PACIFICORP /OR/ - Quarter Report: 2023 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2023

☐ 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)

10700 Energy Way

Glen Allen, Virginia 23060

804-613-5100

333-266049

EASTERN GAS TRANSMISSION AND STORAGE, INC.

55-0629203

(A Delaware Corporation)

10700 Energy Way

Glen Allen, Virginia 23060

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 November 2, 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 November 2, 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 November 2, 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 November 2, 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 November 2, 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 November 2, 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 November 2, 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 November 2, 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	199
Item 4.	Controls and Procedures	199

PART II


Item 1.	Legal Proceedings	200
Item 1A.	Risk Factors	205
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	205
Item 3.	Defaults Upon Senior Securities	205
Item 4.	Mine Safety Disclosures	205
Item 5.	Other Information	205
Item 6.	Exhibits	206
Signatures		211

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




The Transaction						The acquisition of 50% limited partner interests in Cove Point LNG, LP from DECP Holdings, Inc., an indirect wholly owned subsidiary of Dominion Energy, Inc.




Certain Industry Terms

2020 Wildfires						Wildfires in Oregon and Northern California that occurred in September 2020
2022 McKinney Fire						A wildfire that began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California in July 2022


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
DEAA						Deferred Energy Accounting Adjustment
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
IPUC						Idaho Public Utilities Commission

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
PCAM						Power Cost Adjustment Mechanism
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 and the 2022 McKinney Fire, 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;

•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.

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 Incom e (Loss)						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						58
Consolidated Balance Sheets						59
Consolidated Statements of Operations						61
Consolidated Statements of Changes in Shareholders' Equity						62
Consolidated Statements of Cash Flows						63
Notes to Consolidated Financial Statements						64
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm						85
Balance Sheets						86
Statements of Operations						88
Statements of Changes in Shareholder's Equity						89
Statements of Cash Flows						90
Notes to Financial Statements						91
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm						99
Consolidated Balance Sheets						100
Consolidated Statements of Operations						102
Consolidated Statements of Changes in Member's Equity						103
Consolidated Statements of Cash Flows						104
Notes to Consolidated Financial Statements						105
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm						119
Consolidated Balance Sheets						120
Consolidated Statements of Operations						121
Consolidated Statements of Changes in Shareholder's Equity						122
Consolidated Statements of Cash Flows						123
Notes to Consolidated Financial Statements						124
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm						140
Consolidated Balance Sheets						141
Consolidated Statements of Operations						142
Consolidated Statements of Changes in Shareholder's Equity						143
Consolidated Statements of Cash Flows						144
Notes to Consolidated Financial Statements						145
Eastern Energy Gas Holdings, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm						163
Consolidated Balance Sheets						164
Consolidated Statements of Operations						166
Consolidated Statements of Comprehensive Income						167
Consolidated Statements of Changes in Equity						168
Consolidated Statements of Cash Flows						169
Notes to Consolidated Financial Statements						170
Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Report of Independent Registered Public Accounting Firm						183
Consolidated Balance Sheets						184
Consolidated Statements of Operations						186
Consolidated Statements of Comprehensive Income						187
Consolidated Statements of Changes in Shareholder's Equity						188
Consolidated Statements of Cash Flows						189
Notes to Consolidated Financial Statements						190

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						75
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company						109
Nevada Power Company and its subsidiaries						131
Sierra Pacific Power Company and its subsidiaries						154
Eastern Energy Gas Holdings, LLC and its subsidiaries						178
Eastern Gas Transmission and Storage, Inc. and its subsidiaries						195

Berkshire Hathaway Energy Company and its subsidiaries

Consolidated Financial Section

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Berkshire Hathaway Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of September 30, 2023, the related consolidated statements of operations, comprehensive income (loss), and changes in equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 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

November 3, 2023

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	September 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	2,047	$	1,591
Investments and restricted cash and cash equivalents	955		2,141
Trade receivables, net	2,691		2,876

Inventories	1,427		1,256
Mortgage loans held for sale	616		474


Regulatory assets	1,492		1,319
Other current assets	887		1,345
Total current assets	10,115		11,002

Property, plant and equipment, net	96,627		93,043
Goodwill	11,482		11,489
Regulatory assets	4,202		3,743
Investments and restricted cash and cash equivalents and investments	10,104		11,273
Other assets	3,552		3,290

Total assets	$	136,082	$	133,840

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	September 30,		December 31,
	2023		2022
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	2,683	$	2,679
Accrued interest	722		558
Accrued property, income and other taxes	712		746
Accrued employee expenses	451		333
Short-term debt	1,617		1,119
Current portion of long-term debt	2,313		3,201
Other current liabilities	1,500		1,677
Total current liabilities	9,998		10,313

BHE senior debt	13,100		13,096
BHE junior subordinated debentures	100		100
Subsidiary debt	37,207		35,238
Regulatory liabilities	6,478		7,070
Deferred income taxes	12,506		12,678
Other long-term liabilities	6,738		4,706
Total liabilities	86,127		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	5,573		6,298

Retained earnings	44,365		41,833
Accumulated other comprehensive loss, net	(2,145)		(2,149)
Total BHE shareholders' equity	48,643		46,832
Noncontrolling interests	1,312		3,807
Total equity	49,955		50,639

Total liabilities and equity	$	136,082	$	133,840

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Operating revenue:
Energy	$	5,958	$	6,095	$	16,362	$	15,858
Real estate	1,212		1,405		3,383		4,284
Total operating revenue	7,170		7,500		19,745		20,142

Operating expenses:
Energy:
Cost of sales	2,009		1,959		5,530		4,944
Operations and maintenance	1,184		1,064		3,518		3,024
Wildfire losses, net of recoveries (Note 11)	1,263		—		1,671		64
Depreciation and amortization	1,015		1,102		3,035		3,154
Property and other taxes	204		200		613		604
Real estate	1,181		1,352		3,351		4,086
Total operating expenses	6,856		5,677		17,718		15,876

Operating income	314		1,823		2,027		4,266

Other income (expense):
Interest expense	(603)		(555)		(1,788)		(1,637)
Capitalized interest	36		19		93		54
Allowance for equity funds	76		43		186		123
Interest and dividend income	110		40		323		93
(Losses) gains on marketable securities, net	(76)		(3,270)		926		(1,999)
Other, net	(3)		5		115		(16)
Total other income (expense)	(460)		(3,718)		(145)		(3,382)

Income (loss) before income tax expense (benefit) and equity income (loss)	(146)		(1,895)		1,882		884
Income tax expense (benefit)	(777)		(1,213)		(1,194)		(1,571)
Equity income (loss)	(60)		(13)		(197)		(153)
Net income (loss)	571		(695)		2,879		2,302
Net income attributable to noncontrolling interests	77		147		321		376
Net income (loss) attributable to BHE shareholders	494		(842)		2,558		1,926
Preferred dividends	8		8		25		37
Earnings (loss) on common shares	$	486	$	(850)	$	2,533	$	1,889

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited)

(Amounts in millions)


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Net income (loss)	$	571	$	(695)	$	2,879	$	2,302

Other comprehensive (loss) income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $10, $9, $3 and $21	21		25		10		65
Foreign currency translation adjustment	(313)		(665)		18		(1,256)
Unrealized gains (losses) on cash flow hedges, net of tax of $(3), $22, $(10) and $58	(7)		45		(23)		148
Total other comprehensive (loss) income, net of tax	(299)		(595)		5		(1,043)

Comprehensive income (loss)	272		(1,290)		2,884		1,259
Comprehensive income attributable to noncontrolling interests	77		147		321		376
Comprehensive income (loss) attributable to BHE shareholders	$	195	$	(1,437)	$	2,563	$	883

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)


	BHE Shareholders' Equity
							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, June 30, 2022	$	850	$	—	$	6,298	$	(744)	$	42,688	$	(1,788)	$	3,887	$	51,191
Net (loss) income	—		—		—		—		(842)		—		147		(695)
Other comprehensive loss	—		—		—		—		—		(595)		—		(595)
Long-term income tax receivable adjustments	—		—		—		744		(744)		—		—		—

Preferred stock dividend	—		—		—		—		(8)		—		—		(8)

Distributions	—		—		—		—		—		—		(149)		(149)
Contributions	—		—		—		—		—		—		2		2

Other equity transactions	—		—		—		—		(1)		—		—		(1)
Balance, September 30, 2022	$	850	$	—	$	6,298	$	—	$	41,093	$	(2,383)	$	3,887	$	49,745

Balance, December 31, 2021	$	1,650	$	—	$	6,374	$	(744)	$	40,754	$	(1,340)	$	3,895	$	50,589
Net income	—		—		—		—		1,926		—		376		2,302
Other comprehensive loss	—		—		—		—		—		(1,043)		—		(1,043)
Long-term income tax receivable adjustments	—		—		—		744		(744)		—		—		—
Preferred stock redemptions	(800)		—		—		—		—		—		—		(800)
Preferred stock dividend	—		—		—		—		(37)		—		—		(37)
Common stock purchases	—		—		(77)		—		(793)		—		—		(870)
Distributions	—		—		—		—		—		—		(394)		(394)
Contributions	—		—		—		—		—		—		4		4

Other equity transactions	—		—		1		—		(13)		—		6		(6)
Balance, September 30, 2022	$	850	$	—	$	6,298	$	—	$	41,093	$	(2,383)	$	3,887	$	49,745

Balance, June 30, 2023	$	850	$	—	$	6,298	$	—	$	43,880	$	(1,845)	$	3,777	$	52,960
Net income	—		—		—		—		494		—		77		571
Other comprehensive loss	—		—		—		—		—		(299)		—		(299)


Preferred stock dividend	—		—		—		—		(8)		—		—		(8)

Distributions	—		—		—		—		—		—		(88)		(88)

Purchase of Cove Point noncontrolling interest (Note 3)	—		—		(725)		—		—		(1)		(2,454)		(3,180)
Other equity transactions	—		—		—		—		(1)		—		—		(1)
Balance, September 30, 2023	$	850	$	—	$	5,573	$	—	$	44,365	$	(2,145)	$	1,312	$	49,955

Balance, December 31, 2022	$	850	$	—	$	6,298	$	—	$	41,833	$	(2,149)	$	3,807	$	50,639
Net income	—		—		—		—		2,558		—		321		2,879
Other comprehensive income	—		—		—		—		—		5		—		5


Preferred stock dividend	—		—		—		—		(25)		—		—		(25)

Distributions	—		—		—		—		—		—		(357)		(357)
Contributions	—		—		—		—		—		—		3		3
Purchase of Cove Point noncontrolling interest (Note 3)	—		—		(725)		—		—		(1)		(2,454)		(3,180)
Other equity transactions	—		—		—		—		(1)		—		(8)		(9)
Balance, September 30, 2023	$	850	$	—	$	5,573	$	—	$	44,365	$	(2,145)	$	1,312	$	49,955

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Nine-Month Periods
	Ended September 30,
	2023		2022
Cash flows from operating activities:
Net income	$	2,879	$	2,302
Adjustments to reconcile net income to net cash flows from operating activities:
(Gains) losses on marketable securities, net	(926)		1,999
Depreciation and amortization	3,072		3,197
Allowance for equity funds	(186)		(123)
Equity (income) loss, net of distributions	274		249
Net power cost deferrals	(722)		(1,008)
Amortization of net power cost deferrals	303		246
Other changes in regulatory assets and liabilities	(222)		(81)
Deferred income taxes and investment tax credits, net	(172)		(350)
Other, net	(62)		53
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(224)		(85)
Derivative collateral, net	(201)		106
Pension and other postretirement benefit plans	(10)		(31)
Accrued property, income and other taxes, net	(52)		501
Accounts payable and other liabilities	512		900
Wildfires insurance receivable	(257)		(161)
Wildfires liability	1,854		225
Net cash flows from operating activities	5,860		7,939

Cash flows from investing activities:
Capital expenditures	(6,526)		(5,385)

Purchases of marketable securities	(226)		(375)
Proceeds from sales of marketable securities	2,138		961
Purchases of U.S. Treasury Bills	(3,294)		(613)
Proceeds from sales of U.S. Treasury Bills	1,651		—
Proceeds from maturities of U.S. Treasury Bills	3,034		—
Equity method investments	(12)		(29)
Other, net	13		(28)
Net cash flows from investing activities	(3,222)		(5,469)

Cash flows from financing activities:

Preferred stock redemptions	—		(800)
Preferred dividends	(17)		(33)
Common stock purchases	—		(870)
Proceeds from BHE senior debt	—		986
Repayments of BHE senior debt	(400)		—
Proceeds from subsidiary debt	3,413		1,198
Repayments of subsidiary debt	(1,868)		(882)
Net proceeds from (repayments of) short-term debt	498		(540)

Purchase of Cove Point noncontrolling interest	(3,300)		—
Distributions to noncontrolling interests	(357)		(395)

Other, net	(43)		(269)
Net cash flows from financing activities	(2,074)		(1,605)

Effect of exchange rate changes	2		(51)

Net change in cash and cash equivalents and restricted cash and cash equivalents	566		814
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	$	2,383	$	2,058

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

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

The Company's operations are organized as 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 September 30, 2023, and for the three- and nine-month periods ended September 30, 2023 and 2022. The results of operations for the three- and nine-month periods ended September 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 nine-month period ended September 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 a wildfire that began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California in July 2022 (the "2022 McKinney Fire"), referred to together as "the Wildfires" as discussed in Note 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 September 1, 2023, BHE and Eastern MLP Holding Company II, LLC ("the Buyer"), an indirect wholly owned subsidiary of BHE, completed the acquisition of DECP Holdings, Inc.'s (the "Seller"), an indirect wholly owned subsidiary of Dominion Energy, Inc., 50% limited partner interests in Cove Point LNG, LP ("Cove Point") ("The Transaction"). Under the terms of the Purchase and Sale Agreement, dated July 9, 2023 (the "Purchase Agreement"), the Buyer paid $3.3 billion in cash, plus the pro rata portion of the quarterly distribution made by Cove Point for the third fiscal quarter of 2023. BHE funded the Transaction with cash on hand, including cash realized from the liquidation of certain investments, which was contributed to BHE GT&S. The Buyer now owns an aggregate of 75% of the limited partner interests, and its affiliate, Cove Point GP Holding Company, LLC, continues to own 100% of the general partner interest, of Cove Point. Prior to the Transaction, BHE owned 100% of the general partner interest and 25% of the limited partner interests in Cove Point. BHE previously determined it has the power to direct the activities that most significantly impact Cove Point's economic performance as well as the obligation to absorb losses and benefits which could be significant to it and accordingly, consolidated Cove Point. Because BHE controls Cove Point both before and after the Transaction, the changes in BHE's ownership interest in Cove Point were accounted for as an equity transaction and no gain or loss was recognized. In connection with the Transaction, BHE recognized $120 million of income taxes in equity primarily attributable to the step up in tax basis of the investment in Cove Point of $144 million, partially offset by establishing additional regulatory liabilities related to excess deferred income taxes of $24 million.

(4) Property, Plant and Equipment, Net

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


		As of
	Depreciable	September 30,		December 31,
	Life	2023		2022
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	93,667	$	92,759
Interstate natural gas pipeline assets	3-80 years	18,800		18,328
		112,467		111,087
Accumulated depreciation and amortization		(35,752)		(34,599)
Regulated assets, net		76,715		76,488

Nonregulated assets:
Independent power plants	2-50 years	8,461		8,545
Cove Point LNG facility	40 years	3,415		3,412
Other assets	2-30 years	2,792		2,693
		14,668		14,650
Accumulated depreciation and amortization		(3,703)		(3,452)
Nonregulated assets, net		10,965		11,198

		87,680		87,686
Construction work-in-progress		8,947		5,357
Property, plant and equipment, net		$	96,627	$	93,043

Construction work-in-progress includes $8.4 billion as of September 30, 2023 and $4.9 billion as of December 31, 2022, related to the construction of regulated assets.

(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
	September 30,		December 31,
	2023		2022
Investments:
BYD Company Limited common stock	$	2,794	$	3,763
U.S. Treasury Bills	627		1,931
Rabbi trusts	461		433
Other	327		335
Total investments	4,209		6,462

Equity method investments:
BHE Renewables tax equity investments	4,180		4,535
Electric Transmission Texas, LLC	670		623
Iroquois Gas Transmission System, L.P.	582		600
Other	376		304
Total equity method investments	5,808		6,062

Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds	706		664
Other restricted cash and cash equivalents	336		226
Total restricted cash and cash equivalents and investments	1,042		890

Total investments and restricted cash and cash equivalents and investments	$	11,059	$	13,414

Reflected as:
Other current assets	$	955	$	2,141
Noncurrent assets	10,104		11,273
Total investments and restricted cash and cash equivalents and investments	$	11,059	$	13,414

Investments

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


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Unrealized (losses) gains recognized on marketable securities held at the reporting date	$	(97)	$	(3,168)	$	573	$	(2,002)
Net gains (losses) recognized on marketable securities sold during the period	21		(102)		353		3
(Losses) gains on marketable securities, net	$	(76)	$	(3,270)	$	926	$	(1,999)

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
	September 30,		December 31,
	2023		2022

Cash and cash equivalents	$	2,047	$	1,591
Investments and restricted cash and cash equivalents	283		173
Investments and restricted cash and cash equivalents and investments	53		53
Total cash and cash equivalents and restricted cash and cash equivalents	$	2,383	$	1,817

(6) Recent Financing Transactions

Long-Term Debt

In October 2023, AltaLink, L.P. issued C$500 million of its 5.463% Senior Secured Notes due October 2055 and intends to use the net proceeds to repay its short-term indebtedness.

In September 2023, MidAmerican Energy issued $350 million of its 5.35% First Mortgage Bonds due January 2034 and $1 billion of its 5.850% First Mortgage Bonds due September 2054. MidAmerican Energy 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.

In September 2023, Nevada Power issued $500 million of its 6.00% General and Refunding Mortgage Bonds, Series 2023A, due March 2054. Nevada Power used the net proceeds to repay its term loan due January 14, 2024 and short-term borrowings outstanding under Nevada Power's revolving credit facility, fund capital expenditures and for general corporate purposes.

In September 2023, Sierra Pacific issued $400 million of its 5.90% General and Refunding Mortgage Bonds, Series 2023A, due March 2054. Sierra Pacific used the net proceeds to repay short-term borrowings incurred under Sierra Pacific's revolving credit facility in connection with the redemption in August 2023 of its 3.375% General and Refunding Mortgage Notes, Series T, due 2023, fund capital expenditures and for general corporate purposes.

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.

(7) Income Taxes

The effective income tax rate for the three-month period ended September 30, 2023, is 532% and results from a $777 million income tax benefit associated with a $146 million pre-tax loss, primarily related to increases in wildfire loss accruals, net of expected insurance recoveries of $1,263 million as described in Note 11. The $777 million benefit is primarily comprised of a $558 million benefit (382%) from income tax credits, an $82 million benefit (56%) from effects of ratemaking, and a $65 million benefit (44%) from state income tax.

The effective income tax rate for the three-month period ended September 30, 2022, is 64% and results from a $1,213 million income tax benefit associated with a $1,895 million pre-tax loss, primarily relating to a pre-tax loss of $3,259 million on the Company's investment in BYD Company Limited. The $1,213 million income tax benefit is primarily comprised of a $398 million benefit (21%) from the application of the federal statutory income tax rate to the pre-tax loss and a $680 million benefit (36%) from income tax credits.

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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Federal statutory income tax rate	21	%	21	%	21	%	21	%
Income tax credits	382		36		(67)		(165)
State income tax, net of federal income tax impacts	44		—		(5)		(2)
Income tax effect of foreign income	9		—		1		(4)
Effects of ratemaking	56		5		(8)		(18)
Equity income	9		—		(2)		(4)
Noncontrolling interest	11		2		(4)		(9)
Other, net	—		—		1		3
Effective income tax rate	532	%	64	%	(63)	%	(178)	%

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 nine-month periods ended September 30, 2023 and 2022 totaled $1,258 million and $1,414 million, respectively.

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 nine-month periods ended September 30, 2023 and 2022 totaling $1,000 million and $1,742 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.

(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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Pension:
Service cost	$	3	$	7	$	12	$	20
Interest cost	27		20		82		58
Expected return on plan assets	(30)		(28)		(92)		(82)
Settlement	—		—		(5)		2
Net amortization	4		4		11		13
Net periodic benefit cost	$	4	$	3	$	8	$	11

Other postretirement:
Service cost	$	3	$	2	$	6	$	8
Interest cost	8		5		22		15
Expected return on plan assets	(7)		(8)		(25)		(22)
Net amortization	(1)		—		(2)		(1)
Net periodic benefit cost (credit)	$	3	$	(1)	$	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 September 30, 2023, $10 million and $5 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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Service cost	$	2	$	3	$	5	$	10
Interest cost	14		8		42		27
Expected return on plan assets	(20)		(22)		(60)		(70)

Net amortization	7		6		20		18
Net periodic benefit cost (credit)	$	3	$	(5)	$	7	$	(15)

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 September 30, 2023, £8 million, or $10 million, of contributions had been made to the United Kingdom pension plan.

(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 nine-month period ended September 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.

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


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of September 30, 2023:
Assets:
Commodity derivatives	$	—	$	170	$	12	$	(37)	$	145

Interest rate derivatives	48		66		9		—		123
Mortgage loans held for sale	—		616		—		—		616
Money market mutual funds	1,798		—		—		—		1,798
Debt securities:
U.S. government obligations	866		—		—		—		866

Corporate obligations	—		74		—		—		74
Municipal obligations	—		3		—		—		3

Equity securities:
U.S. companies	380		—		—		—		380
International companies	2,802		—		—		—		2,802
Investment funds	285		—		—		—		285
	$	6,179	$	929	$	21	$	(37)	$	7,092
Liabilities:
Commodity derivatives	$	(4)	$	(45)	$	(96)	$	45	$	(100)
Foreign currency exchange rate derivatives	—		(18)		—		—		(18)
Interest rate derivatives	—		—		(3)		—		(3)
	$	(4)	$	(63)	$	(99)	$	45	$	(121)


	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 $8 million as of September 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.

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				Nine-Month Periods
	Ended September 30,				Ended September 30,
			Interest				Interest
	Commodity		Rate		Commodity		Rate
	Derivatives		Derivatives		Derivatives		Derivatives
2023:
Beginning balance	$	(174)	$	11	$	(59)	$	6
Changes included in earnings(1)	(1)		(5)		9		—
Changes in fair value recognized in OCI	—		—		(3)		—
Changes in fair value recognized in net regulatory assets	(48)		—		(231)		—

Purchases	1		—		1		—

Settlements	138		—		199		—


Ending balance	$	(84)	$	6	$	(84)	$	6







2022:
Beginning balance	$	(178)	$	21	$	(151)	$	19
Changes included in earnings(1)	(14)		(22)		(96)		(20)
Changes in fair value recognized in OCI	3		—		13		—
Changes in fair value recognized in net regulatory assets	(5)		—		(64)		—
Purchases	1		—		2		—

Settlements	138		—		172		—
Transfers out of Level 3 into Level 2	—		—		69		—
Ending balance	$	(55)	$	(1)	$	(55)	$	(1)

(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 September 30, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	52,720	$	45,166	$	51,635	$	46,906

(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 nine-month period ended September 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 nine-month period ended September 30, 2023, MidAmerican Energy entered into firm construction commitments totaling $354 million for the remainder of 2023 through 2024 related to the construction and repowering of wind-powered generating facilities in Iowa.

Fuel Contracts

During the nine-month period ended September 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.

Pursuant to Accounting Standards Codification Topic 450, Contingencies, a provision for a loss contingency is recorded when it is probable a liability is likely to occur 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.

Wildfire Liability Overview

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 have been or are 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 and in certain demands made in California total nearly $8 billion, excluding any doubling or trebling of damages included in the complaints. Generally, the lawsuits and complaints filed in California do not specify damages sought and are excluded from this amount.

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 242 wildfires. In May 2022, the Multnomah County Circuit Court granted issue class certification and consolidated the James case with several other cases. While PacifiCorp's pre-trial request for immediate appeal of the class certification was denied, it will have the opportunity to appeal the class issues post-judgment. 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. In September 2023, the Multnomah County Circuit Court ordered trial dates for two consolidated jury trials including approximately 10 class members each and a third trial for certain commercial timber plaintiffs wherein plaintiffs in each of the three trials will present evidence regarding their damages. The trials are scheduled at various dates from January to April 2024. A fourth jury trial is scheduled in May 2024 relating to certain nonclass plaintiffs associated with the Echo Mountain Complex fire. Hearings on PacifiCorp's post-trial motions are scheduled to be held November 9, 2023. Under ORS 82.010, interest at a rate of 9% per annum will accrue on the judgment commencing at the date the judgment is entered unless otherwise specified in the judgment. No judgment has yet been entered by the Multnomah County Circuit Court. PacifiCorp intends to appeal the jury's findings and damage awards in the James case, including whether the case can proceed as a class action. The appeals process and further actions could take several years.

Based on available information to date, PacifiCorp believes it is probable that losses will be incurred associated with the 2020 Wildfires. 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.

2022 McKinney Fire

According to the California Department of Forestry and Fire Protection, on July 29, 2022, the 2022 McKinney Fire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California 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, the California Public Utilities Commission, PacifiCorp and various experts engaged by PacifiCorp.

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.

PacifiCorp had previously not considered a loss probable related to the 2022 McKinney Fire; however, based on available information to date, PacifiCorp now believes it is probable a loss will be incurred associated with the 2022 McKinney Fire. Final determinations of liability will only be made following the completion of comprehensive investigations, litigation or similar processes.

Estimated Losses for the Wildfires

Based on the facts and circumstances available to PacifiCorp as of the date of this filing, including (i) ongoing cause and origin investigations; (ii) ongoing settlement and mediation discussions; (iii) other litigation matters and upcoming legal proceedings; and (iv) the status of the James case, PacifiCorp increased its accrual by $1,387 million during the three-month period ended September 30, 2023, bringing its cumulative estimated probable losses associated with the Wildfires to $2,405 million through September 30, 2023. PacifiCorp's cumulative accrual includes estimates of probable losses for fire suppression costs, real and personal property damages, natural resource damages and noneconomic damages such as personal injury damages and loss of life damages that it is reasonably able to estimate at this time and which is subject to change as additional relevant information becomes available.

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


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Beginning balance	$	948	$	477	$	424	$	252
Accrued losses	1,387		—		1,928		225
Payments	(57)		—		(74)		—
Ending balance	$	2,278	$	477	$	2,278	$	477

Until such time that settlement terms or other conclusions are reached to indicate that payments are expected to occur in the short-term, PacifiCorp's liability for estimated losses associated with the Wildfires is classified as a noncurrent liability on the Consolidated Balance Sheets.

PacifiCorp's receivable for expected insurance recoveries associated with the probable losses was $503 million and $246 million, respectively, as of September 30, 2023 and December 31, 2022 and is included in Other assets on the Consolidated Balance Sheets. During the three- and nine-month periods ended September 30, 2023, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $1,263 million and $1,671 million, respectively. During the three- and nine-month periods ended September 30, 2022, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $— million and $64 million, respectively. No additional insurance recoveries beyond those accrued to date are expected to be available.

It is reasonably possible PacifiCorp will incur material additional losses beyond the amounts accrued for the Wildfires that could have a material adverse effect on PacifiCorp's financial condition. PacifiCorp is currently unable to reasonably estimate a specific 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 the types of properties and damages and the ultimate outcome of legal actions.

HomeServices Antitrust Cases

HomeServices is currently defending against four antitrust cases, all in federal district courts. In each case, plaintiffs claim HomeServices and certain subsidiaries conspired with co-defendants to artificially inflate real estate commissions by following and enforcing multiple listing service ("MLS") rules that require listing agents to offer a commission split to cooperating agents in order for the property to appear on the MLS ("Cooperative Compensation Rule"). Three of the four cases are brought on behalf of sellers and one is brought on behalf of buyers. None of the complaints specify damages sought.

In April 2019, the Burnett (formerly Sitzer) et al. v. HomeServices of America, Inc. et al. complaint was filed in the U.S. District Court for the Western District of Missouri (the "Burnett case"). This lawsuit, which was certified as a class in April 2022, was originally brought on behalf of named plaintiffs Joshua Sitzer and Amy Winger against the National Association of Realtors ("NAR"), Anywhere Real Estate (formerly Realogy Holdings Corp.), HomeServices of America, Inc., RE/MAX, LLC, and Keller Williams Realty, Inc. HSF Affiliates, LLC and BHH Affiliates, LLC, each a subsidiary of HomeServices, were subsequently added as defendants. Rhonda Burnett became a lead class plaintiff in June 2021. The jury trial commenced on October 16, 2023, and the jury returned a verdict for the plaintiffs on October 31, 2023, finding that the named defendants participated in a conspiracy to follow and enforce the Cooperative Compensation Rule, which had the purpose or effect of raising, inflating, or stabilizing broker commission rates paid by home sellers. The jury further found that the class plaintiffs had proved damages in the amount of $1.8 billion. Federal law authorizes trebling of damages and the award of pre-judgment interest and attorney fees. Joint and several liability applies for the co-defendants. Prior to the trial, Anywhere Real Estate (formerly Realogy Holdings Corp.) and RE/MAX, LLC reached settlement agreements with the plaintiffs, which have not yet been approved by the court. Final judgment has not yet been entered by the U.S. District Court for the Western District of Missouri. HomeServices intends to vigorously appeal on multiple grounds the jury's findings and damage award in the Burnett case, including whether the case can proceed as a class action. The appeals process and further actions could take several years.

Based on available information to date, HomeServices believes losses are likely to occur as a result of the jury verdict in the Burnett case and that such damages could be up to $5.4 billion, excluding attorneys' fees, prejudgment interest and other costs subject to determination by the court. Under the current circumstances, HomeServices is currently unable to reasonably estimate such losses due to, among other reasons, the joint and several nature of the liability and the early stage of the appeals process; therefore, no loss has been accrued as of the date of this filing. While HomeServices intends to vigorously appeal any final judgment, the outcome of such appeals, if adverse, could have a material adverse effect on HomeServices’ financial condition.

It is also reasonably possible HomeServices will incur losses from the three remaining antitrust cases that could have a material adverse effect on HomeServices’ financial condition. HomeServices is currently unable to reasonably estimate a specific range of possible losses that could be incurred due to, among other reasons, the lack of information about the size of the plaintiff class and potential damages, as well as the joint and several nature of potential liability of the defendants.

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.

(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 September 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	$	1,543	$	773	$	1,448	$	—	$	—	$	—	$	—	$	(1)	$	3,763
Retail gas	—		77		28		—		—		—		—		—		105
Wholesale	47		81		15		—		—		—		—		(2)		141
Transmission and distribution	44		15		21		248		—		165		—		—		493
Interstate pipeline	—		—		—		—		551		—		—		(30)		521
Other	31		—		—		—		8		—		—		—		39
Total Regulated	1,665		946		1,512		248		559		165		—		(33)		5,062
Nonregulated	—		2		2		35		230		30		457		(2)		754
Total Customer Revenue	1,665		948		1,514		283		789		195		457		(35)		5,816
Other revenue	11		16		4		32		15		1		62		1		142
Total	$	1,676	$	964	$	1,518	$	315	$	804	$	196	$	519	$	(34)	$	5,958


	For the Nine-Month Period Ended September 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	$	4,124	$	1,833	$	3,339	$	—	$	—	$	—	$	—	$	(1)	$	9,295
Retail gas	—		463		167		—		—		—		—		—		630
Wholesale	134		233		55		—		—		—		—		(1)		421
Transmission and distribution	116		42		58		773		—		496		—		—		1,485
Interstate pipeline	—		—		—		—		1,971		—		—		(113)		1,858
Other	87		—		—		—		9		—		—		—		96
Total Regulated	4,461		2,571		3,619		773		1,980		496		—		(115)		13,785
Nonregulated	—		6		3		113		766		100		1,138		(1)		2,125
Total Customer Revenue	4,461		2,577		3,622		886		2,746		596		1,138		(116)		15,910
Other revenue	26		66		14		89		49		(3)		211		—		452
Total	$	4,487	$	2,643	$	3,636	$	975	$	2,795	$	593	$	1,349	$	(116)	$	16,362


	For the Three-Month Period Ended September 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	$	1,465	$	799	$	1,250	$	—	$	—	$	—	$	—	$	(1)	$	3,513
Retail gas	—		97		20		—		—		—		—		1		118
Wholesale	69		208		33		—		—		—		—		—		310
Transmission and distribution	54		16		24		260		—		168		—		—		522
Interstate pipeline	—		—		—		—		594		—		—		(26)		568
Other	24		—		—		—		1		—		—		(1)		24
Total Regulated	1,612		1,120		1,327		260		595		168		—		(27)		5,055
Nonregulated	—		1		—		71		326		16		440		1		855
Total Customer Revenue	1,612		1,121		1,327		331		921		184		440		(26)		5,910
Other revenue	23		27		7		28		43		(7)		67		(3)		185
Total	$	1,635	$	1,148	$	1,334	$	359	$	964	$	177	$	507	$	(29)	$	6,095


	For the Nine-Month Period Ended September 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	$	3,817	$	1,865	$	2,680	$	—	$	—	$	—	$	—	$	(2)	$	8,360
Retail gas	—		570		99		—		—		—		—		1		670
Wholesale	179		488		68		—		—		—		—		(2)		733
Transmission and distribution	131		44		59		803		—		516		—		—		1,553
Interstate pipeline	—		—		—		—		1,863		—		—		(94)		1,769
Other	72		—		1		—		2		—		—		(1)		74
Total Regulated	4,199		2,967		2,907		803		1,865		516		—		(98)		13,159
Nonregulated	—		3		1		128		889		38		1,156		—		2,215
Total Customer Revenue	4,199		2,970		2,908		931		2,754		554		1,156		(98)		15,374
Other revenue	47		80		18		88		101		(11)		165		(4)		484
Total	$	4,246	$	3,050	$	2,926	$	1,019	$	2,855	$	543	$	1,321	$	(102)	$	15,858

(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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Customer Revenue:
Brokerage	$	1,125	$	1,310	$	3,126	$	3,946
Franchise	16		18		43		55
Total Customer Revenue	1,141		1,328		3,169		4,001
Mortgage and other revenue	71		77		214		283
Total	$	1,212	$	1,405	$	3,383	$	4,284

Remaining Performance Obligations

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


	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total
BHE Pipeline Group	$	2,972	$	20,278	$	23,250
BHE Transmission	164		—		164
Total	$	3,136	$	20,278	$	23,414

(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)	65		(1,256)		148		—		(1,043)
Balance, September 30, 2022	$	(253)	$	(2,342)	$	207	$	5	$	(2,383)

Balance, December 31, 2022	$	(390)	$	(1,896)	$	135	$	2	$	(2,149)
Other comprehensive income (loss)	10		18		(23)		—		5
Purchase of noncontrolling interest	—		—		—		(1)		(1)
Balance, September 30, 2023	$	(380)	$	(1,878)	$	112	$	1	$	(2,145)

(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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Operating revenue:
PacifiCorp	$	1,676	$	1,635	$	4,487	$	4,246
MidAmerican Funding	964		1,148		2,643		3,050
NV Energy	1,518		1,334		3,636		2,926
Northern Powergrid	314		359		975		1,019
BHE Pipeline Group	804		964		2,795		2,855
BHE Transmission	196		177		593		543
BHE Renewables	519		506		1,349		1,320
HomeServices	1,212		1,405		3,383		4,284
BHE and Other(1)	(33)		(28)		(116)		(101)
Total operating revenue	$	7,170	$	7,500	$	19,745	$	20,142





Depreciation and amortization:
PacifiCorp	$	285	$	277	$	843	$	836
MidAmerican Funding	210		338		670		865
NV Energy	155		144		460		423
Northern Powergrid	97		92		267		272
BHE Pipeline Group	136		124		403		380
BHE Transmission	64		58		190		176
BHE Renewables	67		68		200		199
HomeServices	12		14		37		43
BHE and Other(1)	1		1		2		3
Total depreciation and amortization	$	1,027	$	1,116	$	3,072	$	3,197


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Operating income:
PacifiCorp	$	(943)	$	437	$	(979)	$	811
MidAmerican Funding	289		230		495		420
NV Energy	328		332		502		534
Northern Powergrid	102		151		369		420
BHE Pipeline Group	290		433		1,242		1,323
BHE Transmission	80		81		244		248
BHE Renewables	155		138		175		347
HomeServices	31		53		32		198
BHE and Other(1)	(18)		(32)		(53)		(35)
Total operating income	314		1,823		2,027		4,266
Interest expense	(603)		(555)		(1,788)		(1,637)
Capitalized interest	36		19		93		54
Allowance for equity funds	76		43		186		123
Interest and dividend income	110		40		323		93
(Losses) gains on marketable securities, net	(76)		(3,270)		926		(1,999)
Other, net	(3)		5		115		(16)
Total income (loss) before income tax expense (benefit) and equity income (loss)	$	(146)	$	(1,895)	$	1,882	$	884





Interest expense:
PacifiCorp	$	140	$	105	$	398	$	318
MidAmerican Funding	89		84		258		249
NV Energy	65		55		192		158
Northern Powergrid	26		31		86		97
BHE Pipeline Group	39		37		117		110
BHE Transmission	37		39		112		115
BHE Renewables	36		46		124		133
HomeServices	3		2		11		5
BHE and Other(1)	168		156		490		452
Total interest expense	$	603	$	555	$	1,788	$	1,637


Earnings (loss) on common shares:
PacifiCorp	$	(652)	$	409	$	(665)	$	622
MidAmerican Funding	321		300		803		745
NV Energy	278		270		402		392
Northern Powergrid	66		100		173		282
BHE Pipeline Group	175		234		731		755
BHE Transmission	59		59		181		183
BHE Renewables	160		176		445		585
HomeServices	25		29		25		134
BHE and Other(1)	54		(2,427)		438		(1,809)
Total earnings (loss) on common shares	$	486	$	(850)	$	2,533	$	1,889


	As of
	September 30,		December 31,
	2023		2022
Assets:
PacifiCorp	$	32,515	$	30,559
MidAmerican Funding	26,907		26,077
NV Energy	17,817		16,676
Northern Powergrid	9,223		9,005
BHE Pipeline Group	21,435		21,005
BHE Transmission	9,390		9,334
BHE Renewables	11,321		12,632
HomeServices	3,597		3,436
BHE and Other(1)	3,877		5,116
Total assets	$	136,082	$	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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Operating revenue by country:
U.S.	$	6,677	$	6,967	$	18,241	$	18,588
United Kingdom	308		351		936		1,011
Canada	179		174		529		535
Australia	6		8		39		8

Total operating revenue by country	$	7,170	$	7,500	$	19,745	$	20,142


Income (loss) before income tax expense (benefit) and equity income (loss) by country:
U.S.	$	(271)	$	(2,068)	$	1,462	$	395
United Kingdom	68		118		274		344
Canada	48		43		135		135
Australia	11		11		13		12
Other	(2)		1		(2)		(2)
Total income (loss) before income tax expense (benefit) and equity income (loss) by country	$	(146)	$	(1,895)	$	1,882	$	884

The following table shows the change in the carrying amount of goodwill by reportable segment for the nine-month period ended September 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	—		—		—		5		—		(6)		—		—		(1)
Other	—		—		—		—		—		—		—		(7)		(7)
September 30, 2023	$	1,129	$	2,102	$	2,369	$	922	$	1,814	$	1,455	$	95	$	1,596	$	11,482

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 November 2, 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.

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


	Third Quarter								First Nine Months
	2023		2022		Change				2023		2022		Change
Operating revenue:
PacifiCorp	$	1,676	$	1,635	$	41	3	%	$	4,487	$	4,246	$	241	6	%
MidAmerican Funding	964		1,148		(184)		(16)		2,643		3,050		(407)		(13)
NV Energy	1,518		1,334		184		14		3,636		2,926		710		24
Northern Powergrid	314		359		(45)		(13)		975		1,019		(44)		(4)
BHE Pipeline Group	804		964		(160)		(17)		2,795		2,855		(60)		(2)
BHE Transmission	196		177		19		11		593		543		50		9
BHE Renewables	519		506		13		3		1,349		1,320		29		2
HomeServices	1,212		1,405		(193)		(14)		3,383		4,284		(901)		(21)
BHE and Other	(33)		(28)		(5)		(18)		(116)		(101)		(15)		(15)
Total operating revenue	$	7,170	$	7,500	$	(330)	(4)	%	$	19,745	$	20,142	$	(397)	(2)	%

Earnings (loss) on common shares:
PacifiCorp	$	(652)	$	409	$	(1,061)	*		$	(665)	$	622	$	(1,287)	*
MidAmerican Funding	321		300		21		7		803		745		58		8
NV Energy	278		270		8		3		402		392		10		3
Northern Powergrid	66		100		(34)		(34)		173		282		(109)		(39)
BHE Pipeline Group	175		234		(59)		(25)		731		755		(24)		(3)
BHE Transmission	59		59		—		—		181		183		(2)		(1)
BHE Renewables(1)	160		176		(16)		(9)		445		585		(140)		(24)
HomeServices	25		29		(4)		(14)		25		134		(109)		(81)
BHE and Other	54		(2,427)		2,481		*		438		(1,809)		2,247		*
Total earnings (loss) on common shares	$	486	$	(850)	$	1,336	*		$	2,533	$	1,889	$	644	34	%

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

* Not meaningful

Earnings on common shares increased $1,336 million for the third quarter of 2023 compared to 2022. Included in these results was a pre-tax loss in the third quarter of 2023 of $69 million ($54 million after-tax) compared to a pre-tax loss in the third quarter of 2022 of $3,258 million ($2,574 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 third quarter of 2023 was $540 million, a decrease of $1,184 million, or 69%, compared to adjusted earnings on common shares for the third quarter of 2022 of $1,724 million.

Earnings on common shares increased $644 million for the first nine months of 2023 compared to 2022. Included in these results was a pre-tax gain in the first nine months of 2023 of $915 million ($723 million after-tax) compared to a pre-tax loss in the first nine months of 2022 of $1,948 million ($1,539 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 nine months of 2023 was $1,810 million, a decrease of $1,618 million, or 47%, compared to adjusted earnings on common shares for the first nine months of 2022 of $3,428 million.

The increases in earnings on common shares for the third quarter and for the first nine months of 2023 compared to 2022 were primarily due to the following:

•The Utilities' earnings decreased $1,032 million for the third quarter and $1,219 million for the first nine months of 2023 compared to 2022, largely due to increases in wildfire loss accruals, net of expected insurance recoveries, higher operations and maintenance expense, increased interest expense and lower electric utility margin. These items were offset by lower depreciation and amortization expense, higher allowances for equity and borrowed funds used during construction, increased interest and dividend income and favorable changes in the cash surrender value of corporate-owned life insurance policies. Electric retail customer volumes decreased 0.6% for the first nine months of 2023 compared to 2022, primarily due to the unfavorable impact of weather, partially offset by an increase in the average number of customers and higher customer usage;

•Northern Powergrid's earnings decreased $34 million for the third quarter and $109 million for the first nine months of 2023 compared to 2022, primarily due to unfavorable operating performance at CE Gas, increased non-service benefit plan costs and income tax expense related to the enactment of a new Energy Profits Levy income tax. Units distributed declined 4.7% for the first nine months of 2023 compared to 2022 due to the unfavorable impact of weather and lower customer usage;

•BHE Pipeline Group's earnings decreased $59 million for the third quarter and $24 million for the first nine months of 2023 compared to 2022, largely due to higher operations and maintenance expense, favorable income tax adjustments recognized at BHE GT&S in 2022 and lower earnings at Cove Point as a result of increased scheduled maintenance days in 2023, partially offset by the impact of a general rate case, with interim rates effective January 1, 2023, subject to refund, at Northern Natural Gas;

•BHE Renewables' earnings decreased $16 million for the third quarter and $140 million for the first nine 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, lower natural gas and geothermal earnings for the first nine months due to maintenance outages and higher development costs, lower solar earnings from lower generation 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 $4 million for the third quarter and $109 million for the first nine 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 increased $2,481 million for the third quarter and $2,247 million for the first nine months of 2023 compared to 2022, mainly due to $2,520 million and $2,262 million, respectively, of favorable comparative changes in fair value related to the Company's investment in BYD, partially offset by lower federal income tax credits recognized on a consolidated basis.

Reportable Segment Results

PacifiCorp

Operating revenue increased $41 million for the third quarter of 2023 compared to 2022, primarily due to higher retail revenue of $76 million, partially offset by lower wholesale and other revenue of $35 million, primarily due to lower average wholesale market prices and volumes. Retail revenue increased primarily due to price impacts of $111 million from higher average retail rates largely due to tariff changes, partially offset by $36 million from lower retail volumes. Retail customer volumes decreased 2.3%, primarily due to the unfavorable impact of weather, partially offset by an increase in the average number of customers and higher customer usage.

Earnings decreased $1,061 million for the third quarter of 2023 compared to 2022, primarily due to an increase in wildfire loss accruals, net of expected insurance recoveries, of $1,263 million, higher operations and maintenance expense of $67 million, lower utility margin of $42 million, increased interest expense of $35 million due to debt issuances in December 2022 and May 2023 and an unfavorable income tax benefit from lower PTCs recognized of $19 million and the effects of ratemaking of $10 million. These items were partially offset by higher allowances for equity and borrowed funds used during construction of $31 million and increased interest and dividend income of $13 million. Operations and maintenance expense increased due to higher wildfire mitigation and vegetation management costs, increased general and plant maintenance costs, increased insurance premiums and higher legal expenses. Utility margin decreased primarily due to higher purchased power and thermal generation costs, lower retail volumes and lower average wholesale market prices and volumes, partially offset by higher retail rates and favorable deferred net power costs.

Operating revenue increased $241 million for the first nine months of 2023 compared to 2022, primarily due to higher retail revenue of $293 million, partially offset by lower wholesale revenue and other revenue of $52 million, primarily due to lower volumes, partially offset by higher average wholesale market prices. Retail revenue increased primarily due to price impacts of $300 million from higher average retail rates largely due to tariff changes and product mix, partially offset by $7 million from lower volumes. Retail customer volumes decreased 0.5%, 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 $1,287 million for the first nine months of 2023 compared to 2022, primarily due to an increase in wildfire loss accruals, net of expected insurance recoveries, of $1,607 million, higher operations and maintenance expense of $179 million, increased interest expense of $80 million due to debt issuances in December 2022 and May 2023 and lower utility margin of $2 million. These items were partially offset by higher allowances for equity and borrowed funds used during construction of $81 million, increased interest and dividend income of $44 million and a favorable income tax benefit from valuation changes on state net operating loss carryforwards, partially offset by lower PTCs recognized of $8 million. Operations and maintenance expense increased due to higher wildfire mitigation and vegetation management costs, increased general and plant maintenance costs, higher legal expenses and increased insurance premiums. Utility margin decreased primarily due to higher purchased power and thermal generation costs and lower wholesale volumes, partially offset by higher retail rates, favorable deferred net power costs and higher average wholesale market prices.

MidAmerican Funding

Operating revenue decreased $184 million for the third quarter of 2023 compared to 2022, primarily due to lower electric operating revenue of $140 million and lower natural gas operating revenue of $45 million. Electric operating revenue decreased due to lower wholesale and other revenue of $115 million and lower retail revenue of $25 million. Electric wholesale and other revenue decreased mainly due to lower average wholesale per-unit prices of $87 million and lower wholesale volumes of $25 million. Electric retail revenue decreased primarily due to lower recoveries through adjustment clauses of $29 million (fully offset in expense, primarily cost of sales), partially offset by $3 million from higher retail volumes. Electric retail customer volumes increased 0.9%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather. Natural gas operating revenue decreased due to a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $51 million (fully offset in cost of sales), partially offset by higher average rates of $4 million.

Earnings increased $21 million for the third quarter of 2023 compared to 2022, primarily due to lower depreciation and amortization expense of $128 million and higher allowances for equity and borrowed funds used during construction of $7 million, partially offset by lower electric utility margin of $70 million and an unfavorable income tax benefit, primarily from the effects of ratemaking of $25 million and lower PTCs recognized of $8 million. Depreciation and amortization expense decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Electric utility margin decreased primarily due to the lower wholesale and retail revenues, partially offset by lower purchased power and thermal generation costs.

Operating revenue decreased $407 million for the first nine months of 2023 compared to 2022, primarily due to lower electric operating revenue of $221 million and lower natural gas operating revenue of $189 million. Electric operating revenue decreased due to lower wholesale and other revenue of $188 million and lower retail revenue of $33 million. Electric wholesale and other revenue decreased mainly due to lower average wholesale per-unit prices of $133 million and lower wholesale volumes of $53 million. Electric retail revenue decreased primarily due to lower recoveries through adjustment clauses of $42 million (fully offset in expense, primarily cost of sales), partially offset by $5 million from higher retail volumes and price impacts of $4 million from changes in sales mix. Electric retail customer volumes increased 1.1%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather. Natural gas operating revenue decreased due to a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $187 million (fully offset in cost of sales) and the unfavorable impact of weather of $9 million, partially offset by higher average rates of $5 million.

Earnings increased $58 million for the first nine months of 2023 compared to 2022, primarily due to lower depreciation and amortization expense of $195 million, favorable changes in the cash surrender value of corporate-owned life insurance policies of $34 million and a one-time gain on the sale of an investment of $13 million, partially offset by lower electric utility margin of $80 million, an unfavorable income tax benefit, largely from the effects of ratemaking of $24 million and lower PTCs recognized of $21 million, and higher operations and maintenance expense of $33 million. Depreciation and amortization expense decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Electric utility margin decreased primarily due to the lower wholesale and retail revenues, partially offset by lower purchased power and thermal generation costs. Operations and maintenance expense increased mainly due to increased administrative and other costs, higher general and plant maintenance costs and unfavorable property insurance costs.

NV Energy

Operating revenue increased $184 million for the third quarter of 2023 compared to 2022, primarily due to higher electric operating revenue of $177 million and higher natural gas operating revenue of $7 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 $175 million and increased base tariff general rates of $15 million at Sierra Pacific, partially offset by lower customer volumes of $19 million. Electric retail customer volumes decreased 3.0%, 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 $8 million for the third quarter of 2023 compared to 2022, primarily due to higher allowances for equity and borrowed funds used during construction of $13 million, lower operations and maintenance expense of $7 million, favorable interest and dividend income of $5 million, mainly from carrying charges on higher deferred energy balances, and higher electric utility margin of $2 million, partially offset by higher depreciation and amortization expense of $11 million and increased interest expense of $10 million due to higher outstanding long-term debt balances and higher average interest rates. Operations and maintenance expense decreased primarily due to a favorable change in earnings sharing at Nevada Power. Electric utility margin increased primarily due to higher base tariff general rates at Sierra Pacific, partially offset by lower retail customer volumes. Depreciation and amortization expense increased largely due to additional assets placed in-service.

Operating revenue increased $710 million for the first nine months of 2023 compared to 2022, primarily due to higher electric operating revenue of $643 million and higher natural gas operating revenue of $67 million largely 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 $610 million, increased base tariff general rates of $42 million at Sierra Pacific and higher transmission and wholesale revenue of $7 million, partially offset by lower customer volumes of $36 million. Electric retail customer volumes decreased 2.3%, 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 $10 million for the first nine months of 2023 compared to 2022, primarily due to favorable interest and dividend income of $33 million, mainly from carrying charges on higher deferred energy balances, higher electric utility margin of $32 million, increased allowances for equity and borrowed funds used during construction of $27 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $13 million, partially offset by higher depreciation and amortization expense of $37 million, increased interest expense of $34 million due to higher outstanding long-term debt balances and higher average interest rates and higher operations and maintenance expense of $27 million. 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. Depreciation and amortization expense increased largely due to additional assets placed in-service. Operations and maintenance expense increased primarily due to higher general and plant maintenance costs and higher customer service operations costs, partially offset by a favorable change in earnings sharing at Nevada Power.

Northern Powergrid

Operating revenue decreased $45 million for the third quarter of 2023 compared to 2022, primarily due to lower revenue at CE Gas of $45 million and lower distribution revenue of $30 million, partially offset by $22 million from the weaker U.S. dollar and higher non-regulated contracting revenue of $6 million. CE Gas revenue decreased due to lower gas production volumes and prices from a gas project that commenced commercial operation in March 2022. Distribution revenue decreased primarily due to lower recoveries of Supplier of Last Resort payments of $28 million (largely offset in cost of sales).

Earnings decreased $34 million for the third quarter of 2023 compared to 2022, primarily due to unfavorable operating performance at CE Gas of $49 million, partially offset by favorable income tax expense from adjustments to the Energy Profits Levy income tax and $4 million from the weaker U.S. dollar. The unfavorable operating performance at CE Gas was largely due to lower gas production volumes and prices from a gas project that commenced commercial operation in March 2022.

Operating revenue decreased $44 million for the first nine months of 2023 compared to 2022, primarily due to lower revenue at CE Gas of $36 million, lower distribution revenue of $23 million and $7 million from the stronger U.S. dollar, partially offset by higher non-regulated contracting revenue of $18 million. 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 operations in June 2022. Distribution revenue decreased primarily due to lower recoveries of Supplier of Last Resort payments of $18 million (largely offset in cost of sales) and a 4.7% decline in units distributed of $11 million, largely due to the unfavorable impact of weather and lower customer usage, partially offset by higher tariff rates of $8 million.

Earnings decreased $109 million for the first nine months of 2023 compared to 2022, primarily due to unfavorable operating performance at CE Gas of $41 million, unfavorable income tax expense related to the enactment of a new Energy Profits Levy income tax and increased non-service benefit plan costs of $26 million. The unfavorable operating performance at CE Gas was largely 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 operations in June 2022.

BHE Pipeline Group

Operating revenue decreased $160 million for the third quarter of 2023 compared to 2022, primarily due to lower operating revenue of $155 million at BHE GT&S. The decrease in operating revenue at BHE GT&S was primarily due to lower non-regulated revenue of $86 million (largely offset in cost of sales) from lower volumes and unfavorable commodity prices and lower LNG revenue of $68 million at Cove Point.

Earnings decreased $59 million for the third quarter of 2023 compared to 2022, primarily due to lower earnings of $68 million at BHE GT&S, partially offset by higher earnings of $21 million at Northern Natural Gas, mainly from higher transportation revenue. The decrease at BHE GT&S was largely due to favorable income tax adjustments recognized in 2022, higher operations and maintenance expense of $28 million, mainly due to increases in technology, pension and outside services costs, and lower earnings at Cove Point as a result of increased scheduled maintenance days in 2023.

Operating revenue decreased $60 million for the first nine months of 2023 compared to 2022, primarily due to lower operating revenue of $150 million at BHE GT&S, partially offset by higher operating revenue of $98 million at Northern Natural Gas. The decrease in operating revenue at BHE GT&S was primarily due to lower nonregulated revenue of $177 million (largely offset in cost of sales) from lower volumes and unfavorable commodity prices, lower LNG revenue of $36 million at Cove Point and lower volumes at EGTS primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $26 million, partially offset by an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $45 million and an increase in variable revenue related to natural gas storage park and loan activity of $22 million at EGTS. 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 $80 million and higher transportation revenue of $60 million from higher rates, partially offset by lower gas sales of $51 million (largely offset in cost of sales) from system balancing activities.

Earnings decreased $24 million for the first nine months of 2023 compared to 2022, primarily due to lower earnings of $92 million at BHE GT&S, partially offset by higher earnings of $78 million at Northern Natural Gas. The decrease at BHE GT&S was due to favorable income tax adjustments recognized in 2022, increased cost of gas of $74 million from operational and system balancing fuel activities at EGTS prior to the effective date of the new fuel tracker and the unfavorable revaluation of volumes retained at EGTS due to lower natural gas prices and higher operations and maintenance expense of $60 million, partially offset by the favorable rate case settlement at EGTS in 2022 of $51 million and the variable revenue increase related to natural gas storage park and loan activity at EGTS. Operations and maintenance expense increased at BHE GT&S mainly due to higher technology, pension and outside services costs. The increase at Northern Natural Gas was due to the impacts of the general rate case of $54 million and the higher transportation revenue, partially offset by higher operations and maintenance expense of $27 million, an increase in depreciation and amortization expense of $11 million and unfavorable margin on gas sales from system balancing activities of $9 million.

BHE Transmission

Operating revenue increased $19 million for the third quarter of 2023 compared to 2022, primarily due to $14 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 $5 million from the stronger U.S. dollar.

Earnings for the third quarter of 2023 were equal to 2022, primarily due to the higher non-regulated revenue at BHE Canada offset by losses from non-regulated wind-powered generating facilities acquired in November 2022.

Operating revenue increased $50 million for the first nine months of 2023 compared to 2022, primarily due to $56 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 $26 million from the stronger U.S. dollar.

Earnings decreased $2 million for the first nine months of 2023 compared to 2022, primarily due to $7 million from the stronger U.S. dollar, partially offset by the higher non-regulated revenue at BHE Canada.

BHE Renewables

Operating revenue increased $13 million for the third quarter of 2023 compared to 2022, primarily due to higher natural gas and geothermal revenues of $39 million, primarily due to favorable pricing, and higher wind revenues of $8 million, partially offset by lower natural gas and electric retail energy services revenue of $13 million and lower solar revenue of $11 million, primarily from lower generation. Wind revenue increased mainly due to favorable changes in the valuations of certain derivative contracts. Retail energy services revenue decreased mainly due to unfavorable natural gas pricing and electric retail volumes, partially offset by favorable natural gas volumes and electricity pricing.

Earnings decreased $16 million for the third quarter of 2023 compared to 2022, primarily due to lower wind earnings of $24 million, lower earnings of $7 million from the retail energy services business, largely due to lower retail gas and electric revenue, and lower solar earnings of $6 million, primarily due to lower generation, partially offset by higher natural gas and geothermal earnings of $22 million. Wind earnings decreased due to lower earnings from tax equity investments of $41 million due to lower PTCs, partially offset by higher earnings at owned wind projects of $17 million, primarily due to lower interest expense from the extinguishment of debt and favorable derivative contract valuations. Natural gas and geothermal earnings increased primarily due to favorable pricing, partially offset by higher geothermal development costs and maintenance outages.

Operating revenue increased $29 million for the first nine months of 2023 compared to 2022, primarily due to higher wind revenue of $75 million and higher natural gas and geothermal revenue of $31 million, primarily due to favorable pricing, partially offset by lower solar revenues of $46 million, primarily from lower generation, and lower natural gas and electric retail energy services revenue of $11 million. Wind revenue increased primarily due to favorable changes in the valuations of certain derivative contracts of $90 million, partially offset by lower generation of $21 million. Retail energy services revenue decreased mainly due to unfavorable natural gas pricing, partially offset by an increase in natural gas volumes and favorable changes in the valuation of derivative contracts.

Earnings decreased $140 million for the first nine months of 2023 compared to 2022, primarily due to lower earnings of $105 million from the retail energy services business, largely due to unfavorable changes in unrealized positions on derivative contracts, lower natural gas and geothermal earnings of $35 million, primarily due to maintenance outages and higher geothermal development costs, and lower solar earnings of $34 million, largely from lower generation, partially offset by higher wind earnings of $39 million. Wind earnings were favorable due to increased earnings from owned projects of $98 million, partially offset by lower earnings from tax equity investments of $59 million due to lower PTCs. Earnings from owned projects were higher primarily due to 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 $193 million for the third quarter of 2023 compared to 2022, primarily due to lower brokerage and settlement services revenue of $187 million from a 15% decrease in closed transaction volume due to rising interest rates and a corresponding decline in home sales.

Earnings decreased $4 million for the third quarter of 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services of $11 million, partially offset by higher earnings from mortgage services of $4 million. Earnings declined due to the decrease in closed brokerage transaction volume, partially offset by favorable operating expenses primarily due to lower compensation costs.

Operating revenue decreased $901 million for the first nine months of 2023 compared to 2022, primarily due to lower brokerage and settlement services revenue of $824 million and lower mortgage revenue of $70 million. The decrease in brokerage and settlement services revenue resulted from a 22% 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 33% decrease in funded volume, primarily due to rising interest rates.

Earnings decreased $109 million for the first nine months of 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services of $87 million and mortgage services of $18 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 decreased $5 million for the third quarter of 2023 and $15 million for the first nine months of 2023 compared to 2022, due to changes in intersegment eliminations.

Earnings increased $2,481 million for the third quarter of 2023 compared to 2022, primarily due to the Company's investment in BYD, including the $2,520 million favorable comparative change in fair value and $28 million of higher net interest and dividend income, partially offset by $56 million of lower federal income tax credits recognized on a consolidated basis and higher BHE corporate interest expense from an April 2022 debt issuance.

Earnings increased $2,247 million for the first nine months of 2023 compared to 2022, primarily due to the Company's investment in BYD, including the $2,262 million favorable comparative change in fair value and $103 million of higher net interest and dividend income, favorable changes in the cash surrender value of corporate-owned life insurance policies of $40 million and $12 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain insurance subsidiaries of Berkshire Hathaway. These items were partially offset by $102 million of lower federal income tax credits recognized on a consolidated basis and higher BHE corporate interest expense from an April 2022 debt issuance.

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.

As of September 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	$	397	$	98	$	700	$	78	$	30	$	71	$	296	$	377	$	2,047

Credit facilities(1)	3,500		2,000		1,509		1,000		334		792		2,355		—		11,490
Less:
Short-term debt	(747)		(165)		—		—		(91)		(36)		(578)		—		(1,617)
Tax-exempt bond support and letters of credit	—		(249)		(306)		—		—		(1)		—		—		(556)
Net credit facilities	2,753		1,586		1,203		1,000		243		755		1,777		—		9,317

Total net liquidity	$	3,150	$	1,684	$	1,903	$	1,078	$	273	$	826	$	2,073	$	377	$	11,364
Credit facilities:
Maturity dates	2026		2026		2024, 2026		2026		2025		2024, 2026, 2027		2023, 2024, 2026

(1)Includes $91 million drawn on capital expenditure and other uncommitted credit facilities at Northern Powergrid.

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022, were $5.9 billion and $7.9 billion, respectively. The decrease was primarily due to unfavorable operating results, the timing of payments related to fuel and energy costs and a decrease in income tax receipts, partially offset by changes in working capital.

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

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2023 and 2022, were $(3.2) billion and $(5.5) billion, respectively. The change was primarily due to higher proceeds from sales and maturities, net of purchases, of U.S. Treasury Bills totaling $2.0 billion and higher proceeds from sales, net of purchases, of marketable securities of $1.3 billion, partially offset by higher capital expenditures of $1.1 billion. Refer to "Future Uses of Cash" for a discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2023, was $(2.1) billion. Sources of cash totaled $3.9 billion and consisted of proceeds from subsidiary debt issuances totaling $3.4 billion and net proceeds from short-term debt totaling $498 million. Uses of cash totaled $6.0 billion and consisted mainly of $3.3 billion for the purchase of Cove Point noncontrolling interest, repayments of subsidiary debt totaling $1.9 billion, repayments of BHE senior debt totaling $400 million and distributions to noncontrolling interests of $357 million.

For a discussion of business acquisitions and recent financing transactions, refer to Note 3 and Note 6, respectively, of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Net cash flows from financing activities for the nine-month period ended September 30, 2022, was $(1.6) billion. 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 $1.0 billion. Uses of cash totaled $3.8 billion and consisted mainly of repayments of subsidiary debt totaling $882 million, purchases of common stock totaling $870 million, preferred stock redemptions of $800 million, net repayments of short-term debt totaling $540 million and distributions to noncontrolling interests of $395 million.

Future Uses of Cash

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

Capital Expenditures

The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to 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):


	Nine-Month Periods				Annual
	Ended September 30,				Forecast
	2022		2023		2023
Capital expenditures by business:
PacifiCorp	$	1,481	$	2,250	$	3,322
MidAmerican Funding	1,404		1,339		1,878
NV Energy	801		1,386		2,006
Northern Powergrid	614		405		556
BHE Pipeline Group	800		827		1,338
BHE Transmission	143		159		220
BHE Renewables	100		111		264
HomeServices	31		30		38
BHE and Other(1)	11		19		20
Total	$	5,385	$	6,526	$	9,642





Capital expenditures by type:
Wind generation	$	582	$	1,109	$	1,658
Electric distribution	1,297		1,639		2,224
Electric transmission	1,174		1,226		2,094
Natural gas transmission and storage	640		649		957
Solar generation	332		305		387
Electric battery and pumped hydro storage	7		123		261
Other	1,353		1,475		2,061
Total	$	5,385	$	6,526	$	9,642

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

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

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

◦Construction of wind-powered generating facilities at MidAmerican Energy totaling $460 million and $39 million for the nine-month periods ended September 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 $171 million for the remainder of 2023.

◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $48 million and $422 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for the repowering of wind-powered generating facilities totals $21 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 $540 million and $21 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $260 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 $13 million and $45 million for the nine-month period ended September 30, 2023 September 30, 2022. Planned spending for the repower of wind-powered facilities totals $37 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 $536 million and $643 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for these Energy Gateway Transmission segments totals $411 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 $141 million and $91 million for the nine-month periods ended September 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 $76 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.

•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 $3 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 nine-month periods ended September 30, 2023 and 2022, solar generation spending totaled $11 million and $103 million, respectively. Planned spending totals $10 million for the remainder of 2023.

◦Construction of a solar-powered generating facility at Nevada Power totaling $175 million and $47 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending totals $29 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 $28 million and $22 million for the nine-month periods ended September 30, 2023 and 2022. Planned spending totals $31 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 nine-month period ended September 30, 2023, was $106 million with planned spending of $136 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.

Material Cash Requirements

As of September 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.

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%, which was 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 October 2023, in response to discussions with the OPUC staff, PacifiCorp requested the effective date for the WMP AAC shift to December 13, 2023, to allow more time for the OPUC staff to review the filing.

In April 2023, PacifiCorp filed its transition adjustment mechanism ("TAM") 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. In July 2023, PacifiCorp updated its filing to reduce the requested rate increase to $131 million to reflect changes in PacifiCorp's forecast net power costs for 2024. In September 2023, a stipulation with certain intervening parties was filed settling substantially all issues in the 2024 TAM and in October 2023, the OPUC issued an order approving the stipulation. A final update to be filed in November 2023 will determine the rate increase effective January 1, 2024.

In May 2023, PacifiCorp filed its 2022 PCAM requesting recovery of the difference between actual power costs and base power costs established in the 2022 TAM. The filing requested recovery of $131 million, which PacifiCorp proposed to recover over a two-year period with interest, resulting in a rate increase of $69 million, or 4.0%, effective January 1, 2024. In October 2023, a stipulation was filed providing for the requested amounts. As established in the stipulation, if the combined January 1, 2024 rate increase for residential customers from all January 1 rate changes is greater than 15%, PacifiCorp will delay the rate effective date of the 2022 PCAM for residential customers to April 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 September 2023, PacifiCorp filed updated testimony that included updated net power costs and increased insurance premium costs associated with wildfire liability coverage. As a result of the updates, the requested rate increase has been revised to $137 million, or 21.1%.

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%, which was effective on an interim basis July 1, 2023. In October 2023, PacifiCorp filed rebuttal testimony updating the energy cost adjustment mechanism calculation. As a result of the updates, the requested combined rate increase has been revised to $42 million, or 6.3%, to be effective at the time of a Wyoming Public Service Commission order or February 15, 2024, whichever date comes first.

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 October 2023, PacifiCorp filed updated testimony that included updated net power costs, increased insurance premium costs and removal of some capital projects. As a result of the updates, the requested rate increases have been revised to $19 million, or 4.6%, to become effective March 1, 2024, and $22 million, or 5.2%, to become effective March 1, 2025.

In June 2023, PacifiCorp filed its PCAM 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 IPUC 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.

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 late 2024. In October 2023, PacifiCorp filed updated testimony in the first track that removed the costs considered in the second track, as directed by the CPUC. The updated testimony clarified that the rate increase for the first track is $22 million, or 20.1%.

In September 2023, PacifiCorp filed its 2024 combined energy cost adjustment clause ("ECAC") and greenhouse gas related costs ("GHG") application requesting an overall rate increase of $30 million, or 25.0%, effective March 1, 2024. Approximately $36 million of the increase is attributed to the ECAC rate, which is offset by $6 million decrease to the GHG rate.

Deferral Accounting Treatment for Increased Costs Associated with Wildfires

In June 2023, PacifiCorp filed deferral applications with the UPSC, the OPUC, the Wyoming Public Service Commission, the WUTC and the IPUC 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. In August 2023, PacifiCorp filed a motion to withdraw without prejudice with the UPSC, and in September 2023, PacifiCorp filed a notice of withdrawal without prejudice with the IPUC. These filings preserve the ability of PacifiCorp to file for deferred accounting treatment when the actual liability costs are more certain.

In June 2023, PacifiCorp filed an application with the CPUC for authority to establish a Wildfire Expense Memorandum Account to track the costs associated with third-party liability from litigation due to the 2020 Wildfires, increased insurance premium costs associated with wildfire coverage and costs associated with potential liability for future catastrophic wildfires.

In August 2023, PacifiCorp filed deferral applications with the UPSC, the OPUC, the WUTC and the IPUC for costs associated with increased insurance premium costs arising from the impacts to the commercial insurance markets that have occurred due to wildfire liability risk.

MidAmerican Energy

Iowa

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. On September 6, 2023, the IUB issued a procedural schedule with hearing set to begin on January 9, 2024.

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. 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 and set rehearing for October 10, 2023. In August 2023, MidAmerican Energy, the Iowa Office of Consumer Advocate and the Environmental Intervenors filed a revised non-unanimous settlement with the IUB that included a rate of return of 10.75%. The settlement would also benefit customers by providing a rate decrease through lower retail fuel costs and future rate increase mitigation through accelerated depreciation of generation assets. On October 10, 2023, the IUB completed the rehearing. MidAmerican Energy expects the IUB to issue an order on the revised non-unanimous settlement by the end of 2023.

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 collaborated to resist the motion and submit a cross motion for summary judgment. The Iowa district court held a hearing on the motions for summary judgment on September 29, 2023, and asked the parties to file draft orders addressing remedies should the court determine the statute is invalid. In October 2023, all parties filed the draft orders addressing remedies that were requested by the Iowa district court. A decision is expected by late November 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.

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 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. In August 2023, the Nevada Utilities' filed a notice to implement quarterly changes to the BTER and DEAA rates within the maximum allowable adjustment returning to an ordinary level of adjustment. In October 2023, the PUCN approved the BTER and DEAA rates effective October 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. In August, 2023, Nevada Power filed an updated certification filing that requested an annual revenue increase of $96 million, or 3.3%. Parties to the review filed testimony and evidence in August and September 2023. Hearings in the cost of capital and revenue requirement phases were held in October 2023. The hearings in the rate design phase are scheduled for November 2023. An order is expected by the end of 2023 and, if approved, rates 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, which confirmed its Final Determination on September 21, 2023. The CMA upheld Northern Powergrid's appeal in relation to Ofgem's misallocation of allowances that is inconsistent with efficient costs. The CMA found that GEMA's decision was unlawful on the grounds of irrationality. The CMA has remitted the matter back to Ofgem to determine and implement a remedy, with the result having the potential to increase Northern Powergrid's cost allowances for the period April 2023 to March 2028 up to £160 million in 2020/21 prices. Ofgem successfully defended its decision not to grant Northern Powergrid a reward under its Business Plan Incentive mechanism.

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.

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%, Field Area transportation reservation rates increased 20.5% 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, including accrued interest, totaled $92 million. In September 2023, the FERC approved the settlement agreement and the rate refunds to customers were processed in October 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. The application also requested 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 required the schedule delay to amend its application in response to the unprecedented wildfire events that AltaLink experienced in Alberta, Canada in May and June 2023. In August 2023, AltaLink filed an amendment to its 2024-2025 GTA. The amendment increased AltaLink's Wildfire Mitigation Plan capital expenditures from C$16.0 million to C$38.5 million in 2024 and from C$14.6 million to C$38.4 million for 2025. AltaLink's total amended transmission tariffs for 2024 and 2025 are C$903.5 million and C$911.9 million, respectively. AltaLink also plans to file an application with the AUC later this year to recover all costs incurred as a result of the May and June 2023 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 generic cost of capital 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.

In October 2023, the AUC issued its decision on the Generic Cost of Capital for 2024 and beyond for Alberta's regulated electric and gas utilities, approving a set equity ratio and a formula to determine return on equity. The AUC set the deemed equity ratio at 37% and set a notional return on equity of 9.00%, which is subject to formulaic adjustments utilizing 30-year Government of Canada bond yields and Canadian utility spreads. In November 2023, the AUC will set and provide utilities with the approved return on equity for 2024 and will provide the same in November of each year going forward.

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 accepted 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.

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.

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.

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. 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 seven different regional federal courts of appeal. Stays have been granted by six circuit courts for SIP disapprovals in 12 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 took effect August 4, 2023. The EPA issued several interim final rules stating that the federal rule will not take effect in states in which the SIP disapprovals have been deferred or stayed. The EPA published its proposed approval of Wyoming's SIP on August 14, 2023 and accepted comments through September 13, 2023. 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 four different circuit courts. On September 25, 2023, the D.C. Circuit denied the motion to stay the Good Neighbor Rule filed by several state and industry parties. The denial means that states that do not have stays on their SIP disapprovals are subject to the Good Neighbor Rule. The states of Ohio, Indiana and West Virginia filed a request for stay of the Good Neighbor Rule with the U.S. Supreme Court on October 13, 2023. Several industry groups representing utilities as well as pipeline, paper, cement and other industries affected by the rule filed supportive requests for stay on the same day. 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.

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. On August 14, 2023, the Tenth Circuit denied the petition to vacate Utah's first planning period regional haze plan.

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 on other parts of 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 an 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. On August 15, 2023, the Tenth Circuit remanded the Wyodak portion of Wyoming's state plan to EPA for further review. For Naughton Units 1 and 2, the court determined EPA properly approved Wyoming's Naughton determination and denied environmental groups' petition. 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 the end of 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.

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 has not yet made determinations on these plans. It was 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 U.S. Supreme Court significantly narrowed protections for wetlands and intermittent streams under the federal Clean Water Act. The U.S. Supreme Court unanimously rejected the significant nexus test as unworkable. A divided U.S. Supreme 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 U.S. Supreme Court's decision. On September 8, 2023, the EPA issued a new rule conforming to the U.S. Supreme Court's decision.

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.

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.

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.

PacifiCorp and its subsidiaries

Consolidated Financial Section

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PacifiCorp

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of September 30, 2023, the related consolidated statements of operations, and changes in shareholders' equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 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.

/s/ Deloitte & Touche LLP

Portland, Oregon

November 3, 2023

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	September 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	98	$	641
Trade receivables, net	886		825
Other receivables, net	89		72
Inventories	519		474
Derivative contracts	47		184

Regulatory assets	459		275
Prepaid expenses	146		102
Other current assets	70		111
Total current assets	2,314		2,684

Property, plant and equipment, net	26,099		24,430
Regulatory assets	1,931		1,605
Other assets	1,023		686

Total assets	$	31,367	$	29,405

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	September 30,		December 31,
	2023		2022
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	1,204	$	1,049
Accrued interest	171		128
Accrued property, income and other taxes	162		67

Accrued employee expenses	132		86
Short-term debt	165		—
Current portion of long-term debt	473		449
Regulatory liabilities	91		96

Other current liabilities	359		271
Total current liabilities	2,757		2,146

Long-term debt	9,984		9,217
Regulatory liabilities	2,607		2,843
Deferred income taxes	2,933		3,152
Wildfires liabilities (Note 9)	2,278		400
Other long-term liabilities	1,033		906
Total liabilities	21,592		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	5,303		6,269
Accumulated other comprehensive loss, net	(9)		(9)
Total shareholders' equity	9,775		10,741

Total liabilities and shareholders' equity	$	31,367	$	29,405

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Operating revenue	$	1,676	$	1,635	$	4,487	$	4,246

Operating expenses:
Cost of fuel and energy	664		581		1,740		1,497
Operations and maintenance	356		289		1,056		877
Wildfires losses, net of recoveries (Note 9)	1,263		—		1,671		64
Depreciation and amortization	285		277		843		836
Property and other taxes	51		51		156		161
Total operating expenses	2,619		1,198		5,466		3,435

Operating (loss) income	(943)		437		(979)		811

Other income (expense):
Interest expense	(140)		(105)		(398)		(318)
Allowance for borrowed funds	19		9		48		21
Allowance for equity funds	40		19		101		47
Interest and dividend income	28		15		73		29
Other, net	(1)		(3)		4		(12)
Total other income (expense)	(54)		(65)		(172)		(233)

Income (loss) before income tax expense (benefit)	(997)		372		(1,151)		578
Income tax expense (benefit)	(345)		(37)		(485)		(43)
Net (loss) income	$	(652)	$	409	$	(666)	$	621

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)

(Amounts in millions)


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

Balance, June 30, 2022	$	2	$	—	$	4,479	$	5,561	$	(16)	$	10,026
Net income	—		—		—		409		—		409


Balance, September 30, 2022	$	2	$	—	$	4,479	$	5,970	$	(16)	$	10,435

Balance, December 31, 2021	$	2	$	—	$	4,479	$	5,449	$	(17)	$	9,913
Net income	—		—		—		621		—		621
Other comprehensive income	—		—		—		—		1		1
Common stock dividends declared	—		—		—		(100)		—		(100)
Balance, September 30, 2022	$	2	$	—	$	4,479	$	5,970	$	(16)	$	10,435

Balance, June 30, 2023	$	2	$	—	$	4,479	$	5,955	$	(9)	$	10,427
Net loss	—		—		—		(652)		—		(652)


Balance, September 30, 2023	$	2	$	—	$	4,479	$	5,303	$	(9)	$	9,775

Balance, December 31, 2022	$	2	$	—	$	4,479	$	6,269	$	(9)	$	10,741
Net loss	—		—		—		(666)		—		(666)

Common stock dividends declared	—		—		—		(300)		—		(300)
Balance, September 30, 2023	$	2	$	—	$	4,479	$	5,303	$	(9)	$	9,775

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Nine-Month Periods
	Ended September 30,
	2023		2022
Cash flows from operating activities:
Net (loss) income	$	(666)	$	621
Adjustments to reconcile net (loss) income to net cash flows from operating activities:
Depreciation and amortization	843		836
Allowance for equity funds	(101)		(47)
Net power cost deferrals	(578)		(262)
Amortization of net power cost deferrals	156		67
Other changes in regulatory assets and liabilities	(101)		(90)
Deferred income taxes and amortization of investment tax credits	(320)		48
Other, net	1		15
Changes in other operating assets and liabilities:
Trade receivables, other receivables and other assets	(133)		(47)
Inventories	(45)		3
Derivative collateral, net	(87)		28
Prepaid expenses	(56)		(25)
Accrued property, income and other taxes, net	165		180
Accounts payable and other liabilities	392		361
Wildfires insurance receivable	(257)		(161)
Wildfires liability	1,854		225
Net cash flows from operating activities	1,067		1,752

Cash flows from investing activities:
Capital expenditures	(2,250)		(1,481)
Other, net	5		4
Net cash flows from investing activities	(2,245)		(1,477)

Cash flows from financing activities:
Proceeds from long-term debt	1,189		—
Repayments of long-term debt	(401)		(104)
Proceeds from short-term debt	165		—

Dividends paid	(300)		(100)
Other, net	(4)		(2)
Net cash flows from financing activities	649		(206)

Net change in cash and cash equivalents and restricted cash and cash equivalents	(529)		69
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	$	145	$	255

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

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 September 30, 2023, and for the three- and nine-month periods ended September 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 nine-month periods ended September 30, 2023 and 2022. The results of operations for the three- and nine-month periods ended September 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 nine-month period ended September 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 a wildfire that began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California in July 2022 (the "2022 McKinney Fire"), referred to together as "the Wildfires" 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
	September 30,		December 31,
	2023		2022

Cash and cash equivalents	$	98	$	641
Restricted cash and cash equivalents included in other current assets	11		7
Restricted cash included in other assets	36		26
Total cash and cash equivalents and restricted cash and cash equivalents	$	145	$	674

(3) Property, Plant and Equipment, Net

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


		As of
		September 30,		December 31,
	Depreciable Life	2023		2022
Utility plant:
Generation	15 - 59 years	$	13,814	$	13,726
Transmission	60 - 90 years	8,140		8,051
Distribution	20 - 75 years	8,840		8,477
Intangible plant(1) and other	5 - 75 years	2,810		2,755
Utility plant in-service		33,604		33,009
Accumulated depreciation and amortization		(11,649)		(11,093)
Utility plant in-service, net		21,955		21,916
Nonregulated, net of accumulated depreciation and amortization	14 - 95 years	18		18
		21,973		21,934
Construction work-in-progress		4,126		2,496
Property, plant and equipment, net		$	26,099	$	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

Credit Facilities

Common Shareholders' Equity

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

(5) Income Taxes

The effective income tax rate for the three-month period ended September 30, 2023, is 35% and results from a $345 million income tax benefit associated with a $997 million pre-tax loss, primarily related to increases in wildfire loss accruals, net of expected insurance recoveries of $1,263 million as described in Note 9. The $345 million income tax benefit is primarily comprised of a $210 million benefit (21%) from the application of the federal statutory income tax rate to the pre-tax loss, a $64 million benefit (6%) from federal income tax credits, a $37 million benefit (4%) from state income tax and a $36 million benefit (4%) from effects of ratemaking.

The effective income tax rate for the nine-month period ended September 30, 2023 is 42% and results from a $485 million income tax benefit associated with a $1,151 million pre-tax loss, primarily related to increases in wildfire loss accruals, net of expected insurance recoveries of $1,671 million as described in Note 9. The $485 million income tax benefit is primarily comprised of a $242 million benefit (21%) from the application of the federal statutory income tax rate to the pre-tax loss, a $119 million benefit (10%) from federal income tax credits, a $70 million benefit (6%) from effects of ratemaking and a $44 million benefit (4%) from state income tax.

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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Federal statutory income tax rate	21	%	21	%	21	%	21	%
State income tax, net of federal income tax benefit	4		4		4		4
Federal income tax credits	6		(22)		10		(22)
Effects of ratemaking(1)	4		(13)		6		(12)

Valuation allowance	—		—		1		1
Other	—		—		—		1
Effective income tax rate	35	%	(10)	%	42	%	(7)	%

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

Income tax credits relate primarily to production tax credits ("PTC") 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 September 30, 2023 and 2022, totaled $64 million and $83 million, respectively. PTCs recognized for the nine-month periods ended September 30, 2023 and 2022, totaled $119 million and $127 million, respectively.

For the nine-month period ended September 30, 2023, PacifiCorp released an $11 million valuation allowance related to state net operating loss carryforwards. For the nine-month period ended September 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 nine-month periods ended September 30, 2023 and 2022, PacifiCorp received net cash payments for federal and state income tax from BHE totaling $255 million and $194 million, respectively. As of September 30, 2023, net income taxes payable to BHE were $12 million. As of December 31, 2022, net income taxes receivable from BHE were $84 million.

(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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Pension:

Interest cost	$	10	$	8	$	29	$	22
Expected return on plan assets	(12)		(11)		(36)		(32)

Net amortization	3		4		9		12
Net periodic benefit cost	$	1	$	1	$	2	$	2

Other postretirement:
Service cost	$	—	$	—	$	1	$	1
Interest cost	3		2		8		6
Expected return on plan assets	(3)		(3)		(10)		(8)
Net amortization	(1)		1		(2)		1
Net periodic benefit credit	$	(1)	$	—	$	(3)	$	—

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 September 30, 2023, $3 million of contributions had been made to the pension plans.

(7) Risk Management and Hedging Activities

PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its 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.

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 September 30, 2023
Not designated as hedging contracts(1):
Commodity assets	$	66	$	11	$	5	$	—	$	82
Commodity liabilities	(11)		(4)		(17)		—		(32)
Total	55		7		(12)		—		50

Total derivatives	55		7		(12)		—		50
Cash collateral (payable) receivable	(8)		—		5		—		(3)
Total derivatives - net basis	$	47	$	7	$	(7)	$	—	$	47

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 September 30, 2023, a regulatory liability of $50 million was recorded related to the net derivative asset of $50 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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Beginning balance	$	(9)	$	(223)	$	(270)	$	(53)
Changes in fair value recognized in regulatory (liabilities) assets	(9)		(79)		83		(296)
Net gains (losses) reclassified to operating revenue	—		7		(8)		(4)
Net (losses) gains reclassified to energy costs	(32)		129		145		187
Ending balance	$	(50)	$	(166)	$	(50)	$	(166)

Derivative Contract Volumes

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


	Unit of	September 30,	December 31,
	Measure	2023	2022

Electricity purchases, net	Megawatt hours	2	2
Natural gas purchases	Decatherms	126	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 September 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 $32 million and $48 million as of September 30, 2023 and December 31, 2022, respectively, for which PacifiCorp had posted collateral of $5 million and $— million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of September 30, 2023 and December 31, 2022, PacifiCorp would have been required to post $7 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 3 — Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including its own data.

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


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of September 30, 2023:
Assets:
Commodity derivatives	$	—	$	82	$	—	$	(28)	$	54
Money market mutual funds	120		—		—		—		120
Investment funds	29		—		—		—		29
	$	149	$	82	$	—	$	(28)	$	203

Liabilities - Commodity derivatives	$	—	$	(32)	$	—	$	25	$	(7)

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 payable of $3 million and $78 million as of September 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.

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


	As of September 30, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	10,457	$	8,834	$	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

Fuel Contracts

During the nine-month period ended September 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

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.

Pursuant to Accounting Standards Codification Topic 450, Contingencies, a provision for a loss contingency is recorded when it is probable a liability is likely to occur 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.

Wildfires Overview

2020 Wildfires

2022 McKinney Fire

Estimated Losses for the Wildfires

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


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Beginning balance	$	948	$	477	$	424	$	252
Accrued losses	1,387		—		1,928		225
Payments	(57)		—		(74)		—
Ending balance	$	2,278	$	477	$	2,278	$	477

PacifiCorp's receivable for expected insurance recoveries associated with the probable losses was $503 million and $246 million, respectively, as of September 30, 2023 and December 31, 2022, and is included in Other assets on the Consolidated Balance Sheets. During the three- and nine-month periods ended September 30, 2023, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $1,263 million and $1,671 million, respectively. During the three- and nine-month periods ended September 30, 2022, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $— million and $64 million, respectively. No additional insurance recoveries beyond those accrued to date are expected to be available.

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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Customer Revenue:
Retail:
Residential	$	601	$	576	$	1,636	$	1,498
Commercial	513		461		1,372		1,224
Industrial	310		310		870		860
Other retail	119		118		246		235
Total retail	1,543		1,465		4,124		3,817
Wholesale	47		69		134		179
Transmission	44		54		116		131
Other Customer Revenue	31		24		87		72
Total Customer Revenue	1,665		1,612		4,461		4,199
Other revenue	11		23		26		47
Total operating revenue	$	1,676	$	1,635	$	4,487	$	4,246

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

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

Results of Operations for the Third Quarter and First Nine Months of 2023 and 2022

Overview

Net loss for the third quarter of 2023 was $652 million, a decrease of $1,061 million compared to 2022 net income of $409 million. The decrease in net income was primarily due to an increase in estimated losses of $1,263 million associated with the 2020 Wildfires and the 2022 McKinney Fire, net of expected insurance recoveries, higher operations and maintenance expense and lower utility margin, partially offset by higher income tax benefit. Utility margin decreased $42 million primarily due to higher purchased electricity costs from higher prices and volumes, higher coal-fueled generation prices, lower retail revenue volumes, lower wholesale revenue volumes and prices, lower wheeling revenue and lower gas-fueled generation volumes, partially offset by higher retail revenue prices, higher net power costs deferrals, lower coal-fueled generation volumes and lower gas-fueled generation prices. Retail customer volumes decreased 2%, primarily due to unfavorable weather-related impacts and lower industrial usage, partially offset by higher commercial customer usage and an increase in the average number of customers. Energy generated decreased 8% for the third quarter of 2023 compared to 2022 primarily due to lower coal-fueled and hydro-powered generation volumes, partially offset by higher natural gas-fueled and wind-powered generation volumes. Wholesale electricity sales volumes decreased 12% and purchased electricity volumes increased 16%.

Net loss for the first nine months of 2023 was $666 million, a decrease of $1,287 million compared to 2022 net income of $621 million. The decrease in net income was primarily due to an increase in estimated losses of $1,607 million associated with the 2020 Wildfires and the 2022 McKinney Fire, net of expected insurance recoveries and increased operations and maintenance expense, partially offset by higher income tax benefit and lower other expense. Utility margin was unfavorable $2 million, primarily due to higher purchased electricity costs from higher prices and volumes, higher coal-fueled generation prices, lower wholesale revenue volumes, higher natural gas-fueled generation costs from higher volumes and prices and lower wheeling revenue, partially offset by higher average retail rates, higher net power cost deferrals, lower coal-fueled generation volumes and higher wholesale market prices. Retail customer volumes were flat, primarily due to lower industrial and irrigation customer usage and unfavorable impacts of weather, partially offset by higher commercial customer usage and an increase in the average number of customers. Energy generated decreased 12% for the first nine 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 generation volumes. Wholesale electricity sales volumes decreased 39% and purchased electricity volumes increased 29%.

Non-GAAP Financial Measure

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

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

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


	Third Quarter								First Nine Months
	2023		2022		Change				2023		2022		Change
Utility margin:
Operating revenue	$	1,676	$	1,635	$	41	3	%	$	4,487	$	4,246	$	241	6	%
Cost of fuel and energy	664		581		83		14		1,740		1,497		243		16
Utility margin	1,012		1,054		(42)		(4)		2,747		2,749		(2)		—
Operations and maintenance	356		289		67		23		1,056		877		179		20
Wildfires losses, net of recoveries	1,263		—		1,263		*		1,671		64		1,607		*
Depreciation and amortization	285		277		8		3		843		836		7		1
Property and other taxes	51		51		—		—		156		161		(5)		(3)
Operating (loss) income	$	(943)	$	437	$	(1,380)	(316)	%	$	(979)	$	811	$	(1,790)	(221)	%

* Not meaningful

Utility Margin

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


	Third Quarter								First Nine Months
	2023		2022		Change				2023		2022		Change
Utility margin (in millions):
Operating revenue	$	1,676	$	1,635	$	41	3	%	$	4,487	$	4,246	$	241	6	%
Cost of fuel and energy	664		581		83		14		1,740		1,497		243		16
Utility margin	$	1,012	$	1,054	$	(42)	(4)	%	$	2,747	$	2,749	$	(2)	—	%

Sales (GWhs):
Residential	4,813		5,035		(222)		(4)	%	13,724		13,653		71		1	%
Commercial	5,559		5,343		216		4		15,336		14,526		810		6
Industrial, irrigation and other	4,974		5,337		(363)		(7)		13,627		14,709		(1,082)		(7)
Total retail	15,346		15,715		(369)		(2)		42,687		42,888		(201)		—
Wholesale	912		1,037		(125)		(12)		2,338		3,835		(1,497)		(39)
Total sales	16,258		16,752		(494)		(3)	%	45,025		46,723		(1,698)		(4)	%


Average number of retail customers (in thousands)	2,072		2,040		32		2	%	2,065		2,033		32		2	%

Average revenue per MWh:
Retail	$	100.55	$	93.38	$	7.17	8	%	$	96.48	$	89.19	$	7.29	8	%
Wholesale	$	61.14	$	84.28	$	(23.14)	(27)	%	$	68.70	$	55.37	$	13.33	24	%

Heating degree days	174		91		83		91	%	6,692		6,572		120		2	%

Cooling degree days	2,344		2,021		323		16	%	2,800		2,432		368		15	%

Sources of energy (GWhs)(1):
Coal	7,150		8,606		(1,456)		(17)	%	16,299		21,777		(5,478)		(25)	%
Natural gas	3,876		3,684		192		5		10,939		9,546		1,393		15
Wind(2)	1,191		1,051		140		13		4,719		5,260		(541)		(10)
Hydroelectric and other(2)	509		555		(46)		(8)		2,432		2,572		(140)		(5)
Total energy generated	12,726		13,896		(1,170)		(8)		34,389		39,155		(4,766)		(12)
Energy purchased	4,677		4,047		630		16		14,187		10,987		3,200		29
Total	17,403		17,943		(540)		(3)	%	48,576		50,142		(1,566)		(3)	%

Average cost of energy per MWh:
Energy generated(3)	$	24.85	$	21.60	$	3.25	15	%	$	23.13	$	20.74	$	2.39	12	%
Energy purchased	$	115.30	$	97.72	$	17.58	18	%	$	82.43	$	68.82	$	13.61	20	%

(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.

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

Utility margin decreased $42 million for the third quarter of 2023 compared to 2022 primarily due to:

•$144 million of higher purchased electricity costs from higher average market prices and higher volumes;

•$32 million decrease in wholesale revenue primarily due to lower average market prices and wholesale volumes;

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

•$3 million of lower other revenue primarily due to lower wheeling revenue, partially offset by higher renewable energy credit sales.

The decreases above were partially offset by:

•$78 million of higher deferred net power costs net of amortization of previous deferrals in accordance with established adjustment mechanisms;

•$76 million increase in retail revenue due to higher average prices, partially offset by lower volumes. Retail customer volumes decreased 2.3%, primarily due to unfavorable weather-related impacts across the service territory, primarily in Utah and Oregon, lower industrial customer usage across all states, except Oregon, partially offset by higher Utah and Oregon commercial customer usage and an increase in the average number of residential and commercial customers across all states, except California; and

•$4 million of lower natural gas-fueled generation costs primarily due to lower average market prices, partially offset by higher volumes.

Operations and maintenance increased $67 million, or 23% for the third quarter of 2023 compared to 2022 primarily due to $23 million increase in vegetation management costs (including the impacts of deferrals and amortizations), $17 million increase in plant operations and maintenance costs, $8 million due to increased insurance premiums, $6 million increase in DSM amortization expense driven by higher spend in Oregon, Utah and Washington (offset in retail revenue) and $4 million of higher legal fees, primarily related to wildfire matters.

Wildfire losses, net of recoveries increased $1,263 million for the third quarter of 2023 compared to 2022 primarily due to increase in estimated losses, net of expected insurance recoveries, associated with the 2020 Wildfires and the 2022 McKinney Fire.

Interest expense increased $35 million, or 33%, for the third quarter of 2023 compared to 2022 primarily due to higher average long-term debt balances and higher average long-term debt interest rates.

Allowance for borrowed and equity funds increased $31 million for the third quarter of 2023 compared to 2022 primarily due to higher qualified construction work-in-progress balances.

Interest and dividend income increased $13 million for the third 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.

Income tax benefit increased $308 million for the third quarter of 2023 compared to 2022 and the effective tax rate was 35% for 2023 and (10)% for 2022. The $308 million increase is primarily due to the increase in the accruals, net of expected insurance recoveries for the 2020 Wildfires and the 2022 McKinney Fire, partially offset by lower PTCs from PacifiCorp's wind-powered generating facilities and lower benefit from the effects of ratemaking.

First Nine Months of 2023 compared to First Nine Months of 2022

Utility margin decreased $2 million for the first nine months of 2023 compared to 2022 primarily due to:

•$413 million of higher purchased electricity costs from higher average market prices and higher volumes;

•$70 million of higher natural gas-fueled generation costs due to higher volumes and higher average market prices; and

•$52 million decrease in wholesale revenue primarily due to lower volumes, partially offset by higher average market prices.

The decreases above were partially offset by:

•$293 million increase in retail revenue due to higher average prices, partially offset by lower retail volumes. Retail customer volumes decreased 0.5%, primarily due to lower industrial and irrigation customer usage and unfavorable weather-related impacts across eastern states, mainly in Utah, partially offset by higher commercial and residential customer usage across eastern states, primarily in Utah and Wyoming, higher Oregon commercial customer usage, increase in average number of residential and commercial customers across all states, except California and favorable impacts of weather in Oregon.

•$227 million higher deferred net power costs net of amortization of previous deferrals in accordance with established adjustment mechanisms; and

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

Operations and maintenance increased $179 million, or 20%, for the first nine months of 2023 compared to 2022 primarily due to $60 million increase in vegetation management costs (including the impacts of deferrals and amortizations), $33 million increase in plant operations and maintenance costs, $21 million increase in DSM amortization expense driven by higher spend in Oregon, Utah and Washington (offset in retail revenue), $21 million of higher legal fees primarily related to wildfires matters, $14 million increase in insurance premiums, $7 million of higher bad debt expense and $7 million higher labor and employee-related expenses.

Wildfire losses, net of recoveries increased $1,607 million for the first nine months of 2023 compared to 2022 primarily due to increase in estimated losses, net of expected insurance recoveries, associated with the 2020 Wildfires and the 2022 McKinney Fire.

Property and other taxes decreased $5 million, or 3%, for the first nine months of 2023 compared to 2022 primarily due to lower property tax rates in Utah, partially offset by higher franchise taxes in Oregon and higher property taxes in Wyoming.

Interest expense increased $80 million, or 25%, for the first nine months of 2023 compared to 2022 primarily due to higher average long-term debt balances, higher average long-term debt interest rates and higher interest expense on transmission-related deposits.

Allowance for borrowed and equity funds increased $81 million for the first nine months of 2023 compared to 2022 primarily due to higher qualified construction work-in-progress balances.

Interest and dividend income increased $44 million for the first nine 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 $16 million for the first nine 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 investments primarily due to market movements (offset in operations and maintenance expense).

Income tax benefit increased $442 million for the first nine months of 2023 compared to 2022 and the effective tax rate was 42% for 2023 and (7)% for 2022. The $442 million increase is primarily due to the increase in the accruals, net of expected insurance recoveries for the 2020 Wildfires and the 2022 McKinney Fire, higher benefit from the effects of ratemaking, release of a valuation allowance on state net operating loss carryforwards in 2023 compared to the establishment of a state valuation allowance in 2022, partially offset by lower PTCs from PacifiCorp's wind-powered generating facilities.

Liquidity and Capital Resources

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


Cash and cash equivalents	$	98

Credit facilities	2,000
Less:
Short-term debt	(165)
Tax-exempt bond support and letters of credit	(249)
Net credit facilities	1,586

Total net liquidity	$	1,684
Credit facilities:
Maturity dates	2026

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022 were $1,067 million and $1,752 million, respectively. The decrease is primarily due to higher wholesale and fuel purchases, higher operating expense payments 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 nine-month periods ended September 30, 2023 and 2022 were $(2,245) million and $(1,477) million, respectively. The change is primarily due to an increase in capital expenditures of $769 million. Refer to "Future Uses of Cash" for discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2023 were $649 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $1.2 billion and from the borrowing of short-term debt of $165 million. Uses of cash consisted primarily of $401 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 nine-month period ended September 30, 2022 were $(206) million. Uses of cash consisted primarily of $100 million for common stock dividends paid to PPW Holdings LLC and $104 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 September 30, 2023, PacifiCorp had $165 million of short-term debt outstanding at a weighted average interest rate of 5.53%. As of December 31, 2022, PacifiCorp had no short-term debt outstanding.

Debt Authorizations

PacifiCorp currently has regulatory authority from the OPUC and the IPUC 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 2026.

Common Shareholders' Equity

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

Future Uses of Cash

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

Capital Expenditures

PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to 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 and the 2022 McKinney Fire; 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):


	Nine-Month Periods				Annual
	Ended September 30,				Forecast
	2022		2023		2023

Wind generation	$	21	$	550	$	818
Electric distribution	487		649		890
Electric transmission	832		763		1,333
Solar generation	—		1		8
Electric battery and pumped hydro storage	6		3		5
Other	135		284		268
Total	$	1,481	$	2,250	$	3,322

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 $540 million and $21 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $260 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 $177 million and $98 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for wildfire mitigation totals $36 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 $536 million and $643 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for these Energy Gateway Transmission segments totals $411 million for the remainder of 2023.

•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $128 million and $115 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned information technology spending totals $52 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. PacifiCorp filed its 2023 IRP (Amended Final) report on May 31, 2023, following a 60-day extended comment period.

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. In October, the WUTC approved a multi-party settlement agreement that resolved challenges to the Clean Energy Implementation Plan.

PacifiCorp has drafted a petition requesting that the WUTC approve an alternative IRP filing schedule, which would extend the existing timeline of each of several filing deadlines by three months to align with the filing schedules of the other five states within PacifiCorp's six-state territory. This is pertinent to maintaining a March 31, 2025 filing date for the 2025 IRP and all key dependent filing dates.

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 ("2022AS") RFP, was issued to market in April 2022. In September 2023, PacifiCorp suspended its 2022AS RFP. No final shortlist will be announced while the RFP is paused. Pursuant to Section 2.E of the 2022AS RFP, PacifiCorp reserves the right, without limitation or qualification and in its sole discretion, to reject any or all bids, and to terminate or suspend this RFP in whole or in part at any time.

Key drivers behind PacifiCorp's decision to pause the RFP included:

•A federal court's stay of the EPA's proposed ozone transport rule.

•Ongoing rulemaking by the EPA regarding greenhouse gas emissions.

•Wildfire risk and associated liability across PacifiCorp's six-state service area and throughout the West.

•Evolving extreme weather risks that necessitate further decision-making regarding PacifiCorp's operational and resource requirements.

Material Cash Requirements

As of September 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.

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.

MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company

Consolidated Financial Section

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

MidAmerican Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of September 30, 2023, the related statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 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.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

November 3, 2023

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	September 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	700	$	258
Trade receivables, net	345		536
Income tax receivable	—		42
Inventories	333		277
Prepayments	121		91
Other current assets	33		66
Total current assets	1,532		1,270

Property, plant and equipment, net	21,521		21,091
Regulatory assets	630		550
Investments and restricted investments	959		902
Other assets	170		165

Total assets	$	24,812	$	23,978

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

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	September 30,		December 31,
	2023		2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	449	$	536
Accrued interest	93		85
Accrued property, income and other taxes	221		170

Current portion of long-term debt	4		317
Other current liabilities	130		93
Total current liabilities	897		1,201

Long-term debt	8,761		7,412
Regulatory liabilities	860		1,119
Deferred income taxes	3,505		3,433
Asset retirement obligations	793		683
Other long-term liabilities	548		485
Total liabilities	15,364		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	8,887		9,084

Total shareholder's equity	9,448		9,645

Total liabilities and shareholder's equity	$	24,812	$	23,978

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

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Operating revenue:
Regulated electric	$	869	$	1,009	$	2,121	$	2,342
Regulated natural gas and other	95		139		522		708
Total operating revenue	964		1,148		2,643		3,050

Operating expenses:
Cost of fuel and energy	165		235		393		534
Cost of natural gas purchased for resale and other	47		97		329		515
Operations and maintenance	214		210		635		602
Depreciation and amortization	210		338		670		865
Property and other taxes	39		38		121		114
Total operating expenses	675		918		2,148		2,630

Operating income	289		230		495		420

Other income (expense):
Interest expense	(85)		(79)		(246)		(235)
Allowance for borrowed funds	6		3		14		12
Allowance for equity funds	16		12		40		41
Other, net	6		4		37		(11)
Total other income (expense)	(57)		(60)		(155)		(193)

Income before income tax expense (benefit)	232		170		340		227
Income tax expense (benefit)	(92)		(135)		(462)		(529)

Net income	$	324	$	305	$	802	$	756

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

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions)


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

Balance, June 30, 2022	$	—	$	561	$	8,850	$	9,411
Net income	—		—		305		305
Common stock dividend	—		—		(50)		(50)
Other equity transactions	—		—		(1)		(1)
Balance, September 30, 2022	$	—	$	561	$	9,104	$	9,665

Balance, December 31, 2021	$	—	$	561	$	8,399	$	8,960
Net income	—		—		756		756
Common stock dividend	—		—		(50)		(50)
Other equity transactions	—		—		(1)		(1)
Balance, September 30, 2022	$	—	$	561	$	9,104	$	9,665

Balance, June 30, 2023	$	—	$	561	$	9,463	$	10,024
Net income	—		—		324		324
Common stock dividend	—		—		(900)		(900)

Balance, September 30, 2023	$	—	$	561	$	8,887	$	9,448

Balance, December 31, 2022	$	—	$	561	$	9,084	$	9,645
Net income	—		—		802		802
Common stock dividends	—		—		(1,000)		(1,000)
Other equity transactions	—		—		1		1
Balance, September 30, 2023	$	—	$	561	$	8,887	$	9,448

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

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Nine-Month Periods
	Ended September 30,
	2023		2022
Cash flows from operating activities:
Net income	$	802	$	756
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	670		865
Amortization of utility plant to other operating expenses	25		26
Allowance for equity funds	(40)		(41)
Deferred income taxes and investment tax credits, net	106		11
Settlements of asset retirement obligations	(20)		(55)
Other, net	44		40
Changes in other operating assets and liabilities:
Trade receivables and other assets	175		(10)
Inventories	(56)		(38)

Pension and other postretirement benefit plans	(1)		4
Accrued property, income and other taxes, net	93		197
Accounts payable and other liabilities	(37)		46
Net cash flows from operating activities	1,761		1,801

Cash flows from investing activities:
Capital expenditures	(1,339)		(1,404)
Purchases of marketable securities	(165)		(306)
Proceeds from sales of marketable securities	150		299
Other, net	14		12
Net cash flows from investing activities	(1,340)		(1,399)

Cash flows from financing activities:
Common stock dividends	(1,000)		(50)
Proceeds from long-term debt	1,338		—
Repayments of long-term debt	(316)		(2)

Other, net	(2)		—
Net cash flows from financing activities	20		(52)

Net change in cash and cash equivalents and restricted cash and cash equivalents	441		350
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	$	709	$	589

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

MIDAMERICAN ENERGY COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

(1) General

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

The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of September 30, 2023, and for the three- and nine-month periods ended September 30, 2023 and 2022. The results of operations for the nine-month period ended September 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 nine-month period ended September 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
	September 30,		December 31,
	2023		2022

Cash and cash equivalents	$	700	$	258
Restricted cash and cash equivalents in other current assets	9		10
Total cash and cash equivalents and restricted cash and cash equivalents	$	709	$	268

(3) Property, Plant and Equipment, Net

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


		As of
		September 30,		December 31,
	Depreciable Life	2023		2022
Utility plant:
Generation	20-62 years	$	17,550	$	18,582
Transmission	55-80 years	2,758		2,662
Electric distribution	15-80 years	5,163		4,931
Natural gas distribution	30-75 years	2,239		2,144
Utility plant in-service		27,710		28,319
Accumulated depreciation and amortization		(7,674)		(8,024)
Utility plant in-service, net		20,036		20,295



Nonregulated property, net of accumulated depreciation and amortization	20-50 years	6		6
		20,042		20,301
Construction work-in-progress		1,479		790
Property, plant and equipment, net		$	21,521	$	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 nine-month periods ended September 30, 2023 and 2022, $12 million and $211 million, respectively, is reflected in depreciation and amortization expense on the Statements of Operations.

(4) Recent Financing Transactions

Long-Term Debt

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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Federal statutory income tax rate	21	%	21	%	21	%	21	%
Income tax credits	(47)		(69)		(142)		(222)
State income tax, net of federal income tax impacts	(8)		(21)		(9)		(21)
Effects of ratemaking	(5)		(13)		(5)		(12)
Other, net	(1)		3		(1)		1
Effective income tax rate	(40)	%	(79)	%	(136)	%	(233)	%

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 the remaining 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 nine-month periods ended September 30, 2023 and 2022, totaled $484 million and $505 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 $698 million and $757 million for the nine-month periods ended September 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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Pension:
Service cost	$	2	$	5	$	8	$	14
Interest cost	8		5		24		15
Expected return on plan assets	(7)		(7)		(23)		(21)
Settlement	—		—		(5)		2
Net amortization	—		—		—		1
Net periodic benefit cost	$	3	$	3	$	4	$	11

Other postretirement:
Service cost	$	2	$	2	$	4	$	6
Interest cost	4		2		10		6
Expected return on plan assets	(3)		(4)		(11)		(11)
Net amortization	—		(1)		—		(2)
Net periodic benefit cost (credit)	$	3	$	(1)	$	3	$	(1)

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net on 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 September 30, 2023, $5 million and $2 million of contributions had been made to the pension and other postretirement benefit plans, respectively.

(7) Asset Retirement Obligations

(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 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 September 30, 2023:
Assets:
Commodity derivatives	$	—	$	8	$	2	$	(5)	$	5
Money market mutual funds	707		—		—		—		707
Debt securities:
U.S. government obligations	239		—		—		—		239
International government obligations	—		—		—		—		—
Corporate obligations	—		74		—		—		74
Municipal obligations	—		3		—		—		3

Equity securities:
U.S. companies	380		—		—		—		380
International companies	8		—		—		—		8
Investment funds	22		—		—		—		22
	$	1,356	$	85	$	2	$	(5)	$	1,438

Liabilities - commodity derivatives	$	—	$	(20)	$	(17)	$	17	$	(20)


	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 $12 million and $— million as of September 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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Beginning balance	$	(14)	$	26	$	5	$	(5)
Changes in fair value recognized in net regulatory assets	(9)		(2)		(36)		42
Settlements	8		(10)		16		(23)
Ending balance	$	(15)	$	14	$	(15)	$	14

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


	As of September 30, 2023				As of December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	8,765	$	7,594	$	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

Environmental 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.

(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 September 30, 2023								For the Nine-Month Period Ended September 30, 2023
	Electric		Natural Gas		Other		Total		Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential	$	254	$	48	$	—	$	302	$	594	$	305	$	—	$	899
Commercial	111		14		—		125		272		109		—		381
Industrial	360		3		—		363		846		14		—		860
Natural gas transportation services	—		11		—		11		—		34		—		34
Other retail	48		1		—		49		121		1		—		122
Total retail	773		77		—		850		1,833		463		—		2,296
Wholesale	66		15		—		81		182		51		—		233
Multi-value transmission projects	15		—		—		15		42		—		—		42
Other Customer Revenue	—		—		2		2		—		—		6		6
Total Customer Revenue	854		92		2		948		2,057		514		6		2,577
Other revenue	15		1		—		16		64		2		—		66
Total operating revenue	$	869	$	93	$	2	$	964	$	2,121	$	516	$	6	$	2,643


	For the Three-Month Period Ended September 30, 2022								For the Nine-Month Period Ended September 30, 2022
	Electric		Natural Gas		Other		Total		Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential	$	267	$	58	$	—	$	325	$	620	$	370	$	—	$	990
Commercial	117		20		—		137		282		139		—		421
Industrial	364		9		—		373		839		27		—		866
Natural gas transportation services	—		8		—		8		—		31		—		31
Other retail	51		2		—		53		124		3		—		127
Total retail	799		97		—		896		1,865		570		—		2,435
Wholesale	167		41		—		208		355		133		—		488
Multi-value transmission projects	16		—		—		16		44		—		—		44
Other Customer Revenue	—		—		1		1		—		—		3		3
Total Customer Revenue	982		138		1		1,121		2,264		703		3		2,970
Other revenue	27		—		—		27		78		2		—		80
Total operating revenue	$	1,009	$	138	$	1	$	1,148	$	2,342	$	705	$	3	$	3,050

(11) Shareholder's Equity

In January and September 2023, MidAmerican Energy paid $100 million and $900 million, respectively, in cash dividends to its parent company, MHC.

(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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Operating revenue:
Regulated electric	$	869	$	1,009	$	2,121	$	2,342
Regulated natural gas	93		138		516		705
Other	2		1		6		3
Total operating revenue	$	964	$	1,148	$	2,643	$	3,050

Operating income:
Regulated electric	$	295	$	245	$	465	$	383
Regulated natural gas	(6)		(15)		30		37

Total operating income	289		230		495		420
Interest expense	(85)		(79)		(246)		(235)
Allowance for borrowed funds	6		3		14		12
Allowance for equity funds	16		12		40		41
Other, net	6		4		37		(11)
Total income before income tax expense (benefit)	$	232	$	170	$	340	$	227


	As of
	September 30, 2023		December 31, 2022
Assets:
Regulated electric	$	22,993	$	22,092
Regulated natural gas	1,818		1,885
Other	1		1
Total assets	$	24,812	$	23,978

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers and Member of

MidAmerican Funding, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of September 30, 2023, the related consolidated statements of operations and changes in member's equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 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

November 3, 2023

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	September 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	700	$	261
Trade receivables, net	345		536
Income tax receivable	—		43
Inventories	333		277
Prepayments	121		91
Other current assets	43		66
Total current assets	1,542		1,274

Property, plant and equipment, net	21,522		21,092
Goodwill	1,270		1,270
Regulatory assets	630		550
Investments and restricted investments	961		904
Other assets	169		164

Total assets	$	26,094	$	25,254

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

100

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	September 30,		December 31,
	2023		2022
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	449	$	536
Accrued interest	94		90
Accrued property, income and other taxes	221		170
Note payable to affiliate	1		—

Current portion of long-term debt	4		317
Other current liabilities	130		93
Total current liabilities	899		1,206

Long-term debt	9,001		7,652
Regulatory liabilities	860		1,119
Deferred income taxes	3,503		3,431
Asset retirement obligations	793		683
Other long-term liabilities	548		484
Total liabilities	15,604		14,575

Commitments and contingencies (Note 9)

Member's equity:
Paid-in capital	1,679		1,679
Retained earnings	8,811		9,000

Total member's equity	10,490		10,679

Total liabilities and member's equity	$	26,094	$	25,254

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

101

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Operating revenue:
Regulated electric	$	869	$	1,009	$	2,121	$	2,342
Regulated natural gas and other	95		139		522		708
Total operating revenue	964		1,148		2,643		3,050

Operating expenses:
Cost of fuel and energy	165		235		393		534
Cost of natural gas purchased for resale and other	47		97		329		515
Operations and maintenance	214		210		635		602
Depreciation and amortization	210		338		670		865
Property and other taxes	39		38		121		114
Total operating expenses	675		918		2,148		2,630

Operating income	289		230		495		420

Other income (expense):
Interest expense	(89)		(84)		(258)		(249)
Allowance for borrowed funds	6		3		14		12
Allowance for equity funds	16		12		40		41
Other, net	6		2		49		(12)
Total other income (expense)	(61)		(67)		(155)		(208)

Income before income tax expense (benefit)	228		163		340		212
Income tax expense (benefit)	(93)		(137)		(463)		(533)

Net income	$	321	$	300	$	803	$	745

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

102

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

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

(Amounts in millions)


	Paid-in Capital		Retained Earnings		Total Member's Equity

Balance, June 30, 2022	$	1,679	$	8,567	$	10,246
Net income	—		300		300
Other equity transactions	—		1		1
Balance, September 30, 2022	$	1,679	$	8,868	$	10,547

Balance, December 31, 2021	$	1,679	$	8,122	$	9,801
Net income	—		745		745
Other equity transactions	—		1		1
Balance, September 30, 2022	$	1,679	$	8,868	$	10,547

Balance, June 30, 2023	$	1,679	$	9,382	$	11,061
Net income	—		321		321
Distribution to member	—		(892)		(892)

Balance, September 30, 2023	$	1,679	$	8,811	$	10,490

Balance, December 31, 2022	$	1,679	$	9,000	$	10,679
Net income	—		803		803
Distributions to member	—		(992)		(992)

Balance, September 30, 2023	$	1,679	$	8,811	$	10,490

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

103

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Nine-Month Periods
	Ended September 30,
	2023		2022
Cash flows from operating activities:
Net income	$	803	$	745
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	670		865
Amortization of utility plant to other operating expenses	25		26
Allowance for equity funds	(40)		(41)
Deferred income taxes and investment tax credits, net	106		11

Settlements of asset retirement obligations	(20)		(55)
Other, net	31		42
Changes in other operating assets and liabilities:
Trade receivables and other assets	166		(12)
Inventories	(56)		(38)

Pension and other postretirement benefit plans	(1)		4
Accrued property, income and other taxes, net	94		197
Accounts payable and other liabilities	(41)		42
Net cash flows from operating activities	1,737		1,786

Cash flows from investing activities:
Capital expenditures	(1,339)		(1,404)
Purchases of marketable securities	(165)		(306)
Proceeds from sales of marketable securities	150		299
Proceeds from sale of investment	12		—
Other, net	14		12
Net cash flows from investing activities	(1,328)		(1,399)

Cash flows from financing activities:
Distributions to member	(992)		—
Proceeds from long-term debt	1,338		—
Repayments of long-term debt	(316)		(2)
Net change in note payable to affiliate	1		(34)

Other, net	(2)		(1)
Net cash flows from financing activities	29		(37)

Net change in cash and cash equivalents and restricted cash and cash equivalents	438		350
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	$	709	$	590

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

104

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

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

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2023, and for the three- and nine-month periods ended September 30, 2023 and 2022. The results of operations for the nine-month period ended September 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 nine-month period ended September 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
	September 30,		December 31,
	2023		2022

Cash and cash equivalents	$	700	$	261
Restricted cash and cash equivalents in other current assets	9		10
Total cash and cash equivalents and restricted cash and cash equivalents	$	709	$	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.

105

(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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Federal statutory income tax rate	21	%	21	%	21	%	21	%
Income tax credits	(48)		(72)		(142)		(238)
State income tax, net of federal income tax impacts	(8)		(22)		(9)		(24)
Effects of ratemaking	(5)		(13)		(5)		(13)
Other, net	(1)		2		(1)		3
Effective income tax rate	(41)	%	(84)	%	(136)	%	(251)	%

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 the remaining 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 nine-month periods ended September 30, 2023 and 2022, totaled $484 million and $505 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 $700 million and $761 million for the nine-month periods ended September 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 September 30, 2023				As of December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	9,005	$	7,844	$	7,969	$	7,219

106

(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 and September 2023, MidAmerican Funding paid $100 million and $892 million. respectively, in cash distributions 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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Operating revenue:
Regulated electric	$	869	$	1,009	$	2,121	$	2,342
Regulated natural gas	93		138		516		705
Other	2		1		6		3
Total operating revenue	$	964	$	1,148	$	2,643	$	3,050

Operating income:
Regulated electric	$	295	$	245	$	465	$	383
Regulated natural gas	(6)		(15)		30		37

Total operating income	289		230		495		420
Interest expense	(89)		(84)		(258)		(249)
Allowance for borrowed funds	6		3		14		12
Allowance for equity funds	16		12		40		41
Other, net	6		2		49		(12)
Total income before income tax expense (benefit)	$	228	$	163	$	340	$	212

107


	As of
	September 30, 2023		December 31, 2022
Assets(1):
Regulated electric	$	24,184	$	23,283
Regulated natural gas	1,897		1,963
Other	13		8
Total assets	$	26,094	$	25,254


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

108

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

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

Results of Operations for the Third Quarter and First Nine Months of 2023 and 2022

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the third quarter of 2023 was $324 million, an increase of $19 million, or 6%, compared to 2022, primarily due to lower depreciation and amortization expense, higher allowance for borrowed and equity funds, higher gas utility margin and favorable other, net, partially offset by lower electric utility margin, lower income tax benefit, higher interest expense, higher operations and maintenance expense and higher property and other taxes. The decrease in depreciation and amortization expense was primarily due to lower Iowa revenue sharing. 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 3%, due to lower wind-powered generation, partially offset by higher natural gas- and coal-fueled generation; and energy purchased increased 5%. Wholesale electricity sales volumes decreased 13% due to unfavorable market conditions. Natural gas retail customer volumes decreased 3% due to the unfavorable impact of weather.

MidAmerican Energy's net income for the first nine months of 2023 was $802 million, an increase of $46 million, or 6%, compared to 2022, primarily due to lower depreciation and amortization expense, favorable other, net, higher nonregulated utility margin and higher allowance for borrow and equity funds, partially offset by lower electric utility margin, lower income tax benefit, higher operations and maintenance expense, higher interest expense, higher property and other taxes and lower natural gas utility margin. The decrease in depreciation and amortization expense was primarily due to lower Iowa revenue sharing. 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 5%. Wholesale electricity sales volumes decreased 13% 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 third quarter of 2023 was $321 million, an increase of $21 million, or 7%, compared to 2022. MidAmerican Funding's net income for the first nine months of 2023 was $803 million, an increase of $58 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.

109

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

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


	Third Quarter								First Nine Months
	2023		2022		Change				2023		2022		Change
Electric utility margin:
Operating revenue	$	869	$	1,009	$	(140)	(14)	%	$	2,121	$	2,342	$	(221)	(9)	%
Cost of fuel and energy	165		235		(70)		(30)		393		534		(141)		(26)
Electric utility margin	704		774		(70)		(9)	%	1,728		1,808		(80)		(4)	%

Natural gas utility margin:
Operating revenue	93		138		(45)		(33)	%	516		705		(189)		(27)	%
Natural gas purchased for resale	47		97		(50)		(52)		329		515		(186)		(36)
Natural gas utility margin	46		41		5		12	%	187		190		(3)		(2)	%

Utility margin	750		815		(65)		(8)	%	1,915		1,998		(83)		(4)	%

Other operating revenue	2		1		1		100	%	6		3		3		100	%

Operations and maintenance	214		210		4		2		635		602		33		5
Depreciation and amortization	210		338		(128)		(38)		670		865		(195)		(23)
Property and other taxes	39		38		1		3		121		114		7		6

Operating income	$	289	$	230	$	59	26	%	$	495	$	420	$	75	18	%

110

Electric Utility Margin

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


	Third Quarter								First Nine Months
	2023		2022		Change				2023		2022		Change
Utility margin (in millions):
Operating revenue	$	869	$	1,009	$	(140)	(14)	%	$	2,121	$	2,342	$	(221)	(9)	%
Cost of fuel and energy	165		235		(70)		(30)		393		534		(141)		(26)
Utility margin	$	704	$	774	$	(70)	(9)	%	$	1,728	$	1,808	$	(80)	(4)	%

Sales (GWhs):
Residential	2,038		2,056		(18)		(1)	%	5,310		5,461		(151)		(3)	%
Commercial	1,065		1,055		10		1		3,012		3,021		(9)		—
Industrial	4,403		4,335		68		2		12,870		12,463		407		3
Other	430		422		8		2		1,231		1,231		—		—
Total retail	7,936		7,868		68		1		22,423		22,176		247		1
Wholesale	2,839		3,267		(428)		(13)		11,133		12,738		(1,605)		(13)
Total sales	10,775		11,135		(360)		(3)	%	33,556		34,914		(1,358)		(4)	%

Average number of retail customers (in thousands)	821		813		8		1	%	819		812		7		1	%

Average revenue per MWh:
Retail	$	97.40	$	101.53	$	(4.13)	(4)	%	$	81.74	$	84.10	$	(2.36)	(3)	%
Wholesale	$	25.41	$	55.68	$	(30.27)	(54)	%	$	19.59	$	31.12	$	(11.53)	(37)	%

Heating degree days	12		67		(55)		(82)	%	3,466		4,059		(593)		(15)	%
Cooling degree days	818		838		(20)		(2)	%	1,211		1,259		(48)		(4)	%

Sources of energy (GWhs)(1):
Wind and other(2)	3,955		4,528		(573)		(13)	%	17,652		20,182		(2,530)		(13)	%
Coal	4,064		3,990		74		2		8,397		7,830		567		7
Nuclear	982		987		(5)		(1)		2,771		2,770		1		—
Natural gas	806		624		182		29		1,719		1,255		464		37
Total energy generated	9,807		10,129		(322)		(3)		30,539		32,037		(1,498)		(5)
Energy purchased	1,247		1,189		58		5		3,652		3,466		186		5
Total	11,054		11,318		(264)		(2)	%	34,191		35,503		(1,312)		(4)	%

Average cost of energy per MWh:
Energy generated(3)	$	9.94	$	12.60	$	(2.66)	(21)	%	$	7.37	$	8.03	$	(0.66)	(8)	%
Energy purchased	$	54.99	$	90.62	$	(35.63)	(39)	%	$	46.17	$	79.97	$	(33.80)	(42)	%

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

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

111

Natural Gas Utility Margin

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


	Third Quarter								First Nine Months
	2023		2022		Change				2023		2022		Change
Utility margin (in millions):
Operating revenue	$	93	$	138	$	(45)	(33)	%	$	516	$	705	$	(189)	(27)	%
Natural gas purchased for resale	47		97		(50)		(52)		329		515		(186)		(36)
Utility margin	$	46	$	41	$	5	12	%	$	187	$	190	$	(3)	(2)	%

Throughput (000's Dths):
Residential	2,589		2,798		(209)		(7)	%	33,179		37,397		(4,218)		(11)	%
Commercial	1,435		1,492		(57)		(4)		15,810		17,551		(1,741)		(10)
Industrial	1,186		1,097		89		8		4,042		4,406		(364)		(8)
Other	12		4		8		200		59		55		4		7
Total retail sales	5,222		5,391		(169)		(3)		53,090		59,409		(6,319)		(11)
Wholesale sales	6,295		5,556		739		13		20,698		22,700		(2,002)		(9)
Total sales	11,517		10,947		570		5		73,788		82,109		(8,321)		(10)
Natural gas transportation service	25,246		20,901		4,345		21		78,661		74,705		3,956		5
Total throughput	36,763		31,848		4,915		15	%	152,449		156,814		(4,365)		(3)	%

Average number of retail customers (in thousands)	791		781		10		1	%	792		784		8		1	%

Average revenue per retail Dth sold	$	12.88	$	16.48	$	(3.60)	(22)	%	$	8.13	$	9.10	$	(0.97)	(11)	%

Heating degree days	18		84		(66)		(79)	%	3,659		4,303		(644)		(15)	%

Average cost of natural gas per retail Dth sold	$	6.10	$	10.38	$	(4.28)	(41)	%	$	5.24	$	6.42	$	(1.18)	(18)	%

Combined retail and wholesale average cost of natural gas per Dth sold	$	3.99	$	8.89	$	(4.90)	(55)	%	$	4.45	$	6.27	$	(1.82)	(29)	%

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

MidAmerican Energy -

Electric utility margin decreased $70 million, or 9%, for the third quarter of 2023 compared to 2022, primarily due to:

•a $90 million decrease in wholesale utility margin due to lower margins per unit of $72 million from lower market prices, and lower volumes of $18 million or 13.1%; partially offset by

•a $21 million increase in retail utility margin primarily due to $19 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); and $8 million from higher customer usage; partially offset by $5 million due to the unfavorable impact of weather; and $2 million from lower wind-turbine performance settlements. Retail customer volumes increased 0.9%.

Natural gas utility margin increased $5 million, or 12%, for the third quarter of 2023 compared to 2022, primarily due to:

•a $4 million increase from higher average rates mainly due to the South Dakota and Iowa natural gas general rate cases; and

•a $1 million increase from higher natural gas transportation margin.

112

Operations and maintenance increased $4 million, or 2%, for the third quarter of 2023 compared to 2022 primarily due to higher technology costs of $4 million, higher nuclear power generation costs of $3 million and higher administrative and other costs of $3 million, partially offset by lower gas distribution costs of $4 million and lower electric distribution and transmission costs of $2 million.

Depreciation and amortization decreased $128 million, or 38%, for the third quarter of 2023 compared to 2022 primarily due to $119 million from lower Iowa revenue sharing accruals, and $14 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects, partially offset by $3 million from lower depreciation expense deferrals in 2023 and $2 million from wind-powered generating facilities and other plant placed in-service.

Property and other taxes increased $1 million, or 3%, for the third quarter of 2023 compared to 2022 primarily due to $2 million from higher wind turbine property taxes, partially offset by $1 million from lower replacement taxes.

Interest expense increased $6 million, or 8%, for the third quarter of 2023 compared to 2022 due to higher interest expense from a September 2023 long-term debt issuance and higher interest rates on variable rate long-term debt.

Allowance for borrowed and equity funds increased $7 million, or 47%, for the third quarter of 2023 compared to 2022 due to higher construction work-in-progress balances related to wind-powered generation.

Other, net increased $2 million, or 50%, for the third quarter of 2023 compared to 2022 primarily due to higher interest income from higher interest rates and higher cash surrender values of corporate-owned life insurance policies, partially offset by higher non-service employee benefit plans cost.

Income tax benefit decreased $43 million, or 32%, for the third quarter of 2023 compared to 2022 primarily due to $30 million of higher federal and state income tax expense largely from higher pretax income and $8 million from lower PTCs recognized due to lower wind generation. PTCs for the third quarter of 2023 and 2022 totaled $109 million and $117 million, respectively.

MidAmerican Funding -

Income tax benefit decreased $44 million, or 32%, for the third quarter of 2023 compared to 2022 principally due to the changes in MidAmerican Energy's income tax benefit discussed above.

First Nine Months of 2023 Compared to First Nine Months of 2022

MidAmerican Energy -

Electric utility margin decreased $80 million, or 4%, for the first nine months of 2023 compared to 2022, due to:

•a $145 million decrease in wholesale utility margin due to lower margins per unit of $108 million from lower market prices, and lower volumes of $37 million or 12.6%; partially offset by

•a $67 million increase in retail utility margin primarily due to $58 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); $23 million from higher customer usage; and $4 million due to price impacts from changes in sales mix; partially offset by $18 million from the unfavorable impact of weather. Retail customer volumes increased 1.1%.

Natural gas utility margin decreased $3 million, or 2%, for the first nine months of 2023 compared to 2022 primarily due to:

•a $9 million decrease from the unfavorable impact of weather; partially offset by

•a $4 million increase from higher average rates mainly due to the South Dakota and Iowa natural gas general rate cases; and

•a $2 million increase from natural gas transportation margin.

Operations and maintenance increased $33 million, or 5%, for the first nine months of 2023 compared to 2022 primarily due to higher technology costs of $10 million, higher benefits costs of $8 million, higher administrative and other costs of $8 million, higher nuclear power generation costs of $6 million, higher other power generation costs of $6 million and higher property insurance costs of $4 million, partially offset by lower electric distribution and transmission costs of $5 million and lower gas distribution costs of $4 million.

113

Depreciation and amortization decreased $195 million, or 23%, for the first nine months of 2023 compared to 2022 primarily due to $200 million from lower Iowa revenue sharing accruals and $40 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects, partially offset by $36 million from new wind-powered generating facilities and other plant placed in-service and $9 million from lower depreciation expense deferrals in 2023.

Property and other taxes increased $7 million, or 6%, for the first nine months of 2023 compared to 2022 primarily due to $5 million from higher wind turbine property taxes and $2 million from higher replacement taxes.

Interest expense increased $11 million, or 5%, for the first nine months of 2023 compared to 2022 due to higher interest expense from a September 2023 long-term debt issuance and higher interest rates on variable rate long-term debt.

Allowance for borrowed and equity funds increased $1 million, or 2%, for the first nine months of 2023 compared to 2022 primarily due to higher construction work-in-progress balances related to wind-powered generation.

Other, net increased $48 million, or 436%, for the first nine 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, and higher interest income from higher interest rates.

Income tax benefit decreased $67 million, or 13%, for the first nine months of 2023 compared to 2022 primarily due to $46 million of higher federal and state income tax expense largely from higher pretax income, and $21 million from lower PTCs recognized due to lower wind generation. PTCs for the first nine months of 2023 and 2022 totaled $484 million and $505 million, respectively.

MidAmerican Funding -

Income tax benefit decreased $70 million, or 13%, for the first nine 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 September 30, 2023, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):


MidAmerican Energy:
Cash and cash equivalents	$	700

Credit facilities, maturing 2024 and 2026	1,505
Less:

Tax-exempt bond support	(306)
Net credit facilities	1,199

MidAmerican Energy total net liquidity	$	1,899

MidAmerican Funding:
MidAmerican Energy total net liquidity	$	1,899

MHC, Inc. credit facility, maturing 2024	4
MidAmerican Funding total net liquidity	$	1,903

114

Operating Activities

MidAmerican Energy's net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022, were $1,761 million and $1,801 million, respectively. MidAmerican Funding's net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022, were $1,737 million and $1,786 million, respectively. Cash flows from operating activities reflect lower income tax receipts and higher payments to vendors, partially offset by the cash impacts of utility margins for MidAmerican Energy's regulated electric and natural gas businesses and lower asset retirement obligation settlements.

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 nine-month periods ended September 30, 2023 and 2022, were $(1,340) million and $(1,399) million, respectively. MidAmerican Funding's net cash flows from investing activities for the nine-month periods ended September 30, 2023 and 2022, were $(1,328) million and $(1,399) 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 nine-month periods ended September 30, 2023 and 2022 were $20 million and $(52) million, respectively. MidAmerican Funding's net cash flows from financing activities for the nine-month periods ended September 30, 2023 and 2022, were $29 million and $(37) million, respectively. Proceeds from long-term debt reflect MidAmerican Energy's issuance in September 2023 of $350 million of its 5.350% First Mortgage Bonds due January 2034 and $1 billion of its 5.850% First Mortgage Bonds due September 2054. In January 2023 and September 2023, MidAmerican Funding paid $100 million and $892 million, respectively, in cash distributions to its sole member, BHE. In 2023, MidAmerican Energy repaid $316 million of long-term debt. In 2022, MidAmerican Funding made payments of $34 million 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 an additional $1.9 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 $1.65 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 $1.6 billion and preferred stock up to an aggregate of $500 million.

115

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.

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):


	Nine-Month Periods				Annual
	Ended September 30,				Forecast
	2022		2023		2023

Wind generation	$	515	$	546	$	790
Electric distribution	206		251		321
Electric transmission	78		150		191
Solar generation	103		11		21
Other	502		381		555
Total	$	1,404	$	1,339	$	1,878

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 $460 million and $39 million for the nine-month periods ended September 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 $171 million for the remainder of 2023.

◦Repowering of wind-powered generating facilities totaling $48 million and $422 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for the repowering of wind-powered generating facilities totals $21 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 nine-month periods ended September 30, 2023 and 2022, solar generation spending totaled $11 million and $103 million, respectively. Planned spending totals $10 million for the remainder of 2023.

116

•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 September 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.

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.

117

Nevada Power Company and its subsidiaries

Consolidated Financial Section

118

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Nevada Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of September 30, 2023, the related consolidated statements of operations, and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 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.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

November 3, 2023

119

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)


	As of
	September 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	44	$	43
Trade receivables, net	558		388
Note receivable from affiliate	—		100
Inventories	127		93

Regulatory assets	780		666


Other current assets	68		89
Total current assets	1,577		1,379

Property, plant and equipment, net	8,269		7,406

Regulatory assets	567		628
Other assets	382		388

Total assets	$	10,795	$	9,801

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	428	$	422
Accrued interest	51		40
Accrued property, income and other taxes	100		32


Regulatory liabilities	50		45
Customer deposits	57		51

Derivative contracts	49		51
Other current liabilities	88		49
Total current liabilities	823		690

Long-term debt	3,391		3,195
Finance lease obligations	280		295
Regulatory liabilities	1,017		1,093
Deferred income taxes	904		875
Other long-term liabilities	345		299
Total liabilities	6,760		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	1,303		1,022
Accumulated other comprehensive loss, net	(1)		(1)
Total shareholder's equity	4,035		3,354

Total liabilities and shareholder's equity	$	10,795	$	9,801

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

120

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Operating revenue	$	1,145	$	1,003	$	2,525	$	2,057

Operating expenses:
Cost of fuel and energy	688		538		1,565		1,086
Operations and maintenance	85		90		236		230
Depreciation and amortization	109		106		323		312
Property and other taxes	14		14		42		39
Total operating expenses	896		748		2,166		1,667

Operating income	249		255		359		390

Other income (expense):
Interest expense	(49)		(41)		(147)		(118)
Capitalized interest	7		1		16		4
Allowance for equity funds	6		3		14		8
Interest and dividend income	18		13		59		31
Other, net	1		3		9		3
Total other income (expense)	(17)		(21)		(49)		(72)

Income before income tax expense (benefit)	232		234		310		318
Income tax expense (benefit)	21		25		29		35
Net income	$	211	$	209	$	281	$	283

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

121

NEVADA POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)


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

Balance, June 30, 2022	1,000	$	—	$	2,333	$	798	$	(2)	$	3,129
Net income	—	—		—		209		—		209


Balance, September 30, 2022	1,000	$	—	$	2,333	$	1,007	$	(2)	$	3,338

Balance, December 31, 2021	1,000	$	—	$	2,308	$	724	$	(2)	$	3,030
Net income	—	—		—		283		—		283

Contributions	—	—		25		—		—		25
Balance, September 30, 2022	1,000	$	—	$	2,333	$	1,007	$	(2)	$	3,338

Balance, June 30, 2023	1,000	$	—	$	2,733	$	1,092	$	(1)	$	3,824
Net income	—	—		—		211		—		211



Balance, September 30, 2023	1,000	$	—	$	2,733	$	1,303	$	(1)	$	4,035

Balance, December 31, 2022	1,000	$	—	$	2,333	$	1,022	$	(1)	$	3,354
Net income	—	—		—		281		—		281

Contributions	—	—		400		—		—		400

Balance, September 30, 2023	1,000	$	—	$	2,733	$	1,303	$	(1)	$	4,035

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

122

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Nine-Month Periods
	Ended September 30,
	2023		2022
Cash flows from operating activities:
Net income	$	281	$	283
Adjustments to reconcile net income to net cash flows from operating activities:


Depreciation and amortization	323		312
Allowance for equity funds	(14)		(8)
Changes in regulatory assets and liabilities	(31)		(9)
Deferred income taxes and amortization of investment tax credits	(18)		48
Deferred energy	(184)		(543)
Amortization of deferred energy	70		113
Other, net	—		11
Changes in other operating assets and liabilities:
Trade receivables and other assets	(191)		(302)
Inventories	(34)		(14)
Accrued property, income and other taxes	68		15
Accounts payable and other liabilities	153		326
Net cash flows from operating activities	423		232

Cash flows from investing activities:
Capital expenditures	(1,102)		(523)
Proceeds from repayment of affiliate note receivable	100		—



Net cash flows from investing activities	(1,002)		(523)

Cash flows from financing activities:
Proceeds from long-term debt	494		300
Repayments of long-term debt	(300)		—
Net proceeds from short-term debt	—		20

Contributions from parent	400		25

Other, net	(15)		(13)
Net cash flows from financing activities	579		332

Net change in cash and cash equivalents and restricted cash and cash equivalents	—		41
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	$	60	$	86

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

123

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 September 30, 2023, and for the three- and nine-month periods ended September 30, 2023 and 2022. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2023 and 2022. The results of operations for the three- and nine-month periods ended September 30, 2023, are not necessarily indicative of the results to be expected for the full year.

(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
	September 30,		December 31,
	2023		2022

Cash and cash equivalents	$	44	$	43
Restricted cash and cash equivalents included in other current assets	16		17
Total cash and cash equivalents and restricted cash and cash equivalents	$	60	$	60

124

(3) Property, Plant and Equipment, Net

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


		As of
	Depreciable Life	September 30,		December 31,
		2023		2022
Utility plant:
Generation	30 - 55 years	$	4,113	$	3,977
Transmission	45 - 70 years	1,585		1,562
Distribution	20 - 65 years	4,365		4,134
General and intangible plant	5 - 65 years	902		871
Utility plant		10,965		10,544
Accumulated depreciation and amortization		(3,797)		(3,624)
Utility plant, net		7,168		6,920
Nonregulated, net of accumulated depreciation and amortization	45 years	1		1
		7,169		6,921
Construction work-in-progress		1,100		485
Property, plant and equipment, net		$	8,269	$	7,406

(4) Recent Financing Transactions

Long-Term Debt

In September 2023, Nevada Power issued $500 million of its 6.000% General and Refunding Mortgage Bonds, Series 2023A, due March 2054. Nevada Power used the net proceeds to repay its term loan due January 14, 2024 and short-term borrowings outstanding under Nevada Power's revolving credit facility, fund capital expenditures and for general corporate purposes.

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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Federal statutory income tax rate	21	%	21	%	21	%	21	%
Effects of ratemaking	(12)		(10)		(12)		(10)




Effective income tax rate	9	%	11	%	9	%	11	%

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.

125

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 nine-month periods ended September 30, 2023 and 2022, respectively, Nevada Power received net cash payments for federal income tax from BHE totaling $17 million and $20 million, respectively.

(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
	September 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.

126

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 September, 30 2023
Not designated as hedging contracts(1) -







Total derivatives - commodity liabilities	$	—	$	(49)	$	(9)	$	(58)

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 September 30, 2023 a regulatory asset of $58 million was recorded related to the net derivative liability of $58 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	September 30,	December 31,
	Measure	2023	2022

Electricity purchases	Megawatt hours	1	2
Natural gas purchases	Decatherms	162	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 September 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.

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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 September 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 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 September 30, 2023:
Assets:

Money market mutual funds	$	34	—		—		$	34
Investment funds	4		—		—		4
	$	38	$	—	$	—	$	38

Liabilities - commodity derivatives	$	—	$	—	$	(58)	$	(58)

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)

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

Beginning balance	$	(126)	$	(175)	$	(52)	$	(113)
Changes in fair value recognized in regulatory assets	(31)		(4)		(150)		(81)

Settlements	99		113		144		128
Ending balance	$	(58)	$	(66)	$	(58)	$	(66)

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


	As of September 30, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	3,391	$	3,146	$	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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Customer Revenue:
Retail:
Residential	$	668	$	582	$	1,365	$	1,149
Commercial	199		172		512		398
Industrial	246		202		557		404
Other	6		5		16		9
Total fully bundled	1,119		961		2,450		1,960
Distribution only service	3		5		10		15
Total retail	1,122		966		2,460		1,975
Wholesale, transmission and other	18		31		51		66
Total Customer Revenue	1,140		997		2,511		2,041
Other revenue	5		6		14		16
Total operating revenue	$	1,145	$	1,003	$	2,525	$	2,057

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

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

Results of Operations for the Third Quarter and First Nine Months of 2023 and 2022

Overview

Net income for the third quarter of 2023 was $211 million, an increase of $2 million, compared to 2022 primarily due to higher capitalized interest and allowance for equity funds, mainly due to higher construction work-in-progress, lower operations and maintenance expenses, mainly due to lower earnings sharing, favorable interest and dividend income, mainly from higher carrying charges on regulatory balances, and lower income tax expense, mainly due to lower pretax income. The increase is partially offset by higher interest expense, primarily due to higher long-term debt and average interest rate, lower utility margin and higher depreciation and amortization, mainly due to higher plant placed in-service. Utility margin decreased primarily due to lower retail customer volumes and lower transmission and wholesale revenue, partially offset by higher regulatory-related revenue deferrals. Retail customer volumes, including distribution only service customers, decreased 3% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers. Energy generated decreased 8% for the third quarter of 2023 compared to 2022 primarily due to lower natural-gas fueled generation. Wholesale electricity sales volumes decreased 63% and purchased electricity volumes increased 1%.

Net income for the first nine months of 2023 was $281 million, a decrease of $2 million, compared to 2022 primarily due to higher interest expense, mainly due to higher long-term debt and higher average interest rate, lower utility margin, higher depreciation and amortization, mainly due to higher plant placed in-service, and higher operations and maintenance expenses. The decrease is partially offset by favorable interest and dividend income, mainly from higher carrying charges on regulatory balances, higher capitalized interest and allowance for equity funds, mainly due to higher construction work-in-progress, favorable cash surrender value of corporate-owned life insurance policies and lower income tax expense, mainly due to lower pretax income. 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 2% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers. Operations and maintenance expenses increased primarily due to increased plant operations and maintenance expenses, higher technology costs and higher customer service operations expenses, partially offset by lower earnings sharing. Energy generated increased 6% for the first nine months of 2023 compared to 2022 primarily due to higher natural-gas fueled generation. Wholesale electricity sales volumes decreased 62% and purchased electricity volumes decreased 11%.

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):


	Third Quarter								First Nine Months
	2023		2022		Change				2023		2022		Change
Utility margin:
Operating revenue	$	1,145	$	1,003	$	142	14	%	$	2,525	$	2,057	$	468	23	%
Cost of fuel and energy	688		538		150		28		1,565		1,086		479		44
Utility margin	457		465		(8)		(2)		960		971		(11)		(1)
Operations and maintenance	85		90		(5)		(6)		236		230		6		3
Depreciation and amortization	109		106		3		3		323		312		11		4
Property and other taxes	14		14		—		—		42		39		3		8
Operating income	$	249	$	255	$	(6)	(2)	%	$	359	$	390	$	(31)	(8)	%

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Utility Margin

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


	Third Quarter								First Nine Months
	2023		2022		Change				2023		2022		Change
Utility margin (in millions):
Operating revenue	$	1,145	$	1,003	$	142	14	%	$	2,525	$	2,057	$	468	23	%
Cost of fuel and energy	688		538		150		28		1,565		1,086		479		44
Utility margin	$	457	$	465	$	(8)	(2)	%	$	960	$	971	$	(11)	(1)	%

Sales (GWhs):
Residential	3,993		4,228		(235)		(6)	%	7,897		8,425		(528)		(6)	%
Commercial	1,497		1,589		(92)		(6)		3,745		3,859		(114)		(3)
Industrial	1,716		1,696		20		1		4,414		4,280		134		3
Other	46		50		(4)		(8)		133		142		(9)		(6)
Total fully bundled(1)	7,252		7,563		(311)		(4)		16,189		16,706		(517)		(3)
Distribution only service	879		792		87		11		2,185		2,022		163		8
Total retail	8,131		8,355		(224)		(3)		18,374		18,728		(354)		(2)
Wholesale	63		172		(109)		(63)		193		507		(314)		(62)
Total GWhs sold	8,194		8,527		(333)		(4)	%	18,567		19,235		(668)		(3)	%

Average number of retail customers (in thousands)	1,018		1,003		15		1	%	1,014		999		15		2	%





Average revenue per MWh:
Retail - fully bundled(1)	$	154.23	$	127.11	$	27.12	21	%	$	151.33	$	117.34	$	33.99	29	%

Wholesale	$	55.88	$	92.51	$	(36.63)	(40)	%	$	66.80	$	56.19	$	10.61	19	%

Heating degree days	—		—		—		—		1,383		985		398		40	%
Cooling degree days	2,277		2,351		(74)		(3)	%	3,401		3,722		(321)		(9)	%

Sources of energy (GWhs)(2)(3):
Natural gas	3,989		4,326		(337)		(8)	%	10,183		9,639		544		6	%

Renewables	17		19		(2)		(11)		51		53		(2)		(4)
Total energy generated	4,006		4,345		(339)		(8)		10,234		9,692		542		6
Energy purchased	3,416		3,373		43		1		6,752		7,606		(854)		(11)
Total	7,422		7,718		(296)		(4)	%	16,986		17,298		(312)		(2)	%

Average cost of energy per MWh(2)(4):
Energy generated	$	35.61	$	41.04	$	(5.43)	(13)	%	$	60.30	$	43.88	$	16.42	37	%
Energy purchased	$	159.42	$	106.73	$	52.69	49	%	$	140.31	$	86.88	$	53.43	61	%

(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 214 GWhs and 183 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2023 and 2022, respectively. The average cost of energy per MWh and sources of energy excludes 676 GWhs and 967 GWhs of gas generated energy that is purchased at cost by related parties for the first nine 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 September 30, 2023 Compared to Quarter Ended September 30, 2022

Utility margin decreased $8 million, or 2%, for the third quarter of 2023 compared to 2022 primarily due to:

•$16 million of lower electric retail utility margin primarily due to lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 2.7% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers and

•$2 million of lower transmission and wholesale revenue.

The decrease in utility margin was partially offset by:

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

•$4 million of higher regulatory-related revenue deferrals.

Operations and maintenance decreased $5 million, or 6%, for the third quarter of 2023 compared to 2022 primarily due to lower earnings sharing, partially offset by higher energy efficiency program costs (offset in operating revenue), higher customer service operations expenses, higher technology costs and increased plant operations and maintenance expenses.

Depreciation and amortization increased $3 million, or 3%, for the third quarter of 2023 compared to 2022 primarily due to higher plant placed in-service.

Interest expense increased $8 million, or 20%, for the third quarter of 2023 compared to 2022 primarily due to higher long-term debt and higher average interest rate.

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

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

Interest and dividend income increased $5 million or 38% for the third quarter of 2023 compared to 2022 primarily due to favorable interest income, mainly from carrying charges on regulatory balances.

Other, net decreased $2 million or 67% for the third quarter of 2023 compared to 2022 primarily due to higher non-service pension costs.

Income tax expense decreased $4 million, or 16%, for the third quarter of 2023 compared to 2022 primarily due to lower pretax income. The effective tax rate was 9% in 2023 and 11% in 2022 and decreased primarily due to the effects of ratemaking.

First Nine Months of 2023 Compared to First Nine Months of 2022

Utility margin decreased $11 million, or 1%, for the first nine months of 2023 compared to 2022 primarily due to:

•$34 million of lower electric retail utility margin primarily due to lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 1.9% 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:

•$11 million of higher energy efficiency program rates (offset in operations and maintenance expense);

•$9 million of higher regulatory-related revenue deferrals; and

•$4 million of higher other retail revenue.

Operations and maintenance increased by $6 million, or 3%, for the first nine months of 2023 compared to 2022 primarily due to higher energy efficiency program costs (offset in operating revenue), increased plant operations and maintenance expenses, higher technology costs and higher customer service operations expenses, partially offset by lower earnings sharing.

Depreciation and amortization increased $11 million, or 4%, for the first nine months of 2023 compared to 2022 primarily due to higher plant placed in-service.

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Property and other taxes increased $3 million, or 8%, for the first nine 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 $29 million, or 25%, for the first nine months of 2023 compared to 2022 primarily due to higher long-term debt and higher average interest rate.

Capitalized interest increased $12 million for the first nine months of 2023 compared to 2022 primarily due to higher construction work-in-progress.

Allowance for equity funds increased $6 million, or 75% for the first nine months of 2023 compared to 2022 primarily due to higher construction work-in-progress.

Interest and dividend income increased $28 million or 90% for the first nine months of 2023 compared to 2022 primarily due to favorable interest income, mainly from carrying charges on regulatory balances.

Other, net increased $6 million for the first nine months of 2023 compared to 2022 primarily due to favorable cash surrender value of corporate-owned life insurance policies, partially offset by higher non-service pension costs.

Income tax expense decreased $6 million, or 17%, for the first nine months of 2023 compared to 2022 primarily due to lower pretax income. The effective tax rate was 9% in 2023 and 11% in 2022 and decreased primarily due to the effects of ratemaking.

Liquidity and Capital Resources

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


Cash and cash equivalents	$	44

Credit facility	600





Total net liquidity	$	644
Credit facility:
Maturity date	2026

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022, were $423 million and $232 million, respectively. The change was primarily due to higher collections from customers and increased customer and vendor deposits, partially offset by higher payments related to fuel and energy costs, the timing of payments for operating costs 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 nine-month periods ended September 30, 2023 and 2022, were $(1,002) million and $(523) 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 nine-month periods ended September 30, 2023 and 2022, were $579 million and $332 million, respectively. The change was primarily due to contributions from NV Energy, Inc. and higher proceeds from the issuance of long-term debt, offset by higher repayments of long-term debt and lower proceeds from short-term debt.

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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 an additional $2.1 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):


	Nine-Month Periods				Annual
	Ended September 30,				Forecast
	2022		2023		2023

Electric distribution	$	173	$	257	$	355
Electric transmission	61		110		183
Solar generation	47		257		286
Electric battery storage	1		104		240
Other	241		374		520
Total	$	523	$	1,102	$	1,584

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.

•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.

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•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.

2021 Joint Integrated Resource Plan

In August 2023, the Nevada Utilities filed its Joint Application for approval of the Fifth Amendment to the 2021 Joint Integrated Resource Plan. The Fifth Amendment seeks, in part (1) to convert the existing coal fueled plant at North Valmy Generating Station to a cleaner natural gas fueled plant (2) to purchase, install, and operate a company-owned 400 MW solar plant along with a 400 MW, four-hour battery storage system in Northern Nevada; (3) to continue operation of Tracy units 4 and 5 to 2049; (4) to purchase development assets for the 149 MW photovoltaic and 149 MW battery energy storage system Crescent Valley Solar project; (5) to construct the Esmeralda and Amargosa substations transformers; and (6) to construct the necessary infrastructure in the Apex Area Master Plan. The Nevada Utilities seek approval of approximately $1.8 billion in total costs of new projects of which Nevada Power's share is approximately $1.0 billion with an order expected in 2024.

Material Cash Requirements

As of September 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.

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Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of 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.

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Sierra Pacific Power Company and its subsidiaries

Consolidated Financial Section

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PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of September 30, 2023, the related consolidated statements of operations, and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 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.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

November 3, 2023

140

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)


	As of
	September 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	39	$	49
Trade receivables, net	170		175

Inventories	109		79

Regulatory assets	237		357

Other current assets	51		50
Total current assets	606		710

Property, plant and equipment, net	3,745		3,587

Regulatory assets	231		254
Other assets	183		181

Total assets	$	4,765	$	4,732

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	226	$	224
Note payable to affiliate	—		70

Accrued property, income and other taxes	19		15

Accrued employee expenses	19		11
Current portion of long-term debt	—		250


Customer deposits	20		18

Other current liabilities	53		64
Total current liabilities	337		652

Long-term debt	1,292		898
Finance lease obligations	95		100
Regulatory liabilities	424		436
Deferred income taxes	419		445
Other long-term liabilities	139		153
Total liabilities	2,706		2,684

Commitments and contingencies (Note 9)

Shareholder's equity:
Common stock - $3.75 stated value, 1,000 shares authorized, issued and outstanding	—		—
Additional paid-in capital	1,576		1,576
Retained earnings	484		473
Accumulated other comprehensive loss, net	(1)		(1)
Total shareholder's equity	2,059		2,048

Total liabilities and shareholder's equity	$	4,765	$	4,732

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

141

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Operating revenue:
Regulated electric	$	345	$	310	$	942	$	767
Regulated natural gas	27		20		167		100
Total operating revenue	372		330		1,109		867

Operating expenses:
Cost of fuel and energy	178		153		538		406
Cost of natural gas purchased for resale	17		10		123		60
Operations and maintenance	47		50		152		138
Depreciation and amortization	46		37		138		110
Property and other taxes	6		6		19		18
Total operating expenses	294		256		970		732

Operating income	78		74		139		135

Other income (expense):
Interest expense	(16)		(15)		(47)		(42)
Allowance for borrowed funds	—		1		5		2
Allowance for equity funds	5		1		10		5
Interest and dividend income	6		5		18		12
Other, net	1		1		3		3
Total other income (expense)	(4)		(7)		(11)		(20)

Income before income tax expense (benefit)	74		67		128		115
Income tax expense (benefit)	10		8		17		15
Net income	$	64	$	59	$	111	$	100

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

142

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)


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

Balance, June 30, 2022	1,000	$	—	$	1,451	$	396	$	(1)	$	1,846
Net income	—	—		—		59		—		59



Balance, September 30, 2022	1,000	$	—	$	1,451	$	455	$	(1)	$	1,905

Balance, December 31, 2021	1,000	$	—	$	1,111	$	425	$	(1)	$	1,535
Net income	—	—		—		100		—		100
Dividends declared	—	—		—		(70)		—		(70)

Contributions	—	—		340		—		—		340
Balance, September 30, 2022	1,000	$	—	$	1,451	$	455	$	(1)	$	1,905

Balance, June 30, 2023	1,000	$	—	$	1,576	$	520	$	(1)	$	2,095
Net income	—	—		—		64		—		64
Dividends declared	—	—		—		(100)		—		(100)


Balance, September 30, 2023	1,000	$	—	$	1,576	$	484	$	(1)	$	2,059

Balance, December 31, 2022	1,000	$	—	$	1,576	$	473	$	(1)	$	2,048
Net income	—	—		—		111		—		111
Dividends declared	—	—		—		(100)		—		(100)


Balance, September 30, 2023	1,000	$	—	$	1,576	$	484	$	(1)	$	2,059

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

143

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Nine-Month Periods
	Ended September 30,
	2023		2022
Cash flows from operating activities:
Net income	$	111	$	100
Adjustments to reconcile net income to net cash flows from operating activities:

Depreciation and amortization	138		110
Allowance for equity funds	(10)		(5)
Changes in regulatory assets and liabilities	6		(9)
Deferred income taxes and amortization of investment tax credits	(38)		22
Deferred energy	40		(203)
Amortization of deferred energy	77		66
Other, net	—		3
Changes in other operating assets and liabilities:
Trade receivables and other assets	(2)		(32)
Inventories	(31)		(11)
Accrued property, income and other taxes	(1)		(9)
Accounts payable and other liabilities	16		74
Net cash flows from operating activities	306		106

Cash flows from investing activities:
Capital expenditures	(284)		(278)


Net cash flows from investing activities	(284)		(278)

Cash flows from financing activities:
Proceeds from long-term debt	394		248
Repayments of long-term debt	(250)		—
Long-term debt reacquired	—		(265)
Net repayments of short-term debt	—		(39)
Dividends paid	(100)		(70)
Contributions from parent	—		340
Repayments of affiliate note payable	(70)		—
Other, net	(6)		(5)
Net cash flows from financing activities	(32)		209

Net change in cash and cash equivalents and restricted cash and cash equivalents	(10)		37
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	$	46	$	53

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

144

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 September 30, 2023, and for the three- and nine-month periods ended September 30, 2023 and 2022. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2023 and 2022. The results of operations for the three- and nine-month periods ended September 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 nine-month period ended September 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
	September 30,		December 31,
	2023		2022

Cash and cash equivalents	$	39	$	49
Restricted cash and cash equivalents included in other current assets	7		7
Total cash and cash equivalents and restricted cash and cash equivalents	$	46	$	56

145

(3) Property, Plant and Equipment, Net

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


		As of
	Depreciable Life	September 30,		December 31,
		2023		2022
Utility plant:
Electric generation	25 - 70 years	$	1,298	$	1,298
Electric transmission	50 - 76 years	1,000		993
Electric distribution	20 - 76 years	2,034		1,983
Electric general and intangible plant	5 - 65 years	227		219
Natural gas distribution	35 - 70 years	470		455
Natural gas general and intangible plant	5 - 65 years	17		15
Common general	5 - 65 years	386		380
Utility plant		5,432		5,343
Accumulated depreciation and amortization		(2,072)		(1,992)
		3,360		3,351


Construction work-in-progress		385		236
Property, plant and equipment, net		$	3,745	$	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

Long-Term Debt

In September 2023, Sierra Pacific issued $400 million of its 5.900% General and Refunding Mortgage Bonds, Series 2023A, due March 2054. Sierra Pacific used the net proceeds to repay short-term borrowings incurred under Sierra Pacific's revolving credit facility in connection with the redemption in August 2023 of its 3.375% General and Refunding Mortgage Notes, Series T, due 2023, fund capital expenditures and for general corporate purposes.

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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Federal statutory income tax rate	21	%	21	%	21	%	21	%
Effects of ratemaking	(8)		(8)		(8)		(8)




Other	1		(1)		—		—
Effective income tax rate	14	%	12	%	13	%	13	%

146

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 nine-month period ended September 30, 2023, Sierra Pacific made net cash payments for federal income tax to BHE totaling $54 million. For the nine-month period ended September 30, 2022, Sierra Pacific made no cash payments for federal income tax to BHE.

(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 $3 million to the Other Post Retirement Plans for the nine-month period ended September 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
	September 30,		December 31,
	2023		2022
Qualified Pension Plan:

Other non-current assets	$	45	$	43



Non-Qualified Pension Plans:


Other current liabilities	(1)		(1)
Other long-term liabilities	(5)		(5)

Other Postretirement Plans:

Other non-current assets	1		—

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.

147

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.

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 September, 30 2023
Not designated as hedging contracts(1) -






Total derivatives - commodity liabilities	$	—	$	(11)	$	(1)	$	(12)

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 September 30, 2023 a net regulatory asset of $12 million was recorded related to the net derivative liability of $12 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	September 30,	December 31,
	Measure	2023	2022

Electricity purchases	Megawatt hours	—	1
Natural gas purchases	Decatherms	70	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.

148

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 September 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.

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 September 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 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.

149

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 September 30, 2023:
Assets:

Money market mutual funds	$	38	—		—		$	38
Investment funds	1		—		—		1
	$	39	$	—	$	—	$	39

Liabilities - commodity derivatives	$	—	$	—	$	(12)	$	(12)

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)

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 September 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.

150

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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Beginning balance	$	(36)	$	(54)	$	(13)	$	(33)
Changes in fair value recognized in regulatory assets	(8)		1		(45)		(25)

Settlements	32		36		46		41
Ending balance	$	(12)	$	(17)	$	(12)	$	(17)

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


	As of September 30, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	1,292	$	1,218	$	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.

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.

151

(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 September 30,
	2023						2022
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Customer Revenue:
Retail:
Residential	$	116	$	15	$	131	$	107	$	13	$	120
Commercial	111		6		117		100		5		105
Industrial	96		5		101		73		2		75
Other	—		1		1		2		—		2
Total fully bundled	323		27		350		282		20		302
Distribution only service	2		—		2		1		—		1
Total retail	325		27		352		283		20		303
Wholesale, transmission and other	20		—		20		26		—		26
Total Customer Revenue	345		27		372		309		20		329
Other revenue	—		—		—		1		—		1
Total operating revenue	$	345	$	27	$	372	$	310	$	20	$	330


	Nine-Month Periods
	Ended September 30,
	2023						2022
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Customer Revenue:
Retail:
Residential	$	326	$	100	$	426	$	270	$	64	$	334
Commercial	304		45		349		251		26		277
Industrial	241		20		261		175		9		184
Other	3		1		4		4		—		4
Total fully bundled	874		166		1,040		700		99		799
Distribution only service	4		—		4		4		—		4
Total retail	878		166		1,044		704		99		803
Wholesale, transmission and other	64		—		64		61		—		61
Total Customer Revenue	942		166		1,108		765		99		864
Other revenue	—		1		1		2		1		3
Total operating revenue	$	942	$	167	$	1,109	$	767	$	100	$	867

152

(11) Segment Information

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

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


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Operating revenue:
Regulated electric	$	345	$	310	$	942	$	767
Regulated natural gas	27		20		167		100
Total operating revenue	$	372	$	330	$	1,109	$	867





















Operating income:
Regulated electric	$	78	$	74	$	126	$	123
Regulated natural gas	—		—		13		12
Total operating income	78		74		139		135
Interest expense	(16)		(15)		(47)		(42)
Allowance for borrowed funds	—		1		5		2
Allowance for equity funds	5		1		10		5
Interest and dividend income	6		5		18		12
Other, net	1		1		3		3
Total income before income tax expense (benefit)	$	74	$	67	$	128	$	115










	As of
		September 30,		December 31,
		2023		2022
Assets:
Regulated electric		$	4,238	$	4,224
Regulated natural gas		451		441
Other(1)		76		67
Total assets		$	4,765	$	4,732

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

153

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

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

Results of Operations for the Third Quarter and First Nine Months of 2023 and 2022

Overview

Net income for the third quarter of 2023 was $64 million, an increase of $5 million, or 8%, compared to 2022 primarily due to higher utility margin, higher allowance for equity 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 4% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers. Energy generated decreased 12% for the third quarter of 2023 compared to 2022 primarily due to lower coal-fueled generation and lower natural gas-fueled generation. Wholesale electricity sales volumes decreased 39% and purchased electricity volumes increased 28%.

Net income for the first nine months of 2023 was $111 million, an increase of $11 million, or 11%, compared to 2022 primarily due to higher utility margin, higher interest and dividend income, primarily from carrying charges on regulatory balances and higher allowances for borrowed and equity 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, 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 3% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers. Energy generated decreased 2% for the first nine months of 2023 compared to 2022 primarily due to lower coal-fueled generation offset by higher natural gas-fueled generation. Wholesale electricity sales volumes decreased 20% and purchased electricity volumes decreased 4%.

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.

154

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


	Third Quarter								First Nine Months
	2023		2022		Change				2023		2022		Change
Electric utility margin:
Operating revenue	$	345	$	310	$	35	11	%	$	942	$	767	$	175	23	%
Cost of fuel and energy	178		153		25		16		538		406		132		33
Electric utility margin	167		157		10		6	%	404		361		43		12	%

Natural gas utility margin:
Operating revenue	27		20		7		35	%	167		100		67		67	%
Natural gas purchased for resale	17		10		7		70		123		60		63		*
Natural gas utility margin	10		10		—		—	%	44		40		4		10	%

Utility margin	177		167		10		6	%	448		401		47		12	%

Operations and maintenance	47		50		(3)		(6)	%	152		138		14		10	%
Depreciation and amortization	46		37		9		24		138		110		28		25
Property and other taxes	6		6		—		—		19		18		1		6
Operating income	$	78	$	74	$	4	5	%	$	139	$	135	$	4	3	%

* Not meaningful

155

Electric Utility Margin

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


	Third Quarter								First Nine Months
	2023		2022		Change				2023		2022		Change
Utility margin (in millions):
Operating revenue	$	345	$	310	$	35	11	%	$	942	$	767	$	175	23	%
Cost of fuel and energy	178		153		25		16		538		406		132		33
Utility margin	$	167	$	157	$	10	6	%	$	404	$	361	$	43	12	%

Sales (GWhs):
Residential	752		834		(82)		(10)	%	2,023		2,070		(47)		(2)	%
Commercial	847		910		(63)		(7)		2,303		2,388		(85)		(4)
Industrial	693		712		(19)		(3)		2,010		2,188		(178)		(8)
Other	3		3		—		—		9		10		(1)		(10)
Total fully bundled(1)	2,295		2,459		(164)		(7)		6,345		6,656		(311)		(5)
Distribution only service	744		700		44		6		2,082		2,037		45		2
Total retail	3,039		3,159		(120)		(4)		8,427		8,693		(266)		(3)
Wholesale	113		184		(71)		(39)		473		589		(116)		(20)
Total GWhs sold	3,152		3,343		(191)		(6)	%	8,900		9,282		(382)		(4)	%

Average number of retail customers (in thousands)	376		372		4		1	%	375		370		5		1	%





Average revenue per MWh:
Retail - fully bundled(1)	$	141.30	$	114.38	$	26.92	24	%	$	137.85	$	105.18	$	32.67	31	%

Wholesale	$	97.06	$	93.37	$	3.69	4	%	$	88.84	$	67.18	$	21.66	32	%

Heating degree days	56		37		19		51	%	3,294		2,735		559		20	%
Cooling degree days	956		1,133		(177)		(16)	%	1,091		1,347		(256)		(19)	%

Sources of energy (GWhs)(2):
Natural gas	1,200		1,283		(83)		(6)	%	3,161		2,980		181		6	%
Coal	225		335		(110)		(33)		578		840		(262)		(31)
Renewables	8		8		—		—		21		21		—		—
Total energy generated	1,433		1,626		(193)		(12)		3,760		3,841		(81)		(2)
Energy purchased	1,832		1,432		400		28		3,882		4,055		(173)		(4)
Total	3,265		3,058		207		7	%	7,642		7,896		(254)		(3)	%

Average cost of energy per MWh(3):
Energy generated	$	31.94	$	29.41	$	2.53	9	%	$	64.29	$	43.56	$	20.73	48	%
Energy purchased	$	72.52	$	73.26	$	(0.74)	(1)	%	$	76.34	$	58.92	$	17.42	30	%

(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.

156

Natural Gas Utility Margin

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


	Third Quarter								First Nine Months
	2023		2022		Change				2023		2022		Change
Utility margin (in millions):
Operating revenue	$	27	$	20	$	7	35	%	$	167	$	100	$	67	67	%
Natural gas purchased for resale	17		10		7		70		123		60		63		*
Utility margin	$	10	$	10	$	—	—	%	$	44	$	40	$	4	10	%

Sold (000's Dths):
Residential	838		785		53		7	%	8,547		7,134		1,413		20	%
Commercial	528		535		(7)		(1)		4,451		3,798		653		17
Industrial	472		295		177		60		2,119		1,350		769		57
Total retail	1,838		1,615		223		14	%	15,117		12,282		2,835		23	%

Average number of retail customers (in thousands)	183		180		3		2	%	183		180		3		2	%

Average revenue per retail Dth sold	$	14.81	$	12.79	$	2.02	16	%	$	11.04	$	8.16	$	2.88	36	%

Heating degree days	56		37		19		51	%	3,294		2,735		559		20	%

Average cost of natural gas per retail Dth sold	$	9.00	$	6.36	$	2.64	42	%	$	8.11	$	4.89	$	3.22	66	%

* Not meaningful

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

Electric utility margin increased $10 million, or 6%, for the third quarter of 2023 compared to 2022 primarily due to:

•$13 million of higher electric retail utility margin primarily due to higher retail rates from 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 3.8% 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:

•$2 million of lower transmission and wholesale revenue.

Operations and maintenance decreased $3 million, or 6%, for the third quarter of 2023 compared to 2022 primarily due to lower regulatory-approved amortization from the recovery for the ON Line reallocation (offset in operating revenue) and lower plant operations and maintenance expenses, partially offset by lower regulatory credits from the deferral of the ON Line lease cost reallocation in 2022.

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

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

Income tax expense increased $2 million, or 25%, for the third quarter of 2023 compared to 2022 primarily due to higher pretax income. The effective tax rate was 14% in 2023 and 12% in 2022.

157

First Nine Months of 2023 Compared to First Nine Months of 2022

Electric utility margin increased $43 million, or 12%, for the first nine months of 2023 compared to 2022 primarily due to:

•$41 million of higher electric retail utility margin primarily due to 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 3.1% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers and

•$4 million of higher transmission and wholesale revenue.

Natural gas utility margin increased $4 million, or 10%, for the first nine months of 2023 compared to 2022 primarily due to higher customer volumes from the favorable impact of weather.

Operations and maintenance increased $14 million, or 10%, for the first nine months of 2023 compared to 2022 primarily due to increased plant operations and maintenance expenses, lower regulatory credits from the deferral of the ON Line lease cost reallocation in 2022 and higher customer service operations expenses, partially offset by lower regulatory-approved amortization from the recovery for the ON Line reallocation (offset in operating revenue).

Depreciation and amortization increased $28 million, or 25%, for the first nine months of 2023 compared to 2022 primarily due to higher plant placed in-service and higher regulatory amortizations.

Interest expense increased $5 million, or 12%, for the first nine months of 2023 compared to 2022 primarily due to higher long-term debt and higher average interest rate.

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

Allowance for equity funds increased $5 million for the first nine months of 2023 compared to 2022 primarily due to higher construction work-in-progress.

Interest and dividend income increased $6 million, or 50%, for the first nine months of 2023 compared to 2022 primarily due to higher interest income, mainly from carrying charges on regulatory balances.

Income tax expense increased $2 million, or 13%, for the first nine months of 2023 compared to 2022 primarily due to higher pretax income. The effective tax rate was 13% in 2023 and 2022.

Liquidity and Capital Resources

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


Cash and cash equivalents	$	39

Credit facility	400





Total net liquidity	$	439
Credit facility:
Maturity date	2026

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022, were $306 million and $106 million, respectively. The change was primarily due to higher collections from customers and the timing of payments for operating costs, partially offset by increased income tax payments, higher payments related to fuel and energy costs, decreased customer deposits and higher interest payments.

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.

158

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2023 and 2022, were $(284) million and $(278) million, respectively. The change was primarily due to increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month periods ended September 30, 2023 and 2022, were $(32) million and $209 million, respectively. The change was primarily due to lower contributions from NV Energy, Inc., higher repayments of long-term debt, higher repayments of an affiliate note payable and higher dividends paid to NV Energy, Inc., partially offset by lower long-term debt reacquired, higher proceeds from the issuance of long-term debt and lower repayments of short-term debt.

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):


	Nine-Month Periods				Annual
	Ended September 30,				Forecast
	2022		2023		2023


Electric distribution	$	84	$	120	$	179
Electric transmission	69		67		104
Solar generation	—		1		2
Electric battery storage	—		2		2
Other	125		94		135
Total	$	278	$	284	$	422

159

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.

2021 Joint Integrated Resource Plan

In August 2023, the Nevada Utilities filed its Joint Application for approval of the Fifth Amendment to the 2021 Joint Integrated Resource Plan. The Fifth Amendment seeks, in part (1) to convert the existing coal fueled plant at North Valmy Generating Station to a cleaner natural gas fueled plant (2) to purchase, install, and operate a company-owned 400 MW solar plant along with a 400 MW, four-hour battery storage system in Northern Nevada; (3) to continue operation of Tracy units 4 and 5 to 2049; (4) to purchase development assets for the 149 MW photovoltaic and 149 MW battery energy storage system Crescent Valley Solar project; (5) to construct the Esmeralda and Amargosa substations transformers; and (6) to construct the necessary infrastructure in the Apex Area Master Plan. The Nevada Utilities seek approval of approximately $1.8 billion in total costs of new projects of which Sierra Pacific's share is approximately $0.8 billion with an order expected in 2024.

Material Cash Requirements

As of September 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.

160

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.

161

Eastern Energy Gas Holdings, LLC and its subsidiaries

Consolidated Financial Section

162

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Eastern Energy Gas Holdings, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Eastern Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of September 30, 2023, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 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.

/s/ Deloitte & Touche LLP

Richmond, Virginia

November 3, 2023

163

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	September 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	94	$	65

Trade receivables, net	161		202
Receivables from affiliates	19		30
Income taxes receivable	245		17
Notes receivable from affiliates	—		536

Inventories	135		127
Prepayments and other deferred charges	31		78
Natural gas imbalances	17		193
Other current assets	39		55
Total current assets	741		1,303

Property, plant and equipment, net	10,344		10,202
Goodwill	1,286		1,286

Investments	264		278

Other assets	101		95

Total assets	$	12,736	$	13,164

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

164

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	September 30, 2023		December 31, 2022
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	67	$	86
Accounts payable to affiliates	19		10
Accrued interest	47		19
Accrued property, income and other taxes	79		77


Regulatory liabilities	36		126

Current portion of long-term debt	400		649
Other current liabilities	105		146
Total current liabilities	753		1,113

Long-term debt	3,242		3,243


Regulatory liabilities	612		596
Deferred income taxes	295		166
Other long-term liabilities	155		158
Total liabilities	5,057		5,276

Commitments and contingencies (Note 9)

Equity:
Member's equity:

Membership interests	6,417		3,983


Accumulated other comprehensive loss, net	(39)		(42)
Total member's equity	6,378		3,941
Noncontrolling interests	1,301		3,947
Total equity	7,679		7,888

Total liabilities and equity	$	12,736	$	13,164

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

165

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022




Operating revenue	$	475	$	547	$	1,549	$	1,533

Operating expenses:

Cost of (excess) gas	6		(24)		31		(46)
Operations and maintenance	157		117		434		359
Depreciation and amortization	80		76		240		241
Property and other taxes	36		36		99		102

Total operating expenses	279		205		804		656

Operating income	196		342		745		877

Other income (expense):
Interest expense	(35)		(36)		(107)		(108)

Allowance for equity funds	2		2		6		5
Interest and dividend income	8		3		28		3

Other, net	(1)		(2)		—		(3)
Total other income (expense)	(26)		(33)		(73)		(103)

Income before income tax expense (benefit) and equity income (loss)	170		309		672		774
Income tax expense (benefit)	5		64		75		131
Equity income (loss)	5		52		43		80


Net income	170		297		640		723
Net income attributable to noncontrolling interests	78		146		327		375
Net income attributable to Eastern Energy Gas	$	92	$	151	$	313	$	348

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

166

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Net income	$	170	$	297	$	640	$	723

Other comprehensive income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $(1), $—, $(1) and $—	(1)		—		(2)		1


Unrealized gains on cash flow hedges, net of tax of $—, $1, $3 and $2	1		1		6		4
Total other comprehensive income, net of tax	—		1		4		5

Comprehensive income	170		298		644		728
Comprehensive income attributable to noncontrolling interests	78		146		327		375
Comprehensive income attributable to Eastern Energy Gas	$	92	$	152	$	317	$	353

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

167

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, June 30, 2022	$	3,733	$	(39)	$	4,023	$	7,717
Net income	151		—		146		297
Other comprehensive income	—		1		—		1
Distributions	(4)		—		(146)		(150)
Contributions	11		—		—		11
Balance, September 30, 2022	$	3,891	$	(38)	$	4,023	$	7,876

Balance, December 31, 2021	$	3,501	$	(43)	$	4,036	$	7,494
Net income	348		—		375		723
Other comprehensive income	—		5		—		5
Distributions	(37)		—		(388)		(425)
Contributions	79		—		—		79






Balance, September 30, 2022	$	3,891	$	(38)	$	4,023	$	7,876

Balance, June 30, 2023	$	4,152	$	(38)	$	3,930	$	8,044
Net income	92		—		78		170

Distributions	(148)		—		(87)		(235)
Contributions	2,880		—		—		2,880
Purchase of Cove Point noncontrolling interest (Note 2)	(559)		(1)		(2,620)		(3,180)
Balance, September 30, 2023	$	6,417	$	(39)	$	1,301	$	7,679

Balance, December 31, 2022	$	3,983	$	(42)	$	3,947	$	7,888
Net income	313		—		327		640
Other comprehensive income	—		4		—		4
Distributions	(233)		—		(353)		(586)
Contributions	2,913		—		—		2,913
Purchase of Cove Point noncontrolling interest (Note 2)	(559)		(1)		(2,620)		(3,180)
Balance, September 30, 2023	$	6,417	$	(39)	$	1,301	$	7,679

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

168

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Nine-Month Periods
	Ended September 30,
	2023		2022
Cash flows from operating activities:
Net income	$	640	$	723
Adjustments to reconcile net income to net cash flows from operating activities:

(Gains) losses on other items, net	(5)		2
Depreciation and amortization	240		241
Allowance for equity funds	(6)		(5)
Equity loss (income), net of distributions	16		(46)
Changes in regulatory assets and liabilities	(97)		37
Deferred income taxes	267		99
Other, net	(3)		7
Changes in other operating assets and liabilities:
Trade receivables and other assets	84		(48)
Receivables from affiliates	10		33
Gas balancing activities	22		(48)
Derivative collateral, net	1		(3)

Accrued property, income and other taxes	(194)		8
Accounts payable to affiliates	9		(18)
Accounts payable and other liabilities	(2)		53
Net cash flows from operating activities	982		1,035

Cash flows from investing activities:
Capital expenditures	(241)		(252)
Proceeds from assignment of shale development rights	8		—

Repayment of notes by affiliates	734		31
Notes to affiliates	(198)		(363)

Other, net	(2)		(11)
Net cash flows from investing activities	301		(595)

Cash flows from financing activities:

Repayments of long-term debt	(250)		—




Proceeds from equity contributions	2,876		—
Purchase of Cove Point noncontrolling interest	(3,300)		—
Distributions to noncontrolling interests	(353)		(388)
Distributions to parent	(226)		—
Other, net	—		(4)
Net cash flows from financing activities	(1,253)		(392)



Net change in cash and cash equivalents and restricted cash and cash equivalents	30		48
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	$	125	$	87

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

169

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. On September 1, 2023, Eastern Energy Gas completed its acquisition of 50% of the limited partner interests in Cove Point from Dominion Energy, Inc. ("DEI"), and accordingly, owns an aggregate of 75% of the limited partner interests and continues to own 100% of the general partner interest of 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 September 30, 2023 and for the three- and nine-month periods ended September 30, 2023 and 2022. The results of operations for the three- and nine-month periods ended September 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 nine-month period ended September 30, 2023.

(2) Business Acquisitions

On September 1, 2023, BHE and Eastern MLP Holding Company II, LLC ("the Buyer"), a wholly owned subsidiary of Eastern Energy Gas, completed the acquisition of DECP Holdings, Inc.'s (the "Seller"), an indirect wholly owned subsidiary of Dominion Energy, Inc., 50% limited partner interests in Cove Point ("The Transaction"). Under the terms of the Purchase and Sale Agreement, dated July 9, 2023 (the "Purchase Agreement"), the Buyer paid $3.3 billion in cash, plus the pro rata portion of the quarterly distribution made by Cove Point for the third fiscal quarter of 2023. Eastern Energy Gas funded the Transaction through cash provided by BHE GT&S, LLC, which included an equity contribution of $2.9 billion and the repayment of affiliated notes of $474 million. The Buyer now owns an aggregate of 75% of the limited partner interests, and its affiliate, Cove Point GP Holding Company, LLC, continues to own 100% of the general partner interest, of Cove Point. Prior to the Transaction, Eastern Energy Gas owned 100% of the general partner interest and 25% of the limited partner interests in Cove Point. Eastern Energy Gas previously determined it has the power to direct the activities that most significantly impact Cove Point's economic performance as well as the obligation to absorb losses and benefits which could be significant to it and accordingly, consolidated Cove Point. Because Eastern Energy Gas controls Cove Point both before and after the Transaction, the changes in Eastern Energy Gas' ownership interest in Cove Point were accounted for as an equity transaction and no gain or loss was recognized. In connection with the Transaction, Eastern Energy Gas recognized $120 million of income taxes in equity primarily attributable to the step up in tax basis of the investment in Cove Point of $144 million, partially offset by establishing additional regulatory liabilities related to excess deferred income taxes of $24 million.

170

(3) Property, Plant and Equipment, Net

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


		As of
		September 30,		December 31,
	Depreciable Life	2023		2022
Utility plant:

Interstate natural gas transmission and storage assets	21 - 51 years	$	9,197	$	8,922
Intangible plant	5 - 17 years	117		113
Utility plant in-service		9,314		9,035
Accumulated depreciation and amortization		(3,162)		(3,039)
Utility plant in-service, net		6,152		5,996

Nonutility plant:

LNG facility	40 years	4,525		4,522
Intangible plant	14 years	25		25
Nonutility plant		4,550		4,547
Accumulated depreciation and amortization		(634)		(542)
Nonutility plant, net		3,916		4,005

		10,068		10,001
Construction work-in-progress		276		201
Property, plant and equipment, net		$	10,344	$	10,202

Construction work-in-progress includes $260 million and $181 million as of September 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.

171

(5) Investments and Restricted Cash and Cash Equivalents

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


	As of
	September 30,		December 31,
	2023		2022
Investments:
Investment funds	$	18	$	14


Equity method investments:
Iroquois	246		264


Total investments	264		278

Restricted cash and cash equivalents:
Customer deposits	31		30
Total restricted cash and cash equivalents	31		30

Total investments and restricted cash and cash equivalents	$	295	$	308

Reflected as:
Other current assets	$	31	$	30
Noncurrent assets	264		278
Total investments and restricted cash and cash equivalents	$	295	$	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 September 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 $59 million and $34 million for the nine-month periods ended September 30, 2023 and 2022, respectively. In the third quarter of 2022, in connection with the settlement of regulated tax matters in the Iroquois rate case, Eastern Energy Gas released a long-term regulatory liability and recognized a $45 million benefit that was recorded in equity income (loss) in its Consolidated Statements of Operations.

172

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
	September 30,		December 31,
	2023		2022

Cash and cash equivalents	$	94	$	65
Restricted cash and cash equivalents included in other current assets	31		30
Total cash and cash equivalents and restricted cash and cash equivalents	$	125	$	95

(6) Income Taxes

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


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Federal statutory income tax rate	21	%	21	%	21	%	21	%
State income tax, net of federal income tax benefit	(8)		6		(1)		5



Equity interest	1		4		1		2
Effects of ratemaking	—		—		—		(1)





Noncontrolling interest	(10)		(10)		(10)		(10)

Other, net	(1)		—		—		—
Effective income tax rate	3	%	21	%	11	%	17	%

For the period ended September 30, 2023, Eastern Energy Gas' reconciliation of the federal statutory income tax rate to the effective income tax rate is driven primarily by the change in the state apportionment and its impact on Eastern Energy Gas' deferred tax liability, as well as the Transaction's impact on certain combined state filing adjustments. An additional rate driver was the absence of tax on income attributable to Cove Point's 25% noncontrolling interest.

Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, Eastern Energy Gas' 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 current federal and state income taxes, Eastern Energy Gas had a receivable from BHE of $241 million and $16 million as of September 30, 2023 and December 31, 2022, respectively. The increase in the income tax receivable is primarily due to the bonus deprecation deduction being taken on the step-up of tax basis on non-regulated assets as a result of the Transaction.

173

(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 $6 million and $10 million to the MidAmerican Energy Company Retirement Plan for the nine-month periods ended September 30, 2023 and 2022, respectively, and $1 million and $2 million to the MidAmerican Energy Company Welfare Benefit Plan for the nine-month periods ended September 30, 2023 and 2022, respectively. 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 September 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.

174

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 September 30, 2023:
Assets:


Money market mutual funds	$	94	$	—	$	—	$	94
Equity securities:
Investment funds	18		—		—		18
	$	112	$	—	$	—	$	112

Liabilities:

Foreign currency exchange rate derivatives	$	—	$	(18)	$	—	$	(18)

	$	—	$	(18)	$	—	$	(18)

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.

175

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 September 30, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	3,642	$	3,200	$	3,892	$	3,510

(9) Commitments and Contingencies

Environmental 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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Customer Revenue:
Regulated:
Gas transmission and storage	$	281	$	296	$	907	$	867

Other	8		1		9		1
Total regulated	289		297		916		868




Nonregulated	187		254		630		673
Total Customer Revenue	476		551		1,546		1,541
Other revenue(1)	(1)		(4)		3		(8)
Total operating revenue	$	475	$	547	$	1,549	$	1,533

(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 $28 million and $80 million as of September 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 nine-month period ended September 30, 2023, Eastern Energy Gas recognized revenue of $51 million from the beginning contract liability balance.

176

Remaining Performance Obligations

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


	Performance obligations expected to be satisfied
	Less than 12 months		More than 12 months		Total

Eastern Energy Gas	$	1,657	$	14,744	$	16,401

(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		4		—		5
Balance, September 30, 2022	$	(5)	$	(38)	$	5	$	(38)

Balance, December 31, 2022	$	(1)	$	(43)	$	2	$	(42)
Other comprehensive (loss) income	(2)		6		—		4
Purchase of noncontrolling interest	—		—		(1)		(1)
Balance, September 30, 2023	$	(3)	$	(37)	$	1	$	(39)

177

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

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

Results of Operations for the Third Quarter and First Nine Months of 2023 and 2022

Overview

Net income attributable to Eastern Energy Gas for the third quarter of 2023 was $92 million, a decrease of $59 million, or 39%, compared to 2022. Net income decreased primarily due to a benefit in 2022 from the settlement of regulated tax matters in the Iroquois rate case, lower margin from EGTS' regulated gas transmission and storage operations of $38 million, an increase in operations and maintenance expense excluding Cove Point of $23 million and lower net income at Cove Point as a result of increased scheduled maintenance days in 2023 of $12 million, partially offset by lower income tax expense primarily due to lower pre-tax income.

Net income attributable to Eastern Energy Gas for the first nine months of 2023 was $313 million, a decrease of $35 million, or 10%, compared to 2022. Net income decreased primarily due to a benefit in 2022 from the settlement of regulated tax matters in the Iroquois rate case, lower margin from EGTS' regulated gas transmission and storage operations of $30 million, an increase in salaries, wages and benefits and higher technology and related charges, partially offset by lower income tax expense primarily due to lower pre-tax income and interest income from higher outstanding loans and higher interest rates under BHE GT&S' intercompany revolving credit agreement.

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

Operating revenue decreased $72 million, or 13%, for the third quarter of 2023 compared to 2022, primarily due to a decrease in Cove Point LNG variable revenue of $41 million, decreased LNG service as a result of increased scheduled maintenance days of $29 million, 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 $9 million and a decrease in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of $5 million, partially offset by derivative losses in 2022 of $6 million and an increase in regulated gas sales for operational and system balancing purposes primarily due to increased volumes of $5 million.

Cost of (excess) gas was an expense of $6 million for the third quarter of 2023 compared to a credit of $24 million for the third 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 $25 million and an increase in volumes sold of $5 million.

Operations and maintenance increased $40 million, or 34%, for the third quarter of 2023 compared to 2022, primarily due to an increase in outside services of $12 million, an increase in the cost of materials of $11 million, an increase in salaries, wages and benefits of $7 million, Cove Point planned outage costs of $6 million and higher technology and related charges of $5 million.

Depreciation and amortization increased $4 million, or 5%, for the third quarter of 2023 compared to 2022, primarily due to a 2022 amortization true-up as a result of the settlement of depreciation rates in EGTS' general rate case of $2 million and higher plant placed in-service of $2 million.

Interest and dividend income increased $5 million for the third quarter of 2023 compared to 2022, primarily due to income from money market mutual fund investments of $3 million and interest income from higher outstanding loans and higher interest rates under BHE GT&S' intercompany revolving credit agreement of $2 million.

Income tax expense decreased $59 million, or 92%, for the third quarter of 2023 compared to 2022, primarily due to lower pre-tax income and the effective tax rate was 3% for 2023 and 21% for 2022. The effective tax rate decreased primarily due to the impacts from the Transaction and various changes in the state effective rate.

Equity income decreased $47 million, or 90%, for the third quarter of 2023 compared to 2022, primarily due to a benefit in 2022 from the settlement of regulated tax matters in the Iroquois rate case.

178

Net income attributable to noncontrolling interests decreased $68 million, or 47%, for the third quarter of 2023 compared to 2022, primarily due to lower net income attributable to Cove Point of $63 million and the acquisition of DEI's 50% noncontrolling interest in Cove Point of $5 million.

First Nine Months of 2023 Compared to First Nine Months of 2022

Operating revenue increased $16 million, or 1%, for the first nine 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 $45 million, increased LNG revenues as a result of the timing of the release of contract liabilities from scheduled outage days in 2022 of $42 million, an increase in variable revenue related to park and loan activity of $22 million and derivative losses in 2022 of $13 million, partially offset by a decrease in Cove Point LNG variable revenue of $49 million, decreased LNG service as a result of increased scheduled maintenance days of $29 million and 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 $26 million.

Cost of (excess) gas was an expense of $31 million for the first nine months of 2023 compared to a credit of $46 million for the first nine months of 2022. The change is primarily from a decrease from 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 $39 million, the unfavorable revaluation of the volumes retained prior to the effective date of the new fuel tracker due to lower natural gas prices of $35 million, and an increase in volumes sold of $5 million.

Operations and maintenance increased $75 million, or 21%, for the first nine months of 2023 compared to 2022, primarily due to an increase in salaries, wages and benefits of $25 million, higher technology and related charges of $16 million, an increase in outside services of $12 million, Cove Point planned outage costs of $6 million and various other immaterial items, 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 $3 million, or 3%, for the first nine months of 2023 compared to 2022, primarily due to lower than estimated 2022 tax assessments.

Interest and dividend income increased $25 million for the first nine 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 of $17 million and income from money market mutual fund investments of $8 million.

Income tax expense decreased $56 million, or 43%, for the first nine months of 2023 compared to 2022, primarily due to lower pre-tax income and the effective tax rate was 11% for 2023 and 17% for 2022. The effective tax rate decreased primarily due to the impacts from the Transaction and various changes in the state effective rate.

Equity income decreased $37 million, or 46%, for the first nine months of 2023 compared to 2022, primarily due to a benefit in 2022 from the settlement of regulated tax matters in the Iroquois rate case of $45 million, offset by higher earnings from Iroquois due to favorable negotiated rate agreements and hedges of $8 million.

Net income attributable to noncontrolling interests decreased $48 million, or 13%, for the first nine months of 2023 compared to 2022, primarily due to lower net income attributable to Cove Point of $43 million and the acquisition of DEI's 50% noncontrolling interest in Cove Point of $5 million.

Liquidity and Capital Resources

As of September 30, 2023, Eastern Energy Gas' total net liquidity was as follows (in millions):


Cash and cash equivalents	$	94

Intercompany revolving credit agreement	400





Total net liquidity	$	494

Intercompany revolving credit agreement:
Maturity date	2024

179

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022 were $982 million and $1.0 billion, respectively. The change is primarily due to the timing of income tax payments and the repayment of EGTS rate refunds to customers, partially offset by 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 nine-month periods ended September 30, 2023 and 2022 were $301 million and $(595) million, respectively. The change is primarily due to an increase in repayments of loans by affiliates of $703 million, a decrease in loans to its parent under an intercompany revolving credit agreement of $165 million, a decrease in capital expenditures of $11 million and proceeds from the assignment of shale development rights of $8 million.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2023 were $(1.3) billion. Uses of cash totaled $4.1 billion and consisted of $3.3 billion for the purchase of Cove Point noncontrolling interest, distributions to noncontrolling interests from Cove Point of $352 million, repayment of long-term debt of $250 million and distributions to its indirect parent, BHE, of $227 million. Sources of cash totaled $2.9 billion and consisted of proceeds from equity contributions to fund the Transaction.

For a discussion of business acquisitions, refer to Note 2 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Net cash flows from financing activities for the nine-month period ended September 30, 2022 were $(392) million and consisted primarily 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.

180

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


	Nine-Month Periods				Annual
	Ended September 30,				Forecast
	2022		2023		2023

Natural gas transmission and storage	$	36	$	17	$	32
Other	216		224		338
Total	$	252	$	241	$	370

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.

Material Cash Requirements

As of September 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.

181

Eastern Gas Transmission and Storage, Inc. and its subsidiaries

Consolidated Financial Section

182

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 September 30, 2023, the related consolidated statements of operations, comprehensive income, and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 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.

/s/ Deloitte & Touche LLP

Richmond, Virginia

November 3, 2023

183

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	September 30,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	12	$	16
Restricted cash and cash equivalents	29		29
Trade receivables, net	86		113
Receivables from affiliates	8		13

Inventories	54		50
Income taxes receivable	28		21
Prepayments and other deferred charges	25		36
Natural gas imbalances	13		193
Other current assets	6		9
Total current assets	261		480

Property, plant and equipment, net	4,699		4,504



Other assets	140		190

Total assets	$	5,100	$	5,174

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

184

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions, except share data)


	As of
	September 30, 2023		December 31, 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	41	$	46
Accounts payable to affiliates	17		5
Accrued interest	23		7
Accrued property, income and other taxes	51		71
Accrued employee expenses	21		13
Notes payable to affiliates	15		36
Regulatory liabilities	28		109
Customer and security deposits	29		29
Asset retirement obligations	9		25
Other current liabilities	23		32
Total current liabilities	257		373

Long-term debt	1,583		1,582
Regulatory liabilities	516		518
Other long-term liabilities	101		101
Total liabilities	2,457		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	763		746
Accumulated other comprehensive loss, net	(29)		(30)
Total shareholder's equity	2,643		2,600

Total liabilities and shareholder's equity	$	5,100	$	5,174

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

185

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Operating revenue	$	233	$	240	$	747	$	697

Operating expenses:
Cost of (excess) gas	6		(25)		31		(49)
Operations and maintenance	99		80		293		250
Depreciation and amortization	38		34		112		115
Property and other taxes	14		15		35		39
Total operating expenses	157		104		471		355

Operating income	76		136		276		342

Other income (expense):
Interest expense	(17)		(16)		(52)		(50)

Allowance for equity funds	1		1		4		3

Other, net	—		(1)		2		(2)
Total other income (expense)	(16)		(16)		(46)		(49)

Income before income tax expense (benefit)	60		120		230		293
Income tax expense (benefit)	16		39		59		86
Net income	$	44	$	81	$	171	$	207

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

186

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)


	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Net income	$	44	$	81	$	171	$	207

Other comprehensive income, net of tax:
Unrealized gains on cash flow hedges, net of tax of $1, $1, $1 and $1	—		—		1		1

Total other comprehensive income, net of tax	—		—		1		1
Comprehensive income	$	44	$	81	$	172	$	208

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

187

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, June 30, 2022	60,101	$	609	$	1,254	$	750	$	(30)	$	2,583
Net income	—	—		—		81		—		81

Dividends declared	—	—		—		(92)		—		(92)
Contributions	—	—		11		—		—		11

Balance, September 30, 2022	60,101	$	609	$	1,265	$	739	$	(30)	$	2,583

Balance, December 31, 2021	60,101	$	609	$	1,241	$	721	$	(31)	$	2,540
Net income	—	—		—		207		—		207
Other comprehensive income	—	—		—		—		1		1
Dividends declared	—	—		—		(189)		—		(189)
Contributions	—	—		24		—		—		24
Balance, September 30, 2022	60,101	$	609	$	1,265	$	739	$	(30)	$	2,583

Balance, June 30, 2023	60,101	$	609	$	1,300	$	743	$	(29)	$	2,623
Net income	—	—		—		44		—		44

Dividends declared	—	—		—		(24)		—		(24)


Balance, September 30, 2023	60,101	$	609	$	1,300	$	763	$	(29)	$	2,643

Balance, December 31, 2022	60,101	$	609	$	1,275	$	746	$	(30)	$	2,600
Net income	—	—		—		171		—		171
Other comprehensive income	—	—		—		—		1		1
Dividends declared	—	—		—		(154)		—		(154)
Contributions	—	—		25		—		—		25

Balance, September 30, 2023	60,101	$	609	$	1,300	$	763	$	(29)	$	2,643

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

188

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Nine-Month Periods
	Ended September 30,
	2023		2022
Cash flows from operating activities:
Net income	$	171	207
Adjustments to reconcile net income to net cash flows from operating activities:

(Gains) losses on other items, net	(8)		1
Depreciation and amortization	112		115
Allowance for equity funds	(4)		(3)
Changes in regulatory assets and liabilities	(79)		35
Deferred income taxes	50		58
Other, net	(5)		5
Changes in other operating assets and liabilities:
Trade receivables and other assets	35		34
Receivables from affiliates	5		3
Gas balancing activities	26		(47)

Accrued property, income and other taxes	(21)		(1)
Accounts payable and other liabilities	24		34
Accounts payable to affiliates	11		7
Net cash flows from operating activities	317		448

Cash flows from investing activities:
Capital expenditures	(163)		(179)
Proceeds from assignment of shale development rights	8		—

Repayment of notes by affiliates	—		11
Notes to affiliates	—		(8)
Other, net	(4)		(9)
Net cash flows from investing activities	(159)		(185)

Cash flows from financing activities:



Repayment of notes payable to affiliates, net	(21)		(53)



Dividends paid	(141)		(172)


Net cash flows from financing activities	(162)		(225)



Net change in cash and cash equivalents and restricted cash and cash equivalents	(4)		38
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	$	41	$	64

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

189

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 September 30, 2023 and for the three- and nine-month periods ended September 30, 2023 and 2022. The results of operations for the three- and nine-month periods ended September 30, 2023 are not necessarily indicative of the results to be expected for the full year.

(2) Property, Plant and Equipment, Net

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


		As of
		September 30,		December 31,
	Depreciable Life	2023		2022

Interstate natural gas transmission and storage assets	28 - 50 years	$	6,946	$	6,724
Intangible plant	12 - 19 years	81		79
Plant in-service		7,027		6,803
Accumulated depreciation and amortization		(2,533)		(2,440)
		4,494		4,363










Construction work-in-progress		205		141
Property, plant and equipment, net		$	4,699	$	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.

190

(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
	September 30,		December 31,
	2023		2022
Investments:
Investment funds	$	18	$	14


Restricted cash and cash equivalents:
Customer deposits	29		29
Total restricted cash and cash equivalents	29		29

Total investments and restricted cash and cash equivalents	$	47	$	43

Reflected as:
Current assets	$	29	$	29
Noncurrent assets	18		14
Total investments and restricted cash and cash equivalents	$	47	$	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
	September 30,		December 31,
	2023		2022

Cash and cash equivalents	$	12	$	16
Restricted cash and cash equivalents	29		29
Total cash and cash equivalents and restricted cash and cash equivalents	$	41	$	45

191

(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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022

Federal statutory income tax rate	21	%	21	%	21	%	21	%
State income tax, net of federal income tax benefit	6		11		5		8












Other, net	—		1		—		—
Effective income tax rate	27	%	33	%	26	%	29	%

(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 $5 million and $9 million to the MidAmerican Energy Company Retirement Plan for the nine-month periods ended September 30, 2023 and 2022, respectively, and $1 million and $2 million to the MidAmerican Energy Company Welfare Benefit Plan for the nine-month periods ended September 30, 2023 and 2022, respectively. 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 September 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 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.

192

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 September 30, 2023:
Assets:

Money market mutual funds	$	12	$	—	$	—	$	12
Equity securities:
Investment funds	18		—		—		18
	$	30	$	—	$	—	$	30







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 September 30, 2023				As of December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	1,583	$	1,275	$	1,582	$	1,337

193

(8) Commitments and Contingencies

Environmental 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				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2023		2022		2023		2022
Customer Revenue:
Regulated:
Gas transmission	$	144	$	151	$	486	$	461
Gas storage	69		74		206		190

Other	6		—		6		—
Total regulated	219		225		698		651
Management service and other revenues	14		19		46		56
Total Customer Revenue	233		244		744		707
Other revenue(1)	—		(4)		3		(10)
Total operating revenue	$	233	$	240	$	747	$	697

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 September 30, 2023 (in millions):


	Performance obligations expected to be satisfied
	Less than 12 months		More than 12 months		Total

EGTS	$	764	$	3,171	$	3,935

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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 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 Third Quarter and First Nine Months of 2023 and 2022

Overview

Net income for the third quarter of 2023 was $44 million, a decrease of $37 million, or 46%, compared to 2022. Net income decreased primarily due to lower margin from regulated gas transmission and storage operations of $38 million, an increase in outside services, higher technology and related charges and an increase in salaries, wages and benefits, partially offset by lower income tax expense primarily due to lower pre-tax income.

Net income for the first nine months of 2023 was $171 million, a decrease of $36 million, or 17%, compared to 2022. Net income decreased primarily due to lower margin from regulated gas transmission and storage operations of $30 million, higher technology and related charges and an increase in salaries, wages and benefits, partially offset by lower income tax expense primarily due to lower pre-tax income.

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

Operating revenue decreased $7 million, or 3%, for the third quarter of 2023 compared to 2022, primarily due to 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 $9 million and a decrease in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of $5 million, partially offset by derivative losses in 2022 of $6 million and an increase in regulated gas sales for operational and system balancing purposes primarily due to increased volumes of $5 million.

Cost of (excess) gas was an expense of $6 million for the third quarter of 2023 compared to a credit of $25 million for the third 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 $25 million and an increase in volumes sold of $5 million.

Operations and maintenance increased $19 million, or 24%, for the third quarter of 2023 compared to 2022, primarily due to an increase in outside services of $9 million, higher technology and related charges of $5 million and an increase in salaries, wages and benefits of $3 million.

Depreciation and amortization increased $4 million, or 12%, for the third quarter of 2023 compared to 2022, primarily due to a 2022 amortization true-up as a result of the settlement of depreciation rates in EGTS' general rate case of $2 million and higher plant placed in-service of $2 million.

Income tax expense decreased $23 million, or 59%, for the third quarter of 2023 compared to 2022, primarily due to lower pre-tax income and the effective tax rate was 27% for 2023 and 33% for 2022. The effective tax rate decreased primarily due to the reduction in the state effective rate.

First Nine Months of 2023 Compared to First Nine Months of 2022

Operating revenue increased $50 million, or 7%, for the first nine 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 $45 million, an increase in variable revenue related to park and loan activity of $22 million, derivative losses in 2022 of $13 million and an increase in regulated gas sales for operational and system balancing purposes primarily due to increased volumes of $5 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 $26 million.

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Cost of (excess) gas was an expense of $31 million for the first nine months of 2023 compared to a credit of $49 million for the first nine months of 2022. The change is primarily from a decrease from 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 $39 million, the unfavorable revaluation of the volumes retained prior to the effective date of the new fuel tracker due to lower natural gas prices of $35 million, and an increase in volumes sold of $5 million.

Operations and maintenance increased $43 million, or 17%, for the first nine months of 2023 compared to 2022, primarily due to higher technology and related charges of $15 million, an increase in salaries, wages and benefits of $12 million, an increase in outside services of $9 million and various other immaterial items, 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 $3 million, or 3%, for the first nine months of 2023 compared to 2022, primarily due to the settlement of depreciation rates in EGTS' general rate case of $6 million, partially offset by higher plant placed in-service of $3 million.

Property and other taxes decreased $4 million, or 10%, for the first nine 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 nine months of 2023 compared to expense of $2 million for the first nine months of 2022. The change is primarily from gains on marketable securities of $3 million and income from money market mutual fund investments of $2 million.

Income tax expense decreased $27 million, or 31%, for the first nine months of 2023 compared to 2022, primarily due to lower pre-tax income and the effective tax rate was 26% for 2023 and 29% for 2022. The effective tax rate decreased primarily due to the reduction in the state effective rate.

Liquidity and Capital Resources

As of September 30, 2023, EGTS' total net liquidity was as follows (in millions):


Cash and cash equivalents	$	12

Intercompany revolving credit agreement	400
Less:
Notes payable to affiliates	15

Net intercompany revolving credit agreement	385

Total net liquidity	$	397

Intercompany credit agreement:
Maturity date	2024

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022 were $317 million and $448 million, respectively. The change is primarily due to the repayment of EGTS rate refunds to customers 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.

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Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2023 and 2022 were $(159) million and $(185) million, respectively. The change is primarily due to a decrease in capital expenditures of $16 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 $11 million.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2023 were $(162) million and consisted of dividends paid to Eastern Energy Gas of $141 million and net repayment of notes payable to Eastern Energy Gas of $21 million.

Net cash flows from financing activities for the nine-month period ended September 30, 2022 were $(225) million and consisted of dividends paid to Eastern Energy Gas of $172 million and net repayment of notes payable to Eastern Energy Gas of $53 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

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):


	Nine-Month Periods				Annual
	Ended September 30,				Forecast
	2022		2023		2023

Natural gas transmission and storage	$	30	$	11	$	23
Other	149		152		213
Total	$	179	$	163	$	236

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 September 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.

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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.

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 September 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 September 30, 2023 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

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PART II

Item 1.Legal Proceedings

The following disclosures reflect material updates to legal proceedings and should be read in conjunction with Item 3 of Berkshire Hathaway Energy's and PacifiCorp's Annual Reports on Form 10-K for the year ended December 31, 2022.

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP

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 and in certain demands made in California total nearly $8 billion, excluding any doubling or trebling of damages included in the complaints. Generally, the lawsuits and complaints filed in California do not specify damages sought and are excluded from this amount. 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, 242 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. While in January 2023, the Oregon Court of Appeals denied PacifiCorp's request for immediate appeal of the class certification, PacifiCorp will appeal the class issues as a matter of right when the issues are finally decided by the Multnomah County Circuit Court. 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 Multnomah County 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. In September 2023, the Multnomah County Circuit Court ordered trial dates for two consolidated jury trials including approximately 10 class members each and a third trial for certain commercial timber plaintiffs wherein plaintiffs in each of the three trials will present evidence regarding their damages. The trials are scheduled at various dates from January to April 2024. Hearings on PacifiCorp's post-trial motions are scheduled to be held November 9, 2023. Under ORS 82.010, interest at a rate of 9% per annum will accrue on the judgment commencing at the date the judgment is entered unless otherwise specified in the judgment. No judgment has yet been entered by the Multnomah County Circuit Court. PacifiCorp intends to appeal the jury's findings and damage awards in the James case, 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, 242 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, 242, 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) and a jury trial is scheduled for May 2024.

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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.

203

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 State of Oregon – Loss and Damages to Federal and State Lands

PacifiCorp received a notice of indebtedness from the U.S. Department of Agriculture Forest Service ("USFS") indicating that PacifiCorp owes the U.S. $356 million for fire suppression costs, natural resource damages and burned area emergency response costs incurred by the USFS associated with the September 2020 Slater fire in California. The notice further indicates that the alleged amounts owed may not include all environmental damages to which the USFS may be entitled and which the U.S. may seek to recover if further action is taken to resolve the debt. Additional charges for interest, penalties and administrative costs may also be sought associated with amounts considered overdue.

PacifiCorp 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 $96 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.

BERKSHIRE HATHAWAY ENERGY

HomeServices, a subsidiary of Berkshire Hathaway Energy, is currently defending against four antitrust cases, all in federal district courts. In each case, plaintiffs claim HomeServices and certain subsidiaries conspired with co-defendants to artificially inflate real estate commissions by following and enforcing multiple listing service ("MLS") rules that require listing agents to offer a commission split to cooperating agents in order for the property to appear on the MLS ("Cooperative Compensation Rule"). Three of the four cases are brought on behalf of sellers and one is brought on behalf of buyers. None of the complaints specify damages sought. The cases are captioned as follows.

204

In April 2019, the Burnett (formerly Sitzer) et al. v. HomeServices of America, Inc. et al., Case No. 19CV332, complaint was filed in the U.S. District Court for the Western District of Missouri (the "Burnett case"). This lawsuit, which was certified as a class in April 2022, was originally brought on behalf of named plaintiffs Joshua Sitzer and Amy Winger against the National Association of Realtors ("NAR"), Anywhere Real Estate (formerly Realogy Holdings Corp.), HomeServices of America, Inc., RE/MAX, LLC, and Keller Williams Realty, Inc. HSF Affiliates, LLC and BHH Affiliates, LLC, each a subsidiary of HomeServices, were subsequently added as defendants. Rhonda Burnett became a lead class plaintiff in June 2021. The jury trial commenced on October 16, 2023, and the jury returned a verdict for the plaintiffs on October 31, 2023, finding that the named defendants participated in a conspiracy to follow and enforce the Cooperative Compensation Rule, which had the purpose or effect of raising, inflating, or stabilizing broker commission rates paid by home sellers. The jury further found that the class plaintiffs had proved damages in the amount of $1.8 billion. Federal law authorizes trebling of damages and the award of pre-judgment interest and attorney fees. Joint and several liability applies for the co-defendants. Prior to the trial, Anywhere Real Estate (formerly Realogy Holdings Corp.) and RE/MAX, LLC reached settlement agreements with the plaintiffs, which have not yet been approved by the court. Final judgment has not yet been entered by the U.S. District Court for the Western District of Missouri. HomeServices intends to vigorously appeal on multiple grounds the jury's findings and damage award in the Burnett case, including whether the case can proceed as a class action. The appeals process and further actions could take several years.

On March 6, 2019, the Christopher Moehrl v. National Association of Realtors, et al. & Sawbill Strategic, Inc. v. HomeServices of America, Inc. et al., Case Nos. 19CV01610 and 19CV2544, (together "Moehrl") complaint was filed in the U.S. District Court for the Northern District of Illinois. This certified class action lawsuit was brought on behalf of named plaintiff Christopher Moehrl against the NAR, Anywhere Real Estate (formerly Realogy Holdings Corp.), HomeServices of America, Inc., HSF Affiliates, LLC, BHH Affiliates, LLC, Long & Foster Companies, Inc. (also a HomeServices subsidiary), RE/MAX, LLC and Keller Williams Realty, Inc.

In December 2020, the Nosalek (formerly Bauman) v. HomeServices of America, Inc. et al., Case No. 20CV1244, complaint was filed in the U.S. District Court for the District of Massachusetts. This putative class action lawsuit was originally filed on behalf of named plaintiffs Gary Bauman, Mary Jane Bauman, and Jennifer Nosalek against the MLS Property Information Network, Inc. (MassPIN), Anywhere Real Estate (formerly Realogy Holdings Corp.), HomeServices of America, Inc., BHH Affiliates, LLC, HSF Affiliates, LLC, RE/MAX, LLC, Keller Williams Realty, Inc. and additional named defendants. In October 2021, the Baumans voluntarily dismissed themselves from the case, removing them as class representatives.

In January 2021, the Batton (formerly Leeder) v. HomeServices of America, Inc. et al., Case No. 21CV00430, complaint was filed in the U.S. District Court for the Northern District of Illinois. This putative class action lawsuit was originally brought on behalf of former named plaintiff Judah Leeder against the NAR, HomeServices of America, Inc. HSF Affiliates, LLC, BHH Affiliates, LLC, Long & Foster Companies, Inc., Anywhere Real Estate (formerly Realogy Holdings Corp.), RE/MAX, LLC and Keller Williams Realty, Inc. Mya Batton replaced Leeder as class representative in July 2022.

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.

Item 5.Other Information

205

Not applicable.

Item 6.Exhibits

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

206


Exhibit No.			Description

BERKSHIRE HATHAWAY ENERGY


4.1			T wenty-Fifth Supplemental Indenture, dated as of October 11, 2023, by and between Alta Link, L.P., AltaLink Management Ltd. and BNY Trust Company of Canada, as trustee, relating to the C$500,000,000 in principal amount of the 5.463% Series 2023-1 Senior Secured Notes due 2055.

10.1			F ourth Amending Agreement to the Amended and R estated Credit Agreement, da ted as of September 5, 2023, among AltaLink Investments, L.P., as borr ower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agen t, and Lenders.

10.2			Fifth Amending Agreement to the Amended and Restated Credit Agreement, dated as of September 28 , 2023, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders.

10.3			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 (incorporated by reference to Exhibit 10.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2023).

10.4			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).

10.5			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).

10.6			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


3.1			Bylaws of PacifiCorp, as amende d January 10, 2014.

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.

207


Exhibit No.			Description

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP


4.2			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).

10.7			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 (incorporated by reference to Exhibit 10.5 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2023).
95			Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act.

MIDAMERICAN ENERGY


15.3			Awareness Letter of Independent Registered Public Accounting Firm.

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

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

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

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

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


4.3			Eleventh Supplemental Indenture, dated as of September 7 , 202 3 , by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Company Current Report on Form 8-K dated September 7 , 202 3 ).

4.4			Specimen of the 5.350 % First Mortgage Bonds due 20 34 (incorporated by reference to Exhibit 4.4 to the MidAmerican Energy Company Current Report on Form 8-K dated Se ptember 7 , 202 3 ).

4.5			Specimen of the 5.850 % First Mortgage Bonds due 205 4 (incorporated by reference to Exhibit 4.5 to the MidAmerican Energy Company Current Report on Form 8-K dated September 7 , 202 3 ).

10.8			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 (incorporated by reference to Exhibit 10.6 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2023).

208


Exhibit No.			Description

NEVADA POWER


15.4			Awareness Letter of Independent Registered Public Accounting Firm.

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

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

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

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

BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER


4.6			Officer's Certificate establishing the terms of Nevada Power Company's 6.00 0% General and Refunding Mortgage Notes, Series 2023A , due 205 4 (incorporated by reference to Exhibit 4.1 to the Nevada Power Company Current Report on Form 8-K dated September 14 , 202 3 ).

10.9			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 (incorporated by reference to Exhibit 10.7 to the Nevada Power Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2023).

SIERRA PACIFIC


3.2			R e stated Articles of Incorporation of Sierra Pacific Power Compan y, dated January 23, 2019 .

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

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

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

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

BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC


4.7			Officer's Certificate establishing the terms of Sierra Pacific Power Company's 5.900 % General and Refunding Mortgage Bonds, Series 2023A , due 205 4 (incorporated by reference to Exhibit 4.1 to the Sierra Pacific Power Company Current Report on Form 8-K dated September 18 , 202 3 ).

10.10			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 (incorporated by reference to Exhibit 10.8 to the Sierra Pacific Power Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2023).

209


Exhibit No.			Description

EASTERN ENERGY GAS


10.11			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.

BERKSHIRE HATHAWAY ENERGY AND EASTERN ENERGY GAS


2.1			Purchase and Sale Agreement, dated as of July 9, 2023, by and between Dominion Energy, Inc., DECP Holdings Inc., Eastern MLP H olding Company II, LLC and Berkshire Hathaway Energ y Company (inc orporated by reference to Exhibit 2.1 to the Berkshire Hathaway Energy Company and Eastern Ener gy Gas Holdings, LLC Current Report on Form 8-K dated Sep tem ber 1, 2023).

EASTERN GAS TRANSMISSION AND STORAGE


10.12			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).

10.13			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


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

210

SIGNATURES

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


			BERKSHIRE HATHAWAY ENERGY COMPANY

Date: November 3, 2023			/s/ Calvin D. Haack
			Calvin D. Haack
			Senior Vice President and Chief Financial Officer
			(principal financial and accounting officer)

			PACIFICORP

Date: November 3, 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: November 3, 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: November 3, 2023			/s/ Michael J. Behrens
			Michael J. Behrens
			Vice President and Chief Financial Officer
			(principal financial and accounting officer)

			SIERRA PACIFIC POWER COMPANY

Date: November 3, 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: November 3, 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: November 3, 2023			/s/ Scott C. Miller
			Scott C. Miller
			Vice President, Chief Financial Officer and Treasurer
			(principal financial and accounting officer)

211