribution only service	708		661		47		7		1,306		1,230		76		6
Total retail	5,727		6,000		(273)		(5)		10,243		10,373		(130)		(1)
Wholesale	67		210		(143)		(68)		130		335		(205)		(61)
Total GWhs sold	5,794		6,210		(416)		(7)	%	10,373		10,708		(335)		(3)	%
Average number of retail customers (in thousands)	1,012		1,000		12		1	%	1,011		997		14		1	%
Average revenue per MWh:
Retail - fully bundled(1)	$	151.17	$	114.36	$	36.81	32	%	$	148.98	$	109.26	$	39.72	36	%
Wholesale	$	47.45	$	34.36	$	13.09	38	%	$	72.10	$	37.55	$	34.55	92	%
Heating degree days	73		31		42		*		1,383		985		398		40	%
Cooling degree days	1,121		1,322		(201)		(15)	%	1,124		1,371		(247)		(18)	%
Sources of energy (GWhs)(2)(3):
Natural gas	2,931		2,935		(4)		—	%	6,194		5,313		881		17	%
Renewables	19		20		(1)		(5)		34		34		—		—
Total energy generated	2,950		2,955		(5)		—		6,228		5,347		881		16
Energy purchased	2,199		2,472		(273)		(11)		3,336		4,233		(897)		(21)
Total	5,149		5,427		(278)		(5)	%	9,564		9,580		(16)		—	%
Average cost of energy per MWh(4):
Energy generated	$	60.13	$	49.65	$	10.48	21	%	$	76.19	$	46.19	$	30.00	65	%
Energy purchased	$	143.80	$	76.63	$	67.17	88	%	$	120.73	$	71.07	$	49.66	70	%

*    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 179 GWhs and 360 GWhs of gas generated energy that is purchased at cost by related parties for the second quarter of 2023 and 2022, respectively. The average cost of energy per MWh and sources of energy excludes 462 GWhs and 784 GWhs of gas generated energy that is purchased at cost by related parties for the first six months of 2023 and 2022, 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.

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Quarter Ended June 30, 2023 Compared to Quarter Ended June 30, 2022

Utility margin decreased $15 million, or 5%, for the second quarter of 2023 compared to 2022 primarily due to:

•$21 million of lower electric retail utility margin primarily due to lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 4.5% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers.

The decrease in utility margin was partially offset by:

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

•$3 million of higher regulatory-related revenue deferrals.

Operations and maintenance increased $3 million, or 4%, for the second quarter of 2023 compared to 2022 primarily due to increased plant operations and maintenance expenses, higher energy efficiency program costs (offset in operating revenue) and higher customer service operations expenses, partially offset by lower earnings sharing.

Depreciation and amortization increased $5 million, or 5%, for the second quarter of 2023 compared to 2022 primarily due to higher plant placed in-service.

Property and other taxes increased $2 million, or 17%, for the second quarter of 2023 compared to 2022 primarily due to a decrease in the amount of abatements available and an increase in commerce and franchise tax from higher revenue.

Interest expense increased $10 million, or 26%, for the second quarter of 2023 compared to 2022 primarily due to higher long-term debt.

Capitalized interest increased $5 million for the second quarter of 2023 compared to 2022 primarily due to higher construction work-in-progress.

Allowance for equity funds increased $2 million for the second quarter of 2023 compared to 2022 primarily due to higher construction work-in-progress.

Interest and dividend income increased $10 million for the second quarter of 2023 compared to 2022 primarily due to favorable interest income, mainly from carrying charges on regulatory balances.

Other, net increased $5 million for the second quarter of 2023 compared to 2022 primarily due to favorable cash surrender value of corporate-owned life insurance policies.

Income tax expense decreased $3 million, or 30%, for the second quarter of 2023 compared to 2022 primarily due to lower pretax income. The effective tax rate was 10% in 2023 and 12% in 2022 and decreased primarily due to the effects of ratemaking.

First Six Months of 2023 Compared to First Six Months of 2022

Utility margin decreased $3 million, or 5%, for the first six months of 2023 compared to 2022 primarily due to:

•$18 million of lower electric retail utility margin primarily due to lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 1.2% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers.

The decrease in utility margin was offset by:

•$6 million of higher energy efficiency program rates (offset in operations and maintenance expense);

•$5 million of higher regulatory-related revenue deferrals; and

•$3 million of higher other retail revenue.

Operations and maintenance increased by $11 million, or 8%, for the first six months of 2023 compared to 2022 primarily due to increased plant operations and maintenance expenses, higher energy efficiency program costs (offset in operating revenue) and higher customer service operations expenses, partially offset by lower earnings sharing.

133

Depreciation and amortization increased $8 million, or 4%, for the first six months of 2023 compared to 2022 primarily due to higher plant placed in-service.

Property and other taxes increased $3 million, or 12%, for the first six months of 2023 compared to 2022 primarily due to a decrease in the amount of abatements available and an increase in commerce and franchise tax from higher revenue.

Interest expense increased $21 million, or 27%, for the first six months of 2023 compared to 2022 primarily due to higher long-term debt.

Capitalized interest increased $6 million for the first six months of 2023 compared to 2022 primarily due to higher construction work-in-progress.

Allowance for equity funds increased $3 million, or 60% for the first six months of 2023 compared to 2022 primarily due to higher construction work-in-progress.

Interest and dividend income increased $23 million for the first six months of 2023 compared to 2022 primarily due to favorable interest income, mainly from carrying charges on regulatory balances.

Other, net increased $8 million for the first six months of 2023 compared to 2022 primarily due to favorable cash surrender value of corporate-owned life insurance policies.

Income tax expense decreased $2 million, or 20%, for the first six months of 2023 compared to 2022 primarily due to lower pretax income. The effective tax rate was 10% in 2023 and 12% in 2022 and decreased primarily due to the effects of ratemaking.

Liquidity and Capital Resources

As of June 30, 2023, Nevada Power's total net liquidity was as follows (in millions):

Cash and cash equivalents	$	47
Credit facility	600
Total net liquidity	$	647
Credit facility:
Maturity date	2026

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022, were $232 million and $224 million, respectively. The change was primarily due to higher collections from customers, the timing of payments for operating costs and increased customer advance collections, partially offset by higher payments related to fuel and energy costs, lower cash received for income tax and higher interest payments.

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

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2023 and 2022, were $(619) million and $(350) million, respectively. The change was primarily due to increased capital expenditures, offset by the repayment of an affiliate note receivable. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the six-month periods ended June 30, 2023 and 2022, were $389 million and $136 million, respectively. The change was primarily due to contributions from NV Energy, Inc. and lower repayments of short-term debt, partially offset by lower proceeds from the issuance of long-term debt.

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Long-Term Debt

In March 2023, Nevada Power repurchased and entered into a re-offering of the following series of fixed-rate tax-exempt bonds: $40 million of its Coconino County, Arizona Pollution Control Corporation Revenue Bonds, Series 2017A, due 2032; $13 million of its Coconino County, Arizona Pollution Control Corporation Revenue Bonds, Series 2017B, due 2039; and $40 million of its Clark County, Nevada Revenue Bonds, Series 2017, due 2036. The Coconino Series 2017A bond was offered at a fixed rate of 4.125% and the Coconino Series 2017B and Clark Series 2017 bonds were offered at a fixed rate of 3.750%.

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 $3.8 billion (excluding borrowings under Nevada Power's $600 million secured credit facility); and (2) maintain a revolving credit facility of up to $1.3 billion. Nevada Power currently has an effective shelf registration statement with the SEC to issue up to $2.6 billion of general and refunding mortgage securities through November 2025.

Future Uses of Cash

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

Capital Expenditures

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customer 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.

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

	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2022		2023		2023
Electric distribution	$	108	$	148	$	315
Electric transmission	39		94		189
Solar generation	23		238		288
Electric battery storage	—		41		241
Other	180		198		367
Total	$	350	$	719	$	1,400

Nevada Power received PUCN approval through its previous IRP filings for an increase in solar generation and electric transmission and through the fourth amendment to its 2021 Joint IRP filing for the addition of peaking turbines at a generating facility. Nevada Power has included estimates from its previous and latest IRP filings in its forecast capital expenditures for 2023. 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.

135

•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program. Nevada Power has received approval from the PUCN to build a 350-mile, 525-kV transmission line connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line 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 substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substation. 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-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023 or early 2024.

•Electric battery storage includes two growth projects consisting of a 100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023 or early 2024. The second project is a 220-MW grid-tied battery energy storage system that will be developed on the site of the retired Reid Gardner generating facility in Clark County, Nevada. Commercial operation is expected by the end of 2023.

•Other includes both growth projects and operating expenditures. Growth projects primarily consist of an additional 400 MW of peaking combustion turbines that will be developed at the Silverhawk generating facility in Clark County, Nevada. Commercial operation is expected by the third quarter of 2024. Operating expenditures consist of turbine upgrades at several generating facilities, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.

Material Cash Requirements

As of June 30, 2023, there have been no material changes in 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, 2022, other than those disclosed in Note 4 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

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

Refer to "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, 2022. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2022.

136

Sierra Pacific Power Company and its subsidiaries

Consolidated Financial Section

137

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of June 30, 2023, the related consolidated statements of operations, and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for the six-month periods ended June 30, 2023 and 2022, 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, 2022, 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 24, 2023, 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, 2022, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

August 4, 2023

138

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)

	As of
	June 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	37	$	49
Trade receivables, net	165		175
Inventories	112		79
Regulatory assets	214		357
Other current assets	30		50
Total current assets	558		710
Property, plant and equipment, net	3,684		3,587
Regulatory assets	259		254
Other assets	183		181
Total assets	$	4,684	$	4,732
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	190	$	224
Note payable to affiliate	—		70
Accrued property, income and other taxes	51		15
Current portion of long-term debt	250		250
Derivative contracts	31		14
Other current liabilities	87		79
Total current liabilities	609		652
Long-term debt	899		898
Finance lease obligations	96		100
Regulatory liabilities	426		436
Deferred income taxes	416		445
Other long-term liabilities	143		153
Total liabilities	2,589		2,684
Commitments and contingencies (Note 9)
Shareholder's equity:
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding	—		—
Additional paid-in capital	1,576		1,576
Retained earnings	520		473
Accumulated other comprehensive loss, net	(1)		(1)
Total shareholder's equity	2,095		2,048
Total liabilities and shareholder's equity	$	4,684	$	4,732
The accompanying notes are an integral part of the consolidated financial statements.

139

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Operating revenue:
Regulated electric	$	293	$	230	$	597	$	457
Regulated natural gas	44		28		140		80
Total operating revenue	337		258		737		537
Operating expenses:
Cost of fuel and energy	179		129		360		253
Cost of natural gas purchased for resale	31		16		106		50
Operations and maintenance	49		47		105		88
Depreciation and amortization	46		37		92		73
Property and other taxes	6		6		13		12
Total operating expenses	311		235		676		476
Operating income	26		23		61		61
Other income (expense):
Interest expense	(15)		(14)		(31)		(27)
Allowance for borrowed funds	3		—		5		1
Allowance for equity funds	3		2		5		4
Interest and dividend income	5		4		12		7
Other, net	1		—		2		2
Total other income (expense)	(3)		(8)		(7)		(13)
Income before income tax expense (benefit)	23		15		54		48
Income tax expense (benefit)	3		2		7		7
Net income	$	20	$	13	$	47	$	41
The accompanying notes are an integral part of these consolidated financial statements.

140

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)

								Accumulated
				Additional				Other		Total
	Common Stock			Paid-in		Retained		Comprehensive		Shareholder's
	Shares	Amount		Capital		Earnings		Loss, Net		Equity
Balance, March 31, 2022	1,000	$	—	$	1,241	$	453	$	(1)	$	1,693
Net income	—	—		—		13		—		13
Dividends declared	—	—		—		(70)		—		(70)
Contributions	—	—		210		—		—		210
Balance, June 30, 2022	1,000	$	—	$	1,451	$	396	$	(1)	$	1,846
Balance, December 31, 2021	1,000	$	—	$	1,111	$	425	$	(1)	$	1,535
Net income	—	—		—		41		—		41
Dividends declared	—	—		—		(70)		—		(70)
Contributions	—	—		340		—		—		340
Balance, June 30, 2022	1,000	$	—	$	1,451	$	396	$	(1)	$	1,846
Balance, March 31, 2023	1,000	$	—	$	1,576	$	500	$	(1)	$	2,075
Net income	—	—		—		20		—		20
Balance, June 30, 2023	1,000	$	—	$	1,576	$	520	$	(1)	$	2,095
Balance, December 31, 2022	1,000	$	—	$	1,576	$	473	$	(1)	$	2,048
Net income	—	—		—		47		—		47
Balance, June 30, 2023	1,000	$	—	$	1,576	$	520	$	(1)	$	2,095
The accompanying notes are an integral part of these consolidated financial statements.

141

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2023		2022
Cash flows from operating activities:
Net income	$	47	$	41
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	92		73
Allowance for equity funds	(5)		(4)
Changes in regulatory assets and liabilities	8		(8)
Deferred income taxes and amortization of investment tax credits	(38)		5
Deferred energy	61		(67)
Amortization of deferred energy	77		46
Other, net	(1)		2
Changes in other operating assets and liabilities:
Trade receivables and other assets	9		(1)
Inventories	(34)		(10)
Accrued property, income and other taxes	49		3
Accounts payable and other liabilities	(33)		28
Net cash flows from operating activities	232		108
Cash flows from investing activities:
Capital expenditures	(170)		(191)
Net cash flows from investing activities	(170)		(191)
Cash flows from financing activities:
Proceeds from long-term debt	—		249
Long-term debt reacquired	—		(265)
Net repayments from short-term debt	—		(159)
Dividends paid	—		(70)
Contributions from parent	—		340
Repayments of affiliate note payable	(70)		—
Other, net	(4)		(4)
Net cash flows from financing activities	(74)		91
Net change in cash and cash equivalents and restricted cash and cash equivalents	(12)		8
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	56		16
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	44	$	24
The accompanying notes are an integral part of these consolidated financial statements.

142

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 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 June 30, 2023, and for the three- and six-month periods ended June 30, 2023 and 2022. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and six-month periods ended June 30, 2023 and 2022. The results of operations for the three- and six-month periods ended June 30, 2023, 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, 2022, 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 accounting policies or its assumptions regarding significant accounting estimates during the six-month period ended June 30, 2023.

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

Cash equivalents consist of funds invested in money market mutual funds, 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 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 presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):

	As of
	June 30,		December 31,
	2023		2022
Cash and cash equivalents	$	37	$	49
Restricted cash and cash equivalents included in other current assets	7		7
Total cash and cash equivalents and restricted cash and cash equivalents	$	44	$	56

143

(3)    Property, Plant and Equipment, Net

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

		As of
	Depreciable Life	June 30,		December 31,
		2023		2022
Utility plant:
Electric generation	25 - 70 years	$	1,308	$	1,298
Electric transmission	50 - 76 years	998		993
Electric distribution	20 - 76 years	2,015		1,983
Electric general and intangible plant	5 - 65 years	225		219
Natural gas distribution	35 - 70 years	465		455
Natural gas general and intangible plant	5 - 65 years	16		15
Common general	5 - 65 years	385		380
Utility plant		5,412		5,343
Accumulated depreciation and amortization		(2,058)		(1,992)
		3,354		3,351
Construction work-in-progress		330		236
Property, plant and equipment, net		$	3,684	$	3,587

During 2022, Sierra Pacific revised its electric and gas depreciation rates effective January 2023 based on the results of a new depreciation study, the most significant impact of which was shorter average service lives for intangible software. The net effect of this change along with various changes to the average service lives of other utility plant groups will increase depreciation and amortization expense by $19 million annually based on depreciable plant balances at the time of the change.

(4)    Recent Financing Transactions

Credit Facilities

In June 2023, Sierra Pacific amended its existing $250 million secured credit facility expiring in June 2025. The amendment increased the commitment of the lenders to $400 million and extended the expiration date to June 2026.

(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 (benefit) is as follows:

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Effects of ratemaking	(9)		(8)		(9)		(7)
Other	1		—		1		1
Effective income tax rate	13	%	13	%	13	%	15	%

Effects of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to 2017 tax reform pursuant to an order issued by the PUCN effective January 1, 2020.

Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, Sierra Pacific's provision for federal income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. For the six-month periods ended June 30, 2023 and 2022, Sierra Pacific made no cash payments for federal income tax to BHE.

144

(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 $2 million to the Other Post Retirement Plans for the six-month period ended June 30, 2023. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.

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

	As of
	June 30,		December 31,
	2023		2022
Qualified Pension Plan:
Other non-current assets	$	44	$	43
Non-Qualified Pension Plans:
Other current liabilities	(1)		(1)
Other long-term liabilities	(5)		(5)
Other Postretirement Plans:
Other long-term liabilities	—		(2)

(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.

145

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):

	Other				Other
	Current		Current		Long-term
	Assets		Liabilities		Liabilities		Total
As of June, 30 2023
Not designated as hedging contracts(1) -
Total derivatives - commodity liabilities	$	—	$	(31)	$	(5)	$	(36)
As of December 31, 2022
Not designated as hedging contracts(1):
Commodity assets	$	8	$	—	$	—	$	8
Commodity liabilities	—		(14)		(7)		(21)
Total derivatives - net basis	$	8	$	(14)	$	(7)	$	(13)

(1)Sierra Pacific's commodity derivatives not designated as hedging contracts are included in regulated rates. As of June 30, 2023 a net regulatory asset of $36 million was recorded related to the net derivative liability of $36 million. As of December 31, 2022 a net regulatory asset of $13 million was recorded related to the net derivative liability of $13 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	June 30,	December 31,
	Measure	2023	2022
Electricity purchases	Megawatt hours	1	1
Natural gas purchases	Decatherms	56	52

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 June 30, 2023, 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.

146

The aggregate fair value of Sierra Pacific's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $1 million and $— million as of June 30, 2023 and December 31, 2022, 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 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 Sierra Pacific has the ability to access at the measurement date.

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

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

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

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Total
As of June 30, 2023:
Assets:
Money market mutual funds	$	36	—		—		$	36
Investment funds	1		—		—		1
	$	37	$	—	$	—	$	37
Liabilities - commodity derivatives	$	—	$	—	$	(36)	$	(36)
As of December 31, 2022:
Assets:
Commodity derivatives	$	—	$	—	$	8	$	8
Money market mutual funds	49		—		—		49
Investment funds	1		—		—		1
	$	50	$	—	$	8	$	58
Liabilities - commodity derivatives	$	—	$	—	$	(21)	$	(21)

147

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 Sierra Pacific transacts. When quoted prices for identical contracts are not available, Sierra Pacific uses forward price curves. Forward price curves represent Sierra Pacific's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Sierra Pacific 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, Sierra Pacific 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 Sierra Pacific's nonperformance risk on its liabilities, which as of June 30, 2023 and December 31, 2022, had an immaterial impact to the fair value of its derivative contracts. As such, Sierra Pacific considers its derivative contracts to be valued using Level 3 inputs.

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.

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				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Beginning balance	$	(33)	$	(52)	$	(13)	$	(33)
Changes in fair value recognized in regulatory assets	(17)		(7)		(37)		(26)
Settlements	14		5		14		5
Ending balance	$	(36)	$	(54)	$	(36)	$	(54)

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

	As of June 30, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	1,149	$	1,108	$	1,148	$	1,111

(9)    Commitments and Contingencies

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.

148

Legal Matters

Sierra Pacific is party to a variety of legal actions arising out of the normal course of business. Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

(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 11 (in millions):

	Three-Month Periods
	Ended June 30,
	2023						2022
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Customer Revenue:
Retail:
Residential	$	95	$	25	$	120	$	79	$	19	$	98
Commercial	102		12		114		82		6		88
Industrial	82		6		88		53		3		56
Other	1		—		1		1		—		1
Total fully bundled	280		43		323		215		28		243
Distribution only service	1		—		1		1		—		1
Total retail	281		43		324		216		28		244
Wholesale, transmission and other	12		—		12		14		—		14
Total Customer Revenue	293		43		336		230		28		258
Other revenue	—		1		1		—		—		—
Total operating revenue	$	293	$	44	$	337	$	230	$	28	$	258

	Six-Month Periods
	Ended June 30,
	2023						2022
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Customer Revenue:
Retail:
Residential	$	210	$	85	$	295	$	162	$	51	$	213
Commercial	193		39		232		151		21		172
Industrial	145		15		160		102		7		109
Other	3		—		3		3		—		3
Total fully bundled	551		139		690		418		79		497
Distribution only service	2		—		2		3		—		3
Total retail	553		139		692		421		79		500
Wholesale, transmission and other	44		—		44		35		—		35
Total Customer Revenue	597		139		736		456		79		535
Other revenue	—		1		1		1		1		2
Total operating revenue	$	597	$	140	$	737	$	457	$	80	$	537

149

(11)    Segment Information

Sierra Pacific has identified two reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by the PUCN; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance.

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Operating revenue:
Regulated electric	$	293	$	230	$	597	$	457
Regulated natural gas	44		28		140		80
Total operating revenue	$	337	$	258	$	737	$	537
Operating income:
Regulated electric	$	23	$	19	$	48	$	49
Regulated natural gas	3		4		13		12
Total operating income	26		23		61		61
Interest expense	(15)		(14)		(31)		(27)
Allowance for borrowed funds	3		—		5		1
Allowance for equity funds	3		2		5		4
Interest and dividend income	5		4		12		7
Other, net	1		—		2		2
Total income before income tax expense (benefit)	$	23	$	15	$	54	$	48

	As of
	June 30,		December 31,
	2023		2022
Assets:
Regulated electric	$	4,182	$	4,224
Regulated natural gas	444		441
Other(1)	58		67
Total assets	$	4,684	$	4,732

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

150

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

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

Results of Operations for the Second Quarter and First Six Months of 2023 and 2022

Overview

Net income for the second quarter of 2023 was $20 million, an increase of $7 million, or 54%, compared to 2022 primarily due to higher utility margin and higher allowance for borrowed funds, primarily due to increased construction work-in-progress, partially offset by higher depreciation and amortization, mainly due to increased plant placed in-service and higher regulatory amortizations. Electric utility margin increased primarily due to higher retail rates due to the 2022 regulatory rate review with new rates effective January 2023, partially offset by lower customer volumes and lower transmission and wholesale revenue. Electric retail customer volumes, including distribution only service customers, decreased by 7.4% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers. Energy generated decreased 1% for the second quarter of 2023 compared to 2022 primarily due to lower coal-fueled generation offset by higher natural gas-fueled generation. Wholesale electricity sales volumes increased 15% and purchased electricity volumes decreased 23%.

Net income for the first six months of 2023 was $47 million, an increase of $6 million, or 15%, compared to 2022 primarily due to higher utility margin and higher interest and dividend income, primarily from carrying charges on regulatory balances, partially offset by higher depreciation and amortization, mainly due to increased plant placed in-service and higher regulatory amortizations, and increased operations and maintenance expenses, mainly due to higher plant operations and maintenance expenses and increased customer service operations expenses. Electric utility margin increased primarily due to higher retail rates due to the 2022 regulatory rate review with new rates effective January 2023 and higher transmission and wholesale revenue, partially offset by lower customer volumes. Electric retail customer volumes, including distribution only service customers, decreased by 2.6% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers. Energy generated increased 5% for the first six months of 2023 compared to 2022 primarily due to higher natural gas-fueled generation offset by lower coal-fueled generation. Wholesale electricity sales volumes decreased 11% and purchased electricity volumes decreased 22%.

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.

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

	Second Quarter								First Six Months
	2023		2022		Change				2023		2022		Change
Electric utility margin:
Operating revenue	$	293	$	230	$	63	27	%	$	597	$	457	$	140	31	%
Cost of fuel and energy	179		129		50		39		360		253		107		42
Electric utility margin	114		101		13		13	%	237		204		33		16	%
Natural gas utility margin:
Operating revenue	44		28		16		57	%	140		80		60		75	%
Natural gas purchased for resale	31		16		15		94	%	106		50		56		*
Natural gas utility margin	13		12		1		8	%	34		30		4		13	%
Utility margin	127		113		14		12	%	271		234		37		16	%
Operations and maintenance	49		47		2		4	%	105		88		17		19	%
Depreciation and amortization	46		37		9		24		92		73		19		26
Property and other taxes	6		6		—		—		13		12		1		8
Operating income	$	26	$	23	$	3	13	%	$	61	$	61	$	—	—	%

*    Not meaningful

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Electric Utility Margin

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

	Second Quarter								First Six Months
	2023		2022		Change				2023		2022		Change
Utility margin (in millions):
Operating revenue	$	293	$	230	$	63	27	%	$	597	$	457	$	140	31	%
Cost of fuel and energy	179		129		50		39		360		253		107		42
Utility margin	$	114	$	101	$	13	13	%	$	237	$	204	$	33	16	%
Sales (GWhs):
Residential	539		573		(34)		(6)	%	1,271		1,236		35		3	%
Commercial	735		778		(43)		(6)		1,456		1,478		(22)		(1)
Industrial	671		721		(50)		(7)		1,317		1,476		(159)		(11)
Other	3		3		—		—		6		7		(1)		(14)
Total fully bundled(1)	1,948		2,075		(127)		(6)		4,050		4,197		(147)		(4)
Distribution only service	670		752		(82)		(11)		1,338		1,337		1		—
Total retail	2,618		2,827		(209)		(7)		5,388		5,534		(146)		(3)
Wholesale	131		114		17		15		360		405		(45)		(11)
Total GWhs sold	2,749		2,941		(192)		(7)	%	5,748		5,939		(191)		(3)	%
Average number of retail customers (in thousands)	375		370		5		1	%	374		370		4		1	%
Average revenue per MWh:
Retail - fully bundled(1)	$	143.34	$	103.25	$	40.09	39	%	$	135.89	$	99.79	$	36.10	36	%
Wholesale	$	48.67	$	65.84	$	(17.17)	(26)	%	$	86.26	$	55.28	$	30.98	56	%
Heating degree days	586		661		(75)		(11)	%	3,238		2,698		540		20	%
Cooling degree days	135		214		(79)		(37)	%	135		214		(79)		(37)	%
Sources of energy (GWhs)(2):
Natural gas	895		707		188		27	%	1,961		1,697		264		16	%
Coal	152		352		(200)		(57)		353		505		(152)		(30)
Renewables	9		8		1		13		13		13		—		—
Total energy generated	1,056		1,067		(11)		(1)		2,327		2,215		112		5
Energy purchased	1,227		1,590		(363)		(23)		2,050		2,623		(573)		(22)
Total	2,283		2,657		(374)		(14)	%	4,377		4,838		(461)		(10)	%
Average cost of energy per MWh(3):
Energy generated	$	62.36	$	47.59	$	14.77	31	%	$	84.21	$	53.95	$	30.26	56	%
Energy purchased	$	92.08	$	49.73	$	42.35	85	%	$	79.75	$	51.09	$	28.66	56	%

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

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

(3)    The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.

153

Natural Gas Utility Margin

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

	Second Quarter								First Six Months
	2023		2022		Change				2023		2022		Change
Utility margin (in millions):
Operating revenue	$	44	$	28	$	16	57	%	$	140	$	80	$	60	75	%
Natural gas purchased for resale	31		16		15		94	%	106		50		56		*
Utility margin	$	13	$	12	$	1	8	%	$	34	$	30	$	4	13	%
Sold (000's Dths):
Residential	1,843		1,797		46		3	%	7,709		6,349		1,360		21	%
Commercial	985		751		234		31		3,923		3,263		660		20
Industrial	581		402		179		45		1,647		1,055		592		56
Total retail	3,409		2,950		459		16	%	13,279		10,667		2,612		24	%
Average number of retail customers (in thousands)	182		179		3		2	%	182		179		3		2	%
Average revenue per retail Dth sold	$	12.79	$	9.47	$	3.32	35	%	$	10.52	$	7.46	$	3.06	42	%
Heating degree days	586		661		(75)		(11)	%	3,238		2,698		540		20	%
Average cost of natural gas per retail Dth sold	$	9.01	$	5.48	$	3.53	64	%	$	7.98	$	4.67	$	3.32	71	%

*    Not meaningful

Quarter Ended June 30, 2023 Compared to Quarter Ended June 30, 2022

Electric utility margin increased $13 million, or 13%, for the second quarter of 2023 compared to 2022 primarily due to:

•$14 million of higher retail rates due to the 2022 regulatory rate review with new rates effective January 2023, offset by lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 7.4% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers.

The increase in electric utility margin was offset by:

•$1 million of lower transmission and wholesale revenue.

Operations and maintenance increased $2 million, or 4%, for the second quarter of 2023 compared to 2022 primarily due to higher plant operations and maintenance expenses and increased customer service operations expenses, partially offset by lower regulatory-approved recovery for the ON Line reallocation (offset in operating revenue).

Depreciation and amortization increased $9 million, or 24%, for the second quarter of 2023 compared to 2022 primarily due to increased plant placed in-service and higher regulatory amortizations.

Allowance for borrowed funds increased $3 million for the second quarter of 2023 compared to 2022 primarily due to higher construction work-in-progress.

First Six Months of 2023 Compared to First Six Months of 2022

Electric utility margin increased $33 million, or 16%, for the first six months of 2023 compared to 2022 primarily due to:

•$28 million of higher retail rates due to the 2022 regulatory rate review with new rates effective January 2023, offset by lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 2.6% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers and

154

•$6 million of higher transmission and wholesale revenue.

Natural gas utility margin increased $4 million, or 13%, for the first six months of 2023 compared to 2022 primarily due to higher customer volumes from the favorable impact of weather.

Operations and maintenance increased $17 million, or 19%, for the first six months of 2023 compared to 2022 primarily due to higher plant operations and maintenance expenses, increased customer service operations expenses and higher regulatory-approved amortization from the recovery for the ON Line reallocation (offset in operating revenue).

Depreciation and amortization increased $19 million, or 26%, for the first six months of 2023 compared to 2022 primarily due to higher plant placed in-service and higher regulatory amortizations.

Interest expense increased $4 million, or 15%, for the first six months of 2023 compared to 2022 primarily due to higher interest rates.

Allowance for borrowed funds increased $4 million for the first six months of 2023 compared to 2022 primarily due to higher construction work-in-progress.

Interest and dividend income increased $5 million, or 71%, for the first six months of 2023 compared to 2022 primarily due to higher interest income, mainly from carrying charges on regulatory balances.

Liquidity and Capital Resources

As of June 30, 2023, Sierra Pacific's total net liquidity was as follows (in millions):

Cash and cash equivalents	$	37
Credit facility	400
Total net liquidity	$	437
Credit facility:
Maturity date	2026

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022, were $232 million and $108 million, respectively. The change was primarily due to higher collections from customers, partially offset by higher payments related to fuel and energy costs and the timing of payments for operating costs.

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

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2023 and 2022, were $(170) million and $(191) million, respectively. The change was primarily due to decreased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the six-month periods ended June 30, 2023 and 2022, were $(74) million and $91 million, respectively. The change was primarily due to lower contributions from NV Energy, Inc., lower proceeds from the issuance of long-term debt and higher repayments of an affiliate note payable, partially offset by lower long-term debt reacquired, lower repayments of short-term debt and lower dividends paid to NV Energy, Inc.

155

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 $1.9 billion (excluding borrowings under Sierra Pacific's $400 million secured credit facility); and (2) maintain a revolving credit facility of up to $600 million.

Future Uses of Cash

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

Capital Expenditures

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customer 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.

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

	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2022		2023		2023
Electric distribution	$	46	$	72	$	166
Electric transmission	45		47		98
Solar generation	—		1		1
Electric battery storage	—		2		3
Other	100		48		126
Total	$	191	$	170	$	394

Sierra Pacific received PUCN approval through its previous IRP 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 2023. 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.

•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program. Sierra Pacific has received approval from the PUCN to build a 350-mile, 525-kV transmission line connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line 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 substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substation. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.

•Other 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.

156

Material Cash Requirements

As of June 30, 2023, there have been no material changes outside the normal course of business in 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, 2022.

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

Refer to "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, 2022. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2022.

157

Eastern Energy Gas Holdings, LLC and its subsidiaries

Consolidated Financial Section

158

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Eastern Energy Gas Holdings, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Eastern Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of June 30, 2023, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for the six-month periods ended June 30, 2023 and 2022, 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, 2022, 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 24, 2023, 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, 2022, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Richmond, Virginia

August 4, 2023

159

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	82	$	65
Trade receivables, net	153		202
Receivables from affiliates	21		30
Notes receivable from affiliates	449		536
Inventories	134		127
Prepayments and other deferred charges	31		78
Natural gas imbalances	28		193
Other current assets	70		72
Total current assets	968		1,303
Property, plant and equipment, net	10,309		10,202
Goodwill	1,286		1,286
Investments	278		278
Other assets	90		95
Total assets	$	12,931	$	13,164

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

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EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	June 30, 2023		December 31, 2022
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	40	$	86
Accounts payable to affiliates	1		10
Accrued property, income and other taxes	65		77
Regulatory liabilities	37		126
Current portion of long-term debt	400		649
Other current liabilities	145		165
Total current liabilities	688		1,113
Long-term debt	3,248		3,243
Regulatory liabilities	597		596
Other long-term liabilities	354		324
Total liabilities	4,887		5,276
Commitments and contingencies (Note 9)
Equity:
Member's equity:
Membership interests	4,152		3,983
Accumulated other comprehensive loss, net	(38)		(42)
Total member's equity	4,114		3,941
Noncontrolling interests	3,930		3,947
Total equity	8,044		7,888
Total liabilities and equity	$	12,931	$	13,164

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

161

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Operating revenue	$	521	$	504	$	1,074	$	986
Operating expenses:
Cost of (excess) gas	5		(21)		25		(22)
Operations and maintenance	134		124		277		242
Depreciation and amortization	80		80		160		165
Property and other taxes	26		37		63		66
Total operating expenses	245		220		525		451
Operating income	276		284		549		535
Other income (expense):
Interest expense	(35)		(36)		(72)		(72)
Allowance for equity funds	2		1		4		3
Interest and dividend income	11		—		20		—
Other, net	1		—		1		(1)
Total other income (expense)	(21)		(35)		(47)		(70)
Income before income tax expense (benefit) and equity income (loss)	255		249		502		465
Income tax expense (benefit)	31		37		70		67
Equity income (loss)	6		9		38		28
Net income	230		221		470		426
Net income attributable to noncontrolling interests	131		118		249		229
Net income attributable to Eastern Energy Gas	$	99	$	103	$	221	$	197

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

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EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Net income	$	230	$	221	$	470	$	426
Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $—, $—, $— and $—	—		—		(1)		1
Unrealized gains (losses) on cash flow hedges, net of tax of $4, $—, $3 and $1	7		(1)		5		3
Total other comprehensive income (loss), net of tax	7		(1)		4		4
Comprehensive income	237		220		474		430
Comprehensive income attributable to noncontrolling interests	131		118		249		229
Comprehensive income attributable to Eastern Energy Gas	$	106	$	102	$	225	$	201

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

163

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)

			Accumulated
			Other
	Membership		Comprehensive		Noncontrolling		Total
	Interests		Loss, Net		Interests		Equity
Balance, March 31, 2022	$	3,595	$	(38)	$	4,033	$	7,590
Net income	103		—		118		221
Other comprehensive loss	—		(1)		—		(1)
Distributions	(33)		—		(128)		(161)
Contributions	68		—		—		68
Balance, June 30, 2022	$	3,733	$	(39)	$	4,023	$	7,717
Balance, December 31, 2021	$	3,501	$	(43)	$	4,036	$	7,494
Net income	197		—		229		426
Other comprehensive income	—		4		—		4
Distributions	(33)		—		(242)		(275)
Contributions	68		—		—		68
Balance, June 30, 2022	$	3,733	$	(39)	$	4,023	$	7,717
Balance, March 31, 2023	$	4,109	$	(45)	$	3,941	$	8,005
Net income	99		—		131		230
Other comprehensive income	—		7		—		7
Distributions	(79)		—		(142)		(221)
Contributions	23		—		—		23
Balance, June 30, 2023	$	4,152	$	(38)	$	3,930	$	8,044
Balance, December 31, 2022	$	3,983	$	(42)	$	3,947	$	7,888
Net income	221		—		249		470
Other comprehensive income	—		4		—		4
Distributions	(85)		—		(266)		(351)
Contributions	33		—		—		33
Balance, June 30, 2023	$	4,152	$	(38)	$	3,930	$	8,044

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

164

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2023		2022
Cash flows from operating activities:
Net income	$	470	$	426
Adjustments to reconcile net income to net cash flows from operating activities:
(Gains) losses on other items, net	(7)		2
Depreciation and amortization	160		165
Allowance for equity funds	(4)		(3)
Equity loss (income), net of distributions	2		(5)
Changes in regulatory assets and liabilities	(92)		(2)
Deferred income taxes	47		52
Other, net	—		5
Changes in other operating assets and liabilities:
Trade receivables and other assets	89		26
Receivables from affiliates	8		32
Gas balancing activities	17		(22)
Derivative collateral, net	2		(3)
Accrued property, income and other taxes	6		(3)
Accounts payable to affiliates	(9)		(32)
Accounts payable and other liabilities	(45)		43
Net cash flows from operating activities	644		681
Cash flows from investing activities:
Capital expenditures	(124)		(151)
Proceeds from assignment of shale development rights	8		—
Repayment of notes by affiliates	252		15
Notes to affiliates	(166)		(204)
Other, net	(3)		(7)
Net cash flows from investing activities	(33)		(347)
Cash flows from financing activities:
Repayments of long-term debt	(250)		—
Distributions to noncontrolling interests	(266)		(242)
Distributions to parent	(78)		—
Net cash flows from financing activities	(594)		(242)
Net change in cash and cash equivalents and restricted cash and cash equivalents	17		92
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	95		39
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	112	$	131

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

165

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") conducts business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transmission systems and underground storage operations in the eastern region of the 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 partner interests 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 transmission system. Eastern Energy Gas 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 the energy industry. BHE is a consolidated subsidiary of Berkshire Hathaway Inc.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of June 30, 2023 and for the three- and six-month periods ended June 30, 2023 and 2022. The results of operations for the three- and six-month periods ended June 30, 2023 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2022 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' accounting policies or its assumptions regarding significant accounting estimates during the six-month period ended June 30, 2023.

(2)    Business Acquisitions

On July 9, 2023, BHE and Eastern MLP Holding Company II, LLC ("the Buyer"), an indirect wholly owned subsidiary of Eastern Energy Gas, entered into a Purchase and Sale Agreement (the "Purchase Agreement") with Dominion Energy, Inc. ("DEI") and DECP Holdings, Inc. (the "Seller"), an indirect wholly owned subsidiary of DEI, to purchase (the "Transaction") Seller's 50% limited partner interests in Cove Point for a cash purchase price of $3.3 billion, plus the pro rata portion of any quarterly distribution made by Cove Point for the fiscal quarter in which the Transaction closes. Eastern Energy Gas expects to fund the purchase price with equity contributions from BHE. Upon the completion of the Transaction, the Buyer will own an aggregate of 75% of the limited partner interests, and its affiliate, Cove Point GP Holding Company, LLC, will continue to own 100% of the general partner interest, of Cove Point.

The consummation of the Transaction contemplated by the Purchase Agreement is subject to customary closing conditions, including without limitation (i) the expiration or termination of any applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (ii) the filing of a notification with the U.S. Department of Energy and the expiration of any applicable period; and (iii) the accuracy of the representations and warranties and compliance by the parties in all material respects with their respective obligations under the Purchase Agreement. The Transaction is expected to close by year-end 2023, subject to satisfaction of the foregoing conditions, among other things.

The Purchase Agreement provides that if the Seller or DEI terminates the Purchase agreement due to a breach of the Purchase Agreement by the Buyer or Buyer's failure to consummate the Transaction within three business days after all of the conditions to close have been satisfied or waived, BHE will pay to the Seller a termination fee of $150 million.

166

(3)    Property, Plant and Equipment, Net

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

		As of
		June 30,		December 31,
	Depreciable Life	2023		2022
Utility plant:
Interstate natural gas transmission and storage assets	21 - 51 years	$	9,132	$	8,922
Intangible plant	5 - 17 years	116		113
Utility plant in-service		9,248		9,035
Accumulated depreciation and amortization		(3,118)		(3,039)
Utility plant in-service, net		6,130		5,996
Nonutility plant:
LNG facility	40 years	4,526		4,522
Intangible plant	14 years	25		25
Nonutility plant		4,551		4,547
Accumulated depreciation and amortization		(605)		(542)
Nonutility plant, net		3,946		4,005
		10,076		10,001
Construction work-in-progress		233		201
Property, plant and equipment, net		$	10,309	$	10,202

Construction work-in-progress includes $218 million and $181 million as of June 30, 2023 and December 31, 2022, respectively, related to the construction of utility plant.

Assignment of Shale Development Rights

In June 2023, Eastern Gas Transmission and Storage, Inc. ("EGTS") conveyed development rights to a natural gas producer for approximately 6,500 acres of Utica Shale and Point Pleasant Formation underneath one of its natural gas storage fields and received proceeds of $8 million and an overriding royalty interest in gas produced from the acreage. This transaction resulted in an $8 million ($6 million after-tax) gain, included in operations and maintenance expense in its Consolidated Statements of Operations.

(4)    Regulatory Matters

In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. 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 transmission 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. In September 2022, a settlement agreement was filed with the FERC, which provided for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual firm transmission and storage services revenues of approximately $160 million and a decrease in annual depreciation expense of approximately $30 million, compared to the rates in effect prior to April 1, 2022. EGTS' provision for rate refund for April 2022 through February 2023, including accrued interest, totaled $91 million. In November 2022, the FERC approved the settlement agreement and the rate refunds to customers were processed in late February 2023.

167

(5)    Investments and Restricted Cash and Cash Equivalents

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

	As of
	June 30,		December 31,
	2023		2022
Investments:
Investment funds	$	18	$	14
Equity method investments:
Iroquois	260		264
Total investments	278		278
Restricted cash and cash equivalents:
Customer deposits	30		30
Total restricted cash and cash equivalents	30		30
Total investments and restricted cash and cash equivalents	$	308	$	308
Reflected as:
Current assets	$	30	$	30
Noncurrent assets	278		278
Total investments and restricted cash and cash equivalents	$	308	$	308

Equity Method Investments

Eastern Energy Gas, through subsidiaries, owns 50% of Iroquois, which owns and operates an interstate natural gas transmission system located in the states of New York and Connecticut.

As of June 30, 2023 and December 31, 2022, 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 $40 million and $23 million for the six-month periods ended June 30, 2023 and 2022, respectively.

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, 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 of customer deposits as allowed under the FERC gas tariffs. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):

	As of
	June 30,		December 31,
	2023		2022
Cash and cash equivalents	$	82	$	65
Restricted cash and cash equivalents included in other current assets	30		30
Total cash and cash equivalents and restricted cash and cash equivalents	$	112	$	95

168

(6)    Income Taxes

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Federal statutory income tax rate	21	%	21	%	21	%	21	%
State income tax, net of federal income tax benefit	2		3		2		4
Equity interest	1		1		1		1
Effects of ratemaking	—		—		—		(2)
Noncontrolling interest	(11)		(10)		(10)		(10)
Other, net	(1)		—		—		—
Effective income tax rate	12	%	15	%	14	%	14	%

For the period ended June 30, 2023, Eastern Energy Gas' reconciliation of the federal statutory income tax rate to the effective income tax rate is driven primarily by an absence of tax on income attributable to Cove Point's 75% noncontrolling interest.

(7)    Employee Benefit Plans

Eastern Energy Gas is a participant in benefit plans sponsored by MidAmerican Energy Company ("MidAmerican Energy"), an affiliate. The MidAmerican Energy Company Retirement Plan includes a qualified pension plan that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain postretirement health care and life insurance benefits for eligible retirees on behalf of Eastern Energy Gas. Eastern Energy Gas contributed $4 million and $6 million to the MidAmerican Energy Company Retirement Plan for the six-month periods ended June 30, 2023 and 2022, respectively, and $1 million to the MidAmerican Energy Company Welfare Benefit Plan for the six-month periods ended June 30, 2023 and 2022. Contributions related to these plans are reflected as net periodic benefit cost in operations and maintenance expense on the Consolidated Statements of Operations. Amounts attributable to Eastern Energy Gas were allocated from MidAmerican Energy in accordance with the intercompany administrative service agreement. 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. As of June 30, 2023 and December 31, 2022, 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 $51 million.

(8)    Fair Value Measurements

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

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

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

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

169

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

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Total
As of June 30, 2023:
Assets:
Money market mutual funds	$	95	$	—	$	—	$	95
Equity securities:
Investment funds	18		—		—		18
	$	113	$	—	$	—	$	113
Liabilities:
Commodity derivatives	$	—	$	(1)	$	—	$	(1)
Foreign currency exchange rate derivatives	—		(11)		—		(11)
	$	—	$	(12)	$	—	$	(12)
As of December 31, 2022:
Assets:
Commodity derivatives	$	—	$	1	$	—	$	1
Money market mutual funds	42		—		—		42
Equity securities:
Investment funds	14		—		—		14
	$	56	$	1	$	—	$	57
Liabilities:
Foreign currency exchange rate derivatives	$	—	$	(20)	$	—	$	(20)
	$	—	$	(20)	$	—	$	(20)

Eastern Energy Gas' 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.

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.

170

Eastern Energy Gas' long-term debt is carried at cost on the Consolidated 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 June 30, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	3,648	$	3,295	$	3,892	$	3,510

(9)    Commitments and Contingencies

Environmental Laws and Regulations

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

Legal Matters

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

(10)    Revenue from Contracts with Customers

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Customer Revenue:
Regulated:
Gas transmission and storage	$	294	$	286	$	626	$	571
Other	(1)		—		1		—
Total regulated	293		286		627		571
Nonregulated	226		216		443		419
Total Customer Revenue	519		502		1,070		990
Other revenue(1)	2		2		4		(4)
Total operating revenue	$	521	$	504	$	1,074	$	986

(1)Other revenue consists primarily of revenue recognized in accordance with Accounting Standards Codification 815, "Derivative and Hedging" and includes unrealized gains and losses for derivatives not designated as hedges related to natural gas sales contracts.

Eastern Energy Gas has recognized contract liabilities of $35 million and $80 million as of June 30, 2023 and December 31, 2022, respectively, due to the relationship between Eastern Energy Gas' performance and the customer's payment. Eastern Energy Gas recognizes revenue as it fulfills its obligations to provide services to its customers. During the six-month period ended June 30, 2023, Eastern Energy Gas recognized revenue of $49 million from the beginning contract liability balance.

171

Remaining Performance Obligations

The following table summarizes Eastern Energy Gas' revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of June 30, 2023 (in millions):

	Performance obligations expected to be satisfied
	Less than 12 months		More than 12 months		Total
Eastern Energy Gas	$	1,662	$	15,132	$	16,794

(11)    Components of Accumulated Other Comprehensive Loss, Net

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

	Unrecognized						Accumulated
	Amounts On		Unrealized				Other
	Retirement		Losses on Cash		Noncontrolling		Comprehensive
	Benefits		Flow Hedges		Interests		Loss, Net
Balance, December 31, 2021	$	(6)	$	(42)	$	5	$	(43)
Other comprehensive income	1		3		—		4
Balance, June 30, 2022	$	(5)	$	(39)	$	5	$	(39)
Balance, December 31, 2022	$	(1)	$	(43)	$	2	$	(42)
Other comprehensive (loss) income	(1)		5		—		4
Balance, June 30, 2023	$	(2)	$	(38)	$	2	$	(38)

172

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

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Eastern Energy Gas during the periods included herein. This discussion should be read in conjunction with Eastern Energy Gas' historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Eastern Energy Gas' actual results in the future could differ significantly from the historical results.

Results of Operations for the Second Quarter and First Six Months of 2023 and 2022

Overview

Net income attributable to Eastern Energy Gas for the second quarter of 2023 was $99 million, a decrease of $4 million, or 4%, compared to 2022. Net income decreased primarily due to lower margin from EGTS' regulated gas transmission and storage operations of $24 million, partially offset by lower than estimated 2022 tax assessments and a gain from an agreement to convey development rights underneath one of its natural gas storage fields.

Net income attributable to Eastern Energy Gas for the first six months of 2023 was $221 million, an increase of $24 million, or 12%, compared to 2022. Net income increased primarily due to interest income from higher outstanding loans and higher interest rates under BHE GT&S' intercompany revolving credit agreement with Eastern Energy Gas, higher earnings from Iroquois due to favorable negotiated rate agreements and hedges, a gain from an agreement to convey development rights underneath one of its natural gas storage fields, lower depreciation rates due to the settlement in EGTS' general rate case, higher margin from EGTS' regulated gas transmission and storage operations of $8 million and additional LNG revenues from Cove Point of $8 million, partially offset by higher technology and related charges and an increase in salaries, wages and benefits.

Quarter Ended June 30, 2023 Compared to Quarter Ended June 30, 2022

Operating revenue increased $17 million, or 3%, for the second quarter of 2023 compared to 2022, primarily due to increased LNG revenues as a result of the timing of the release of contract liabilities from scheduled outage days in 2022 of $22 million, an increase in variable revenue related to park and loan activity of $10 million and an increase in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of $8 million, partially offset by a net decrease in regulated gas transmission and storage services revenues due to volumes primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $11 million and a decrease in Cove Point LNG variable revenue of $5 million.

Cost of (excess) gas was an expense of $5 million for the second quarter of 2023 compared to a credit of $21 million for the second quarter of 2022. The change is primarily from a decrease in other operational and system balancing fuel activities prior to the effective date of the new fuel tracker due to the settlement of EGTS' general rate case of $14 million and the unfavorable revaluation of the volumes retained prior to the effective date of the new fuel tracker due to lower natural gas prices of $12 million.

Operations and maintenance increased $10 million, or 8%, for the second quarter of 2023 compared to 2022, primarily due to higher technology and related charges of $9 million and an increase in salaries, wages and benefits of $9 million, partially offset by a gain from an agreement to convey development rights underneath one of its natural gas storage fields of $8 million.

Property and other taxes decreased $11 million, or 30%, for the second quarter of 2023 compared to 2022, primarily due to lower than estimated 2022 tax assessments.

Interest and dividend income increased $11 million for the second quarter of 2023 compared to 2022, primarily due to interest income from higher outstanding loans and higher interest rates under BHE GT&S' intercompany revolving credit agreement with Eastern Energy Gas of $8 million and income from money market mutual fund investments of $2 million.

Income tax expense decreased $6 million, or 16%, for the second quarter of 2023 compared to 2022, primarily due to lower pre-tax income and the effective tax rate was 12% for 2023 and 15% for 2022. The effective tax rate decreased primarily due to the reduction in the Pennsylvania statutory rate.

Net income attributable to noncontrolling interests increased $13 million, or 11%, for the second quarter of 2023 compared to 2022, primarily due to increased LNG revenues as a result of the timing of the release of contract liabilities from scheduled outage days in 2022.

173

First Six Months of 2023 Compared to First Six Months of 2022

Operating revenue increased $88 million, or 9%, for the first six months of 2023 compared to 2022, primarily due to an increase in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of $50 million, increased LNG revenues as a result of the timing of the release of contract liabilities from scheduled outage days in 2022 of $41 million, an increase in variable revenue related to park and loan activity of $20 million and derivative losses in 2022 of $7 million, partially offset by a net decrease in regulated gas transmission and storage services revenues due to volumes primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $17 million and a decrease in Cove Point LNG variable revenue of $8 million.

Cost of (excess) gas was an expense of $25 million for the first six months of 2023 compared to a credit of $22 million for the first six months of 2022. The change is primarily from the unfavorable revaluation of the volumes retained prior to the effective date of the new fuel tracker due to the settlement of EGTS' general rate case due to lower natural gas prices of $35 million and a decrease from other operational and system balancing fuel activities prior to the effective date of the new fuel tracker of $14 million.

Operations and maintenance increased $35 million, or 14%, for the first six months of 2023 compared to 2022, primarily due to higher technology and related charges of $19 million, an increase in salaries, wages and benefits of $15 million and an increase in Cove Point outside services of $3 million, partially offset by a gain from an agreement to convey development rights underneath one of its natural gas storage fields of $8 million.

Depreciation and amortization decreased $5 million, or 3%, for the first six months of 2023 compared to 2022, primarily due to the settlement of depreciation rates in EGTS' general rate case of $8 million, partially offset by higher plant placed in-service of $3 million.

Property and other taxes decreased $3 million, or 5%, for the first six months of 2023 compared to 2022, primarily due to lower than estimated 2022 tax assessments.

Interest and dividend income increased $20 million for the first six months of 2023 compared to 2022, primarily due to interest income from higher outstanding loans and higher interest rates under BHE GT&S' intercompany revolving credit agreement with Eastern Energy Gas of $15 million and income from money market mutual fund investments of $4 million.

Income tax expense increased $3 million, or 4%, for the first six months of 2023 compared to 2022, primarily due to higher pre-tax income. The effective tax rate was 14% for 2023 and 2022.

Equity income increased $10 million, or 36%, for the first six months of 2023 compared to 2022, primarily due to higher earnings from Iroquois due to favorable negotiated rate agreements and hedges.

Net income attributable to noncontrolling interests increased $20 million, or 9%, for the first six months of 2023 compared to 2022, primarily due to increased LNG revenues as a result of the timing of the release of contract liabilities from scheduled outage days in 2022, partially offset by a decrease in Cove Point LNG variable revenue and an increase in Cove Point outside services.

Liquidity and Capital Resources

As of June 30, 2023, Eastern Energy Gas' total net liquidity was as follows (in millions):

Cash and cash equivalents	$	82
Intercompany revolving credit agreement	400
Total net liquidity	$	482
Intercompany revolving credit agreement:
Maturity date	2024

174

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022 were $644 million and $681 million, respectively. The change is primarily due to the repayment of EGTS rate refunds to customers, partially offset by the impacts from the rate increase in effect April 1, 2022 for the EGTS general rate case, higher collections from customers and other changes in working capital.

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 made for each payment date.

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2023 and 2022 were $(33) million and $(347) million, respectively. The change is primarily due to an increase in repayments of loans by affiliates of $237 million, a decrease in loans to its parent under an intercompany revolving credit agreement of $38 million, a decrease in capital expenditures of $27 million and proceeds from the assignment of shale development rights of $8 million.

Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2023 were $(594) million and consisted of distributions to noncontrolling interests from Cove Point of $266 million, repayment of long-term debt of $250 million and distributions to its indirect parent, BHE, of $78 million.

Net cash flows from financing activities for the six-month period ended June 30, 2022 were $(242) million and consisted of distributions to noncontrolling interests from Cove Point.

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, intercompany revolving credit agreements, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, 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 natural gas transmission and storage and LNG export, import and storage industries.

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, new growth projects and the timing of growth projects; changes in environmental and other rules and regulations; impacts to customer 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.

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

	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2022		2023		2023
Natural gas transmission and storage	$	23	$	11	$	40
Other	128		113		375
Total	$	151	$	124	$	415

175

Natural gas transmission and storage primarily includes growth capital expenditures related to planned regulated projects. Other includes primarily nonregulated and routine capital expenditures for natural gas transmission, storage and LNG terminalling infrastructure needed to serve existing and expected demand.

Cove Point Acquisition

On July 9, 2023, BHE and Eastern MLP Holding Company II, LLC ("the Buyer"), an indirect wholly owned subsidiary of Eastern Energy Gas, entered into a Purchase and Sale Agreement (the "Purchase Agreement") with Dominion Energy, Inc. ("DEI") and DECP Holdings, Inc. (the "Seller"), an indirect wholly owned subsidiary of DEI, to purchase (the "Transaction") Seller's 50% limited partner interests in Cove Point for a cash purchase price of $3.3 billion, plus the pro rata portion of any quarterly distribution made by Cove Point for the fiscal quarter in which the Transaction closes. Eastern Energy Gas expects to fund the purchase price with equity contributions from BHE. Upon the completion of the Transaction, the Buyer will own an aggregate of 75% of the limited partner interests, and its affiliate, Cove Point GP Holding Company, LLC, will continue to own 100% of the general partner interest, of Cove Point. Subject to certain closing conditions, the Transaction is expected to close by year-end 2023.

Material Cash Requirements

As of June 30, 2023, there have been no material changes in 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, 2022.

Regulatory Matters

Eastern Energy Gas 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 Eastern Energy Gas' current regulatory matters.

Environmental Laws and Regulations

Eastern Energy Gas is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Eastern Energy Gas 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 Eastern Energy Gas 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, 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, 2022. There have been no significant changes in Eastern Energy Gas' assumptions regarding critical accounting estimates since December 31, 2022.

176

Eastern Gas Transmission and Storage, Inc. and its subsidiaries

Consolidated Financial Section

177

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Eastern Gas Transmission and Storage, Inc.

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Eastern Gas Transmission and Storage, Inc. and subsidiaries ("EGTS") as of June 30, 2023, the related consolidated statements of operations, comprehensive income, and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for the six-month periods ended June 30, 2023 and 2022, 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 EGTS as of December 31, 2022 and the related consolidated statements of operations, comprehensive income (loss), changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2023 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, 2022, 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 EGTS' management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to EGTS in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

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

/s/ Deloitte & Touche LLP

Richmond, Virginia

August 4, 2023

178

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	June 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	22	$	16
Restricted cash and cash equivalents	28		29
Trade receivables, net	71		113
Receivables from affiliates	12		13
Inventories	53		50
Income taxes receivable	27		21
Prepayments and other deferred charges	26		36
Natural gas imbalances	26		193
Other current assets	6		9
Total current assets	271		480
Property, plant and equipment, net	4,655		4,504
Other assets	161		190
Total assets	$	5,087	$	5,174

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

179

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions, except share data)

	As of
	June 30, 2023		December 31, 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	31	$	46
Accounts payable to affiliates	3		5
Accrued property, income and other taxes	56		71
Accrued employee expenses	27		13
Notes payable to affiliates	40		36
Regulatory liabilities	26		109
Customer and security deposits	28		29
Asset retirement obligations	16		25
Other current liabilities	36		39
Total current liabilities	263		373
Long-term debt	1,583		1,582
Regulatory liabilities	519		518
Other long-term liabilities	99		101
Total liabilities	2,464		2,574
Commitments and contingencies (Note 8)
Shareholder's equity:
Common stock - 75,000 shares authorized, $10,000 par value, 60,101 issued and outstanding	609		609
Additional paid-in capital	1,300		1,275
Retained earnings	743		746
Accumulated other comprehensive loss, net	(29)		(30)
Total shareholder's equity	2,623		2,600
Total liabilities and shareholder's equity	$	5,087	$	5,174

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

180

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Operating revenue	$	236	$	234	$	514	$	457
Operating expenses:
Cost of (excess) gas	5		(21)		25		(24)
Operations and maintenance	95		86		194		170
Depreciation and amortization	37		38		74		81
Property and other taxes	7		15		21		24
Total operating expenses	144		118		314		251
Operating income	92		116		200		206
Other income (expense):
Interest expense	(17)		(17)		(35)		(34)
Allowance for equity funds	2		1		3		2
Other, net	2		(1)		2		(1)
Total other income (expense)	(13)		(17)		(30)		(33)
Income before income tax expense (benefit)	79		99		170		173
Income tax expense (benefit)	20		28		43		47
Net income	$	59	$	71	$	127	$	126

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

181

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Net income	$	59	$	71	$	127	$	126
Other comprehensive income, net of tax:
Unrealized gains on cash flow hedges, net of tax of $—, $—, $— and $—	—		—		1		1
Total other comprehensive income, net of tax	—		—		1		1
Comprehensive income	$	59	$	71	$	128	$	127

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

182

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

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

(Amounts in millions, except shares)

								Accumulated
				Additional				Other		Total
	Common Stock			Paid-in		Retained		Comprehensive		Shareholder's
	Shares	Amount		Capital		Earnings		Loss, Net		Equity
Balance, March 31, 2022	60,101	$	609	$	1,241	$	776	$	(30)	$	2,596
Net income	—	—		—		71		—		71
Dividends declared	—	—		—		(97)		—		(97)
Contributions	—	—		13		—		—		13
Balance, June 30, 2022	60,101	$	609	$	1,254	$	750	$	(30)	$	2,583
Balance, December 31, 2021	60,101	$	609	$	1,241	$	721	$	(31)	$	2,540
Net income	—	—		—		126		—		126
Other comprehensive income	—	—		—		—		1		1
Dividends declared	—	—		—		(97)		—		(97)
Contributions	—	—		13		—		—		13
Balance, June 30, 2022	60,101	$	609	$	1,254	$	750	$	(30)	$	2,583
Balance, March 31, 2023	60,101	$	609	$	1,282	$	805	$	(29)	$	2,667
Net income	—	—		—		59		—		59
Dividends declared	—	—		—		(121)		—		(121)
Contributions	—	—		18		—		—		18
Balance, June 30, 2023	60,101	$	609	$	1,300	$	743	$	(29)	$	2,623
Balance, December 31, 2022	60,101	$	609	$	1,275	$	746	$	(30)	$	2,600
Net income	—	—		—		127		—		127
Other comprehensive income	—	—		—		—		1		1
Dividends declared	—	—		—		(130)		—		(130)
Contributions	—	—		25		—		—		25
Balance, June 30, 2023	60,101	$	609	$	1,300	$	743	$	(29)	$	2,623

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

183

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Six-Month Periods
	Ended June 30,
	2023		2022
Cash flows from operating activities:
Net income	$	127	126
Adjustments to reconcile net income to net cash flows from operating activities:
(Gains) losses on other items, net	(8)		1
Depreciation and amortization	74		81
Allowance for equity funds	(3)		(2)
Changes in regulatory assets and liabilities	(80)		(9)
Deferred income taxes	30		30
Other, net	(1)		4
Changes in other operating assets and liabilities:
Trade receivables and other assets	53		28
Receivables from affiliates	1		1
Gas balancing activities	21		(22)
Accrued property, income and other taxes	(15)		(8)
Accounts payable and other liabilities	8		49
Accounts payable to affiliates	(3)		2
Net cash flows from operating activities	204		281
Cash flows from investing activities:
Capital expenditures	(86)		(109)
Proceeds from assignment of shale development rights	8		—
Repayment of notes by affiliates	—		10
Notes to affiliates	—		(8)
Other, net	(3)		(6)
Net cash flows from investing activities	(81)		(113)
Cash flows from financing activities:
Issuance (repayment) of notes payable to affiliates, net	4		(61)
Dividends paid	(122)		(80)
Net cash flows from financing activities	(118)		(141)
Net change in cash and cash equivalents and restricted cash and cash equivalents	5		27
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	45		26
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	50	$	53

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

184

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    General

Eastern Gas Transmission and Storage, Inc. and its subsidiaries ("EGTS") conduct business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transmission systems and underground storage. EGTS' operations include transmission assets located in Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. EGTS also operates one of the nation's largest underground natural gas storage systems located in New York, Pennsylvania and West Virginia. EGTS is a wholly owned subsidiary of Eastern Energy Gas Holdings, LLC ("Eastern Energy Gas"), which 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 the energy industry. BHE is a consolidated subsidiary of Berkshire Hathaway Inc.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of June 30, 2023 and for the three- and six-month periods ended June 30, 2023 and 2022. The results of operations for the three- and six-month periods ended June 30, 2023 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 EGTS' Annual Report on Form 10-K for the year ended December 31, 2022 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in EGTS' accounting policies or its assumptions regarding significant accounting estimates during the six-month period ended June 30, 2023.

(2)    Property, Plant and Equipment, Net

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

		As of
		June 30,		December 31,
	Depreciable Life	2023		2022
Interstate natural gas transmission and storage assets	28 - 50 years	$	6,890	$	6,724
Intangible plant	12 - 19 years	80		79
Plant in-service		6,970		6,803
Accumulated depreciation and amortization		(2,498)		(2,440)
		4,472		4,363
Construction work-in-progress		183		141
Property, plant and equipment, net		$	4,655	$	4,504

Assignment of Shale Development Rights

In June 2023, EGTS conveyed development rights to a natural gas producer for approximately 6,500 acres of Utica Shale and Point Pleasant Formation underneath one of its natural gas storage fields and received proceeds of $8 million and an overriding royalty interest in gas produced from the acreage. This transaction resulted in an $8 million ($6 million after-tax) gain, included in operations and maintenance expense in its Consolidated Statements of Operations.

185

(3)    Regulatory Matters

In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. 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 transmission 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. In September 2022, a settlement agreement was filed with the FERC, which provided for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual firm transmission and storage services revenues of approximately $160 million and a decrease in annual depreciation expense of approximately $30 million, compared to the rates in effect prior to April 1, 2022. EGTS' provision for rate refund for April 2022 through February 2023, including accrued interest, totaled $91 million. In November 2022, the FERC approved the settlement agreement and the rate refunds to customers were processed in late February 2023.

(4)    Investments and Restricted Cash and Cash Equivalents

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

	As of
	June 30,		December 31,
	2023		2022
Investments:
Investment funds	$	18	$	14
Restricted cash and cash equivalents:
Customer deposits	28		29
Total restricted cash and cash equivalents	28		29
Total investments and restricted cash and cash equivalents	$	46	$	43
Reflected as:
Current assets	$	28	$	29
Noncurrent assets	18		14
Total investments and restricted cash and cash equivalents	$	46	$	43

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, 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 of customer deposits as allowed under the FERC gas tariff. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):

	As of
	June 30,		December 31,
	2023		2022
Cash and cash equivalents	$	22	$	16
Restricted cash and cash equivalents	28		29
Total cash and cash equivalents and restricted cash and cash equivalents	$	50	$	45

186

(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 (benefit) is as follows:

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Federal statutory income tax rate	21	%	21	%	21	%	21	%
State income tax, net of federal income tax benefit	5		7		5		6
Allowance for funds used during construction-equity	(1)		—		—		—
Other, net	—		—		(1)		—
Effective income tax rate	25	%	28	%	25	%	27	%

(6)    Employee Benefit Plans

EGTS is a participant in benefit plans sponsored by MidAmerican Energy Company ("MidAmerican Energy"), an affiliate. The MidAmerican Energy Company Retirement Plan includes a qualified pension plan that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain postretirement health care and life insurance benefits for eligible retirees on behalf of EGTS. EGTS contributed $4 million and $5 million to the MidAmerican Energy Company Retirement Plan for the six-month periods ended June 30, 2023 and 2022, respectively, and $1 million to the MidAmerican Energy Company Welfare Benefit Plan for the six-month periods ended June 30, 2023 and 2022. Contributions related to these plans are reflected as net periodic benefit cost in operations and maintenance expense on the Consolidated Statements of Operations. Amounts attributable to EGTS were allocated from MidAmerican Energy in accordance with the intercompany administrative service agreement. 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. As of June 30, 2023 and December 31, 2022, EGTS' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets was $47 million.

(7)    Fair Value Measurements

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

187

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

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Total
As of June 30, 2023:
Assets:
Money market mutual funds	$	29	$	—	$	—	$	29
Equity securities:
Investment funds	18		—		—		18
	$	47	$	—	$	—	$	47
Liabilities:
Commodity derivatives	$	—	$	(1)	$	—	$	(1)
	$	—	$	(1)	$	—	$	(1)
As of December 31, 2022:
Assets:
Commodity derivatives	$	—	$	1	$	—	$	1
Money market mutual funds	8		—		—		8
Equity securities:
Investment funds	14		—		—		14
	$	22	$	1	$	—	$	23

EGTS' 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.

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 EGTS transacts. When quoted prices for identical contracts are not available, EGTS uses forward price curves. Forward price curves represent EGTS' estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. EGTS 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 EGTS. Market price quotations are generally readily obtainable for the applicable term of EGTS' outstanding derivative contracts; therefore, EGTS' 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, EGTS 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, related volatility, counterparty creditworthiness and duration of contracts.

EGTS' long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of EGTS' 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 following table presents the carrying value and estimated fair value of EGTS' long-term debt (in millions):

	As of June 30, 2023				As of December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	1,583	$	1,354	$	1,582	$	1,337

188

(8)    Commitments and Contingencies

Environmental Laws and Regulations

EGTS is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its current and future operations. EGTS believes it is in material compliance with all applicable laws and regulations.

Legal Matters

EGTS is party to a variety of legal actions arising out of the normal course of business. EGTS does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

(9)    Revenue from Contracts with Customers

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

	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Customer Revenue:
Regulated:
Gas transmission	$	151	$	145	$	342	$	310
Gas storage	70		69		137		116
Other	(2)		—		—		—
Total regulated	219		214		479		426
Management service and other revenues	15		19		32		37
Total Customer Revenue	234		233		511		463
Other revenue(1)	2		1		3		(6)
Total operating revenue	$	236	$	234	$	514	$	457

(1)Other revenue consists primarily of revenue recognized in accordance with Accounting Standards Codification 815, "Derivative and Hedging" and includes unrealized gains and losses for derivatives not designated as hedges related to natural gas sales contracts.

Remaining Performance Obligations

The following table summarizes EGTS' revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of June 30, 2023 (in millions):

	Performance obligations expected to be satisfied
	Less than 12 months		More than 12 months		Total
EGTS	$	757	$	3,339	$	4,096

189

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

Results of Operations for the Second Quarter and First Six Months of 2023 and 2022

Overview

Net income for the second quarter of 2023 was $59 million, a decrease of $12 million, or 17%, compared to 2022. Net income decreased primarily due to lower margin from regulated gas transmission and storage operations of $24 million, an increase in salaries, wages and benefits and higher technology and related charges, partially offset by a gain from an agreement to convey development rights underneath one of its natural gas storage fields, lower than estimated 2022 tax assessments and lower income tax expense primarily due to lower pre-tax income.

Net income for the first six months of 2023 was $127 million, an increase of $1 million, or 1%, compared to 2022. Net income increased primarily due to higher margin from regulated gas transmission and storage operations of $8 million, a gain from an agreement to convey development rights underneath one of its natural gas storage fields, lower depreciation rates due to the settlement in EGTS' general rate case, lower income tax expense primarily due to lower pre-tax income and lower than estimated 2022 tax assessments, partially offset by higher technology and related charges and an increase in salaries, wages and benefits.

Quarter Ended June 30, 2023 Compared to Quarter Ended June 30, 2022

Operating revenue increased $2 million, or 1%, for the second quarter of 2023 compared to 2022, primarily due to an increase in variable revenue related to park and loan activity of $10 million and an increase in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of $8 million, partially offset by a net decrease in regulated gas transmission and storage services revenues due to volumes primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $11 million.

Cost of (excess) gas was an expense of $5 million for the second quarter of 2023 compared to a credit of $21 million for the second quarter of 2022. The change is primarily from a decrease in other operational and system balancing fuel activities prior to the effective date of the new fuel tracker due to the settlement of EGTS' general rate case of $14 million and the unfavorable revaluation of the volumes retained prior to the effective date of the new fuel tracker due to lower natural gas prices of $12 million.

Operations and maintenance increased $9 million, or 10%, for the second quarter of 2023 compared to 2022, primarily due to higher technology and related charges of $12 million and an increase in salaries, wages and benefits of $9 million, partially offset by a gain from an agreement to convey development rights underneath one of its natural gas storage fields of $8 million.

Property and other taxes decreased $8 million, or 53%, for the second quarter of 2023 compared to 2022, primarily due to lower than estimated 2022 tax assessments.

Other, net was income of $2 million for the second quarter of 2023 compared to expense of $1 million for the second quarter of 2022. The change is primarily from gains on marketable securities.

Income tax expense decreased $8 million, or 29%, for the second quarter of 2023 compared to 2022, primarily due to lower pre-tax income and the effective tax rate was 25% for 2023 and 28% for 2022. The effective tax rate decreased primarily due to the reduction in the Pennsylvania statutory rate.

First Six Months of 2023 Compared to First Six Months of 2022

Operating revenue increased $57 million, or 12%, for the first six months of 2023 compared to 2022, primarily due to an increase in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of $50 million, an increase in variable revenue related to park and loan activity of $20 million and derivative losses in 2022 of $7 million, partially offset by a net decrease in regulated gas transmission and storage services revenues due to volumes primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $17 million.

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Cost of (excess) gas was an expense of $25 million for the first six months of 2023 compared to a credit of $24 million for the first six months of 2022. The change is primarily from the unfavorable revaluation of the volumes retained prior to the effective date of the new fuel tracker due to the settlement of EGTS' general rate case due to lower natural gas prices of $35 million and a decrease from other operational and system balancing fuel activities prior to the effective date of the new fuel tracker of $14 million.

Operations and maintenance increased $24 million, or 14%, for the first six months of 2023 compared to 2022, primarily due to higher technology and related charges of $18 million and an increase in salaries, wages and benefits of $14 million, partially offset by a gain from an agreement to convey development rights underneath one of its natural gas storage fields of $8 million.

Depreciation and amortization decreased $7 million, or 9%, for the first six months of 2023 compared to 2022, primarily due to the settlement of depreciation rates in EGTS' general rate case of $8 million, partially offset by higher plant placed in-service of $1 million.

Property and other taxes decreased $3 million, or 13%, for the first six months of 2023 compared to 2022, primarily due to lower than estimated 2022 tax assessments.

Other, net was income of $2 million for the first six months of 2023 compared to expense of $1 million for the first six months of 2022. The change is primarily from gains on marketable securities.

Income tax expense decreased $4 million, or 9%, for the first six months of 2023 compared to 2022, primarily due to lower pre-tax income and the effective tax rate was 25% for 2023 and 27% for 2022. The effective tax rate decreased primarily due to the reduction in the Pennsylvania statutory rate.

Liquidity and Capital Resources

As of June 30, 2023, EGTS' total net liquidity was as follows (in millions):

Cash and cash equivalents	$	22
Intercompany revolving credit agreement	400
Less:
Notes payable to affiliates	40
Net intercompany revolving credit agreement	360
Total net liquidity	$	382
Intercompany credit agreement:
Maturity date	2024

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022 were $204 million and $281 million, respectively. The change is primarily due to the repayment of EGTS rate refunds to customers, partially offset by the impacts from the rate increase in effect April 1, 2022 for the EGTS general rate case and other changes in working capital.

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

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2023 and 2022 were $(81) million and $(113) million, respectively. The change is primarily due to a decrease in capital expenditures of $23 million, proceeds from the assignment of shale development rights of $8 million and a decrease in loans to affiliates of $8 million, partially offset by a decrease in repayments of loans by affiliates of $10 million.

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Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2023 were $(118) million and consisted of dividends paid to Eastern Energy Gas of $122 million, partially offset by net issuance of notes payable to Eastern Energy Gas of $4 million.

Net cash flows from financing activities for the six-month period ended June 30, 2022 were $(141) million and consisted of dividends paid to Eastern Energy Gas of $80 million and net repayment of notes payable to Eastern Energy Gas of $61 million.

Future Uses of Cash

EGTS 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, intercompany revolving credit agreements, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, investments, debt retirements and other capital requirements. The availability and terms under which EGTS has access to external financing depends on a variety of factors, including regulatory approvals, EGTS' credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the natural gas transmission and storage 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, new growth projects and the timing of growth projects; changes in environmental and other rules and regulations; impacts to customer 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.

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

	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2022		2023		2023
Natural gas transmission and storage	$	21	$	8	$	28
Other	88		78		209
Total	$	109	$	86	$	237

Natural gas transmission and storage includes primarily growth capital expenditures related to planned regulated projects. Other includes primarily pipeline integrity work, automation and controls upgrades, underground storage, corrosion control, unit exchanges, compressor modifications and projects related to Pipeline Hazardous Materials Safety Administration natural gas storage rules. The amounts also include EGTS' asset modernization program, which includes projects for vintage pipeline replacement, compression replacement, pipeline assessment and underground storage integrity.

Material Cash Requirements

As of June 30, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of EGTS' Annual Report on Form 10-K for the year ended December 31, 2022.

Regulatory Matters

EGTS 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 EGTS' current regulatory matters.

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Environmental Laws and Regulations

EGTS is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. EGTS 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 EGTS 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, impairment of long-lived assets and income taxes. For additional discussion of EGTS' critical accounting estimates, see Item 7 of EGTS' Annual Report on Form 10-K for the year ended December 31, 2022. There have been no significant changes in EGTS' assumptions regarding critical accounting estimates since December 31, 2022.

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Item 3.Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting the Registrants, see Item 7A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2022. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2022. Refer to Note 7 of the Notes to Consolidated Financial Statements of PacifiCorp, Note 7 of the Notes to Consolidated Financial Statements of Nevada Power and Note 7 of the Notes to Consolidated Financial Statements of Sierra Pacific in Part I, Item 1 of this Form 10-Q for disclosure of the respective Registrant's derivative positions as of June 30, 2023.

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, Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. carried out separate evaluations, under the supervision and with the participation of each such entity's management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended). Based upon these evaluations, management of each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures for such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended June 30, 2023 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting except for Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. In April 2023, Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. completed implementation of a new enterprise resource planning system, which was designed to replace or enhance certain internal financial and operating systems. In connection with the enterprise resource planning implementation, Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. updated the processes and controls that constitute the internal control over financial reporting, as necessary, to accommodate related changes to the accounting procedures and business processes. There have been no other changes in internal control over financial reporting during the quarter ended June 30, 2023 that have materially affected, or are reasonably likely to materially affect, the Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. internal control over financial reporting environments.

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PART II

Item 1.Legal Proceedings

Berkshire Hathaway Energy and PacifiCorp

The following disclosures reflect material updates to legal proceedings and should be read in conjunction with Item 3 of PacifiCorp's and Berkshire Hathaway Energy's Annual Reports on Form 10-K for the year ended December 31, 2022.

Multiple lawsuits, complaints and demands alleging similar claims have been filed in Oregon and California related to the Labor Day 2020 Wildfires, certain of which have been described below. Amounts sought in the lawsuits, complaints and demands filed in Oregon total over $7 billion, excluding any doubling or trebling of damages included in the complaints. Generally, the complaints filed in California do not specify damages sought and are excluded from the total above. Multiple complaints have also been filed in California for the 2022 McKinney fire. 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 11 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q, and PacifiCorp, refer to Note 9 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q.

Jeanyne James et al. v. PacifiCorp and Consolidated Cases

On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885, in Multnomah County Circuit Court, Oregon ("James"). The complaint was filed by Oregon residents and businesses who sought 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 Complex, South Obenchain, Two Four Two and Santiam Canyon fires, as well as to add claims for noneconomic damages. The amended complaint alleged 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 sought the following damages for the plaintiffs and the 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 demanded a trial by jury and reserved their right to further amend the complaint to allege claims for punitive damages. In May 2022, the Multnomah County Circuit Court granted issue class certification and consolidated this case with others as described below. Plaintiffs' motion to bifurcate issues for trial between class-wide liability and individual damages was also granted. PacifiCorp requested an immediate appeal of the issue class certification before the Oregon Court of Appeals. In January 2023, the Oregon Court of Appeals denied PacifiCorp's request for immediate appeal. In February 2023, the plaintiffs filed a motion to amend the complaint to add punitive damages in an unspecified amount. On March 23, 2023, the plaintiffs filed an amended complaint seeking punitive damages with permission of the Circuit Court. Plaintiffs sought punitive damages at a five times multiplier to the amount of compensatory damages awarded. On April 24, 2023, the jury trial began in Multnomah County Circuit Court for the 17 named plaintiffs. In June 2023, the jury issued its verdict finding PacifiCorp liable to the 17 individual plaintiffs and to the class with respect to the four wildfires. The jury awarded the 17 named plaintiffs $90 million of damages, including $4 million of economic and property damages, $68 million of noneconomic damages and $18 million of punitive damages based on a 0.25 multiplier of the economic and noneconomic damages. Under ORS 477.089, the economic and property damages awarded may be subject to doubling. No judgment has been entered by the Multnomah County Circuit Court. The number of claimants in the class and the amounts of their claims, if any, have not been determined, and no determination has been made by the court as to the timing, process and procedures that will be used to adjudicate individual class member damages. PacifiCorp intends to vigorously appeal the jury's findings and damage awards, including whether the case can proceed as a class action. The appeals process and further actions could take several years.

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On August 20, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter et al. v. PacifiCorp, Case No. 21CV33595, ("Salter"), in Multnomah County Circuit Court, Oregon, in which two complaints, Case No. 21CV09339 and Case No. 21CV09520, previously filed in Marion County Circuit Court, 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 to add a claim for punitive damages. In May 2022, the Salter case was consolidated with the James case (described above).

In October 2020, the case Amy Allen, et al. v. PacifiCorp, Case No. 20CV37430 ("Allen") was filed in Multnomah County Circuit Court, Oregon. The Allen case was filed by five individuals as amended in September 2021 claiming in excess of $32 million in economic and noneconomic damages related to the Beachie Creek fire, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre- and post-judgment interest. In May 2022, the Allen case was consolidated with the James case (described above).

On August 26, 2022, a putative class action complaint seeking declaratory and equitable relief against PacifiCorp was filed, captioned Margaret Dietrich et al. v. PacifiCorp, Case No. 22CV29187 ("Dietrich"), in Multnomah County Circuit Court, Oregon. The complaint was filed by two Oregon residents individually and on behalf of a class initially defined to include residents of, business owners in, real or personal property owners in and any other individuals physically present in specified Oregon counties as of September 7, 2020 who experienced any harm, damage or loss as a result of the Santiam Canyon, Beachie Creek, Lionshead, Echo Mountain Complex, Two Four Two or South Obenchain fires. The complaint was amended on September 6, 2022, to add a claim for damages of over $900 million. The amended complaint adds four more individual plaintiffs and modifies the class definition to cover only the Santiam Canyon, Echo Mountain Complex, Two Four Two, and South Obenchain fires. The amended complaint alleges: (i) negligence due to alleged failure to comply with certain Oregon statutes and administrative rules; (ii) gross negligence due to alleged conscious indifference to or reckless disregard for the probable consequences of defendant's actions or inactions; (iii) private nuisance; (iv) public nuisance; (v) trespass; (vi) inverse condemnation; (vii) accounting/injunction; and (viii) negligent infliction of emotional distress. The amended complaint seeks the following: (i) an order certifying the matter as a class action; (ii) economic damages not less than $400 million; (iii) double the amount of economic and property damages to the extent applicable under Oregon statute; (iv) reasonable costs of reforestation activities; (v) doubling and trebling of certain other damages to the extent applicable under certain Oregon statutes; (vi) noneconomic damages not less than $500 million; (vii) prejudgment interest; (viii) an order requiring an accounting with respect to the amount of damages; (ix) an order enjoining PacifiCorp from leaving power lines energized in areas of Oregon experiencing extremely critical fire conditions; (x) an award of reasonable attorney fees, costs, investigation costs, disbursements and expert witness fees; and (xi) other relief the court finds appropriate. The plaintiffs and proposed class demand a trial by jury. On December 19, 2022, the Dietrich case was consolidated into James (described above) and is currently stayed.

On April 26, 2022, a complaint against PacifiCorp was filed, captioned Cady et al. v. PacifiCorp, Case No. 22CV13946 ("Cady"), in Multnomah County Circuit Court, Oregon. The Cady case was filed by 21 individuals as amended in April 2022 claiming $10 million in economic and noneconomic damages in connection with the Echo Mountain Complex fire, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest. On September 2, 2022, a complaint against PacifiCorp was filed, captioned Logan et al. v. PacifiCorp, Case No. 22CV29859 ("Logan"), in Multnomah County Circuit Court, Oregon. The Logan case was filed by five individuals claiming $10 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre- and post-judgment interest. The Logan and Cady complaints each allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires and assert claims for: (i) negligence; (ii) trespass; (iii) nuisance; and (iv) inverse condemnation. The Cady and Logan cases have been consolidated with James (described above).

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On October 14, 2022, the Multnomah County Circuit Court consolidated 21st Century Centennial Insurance Company, et al. v. PacifiCorp, Case No. 22CV26326 ("21st Century") and Allstate Vehicle and Property Insurance Company, et al. v. PacifiCorp, Case No. 22CV29976 ("Allstate") into James (described above). The 21st Century and Allstate complaints were each filed in Multnomah County Circuit Court, Oregon by subrogated insurance carriers alleging claims of (i) negligence, (ii) gross negligence, and (iii) inverse condemnation resulting from the September 2020 Santiam Canyon, Echo Mountain Complex, 242 and South Obenchain fires. The 21st Century case was filed in August 2022 by 177 insurance carriers seeking $20 million in damages. The Allstate case was filed in September 2022 by 11 insurance carriers seeking $40 million in damages. In May 2023, PacifiCorp and the subrogated insurance carriers entered into a settlement agreement.

On October 17, 2022, the Multnomah County Circuit Court consolidated Michael Bell, et al. v. PacifiCorp, Case No. 22CV30450 ("Bell") into James (described above). The Bell case was filed in Multnomah County Circuit Court, Oregon on September 7, 2022, by 59 plaintiffs seeking $35 million in damages for claims of (i) negligence, (ii) trespass, (iii) nuisance, and (iv) inverse condemnation.

On October 19, 2022, the Multnomah County Circuit Court consolidated Freres Timber, Inc. v. PacifiCorp, Case No. 22CV29694 ("Freres") into James (described above). The Freres case was filed in Multnomah County Circuit Court, Oregon on September 1, 2022, by one plaintiff and seeks $40 million for claims of (i) negligence, (ii) gross negligence, and (iii) inverse condemnation.

On December 6, 2022, CW Specialty Lumber, Inc., et al. v. PacifiCorp, Case No. 22CV41640 ("CW Specialty") was filed in Multnomah County Circuit Court, Oregon by two plaintiffs seeking $29 million in damages for claims of (i) negligence, (ii) gross negligence, (iii) trespass, and (iv) inverse condemnation. The CW Specialty case has been consolidated with James (described above).

Roseburg Resources Co et al. v. PacifiCorp and Consolidated Cases

On March 17, 2022, a complaint against PacifiCorp was filed, captioned Roseburg Resources Co et al. v. PacifiCorp, Case No. 22CV09346 ("Roseburg") in Douglas County Circuit Court, Oregon. The complaint was filed by nine businesses and public pension plans that own 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, Archie Creek, Susan Creek and Smith Springs Road fires 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 as amended: (i) economic and property damages in excess of $195 million under a determination of negligence or inverse condemnation; (ii) doubling of those economic damages to in excess of $390 million under a determination of gross negligence pursuant to Oregon statute; (iii) all costs of the lawsuit; (iv) prejudgment interest of $43 million and post-judgment interest as allowed by law; and (v) attorneys' fees of $105 million and other costs.

On November 1, 2022, three complaints were filed against PacifiCorp, captioned Moore et al. v. PacifiCorp, No. 22CV37302; Blodgett et al. v. PacifiCorp, No. 22CV37306; and Ellis et al. v. PacifiCorp, No. 22CV37304. Three additional cases were filed December 5, 2022, captioned Tague et al. v. PacifiCorp, No. 22CV41242; Long, et al. v. PacifiCorp, No. 22CV41283; and Moyers et al. v. PacifiCorp, No. 22CV41293. On January 6, 2023, an additional complaint was filed against PacifiCorp captioned Meyer et al. v. PacifiCorp, No. 23CV00748. On January 17, 2023, seven additional cases were filed, captioned Foster et al. v. PacifiCorp, No. 23CV02142; Hall et al. v. PacifiCorp, No. 23CV02184; Jones et al. v. PacifiCorp, No. 23CV02110; Price et al. v. PacifiCorp, No. 23CV02175; Minott et al. v. PacifiCorp, No. 23CV02203; Webb et al. v. PacifiCorp, No. 23CV02202; and Keith et al. v. PacifiCorp, No. 23CV02200. On January 24, 2023, three additional cases were filed captioned Kidd et al. v. PacifiCorp, No. 23CV03318; Parker et al. v. PacifiCorp, No. 23CV03317; and Diaz et al. v. PacifiCorp, No. 23CV03313.

These complaints were filed in Douglas County Circuit Court, Oregon with substantially similar allegations as those of Roseburg with the exception that certain of the complaints do not allege inverse condemnation. On February 9, 2023, in an oral ruling, the Douglas County Circuit Court ordered these seventeen cases consolidated for trial as to certain specified issues, along with the above-mentioned Roseburg; the precise scope of the trial will be determined in a later order. Collectively, these eighteen cases seek in excess of $1,300 million in damages, inclusive of the $573 million Roseburg case. On February 14, 2023, the Douglas County Circuit Court ordered that all plaintiffs' claims for inverse condemnation be dismissed; a written order is forthcoming.

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Ashley Andersen et al. v. PacifiCorp and Consolidated Cases

On September 1, 2022, multiple complaints against PacifiCorp were filed in Multnomah County Circuit Court, Oregon, captioned Martin Klinger et al. v. PacifiCorp, Case No. 22CV29674 ("Klinger"), Jeremiah E. Bowen et al. v. PacifiCorp, Case No. 22CV29681 ("Bowen") and James Weathers et al. v. PacifiCorp, Case No. 22CV29683 ("Weathers"). The complaints were filed by Oregon residents and Oregon property owners who allege damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.

On September 6, 2022, a complaint against PacifiCorp was filed, captioned Blair Barnholdt et al. v. PacifiCorp, Case No. 22CV30097, in Multnomah County Circuit Court, Oregon ("Barnholdt"). The complaint was filed by Oregon residents or Oregon property owners who allege damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.

On September 7, 2022, multiple complaints against PacifiCorp were filed in Multnomah County Circuit Court, Oregon, captioned Estate of Nancy Darlene Hunter, et al. v. PacifiCorp, Case No. 22CV30214 ("Hunter"), Willard K. Pratt et al. v. PacifiCorp, Case No. 22CV30217 ("Pratt") and April Thompson et al. v. PacifiCorp, Case No. 22CV30451 ("Thompson"). The complaints were filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.

The above-described Klinger, Bowen, Weathers, Barnholdt, Hunter, Pratt and Thompson cases were consolidated with Sparks et al. v. PacifiCorp, Case No. 21CV48022 ("Sparks") and Russie et al. v. PacifiCorp, Case No. 22CV15840 ("Russie") into Ashley Andersen et al. v. PacifiCorp, Case No. 21CV36567 ("Andersen"). The Klinger, Bowen, Weathers, Barnholdt, Pratt and Thompson complaints each allege: (i) negligence due in part to alleged failure to comply with certain Oregon statutes and administrative rules, including those issued by the OPUC; (ii) gross negligence alleged in the form of willful, wanton and reckless disregard of known risks to the public; (iii) trespass; (iv) nuisance; and (v) inverse condemnation. The Klinger, Bowen, Weathers, Barnholdt, Pratt and Thompson complaints each seek the following damages: (i) economic and property related damages of $83 million; (ii) doubling of those economic and property related damages to $167 million to the extent eligible for doubling of damages under the specified Oregon statute; (iii) non-economic damages to the plaintiffs' persons in an amount not less than $83 million for physical injury, mental suffering, emotional distress and other damages; (iv) loss of wages, loss of earnings capacity, evacuation expenses, displacement expenses and similar damages; (v) attorneys' fees and other costs; and (vii) pre-judgment interest. The plaintiffs for each Klinger, Bowen, Weathers, Barnholdt, Pratt and Thompson request a trial by jury and have reserved their right to amend the complaint to add a claim for punitive damages. The Hunter complaint seeks $50 million in damages and alleges claims for: (i) negligence, (ii) trespass, (iii), nuisance, (iv) inverse condemnation, and (v) wrongful death. The Andersen case was filed by 50 individuals as amended in August 2022 seeking $250 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest. The Sparks case was filed by 17 individuals in December 2021 claiming $125 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre- judgment interest. The Russie case was filed by 45 individuals as amended in September 2022 seeking $250 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest.

Judith O'Keefe v. PacifiCorp and Consolidated Cases

On September 1, 2022, a complaint against PacifiCorp was filed, captioned Aaron Macy-Wyngarden et al. v. PacifiCorp, Case No. 22CV29684, in Multnomah County Circuit Court, Oregon ("Macy-Wyngarden"). The complaint was filed by Oregon residents or Oregon property owners who allege injuries and damages resulting from the September 2020 Beachie Creek, Santiam Canyon, Lionshead and Riverside fires. The allegations made and damages sought are described below.

On September 22, 2022, a complaint against PacifiCorp was filed, captioned Zachary Bogle et al. v. PacifiCorp, Case No. 22CV29717, in Multnomah County Circuit Court, Oregon ("Bogle"). The complaint was filed by Oregon residents who allege injuries and damages resulting from the September 2020 Beachie Creek, Santiam Canyon, Lionshead and Riverside fires. The allegations made and damages sought are described below.

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The Macy-Wyngarden and Bogle complaints each allege: (i) negligence due in part to alleged failure to comply with certain Oregon statutes and administrative rules, including those issued by the OPUC; (ii) gross negligence alleged in the form of willful, wanton and reckless disregard of known risks to the public; (iii) trespass; (iv) nuisance; and (v) inverse condemnation. The Macy-Wyngarden and Bogle complaints each seek the following damages: (i) economic and property related damages of $83 million; (ii) doubling of those economic and property related damages to $167 million to the extent eligible for doubling of damages under the specified Oregon statute; (iii) non-economic damages to the plaintiffs' persons in an amount not less than $83 million for physical injury, mental suffering, emotional distress and other damages; (iv) loss of wages, loss of earnings capacity, evacuation expenses, displacement expenses and similar damages; (v) attorneys' fees and other costs; and (vii) pre-judgment interest. The plaintiffs for each Macy-Wyngarden and Bogle request a trial by jury and have reserved their right to amend the complaint to add a claim for punitive damages.

The Macy-Wyngarden and Bogle cases were consolidated with Ruthie Dodge et al. v. PacifiCorp, Case No. 22CV30222 ("Dodge") into Judith O'Keefe v. PacifiCorp, Case No. 21CV15857 ("O'Keefe"). The Dodge case was filed in Multnomah County Circuit Court, Oregon on September 8, 2022, by two plaintiffs seeking $9 million in damages for claims of negligence, trespass, nuisance, and inverse condemnation. The O'Keefe lawsuit was filed in Multnomah County Circuit Court, Oregon on April 23, 2021, by one individual seeking $2 million in damages for claims for negligence, nuisance, and trespass.

United States and Oregon Departments of Justice – Loss and Damages to Federal and State Lands

PacifiCorp recently received correspondence from the U.S. Department of Justice ("USDOJ"), representing the U.S. Department of the Interior, Bureau of Land Management, Bureau of Indian Affairs, Department of Agriculture and Forest Service, regarding the potential recovery of certain costs and damages alleged to have occurred to federal lands from the September 2020 Archie Creek and Susan Creek fires. The USDOJ estimates the costs and damages relating to reforestation, damaged timber and improvements, coordination with hydropower license, suppression costs and other assessment, cleanup and rehabilitation costs and damages at approximately $640 million. The amounts alleged for natural resource damage from these fires do not include environmental damages that the United States could potentially seek to recover if this matter was fully litigated, nor do they include multipliers which the agencies are allegedly entitled to collect under pertinent federal regulations, under which, for example, minimum damages for trespass to timber managed by the U.S. Department of Interior are twice the fair market value of the resource at the time of the trespass, or three times if the violation was willful.

PacifiCorp also received correspondence from the Oregon Department of Justice ("ODOJ"), representing the State of Oregon, regarding the potential recovery of losses and damages to state lands from the Archie Creek and Susan Creek fires. The ODOJ estimates losses and damages relating to the sheltering of, and assistance to, affected Oregonians, fire control and extinguishment costs, 39 acres of Oregon forestland, losses and damages at the Rock Creek Fish Hatchery, road and highway damages, and other costs, at approximately $95 million.

PacifiCorp is actively cooperating with both the USDOJ and ODOJ on resolving these alleged claims, including through the pursuit of alternative dispute resolution means.

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, 2022.

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

Not applicable.

Item 3.Defaults Upon Senior Securities

Not applicable.

Item 4.Mine Safety Disclosures

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

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Item 5.Other Information

Not applicable.

Item 6.Exhibits

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

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Exhibit No. Description

BERKSHIRE HATHAWAY ENERGY

10.1	First Amendment to the $3,500,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, 2023, among Berkshire Hathaway Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, MUFG Bank, Ltd. as Administrative Agent and the LC Issuing Banks.
10.2	First Amending Agreement to the Credit Agreement, dated April 27, 2021, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2023).
10.3	Second Amending Agreement to the Credit Agreement, dated April 27, 2022, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2023).
10.4	Third Amending Agreement to the Credit Agreement, dated April 27, 2023, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2023).
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

4.1	Thirty-Fourth Supplemental Indenture, dated as of May 1, 2023, 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 May 17, 2023).
10.5	First Amendment to the $2,000,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, 2023, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, JP Morgan Chase Bank, N.A. as Administrative Agent and the LC Issuing Banks.
95	Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act.

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Exhibit No. Description

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.

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.

BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN ENERGY AND MIDAMERICAN FUNDING

10.6 First Amendment to the $1,500,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, 2023, 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.

NEVADA POWER

15.4	Awareness Letter of Independent Registered Public Accounting Firm.
31.9	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.10	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.9	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.10	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER

10.7 First Amendment to the $600,000,000 Fifth Amended and Restated Credit Agreement, dated as of June 30, 2023, among Nevada Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks.

SIERRA PACIFIC

31.11	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.12	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.11	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.12	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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Exhibit No. Description

BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC

10.8 First Amendment to the $400,000,000 Fifth Amended and Restated Credit Agreement, dated as of June 30, 2023, 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.

EASTERN ENERGY GAS

10.9	Amended and Restated $400,000,000 Inter-Company Credit Agreement, dated as of March 1, 2023, by and between BHE GT&S, LLC and Eastern Energy Gas Holdings, LLC (incorporated by reference to Exhibit 10.4 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended March 31, 2023).
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.

EASTERN GAS TRANSMISSION AND STORAGE

10.10	Amended and Restated $400,000,000 Inter-Company Credit Agreement, dated as of March 1, 2023, by and between Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. (incorporated by reference to Exhibit 10.5 to the Eastern Gas Transmission and Storage, Inc. Quarterly Report on Form 10-Q for the quarter ended March 31, 2023).
10.11	Amended and Restated $400,000,000 Inter-Company Credit Agreement, dated as of March 1, 2023, by and between Eastern Gas Transmission and Storage, Inc. and Eastern Energy Gas Holdings, LLC (incorporated by reference to Exhibit 10.6 to the Eastern Gas Transmission and Storage Inc. Quarterly Report on Form 10-Q for the quarter ended March 31, 2023).
31.15	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.16	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.15	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.16	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

ALL REGISTRANTS

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The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2023, is formatted in iXBRL (Inline eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail.

104

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

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SIGNATURES

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

	BERKSHIRE HATHAWAY ENERGY COMPANY
Date: August 4, 2023	/s/ Calvin D. Haack
	Calvin D. Haack
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)
	PACIFICORP
Date: August 4, 2023	/s/ Nikki L. Kobliha
	Nikki L. Kobliha
	Vice President, Chief Financial Officer and Treasurer
	(principal financial and accounting officer)
	MIDAMERICAN FUNDING, LLC
	MIDAMERICAN ENERGY COMPANY
Date: August 4, 2023	/s/ Blake M. Groen
	Blake M. Groen
	Vice President and Controller
	of MidAmerican Funding, LLC and
	Vice President and Chief Financial Officer
	of MidAmerican Energy Company
	(principal financial and accounting officer)
	NEVADA POWER COMPANY
Date: August 4, 2023	/s/ Michael J. Behrens
	Michael J. Behrens
	Vice President and Chief Financial Officer
	(principal financial and accounting officer)
	SIERRA PACIFIC POWER COMPANY
Date: August 4, 2023	/s/ Michael J. Behrens
	Michael J. Behrens
	Vice President and Chief Financial Officer
	(principal financial and accounting officer)
	EASTERN ENERGY GAS HOLDINGS, LLC
Date: August 4, 2023	/s/ Scott C. Miller
	Scott C. Miller
	Vice President, Chief Financial Officer and Treasurer
	(principal financial and accounting officer)
	EASTERN GAS TRANSMISSION AND STORAGE, INC.
Date: August 4, 2023	/s/ Scott C. Miller
	Scott C. Miller
	Vice President, Chief Financial Officer and Treasurer
	(principal financial and accounting officer)

204