PacifiCorp (PPWLM) 10-Q 2024 Q3 Quarterly report

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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, 2024

or

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

For the transition period from ______ to _______

	Exact name of registrant as specified in its charter
	State or other jurisdiction of incorporation or organization
Commission	Address of principal executive offices	IRS Employer
File Number	Registrant's telephone number, including area code	Identification No.
001-14881	BERKSHIRE HATHAWAY ENERGY COMPANY	94-2213782
	(An Iowa Corporation)
	1615 Locust Street
	Des Moines, Iowa 50309-3037
	515-242-4300
001-05152	PACIFICORP	93-0246090
	(An Oregon Corporation)
	825 N.E. Multnomah Street
	Portland, Oregon 97232
	888-221-7070
333-90553	MIDAMERICAN FUNDING, LLC	47-0819200
	(An Iowa Limited Liability Company)
	1615 Locust Street
	Des Moines, Iowa 50309-3037
	515-242-4300
333-15387	MIDAMERICAN ENERGY COMPANY	42-1425214
	(An Iowa Corporation)
	1615 Locust Street
	Des Moines, Iowa 50309-3037
	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, former address and former fiscal year, if changed since 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 owned by its parent company, Berkshire Hathaway Inc. As of October 31, 2024, 71,203,419 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 October 31, 2024, 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 October 31, 2024.

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 October 31, 2024, 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 October 31, 2024, 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 October 31, 2024, 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 October 31, 2024.

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 October 31, 2024, 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	211
Item 4.	Controls and Procedures	211

PART II

Item 1.	Legal Proceedings	212
Item 1A.	Risk Factors	224
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	224
Item 3.	Defaults Upon Senior Securities	224
Item 4.	Mine Safety Disclosures	224
Item 5.	Other Information	224
Item 6.	Exhibits	224
Signatures		229

i

Definition of Abbreviations and Industry Terms

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

Berkshire Hathaway Energy Company and Related Entities
BHE	Berkshire Hathaway Energy Company
Berkshire Hathaway	Berkshire Hathaway Inc.
Berkshire Hathaway Energy or the Company	Berkshire Hathaway Energy Company and its subsidiaries
PacifiCorp	PacifiCorp and its subsidiaries
MidAmerican Funding	MidAmerican Funding, LLC and its subsidiaries
MidAmerican Energy	MidAmerican Energy Company
NV Energy	NV Energy, Inc. and its subsidiaries
Nevada Power	Nevada Power Company and its subsidiaries
Sierra Pacific	Sierra Pacific Power Company and its subsidiaries
Nevada Utilities	Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
Eastern Energy Gas	Eastern Energy Gas Holdings, LLC and its subsidiaries
EGTS	Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Registrants	Berkshire Hathaway Energy Company, PacifiCorp and its subsidiaries, MidAmerican Funding, LLC and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries, Eastern Energy Gas Holdings, LLC and its subsidiaries and Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Northern Powergrid	Northern Powergrid Holdings Company and its subsidiaries
BHE Pipeline Group	BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
BHE GT&S	BHE GT&S, LLC and its subsidiaries
Northern Natural Gas	Northern Natural Gas Company
Kern River	Kern River Gas Transmission Company
BHE Transmission	BHE Canada Holdings Corporation and BHE U.S. Transmission, LLC
BHE Canada	BHE Canada Holdings Corporation and its subsidiaries
AltaLink	AltaLink, L.P.
BHE U.S. Transmission	BHE U.S. Transmission, LLC and its subsidiaries
BHE Renewables	BHE Renewables, LLC and its subsidiaries
HomeServices	HomeServices of America, Inc. and its subsidiaries
Utilities	PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
Cove Point	Cove Point LNG, LP
Iroquois	Iroquois Gas Transmission System, L.P.
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.

ii

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
Wildfires	2020 Wildfires and 2022 McKinney Fire
AFUDC	Allowance for Funds Used During Construction
AUC	Alberta Utilities Commission
BART	Best Available Retrofit Technology
CCR	Coal Combustion Residuals
CPUC	California Public Utilities Commission
CSAPR	Cross-State Air Pollution Rule
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
Dth	Decatherm
ECAC	Energy Cost Adjustment Clause
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
GHG	Greenhouse Gases
GTA	General Tariff Application
GWh	Gigawatt Hour
IPUC	Idaho Public Utilities Commission
IRP	Integrated Resource Plan
IUC	Iowa Utilities Commission
kV	Kilovolt
LNG	Liquefied Natural Gas
MATS	Mercury and Air Toxics Standards
MISO	Midcontinent Independent System Operator, Inc.
MW	Megawatt
MWh	Megawatt Hour
NAAQS	National Ambient Air Quality Standards
NOx	Nitrogen Oxides
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
WPSC	Wyoming Public Service Commission
WUTC	Washington Utilities and Transportation Commission

iii

Forward-Looking Statements

This report contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon the relevant Registrant's current intentions, estimates, 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, whether directed towards protection of environmental resources, present and future climate considerations or social justice concerns 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, 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, demands or similar actions initiated against the respective Registrant; the risk that the respective Registrant is not able to recover losses 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 or other actions and the effects of amounts to be paid to complainants as a result of settlements or final legal determinations associated with the Wildfires, which could have a material adverse effect on PacifiCorp's financial condition and could limit PacifiCorp's ability to access capital on terms commensurate with historical transactions or at all and could impact PacifiCorp's liquidity, cash flows and capital expenditure plans;

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

•the ability to economically obtain insurance coverage, or any insurance coverage at all, sufficient to cover losses arising from catastrophic events, such as wildfires;

•a high degree of variance between actual and forecasted load or generation that could impact a Registrant's hedging strategy and the cost of balancing its generation resources with its retail load obligations;

•changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs;

iv

•the financial condition, creditworthiness and operational stability of the respective Registrant's significant customers and suppliers;

•changes in business strategy or development plans;

•availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in interest rates and credit spreads;

•changes in the respective Registrant's credit ratings, changes in rating methodology and placement on negative outlook or credit watch;

•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, regulations that could affect brokerage, mortgage and franchising transactions and the outcomes of legal or other actions and the effects of amounts to be paid to complainants as a result of settlements or final legal determinations;

•the ability to successfully integrate future acquired operations into a Registrant's business;

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

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

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

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

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

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

v

Item 1.Financial Statements

Berkshire Hathaway Energy Company and its subsidiaries
Report of Independent Registered Public Accounting Firm	4
Consolidated Balance Sheets	5
Consolidated Statements of Operations	7
Consolidated Statements of Comprehensive Income	8
Consolidated Statements of Changes in Equity	9
Consolidated Statements of Cash Flows	10
Notes to Consolidated Financial Statements	11
PacifiCorp and its subsidiaries
Report of Independent Registered Public Accounting Firm	61
Consolidated Balance Sheets	62
Consolidated Statements of Operations	64
Consolidated Statements of Changes in Shareholders' Equity	65
Consolidated Statements of Cash Flows	66
Notes to Consolidated Financial Statements	67
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm	92
Balance Sheets	93
Statements of Operations	95
Statements of Changes in Shareholder's Equity	96
Statements of Cash Flows	97
Notes to Financial Statements	98
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm	107
Consolidated Balance Sheets	108
Consolidated Statements of Operations	110
Consolidated Statements of Changes in Member's Equity	111
Consolidated Statements of Cash Flows	112
Notes to Consolidated Financial Statements	113
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm	127
Consolidated Balance Sheets	128
Consolidated Statements of Operations	129
Consolidated Statements of Changes in Shareholder's Equity	130
Consolidated Statements of Cash Flows	131
Notes to Consolidated Financial Statements	132
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm	150
Consolidated Balance Sheets	151
Consolidated Statements of Operations	152
Consolidated Statements of Changes in Shareholder's Equity	153
Consolidated Statements of Cash Flows	154
Notes to Consolidated Financial Statements	155
Eastern Energy Gas Holdings, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm	174
Consolidated Balance Sheets	175
Consolidated Statements of Operations	177
Consolidated Statements of Comprehensive Income	178
Consolidated Statements of Changes in Equity	179
Consolidated Statements of Cash Flows	180
Notes to Consolidated Financial Statements	181
Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Report of Independent Registered Public Accounting Firm	195
Consolidated Balance Sheets	196
Consolidated Statements of Operations	198
Consolidated Statements of Comprehensive Income	199
Consolidated Statements of Changes in Shareholder's Equity	200
Consolidated Statements of Cash Flows	201
Notes to Consolidated Financial Statements	202

1

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

Berkshire Hathaway Energy Company and its subsidiaries	33
PacifiCorp and its subsidiaries	81
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company	117
Nevada Power Company and its subsidiaries	141
Sierra Pacific Power Company and its subsidiaries	165
Eastern Energy Gas Holdings, LLC and its subsidiaries	190
Eastern Gas Transmission and Storage, Inc. and its subsidiaries	208

2

Berkshire Hathaway Energy Company and its subsidiaries

Consolidated Financial Section

3

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Berkshire Hathaway Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of September 30, 2024, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and nine-month periods ended September 30, 2024 and 2023, and of cash flows for the nine-month periods ended September 30, 2024 and 2023, 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, 2023, 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 23, 2024, 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, 2023, 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 1, 2024

4

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,		December 31,
	2024		2023
ASSETS
Current assets:
Cash and cash equivalents	$	2,594	$	1,565
Investments and restricted cash and cash equivalents	336		1,253
Trade receivables, net	2,772		2,667
Inventories	1,892		1,509
Mortgage loans held for sale	559		451
Regulatory assets	1,218		1,398
Other current assets	1,496		1,355
Total current assets	10,867		10,198
Property, plant and equipment, net	102,845		99,248
Goodwill	11,545		11,547
Regulatory assets	4,234		4,167
Investments and restricted cash and cash equivalents and investments	7,879		9,510
Other assets	3,126		3,170
Total assets	$	140,496	$	137,840

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

5

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	September 30,		December 31,
	2024		2023
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	2,858	$	3,175
Accrued interest	758		625
Accrued property, income and other taxes	1,033		828
Accrued employee expenses	497		354
Short-term debt	773		4,148
Current portion of long-term debt	4,183		2,740
Other current liabilities	2,408		1,551
Total current liabilities	12,510		13,421
BHE senior debt	11,456		13,101
BHE junior subordinated debentures	—		100
Subsidiary debt	40,918		36,231
Regulatory liabilities	6,701		6,644
Deferred income taxes	12,383		12,437
Other long-term liabilities	5,927		6,166
Total liabilities	89,895		88,100
Commitments and contingencies (Note 11)
Equity:
BHE shareholders' equity:
Common stock - 115 shares authorized, no par value, 71 and 76 shares issued and outstanding	—		—
Additional paid-in capital	5,418		5,573
Retained earnings	45,626		44,765
Accumulated other comprehensive loss, net	(1,725)		(1,904)
Total BHE shareholders' equity	49,319		48,434
Noncontrolling interests	1,282		1,306
Total equity	50,601		49,740
Total liabilities and equity	$	140,496	$	137,840

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

6

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2024		2023		2024		2023
Operating revenue:
Energy	$	6,026	$	5,958	$	16,386	$	16,362
Real estate	1,179		1,212		3,334		3,383
Total operating revenue	7,205		7,170		19,720		19,745
Operating expenses:
Energy:
Cost of sales	1,902		2,009		5,099		5,530
Operations and maintenance	1,343		1,184		3,888		3,518
Wildfire losses, net of recoveries (Note 11)	—		1,263		251		1,671
Depreciation and amortization	1,020		1,015		3,040		3,035
Property and other taxes	205		204		631		613
Real estate	1,151		1,181		3,477		3,351
Total operating expenses	5,621		6,856		16,386		17,718
Operating income	1,584		314		3,334		2,027
Other income (expense):
Interest expense	(679)		(603)		(2,045)		(1,788)
Capitalized interest	49		36		145		93
Allowance for equity funds	97		76		272		186
Interest and dividend income	112		110		362		323
Gains (losses) on marketable securities, net	268		(76)		474		926
Other, net	34		(3)		90		115
Total other income (expense)	(119)		(460)		(702)		(145)
Income (loss) before income tax expense (benefit) and equity income (loss)	1,465		(146)		2,632		1,882
Income tax expense (benefit)	(614)		(777)		(1,293)		(1,194)
Equity income (loss)	(73)		(60)		(237)		(197)
Net income	2,006		571		3,688		2,879
Net income attributable to noncontrolling interests	31		77		106		321
Net income attributable to BHE shareholders	1,975		494		3,582		2,558
Preferred dividends	—		8		—		25
Earnings on common shares	$	1,975	$	486	$	3,582	$	2,533

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

7

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2024		2023		2024		2023
Net income	$	2,006	$	571	$	3,688	$	2,879
Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $(7), $10, $(2) and $3	(18)		21		(3)		10
Foreign currency translation adjustment	348		(313)		178		18
Unrealized (losses) gains on cash flow hedges, net of tax of $(7), $(3), $1 and $(10)	(22)		(7)		4		(23)
Total other comprehensive income (loss), net of tax	308		(299)		179		5
Comprehensive income	2,314		272		3,867		2,884
Comprehensive income attributable to noncontrolling interests	31		77		106		321
Comprehensive income attributable to BHE shareholders	$	2,283	$	195	$	3,761	$	2,563

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

8

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)

	BHE Shareholders' Equity
									Accumulated
					Additional				Other
	Preferred		Common		Paid-in		Retained		Comprehensive		Noncontrolling		Total
	Stock		Stock		Capital		Earnings		Loss, Net		Interests		Equity
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
Balance, June 30, 2024	$	—	$	—	$	5,573	$	46,371	$	(2,033)	$	1,295	$	51,206
Net income	—		—		—		1,975		—		31		2,006
Other comprehensive income	—		—		—		—		308		—		308
Common stock repurchases	—		—		(155)		(2,721)		—		—		(2,876)
Distributions	—		—		—		—		—		(43)		(43)
Other equity transactions	—		—		—		1		—		(1)		—
Balance, September 30, 2024	$	—	$	—	$	5,418	$	45,626	$	(1,725)	$	1,282	$	50,601
Balance, December 31, 2023	$	—	$	—	$	5,573	$	44,765	$	(1,904)	$	1,306	$	49,740
Net income	—		—		—		3,582		—		106		3,688
Other comprehensive income	—		—		—		—		179		—		179
Common stock repurchases	—		—		(155)		(2,721)		—		—		(2,876)
Distributions	—		—		—		—		—		(127)		(127)
Other equity transactions	—		—		—		—		—		(3)		(3)
Balance, September 30, 2024	$	—	$	—	$	5,418	$	45,626	$	(1,725)	$	1,282	$	50,601

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

9

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2024		2023
Cash flows from operating activities:
Net income	$	3,688	$	2,879
Adjustments to reconcile net income to net cash flows from operating activities:
Gains on marketable securities, net	(474)		(926)
Depreciation and amortization	3,075		3,072
Allowance for equity funds	(272)		(186)
Equity (income) loss, net of distributions	334		274
Net power cost deferrals	(62)		(722)
Amortization of net power cost deferrals	389		303
Other changes in regulatory assets and liabilities	(82)		(222)
Deferred income taxes and investment tax credits, net	(181)		(172)
Other, net	(46)		(62)
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(771)		(224)
Derivative collateral, net	(23)		(201)
Pension and other postretirement benefit plans	(12)		(10)
Accrued property, income and other taxes, net	141		(52)
Accounts payable and other liabilities	400		512
Wildfires insurance receivable	365		(257)
Wildfires liability	(278)		1,854
Net cash flows from operating activities	6,191		5,860
Cash flows from investing activities:
Capital expenditures	(6,236)		(6,526)
Purchases of marketable securities	(258)		(226)
Proceeds from sales of marketable securities	1,841		2,138
Purchases of U.S. Treasury Bills	(1,651)		(3,294)
Proceeds from sales of U.S. Treasury Bills	1,975		1,651
Proceeds from maturities of U.S. Treasury Bills	723		3,034
Equity method investments	(14)		(12)
Other, net	20		13
Net cash flows from investing activities	(3,600)		(3,222)
Cash flows from financing activities:
Preferred dividends	—		(17)
Common stock repurchases	(2,276)		—
Repayments of BHE senior debt	—		(400)
Repayments of BHE junior subordinated debentures	(91)		—
Proceeds from subsidiary debt	5,317		3,413
Repayments of subsidiary debt	(921)		(1,868)
Net (repayments of) proceeds from short-term debt	(3,380)		498
Purchase of Cove Point noncontrolling interest	—		(3,300)
Distributions to noncontrolling interests	(129)		(357)
Other, net	(30)		(43)
Net cash flows from financing activities	(1,510)		(2,074)
Effect of exchange rate changes	2		2
Net change in cash and cash equivalents and restricted cash and cash equivalents	1,083		566
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	1,811		1,817
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	2,894	$	2,383

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

10

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    General

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

The Company's operations are organized as eight business segments: PacifiCorp and its subsidiaries ("PacifiCorp"), MidAmerican Funding, LLC and its subsidiaries ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. and its subsidiaries ("NV Energy") (which primarily consists of Nevada Power Company and its subsidiaries ("Nevada Power") and Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific")), Northern Powergrid Holdings Company and its subsidiaries ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group, LLC and its subsidiaries (which primarily consists of BHE GT&S, LLC and its subsidiaries ("BHE GT&S"), Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation and its subsidiaries ("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, LLC and its subsidiaries), BHE Renewables, LLC and its subsidiaries ("BHE Renewables") and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through these locally managed and operated businesses, owns four utility companies in the U.S. serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies in the U.S., one of which owns a liquefied natural gas ("LNG") export, import and storage facility, 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, 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, 2024, and for the three- and nine-month periods ended September 30, 2024 and 2023. The results of operations for the three- and nine-month periods ended September 30, 2024, 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, 2023, 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, 2024, 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"). Refer to Note 11 for further discussion of the 2020 Wildfires and the 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"), collectively referred to as the "Wildfires."

11

(2)    New Accounting Pronouncements

In November 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items, as well as incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods 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.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. 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.

In March 2024, the United States Securities and Exchange Commission adopted final rules requiring disclosure of certain climate-related information in registrations statements and Form 10-Ks. The final rules require a registrant to disclose, among other things: material climate-related risks; activities to mitigate or adapt to such risks; information about the registrant's board of directors' oversight of climate-related risks and management's role in managing material climate-related risks; and information on any climate-related targets or goals that are material to the registrant's business, results of operations, or financial condition. Further, to facilitate investors' assessment of certain climate-related risks, the final rules require disclosure of Scope 1 and/or Scope 2 greenhouse gas emissions when those emissions are material and disclosure of the financial statement effects of severe weather events and other natural conditions. The final rules include phased-in compliance periods for all registrants, with the compliance date dependent on the registrant's filer status and the content of the disclosure. On April 4, 2024, the United States Securities and Exchange Commission voluntarily stayed implementation of the final rules, pending the completion of judicial review of consolidated challenges by the Court of Appeals for the Eighth Circuit. The Company is currently evaluating the impact of adopting the final rules 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, 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 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.

12

(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	2024		2023
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	99,774	$	96,195
Interstate natural gas pipeline assets	3-80 years	19,750		19,226
		119,524		115,421
Accumulated depreciation and amortization		(38,595)		(36,365)
Regulated assets, net		80,929		79,056
Nonregulated assets:
Independent power plants	2-50 years	8,627		8,484
Cove Point LNG facility	40 years	3,441		3,423
Other assets	2-30 years	3,127		2,874
		15,195		14,781
Accumulated depreciation and amortization		(4,206)		(3,856)
Nonregulated assets, net		10,989		10,925
		91,918		89,981
Construction work-in-progress		10,927		9,267
Property, plant and equipment, net		$	102,845	$	99,248

Construction work-in-progress includes $10.2 billion as of September 30, 2024 and $8.6 billion as of December 31, 2023, related to the construction of regulated assets.

13

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

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

	As of
	September 30,		December 31,
	2024		2023
Investments:
BYD Company Limited common stock	$	825	$	2,218
U.S. Treasury Bills	—		996
Rabbi trusts	522		487
Other	347		338
Total investments	1,694		4,039
Equity method investments:
BHE Renewables tax equity investments	3,637		4,058
Electric Transmission Texas, LLC	739		673
Iroquois Gas Transmission System, L.P.	580		599
Other	397		381
Total equity method investments	5,353		5,711
Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds	868		767
Other restricted cash and cash equivalents	300		246
Total restricted cash and cash equivalents and investments	1,168		1,013
Total investments and restricted cash and cash equivalents and investments	$	8,215	$	10,763
Reflected as:
Other current assets	$	336	$	1,253
Noncurrent assets	7,879		9,510
Total investments and restricted cash and cash equivalents and investments	$	8,215	$	10,763

Investments

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

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2024		2023		2024		2023
Unrealized gains (losses) recognized on marketable securities held at the reporting date	$	166	$	(97)	$	234	$	573
Net gains recognized on marketable securities sold during the period	102		21		240		353
Gains (losses) on marketable securities, net	$	268	$	(76)	$	474	$	926

14

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds restricted for debt service obligations for certain of the Company's nonregulated renewable energy projects. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):

	As of
	September 30,		December 31,
	2024		2023
Cash and cash equivalents	$	2,594	$	1,565
Investments and restricted cash and cash equivalents	282		224
Investments and restricted cash and cash equivalents and investments	18		22
Total cash and cash equivalents and restricted cash and cash equivalents	$	2,894	$	1,811

(6)    Recent Financing Transactions

Long-Term Debt

In October 2024, Eastern Energy Gas issued $900 million of its 5.65% Senior Notes due 2054. Eastern Energy Gas intends to use the net proceeds from the sale of the notes to repay its $600 million Senior Notes due November 15, 2024 and $339 million Senior Notes due December 15, 2024.

In May 2024, AltaLink, L.P. issued C$325 million of its 4.742% Senior Secured Notes, Series 2024-1 due May 2054. AltaLink, L.P. used the net proceeds from the sale of the notes to repay its C$350 million term note due June 6, 2024.

In February 2024, Sierra Pacific entered into a re-offering of the following series of fixed-rate tax exempt bonds: $75 million of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $60 million of Washoe County, Nevada Gas and Water Facilities Refunding Revenue Bonds, Series 2016B, due 2036; $30 million of Humboldt County, Nevada Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029; $30 million of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $20 million of Humboldt County, Nevada Pollution Control Refunding Revenue Bonds, Series 2016A due 2029; and $20 million of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036. The Humboldt County Series 2016A and Series 2016B bonds were offered at a term rate of 3.550%. The Washoe County Series 2016B and Series 2016G bonds were offered at a fixed rate of 3.625% and the Washoe County Series 2016C and Series 2016F bonds were offered at a fixed rate of 4.125%. Sierra Pacific previously purchased the bonds as required by the bond indentures. Sierra Pacific used the net proceeds of the re-offering for general corporate purposes.

In January 2024, PacifiCorp issued $500 million of its 5.10% First Mortgage Bonds due February 2029, $700 million of its 5.30% First Mortgage Bonds due February 2031, $1.1 billion of its 5.45% First Mortgage Bonds due February 2034 and $1.5 billion of its 5.80% First Mortgage Bonds due January 2055, for a total of $3.8 billion. PacifiCorp initially used a portion of the net proceeds to repay outstanding short-term debt and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.

In January 2024, MidAmerican Energy issued $600 million of its 5.30% First Mortgage Bonds due February 2055. MidAmerican Energy intends, within 24 months of the issuance date, to allocate an amount equal to the net proceeds to finance, 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 January 2024, Northern Natural Gas issued $500 million of its 5.625% Senior Bonds due February 2054. Northern Natural Gas intends to use the net proceeds from the sale of the bonds for general corporate purposes, including to fund capital expenditures.

15

Credit Facilities

In June 2024, BHE amended its existing $3.5 billion unsecured credit facility expiring in June 2026. The amendment extended the expiration date to June 2027, updated lenders and amended certain provisions of the existing credit agreement.

In June 2024, PacifiCorp amended its existing $2.0 billion unsecured credit facility expiring in June 2026. The amendment extended the expiration date to June 2027, updated lenders and amended certain provisions of the existing credit agreement.

In June 2024, PacifiCorp terminated its existing $900 million unsecured delayed draw term loan facility expiring in June 2025 and entered into a new $900 million 364-day unsecured credit facility expiring in June 2025. This new credit facility, similar to its existing $2.0 billion unsecured credit facility, provides for loans at a variable interest rate based on the Secured Overnight Financing Rate or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities.

In June 2024, MidAmerican Energy amended its existing $1.5 billion unsecured credit facility expiring in June 2026. The amendment extended the expiration date to June 2027, updated lenders and amended certain provisions of the existing credit agreement.

In June 2024, Nevada Power and Sierra Pacific each amended its existing $600 million and $400 million secured credit facilities expiring in June 2026. The amendments extended the expiration date to June 2027, updated lenders and amended certain provisions of the existing credit agreements.

In March 2024, AltaLink Investments, L.P. amended and restated its existing C$300 million unsecured revolving credit facility expiring December 2026. The restatement incorporated prior amendments as well as updated terms and definitions.

In March 2024, HomeServices amended its existing $700 million unsecured credit facility expiring September 2026. The amendment reduced the commitment of the lenders to $200 million and changed the credit facility from unsecured to secured.

(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.

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,
	2024		2023		2024		2023
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Income tax credits	(55)		382		(60)		(67)
State income tax, net of federal income tax impacts	—		44		(1)		(5)
Income tax effect of foreign income	(1)		9		(2)		1
Effects of ratemaking	(5)		56		(5)		(8)
Equity earnings	(1)		9		(2)		(2)
Noncontrolling interest	—		11		(1)		(4)
Other	(1)		—		1		1
Effective income tax rate	(42)	%	532	%	(49)	%	(63)	%

16

Income tax credits relate primarily to production tax credits ("PTCs") from wind- and solar-powered generating facilities owned by MidAmerican Energy, PacifiCorp, NV Energy 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, 2024 and 2023 totaled $1,571 million and $1,258 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, 2024 and 2023 totaling $1,299 million and $1,000 million, respectively.

(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,
	2024		2023		2024		2023
Pension:
Service cost	$	3	$	3	$	11	$	12
Interest cost	25		27		78		82
Expected return on plan assets	(30)		(30)		(94)		(92)
Settlement	—		—		—		(5)
Net amortization	3		4		7		11
Net periodic benefit cost	$	1	$	4	$	2	$	8
Other postretirement:
Service cost	$	3	$	3	$	5	$	6
Interest cost	7		8		22		22
Expected return on plan assets	(10)		(7)		(27)		(25)
Net amortization	—		(1)		(1)		(2)
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 $5 million, respectively, during 2024. As of September 30, 2024, $9 million and $5 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

17

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,
	2024		2023		2024		2023
Service cost	$	1	$	2	$	4	$	5
Interest cost	13		14		40		42
Expected return on plan assets	(20)		(20)		(59)		(60)
Net amortization	8		7		22		20
Net periodic benefit cost	$	2	$	3	$	7	$	7

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 £9 million during 2024. As of September 30, 2024, £7 million, or $8 million, of contributions had been made to the United Kingdom pension plan.

(9)    Asset Retirement Obligations

In May 2024, the United States Environmental Protection Agency ("EPA") published its final rule on legacy coal combustion residuals ("CCR") surface impoundments and CCR management units ("CCRMUs") in the Federal Register. CCRMUs include CCR surface impoundments and landfills closed before October 19, 2015 and inactive CCR landfills. The final rule contains three main components: (1) a definition for legacy CCR surface impoundments, which are inactive surface impoundments at inactive generating facilities that must adhere to the same regulations as inactive CCR impoundments at active generating facilities, barring location restrictions and liner design criteria, with customized compliance deadlines; (2) groundwater monitoring, corrective action, closure, and post closure care requirements for CCRMUs, which may be located at active generating facilities and inactive generating facilities with a legacy CCR surface impoundment; and (3) the owners and operators of inactive generating facilities must identify the presence of legacy CCR surface impoundments and comply with all rule requirements for surface impoundments; and the owners and operators of active generating facilities and inactive generating facilities with a legacy CCR surface impoundment must prepare Facility Evaluation Reports ("FERs") that identify and describe the CCRMUs and determine whether closure is required. In a manner consistent with existing CCR rules, owners and operators must publish FERs on their CCR websites in two parts, within 15 months (Part 1) and 27 months (Part 2) of the final rule's effective date in November 2024. The Company is currently evaluating the final rule and does not anticipate identifying any legacy surface impoundments, but does anticipate identifying CCRMUs subject to the rule. Due to the number of site investigations warranted by this rule and the nature of engineering and other studies required at each site, the Company is unable to reasonably estimate the potential impact, which may be material, to its asset retirement obligations.

(10)    Fair Value Measurements

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

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

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

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

18

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

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of September 30, 2024:
Assets:
Commodity derivatives	$	—	$	100	$	6	$	(16)	$	90
Interest rate derivatives	34		31		11		—		76
Mortgage loans held for sale	—		559		—		—		559
Money market mutual funds	2,226		—		—		—		2,226
Debt securities:
U.S. government obligations	263		—		—		—		263
Corporate obligations	—		106		—		—		106
Municipal obligations	—		2		—		—		2
Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:
U.S. companies	484		—		—		—		484
International companies	835		—		—		—		835
Investment funds	310		—		—		—		310
	$	4,152	$	799	$	17	$	(16)	$	4,952
Liabilities:
Commodity derivatives	$	(2)	$	(121)	$	(84)	$	39	$	(168)
Foreign currency exchange rate derivatives	—		(5)		—		—		(5)
Interest rate derivatives	—		(3)		(1)		3		(1)
	$	(2)	$	(129)	$	(85)	$	42	$	(174)

19

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2023:
Assets:
Commodity derivatives	$	1	$	121	$	4	$	(31)	$	95
Interest rate derivatives	38		40		7		—		85
Mortgage loans held for sale	—		451		—		—		451
Money market mutual funds	1,310		—		—		—		1,310
Debt securities:
U.S. government obligations	1,253		—		—		—		1,253
Corporate obligations	—		70		—		—		70
Municipal obligations	—		3		—		—		3
Equity securities:
U.S. companies	427		—		—		—		427
International companies	2,226		—		—		—		2,226
Investment funds	268		—		—		—		268
	$	5,523	$	685	$	11	$	(31)	$	6,188
Liabilities:
Commodity derivatives	$	(7)	$	(134)	$	(95)	$	54	$	(182)
Foreign currency exchange rate derivatives	—		(8)		—		—		(8)
Interest rate derivatives	—		(7)		—		4		(3)
	$	(7)	$	(149)	$	(95)	$	58	$	(193)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $26 million and $27 million as of September 30, 2024 and December 31, 2023, respectively.

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of the underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.

The Company's mortgage loans held for sale are valued based on independent quoted market prices, where available, or the prices of other mortgage whole loans with similar characteristics. As necessary, these prices are adjusted for typical securitization activities, including servicing value, portfolio composition, market conditions and liquidity.

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.

20

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
2024:
Beginning balance	$	(133)	$	11	$	(91)	$	7
Changes included in earnings(1)	—		(1)		(5)		3
Changes in fair value recognized in net regulatory assets	(50)		—		(130)		—
Settlements	105		—		148		—
Ending balance	$	(78)	$	10	$	(78)	$	10

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

(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, 2024				As of December 31, 2023
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	56,557	$	53,965	$	52,172	$	48,624

(11)    Commitments and Contingencies

Commitments

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

Fuel Contracts

During the nine-month period ended September 30, 2024, PacifiCorp entered into certain coal supply and transportation agreements totaling $1.9 billion through 2031.

During the nine-month period ended September 30, 2024, MidAmerican Energy entered into firm construction commitments totaling $346 million for the remainder of 2024 through 2026 related to the construction and repowering of wind-powered generating facilities in Iowa.

21

During the nine-month period ended September 30, 2024, the Nevada Utilities entered into engineering, procurement and construction agreements along with equipment and materials agreements totaling $2.1 billion through 2028 for the Greenlink Nevada transmission expansion program that will be developed in western and northern Nevada.

During the nine-month period ended September 30, 2024, Sierra Pacific entered into engineering, procurement and construction agreements along with equipment and materials agreements totaling $986 million for a 400-MW solar photovoltaic facility with an additional 400-MW of co-located battery storage that will be developed in Churchill County, Nevada.

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 owned the Lower Klamath Project, PacifiCorp continued to operate the facilities under an operation and maintenance agreement with the KRRC until each facility was ready for removal. PacifiCorp's obligations under the operations and maintenance agreement terminated in January 2024. Removal of the Copco No. 2 facility was completed in November 2023, and removal of the remaining three dams (J.C. Boyle, Copco No. 1 and Iron Gate) was completed in October 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 supplemental fund and equally share any additional costs above that amount to ensure dam removal and restoration is complete. In May 2024, the KRRC communicated to PacifiCorp and the States that it expects to require the $45 million of supplemental funds.

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 ASC 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.

Wildfires

As of the date of this filing, a significant number of complaints and demands alleging similar claims related to the Wildfires have been filed in Oregon and California, including a class action complaint in Oregon associated with 2020 Wildfires for which certain jury verdicts were issued 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 complaints. Additionally, the U.S. and Oregon Departments of Justice have informed PacifiCorp that they are contemplating filing actions against PacifiCorp in connection with certain of the Oregon 2020 Wildfires. PacifiCorp is actively cooperating with the U.S. and Oregon Departments of Justice on resolving these alleged claims through alternative dispute resolution.

22

As of September 30, 2024, amounts sought in outstanding complaints and demands filed in Oregon and in certain demands made in California totaled approximately $3 billion, excluding any doubling or trebling of damages included in the complaints and the mass complaints described below that seek $46 billion. Generally, the complaints filed in California do not specify damages sought and are excluded from this amount. For class actions, amounts specified by the plaintiffs in the complaints include amounts based on estimates of the potential class size, which ultimately may be significantly greater than estimated. Additionally, damages are not limited to the amounts specified in the initially filed complaints as plaintiffs are frequently allowed to amend their complaints to add additional damages and amounts awarded in a court proceeding may be significantly greater than the damages specified. Oregon law provides for doubling of economic and property damages in the event the defendant is found to have acted with gross negligence, recklessness, willfulness or malice. Oregon law provides for trebling of the damages associated with timber, shrubs and produce in the event the defendant is determined to have willfully and intentionally trespassed.

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.

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

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.

The James Case

On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp, ("James") in Oregon Circuit Court in Multnomah County, Oregon ("Multnomah County Circuit Court Oregon"). The complaint was filed by Oregon residents and businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. 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 Oregon 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 subsequently filed to appeal the class issues as described below.

In April 2023, the jury trial for James with respect to 17 named plaintiffs began in Multnomah County Circuit Court Oregon. In June 2023, the jury issued its verdict finding PacifiCorp liable to the 17 named plaintiffs and to the class with respect to the four wildfires. The jury found PacifiCorp's conduct grossly negligent, reckless and willful as to each plaintiff and the entire class. The jury awarded the 17 named plaintiffs $90 million of damages, including $4 million of economic 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 Oregon ordered trial dates for three damages phase trials described below wherein plaintiffs in each of the three damages phase trials would present evidence regarding their damages.

23

In January 2024, the Multnomah County Circuit Court Oregon entered a limited judgment and money award for the June 2023 James verdict. The limited judgment awards $92 million of damages based on the amounts awarded by the jury, as well as doubling of the economic damages and offsetting of any insurance proceeds received by plaintiffs. The limited judgment created a lien against PacifiCorp, attaching a debt for the money awards. PacifiCorp posted a supersedeas bond, which stays any effort to seek payment of the judgment pending final resolution of any appeals. Under Oregon Revised Statutes 82.010, interest at a rate of 9% per annum will accrue on the judgment commencing at the date the judgment was entered until the entire money award is paid, amended or reversed by an appellate court. In January 2024, PacifiCorp filed a notice of appeal associated with the June 2023 verdict in James, including whether the case can proceed as a class action and filed a motion to stay further damages phase trials. On February 14, 2024, the Oregon Court of Appeals denied PacifiCorp's request to stay the damages phase trials. On February 13, 2024, the 17 named plaintiffs filed a notice of cross-appeal as to the January 2024 limited judgment and money award. The appeals process and further actions could take several years.

In January 2024, the jury for the first James damages phase trial awarded nine plaintiffs $62 million of damages, including $6 million of economic damages and $56 million of noneconomic damages. After the jury verdict, the Multnomah County Circuit Court Oregon doubled the economic damages to $12 million and added $16 million of punitive damages using the 0.25 multiplier determined by the jury for the June 2023 James verdict, bringing the total damages awarded to $84 million. PacifiCorp requested that the Multnomah County Circuit Court Oregon judge offset the damage awards by deducting insurance proceeds received by any of the nine plaintiffs, and on March 25, 2024, the Multnomah County Circuit Court Oregon granted in large part the offset request. In April 2024, the Multnomah County Circuit Court Oregon entered a limited judgment and money award for the January 2024 James verdict. The limited judgment awards $80 million of damages based on the amounts awarded by the jury and offsetting insurance proceeds received by plaintiffs. The limited judgment created a lien against PacifiCorp, attaching a debt for the money awards. In April 2024, PacifiCorp posted a supersedeas bond, which stays any effort to seek payment of the judgment pending final resolution of any appeals. PacifiCorp amended its January 2024 appeal of the June 2023 James verdict to include the January 2024 jury verdict.

In March 2024, the jury for the second James damages phase trial awarded ten plaintiffs $42 million of damages, including $12 million of doubled economic damages, $23 million of noneconomic damages and $7 million of punitive damages using the 0.25 multiplier determined by the jury for the June 2023 James verdict. PacifiCorp requested that the Multnomah County Circuit Court Oregon judge offset the damage awards by deducting insurance proceeds received by any of the ten plaintiffs and on May 6, 2024, the Multnomah County Circuit Court Oregon granted the offset request. In June 2024, the Multnomah County Circuit Court Oregon entered a limited judgment and money award for the March 2024 James verdict. The limited judgment awards $38 million of damages based on the amounts awarded by the jury and offsetting insurance proceeds received by plaintiffs. The limited judgment created a lien against PacifiCorp, attaching a debt for the money awards. In July 2024, PacifiCorp posted a supersedeas bond, which stays any effort to seek payment of the judgment pending final resolution of any appeals. PacifiCorp further amended its appeal of the June 2023 James verdict to include the March 2024 jury verdict.

In March 2024, settlement was reached with five commercial timber plaintiffs in the James consolidated cases, and the jury trial scheduled for April 2024 was cancelled.

In April, May, July and September 2024, five separate mass complaints against PacifiCorp naming 1,536 individual class members were filed in Multnomah County Circuit Court Oregon referencing James as the lead case. These James mass complaints make damages only allegations seeking economic, noneconomic and punitive damages, as well as doubling of economic damages. PacifiCorp believes the magnitude of damages sought by the class members in the James mass complaints to be of remote likelihood of being awarded based on the amounts awarded in the jury verdicts described above that are being appealed.

In October 2024, the Multnomah County Circuit Court Oregon issued a case management order, which sets forth nine additional damages phase trials with 10 plaintiffs per trial. The trials are scheduled to begin February 3, March 24, April 21, May 12, June 2, July 7, September 9, October 6 and December 7, 2025.

2022 McKinney Fire

According to the California Department of Forestry and Fire Protection, a wildfire began on July 29, 2022, in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California located in PacifiCorp's service territory, burning over 60,000 acres. Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged; 185 structures destroyed, including residences; 12 injuries; and four fatalities. 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.

24

Estimated Losses for and Settlements Associated with 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 recorded cumulative estimated probable losses associated with the Wildfires of $2,658 million through September 30, 2024. 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.

Through September 30, 2024, PacifiCorp paid $1,213 million in settlements associated with the Wildfires. As a result of the settlements, various trials have been cancelled.

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,
	2024		2023		2024		2023
Beginning balance	$	1,883	$	948	$	1,723	$	424
Accrued losses	—		1,387		251		1,928
Payments	(438)		(57)		(529)		(74)
Ending balance	$	1,445	$	2,278	$	1,445	$	2,278

As of September 30, 2024 and December 31, 2023, $79 million and $4 million of PacifiCorp's liability for estimated losses associated with the Wildfires was included in Other current liabilities on the Consolidated Balance Sheets. The amounts reflected as current as of September 30, 2024 reflect amounts reasonably expected to be paid out within the next year based on settlements reached as well as ongoing settlement and mediation efforts. The remainder of PacifiCorp's liability for estimated losses associated with the Wildfires as of September 30, 2024 and December 31, 2023 was included in Other long-term liabilities on the Consolidated Balance Sheets.

The following table presents changes in PacifiCorp's receivable for expected insurance recoveries associated with the Wildfires (in millions):

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2024		2023		2024		2023
Beginning balance	$	139	$	379	$	499	$	246
Accruals	—		124		—		257
Payments received	(5)		—		(365)		—
Ending balance	$	134	$	503	$	134	$	503

As of September 30, 2024, $38 million of PacifiCorp's receivable for expected insurance recoveries was included in Other current assets while the remaining $96 million was included in Other assets on the Consolidated Balance Sheets. As of December 31, 2023, $350 million of PacifiCorp's receivable for expected insurance recoveries was included in Other current assets while the remaining $149 million was included in Other assets on the Consolidated Balance Sheets. Insurance proceeds received to date relate to the 2020 Wildfires.

25

During the three-month period ended September 30, 2024 and 2023, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $— million and $1,263 million, respectively. During the nine-month periods ended September 30, 2024 and 2023, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $251 million and $1,671 million, respectively. No additional insurance recoveries beyond those accrued and received 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 several antitrust cases, all in federal district courts. In each case, plaintiffs claim HomeServices and certain of its subsidiaries (in one instance, HomeServices and BHE) 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"). None of the complaints specify damages sought. However, two cases allege Texas state law deceptive trade practices claims, for which plaintiffs have provided written notice of the damages sought totaling approximately $9 billion by separate notice as required by Texas law.

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, 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 conspiracy 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. Joint and several liability applies for the co-defendants. Federal law authorizes trebling of damages and the award of pre-judgment interest and attorney fees. Prior to the trial, Anywhere Real Estate and RE/MAX, LLC reached settlement agreements with the plaintiffs. Subsequent to the trial, settlements were reached by Keller Williams, NAR and HomeServices on February 1, 2024, March 15, 2024, and April 25, 2024, respectively. The Anywhere Real Estate, RE/MAX, LLC and Keller Williams settlements received court approval on May 9, 2024, which has been appealed to the U.S. Court of Appeals for the Eighth Circuit. The NAR and HomeServices settlements are subject to court approval, which is scheduled for November 26, 2024. Final judgment has not yet been entered by the U.S. District Court for the Western District of Missouri.

In April 2024, HomeServices agreed to terms with the plaintiffs to settle all claims asserted against HomeServices, HSF Affiliates, LLC and BHH Affiliates, LLC in the Burnett case as part of a proposed nationwide class settlement. The final settlement agreement includes scheduled payments over the next four years aggregating $250 million. HomeServices recognized an after-tax charge of approximately $140 million during the nine-month period ended September 30, 2024. If the settlement is not approved by the court, 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.

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.

26

(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 15 (in millions):

	For the Three-Month Period Ended September 30, 2024
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	1,789	$	734	$	1,275	$	—	$	—	$	—	$	—	$	(2)	$	3,796
Retail gas	—		82		18		—		—		—		—		—		100
Wholesale	25		62		14		—		7		—		—		—		108
Transmission and    distribution	54		15		23		366		—		178		—		—		636
Interstate pipeline	—		—		—		—		533		—		—		(32)		501
Other	26		—		—		—		—		—		—		—		26
Total Regulated	1,894		893		1,330		366		540		178		—		(34)		5,167
Nonregulated	—		2		1		24		239		24		389		—		679
Total Customer Revenue	1,894		895		1,331		390		779		202		389		(34)		5,846
Other revenue	29		12		1		31		38		1		68		—		180
Total	$	1,923	$	907	$	1,332	$	421	$	817	$	203	$	457	$	(34)	$	6,026

	For the Nine-Month Period Ended September 30, 2024
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	4,628	$	1,798	$	3,088	$	—	$	—	$	—	$	—	$	(3)	$	9,511
Retail gas	—		424		137		—		—		—		—		—		561
Wholesale	67		159		44		—		7		—		—		(1)		276
Transmission and    distribution	137		43		62		986		—		510		—		—		1,738
Interstate pipeline	—		—		—		—		1,957		—		—		(103)		1,854
Other	81		—		1		—		1		—		—		—		83
Total Regulated	4,913		2,424		3,332		986		1,965		510		—		(107)		14,023
Nonregulated	—		4		4		73		770		87		1,015		—		1,953
Total Customer Revenue	4,913		2,428		3,336		1,059		2,735		597		1,015		(107)		15,976
Other revenue	47		52		3		94		47		2		167		(2)		410
Total	$	4,960	$	2,480	$	3,339	$	1,153	$	2,782	$	599	$	1,182	$	(109)	$	16,386

27

	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

(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,
	2024		2023		2024		2023
Customer Revenue:
Brokerage	$	1,084	$	1,125	$	3,068	$	3,126
Franchise	14		16		40		43
Total Customer Revenue	1,098		1,141		3,108		3,169
Mortgage and other revenue	81		71		226		214
Total	$	1,179	$	1,212	$	3,334	$	3,383

28

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, 2024, by reportable segment (in millions):

	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total
BHE Pipeline Group	$	3,044	$	19,351	$	22,395

(13)    BHE Shareholders' Equity

In September 2024, BHE repurchased 4,424,494 shares of its voting common stock held by certain family members and related or affiliated entities of the late Mr. Walter Scott, Jr., a former member of BHE's Board of Directors (each, a "Minority Shareholder") and acquired, cancelled and extinguished the Junior Subordinated Debenture due 2057, having an aggregate principal amount of $100 million, issued by BHE to a certain Minority Shareholder on June 19, 2017 (the "Debenture") (collectively, the "Transactions"). Consideration for the Transactions consisted of (i) cash in an aggregate amount of $2.4 billion and (ii) a Promissory Note having an aggregate principal amount of $600 million (the "Note"). The Note was due and payable on September 30, 2025 and could be prepaid at any time without penalty. The Note was included in Other current liabilities on the Consolidated Balance Sheet as of September 30, 2024. In October 2024, BHE repaid the entire principal amount of the Note plus accrued interest.

Also, in September 2024, certain family members and related or affiliated entities of the late Mr. Walter Scott, Jr. agreed to exchange (the "Exchange Transactions") 1,601,258 shares of BHE's voting common stock for 2,291,631 shares of Berkshire Hathaway Class B common stock. All such Exchange Transactions were completed between September 30, 2024 and October 31, 2024. As a result of the Transactions and the Exchange Transactions, 100% of BHE's voting common stock was owned by Berkshire Hathaway as of October 31, 2024.

(14)    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, 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)
Balance, December 31, 2023	$	(426)	$	(1,550)	$	71	$	1	$	(1,904)
Other comprehensive (loss) income	(3)		178		4		—		179
Balance, September 30, 2024	$	(429)	$	(1,372)	$	75	$	1	$	(1,725)

29

(15)    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. 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,
	2024		2023		2024		2023
Operating revenue:
PacifiCorp	$	1,923	$	1,676	$	4,960	$	4,487
MidAmerican Funding	907		964		2,480		2,643
NV Energy	1,332		1,518		3,339		3,636
Northern Powergrid	421		314		1,153		975
BHE Pipeline Group	817		804		2,782		2,795
BHE Transmission	203		196		599		593
BHE Renewables	457		519		1,182		1,349
HomeServices	1,179		1,212		3,334		3,383
BHE and Other(1)	(34)		(33)		(109)		(116)
Total operating revenue	$	7,205	$	7,170	$	19,720	$	19,745

Depreciation and amortization:
PacifiCorp	$	287	$	285	$	866	$	843
MidAmerican Funding	230		210		685		670
NV Energy	142		155		419		460
Northern Powergrid	87		97		260		267
BHE Pipeline Group	148		136		430		403
BHE Transmission	58		64		174		190
BHE Renewables	68		67		203		200
HomeServices	11		12		35		37
BHE and Other(1)	—		1		3		2
Total depreciation and amortization	$	1,031	$	1,027	$	3,075	$	3,072

30

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2024		2023		2024		2023
Operating income:
PacifiCorp	$	299	$	(943)	$	340	$	(979)
MidAmerican Funding	234		289		395		495
NV Energy	343		328		559		502
Northern Powergrid	227		102		582		369
BHE Pipeline Group	282		290		1,280		1,242
BHE Transmission	81		80		250		244
BHE Renewables	103		155		143		175
HomeServices	28		31		(143)		32
BHE and Other(1)	(13)		(18)		(72)		(53)
Total operating income	1,584		314		3,334		2,027
Interest expense	(679)		(603)		(2,045)		(1,788)
Capitalized interest	49		36		145		93
Allowance for equity funds	97		76		272		186
Interest and dividend income	112		110		362		323
Gains (losses) on marketable securities, net	268		(76)		474		926
Other, net	34		(3)		90		115
Total income (loss) before income tax expense (benefit) and equity income (loss)	$	1,465	$	(146)	$	2,632	$	1,882

Interest expense:
PacifiCorp	$	193	$	140	$	570	$	398
MidAmerican Funding	109		89		327		258
NV Energy	73		65		218		192
Northern Powergrid	36		26		104		86
BHE Pipeline Group	43		39		126		117
BHE Transmission	39		37		114		112
BHE Renewables	34		36		103		124
HomeServices	1		3		7		11
BHE and Other(1)	151		168		476		490
Total interest expense	$	679	$	603	$	2,045	$	1,788

Earnings on common shares:
PacifiCorp	$	325	$	(652)	$	363	$	(665)
MidAmerican Funding	337		321		806		803
NV Energy	264		278		400		402
Northern Powergrid	158		66		393		173
BHE Pipeline Group	194		175		927		731
BHE Transmission	62		59		197		181
BHE Renewables	133		160		372		445
HomeServices	20		25		(96)		25
BHE and Other(1)	482		54		220		438
Total earnings on common shares	$	1,975	$	486	$	3,582	$	2,533

31

	As of
	September 30,		December 31,
	2024		2023
Assets:
PacifiCorp	$	35,886	$	33,757
MidAmerican Funding	28,402		27,331
NV Energy	18,445		17,788
Northern Powergrid	10,463		9,596
BHE Pipeline Group	21,897		21,723
BHE Transmission	9,595		9,624
BHE Renewables	10,812		11,045
HomeServices	3,451		3,407
BHE and Other(1)	1,545		3,569
Total assets	$	140,496	$	137,840

(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,
	2024		2023		2024		2023
Operating revenue by country:
U.S.	$	6,596	$	6,677	$	18,026	$	18,241
United Kingdom	417		308		1,136		936
Canada	188		179		541		529
Australia	3		6		13		39
Other	1		—		4		—
Total operating revenue by country	$	7,205	$	7,170	$	19,720	$	19,745

Income (loss) before income tax expense (benefit) and equity income (loss) by country:
U.S.	$	1,224	$	(271)	$	2,003	$	1,462
United Kingdom	201		68		494		274
Canada	47		48		145		135
Australia	(6)		11		(7)		13
Other	(1)		(2)		(3)		(2)
Total income (loss) before income tax expense (benefit) and equity income (loss) by country	$	1,465	$	(146)	$	2,632	$	1,882

The following table shows the change in the carrying amount of goodwill by reportable segment for the nine-month period ended September 30, 2024 (in millions):

									BHE Pipeline Group
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid				BHE Transmission		BHE Renewables		HomeServices
																	Total
December 31, 2023	$	1,129	$	2,102	$	2,369	$	950	$	1,814	$	1,492	$	95	$	1,596	$	11,547
Foreign currency translation	—		—		—		34		—		(31)		—		—		3
Other	—		—		—		—		—		—		—		(5)		(5)
September 30, 2024	$	1,129	$	2,102	$	2,369	$	984	$	1,814	$	1,461	$	95	$	1,591	$	11,545

32

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 October 31, 2024, owned 100% of BHE's voting common stock.

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., interest 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.

33

Results of Operations for the Third Quarter and First Nine Months of 2024 and 2023

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
	2024		2023		Change				2024		2023		Change
Operating revenue:
PacifiCorp	$	1,923	$	1,676	$	247	15	%	$	4,960	$	4,487	$	473	11	%
MidAmerican Funding	907		964		(57)		(6)		2,480		2,643		(163)		(6)
NV Energy	1,332		1,518		(186)		(12)		3,339		3,636		(297)		(8)
Northern Powergrid	421		314		107		34		1,153		975		178		18
BHE Pipeline Group	817		804		13		2		2,782		2,795		(13)		—
BHE Transmission	203		196		7		4		599		593		6		1
BHE Renewables	457		519		(62)		(12)		1,182		1,349		(167)		(12)
HomeServices	1,179		1,212		(33)		(3)		3,334		3,383		(49)		(1)
BHE and Other	(34)		(33)		(1)		(3)		(109)		(116)		7		6
Total operating revenue	$	7,205	$	7,170	$	35	—	%	$	19,720	$	19,745	$	(25)	—	%
Earnings on common shares:
PacifiCorp	$	325	$	(652)	$	977	* %		$	363	$	(665)	$	1,028	* %
MidAmerican Funding	337		321		16		5		806		803		3		—
NV Energy	264		278		(14)		(5)		400		402		(2)		—
Northern Powergrid	158		66		92		*		393		173		220		*
BHE Pipeline Group	194		175		19		11		927		731		196		27
BHE Transmission	62		59		3		5		197		181		16		9
BHE Renewables(1)	133		160		(27)		(17)		372		445		(73)		(16)
HomeServices	20		25		(5)		(20)		(96)		25		(121)		*
BHE and Other	482		54		428		*		220		438		(218)		(50)
Total earnings on common shares	$	1,975	$	486	$	1,489	* %		$	3,582	$	2,533	$	1,049	41	%

*    Not meaningful

(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.

Earnings on common shares increased $1,489 million for the third quarter of 2024 compared to 2023. Included in these results was a pre-tax gain in the third quarter of 2024 of $255 million ($202 million after-tax) compared to a pre-tax loss in the third quarter of 2023 of $69 million ($54 million after-tax) related to the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the third quarter of 2024 was $1,773 million, an increase of $1,233 million, or 228%, compared to adjusted earnings on common shares for the third quarter of 2023 of $540 million.

Earnings on common shares increased $1,049 million for the first nine months of 2024 compared to 2023. Included in these results was a pre-tax gain in the first nine months of 2024 of $444 million ($351 million after-tax) compared to a pre-tax gain in the first nine months of 2023 of $915 million ($723 million after-tax) related to the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the first nine months of 2024 was $3,231 million, an increase of $1,421 million, or 79%, compared to adjusted earnings on common shares for the first nine months of 2023 of $1,810 million.

34

The increases in earnings on common shares for the third quarter and for the first nine months of 2024 compared to 2023 were primarily due to the following:

•The Utilities' earnings increased $979 million for the third quarter and $1,029 million for the first nine months of 2024 compared to 2023. Wildfire loss accruals, net of expected insurance recoveries, were $1,263 million lower for the third quarter and $1,420 million lower for the first nine months of 2024. The increases also included higher PTCs, higher electric utility margin, higher allowances for equity and borrowed funds used during construction and increased interest and dividend income, partially offset by increased operations and maintenance expense and higher interest expense. Electric retail customer volumes increased 3.6% for the first nine months of 2024 compared to 2023, primarily due to higher customer usage and an increase in the average number of customers, partially offset by the unfavorable impact of weather;

•Northern Powergrid's earnings increased $92 million for the third quarter and $220 million for the first nine months of 2024 compared to 2023, primarily due to higher distribution revenue and lower income tax expense from charges recognized in 2023 related to the Energy Profits Levy income tax and a group relief tax claim recognized in 2024, partially offset by unfavorable operating performance at the gas exploration business and higher distribution-related operating and depreciation and amortization expenses. Units distributed increased 0.9% for the first nine months of 2024 compared to 2023 mainly due to higher customer usage;

•BHE Pipeline Group's earnings increased $19 million for the third quarter and $196 million for the first nine months of 2024 compared to 2023, primarily due to the acquisition of an additional 50% limited partner interest in Cove Point on September 1, 2023, and higher transportation revenue and higher margin on gas sales from system balancing activities at Northern Natural Gas;

•BHE Renewables' earnings decreased $27 million for the third quarter and $73 million for the first nine months of 2024 compared to 2023, primarily due to lower earnings from the wind tax equity investment portfolio and gains on the extinguishment of debt recognized in the second quarter of 2023 and lower geothermal and natural gas earnings from lower pricing and generation, partially offset by higher earnings from the retail energy services business, largely due to favorable changes in unrealized positions on derivative contracts, and higher solar earnings from higher generation;

•HomeServices' earnings decreased $5 million for the third quarter and $121 million for the first nine months of 2024 compared to 2023, primarily due to a charge of approximately $140 million recognized in the first quarter of 2024 associated with a settlement reached in the ongoing real estate industry litigation matters offset by higher mortgage earnings from lower compensation and occupancy costs and higher revenue due to an increase in average loan size caused by lower inventory driving an increase in average home sales prices; and

•BHE and Other's earnings increased $428 million for the third quarter and decreased $218 million for the first nine months of 2024 compared to 2023. The changes included a favorable comparative change of $256 million in the third quarter and an unfavorable comparative change of $372 million for the first nine months of 2024 related to the Company's investment in BYD Company Limited as well as $124 million of higher federal income tax credits recognized on a consolidated basis.

Reportable Segment Results

PacifiCorp

Operating revenue increased $247 million for the third quarter of 2024 compared to 2023, primarily due to higher retail revenues of $248 million. Retail revenue increased primarily due to price impacts of $195 million from higher average rates, largely from tariff changes, and $53 million from higher retail volumes. Retail customer volumes increased 3.2%, primarily due to higher customer usage and an increase in the average number of customers, partially offset by the unfavorable impact of weather.

Earnings increased $977 million for the third quarter of 2024 compared to 2023, primarily due to lower wildfire loss accruals, net of expected insurance recoveries, of $1,263 million, higher utility margin of $49 million, increased allowances for equity and borrowed funds used during construction of $30 million and higher interest and dividend income of $19 million. These items were partially offset by higher operations and maintenance expense of $65 million and increased interest expense of $53 million due to the debt issuance in January 2024. Utility margin increased primarily due to higher retail rates and volumes and lower thermal generation costs, partially offset by unfavorable deferred net power costs and higher purchased power costs. Operations and maintenance expense increased due to higher insurance premiums, increased vegetation management and other wildfire mitigation costs, higher salary and benefit expenses and higher amortization of demand-side management costs.

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Operating revenue increased $473 million for the first nine months of 2024 compared to 2023, primarily due to higher retail revenues of $516 million, partially offset by lower wholesale and other revenue of $43 million. Retail revenue increased primarily due to price impacts of $397 million from higher average rates, largely from tariff changes, and $119 million from higher retail volumes. Retail customer volumes increased 3.2%, primarily due to higher customer usage and an increase in the average number of customers, partially offset by the unfavorable impact of weather. Wholesale and other revenue decreased mainly due to lower wholesale volumes and lower average wholesale prices, partially offset by higher wheeling revenue.

Earnings increased $1,028 million for the first nine months of 2024 compared to 2023, primarily due to lower wildfire loss accruals, net of expected insurance recoveries, of $1,420 million, higher utility margin of $137 million, increased allowances for equity and borrowed funds used during construction of $99 million and higher interest and dividend income of $82 million. These items were partially offset by higher operations and maintenance expense of $211 million, increased interest expense of $172 million due to debt issuances in May 2023 and January 2024 and higher depreciation and amortization expense of $23 million. Utility margin increased primarily due to higher retail rates and volumes and lower thermal generation costs, partially offset by unfavorable deferred net power costs, higher purchased electricity costs and lower wholesale volumes and average prices. Operations and maintenance expense increased due to higher insurance premiums, increased vegetation management and other wildfire mitigation costs, higher salary and benefit expenses and higher amortization of demand-side management costs. Depreciation and amortization expense increased largely due to additional assets placed in-service.

MidAmerican Funding

Operating revenue decreased $57 million for the third quarter of 2024 compared to 2023, primarily due to lower electric operating revenue of $55 million. Electric operating revenue decreased due to lower retail revenue of $42 million and lower wholesale and other revenue of $13 million. Electric retail revenue decreased primarily due to lower recoveries through adjustment clauses of $42 million (fully offset in operations and maintenance expense and income tax benefit) and the unfavorable impact of weather of $5 million, partially offset by higher customer usage of $7 million. Electric retail customer volumes increased 0.5%, primarily due to an increase in the average number of customers, partially offset by the unfavorable impact of weather. Electric wholesale and other revenue decreased mainly due to lower wholesale volumes of $23 million, partially offset by higher average wholesale prices of $7 million.

Earnings increased $16 million for the third quarter of 2024 compared to 2023, primarily due to a favorable income tax benefit, mainly from higher PTCs of $59 million, higher natural gas utility margin of $8 million, increased allowances for equity and borrowed funds used during construction of $5 million and higher interest and dividend income of $4 million. These items were partially offset by lower electric utility margin of $26 million, higher depreciation and amortization expense of $20 million, increased interest expense of $20 million due to debt issuances in September 2023 and January 2024 and higher operations and maintenance expense of $16 million. Natural gas utility margin increased primarily due to higher base rates from tariff changes. Electric utility margin decreased primarily due to lower retail and wholesale revenues, partially offset by lower thermal generation and purchased power costs. Depreciation and amortization expense increased primarily due to additional assets placed in-service and the impacts of certain regulatory mechanisms. Operations and maintenance expense increased primarily due to higher salary and benefit expenses and increased general and plant maintenance costs.

Operating revenue decreased $163 million for the first nine months of 2024 compared to 2023, primarily due to lower electric operating revenue of $107 million and lower natural gas operating revenue of $54 million. Electric operating revenue decreased due to lower wholesale and other revenue of $67 million and lower retail revenue of $40 million. Electric wholesale and other revenue decreased mainly due to lower average wholesale prices of $41 million and lower wholesale volumes of $32 million. Electric retail revenue decreased primarily due to lower recoveries through adjustment clauses of $47 million (fully offset in operations and maintenance expense and income tax benefit) and the unfavorable impact of weather of $11 million, partially offset by higher customer usage of $15 million. Electric retail customer volumes increased 0.6%, primarily due to an increase in the average number of customers, partially offset by the unfavorable impact of weather. Natural gas operating revenue decreased primarily due to lower energy-related rates of $74 million (fully offset in cost of sales) from a lower average per-unit cost of natural gas sold and the unfavorable impact of weather of $6 million, partially offset by higher base rates of $23 million.

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Earnings increased $3 million for the first nine months of 2024 compared to 2023, primarily due to a favorable income tax benefit, primarily from higher PTCs of $118 million offset by the effects of ratemaking of $31 million, higher natural gas utility margin of $21 million, increased allowances for equity and borrowed funds used during construction of $20 million and higher interest and dividend income of $17 million. These items were partially offset by higher interest expense of $69 million due to debt issuances in September 2023 and January 2024, increased operations and maintenance expense of $61 million, lower electric utility margin of $40 million and higher depreciation and amortization expense of $15 million. Natural gas utility margin increased primarily due to higher base rates from tariff changes, partially offset by the unfavorable impact of weather. Operations and maintenance expense increased primarily due to higher salary and benefit expenses, increased general and plant maintenance costs and higher technology costs. Electric utility margin decreased primarily due to lower wholesale and retail revenues, partially offset by lower thermal generation and purchased power costs. Depreciation and amortization expense increased primarily due to additional assets placed in-service, partially offset by the impacts of certain regulatory mechanisms.

NV Energy

Operating revenue decreased $186 million for the third quarter of 2024 compared to 2023, primarily due to lower electric operating revenue of $176 million and lower natural gas operating revenue of $9 million, largely due to lower energy-related rates (fully offset in costs of sales) from a lower average per-unit cost of natural gas sold. Electric operating revenue decreased primarily due to lower fully bundled energy rates (fully offset in cost of sales) of $202 million and lower regulatory-related revenue deferrals of $13 million, partially offset by higher customer volumes of $36 million and higher base rates of $5 million at Nevada Power. Electric retail customer volumes increased 8.2%, primarily due to the favorable impact of weather, an increase in the average number of customers and higher customer usage.

Earnings decreased $14 million for the third quarter of 2024 compared to 2023, primarily due to higher operations and maintenance expense of $24 million, lower interest and dividend income of $16 million, mainly from carrying charges on higher deferred energy balances in 2023, increased interest expense of $8 million due to higher debt outstanding, an unfavorable income tax expense primarily due to the effects of ratemaking of $18 million offset by higher PTCs of $5 million. These items were partially offset by higher electric utility margin of $27 million and lower depreciation and amortization expense of $13 million, largely from lower regulatory amortizations. Operations and maintenance expense increased primarily due to higher general and plant maintenance costs and increased insurance premiums. Electric utility margin increased primarily due to higher retail volumes and higher base rates at Nevada Power, partially offset by lower regulatory-related revenue deferrals.

Operating revenue decreased $297 million for the first nine months of 2024 compared to 2023, primarily due to lower electric operating revenue of $269 million and lower natural gas operating revenue of $29 million, largely due to lower energy-related rates (fully offset in costs of sales) from a lower average per-unit cost of natural gas sold. Electric operating revenue decreased primarily due to lower fully bundled energy rates (fully offset in cost of sales) of $324 million and lower regulatory-related revenue deferrals of $28 million, partially offset by higher customer volumes of $59 million and higher base rates of $30 million at Nevada Power. Electric retail customer volumes increased 6.6%, primarily due to the favorable impact of weather, an increase in the average number of customers and higher customer usage.

Earnings decreased $2 million for the first nine months of 2024 compared to 2023, primarily due to lower interest and dividend income of $45 million, mainly from carrying charges on higher deferred energy balances in 2023, higher operations and maintenance expense of $36 million, increased interest expense of $26 million due to higher debt outstanding and an unfavorable income tax expense primarily due to the effects of ratemaking of $22 million offset by higher PTCs of $8 million. These items were partially offset by higher electric utility margin of $54 million, lower depreciation and amortization expense of $41 million, largely from lower regulatory amortizations, and higher allowances for equity and borrowed funds used during construction of $14 million. Operations and maintenance expense increased primarily due to higher insurance premiums and increased general and plant maintenance costs. Electric utility margin increased primarily due to higher retail volumes and higher base rates at Nevada Power, partially offset by lower regulatory-related revenue deferrals.

Northern Powergrid

Operating revenue increased $107 million for the third quarter of 2024 compared to 2023, primarily due to higher distribution revenue of $109 million and $11 million from the weaker U.S. dollar, partially offset by lower revenue at the gas exploration business of $8 million. Distribution revenue increased primarily due to higher tariff rates of $119 million driven by the impacts of inflation, partially offset by lower recoveries of Supplier of Last Resort payments of $12 million (largely offset in cost of sales). Units distributed increased 1.7% mainly due to higher customer usage. Revenue at the gas exploration business decreased due to lower gas production volumes.

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Earnings increased $92 million for the third quarter of 2024 compared to 2023, primarily due to higher distribution revenue and lower income tax expense from a group tax relief claim recognized in 2024, partially offset by higher income tax expense from favorable adjustments recognized in 2023 related to the Energy Profits Levy income tax and higher distribution-related operating and depreciation and amortization expenses of $7 million.

Operating revenue increased $178 million for the first nine months of 2024 compared to 2023, primarily due to higher distribution revenue of $186 million and $30 million from the weaker U.S. dollar, partially offset by lower revenue at the gas exploration business of $36 million. Distribution revenue increased primarily due to higher tariff rates of $232 million driven by the impacts of inflation, partially offset by lower recoveries of Supplier of Last Resort payments of $51 million (largely offset in cost of sales). Units distributed increased 0.9% mainly due to higher customer usage. Revenue at the gas exploration business decreased due to lower gas production volumes and prices.

Earnings increased $220 million for the first nine months of 2024 compared to 2023, primarily due to higher distribution revenue and lower income tax expense from charges recognized in 2023 related to the Energy Profits Levy income tax and a group relief tax claim recognized in 2024, partially offset by higher distribution-related operating and depreciation and amortization expenses of $28 million and unfavorable operating performance at the gas exploration business of $16 million.

BHE Pipeline Group

Operating revenue increased $13 million for the third quarter of 2024 compared to 2023, primarily due to higher operating revenue of $19 million at Northern Natural Gas, mainly due to higher transportation revenue from increased volumes and rates, and higher non-regulated revenue of $11 million, partially offset by lower operating revenue of $10 million at BHE GT&S and $7 million at Kern River, largely due to a decline in variable transportation revenues from lower rates and volumes. The decrease in operating revenue at BHE GT&S was primarily due to lower revenues at Cove Point of $12 million largely from unfavorable variable revenue and storage-related service revenues.

Earnings increased $19 million for the third quarter of 2024 compared to 2023, primarily due to higher earnings of $23 million at BHE GT&S, partially offset by lower earnings of $1 million at Northern Natural Gas. The increase at BHE GT&S was primarily due to higher earnings at Cove Point of $37 million, largely due to the acquisition of an additional 50% limited partner interest in Cove Point on September 1, 2023, and lower operations and maintenance expense of $6 million, partially offset by favorable income tax adjustments recognized in 2023 of $18 million. The decrease at Northern Natural Gas was primarily due to higher operations and maintenance expense of $25 million, mainly due to the timing of pipeline inspection and remediation costs and higher salary and benefit expenses, largely offset by higher transportation revenue and higher margin on gas sales of $6 million from system balancing activities.

Operating revenue decreased $13 million for the first nine months of 2024 compared to 2023, primarily due to lower operating revenue of $80 million at BHE GT&S and $19 million at Kern River, largely due to a decline in variable transportation revenues from lower rates and volumes, partially offset by higher operating revenue of $58 million at Northern Natural Gas and higher non-regulated revenues of $28 million. The decrease in operating revenue at BHE GT&S was primarily due to lower revenues at Cove Point of $44 million largely from unfavorable variable revenue and storage-related service revenues, lower non-regulated revenue of $28 million (largely offset in cost of sales) primarily from lower volumes and a decrease in variable revenue related to natural gas storage park and loan activity of $20 million at EGTS, partially offset by an increase in regulated gas transmission and storage services revenue of $12 million at EGTS largely due to higher volumes. The increase in operating revenue at Northern Natural Gas was primarily due to higher transportation revenue of $40 million due to higher volumes and rates and higher gas sales of $17 million from system balancing activities.

Earnings increased $196 million for the first nine months of 2024 compared to 2023, primarily due to higher earnings of $154 million at BHE GT&S and higher earnings of $47 million at Northern Natural Gas. The increase at BHE GT&S was primarily due to higher earnings at Cove Point of $145 million, largely due to the acquisition of an additional 50% limited partner interest in Cove Point on September 1, 2023, lower operations and maintenance expense of $32 million, largely from lower salary and benefit expenses and lower outside services, and decreased cost of gas of $30 million from the unfavorable revaluation of volumes retained at EGTS in 2023 due to lower natural gas prices, partially offset by favorable income tax adjustments recognized in 2023 of $18 million and lower interest and dividend income of $18 million. The increase at Northern Natural Gas was primarily due to higher transportation revenue and higher margin on gas sales of $35 million from system balancing activities, partially offset by higher operations and maintenance expense of $13 million, largely from higher salary and benefit expenses, and higher depreciation and amortization expense of $10 million from additional assets placed in-service.

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BHE Transmission

Operating revenue increased $7 million for the third quarter of 2024 compared to 2023, primarily due to the recovery of costs from the 2023 spring wildfire and storm events and the favorable impact of the AUC's approved return on equity rate increase at AltaLink, partially offset by lower revenue from non-regulated wind-powered generating facilities from lower generation and $3 million from the stronger U.S. dollar.

Earnings increased $3 million for the third quarter of 2024 compared to 2023, primarily due to higher equity earnings at Electric Transmission Texas, LLC.

Operating revenue increased $6 million for the first nine months of 2024 compared to 2023, primarily due to the recovery of costs from the 2023 spring wildfire and storm events and the favorable impact of the AUC's approved return on equity rate increase at AltaLink, partially offset by lower revenue from non-regulated wind-powered generating facilities from lower generation and $6 million from the stronger U.S. dollar.

Earnings increased $16 million for the first nine months of 2024 compared to 2023, primarily due to the favorable impact of the AUC's approved return on equity rate increase at AltaLink and higher equity earnings at Electric Transmission Texas, LLC, partially offset by lower revenue from non-regulated wind-power generating facilities.

BHE Renewables

Operating revenue decreased $62 million for the third quarter of 2024 compared to 2023, primarily due to lower natural gas and electric retail energy services revenue of $38 million, lower geothermal and natural gas revenue of $34 million due to lower pricing and generation and lower wind revenue of $5 million, partially offset by higher solar revenue of $16 million from higher generation. Retail energy services revenue decreased mainly due to lower natural gas and electric volumes and unfavorable natural gas pricing. Wind revenue decreased primarily from lower pricing, partially offset by favorable changes in the valuation of certain derivative contracts.

Earnings decreased $27 million for the third quarter of 2024 compared to 2023, primarily due to lower natural gas and geothermal earnings of $27 million from lower revenue, partially offset by higher solar earnings of $8 million due to higher revenue offset by increased maintenance costs and higher wind earnings of $4 million, primarily due to favorable earnings from the wind tax equity investment portfolio of $6 million.

Operating revenue decreased $167 million for the first nine months of 2024 compared to 2023, primarily due to lower natural gas and electric retail energy services revenue of $117 million, lower geothermal and natural gas revenue of $65 million due to lower pricing and lower generation and lower wind revenue of $10 million, partially offset by higher solar revenue of $24 million from higher generation. Retail energy services revenue decreased mainly due to lower natural gas and electric volumes and unfavorable natural gas pricing. Wind revenue decreased largely from lower pricing and unfavorable changes in the valuations of certain derivative contracts, partially offset by higher generation.

Earnings decreased $73 million for the first nine months of 2024 compared to 2023, primarily due to lower wind earnings of $79 million and lower geothermal and natural gas earnings of $24 million from lower revenue offset by maintenance outages in 2023. These items were partially offset by higher earnings of $46 million from the retail energy services business largely due to favorable changes in the unrealized positions on derivative contracts and higher solar earnings of $10 million due to higher revenue offset by higher maintenance costs. Wind earnings were unfavorable due to lower earnings from the wind tax equity investment portfolio of $43 million and lower earnings at owned wind projects of $37 million, primarily due to gains on the extinguishment of debt recognized in the second quarter of 2023 and lower revenue.

HomeServices

Operating revenue decreased $33 million for the third quarter of 2024 compared to 2023, primarily due to lower brokerage and settlement services revenue of $43 million, partially offset by higher mortgage revenue of $13 million. The decrease in brokerage and settlement services revenue resulted mainly from a 7% decrease in closed brokerage units driven by the continued slowdown of overall market activity due to increased interest rates. The increase in mortgage revenue was mainly due to a 7% increase in average loan size caused by low inventory driving an increase in average home sales prices and a 5% increase in funded volume, primarily due to higher refinance activity.

Earnings decreased $5 million for the third quarter of 2024 compared to 2023, primarily due to lower brokerage and settlement services revenue, partially offset by higher mortgage revenue.

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Operating revenue decreased $49 million for the first nine months of 2024 compared to 2023, primarily due to lower brokerage and settlement services revenue of $64 million, partially offset by higher mortgage revenue of $18 million. The decrease in brokerage and settlement services revenue resulted mainly from a 6% decrease in closed brokerage units driven by the continued slowdown of overall market activity due to increased interest rates. The increase in mortgage revenue was mainly due to a 6% increase in average loan size caused by low inventory driving an increase in average home sales prices.

Earnings decreased $121 million for the first nine months of 2024 compared to 2023, primarily due to a charge of approximately $140 million recognized in the first quarter of 2024 associated with a settlement reached in the ongoing real estate industry litigation matters, partially offset by higher mortgage earnings of $28 million mainly due to favorable operating expenses, including lower compensation and occupancy costs, and higher revenue.

BHE and Other

Earnings increased $428 million for the third quarter of 2024 compared to 2023, primarily due to the $256 million favorable comparative change related to the Company's investment in BYD Company Limited, $124 million of higher federal income tax credits recognized on a consolidated basis, favorable changes in the cash surrender value of corporate-owned life insurance policies of $11 million and $8 million of lower dividends due to the final redemption of BHE's 4.00% Perpetual Preferred Stock issued to certain insurance subsidiaries of Berkshire Hathaway in December 2023.

Earnings decreased $218 million for the first nine months of 2024 compared to 2023, primarily due to the $372 million unfavorable comparative change and lower net interest and dividend income of $23 million each related to the Company's investment in BYD Company Limited, partially offset by $124 million of higher federal income tax credits recognized on a consolidated basis, $25 million of lower dividends due to the final redemption of BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in December 2023 and favorable changes in the cash surrender value of corporate-owned life insurance policies of $11 million.

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, 2023 for further discussion regarding the limitation of distributions from BHE's subsidiaries.

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As of September 30, 2024, 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	$	102	$	381	$	1,071	$	51	$	72	$	64	$	285	$	568	$	2,594
Credit facilities(1)	3,500		2,900		1,509		1,000		368		684		1,700		—		11,661
Less:
Short-term debt	—		—		—		(15)		(100)		(131)		(527)		—		(773)
Tax-exempt bond support and letters of credit	—		(218)		(306)		—		—		(2)		—		—		(526)
Net credit facilities	3,500		2,682		1,203		985		268		551		1,173		—		10,362
Total net liquidity(2)	$	3,602	$	3,063	$	2,274	$	1,036	$	340	$	615	$	1,458	$	568	$	12,956
Credit facilities:
Maturity dates	2027		2025, 2027		2025, 2027		2027		2026		2026, 2027, 2028		2025, 2026

(1)Includes $100 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, 2024 and 2023, were $6.2 billion and $5.9 billion, respectively. The increase was primarily due to favorable operating results, changes in working capital, including receipt of $365 million of insurance reimbursements related to wildfire liabilities, and higher income tax receipts, partially offset by an increase in wildfire liability settlement payments and higher cash paid for interest.

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, 2024 and 2023, were $(3.6) billion and $(3.2) billion, respectively. The change was primarily due to lower proceeds from sales and maturities, net of purchases, of U.S. Treasury Bills totaling $344 million and lower proceeds from sales, net of purchases, of marketable securities of $329 million, partially offset by lower capital expenditures of $290 million. Refer to "Future Uses of Cash" for a discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2024, was $(1.5) billion. Sources of cash totaled $5.3 billion and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $6.8 billion and consisted mainly of net repayments of short-term debt totaling $3.4 billion, repurchases of common stock totaling $2.3 billion, repayments of subsidiary debt totaling $921 million and distributions to noncontrolling interests of $129 million.

For a discussion of recent financing transactions and BHE shareholders' equity transactions, refer to Notes 6 and 13 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. In addition, in October 2024, EGTS entered into an agreement authorizing the issuance of $150 million of its 5.02% Senior Notes due 2034, subject to the satisfaction of certain customary terms and conditions, with an expected closing date in December 2024. EGTS intends to use the net proceeds from the sale of the notes to repay its $111 million Senior Notes due December 15, 2024, and for general corporate purposes.

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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.

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
	2023		2024		2024
Capital expenditures by business:
PacifiCorp	$	2,250	$	2,157	$	3,052
MidAmerican Funding	1,339		1,100		1,535
NV Energy	1,386		1,274		1,876
Northern Powergrid	405		474		666
BHE Pipeline Group	827		713		1,140
BHE Transmission	159		181		253
BHE Renewables	111		283		501
HomeServices	30		4		7
BHE and Other(1)	19		50		47
Total	$	6,526	$	6,236	$	9,077

Capital expenditures by type:
Wind generation	$	1,109	$	614	$	971
Electric distribution	1,436		1,618		2,315
Electric transmission	1,201		1,101		1,664
Natural gas transmission and storage	649		559		900
Solar generation	305		218		302
Electric battery and pumped hydro storage	123		134		210
Wildfire mitigation	228		314		577
Other	1,475		1,678		2,138
Total	$	6,526	$	6,236	$	9,077

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

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

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

◦Construction of wind-powered generating facilities at MidAmerican Energy totaling $143 million and $460 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned spending for the construction of additional wind-powered generating facilities totals $22 million for the remainder of 2024.

◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $169 million and $48 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned spending for the repowering of wind-powered generating facilities totals $104 million for the remainder of 2024. MidAmerican Energy expects its repowered facilities to meet Internal Revenue Service guidelines for the re-establishment of PTCs under the prevailing wage and apprenticeship guidelines 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 $249 million and $540 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned spending for the construction of additional wind‑powered generating facilities and those at acquired sites totals $202 million for the remainder of 2024 and is primarily for the Rock River I, Rock Creek I and Rock Creek II wind‑powered generating facilities totaling approximately 640 MWs that are expected to be placed in‑service in 2024 and 2025.

◦Repowering of wind-powered generating facilities at BHE Renewables totaling $5 million and $13 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Repowered facilities were placed in-service in the first quarter of 2024.

•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, 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. 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. Growth expenditures include spending for the following:

◦PacifiCorp's transmission investments primarily reflect costs associated with major transmission projects totaling $376 million and $486 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned spending for major transmission segments that are expected to be placed in‑service in 2024 through 2031 totals $122 million for the remainder of 2024.

◦Nevada Utilities' Greenlink Nevada transmission expansion program. Expenditures for the expansion program and other growth projects totaled $162 million and $141 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned spending for the expansion program estimated to be placed in-service in 2027 through 2028 and other growth projects totals $173 million for the remainder of 2024.

•Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, spending for customer driven expansion projects. Operating expenditures include 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, LNG terminalling infrastructure needs to serve existing and expected demand and asset modernization programs.

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

◦Construction and operation of solar-powered generating facilities at MidAmerican Energy. For the nine-month periods ended September 30, 2024 and 2023, solar generation spending totaled $1 million and $11 million, respectively. Planned spending totals $2 million for the remainder of 2024.

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◦Construction of solar-powered generating facilities at the Nevada Utilities totaled $114 million and $258 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned spending totals $19 million for the remainder of 2024. Construction includes expenditures for a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that was developed in Clark County, Nevada which commenced commercial operation in May 2024 and a 400-MW solar photovoltaic facility with an additional 400-MW of co-located battery storage that would be developed in Churchill County, Nevada with ownership share approved by the PUCN of 10% Nevada Power and 90% Sierra Pacific with commercial operations expected by early 2027.

◦Construction of a solar-powered generating facility at BHE Renewables totaling $101 million and $28 million for the nine-month periods ended September 30, 2024 and 2023. Planned spending totals $60 million for the remainder of 2024. 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 mid 2025.

•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 was developed in Clark County, Nevada which commenced commercial operation in May 2024 and a 400-MW battery energy storage system co-located with a 400MW solar photovoltaic facility that would be developed in Churchill County, Nevada with ownership share approved by the PUCN of 10% Nevada Power and 90% Sierra Pacific with commercial operations expected by early 2026. Total spending was $98 million and $106 million for the nine-month period ended September 30, 2024 and 2023, respectively. Planned spending totals $27 million for the remainder of 2024.

•Wildfire mitigation includes growth and operating expenditures, including spending for the following:

◦Expenditures at PacifiCorp totaling $264 million and $197 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned spending for wildfire mitigation totals $215 million for the remainder of 2024, and is comprised of reducing wildfire risk in fire high consequence areas by conversion of overhead systems to underground, replacing overhead bare wire conductor with covered conductors and deployment of advanced protection devices for faster fault detection. The efforts will also include an expansion of the weather station network and predictive tools for situational awareness across the entire service territory.

◦Expenditures at the Nevada Utilities totaling $33 million and $26 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned spending for wildfire mitigation totals $43 million for the remainder of 2024, and is comprised of reducing wildfire risk in Tier 3 HTAs by rebuilding distribution lines with covered conductor, converting overhead distribution lines to underground and copper wire and pole replacement projects.

•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, 2024, 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, 2023, 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, 2023, and new regulatory matters occurring in 2024.

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PacifiCorp

Utah

In May 2023, PacifiCorp filed its energy balancing account application to recover deferred net power costs from 2022. The filing requested a rate increase of $98 million, or 4.6%, which was effective on an interim basis July 1, 2023. The UPSC held a hearing in January 2024 and issued final approval in February 2024.

In May 2024, PacifiCorp filed its energy balancing account application to recover deferred net power costs from 2023. The filing requested an increase of $280 million to what is currently in rates, which PacifiCorp proposed to recover over a two‑year period with interest, resulting in a first-year rate increase of $52 million, or 2.4%, effective on an interim basis July 1, 2024. In June 2024, the UPSC approved an interim rate change effective July 1, 2024. As part of the interim rate change, the UPSC rejected PacifiCorp's proposal to recover the incremental costs over two years, resulting in a rate increase of $256 million, or 11.6%.

In June 2024, PacifiCorp filed a general rate case requesting a rate increase of $667 million over two years. The request sought an increase of $382 million, or 16.2%, effective February 28, 2025, and a second increase of $285 million, or 12.1%, effective January 1, 2026. The request included increased energy costs, capital investments in transmission and wind‑powered generating facilities and higher insurance premiums for third-party liability coverage. In August 2024, PacifiCorp filed an amended application that removed the second rate increase that was associated with net power costs and updated costs associated with insurance premiums. The amended filing requested a rate increase of $394 million, or 16.7%, effective February 23, 2025. In October 2024, in response to dispositive motions filed by intervenors, the UPSC ordered that the test period costs associated with insurance premiums and wildfire mitigation be removed from the general rate case and consolidated into the separate existing dockets – the insurance premium deferral proceeding and the approval of the wildfire mitigation plan, respectively. The UPSC required that the parties meet to determine "placeholder" amounts for these items in the general rate case pending final decisions in the other proceedings. PacifiCorp filed an objection to the decision in October 2024. Subsequently in October 2024, the UPSC affirmed the order and asked for additional comments from parties on timing and consolidation with a potential effective date for all matters by April 25, 2025.

Oregon

In February 2024, PacifiCorp filed a general rate case requesting a rate increase of $322 million, or 17.9%, to become effective January 1, 2025. The request included new capital investments in transmission and wind-powered generating facilities, higher insurance premiums for third-party liability coverage and proposed funding for a catastrophic fire fund. In July 2024, PacifiCorp filed updated testimony that removed the proposed funding for a catastrophic fire fund and included a reduction in the requested return on equity. As a result of the updates, the requested rate increase was revised to $214 million, or 11.9%. In August 2024, PacifiCorp filed updated testimony in which the requested rate increase was revised to $208 million, or 11.2%.

In February 2024, PacifiCorp filed its transition adjustment mechanism requesting approval to update net power costs for 2025. The filing requested a rate decrease of $18 million, or 1.0%, subject to updates throughout the course of the proceeding, to become effective January 1, 2025. In July 2024, a joint stipulation and supporting testimony was filed settling all issues. Concurrent with the stipulation, PacifiCorp filed its transition adjustment mechanism reply update, which reflected a total rate decrease of $23 million, or 1.3%, subject to final net power cost updates in November 2024. The OPUC approved the joint stipulation in September 2024.

In May 2024, PacifiCorp filed its 2023 PCAM requesting recovery of the difference between actual net power costs and base net power costs established in the 2023 transition adjustment mechanism. The filing requested recovery of $122 million, which PacifiCorp proposed to recover over a two‑year period with interest, resulting in a rate increase of $64 million, or 3.5%, effective October 1, 2024. In October 2024, a joint stipulation and supporting joint brief was filed settling all issues. Under the stipulation, PacifiCorp would recover $118 million over a two‑year period with interest, resulting in a non-residential rate increase of $37 million, or 2.0%, effective December 1, 2024, and a residential rate increase of $26 million, or 1.4%, effective April 1, 2025. A final decision from the OPUC is pending.

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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 included 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 third-party liability coverage. In November 2023, the WPSC approved a rate increase of $54 million, or 8.3%, effective January 1, 2024. The approved rate increase reflected a reduction in the requested return on equity compared to what was sought by PacifiCorp, the exclusion of the increased insurance premium costs and a reduction in net power costs determined by the WPSC. The WPSC's reduction in net power costs reflects the exclusion of the costs associated with the Washington Cap and Invest program. In January 2024, PacifiCorp filed an application for rehearing requesting the WPSC consider three items, including the WPSC's net power costs adjustment, costs associated with the Washington Cap and Invest program and the opportunity to revise PacifiCorp's initial revenue requirement request for updates, corrections and revisions reflected in rebuttal testimony. In April 2024, the WPSC denied a rehearing in an open meeting, and PacifiCorp is pursuing review of this decision in federal and state courts in Wyoming.

In April 2024, PacifiCorp filed its energy cost adjustment and renewable energy credit and sulfur dioxide credit mechanisms to recover deferred net power costs from 2023. The combined filing requested a rate increase of $86 million, or 12.3%, to be effective on an interim basis on July 1, 2024. In June 2024, PacifiCorp updated the filing to reduce the amount of deferred net power costs included in the request by $2 million. In July 2024, the WPSC approved an interim rate increase of $84 million, or 11.9%, effective July 1, 2024.

In August 2024, PacifiCorp filed a general rate case requesting a rate increase of $124 million, or 14.7%, to become effective June 1, 2025. The request included new capital investments in transmission and wind-powered generating facilities, a new insurance cost adjustment mechanism and proposed adjustments to the energy cost adjustment mechanism.

Washington

In March 2023, PacifiCorp filed a general rate case requesting a two-year rate plan with a rate increase that included 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. In December 2023, a multi-party settlement stipulation was filed to update the requested rate increase to $14 million, or 3.4%, to become effective March 19, 2024, and $21 million, or 5.0%, to become effective March 1, 2025. A hearing on the settlement stipulation was held in January 2024, and the WUTC accepted the stipulation on March 19, 2024. PacifiCorp submitted the required compliance filings with an updated net power cost forecast, resulting in a rate increase of $11 million, or 2.7%, effective April 3, 2024.

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. In November 2023, the WUTC suspended PacifiCorp's PCAM filing in response to an intervening party's petition for adjudication request. PacifiCorp's hedging practices were evaluated in the adjudicative proceeding that was heard in June 2024. On October 30, 2024, the WUTC found that PacifiCorp's hedging practices were prudent for 2022 and approved recovery of $70 million of net power costs over a two-year period.

In June 2024, PacifiCorp filed its PCAM to recover deferred net power costs from 2023. The filing requested a rate increase of $81 million, or 20.0%, effective October 1, 2024. In September 2024, the WUTC suspended PacifiCorp's 2023 PCAM filing in response to WUTC staff's submission for adjudication due to the pending nature of the 2022 PCAM.

Idaho

In April 2024, PacifiCorp filed its energy cost adjustment mechanism to recover deferred net power costs from 2023. The filing requested a rate increase of $33 million, or 10.5%, effective June 1, 2024. In May 2024, the IPUC approved a rate increase of $30 million, or 9.7%, effective June 1, 2024, that excluded costs associated with the Washington Cap and Invest program. In June 2024, PacifiCorp filed a petition for reconsideration of the disallowed costs, and in July 2024, the IPUC granted the request for reconsideration. PacifiCorp filed comments in September 2024, and an IPUC decision on the petition for reconsideration is pending.

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In May 2024, PacifiCorp filed a general rate case requesting a rate increase of $92 million over two years. The request seeks an increase of $66 million, or 19.4%, effective January 1, 2025, and a second increase of $26 million, or 7.4%, effective January 1, 2026. The request included increased energy costs, capital investments in transmission and wind‑powered generating facilities, higher insurance premiums for third-party liability coverage and proposed funding for a catastrophic fire fund. In October 2024, the IPUC issued a notice of suspension regarding PacifiCorp's general rate case application, suspending the rate effective date for 60 days, from January 1, 2025, to March 2, 2025. The notice also authorized PacifiCorp to track for future recovery the revenue requirement increase ultimately granted by the IPUC from January 1, 2025, until the new rates become effective.

California

In September 2023, PacifiCorp filed its 2024 combined ECAC and GHG related costs 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 a $6 million decrease to the GHG rate. In January 2024, PacifiCorp filed a joint motion for approval of the GHG portion of the filing. In March 2024, the CPUC approved the joint motion and the GHG related changes went into effect March 12, 2024 and April 1, 2024. In June 2024, PacifiCorp filed a joint motion for approval to settle the ECAC portion of the filing. The joint motion would result in an overall rate increase of $23 million, or 19.3%. The ECAC settlement adjusted the ECAC balancing rate to be amortized over 21 months and maintained a one-year amortization for the ECAC offset rate. PacifiCorp anticipates a final CPUC decision approving the settlement in the fourth quarter of 2024.

In September 2024, PacifiCorp filed to recover costs recorded in the catastrophic events memorandum account requesting a rate increase of $15 million, or 10.2%, over approximately two years, effective March 1, 2025.

Deferral Accounting Treatment for Increased Costs Associated with Wildfires

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 third-party liability coverage and costs associated with potential liability for future catastrophic wildfires. The CPUC issued a proposed decision in February 2024; however, in March 2024, PacifiCorp filed a motion to stay the proceeding in order to re-evaluate the allocation of wildfire liability costs to California customers, and in April 2024, the CPUC granted the stay until December 2024.

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 associated with third-party liability coverage. In December 2023, PacifiCorp filed a deferral application with the WPSC for the increased insurance premium costs. The IPUC and the OPUC approved the request for authorization to defer the increased insurance premium costs in December 2023 and January 2024, respectively. In March 2024, the UPSC denied the application for deferral accounting. In April 2024, PacifiCorp filed a request for review and reconsideration of the legal conclusions in the UPSC order. In May 2024, the UPSC granted PacifiCorp's application for rehearing, and scheduling conferences are ongoing. In October 2024, the WPSC approved an August 2024 all-party stipulation allowing for deferred accounting for the increased insurance premium costs.

MidAmerican Energy

Iowa

In June 2023, MidAmerican Energy filed a request with the IUC for an increase in its Iowa retail natural gas rates, which would increase revenue by $39 million annually or 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. In January 2024, MidAmerican Energy filed a non-unanimous settlement with the Office of Consumer Advocate, which would allow for an increase in revenue of $30 million annually, or an average increase to customer's bills of 4.6%. On March 29, 2024, the IUC issued its order approving the non-unanimous settlement agreement and final rates were implemented on July 1, 2024.

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Iowa Transmission Legislation

In June 2020, Iowa enacted legislation that grants incumbent electric transmission owners the right to construct, own and maintain electric transmission lines that have been approved for construction in a federally registered planning authority's transmission plan and that connect to the incumbent electric transmission owner's facility. This Right of First Refusal ("ROFR") law gave 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. In October 2020, national transmission interests filed a lawsuit that challenged the law on state constitutional grounds. After an appeal in which the Iowa Supreme Court held the national transmission interests had standing to challenge the law and remanded the case to the Iowa district court for a decision on the merits, the district court, in December 2023, found the legislature impermissibly "log-rolled" the ROFR law into a state appropriations bill in violation of the title and single-subject provisions of the Iowa Constitution and held that the law was unconstitutional and unenforceable. The district court issued an injunction that enjoins MidAmerican Energy and ITC Midwest from further developing the Long Range Transmission Projects ("LRTP") Tranche 1 projects to the extent authority to construct was claimed pursuant to, under, or in reliance on the invalid ROFR law, but allows either company to proceed with projects assigned in a manner not relying on the claimed existence of the law.

In April 2024, MidAmerican Energy and ITC Midwest filed an appeal to the Iowa Supreme Court that challenges the application of the injunction to the LRTP Tranche 1 projects; MISO filed an amicus brief that supports the positions taken by MidAmerican Energy and ITC Midwest. The appeal remains pending before the Iowa Supreme Court, and MidAmerican Energy expects a ruling on the appeal by early to mid-2025. The district court injunction remains in effect while the appeal is pending.

In May 2024, MISO issued a public notice that advised it was proceeding with a variance analysis under its tariff to assess actions that could be taken to mitigate the obstacle to construct posed by the district court injunction. The notice confirmed the injunction did not change ownership of the projects or cause any project facility classification to be modified to a competitive transmission facility under MISO's tariff. It also confirmed the injunction did not suspend either company's obligation to construct the projects under MISO's tariff. In August 2024, MISO issued notice of the outcome of its variance analysis, determining that a mitigation plan was the appropriate outcome under the MISO tariff. As part of the mitigation plan, MISO's Competitive Transmission Executive Committee determined the projects should be assigned to the incumbent transmission owners under the transmission owners agreement, which results in no change to the project assignments. MISO's notice reaffirmed that MidAmerican Energy and ITC Midwest remain obligated to construct the projects under MISO's tariff. In October 2024, the national transmission interests filed a motion with the district court that asks the court to enforce the injunction and enjoin MidAmerican Energy and ITC Midwest from proceeding with the projects under MISO's mitigation plan. MidAmerican Energy is resisting the motion.

The litigation regarding the ROFR law would only affect 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)

Regulatory Rate Review

In February 2024, Sierra Pacific filed electric and gas regulatory rate reviews with the PUCN that requested annual revenue increases of $95 million, or 8.8% and $11 million, or 4.9%, respectively. Sierra Pacific filed the certification filing that updated the electric and gas filings to requested annual revenue increases of $96 million, or 9.5% and $12 million, or 6.4%, respectively. Hearings in the cost of capital phase were held in June 2024 and the hearings for the revenue requirement phase were held in July 2024. The hearings in the rate design phase were held in August 2024. In September 2024, the PUCN issued an order approving an increase in base rates for electric of $40 million and for gas of $8 million. In October 2024, Sierra Pacific filed a petition for reconsideration and clarification of the order. The petition for reconsideration is still pending a PUCN order.

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BHE Pipeline Group

BHE GT&S

In November 2023, Carolina Gas Transmission, LLC ("CGT") filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective January 1, 2024. CGT's current rates were established by a 2011 settlement. CGT proposed an annual cost-of-service of $167 million, and requested increases in various rates, including Zone 1 general system transmission rates by 84% and Zone 2 general system transmission rates by 23%. In December 2023, the FERC suspended the rate changes for five months following the proposed effective date, until June 1, 2024, subject to refund. In August 2024, a settlement agreement was filed with the FERC, resolving CGT's general rate case for its FERC-jurisdictional services and providing for increased service rates and depreciation rates. Under the terms of the settlement agreement, CGT's rates result in an average annual increase to firm transmission revenues of $25 million over the settlement period and an increase in annual depreciation expense of $8 million, compared to the rates in effect prior to June 1, 2024. FERC approval of the settlement is expected late 2024 or early 2025.

BHE Transmission

AltaLink

2024-2025 General Tariff Application

In April 2023, AltaLink filed its 2024-2025 GTA with the AUC. In August 2023, AltaLink filed an amendment to its 2024-2025 GTA in response to the unprecedented wildfire events that AltaLink experienced in Alberta, Canada in May and June 2023. The amendment increased AltaLink's Wildfire Mitigation Plan capital expenditures from C$16 million to C$39 million in 2024 and from C$15 million to C$38 million for 2025. In December 2023, the AUC approved 2024 interim refundable transmission tariffs for AltaLink, including monthly tariffs for PLP and KLP, of C$74 million per month effective January 1, 2024. AltaLink advised the AUC that it reached a negotiated settlement with customer groups on the majority of its 2024-2025 GTA and filed the agreement with the AUC for approval in December 2023. In February 2024, the AUC issued its decision with respect to AltaLink's 2024-2025 GTA, approving the negotiated settlement agreement as filed. The agreement did not include AltaLink's proposed wildfire deferral account, certain components of the wildfire mitigation plan, and actual and forecast salvage expenditures from its 2019-2023 GTA and 2024-2025 GTA, respectively.

In June 2024, the AUC issued its decision with respect to AltaLink's 2024-2025 GTA and matters excluded from the negotiated settlement. The AUC approved the previously denied C$99 million actual salvage costs incurred from 2019 to 2021 and the 2022-2025 salvage expenditures of C$124 million, subject to changes arising from revised wildfire mitigation capital expenditures. The AUC also approved AltaLink's transition to the capitalization of site preparation or salvage costs for capital replacement projects starting in 2024. However, the AUC did not approve the recovery of C$11 million of debt and equity returns for 2022-2023 related to the previously denied C$99 million salvage costs. The AUC also approved C$29 million of forecast capital expenditures, including capitalized salvage, related to AltaLink's 2024-2025 Wildfire Mitigation Plan, which is generally consistent with the approved wildfire capital expenditures in AltaLink's 2022-2023 Wildfire Mitigation Plan. The AUC did not approve AltaLink's request, filed in August 2023, for an incremental C$46 million in forecast wildfire mitigation capital expenditures. The AUC denied AltaLink's proposed wildfire damages deferral account stating that AltaLink currently has multiple layers of protection to address the risk of liability for wildfire-related third-party damages.

AltaLink filed its compliance filing in August 2024 which also reflected the 9.28% return on equity for 2024 approved in the Generic Cost of Capital proceeding and the capitalization of site preparation costs as approved by the AUC. As a result, AltaLink's revised transmission tariffs are C$908 million for 2024 and C$914 million for 2025.

In September 2024, AltaLink responded to information requests from the AUC and one intervener on AltaLink's directive responses in its compliance filing related to wildfire mitigation. An AUC decision on the compliance filing is expected by the end of 2024.

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2023 Wildfire and Storm Cost Recovery Application

In December 2023, AltaLink filed an application with the AUC to recover all costs incurred as a result of the 2023 spring wildfire and storm events. The application includes capital expenditures of C$19 million and salvage expenditures of C$6 million. In March 2024, AltaLink submitted responses to information requests. The AUC heard arguments in May 2024. In July 2024, the AUC approved, on an interim basis, the recovery of C$19 million of expenditures through the self-insurance reserve account over the 2024 and 2025 period. The AUC also approved C$6 million of salvage expenditures, on an interim basis, through the net salvage reserve account.

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, 2023, and new environmental matters occurring in 2024.

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.

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Cross-State Air Pollution Rule

The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate matter, from down-wind sources in the eastern U.S. to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate transport of SO2 and NOx emissions in 27 Eastern and Midwestern states. In March 2022, the EPA released its Good Neighbor Rule, which contains proposed revisions to the CSAPR framework and is intended to address ozone transport for the 2015 ozone NAAQS. In March 2023, the EPA released the final Good Neighbor Rule. The electric generation sector remains the key industry regulated by the rule and will be subject to emissions allowance trading, which was slated to begin in summer 2023, but is on hold during the pendency of litigation. 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 and is seeking a request of approval from the PUCN to convert the existing coal-fueled generating facility at the North Valmy Generating Station to a cleaner natural gas-fueled generating facility. The EPA also deferred final action for Wyoming, pending further review of updated air quality and contribution modeling and analysis. The EPA ultimately approved Wyoming's SIP in December 2023. 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. Circuits. 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 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. 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. However, 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. The U.S. Supreme Court heard oral arguments on the emergency stay requests on February 21, 2024, and granted the stay requests on June 27, 2024. Consequently, enforcement of the federal ozone transport rule is halted while litigation over the rule continues in the D.C. Circuit Court of Appeals. On October 10, 2024, the EPA sent for White House Office of Management and Budget pre-publication review an action further explaining how the Good Neighbor Rule can function with fewer states than the 23 originally intended, after the U.S. Supreme Court stayed its implementation over doubts about the program's viability and fairness. The rule addresses the D.C. Circuit's September 2024 partial remand of the rule's record. This response rule is anticipated to be issued by the end of 2024.

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. BHE GT&S operates 157 affected units; Northern Natural Gas operates 18 affected units; and Kern River is not affected by the final rule.

On a parallel track, the Tenth Circuit Court of Appeals granted a motion filed by the EPA on February 27, 2024, transferring the Utah and Oklahoma SIP disapproval litigation to the D.C. Circuit. The D.C. Circuit granted a request to abate the litigation while PacifiCorp, Utah and other petitioners sought a review of the transfer order before the U.S. Supreme Court. The U.S. Supreme Court announced on October 21, 2024, that it would hear this and a related case concerning proper venue under the Clean Air Act. Arguments are anticipated to take place in spring 2025, with a decision by June 2025. In a July 5, 2024, motion filed with the D.C. Circuit Court of Appeals, the EPA asked the court to consolidate and expedite all the remaining cases on the Ozone Transport Rule. The agency proposed a briefing schedule that would have opening briefs filed August 20, 2024, and final briefs filed November 12, 2024, with oral argument set before the end of 2024. On July 26, 2024, the D.C. Circuit Court of Appeals continued abatement of the case until the U.S. Supreme Court acts on the petitions.

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On January 24, 2024, the EPA released a supplemental proposal to expand the Good Neighbor Plan to an additional five states - Arizona, Iowa, Kansas, New Mexico and Tennessee. The EPA cites new modeling showing the states' significant contribution to ozone problems in downwind states. Under the proposal, fossil-fueled generating facilities in these five states would be required to participate in the allowance-based ozone season nitrogen oxides emissions trading program beginning in 2025. Relevant to the Registrants, the new state budget for Iowa was determined by optimizing existing post-combustion controls and installation of neural networks. It does not appear that Iowa's revised budget would require additional emissions control equipment because the EPA determined that Iowa contributed to downwind monitor violations only in 2023 (the base year for the Good Neighbor Plan) and not in 2026 (the latest compliance date under the Good Neighbor Plan). However, because the EPA determined that Arizona contributes to modeled violations in both 2023 and 2026, the requirements for that state are more stringent and may drive installation of additional controls. The EPA accepted comments on the supplemental proposal through May 16, 2024. The EPA submitted the final supplemental rule for interagency review in September 2024 and it is anticipated that the final supplemental rule will be issued by the end of 2024.

Until additional rulemaking is completed and litigation is exhausted, the potential impacts to the relevant Registrants cannot be determined.

Regional Haze

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

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The state of Wyoming issued two regional haze SIPs requiring the installation of SO2, NOx and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the SO2 SIP in December 2012 and the EPA's approval was upheld on appeal by the Tenth Circuit in October 2014. The EPA's final action on the Wyoming SIP in 2014 approved the state's plan to have PacifiCorp install low-NOx burners at Naughton Units 1 and 2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units 1 through 4 between 2015 and 2022, and low-NOx burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility, requiring the installation of SCR controls by 2019. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming and several environmental groups also filed an appeal of the EPA's final action. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit in the appeal. The parties worked to mediate claims under the Wyoming regional haze requirements until the abatement on litigation was lifted in September 2022. On August 15, 2023, the Tenth Circuit ruled in favor of Wyoming and remanded the Wyodak portion of Wyoming's state plan to EPA for further review, with instructions to give appropriate deference to the state's determinations. For Naughton Units 1 and 2, the court determined the 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 on 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. The order includes a one-year deadline to complete the SIP revision. 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 selective catalytic reduction 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 requirements through compliance with the Wyoming consent decree and Wyoming's 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. On April 10, 2024, the EPA proposed approval of Wyoming's regional haze SIP revision for the first planning period. The SIP includes enforceable emissions and heat input limits at Jim Bridger units 1 and 2, consistent with the conversion of those units to natural gas. The EPA accepted comments on the proposed approval through May 10, 2024, and final action is anticipated by fall 2024.

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Nevada, Utah and Wyoming each submitted regional haze SIPs for the regional haze second planning period to the EPA and received completeness determinations in August 2022. The EPA was required to make final determinations on the SIPs by August 2023. The states of Utah and Wyoming filed deadline suits in the Utah and Wyoming federal district courts in October and November 2023, respectively, asking the court to require the EPA to perform its statutory duty to approve or disapprove the states' regional haze second planning period SIPs. PacifiCorp also filed a deadline suit in both courts. Three environmental groups filed similar deadline suits in the federal district court in Washington, D.C. for seven different states on June 15, 2023. The environmental groups amended their lawsuit on November 10, 2023, after Wyoming and PacifiCorp's suits were filed, to include Utah's and Wyoming's state plans. PacifiCorp intervened in the D.C. district court case and asked that court to stay the Utah and Wyoming cases in that court while they proceed in the relevant federal courts in Utah and Wyoming. The EPA published a proposed regional haze second planning period settlement agreement with environmental groups on March 29, 2024, that would require the agency to take final action approving or denying SIPs under a rolling series of deadlines through 2026. The proposed consent decree was subject to public comments through April 29, 2024, before being adopted by the court on July 12, 2024. The consent decree sets final deadlines for the EPA to approve or disapprove the haze plans of 32 states. Relevant to the Registrants, the EPA would be required to take final action on Utah's and Wyoming's plans by November 22, 2024; Texas' plan by May 30, 2025; and Nevada's plan by December 15, 2025. Utah, Wyoming and PacifiCorp withdrew the deadline suits in their respective state federal district courts. On August 1, 2024, the EPA proposed to partially approve and partially disapprove Wyoming's SIP for the second planning period and accepted comments on the proposal through September 3, 2024. On August 19, 2024, the EPA proposed to partially approve and partially disapprove Utah's SIP for the second planning period and accepted comments on the proposal through September 18, 2024. Should the EPA finalize the proposed disapproval, it is required to impose a federal implementation plan within two years unless Wyoming and Utah submit a new plan that the agency approves. On October 15, 2024, the EPA proposed to partially approve and partially disapprove Texas' SIP for the second planning period and will accept comments on the proposal through November 14, 2024. Until the cases are resolved and additional rulemaking is completed by the EPA, any potential impacts to the relevant Registrants cannot be determined.

In August 2023, the Nevada Utilities filed a Joint Application for approval of the Fifth Amendment to the 2021 Joint Integrated Resource Plan. The Fifth Amendment seeks, in part, to convert the existing coal-fueled North Valmy Generating Station to natural gas and to continue operation of Tracy units 4 and 5 to 2049. Based on this filing, the state of Nevada partially withdrew portions of the State Implementation plan for Regional Haze to re-evaluate emission control measures that may be necessary to achieve reasonable progress during the second implementation period of the Regional Haze Rule in Nevada. The state of Nevada expects to submit a revised SIP to the EPA in early 2025, allowing sufficient time for the EPA to act on the plan according to the schedule in the March 2024 consent decree.

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 Iowa Department of Natural Resources issued a SIP in August 2023 that requires operational improvements to existing control equipment at MidAmerican Energy's Louisa Generation Station and Walter Scott, Jr. Energy Center - Unit 3. Iowa submitted that plan to the EPA in fall 2023. On August 2, 2024, the EPA proposed a rule to approve Iowa's SIP as submitted. The EPA accepted comment on the proposal through September 3, 2024. Final action on the SIP is anticipated by the end of 2024.

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Federal Greenhouse Gas Standards

In June 2014, the EPA released proposed regulations to address GHG emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on the "best system of emission reduction." In August 2015, the final Clean Power Plan was released, which established the best system of emission reduction as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The Clean Power Plan was stayed by the U.S. Supreme Court in February 2016. On June 19, 2019, the EPA repealed the Clean Power Plan and issued the Affordable Clean Energy rule. In the Affordable Clean Energy rule, the EPA determined that the best system of emission reduction for existing coal-fueled generating facilities is limited to actions that result in heat rate improvements at individual units. On January 19, 2021, the D.C. Circuit vacated and remanded the Affordable Clean Energy rule to the EPA, finding that the rule "rested critically on a mistaken reading of the Clean Air Act" that limited the best system of emission reduction to actions taken at a facility. In October 2021, the U.S. Supreme Court agreed to hear an appeal of that decision. The U.S. Supreme Court issued its decision regarding the scope of the EPA's authority to regulate greenhouse gas emissions under the Clean Air Act in June 2022. The U.S. Supreme Court held that the "generation shifting" approach in the Clean Power Plan exceeded the powers granted to the EPA by Congress, although the court did not address whether the EPA may only adopt measures applied at the individual source as it did in the Affordable Clean Energy rule. A key area where the EPA went astray was using the Clean Power Plan to give states the option to promulgate regulations that would encourage "generation shifting," or moving away from higher-polluting power sources like coal to lower-polluting sources like natural gas or renewables. The U.S. Supreme Court reversed the D.C. Circuit's vacatur of the Affordable Clean Energy rule and remanded the case for further proceedings. 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). On April 25, 2024, the EPA finalized rules setting greenhouse gas emissions standards for new natural gas-fueled combustion turbines and existing coal-, gas- and oil-fueled steam units. The EPA deferred action on emissions standards for existing natural gas-fueled combustion turbines. New natural gas-fueled combustion turbines are expected to utilize lower-emitting fuels and operate as highly efficient generation. Additionally, new baseload combustion turbines exceeding a 40% annual capacity factor must meet an emission limit equivalent to operating with carbon capture and sequestration beginning January 1, 2032. The EPA identified carbon capture and sequestration as the technology basis for the emissions standards for coal units. Coal-fueled units that will operate after December 31, 2038, must meet emission limits equivalent to operating with carbon capture and sequestration beginning January 1, 2032. Other units are anticipated to co-fire with natural gas and retire prior to January 1, 2039 or convert to natural gas operations and meeting emission limits corresponding to capacity factors. Emission limits for individual generating units must be specified in state compliance plans, which must be submitted to EPA within 24 months of the rule's publication in the Federal Register. Facilities are not required to retrofit with carbon capture technology but must meet emission limits based on the technology. PacifiCorp operates 9 coal-fueled units and MidAmerican Energy operates 6 coal-fueled units that are currently not planned for retirement or conversion to natural gas operations by 2032, when the emissions standards would take effect. NV Energy operates one natural gas-fueled unit subject to limits for new sources. The relevant Registrants continue to evaluate the rule and business plans to identify flexible compliance mechanisms that minimize costs while assuring the delivery of safe and reliable energy to customers. Litigation challenging the final rules was filed the same day they were published. The D.C. Circuit Court of Appeals denied motions to stay the rules July 19, 2024, concluding the measure is not a "major question" requiring higher judicial scrutiny and that critics have not shown they will succeed on the merits of their claims. In addition, a three-judge panel of the court downplayed any "irreparable harm" that opponents of the rule would face while the litigation plays out. The court set an expedited briefing schedule in order to hear oral arguments in fall 2024. Emergency petitions to stay the rules were quickly filed with the U.S. Supreme Court. On October 16, 2024, the U.S. Supreme Court denied petitions to stay the rule, concluding that applicants would not suffer irreparable harm since the case before the D.C. Circuit is proceeding on an expedited schedule. The D.C. Circuit Court of Appeals subsequently set oral arguments in the case for December 6, 2024; a decision is expected by June 2025. Until litigation is exhausted, the relevant Registrants cannot determine the full impacts of the final rule.

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New Source Performance Standards for Methane Emissions

In August 2020, the EPA finalized regulations to rescind standards for methane emissions from the oil and gas sector. The changes eliminate requirements to regulate methane emissions from the production, processing, transmission and storage of oil and gas. The rule was immediately challenged by environmental and tribal groups, as well as numerous states. In January 2021, the D.C. Circuit lifted an administrative stay and allowed the rule to take effect, finding that groups challenging the rule had not met the standard for a long-term stay. On June 30, 2021, President Biden signed into law a joint resolution of Congress, adopted under the Congressional Review Act, disapproving the August 2020 rule. The resolution reinstated the 2012 volatile organic compounds standards and the 2016 volatile organic compounds and methane standards for the oil and natural gas transmission and storage segments, as well as the methane standards for the production and processing segments of the oil and gas sector. On November 2, 2021, the EPA proposed rules that would reduce methane emissions from both new and existing sources in the oil and natural gas industry. The proposals would expand and strengthen emission reduction requirements for new, modified and reconstructed oil and natural gas sources and would require states to reduce methane emissions from existing sources nationwide. The EPA issued a supplemental proposal in November 2022 to further strengthen emission reduction requirements. The EPA issued the final rule in December 2023, establishing emissions standards and leak detection and repair requirements for a number of components across the natural gas system. Kern River is not affected by the rule. Northern Natural Gas and BHE GT&S are affected by the rule and anticipate replacing some pneumatic controllers at compressor stations and seals at centrifugal and reciprocating compressors. Additional leak detection and repair surveys and reports are also anticipated. States and industry groups are challenging the rule at the D.C. Circuit. Both the D.C. Circuit and the U.S. Supreme Court have denied petitions to stay the rule during litigation. In January 2024, the EPA proposed the methane fee rule, which is required under the Inflation Reduction Act. The fee, called a waste emissions charge, will be assessed on natural gas facilities that are subject to Greenhouse Gas Reporting Program Subpart W reporting. For transmission and storage operations, any facility that reports methane emissions over the congressionally-determined "0.11% of the methane sent to sale from or through such facility" will pay a fee to the federal government. The fee can be reduced by the netting of emissions, or altogether eliminated by certain statutory exemptions. The amount of the fee is scaled, beginning at $900 per metric ton of methane over the 0.11% threshold beginning in 2025 and increasing to $1,500 per metric ton of methane over the 0.11% threshold in 2027. The relevant Registrants do not expect significant impacts from the proposed fee rule due to the combination of the excess emissions threshold, netting allowance and compliance with the methane emissions standards rule. The EPA accepted comments on the proposed fee rule through March 11, 2024. Until the EPA takes final action on the proposal, the full impacts of the rule cannot be determined.

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.

On April 25, 2024, the EPA finalized revisions to several aspects of the MATS rule following the agency's review of the 2020 Residual Risk and Technology Review. The EPA made two specific standard changes; one applicable to all covered units and one specific to the existing lignite subcategory. The relevant Registrants are not affected by the changes to the lignite subcategory. The EPA set a more stringent standard for emissions of filterable particulate matter, the surrogate standard for non-mercury metals for coal-fueled electric generating units, and required continuous emissions monitoring for filterable particulate matter to demonstrate compliance with the revised standard. Compliance is due no later than three years after the effective date of the final rule, with limited opportunities for a one-year extension. The relevant Registrants have determined that compliance can be achieved with existing controls, except for PacifiCorp's 10% stake in two units at the Colstrip generating facility, which will require either expensive equipment upgrades or retirement by July 2027. Several states and industry groups have challenged the MATS rule; motions to stay were denied by the D.C. Circuit and the U.S. Supreme Court. Until litigation is exhausted, PacifiCorp cannot determine the full impacts of the final rule for the Colstrip units.

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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 April 25, 2024, the EPA finalized 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.

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 residuals 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 residuals 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 residuals. 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 residuals 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. In October 2023, a new surface impoundment was placed into service at the Jim Bridger facility. At the time the rule was published in April 2015, MidAmerican Energy owned or operated nine surface impoundments and four landfills that contained coal combustion residuals. 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 residuals. As of July 10, 2024, all of the surface impoundments have been closed. 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 residuals. 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 residuals 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.

57

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. 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. On April 25, 2024, the EPA finalized the legacy surface impoundments rule to extend federal CCR regulatory requirements to (1) inactive CCR surface impoundments at inactive utilities and (2) CCR management units (CCRMU) at active facilities, including CCR impoundments and landfills that closed prior to the effective date of the 2015 CCR Rule, inactive CCR landfills, and other areas where CCR is managed directly on the land. The final rule includes exemptions and establishes new categories where regulation is deferred for applicable units, including CCRMU containing less than 1,000 tons of CCR, CCRMU located beneath critical infrastructure or large buildings or structures vital to the continuation of current site activities, and CCRMU that were closed prior to the effective date of the new rule. The EPA also finalized one outstanding item from the Part B Proposal in the final legacy CCR rule: the additional closure option for CCR units being closed by removal of CCR such that impacts to groundwater can be remediated after closure of the CCR unit is complete. Affected active facilities must conduct a facility evaluation and report to determine the presence of CCRMUs. The first phase of the facility evaluation is due February 9, 2026, and the second phase is February 8, 2027. Affected inactive facilities must complete an applicability report by November 8, 2024, to determine the presence of legacy surface impoundments. Legacy surface impoundments must initiate groundwater monitoring within 36 months and must initiate closure within 48 months of the rule's publication in the Federal Register. For CCRMUs, groundwater monitoring must be initiated within 48 months and closure must be initiated within 60 months of the rule's publication in the Federal Register. The relevant Registrants do not anticipate identifying any legacy surface impoundments, but do anticipate identifying CCRMUs subject to the rule. Because the facility evaluation and report requirement will determine the magnitude of compliance obligations, the relevant Registrants cannot assess the full impacts of the rule at this time.

The EPA has previously proposed additional amendments to the CCR rule, including a federal permit program, the "Part B, Part 2" rule, and a beneficial use rulemaking. The Spring 2024 Unified Agenda made available in July 2024 identifies that the EPA plans to finalize the federal permit rule in October 2024. No expected dates were provided for the other two rules.

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

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 residuals. Some of these cases have been successful in imposing liability upon companies if coal combustion residuals 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.

Separately, on June 28, 2024, the D.C. Circuit Court of Appeals issued a decision dismissing industry challenges to both the EPA's January 11, 2022, actions and interpretations related to the closure performance standards in the 2015 CCR rule and the EPA's November 28, 2022, final Part A denial for the Gavin Power Station based, in part, on those interpretations. The court ruled that the challenged actions do not amount to the kind of agency action promulgating a regulation or requirement that the court has jurisdiction to review under the Resource Conservation and Recovery Act. As a result, the court dismissed the petitions for lack of jurisdiction and clarified that EPA's actions were straightforward applications of the rule. The challenged actions concerned the EPA's determinations that (1) operators cannot close surface impoundments with groundwater leaching in and out of the unit; (2) groundwater becomes a "free liquid" as it makes its way into a coal combustion residual unit when assessing the "eliminate free liquids" performance standard; and (3) operators must minimize infiltration of liquids, including groundwater, from all directions to satisfy the infiltration performance standard. The relevant Registrants continue to review the court's decision to assess whether previously closed surface impoundments are impacted.

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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, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and loss contingencies. 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, 2023. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2023. Refer to Note 11 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.

59

PacifiCorp and its subsidiaries

Consolidated Financial Section

60

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, 2024, the related consolidated statements of operations, and changes in shareholders' equity for the three-month and nine-month periods ended September 30, 2024 and 2023, and of cash flows for the nine-month periods ended September 30, 2024 and 2023, 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, 2023, and the related consolidated statements of operations, comprehensive (loss) income, changes in shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 23, 2024, 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, 2023, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Portland, Oregon

November 1, 2024

61

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,		December 31,
	2024		2023
ASSETS
Current assets:
Cash and cash equivalents	$	381	$	138
Trade receivables, net	999		853
Other receivables, net	164		447
Inventories	763		532
Derivative contracts	11		16
Regulatory assets	891		631
Prepaid expenses	319		188
Other current assets	178		182
Total current assets	3,706		2,987
Property, plant and equipment, net	28,415		27,051
Regulatory assets	1,984		1,942
Other assets	652		630
Total assets	$	34,757	$	32,610

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

62

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	September 30,		December 31,
	2024		2023
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	1,498	$	1,560
Accrued interest	207		152
Accrued property, income and other taxes	147		65
Accrued employee expenses	147		93
Short-term debt	—		1,604
Current portion of long-term debt	416		591
Regulatory liabilities	74		70
Wildfires liabilities (Note 11)	79		4
Other current liabilities	476		437
Total current liabilities	3,044		4,576
Long-term debt	13,336		9,819
Regulatory liabilities	2,567		2,540
Deferred income taxes	3,209		3,085
Wildfires liabilities (Note 11)	1,366		1,719
Other long-term liabilities	886		899
Total liabilities	24,408		22,638
Commitments and contingencies (Note 11)
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	5,877		5,501
Accumulated other comprehensive loss, net	(9)		(10)
Total shareholders' equity	10,349		9,972
Total liabilities and shareholders' equity	$	34,757	$	32,610

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

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2024		2023		2024		2023
Operating revenue	$	1,923	$	1,676	$	4,960	$	4,487
Operating expenses:
Cost of fuel and energy	862		664		2,076		1,740
Operations and maintenance	422		356		1,248		1,056
Wildfires losses, net of recoveries (Note 11)	—		1,263		251		1,671
Depreciation and amortization	287		285		866		843
Property and other taxes	55		51		161		156
Total operating expenses	1,626		2,619		4,602		5,466
Operating income (loss)	297		(943)		358		(979)
Other income (expense):
Interest expense	(193)		(140)		(570)		(398)
Allowance for borrowed funds	33		19		92		48
Allowance for equity funds	56		40		156		101
Interest and dividend income	47		28		155		73
Other, net	4		(1)		11		4
Total other income (expense)	(53)		(54)		(156)		(172)
Income (loss) before income tax expense (benefit)	244		(997)		202		(1,151)
Income tax expense (benefit)	(80)		(345)		(174)		(485)
Net income (loss)	$	324	$	(652)	$	376	$	(666)

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

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)

(Amounts in millions)

									Accumulated
					Additional				Other		Total
	Preferred		Common		Paid-in		Retained		Comprehensive		Shareholders'
	Stock		Stock		Capital		Earnings		Loss, Net		Equity
Balance, 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
Balance, June 30, 2024	$	2	$	—	$	4,479	$	5,553	$	(10)	$	10,024
Net income	—		—		—		324		—		324
Other comprehensive income	—		—		—		—		1		1
Balance, September 30, 2024	$	2	$	—	$	4,479	$	5,877	$	(9)	$	10,349
Balance, December 31, 2023	$	2	$	—	$	4,479	$	5,501	$	(10)	$	9,972
Net income	—		—		—		376		—		376
Other comprehensive income	—		—		—		—		1		1
Balance, September 30, 2024	$	2	$	—	$	4,479	$	5,877	$	(9)	$	10,349

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

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2024		2023
Cash flows from operating activities:
Net income (loss)	$	376	$	(666)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization	866		843
Allowance for equity funds	(156)		(101)
Net power cost deferrals	(549)		(578)
Amortization of net power cost deferrals	373		156
Other changes in regulatory assets and liabilities	(35)		(101)
Deferred income taxes and amortization of investment tax credits	22		(320)
Other, net	—		1
Changes in other operating assets and liabilities:
Trade receivables, other receivables and other assets	(123)		(133)
Inventories	(231)		(45)
Derivative collateral, net	(30)		(87)
Prepaid expenses	(174)		(56)
Accrued property, income and other taxes, net	128		165
Accounts payable and other liabilities	117		392
Wildfires insurance receivable	365		(257)
Wildfires liability	(278)		1,854
Net cash flows from operating activities	671		1,067
Cash flows from investing activities:
Capital expenditures	(2,157)		(2,250)
Other, net	7		5
Net cash flows from investing activities	(2,150)		(2,245)
Cash flows from financing activities:
Proceeds from long-term debt	3,762		1,189
Repayments of long-term debt	(425)		(401)
Net (repayments of) proceeds from short-term debt	(1,604)		165
Dividends paid	—		(300)
Other, net	(4)		(4)
Net cash flows from financing activities	1,729		649
Net change in cash and cash equivalents and restricted cash and cash equivalents	250		(529)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	192		674
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	442	$	145

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

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PACIFICORP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    General

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

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2024, and for the three- and nine-month periods ended September 30, 2024 and 2023. 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, 2024 and 2023. The results of operations for the three- and nine-month periods ended September 30, 2024, 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, 2023, 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, 2024, other than the updates associated with PacifiCorp's estimates of loss contingencies related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires"). Refer to Note 11 for further discussion of the 2020 Wildfires and the 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"), collectively referred to as the "Wildfires."

(2)    New Accounting Pronouncements

In November 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items, as well as incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. PacifiCorp is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. PacifiCorp is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

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In March 2024, the United States Securities and Exchange Commission adopted final rules requiring disclosure of certain climate-related information in registrations statements and Form 10-Ks. The final rules require a registrant to disclose, among other things: material climate-related risks; activities to mitigate or adapt to such risks; information about the registrant's board of directors' oversight of climate-related risks and management's role in managing material climate-related risks; and information on any climate-related targets or goals that are material to the registrant's business, results of operations, or financial condition. Further, to facilitate investors' assessment of certain climate-related risks, the final rules require disclosure of Scope 1 and/or Scope 2 greenhouse gas emissions when those emissions are material and disclosure of the financial statement effects of severe weather events and other natural conditions. The final rules include phased-in compliance periods for all registrants, with the compliance date dependent on the registrant's filer status and the content of the disclosure. On April 4, 2024, the United States Securities and Exchange Commission voluntarily stayed implementation of the final rules, pending the completion of judicial review of consolidated challenges by the Court of Appeals for the Eighth Circuit. PacifiCorp is currently evaluating the impact of adopting the final rules on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

(3)    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,
	2024		2023
Cash and cash equivalents	$	381	$	138
Restricted cash and cash equivalents included in other current assets	58		51
Restricted cash included in other assets	3		3
Total cash and cash equivalents and restricted cash and cash equivalents	$	442	$	192

(4)    Property, Plant and Equipment, Net

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

		As of
		September 30,		December 31,
	Depreciable Life	2024		2023
Utility plant:
Generation	15 - 59 years	$	14,104	$	13,904
Transmission	60 - 90 years	8,466		8,216
Distribution	20 - 75 years	9,558		9,060
Intangible plant and other	5 - 75 years	2,906		2,833
Utility plant in-service		35,034		34,013
Accumulated depreciation and amortization		(12,318)		(11,725)
Utility plant in-service, net		22,716		22,288
Nonregulated, net of accumulated depreciation and amortization	14 - 95 years	19		18
		22,735		22,306
Construction work-in-progress		5,680		4,745
Property, plant and equipment, net		$	28,415	$	27,051

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(5)    Recent Financing Transactions

Long-Term Debt

In January 2024, PacifiCorp issued $500 million of its 5.100% First Mortgage Bonds due February 2029, $700 million of its 5.300% First Mortgage Bonds due February 2031, $1.1 billion of its 5.450% First Mortgage Bonds due February 2034 and $1.5 billion of its 5.800% First Mortgage Bonds due January 2055, for a total of $3.8 billion. PacifiCorp initially used a portion of the net proceeds to repay outstanding short-term debt and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.

Credit Facilities

In June 2024, PacifiCorp amended its existing $2.0 billion unsecured credit facility expiring in June 2026. The amendment extended the expiration date to June 2027, updated lenders and amended certain provisions of the existing credit agreement.

In June 2024, PacifiCorp terminated its existing $900 million unsecured delayed draw term loan facility expiring in June 2025 and entered into a new $900 million 364-day unsecured credit facility expiring in June 2025. This new credit facility, similar to its existing $2.0 billion unsecured credit facility, provides for loans at a variable interest rate based on the Secured Overnight Financing Rate or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities.

(6)    Income Taxes

The effective income tax rate for the three-month period ended September 30, 2023, of 35% resulted from a $345 million income tax benefit associated with a $997 million pre-tax loss, primarily related to a $1,263 million increase in wildfire loss accruals, net of expected insurance recoveries, as described in Note 11. The $345 million income tax benefit is primarily comprised of a $210 million benefit, or 21%, from the application of the federal statutory income tax rate to the pre-tax loss, a $64 million benefit, or 6%, from federal income tax credits, a $37 million benefit, or 4%, from state income tax and a $36 million benefit, or 4%, from effects of ratemaking.

The effective income tax rate for the nine-month period ended September 30, 2023, of 42% resulted from a $485 million income tax benefit associated with a $1,151 million pre-tax loss, primarily related to a $1,671 million increase in wildfire loss accruals, net of expected insurance recoveries, as described in Note 11. The $485 million income tax benefit is primarily comprised of a $242 million benefit, or 21%, from the application of the federal statutory income tax rate to the pre-tax loss, a $119 million benefit, or 10%, from federal income tax credits, a $70 million benefit, or 6%, from effects of ratemaking and a $44 million benefit, or 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,
	2024		2023		2024		2023
Federal statutory income tax rate	21	%	21	%	21	%	21	%
State income tax, net of federal income tax impacts	3		4		4		4
Income tax credits	(37)		6		(74)		10
Effects of ratemaking(1)	(18)		4		(35)		6
Valuation allowance	—		—		—		1
Other	(2)		—		(2)		—
Effective income tax rate	(33)	%	35	%	(86)	%	42	%

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

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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, 2024 and 2023, totaled $92 million and $64 million, respectively. PTCs recognized for the nine-month periods ended September 30, 2024 and 2023, totaled $150 million and $119 million, respectively.

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, 2024 and 2023, PacifiCorp received net cash payments for federal and state income taxes from BHE totaling $240 million and $255 million. As of September 30, 2024, net income taxes receivable from BHE were $70 million. As of December 31, 2023, net income taxes receivable from BHE were $114 million.

(7)    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,
	2024		2023		2024		2023
Pension:
Interest cost	$	9	$	10	$	27	$	29
Expected return on plan assets	(11)		(12)		(35)		(36)
Net amortization	2		3		7		9
Net periodic benefit cost (credit)	$	—	$	1	$	(1)	$	2
Other postretirement:
Service cost	$	—	$	—	$	—	$	1
Interest cost	3		3		9		8
Expected return on plan assets	(4)		(3)		(10)		(10)
Net amortization	—		(1)		(2)		(2)
Net periodic benefit credit	$	(1)	$	(1)	$	(3)	$	(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 2024. As of September 30, 2024, $3 million of contributions had been made to the pension plans.

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(8)    Asset Retirement Obligations

In May 2024, the United States Environmental Protection Agency ("EPA") published its final rule on legacy coal combustion residuals ("CCR") surface impoundments and CCR management units ("CCRMUs") in the Federal Register. CCRMUs include CCR surface impoundments and landfills closed before October 19, 2015 and inactive CCR landfills. The final rule contains three main components: (1) a definition for legacy CCR surface impoundments, which are inactive surface impoundments at inactive generating facilities that must adhere to the same regulations as inactive CCR impoundments at active generating facilities, barring location restrictions and liner design criteria, with customized compliance deadlines; (2) groundwater monitoring, corrective action, closure, and post closure care requirements for CCRMUs, which may be located at active generating facilities and inactive generating facilities with a legacy CCR surface impoundment; and (3) the owners and operators of inactive generating facilities must identify the presence of legacy CCR surface impoundments and comply with all rule requirements for surface impoundments; and the owners and operators of active generating facilities and inactive generating facilities with a legacy CCR surface impoundment must prepare Facility Evaluation Reports ("FERs") that identify and describe the CCRMUs and determine whether closure is required. In a manner consistent with existing CCR rules, owners and operators must publish FERs on their CCR websites in two parts, within 15 months (Part 1) and 27 months (Part 2) of the final rule's effective date in November 2024. PacifiCorp is currently evaluating the final rule and does not anticipate identifying any legacy surface impoundments, but does anticipate identifying CCRMUs subject to the rule. Due to the number of site investigations warranted by this rule and the nature of engineering and other studies required at each site, PacifiCorp is unable to reasonably estimate the potential impact, which may be material, to its asset retirement obligations.

(9)    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 has the ability to 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 10 for additional information on derivative contracts.

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

	Derivative
	Contracts -				Other		Other
	Current		Other		Current		Long-term
	Assets		Assets		Liabilities		Liabilities		Total
As of September 30, 2024
Not designated as hedging contracts(1):
Commodity assets	$	16	$	—	$	6	$	1	$	23
Commodity liabilities	(5)		—		(78)		(19)		(102)
Total	11		—		(72)		(18)		(79)
Total derivatives	11		—		(72)		(18)		(79)
Cash collateral receivable	—		—		10		1		11
Total derivatives - net basis	$	11	$	—	$	(62)	$	(17)	$	(68)
As of December 31, 2023
Not designated as hedging contracts(1):
Commodity assets	$	21	$	2	$	7	$	2	$	32
Commodity liabilities	(3)		—		(83)		(22)		(108)
Total	18		2		(76)		(20)		(76)
Total derivatives	18		2		(76)		(20)		(76)
Cash collateral receivable	(2)		—		12		—		10
Total derivatives - net basis	$	16	$	2	$	(64)	$	(20)	$	(66)

(1)PacifiCorp's commodity derivatives are generally included in rates. As of September 30, 2024, a regulatory asset of $79 million was recorded related to the net derivative liability of $79 million. As of December 31, 2023, a regulatory asset of $76 million was recorded related to the net derivative liability of $76 million.

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

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2024		2023		2024		2023
Beginning balance	$	139	$	(9)	$	76	$	(270)
Changes in fair value recognized in regulatory assets	101		(9)		265		83
Net gains (losses) reclassified to operating revenue	12		—		15		(8)
Net (losses) gains reclassified to energy costs	(173)		(32)		(277)		145
Ending balance	$	79	$	(50)	$	79	$	(50)

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Derivative Contract Volumes

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

	Unit of	September 30,	December 31,
	Measure	2024	2023
Electricity purchases, net	Megawatt hours	—	2
Natural gas purchases	Decatherms	140	153

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 thresholds 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, 2024, 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 objective credit-risk-related contingent features totaled $100 million and $108 million as of September 30, 2024 and December 31, 2023, respectively, for which PacifiCorp had posted collateral of $11 million and $12 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, 2024 and December 31, 2023, PacifiCorp would have been required to post $77 million and $84 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.

(10)    Fair Value Measurements

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

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

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

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

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

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of September 30, 2024:
Assets:
Commodity derivatives	$	—	$	23	$	—	$	(12)	$	11
Money market mutual funds	405		—		—		—		405
Investment funds	29		—		—		—		29
	$	434	$	23	$	—	$	(12)	$	445
Liabilities - Commodity derivatives	$	—	$	(102)	$	—	$	23	$	(79)
As of December 31, 2023:
Assets:
Commodity derivatives	$	—	$	32	$	—	$	(14)	$	18
Money market mutual funds	175		—		—		—		175
Investment funds	26		—		—		—		26
	$	201	$	32	$	—	$	(14)	$	219
Liabilities - Commodity derivatives	$	—	$	(108)	$	—	$	24	$	(84)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $11 million and $10 million as of September 30, 2024 and December 31, 2023, respectively.

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. 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 9 for further discussion regarding PacifiCorp's risk management and hedging activities.

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

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

	As of September 30, 2024				As of December 31, 2023
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	13,752	$	13,504	$	10,410	$	9,722

(11)    Commitments and Contingencies

Commitments

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

Fuel Contracts

During the nine-month period ended September 30, 2024, PacifiCorp entered into certain coal supply and transportation agreements totaling $1.9 billion through 2031.

Environmental Laws and Regulations

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

Lower Klamath Hydroelectric Project

In November 2022, the Federal Energy Regulatory Commission ("FERC") issued a license surrender order for the Lower Klamath Project, which was accepted by the Klamath River Renewal Corporation ("KRRC") and the states of Oregon and California ("States") in December 2022, along with the transfer of the Lower Klamath Project dams. Although PacifiCorp no longer owned the Lower Klamath Project, PacifiCorp continued to operate the facilities under an operation and maintenance agreement with the KRRC until each facility was ready for removal. PacifiCorp's obligations under the operations and maintenance agreement terminated in January 2024. Removal of the Copco No. 2 facility was completed in November 2023, and removal of the remaining three dams (J.C. Boyle, Copco No. 1 and Iron Gate) was completed in October 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 supplemental fund and equally share any additional costs above that amount to ensure dam removal and restoration is complete. In May 2024, the KRRC communicated to PacifiCorp and the States that it expects to require the $45 million of supplemental funds.

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 ASC 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.

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Wildfires

As of the date of this filing, a significant number of complaints and demands alleging similar claims related to the Wildfires have been filed in Oregon and California, including a class action complaint in Oregon associated with 2020 Wildfires for which certain jury verdicts were issued 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 complaints. Additionally, the U.S. and Oregon Departments of Justice have informed PacifiCorp that they are contemplating filing actions against PacifiCorp in connection with certain of the Oregon 2020 Wildfires. PacifiCorp is actively cooperating with the U.S. and Oregon Departments of Justice on resolving these alleged claims through alternative dispute resolution.

As of September 30, 2024, amounts sought in outstanding complaints and demands filed in Oregon and in certain demands made in California totaled approximately $3 billion, excluding any doubling or trebling of damages included in the complaints and the mass complaints described below that seek $46 billion. Generally, the complaints filed in California do not specify damages sought and are excluded from this amount. For class actions, amounts specified by the plaintiffs in the complaints include amounts based on estimates of the potential class size, which ultimately may be significantly greater than estimated. Additionally, damages are not limited to the amounts specified in the initially filed complaints as plaintiffs are frequently allowed to amend their complaints to add additional damages and amounts awarded in a court proceeding may be significantly greater than the damages specified. Oregon law provides for doubling of economic and property damages in the event the defendant is found to have acted with gross negligence, recklessness, willfulness or malice. Oregon law provides for trebling of the damages associated with timber, shrubs and produce in the event the defendant is determined to have willfully and intentionally trespassed.

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.

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

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.

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The James Case

On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp, ("James") in Oregon Circuit Court in Multnomah County, Oregon ("Multnomah County Circuit Court Oregon"). The complaint was filed by Oregon residents and businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. 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 Oregon 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 subsequently filed to appeal the class issues as described below.

In April 2023, the jury trial for James with respect to 17 named plaintiffs began in Multnomah County Circuit Court Oregon. In June 2023, the jury issued its verdict finding PacifiCorp liable to the 17 named plaintiffs and to the class with respect to the four wildfires. The jury found PacifiCorp's conduct grossly negligent, reckless and willful as to each plaintiff and the entire class. The jury awarded the 17 named plaintiffs $90 million of damages, including $4 million of economic 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 Oregon ordered trial dates for three damages phase trials described below wherein plaintiffs in each of the three damages phase trials would present evidence regarding their damages.

In January 2024, the Multnomah County Circuit Court Oregon entered a limited judgment and money award for the June 2023 James verdict. The limited judgment awards $92 million of damages based on the amounts awarded by the jury, as well as doubling of the economic damages and offsetting of any insurance proceeds received by plaintiffs. The limited judgment created a lien against PacifiCorp, attaching a debt for the money awards. PacifiCorp posted a supersedeas bond, which stays any effort to seek payment of the judgment pending final resolution of any appeals. Under Oregon Revised Statutes 82.010, interest at a rate of 9% per annum will accrue on the judgment commencing at the date the judgment was entered until the entire money award is paid, amended or reversed by an appellate court. In January 2024, PacifiCorp filed a notice of appeal associated with the June 2023 verdict in James, including whether the case can proceed as a class action and filed a motion to stay further damages phase trials. On February 14, 2024, the Oregon Court of Appeals denied PacifiCorp's request to stay the damages phase trials. On February 13, 2024, the 17 named plaintiffs filed a notice of cross-appeal as to the January 2024 limited judgment and money award. The appeals process and further actions could take several years.

In January 2024, the jury for the first James damages phase trial awarded nine plaintiffs $62 million of damages, including $6 million of economic damages and $56 million of noneconomic damages. After the jury verdict, the Multnomah County Circuit Court Oregon doubled the economic damages to $12 million and added $16 million of punitive damages using the 0.25 multiplier determined by the jury for the June 2023 James verdict, bringing the total damages awarded to $84 million. PacifiCorp requested that the Multnomah County Circuit Court Oregon judge offset the damage awards by deducting insurance proceeds received by any of the nine plaintiffs, and on March 25, 2024, the Multnomah County Circuit Court Oregon granted in large part the offset request. In April 2024, the Multnomah County Circuit Court Oregon entered a limited judgment and money award for the January 2024 James verdict. The limited judgment awards $80 million of damages based on the amounts awarded by the jury and offsetting insurance proceeds received by plaintiffs. The limited judgment created a lien against PacifiCorp, attaching a debt for the money awards. In April 2024, PacifiCorp posted a supersedeas bond, which stays any effort to seek payment of the judgment pending final resolution of any appeals. PacifiCorp amended its January 2024 appeal of the June 2023 James verdict to include the January 2024 jury verdict.

In March 2024, the jury for the second James damages phase trial awarded ten plaintiffs $42 million of damages, including $12 million of doubled economic damages, $23 million of noneconomic damages and $7 million of punitive damages using the 0.25 multiplier determined by the jury for the June 2023 James verdict. PacifiCorp requested that the Multnomah County Circuit Court Oregon judge offset the damage awards by deducting insurance proceeds received by any of the ten plaintiffs and on May 6, 2024, the Multnomah County Circuit Court Oregon granted the offset request. In June 2024, the Multnomah County Circuit Court Oregon entered a limited judgment and money award for the March 2024 James verdict. The limited judgment awards $38 million of damages based on the amounts awarded by the jury and offsetting insurance proceeds received by plaintiffs. The limited judgment created a lien against PacifiCorp, attaching a debt for the money awards. In July 2024, PacifiCorp posted a supersedeas bond, which stays any effort to seek payment of the judgment pending final resolution of any appeals. PacifiCorp further amended its appeal of the June 2023 James verdict to include the March 2024 jury verdict.

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In March 2024, settlement was reached with five commercial timber plaintiffs in the James consolidated cases, and the jury trial scheduled for April 2024 was cancelled.

In April, May, July and September 2024, five separate mass complaints against PacifiCorp naming 1,536 individual class members were filed in Multnomah County Circuit Court Oregon referencing James as the lead case. These James mass complaints make damages only allegations seeking economic, noneconomic and punitive damages, as well as doubling of economic damages. PacifiCorp believes the magnitude of damages sought by the class members in the James mass complaints to be of remote likelihood of being awarded based on the amounts awarded in the jury verdicts described above that are being appealed.

In October 2024, the Multnomah County Circuit Court Oregon issued a case management order, which sets forth nine additional damages phase trials with 10 plaintiffs per trial. The trials are scheduled to begin February 3, March 24, April 21, May 12, June 2, July 7, September 9, October 6 and December 7, 2025.

2022 McKinney Fire

According to the California Department of Forestry and Fire Protection, a wildfire began on July 29, 2022, in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California located in PacifiCorp's service territory, burning over 60,000 acres. Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged; 185 structures destroyed, including residences; 12 injuries; and four fatalities. 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.

Estimated Losses for and Settlements Associated with 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 recorded cumulative estimated probable losses associated with the Wildfires of $2,658 million through September 30, 2024. 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.

Through September 30, 2024, PacifiCorp paid $1,213 million in settlements associated with the Wildfires. As a result of the settlements, various trials have been cancelled.

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,
	2024		2023		2024		2023
Beginning balance	$	1,883	$	948	$	1,723	$	424
Accrued losses	—		1,387		251		1,928
Payments	(438)		(57)		(529)		(74)
Ending balance	$	1,445	$	2,278	$	1,445	$	2,278

As of September 30, 2024 and December 31, 2023, $79 million and $4 million of PacifiCorp's liability for estimated losses associated with the Wildfires is classified as a current liability captioned Wildfires liabilities on the Consolidated Balance Sheets. The amounts reflected as current as of September 30, 2024 reflect amounts reasonably expected to be paid out within the next year based on settlements reached as well as ongoing settlement and mediation efforts. The remainder of PacifiCorp's liability for estimated losses associated with the Wildfires as of September 30, 2024 and December 31, 2023 is classified as a noncurrent liability captioned Wildfires liabilities on the Consolidated Balance Sheets.

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The following table presents changes in PacifiCorp's receivable for expected insurance recoveries associated with the Wildfires (in millions):

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2024		2023		2024		2023
Beginning balance	$	139	$	379	$	499	$	246
Accruals	—		124		—		257
Payments received	(5)		—		(365)		—
Ending balance	$	134	$	503	$	134	$	503

As of September 30, 2024, $38 million of PacifiCorp's receivable for expected insurance recoveries was included in Other receivables, net while the remaining $96 million was included in Other assets on the Consolidated Balance Sheets. As of December 31, 2023, $350 million of PacifiCorp's receivable for expected insurance recoveries was included in Other receivables, net while the remaining $149 million was included in Other assets on the Consolidated Balance Sheets. Insurance proceeds received to date relate to the 2020 Wildfires.

During the three-month periods ended September 30, 2024 and 2023, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $— million and $1,263 million, respectively. During the nine-month periods ended September 30, 2024 and 2023, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $251 million and $1,671 million, respectively. No additional insurance recoveries beyond those accrued and received 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.

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.

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(12)    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,
	2024		2023		2024		2023
Customer Revenue:
Retail:
Residential	$	680	$	601	$	1,786	$	1,636
Commercial	605		513		1,566		1,372
Industrial	361		310		987		870
Other retail	143		119		289		246
Total retail	1,789		1,543		4,628		4,124
Wholesale	25		47		67		134
Transmission	54		44		137		116
Other Customer Revenue	26		31		81		87
Total Customer Revenue	1,894		1,665		4,913		4,461
Other revenue	29		11		47		26
Total operating revenue	$	1,923	$	1,676	$	4,960	$	4,487

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

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

Results of Operations for the Third Quarter and First Nine Months of 2024 and 2023

Overview

Net income for the third quarter of 2024 was $324 million, an increase of $976 million compared to 2023. The increase in net income was primarily due to lower estimated losses of $1,263 million associated with the Wildfires, net of expected insurance recoveries, higher utility margin and higher allowances for equity and borrowed funds used during construction, partially offset by lower income tax benefit, higher operations and maintenance expense and higher net interest expense. Utility margin increased primarily due to higher retail revenue from higher prices and volumes, lower coal‑fueled generation costs and higher net wheeling revenue, partially offset by lower net power cost deferrals, higher purchased electricity costs, higher natural gas‑fueled generation costs and lower wholesale revenue. Retail customer volumes increased 3.2%, primarily due to an increase in customer usage and an increase in the average number of customers, partially offset by unfavorable impacts of weather. Energy generated volumes decreased 10% for the third quarter of 2024 compared to 2023 primarily due to lower coal‑fueled generation, partially offset by higher natural gas‑fueled generation. Wholesale electricity sales volumes decreased 26% and energy purchased volumes increased 37%.

Net income for the first nine months of 2024 was $376 million, an increase of $1,042 million compared to 2023. The increase in net income was primarily due to $1,420 million of lower estimated losses associated with the Wildfires, net of expected insurance recoveries, higher utility margin and higher allowances for equity and borrowed funds used during construction, partially offset lower income tax benefit, higher operations and maintenance expense and higher net interest expense. Utility margin increased primarily due to higher retail revenue from higher prices and volumes, lower coal‑fueled generation costs, lower natural gas‑fueled generation costs and higher net wheeling revenue, partially offset by lower net power cost deferrals, higher purchased electricity costs and lower wholesale revenue. Retail customer volumes increased 3.2%, primarily due to an increase in commercial, industrial and irrigation customer usage and an increase in the average number of customers, partially offset by unfavorable impacts of weather. Energy generated volumes decreased 6% for the first nine months of 2024 compared to 2023 primarily due to lower coal-fueled and hydro-powered generation, partially offset by higher natural gas-fueled and wind-powered generation. Wholesale electricity sales volumes decreased 27% and energy purchased volumes increased 21%.

Non-GAAP Financial Measure

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

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

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

	Third Quarter								First Nine Months
	2024		2023		Change				2024		2023		Change
Utility margin:
Operating revenue	$	1,923	$	1,676	$	247	15	%	$	4,960	$	4,487	$	473	11	%
Cost of fuel and energy	862		664		198		30		2,076		1,740		336		19
Utility margin	1,061		1,012		49		5		2,884		2,747		137		5
Operations and maintenance	422		356		66		19		1,248		1,056		192		18
Wildfires losses, net of recoveries	—		1,263		(1,263)		(100)		251		1,671		(1,420)		(85)
Depreciation and amortization	287		285		2		1		866		843		23		3
Property and other taxes	55		51		4		8		161		156		5		3
Operating income (loss)	$	297	$	(943)	$	1,240	131	%	$	358	$	(979)	$	1,337	137	%

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Utility Margin

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

	Third Quarter								First Nine Months
	2024		2023		Change				2024		2023		Change
Utility margin (in millions):
Operating revenue	$	1,923	$	1,676	$	247	15	%	$	4,960	$	4,487	$	473	11	%
Cost of fuel and energy	862		664		198		30		2,076		1,740		336		19
Utility margin	$	1,061	$	1,012	$	49	5	%	$	2,884	$	2,747	$	137	5	%
Sales (GWhs):
Residential	4,994		4,813		181		4	%	13,728		13,724		4		—	%
Commercial	5,749		5,559		190		3		16,104		15,336		768		5
Industrial, irrigation and other	5,095		4,974		121		2		14,241		13,627		614		5
Total retail	15,838		15,346		492		3		44,073		42,687		1,386		3
Wholesale	678		912		(234)		(26)		1,715		2,338		(623)		(27)
Total sales	16,516		16,258		258		2	%	45,788		45,025		763		2	%
Average number of retail customers  (in thousands)	2,108		2,072		36		2	%	2,099		2,065		34		2	%
Average revenue per MWh:
Retail	$	113.11	$	100.55	$	12.56	12	%	$	105.16	$	96.48	$	8.68	9	%
Wholesale	$	73.12	$	61.14	$	11.98	20	%	$	58.86	$	68.70	$	(9.84)	(14)	%
Heating degree days	125		174		(49)		(28)	%	5,907		6,692		(785)		(12)	%
Cooling degree days	1,762		2,344		(582)		(25)	%	2,276		2,800		(524)		(19)	%
Sources of energy (GWhs)(1):
Coal	4,856		7,150		(2,294)		(32)	%	12,795		16,299		(3,504)		(21)	%
Natural gas	4,964		3,876		1,088		28		12,413		10,939		1,474		13
Wind(2)	1,186		1,191		(5)		—		4,932		4,719		213		5
Hydroelectric and other(2)	497		509		(12)		(2)		2,234		2,432		(198)		(8)
Total energy generated	11,503		12,726		(1,223)		(10)		32,374		34,389		(2,015)		(6)
Energy purchased	6,401		4,677		1,724		37		17,222		14,187		3,035		21
Total	17,904		17,403		501		3	%	49,596		48,576		1,020		2	%
Average cost of energy per MWh:
Energy generated(3)	$	24.52	$	24.85	$	(0.33)	(1)	%	$	24.10	$	23.13	$	0.97	4	%
Energy purchased	$	94.81	$	115.30	$	(20.49)	(18)	%	$	78.09	$	82.43	$	(4.34)	(5)	%

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

(2)    All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities.

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

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Quarter Ended September 30, 2024 compared to Quarter Ended September 30, 2023

Utility margin increased $49 million for the third quarter of 2024 compared to 2023 primarily due to:

•$248 million increase in retail revenue due to higher average prices and higher volumes. Retail customer volumes increased 3.2%, primarily due to favorable residential customer usage, mainly in Utah and Oregon, favorable Wyoming, Washington and Idaho industrial customer usage, favorable commercial customer usage across the service territory, except in Wyoming, and favorable irrigation customer usage across the service territory, partially offset by unfavorable weather related impacts across the service territory, except in Washington and Wyoming and unfavorable Utah, Oregon and California industrial customer usage;

•$53 million of lower coal-fueled generation costs from lower volumes, partially offset by higher prices; and

•$8 million of higher net wheeling revenue.

The increases above were partially offset by:

•$162 million of lower net power costs deferrals in accordance with established adjustment mechanisms;

•$68 million of higher purchased electricity costs from higher volumes, partially offset by lower average market prices;

•$19 million of higher natural gas-fueled generation costs from higher volumes, partially offset by lower prices; and

•$6 million decrease in wholesale revenue primarily due to lower volumes, partially offset by higher average market prices.

Operations and maintenance increased $66 million, or 19%, for the third quarter of 2024 compared to 2023 primarily due to:

•$24 million of higher insurance expense due to higher premiums associated with third-party liability coverage;

•$15 million of higher vegetation management and wildfire mitigation costs, primarily due to amortization of amounts previously deferred in Oregon (largely offset in retail revenue);

•$11 million of higher demand-side management amortization expense;

•$11 million increase in salary and benefit expenses;

•$3 million increase in legal fees; and

•$3 million increase due to costs associated with the Lower Klamath Project.

Wildfire losses, net of recoveries decreased $1,263 million for the third quarter of 2024 compared to 2023 due to a decrease in estimated losses associated with the Wildfires, net of expected insurance recoveries, in 2024 compared to 2023.

Depreciation and amortization increased $2 million, or 1%, for the third quarter of 2024 compared to 2023 primarily due to higher plant-in-service balances in the current year, partially offset by cessation of Washington incremental depreciation of certain coal plants.

Interest expense increased $53 million, or 38%, for the third quarter of 2024 compared to 2023 primarily due to higher average long-term debt balances due to the issuance of $3.8 billion of First Mortgage Bonds in January 2024.

Allowance for borrowed and equity funds increased $30 million, or 51%, for the third quarter of 2024 compared to 2023 primarily due to higher qualified construction work-in-progress balances.

Interest and dividend income increased $19 million, or 68%, for the third quarter of 2024 compared to 2023 primarily due to higher regulatory asset interest income of $10 million primarily from higher deferred net power cost balances and higher investment income of $6 million from higher cash equivalents.

Income tax benefit decreased $265 million, or 77%, for the third quarter of 2024 compared to 2023 and the effective tax rate was (33)% for 2024 and 35% for 2023. The $265 million decrease is primarily due to higher prior year loss accruals, net of expected recoveries, associated with the Wildfires, partially offset by higher recognized PTCs from PacifiCorp's wind-powered generating facilities.

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First Nine Months of 2024 compared to First Nine Months of 2023

Utility margin increased $137 million for the first nine months of 2024 compared to 2023 primarily due to:

•$516 million increase in retail revenue due to higher average prices and higher retail volumes. Retail customer volumes increased 3.2%, primarily due to favorable Utah, Oregon and Washington commercial customer usage and Utah residential customer usage, favorable industrial customer usage across the eastern service territory and Washington, and favorable irrigation customer usage across the service territory, favorable changes in the average number of residential and commercial customers across the service territory, mainly in Utah and Oregon, partially offset by unfavorable weather impacts across the service territory, except Wyoming, and unfavorable residential customer usage across the western service territory, mainly in Oregon;

•$51 million of lower coal-fueled generation costs due to lower volumes, partially offset by higher prices;

•$31 million of lower natural gas-fueled generation costs from lower prices, partially offset by higher volumes; and

•$23 million of higher net wheeling revenue.

The increases above were partially offset by:

•$246 million of lower net power costs deferrals in accordance with established adjustment mechanisms;

•$175 million of higher purchased electricity costs from higher volumes, partially offset by lower average market prices; and

•$60 million decrease in wholesale revenue primarily due to lower volumes and lower average market prices.

Operations and maintenance increased $192 million, or 18%, for the first nine months of 2024 compared to 2023 primarily due to:

•$63 million of higher insurance expense due to higher premiums associated with third-party liability coverage;

•$50 million of higher vegetation management and wildfire mitigation costs, primarily due to amortization of amounts previously deferred in Oregon (largely offset in retail revenue).

•$27 million increase in salary and benefit expenses;

•$16 million of higher demand-side management amortization expense;

•$11 million increase due to costs associated with the Lower Klamath Project;

•$8 million increase in injuries and damages expenses;

•$5 million of higher legal fees; and

•$4 million increase in general and plant maintenance costs.

Wildfire losses, net of recoveries decreased $1,420 million, or 85%, for the first nine months of 2024 compared to 2023 due to a decrease in estimated losses associated with the 2020 Wildfires, net of expected insurance recoveries in 2024 compared to 2023.

Depreciation and amortization increased $23 million, or 3%, for the first nine months of 2024 compared to 2023 primarily due to higher plant-in-service balances in the current year, partially offset by cessation of Washington incremental depreciation of certain coal plants.

Interest expense increased $172 million, or 43%, for the first nine months of 2024 compared to 2023 primarily due to higher average long-term debt balances due to the issuance of $3.8 billion of First Mortgage Bonds in January 2024.

Allowance for borrowed and equity funds increased $99 million, or 66%, for the first nine months of 2024 compared to 2023 primarily due to higher qualified construction work-in-progress balances.

Interest and dividend income increased $82 million for the first nine months of 2024 compared to 2023 primarily due to higher investment income of $44 million from higher cash equivalents and higher regulatory asset interest income of $36 million primarily from higher deferred net power cost balances.

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Income tax benefit decreased $311 million, or 64%, for the first nine months of 2024 compared to 2023 and the effective tax rate was (86)% for 2024 and 42% for 2023. The $311 million decrease is primarily due to higher prior year loss accruals, net of expected insurance recoveries, associated with the Wildfires and the release of a valuation allowance on state net operating loss carryforwards in 2023, partially offset by higher recognized PTCs from PacifiCorp's wind-powered generating facilities.

Liquidity and Capital Resources

As of September 30, 2024, PacifiCorp's total net liquidity was as follows (in millions):

Cash and cash equivalents	$	381
Credit facilities(1)	2,900
Less:
Tax-exempt bond support and letters of credit	(218)
Net credit facility	2,682
Total net liquidity	$	3,063
Maturity dates	2025, 2027

(1)Refer to Note 5 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q and "Credit Facilities and Letters of Credit" below for further discussion regarding PacifiCorp's credit facilities.

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2024 and 2023 were $671 million and $1,067 million, respectively. The decrease is primarily due to higher wildfire liability settlement payments, higher wholesale purchases and lower wholesale sales, higher operating expense payments, lower net transmission and security deposits received and higher cash paid for interest, partially offset by higher collections from retail customers and insurance reimbursements related to wildfire liabilities.

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, 2024 and 2023 were $(2,150) million and $(2,245) million, respectively. The change is primarily due to a decrease in capital expenditures of $93 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, 2024 were $1.7 billion. Sources of cash consisted of net proceeds from the issuance of long-term debt of $3.8 billion in January 2024. Uses of cash consisted primarily of $1.6 billion for the repayment of short-term debt and $425 million for the repayment of long-term debt.

For a discussion of recent financing transactions, refer to Note 5 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Net cash flows from financing activities for the 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 in January 2023 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.

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Short-term Debt

Regulatory authorities limit PacifiCorp to $3.0 billion of short-term debt. As of September 30, 2024, PacifiCorp had no short‑term debt outstanding. As of December 31, 2023, PacifiCorp had $1.6 billion of short-term debt outstanding at a weighted average rate of 6.16%.

Debt Authorizations

In March and April 2024, PacifiCorp applied for additional short-term debt issuance authority from the FERC, the OPUC and the IPUC, and in May 2024, all three commissions issued final orders approving the additional issuance authority from $2.0 billion to up to $3.0 billion in total authorized short-term debt outstanding at any one time.

In March 2024, PacifiCorp applied for additional long-term debt issuance authority from the OPUC and the IPUC. In April and July 2024, respectively, the IPUC and the OPUC issued final orders approving PacifiCorp to issue an additional $5.0 billion of long-term debt. PacifiCorp also must make a notice filing with the WUTC prior to any future long-term debt issuance. PacifiCorp currently has an effective shelf registration statement filed with the SEC to issue an indeterminate amount of first mortgage bonds and unsecured debt securities through July 2027.

Credit Facilities and Letters of Credit

In June 2024, PacifiCorp terminated its existing $900 million unsecured delayed draw term loan facility expiring in June 2025 and entered into a new $900 million 364-day unsecured credit facility expiring in June 2025.

As of September 30, 2024, PacifiCorp had no letters of credit outstanding under its $2.0 billion revolving credit facility and had an additional $34 million of letters of credit outstanding in support of certain transactions required by third parties.

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, bank loans, 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 Wildfires; changes in income tax laws; general business conditions; new customer requests; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

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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
	2023		2024		2024
Wind generation	$	550	$	268	$	478
Electric distribution	472		567		757
Electric transmission	743		612		865
Wildfire mitigation	197		264		479
Other	288		446		473
Total	$	2,250	$	2,157	$	3,052

PacifiCorp's IRP is a roadmap for PacifiCorp's energy transition to renewable and carbon free generation resources, coal-to-natural gas conversion of certain coal-fueled units, energy storage, associated transmission, load forecast and resource adequacy. PacifiCorp anticipates that the additional new renewable and carbon free generation and energy storage will be a mixture of owned and contracted resources. PacifiCorp has included estimates for these new renewable and carbon free generation and energy storage resources, conversion of certain coal-fueled units to natural gas-fueled units, energy storage assets and associated transmission assets in its forecast capital expenditures. These estimates are likely to change as a result of the IRP update and 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 $249 million and $540 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned spending for the construction of additional wind‑powered generating facilities and those at acquired sites totals $202 million for the remainder of 2024 and is primarily for the Rock River I, Rock Creek I and Rock Creek II wind‑powered generating facilities totaling approximately 640 MWs that are expected to be placed in‑service in 2024 and 2025.

•Electric distribution includes both growth projects and operating expenditures. Growth expenditures include spending on new customer connections totaling $253 million and $184 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned spending for new customer connections totals $68 million for the remainder of 2024. The remaining investments primarily relate to expenditures for distribution operations.

•Electric transmission includes both growth projects and operating expenditures. Transmission growth investments primarily reflect costs associated with major transmission projects totaling $376 million and $486 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned spending for major transmission segments that are expected to be placed in‑service in 2024 through 2031 totals $122 million for the remainder of 2024.

•Wildfire mitigation includes operating expenditures for wildfire mitigation activities totaling $264 million and $197 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned spending for wildfire mitigation totals $215 million for the remainder of 2024.

•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $125 million and $128 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned information technology spending totals $36 million for the remainder of 2024. 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.

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In April 2024, PacifiCorp filed its 2023 IRP Update in Utah, Oregon, Wyoming and Idaho. In Washington, this filing was submitted as informational. Concurrent with the filing of the 2023 IRP Update, PacifiCorp filed an Oregon Planning Supplement to address additional requirements related to the Oregon Clean Energy Plan.

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 the market in April 2022. In September 2023, PacifiCorp suspended its 2022AS RFP and in April 2024, PacifiCorp provided notice that the 2022AS RFP was terminated. As indicated in 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 the RFP in whole or in part at any time.

Key drivers behind PacifiCorp's decision to terminate the 2022AS RFP included:

•The EPA approval of Wyoming's state ozone transport plan.

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

These changes remove restrictions that limit energy production in the summer from natural gas and coal-fueled generating facilities in Wyoming and Utah.

The preferred portfolio in the 2023 IRP Update demonstrates that with limited procurement of battery resources in the near‑term, which can be achieved outside of an RFP process, there is material benefit to customers to scaling down and delaying resource acquisition until after 2030. PacifiCorp's 2025 IRP, which is expected to be issued in early 2025, will inform the next steps for incremental resource acquisition.

Material Cash Requirements

As of September 30, 2024, 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, 2023, 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

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.

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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, pension and other postretirement benefits, income taxes 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, 2023. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2023. Refer to Note 11 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for updates regarding the wildfire loss contingency estimates.

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MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company

Consolidated Financial Section

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PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

MidAmerican Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of September 30, 2024, the related statements of operations, and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2024 and 2023, and of cash flows for the nine-month periods ended September 30, 2024 and 2023, 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, 2023, 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 23, 2024, 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, 2023, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Des Moines, Iowa

November 1, 2024

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MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,		December 31,
	2024		2023
ASSETS
Current assets:
Cash and cash equivalents	$	1,071	$	636
Trade receivables, net	234		272
Income tax receivable	85		1
Inventories	385		364
Prepayments	129		113
Other current assets	43		39
Total current assets	1,947		1,425
Property, plant and equipment, net	22,399		21,970
Regulatory assets	637		600
Investments and restricted investments	1,140		1,030
Other assets	189		210
Total assets	$	26,312	$	25,235

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

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MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	September 30,		December 31,
	2024		2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	297	$	543
Accrued interest	100		106
Accrued property, income and other taxes	327		197
Current portion of long-term debt	552		539
Other current liabilities	147		102
Total current liabilities	1,423		1,487
Long-term debt	8,808		8,227
Regulatory liabilities	1,169		1,079
Deferred income taxes	3,544		3,494
Asset retirement obligations	793		768
Other long-term liabilities	582		577
Total liabilities	16,319		15,632
Commitments and contingencies (Note 10)
Shareholder's equity:
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding	—		—
Additional paid-in capital	561		561
Retained earnings	9,432		9,042
Total shareholder's equity	9,993		9,603
Total liabilities and shareholder's equity	$	26,312	$	25,235

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

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MIDAMERICAN ENERGY COMPANY

STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2024		2023		2024		2023
Operating revenue:
Regulated electric	$	814	$	869	$	2,014	$	2,121
Regulated natural gas and other	93		95		466		522
Total operating revenue	907		964		2,480		2,643
Operating expenses:
Cost of fuel and energy	136		165		326		393
Cost of natural gas purchased for resale and other	37		47		254		329
Operations and maintenance	230		214		696		635
Depreciation and amortization	230		210		685		670
Property and other taxes	40		39		124		121
Total operating expenses	673		675		2,085		2,148
Operating income	234		289		395		495
Other income (expense):
Interest expense	(106)		(85)		(315)		(246)
Allowance for borrowed funds	8		6		21		14
Allowance for equity funds	19		16		53		40
Other, net	25		6		69		37
Total other income (expense)	(54)		(57)		(172)		(155)
Income before income tax expense (benefit)	180		232		223		340
Income tax expense (benefit)	(160)		(92)		(592)		(462)
Net income	$	340	$	324	$	815	$	802

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

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MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions)

	Common Stock		Additional Paid-in Capital		Retained Earnings		Total Shareholder's Equity
Balance, 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 dividend	—		—		(1,000)		(1,000)
Other equity transactions	—		—		1		1
Balance, September 30, 2023	$	—	$	561	$	8,887	$	9,448
Balance, June 30, 2024	$	—	$	561	$	9,092	$	9,653
Net income	—		—		340		340
Balance, September 30, 2024	$	—	$	561	$	9,432	$	9,993
Balance, December 31, 2023	$	—	$	561	$	9,042	$	9,603
Net income	—		—		815		815
Common stock dividend	—		—		(425)		(425)
Balance, September 30, 2024	$	—	$	561	$	9,432	$	9,993

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

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MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2024		2023
Cash flows from operating activities:
Net income	$	815	$	802
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	685		670
Amortization of utility plant to other operating expenses	26		25
Allowance for equity funds	(53)		(40)
Deferred income taxes and investment tax credits, net	84		106
Settlements of asset retirement obligations	—		(20)
Other, net	(22)		44
Changes in other operating assets and liabilities:
Trade receivables and other assets	(9)		175
Inventories	(21)		(56)
Accrued property, income and other taxes, net	31		93
Accounts payable and other liabilities	(167)		(38)
Net cash flows from operating activities	1,369		1,761
Cash flows from investing activities:
Capital expenditures	(1,100)		(1,339)
Purchases of marketable securities	(234)		(165)
Proceeds from sales of marketable securities	224		150
Other, net	10		14
Net cash flows from investing activities	(1,100)		(1,340)
Cash flows from financing activities:
Common stock dividends	(425)		(1,000)
Proceeds from long-term debt	592		1,338
Repayments of long-term debt	(2)		(316)
Other, net	(2)		(2)
Net cash flows from financing activities	163		20
Net change in cash and cash equivalents and restricted cash and cash equivalents	432		441
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	642		268
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	1,074	$	709

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

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MIDAMERICAN ENERGY COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

(1)    General

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

The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of September 30, 2024, and for the three- and nine-month periods ended September 30, 2024 and 2023. The results of operations for the nine-month period ended September 30, 2024, 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, 2023, 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, 2024.

(2)    New Accounting Pronouncements

In November 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items, as well as incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to Financial Statements.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to Financial Statements.

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In March 2024, the United States Securities and Exchange Commission adopted final rules requiring disclosure of certain climate-related information in registrations statements and Form 10-Ks. The final rules require a registrant to disclose, among other things: material climate-related risks; activities to mitigate or adapt to such risks; information about the registrant's board of directors' oversight of climate-related risks and management's role in managing material climate-related risks; and information on any climate-related targets or goals that are material to the registrant's business, results of operations, or financial condition. Further, to facilitate investors' assessment of certain climate-related risks, the final rules require disclosure of Scope 1 and/or Scope 2 greenhouse gas emissions when those emissions are material and disclosure of the financial statement effects of severe weather events and other natural conditions. The final rules include phased-in compliance periods for all registrants, with the compliance date dependent on the registrant's filer status and the content of the disclosure. On April 4, 2024, the United States Securities and Exchange Commission voluntarily stayed implementation of the final rules, pending the completion of judicial review of consolidated challenges by the Court of Appeals for the Eighth Circuit. MidAmerican Energy is currently evaluating the impact of adopting the final rules on its Financial Statements and disclosures included within Notes to Financial Statements.

(3)    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,
	2024		2023
Cash and cash equivalents	$	1,071	$	636
Restricted cash and cash equivalents in other current assets	3		6
Total cash and cash equivalents and restricted cash and cash equivalents	$	1,074	$	642

(4)    Property, Plant and Equipment, Net

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

		As of
		September 30,		December 31,
	Depreciable Life	2024		2023
Utility plant:
Generation	20-62 years	$	18,274	$	18,129
Transmission	55-80 years	2,864		2,834
Electric distribution	15-80 years	5,603		5,288
Natural gas distribution	30-75 years	2,335		2,294
Utility plant in-service		29,076		28,545
Accumulated depreciation and amortization		(8,423)		(7,841)
Utility plant in-service, net		20,653		20,704
Nonregulated, net of accumulated depreciation and amortization	20-50 years	6		6
		20,659		20,710
Construction work-in-progress		1,740		1,260
Property, plant and equipment, net		$	22,399	$	21,970

99

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, 2024 and 2023, $— million and $12 million, respectively, is reflected in depreciation and amortization expense on the Statements of Operations.

(5)    Recent Financing Transactions

Long-Term Debt

In January 2024, MidAmerican Energy issued $600 million of its 5.30% First Mortgage Bonds due February 2055. MidAmerican Energy intends, within 24 months of the issuance date, to allocate an amount equal to the net proceeds to finance, 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 2024, MidAmerican Energy amended its existing $1.5 billion unsecured credit facility expiring in June 2026. The amendment extended the expiration date to June 2027, updated lenders and amended certain provisions of the existing credit agreement.

(6)    Income Taxes

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

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2024		2023		2024		2023
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Income tax credits	(94)		(47)		(270)		(142)
State income tax, net of federal income tax impacts	(9)		(8)		(9)		(9)
Effects of ratemaking	(6)		(5)		(5)		(5)
Other, net	(1)		(1)		(2)		(1)
Effective income tax rate	(89)	%	(40)	%	(265)	%	(136)	%

Income tax credits relate primarily to production tax credits ("PTC") earned by 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, 2024 and 2023, totaled $602 million and $484 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 $736 million and $698 million for the nine-month periods ended September 30, 2024 and 2023, respectively.

100

(7)    Employee Benefit Plans

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

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,
	2024		2023		2024		2023
Pension:
Service cost	$	2	$	2	$	7	$	8
Interest cost	7		8		23		24
Expected return on plan assets	(8)		(7)		(24)		(23)
Settlement	—		—		—		(5)
Net amortization	1		—		—		—
Net periodic benefit cost	$	2	$	3	$	6	$	4
Other postretirement:
Service cost	$	2	$	2	$	4	$	4
Interest cost	3		4		9		10
Expected return on plan assets	(4)		(3)		(12)		(11)
Net amortization	—		—		1		—
Net periodic benefit cost	$	1	$	3	$	2	$	3

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 2024 are expected to be $8 million and $2 million, respectively. As of September 30, 2024, $5 million and $2 million of contributions had been made to the pension and other postretirement benefit plans, respectively.

(8)    Asset Retirement Obligations

In May 2024, the United States Environmental Protection Agency ("EPA") published its final rule on legacy coal combustion residuals ("CCR") surface impoundments and CCR management units ("CCRMUs") in the Federal Register. CCRMUs include CCR surface impoundments and landfills closed before October 19, 2015 and inactive CCR landfills. The final rule contains three main components: (1) a definition for legacy CCR surface impoundments, which are inactive surface impoundments at inactive generating facilities that must adhere to the same regulations as inactive CCR impoundments at active generating facilities, barring location restrictions and liner design criteria, with customized compliance deadlines; (2) groundwater monitoring, corrective action, closure, and post closure care requirements for CCRMUs, which may be located at active generating facilities and inactive generating facilities with a legacy CCR surface impoundment; and (3) the owners and operators of inactive generating facilities must identify the presence of legacy CCR surface impoundments and comply with all rule requirements for surface impoundments; and the owners and operators of active generating facilities and inactive generating facilities with a legacy CCR surface impoundment must prepare Facility Evaluation Reports ("FERs") that identify and describe the CCRMUs and determine whether closure is required. In a manner consistent with existing CCR rules, owners and operators must publish FERs on their CCR websites in two parts, within 15 months (Part 1) and 27 months (Part 2) of the final rule's effective date in November 2024. MidAmerican Energy is currently evaluating the final rule and does not anticipate identifying any legacy surface impoundments, but does anticipate identifying CCRMUs subject to the rule. Due to the number of site investigations warranted by this rule and the nature of engineering and other studies required at each site, MidAmerican Energy is unable to reasonably estimate the potential impact, which may be material, to its asset retirement obligations.

101

(9)    Fair Value Measurements

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

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

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

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

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

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of September 30, 2024:
Assets:
Commodity derivatives	$	—	$	5	$	1	$	(2)	$	4
Money market mutual funds	1,040		—		—		—		1,040
Debt securities:
U.S. government obligations	263		—		—		—		263
Corporate obligations	—		106		—		—		106
Municipal obligations	—		2		—		—		2
Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:
U.S. companies	484		—		—		—		484
International companies	10		—		—		—		10
Investment funds	23		—		—		—		23
	$	1,820	$	114	$	1	$	(2)	$	1,933
Liabilities - commodity derivatives	$	—	$	(21)	$	(9)	$	11	$	(19)

102

	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2023:
Assets:
Commodity derivatives	$	—	$	15	$	—	$	(2)	$	13
Money market mutual funds	643		—		—		—		643
Debt securities:
U.S. government obligations	257		—		—		—		257
Corporate obligations	—		70		—		—		70
Municipal obligations	—		3		—		—		3
Equity securities:
U.S. companies	427		—		—		—		427
International companies	9		—		—		—		9
Investment funds	19		—		—		—		19
	$	1,355	$	88	$	—	$	(2)	$	1,441
Liabilities - commodity derivatives	$	—	$	(15)	$	(11)	$	14	$	(12)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $9 million and $12 million as of September 30, 2024 and December 31, 2023, 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,
	2024		2023		2024		2023
Beginning balance	$	(2)	$	(14)	$	(11)	$	5
Changes in fair value recognized in net regulatory assets	(11)		(9)		(17)		(36)
Settlements	5		8		20		16
Ending balance	$	(8)	$	(15)	$	(8)	$	(15)

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, 2024				As of December 31, 2023
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	9,360	$	8,968	$	8,766	$	8,252

103

(10)    Commitments and Contingencies

Commitments

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

Construction Commitments

During the nine-month period ended September 30, 2024, MidAmerican Energy entered into firm construction commitments totaling $346 million for the remainder of 2024 through 2026 related to the construction and repowering of wind-powered generating facilities in Iowa.

Environmental Laws and Regulations

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

Legal Matters

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

Transmission Rates

MidAmerican Energy's wholesale transmission rates are set annually using formula rates approved by the Federal Energy Regulatory Commission ("FERC") subject to true-up for actual cost of service. In November 2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the base return on equity ("ROE") used to determine rates in effect prior to September 2016 no longer be found just and reasonable and sought to reduce the base ROE. In August 2022, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion vacating all orders related to the complaints and remanding them back to the FERC. In October 2024, the FERC issued an order addressing the remand. The order sets a just and reasonable ROE for the first complaint period and for the period from September 28, 2016, forward. The order continued to find that no refunds are required for the second complaint period. MidAmerican Energy has evaluated the impact of the order and has determined it will not have a material impact on its financial results.

104

(11)    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 13 (in millions):

	For the Three-Month Period Ended September 30, 2024								For the Nine-Month Period Ended September 30, 2024
	Electric		Natural Gas		Other		Total		Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential	$	242	$	51	$	—	$	293	$	581	$	276	$	—	$	857
Commercial	104		15		—		119		262		95		—		357
Industrial	338		4		—		342		830		12		—		842
Natural gas transportation services	—		12		—		12		—		37		—		37
Other retail	50		—		—		50		125		4		—		129
Total retail	734		82		—		816		1,798		424		—		2,222
Wholesale	53		9		—		62		122		37		—		159
Multi-value transmission projects	15		—		—		15		43		—		—		43
Other Customer Revenue	—		—		2		2		—		—		4		4
Total Customer Revenue	802		91		2		895		1,963		461		4		2,428
Other revenue	12		—		—		12		51		1		—		52
Total operating revenue	$	814	$	91	$	2	$	907	$	2,014	$	462	$	4	$	2,480

	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

(12)    Shareholder's Equity

In February 2024, MidAmerican Energy paid $425 million in a cash dividend to its parent company, MHC.

105

(13)    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,
	2024		2023		2024		2023
Operating revenue:
Regulated electric	$	814	$	869	$	2,014	$	2,121
Regulated natural gas	91		93		462		516
Other	2		2		4		6
Total operating revenue	$	907	$	964	$	2,480	$	2,643
Operating income:
Regulated electric	$	237	$	295	$	347	$	465
Regulated natural gas	(3)		(6)		48		30
Total operating income	234		289		395		495
Interest expense	(106)		(85)		(315)		(246)
Allowance for borrowed funds	8		6		21		14
Allowance for equity funds	19		16		53		40
Other, net	25		6		69		37
Total income before income tax expense (benefit)	$	180	$	232	$	223	$	340

	As of
	September 30, 2024		December 31, 2023
Assets:
Regulated electric	$	23,746	$	23,334
Regulated natural gas	2,566		1,900
Other	—		1
Total assets	$	26,312	$	25,235

106

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, 2024, the related consolidated statements of operations, and changes in member's equity for the three-month and nine-month periods ended September 30, 2024 and 2023, and of cash flows for the nine-month periods ended September 30, 2024 and 2023, 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, 2023, 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 23, 2024, 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, 2023, 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 1, 2024

107

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,		December 31,
	2024		2023
ASSETS
Current assets:
Cash and cash equivalents	$	1,071	$	637
Trade receivables, net	234		272
Income tax receivable	85		1
Inventories	385		364
Prepayments	129		113
Other current assets	45		40
Total current assets	1,949		1,427
Property, plant and equipment, net	22,400		21,971
Goodwill	1,270		1,270
Regulatory assets	637		600
Investments and restricted investments	1,141		1,032
Other assets	189		209
Total assets	$	27,586	$	26,509

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

108

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	September 30,		December 31,
	2024		2023
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	297	$	543
Accrued interest	102		112
Accrued property, income and other taxes	327		197
Note payable to affiliate	13		—
Current portion of long-term debt	552		539
Other current liabilities	146		102
Total current liabilities	1,437		1,493
Long-term debt	9,048		8,467
Regulatory liabilities	1,169		1,079
Deferred income taxes	3,542		3,492
Asset retirement obligations	793		768
Other long-term liabilities	583		577
Total liabilities	16,572		15,876
Commitments and contingencies (Note 10)
Member's equity:
Paid-in capital	1,679		1,679
Retained earnings	9,335		8,954
Total member's equity	11,014		10,633
Total liabilities and member's equity	$	27,586	$	26,509

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

109

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,
	2024		2023		2024		2023
Operating revenue:
Regulated electric	$	814	$	869	$	2,014	$	2,121
Regulated natural gas and other	93		95		466		522
Total operating revenue	907		964		2,480		2,643
Operating expenses:
Cost of fuel and energy	136		165		326		393
Cost of natural gas purchased for resale and other	37		47		254		329
Operations and maintenance	230		214		696		635
Depreciation and amortization	230		210		685		670
Property and other taxes	40		39		124		121
Total operating expenses	673		675		2,085		2,148
Operating income	234		289		395		495
Other income (expense):
Interest expense	(109)		(89)		(327)		(258)
Allowance for borrowed funds	8		6		21		14
Allowance for equity funds	19		16		53		40
Other, net	23		6		68		49
Total other income (expense)	(59)		(61)		(185)		(155)
Income before income tax expense (benefit)	175		228		210		340
Income tax expense (benefit)	(162)		(93)		(596)		(463)
Net income	$	337	$	321	$	806	$	803

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

110

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, 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
Balance, June 30, 2024	$	1,679	$	8,998	$	10,677
Net income	—		337		337
Balance, September 30, 2024	$	1,679	$	9,335	$	11,014
Balance, December 31, 2023	$	1,679	$	8,954	$	10,633
Net income	—		806		806
Distribution to member	—		(425)		(425)
Balance, September 30, 2024	$	1,679	$	9,335	$	11,014

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

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MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2024		2023
Cash flows from operating activities:
Net income	$	806	$	803
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	685		670
Amortization of utility plant to other operating expenses	26		25
Allowance for equity funds	(53)		(40)
Deferred income taxes and investment tax credits, net	84		106
Settlements of asset retirement obligations	—		(20)
Other, net	(22)		31
Changes in other operating assets and liabilities:
Trade receivables and other assets	(9)		166
Inventories	(21)		(56)
Accrued property, income and other taxes, net	32		94
Accounts payable and other liabilities	(173)		(42)
Net cash flows from operating activities	1,355		1,737
Cash flows from investing activities:
Capital expenditures	(1,100)		(1,339)
Purchases of marketable securities	(234)		(165)
Proceeds from sales of marketable securities	224		150
Proceeds from sale of investment	—		12
Other, net	10		14
Net cash flows from investing activities	(1,100)		(1,328)
Cash flows from financing activities:
Distributions to member	(425)		(992)
Proceeds from long-term debt	592		1,338
Repayments of long-term debt	(2)		(316)
Net change in note payable to affiliate	13		1
Other, net	(2)		(2)
Net cash flows from financing activities	176		29
Net change in cash and cash equivalents and restricted cash and cash equivalents	431		438
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	643		271
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	1,074	$	709

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

112

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, 2024, and for the three- and nine-month periods ended September 30, 2024 and 2023. The results of operations for the nine-month period ended September 30, 2024, 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, 2023, 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, 2024.

(2)    New Accounting Pronouncements

Refer to Note 2 of MidAmerican Energy's Notes to Financial Statements.

(3)    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,
	2024		2023
Cash and cash equivalents	$	1,071	$	637
Restricted cash and cash equivalents in other current assets	3		6
Total cash and cash equivalents and restricted cash and cash equivalents	$	1,074	$	643

(4)    Property, Plant and Equipment, Net

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

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(5)    Recent Financing Transactions

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

(6)    Income Taxes

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

	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2024		2023		2024		2023
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Income tax credits	(96)		(48)		(287)		(142)
State income tax, net of federal income tax impacts	(9)		(8)		(10)		(9)
Effects of ratemaking	(6)		(5)		(5)		(5)
Other, net	(3)		(1)		(3)		(1)
Effective income tax rate	(93)	%	(41)	%	(284)	%	(136)	%

Income tax credits relate primarily to production tax credits ("PTC") earned by 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, 2024 and 2023, totaled $602 million and $484 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 $739 million and $700 million for the nine-month periods ended September 30, 2024 and 2023, respectively.

(7)    Employee Benefit Plans

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

(8)    Asset Retirement Obligations

Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements.

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(9)    Fair Value Measurements

Refer to Note 9 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, 2024				As of December 31, 2023
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	9,600	$	9,231	$	9,006	$	8,515

(10)    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 10 of MidAmerican Energy's Notes to Financial Statements.

(11)    Revenue from Contracts with Customers

Refer to Note 11 of MidAmerican Energy's Notes to Financial Statements.

(12)    Member's Equity

In February 2024, MidAmerican Funding paid $425 million in a cash distribution to its parent company, BHE.

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(13)    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,
	2024		2023		2024		2023
Operating revenue:
Regulated electric	$	814	$	869	$	2,014	$	2,121
Regulated natural gas	91		93		462		516
Other	2		2		4		6
Total operating revenue	$	907	$	964	$	2,480	$	2,643
Operating income:
Regulated electric	$	237	$	295	$	347	$	465
Regulated natural gas	(3)		(6)		48		30
Total operating income	234		289		395		495
Interest expense	(109)		(89)		(327)		(258)
Allowance for borrowed funds	8		6		21		14
Allowance for equity funds	19		16		53		40
Other, net	23		6		68		49
Total income before income tax expense (benefit)	$	175	$	228	$	210	$	340

	As of
	September 30, 2024		December 31, 2023
Assets(1):
Regulated electric	$	24,937	$	24,525
Regulated natural gas	2,645		1,979
Other	4		5
Total assets	$	27,586	$	26,509

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

116

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 2024 and 2023

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the third quarter of 2024 was $340 million, an increase of $16 million, compared to 2023, primarily due to a favorable income tax benefit, favorable changes in the cash surrender value of corporate-owned life insurance policies, higher natural gas utility margin, higher AFUDC and higher interest and dividend income, partially offset by lower electric utility margin, higher depreciation and amortization expense, higher interest expense and higher operations and maintenance expense. Utility margin decreased primarily due to lower recoveries through bill riders and the unfavorable impact of weather, partially offset by higher electric retail customer usage, higher wholesale margin and higher natural gas base rates. Electric retail customer volumes increased 0.5%, primarily due to higher customer usage for certain industrial and other customers, partially offset by lower customer usage for certain residential and commercial customers and the unfavorable impact of weather. Energy generated decreased 6% due to lower coal-fueled generation, partially offset by higher renewable-powered and natural gas-fueled generation; and energy purchased volumes decreased 19%. Wholesale electricity sales volumes decreased 28% due to unfavorable market conditions. Natural gas retail customer volumes decreased 5% due to lower sales to industrial customers.

MidAmerican Energy's net income for the first nine months of 2024 was $815 million, an increase of $13 million, compared to 2023, primarily due to a favorable income tax benefit, higher natural gas utility margin, higher AFUDC, higher interest and dividend income and favorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by higher interest expense, higher operations and maintenance expense, lower electric utility margin, higher depreciation and amortization expense and higher property and other taxes. Utility margin decreased primarily due to lower wholesale margin, lower recoveries through bill riders and the unfavorable impact of weather, partially offset by higher natural gas base rates and higher electric retail customer usage. Electric retail customer volumes increased 0.6%, primarily due to higher customer usage for certain industrial and other customers, partially offset by lower customer usage for certain residential and commercial customers and the unfavorable impact of weather. Energy generated decreased 2% due to lower coal-fueled generation, partially offset by higher renewable-powered and natural gas-fueled generation; and energy purchased volumes decreased 18%. Wholesale electricity sales volumes decreased 11% due to unfavorable market conditions. Natural gas retail customer volumes decreased 10% due to the unfavorable impact of weather.

MidAmerican Funding -

MidAmerican Funding's net income for the third quarter of 2024 was $337 million, an increase of $16 million, compared to 2023. MidAmerican Funding's net income for the first nine months of 2024 was $806 million, an increase of $3 million, compared to 2023. The variance in net income was primarily due to the changes in MidAmerican Energy's earnings discussed above, partially offset by a one-time gain on the sale of an investment of $10 million in 2023.

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Non-GAAP Financial Measure

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

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

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

	Third Quarter								First Nine Months
	2024		2023		Change				2024		2023		Change
Electric utility margin:
Operating revenue	$	814	$	869	$	(55)	(6)	%	$	2,014	$	2,121	$	(107)	(5)	%
Cost of fuel and energy	136		165		(29)		(18)		326		393		(67)		(17)
Electric utility margin	678		704		(26)		(4)	%	1,688		1,728		(40)		(2)	%
Natural gas utility margin:
Operating revenue	91		93		(2)		(2)	%	462		516		(54)		(10)	%
Natural gas purchased for resale	37		47		(10)		(21)		254		329		(75)		(23)
Natural gas utility margin	54		46		8		17	%	208		187		21		11	%
Utility margin	732		750		(18)		(2)	%	1,896		1,915		(19)		(1)	%
Other operating revenue	2		2		—		—	%	4		6		(2)		(33)	%
Operations and maintenance	230		214		16		7		696		635		61		10
Depreciation and amortization	230		210		20		10		685		670		15		2
Property and other taxes	40		39		1		3		124		121		3		2
Operating income	$	234	$	289	$	(55)	(19)	%	$	395	$	495	$	(100)	(20)	%

118

Electric Utility Margin

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

	Third Quarter								First Nine Months
	2024		2023		Change				2024		2023		Change
Utility margin (in millions):
Operating revenue	$	814	$	869	$	(55)	(6)	%	$	2,014	$	2,121	$	(107)	(5)	%
Cost of fuel and energy	136		165		(29)		(18)		326		393		(67)		(17)
Utility margin	$	678	$	704	$	(26)	(4)	%	$	1,688	$	1,728	$	(40)	(2)	%
Sales (GWhs):
Residential	2,010		2,038		(28)		(1)	%	5,207		5,310		(103)		(2)	%
Commercial	1,053		1,065		(12)		(1)		2,962		3,012		(50)		(2)
Industrial	4,471		4,403		68		2		13,144		12,870		274		2
Other	441		430		11		3		1,250		1,231		19		2
Total retail	7,975		7,936		39		—		22,563		22,423		140		1
Wholesale	2,044		2,839		(795)		(28)		9,893		11,133		(1,240)		(11)
Total sales	10,019		10,775		(756)		(7)	%	32,456		33,556		(1,100)		(3)	%
Average number of retail customers (in thousands)	830		821		9		1	%	828		819		9		1	%
Average revenue per MWh:
Retail	$	92.02	$	97.40	$	(5.38)	(6)	%	$	79.71	$	81.74	$	(2.03)	(2)	%
Wholesale	$	25.09	$	25.41	$	(0.32)	(1)	%	$	13.44	$	19.59	$	(6.15)	(31)	%
Heating degree days	22		12		10		83	%	3,127		3,466		(339)		(10)	%
Cooling degree days	772		818		(46)		(6)	%	1,154		1,211		(57)		(5)	%
Sources of energy (GWhs)(1):
Wind and other(2)	4,262		3,955		307		8	%	19,243		17,652		1,591		9	%
Coal	3,148		4,064		(916)		(23)		6,125		8,397		(2,272)		(27)
Nuclear	999		982		17		2		2,860		2,771		89		3
Natural gas	845		806		39		5		1,766		1,719		47		3
Total energy generated	9,254		9,807		(553)		(6)		29,994		30,539		(545)		(2)
Energy purchased	1,014		1,247		(233)		(19)		3,005		3,652		(647)		(18)
Total	10,268		11,054		(786)		(7)	%	32,999		34,191		(1,192)		(3)	%
Average cost of energy per MWh:
Energy generated(3)	$	8.55	$	9.94	$	(1.39)	(14)	%	$	5.69	$	7.37	$	(1.68)	(23)	%
Energy purchased	$	56.34	$	54.99	$	1.35	2	%	$	51.76	$	46.17	$	5.59	12	%

(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.

119

Natural Gas Utility Margin

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

	Third Quarter								First Nine Months
	2024		2023		Change				2024		2023		Change
Utility margin (in millions):
Operating revenue	$	91	$	93	$	(2)	(2)	%	$	462	$	516	$	(54)	(10)	%
Natural gas purchased for resale	37		47		(10)		(21)		254		329		(75)		(23)
Utility margin	$	54	$	46	$	8	17	%	$	208	$	187	$	21	11	%
Throughput (000's Dths):
Residential	2,601		2,589		12		—	%	29,683		33,179		(3,496)		(11)	%
Commercial	1,517		1,435		82		6		14,521		15,810		(1,289)		(8)
Industrial	853		1,186		(333)		(28)		3,607		4,042		(435)		(11)
Other	8		12		(4)		(33)		61		59		2		3
Total retail sales	4,979		5,222		(243)		(5)		47,872		53,090		(5,218)		(10)
Wholesale sales	5,044		6,295		(1,251)		(20)		22,304		20,698		1,606		8
Total sales	10,023		11,517		(1,494)		(13)		70,176		73,788		(3,612)		(5)
Natural gas transportation service	26,811		25,246		1,565		6		80,407		78,661		1,746		2
Total throughput	36,834		36,763		71		—	%	150,583		152,449		(1,866)		(1)	%
Average number of retail customers (in thousands)	798		791		7		1	%	798		792		6		1	%
Average revenue per retail Dth sold	$	14.16	$	12.88	$	1.28	10	%	$	8.10	$	8.13	$	(0.03)	—	%
Heating degree days	26		18		8		44	%	3,261		3,659		(398)		(11)	%
Average cost of natural gas per retail Dth sold	$	5.80	$	6.10	$	(0.30)	(5)	%	$	4.53	$	5.24	$	(0.71)	(14)	%
Combined retail and wholesale average cost of natural gas per Dth sold	$	3.74	$	3.99	$	(0.25)	(6)	%	$	3.62	$	4.45	$	(0.83)	(19)	%

Quarter Ended September 30, 2024 Compared to Quarter Ended September 30, 2023

MidAmerican Energy -

Electric utility margin decreased $26 million, or 4%, for the third quarter of 2024 compared to 2023 primarily due to:

•a $33 million decrease in retail utility margin primarily due to $35 million, net of energy costs, from lower recoveries through bill riders (offset in operations and maintenance expense and income tax benefit), $5 million from the unfavorable impact of weather and $2 million due to price impacts from changes in sales mix, partially offset by $7 million from higher customer usage and $2 million from higher wind-turbine performance settlements; partially offset by

•a $7 million increase in wholesale utility margin due to higher margins per unit of $20 million, reflecting higher market prices, partially offset by lower volumes of $13 million, or 28.0%.

Natural gas utility margin increased $8 million, or 17%, for the third quarter of 2024 compared to 2023 primarily due to:

•a $6 million increase from higher base rates; and

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

120

Operations and maintenance increased $16 million, or 7%, for the third quarter of 2024 compared to 2023 primarily due to higher employee and benefit expenses of $14 million, higher steam power generation costs of $8 million, higher gas meter costs of $3 million, higher electric distribution costs of $3 million and higher energy efficiency costs of $3 million, partially offset by lower nuclear and other power generation costs of $6 million, lower technology costs of $3 million and lower rent costs of $3 million.

Depreciation and amortization increased $20 million, or 10%, for the third quarter of 2024 compared to 2023 primarily due to $14 million related to new and repowered wind-powered generating facilities and other plant placed in-service, $4 million from higher Iowa revenue sharing accruals and $2 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects.

Interest expense increased $21 million, or 25%, for the third quarter of 2024 compared to 2023 due to higher interest expense from September 2023 and January 2024 long-term debt issuances and higher interest rates on variable rate long-term debt.

Allowance for borrowed and equity funds increased $5 million, or 23%, for the third quarter of 2024 compared to 2023 primarily due to higher construction work-in-progress balances related to wind- and solar-powered generation.

Other, net was favorable by $19 million, or 317%, for the third quarter of 2024 compared to 2023 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 increased $68 million, or 74%, for the third quarter of 2024 compared to 2023 primarily due to $59 million of higher PTCs due to a higher PTC rate per MW generated and additional wind capacity placed in-service. PTCs for the third quarter of 2024 and 2023 totaled $168 million and $109 million, respectively.

MidAmerican Funding -

Income tax benefit increased $69 million, or 74%, for the third quarter of 2024 compared to 2023 primarily due to the changes in MidAmerican Energy's income tax benefit discussed above.

First Nine Months of 2024 Compared to First Nine Months of 2023

MidAmerican Energy -

Electric utility margin decreased $40 million, or 2%, for the first nine months of 2024 compared to 2023, due to:

•a $28 million decrease in wholesale utility margin due to lower volumes of $19 million, or 11.1%, and lower margins per unit of $9 million, reflecting lower market prices; and

•a $13 million decrease in retail utility margin primarily due to $25 million, net of energy costs, from lower recoveries through bill riders (offset in operations and maintenance expense and income tax benefit) and $11 million from the unfavorable impact of weather, partially offset by $15 million from higher customer usage, $5 million from higher wind-turbine performance settlements and $3 million due to price impacts from changes in sales mix. Retail customer volumes increased 0.6%.

Natural gas utility margin increased $21 million, or 11%, for the first nine months of 2024 compared to 2023 primarily due to:

•a $23 million increase from higher base rates; and

•a $4 million increase from higher natural gas transportation margin; partially offset by

•a $6 million decrease due to the unfavorable impact of weather.

Operations and maintenance increased $61 million, or 10%, for the first nine months of 2024 compared to 2023 primarily due to higher employee and benefit expenses of $32 million, higher steam power generation costs of $13 million, higher technology costs of $10 million, higher electric distribution and transmission costs of $7 million and higher energy efficiency costs of $4 million, partially offset by lower rent costs of $6 million.

121

Depreciation and amortization increased $15 million, or 2%, for the first nine months of 2024 compared to 2023 primarily due to $41 million related to new and repowered wind-powered generating facilities and other plant placed in-service and $5 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects, partially offset by $19 million from the write-off of certain assets in 2023 and $12 million from lower Iowa revenue sharing accruals.

Property and other taxes increased $3 million, or 2%, for the first nine months of 2024 compared to 2023 primarily due to $2 million from higher replacement taxes.

Interest expense increased $69 million, or 28%, for the first nine months of 2024 compared to 2023 due to higher interest expense from September 2023 and January 2024 long-term debt issuances and higher interest rates on variable rate long-term debt.

Allowance for borrowed and equity funds increased $20 million, or 37%, for the first nine months of 2024 compared to 2023 primarily due to higher construction work-in-progress balances related to wind- and solar-powered generation.

Other, net was favorable by $32 million, or 86%, for the first nine months of 2024 compared to 2023 primarily due to higher interest income from higher interest rates and favorable investment earnings, largely attributable to higher cash surrender values of corporate-owned life insurance policies, partially offset by higher non-service costs of postretirement employee benefit plans.

Income tax benefit increased $130 million, or 28%, for the first nine months of 2024 compared to 2023 primarily due to $118 million of higher PTCs due to a higher PTC rate per MW generated and additional wind capacity placed in-service. PTCs for the first nine months of 2024 and 2023 totaled $602 million and $484 million, respectively.

MidAmerican Funding -

Income tax benefit increased $133 million, or 29%, for the first nine months of 2024 compared to 2023 primarily due to the changes in MidAmerican Energy's income tax benefit discussed above and lower pretax income from a one-time gain on the sale of an investment in 2023.

Liquidity and Capital Resources

As of September 30, 2024, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):

MidAmerican Energy:
Cash and cash equivalents	$	1,071
Credit facilities, maturing 2025 and 2027	1,505
Less:
Tax-exempt bond support	(306)
Net credit facilities	1,199
MidAmerican Energy total net liquidity	$	2,270
MidAmerican Funding:
MidAmerican Energy total net liquidity	$	2,270
MHC, Inc. credit facility, maturing 2025	4
MidAmerican Funding total net liquidity	$	2,274

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Operating Activities

MidAmerican Energy's net cash flows from operating activities for the nine-month periods ended September 30, 2024 and 2023, were $1,369 million and $1,761 million, respectively. MidAmerican Funding's net cash flows from operating activities for the nine-month periods ended September 30, 2024 and 2023, were $1,355 million and $1,737 million, respectively. Cash flows from operating activities reflect higher payments to vendors, lower cash impacts of utility margin for MidAmerican Energy's regulated electric business, higher interest payments and higher property tax payments, partially offset by higher income tax receipts, lower asset retirement obligation settlement payments and higher cash impacts of utility margin for MidAmerican Energy's regulated natural gas business.

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 selected 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, 2024 and 2023, were $(1,100) million and $(1,340) million, respectively. MidAmerican Funding's net cash flows from investing activities for the nine-month periods ended September 30, 2024 and 2023, were $(1,100) million and $(1,328) 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, 2024 and 2023 were $163 million and $20 million, respectively. MidAmerican Funding's net cash flows from financing activities for the nine-month periods ended September 30, 2024 and 2023, were $176 million and $29 million, respectively. In February 2024, MidAmerican Funding paid $425 million and in January and September 2023, paid $100 million and $892 million, respectively, in cash distributions to its sole member, BHE. Proceeds from long-term debt reflect MidAmerican Energy's issuance in January 2024 of $600 million of its 5.30% First Mortgage Bonds due February 2055 and 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 2023, MidAmerican Energy repaid $316 million of long-term debt. In 2024, MidAmerican Funding received $13 million through its note payable with BHE.

For a discussion of recent financing transactions, refer to Note 5 of Notes to Financial Statements in Part I, Item 1 of this Form 10-Q.

Debt Authorizations and Related Matters

Short-term Debt

MidAmerican Energy has authority from the FERC to issue, through April 2, 2026, commercial paper and bank notes aggregating $1.5 billion. MidAmerican Energy has a $1.5 billion unsecured credit facility expiring in June 2027. 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 $1.3 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 $1.05 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 $1.05 billion and preferred stock up to an aggregate of $500 million.

123

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
	2023		2024		2024
Wind generation	$	546	$	341	$	488
Electric distribution	251		239		306
Electric transmission	150		170		216
Solar generation	11		1		3
Other	381		349		522
Total	$	1,339	$	1,100	$	1,535

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 $143 million and $460 million for the nine-month periods ended September 30, 2024 and 2023, respectively. MidAmerican Energy placed in-service 200 MWs during 2023. Planned spending for the construction of additional wind-powered generating facilities totals $22 million for the remainder of 2024.

◦Repowering of wind-powered generating facilities totaling $169 million and $48 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned spending for the repowering of wind-powered generating facilities totals $104 million for the remainder of 2024. MidAmerican Energy expects its repowered facilities to meet Internal Revenue Service guidelines for the re-establishment of PTCs under the prevailing wage and apprenticeship guidelines 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. For the nine-month periods ended September 30, 2024 and 2023, solar generation spending totaled $1 million and $11 million, respectively. Planned spending totals $2 million for the remainder of 2024.

124

•Remaining expenditures primarily relate to 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, 2024, 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, 2023.

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, impairment of goodwill, pension and other postretirement benefits and income taxes. 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, 2023. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2023.

125

Nevada Power Company and its subsidiaries

Consolidated Financial Section

126

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, 2024, the related consolidated statements of operations, and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2024 and 2023, and of cash flows for the nine-month periods ended September 30, 2024 and 2023, 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, 2023, 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 23, 2024, 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, 2023, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

November 1, 2024

127

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)

	As of
	September 30,		December 31,
	2024		2023
ASSETS
Current assets:
Cash and cash equivalents	$	41	$	20
Trade receivables, net	461		374
Inventories	172		129
Regulatory assets	203		586
Prepayments	75		32
Other current assets	48		31
Total current assets	1,000		1,172
Property, plant and equipment, net	9,163		8,658
Regulatory assets	466		499
Other assets	399		398
Total assets	$	11,028	$	10,727
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	348	$	466
Accrued interest	50		44
Accrued property, income and other taxes	52		65
Regulatory liabilities	43		43
Customer deposits	95		59
Derivative contracts	49		62
Other current liabilities	61		48
Total current liabilities	698		787
Long-term debt	3,394		3,392
Finance lease obligations	270		279
Regulatory liabilities	1,010		1,017
Deferred income taxes	805		836
Other long-term liabilities	494		452
Total liabilities	6,671		6,763
Commitments and contingencies (Note 11)
Shareholder's equity:
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding	—		—
Additional paid-in capital	2,833		2,733
Retained earnings	1,525		1,232
Accumulated other comprehensive loss, net	(1)		(1)
Total shareholder's equity	4,357		3,964
Total liabilities and shareholder's equity	$	11,028	$	10,727
The accompanying notes are an integral part of the consolidated financial statements.

128

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,
	2024		2023		2024		2023
Operating revenue	$	993	$	1,145	$	2,355	$	2,525
Operating expenses:
Cost of fuel and energy	513		688		1,336		1,565
Operations and maintenance	90		85		237		236
Depreciation and amortization	95		109		279		323
Property and other taxes	15		14		44		42
Total operating expenses	713		896		1,896		2,166
Operating income	280		249		459		359
Other income (expense):
Interest expense	(51)		(49)		(156)		(147)
Capitalized interest	2		7		16		16
Allowance for equity funds	5		6		22		14
Interest and dividend income	5		18		20		59
Other, net	5		1		14		9
Total other income (expense)	(34)		(17)		(84)		(49)
Income before income tax expense (benefit)	246		232		375		310
Income tax expense (benefit)	35		21		52		29
Net income	$	211	$	211	$	323	$	281
The accompanying notes are an integral part of these consolidated financial statements.

129

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, 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
Balance, June 30, 2024	1,000	$	—	$	2,833	$	1,344	$	(1)	$	4,176
Net income	—	—		—		211		—		211
Dividends declared	—	—		—		(30)		—		(30)
Balance, September 30, 2024	1,000	$	—	$	2,833	$	1,525	$	(1)	$	4,357
Balance, December 31, 2023	1,000	$	—	$	2,733	$	1,232	$	(1)	$	3,964
Net income	—	—		—		323		—		323
Dividends declared	—	—		—		(30)		—		(30)
Contributions	—	—		100		—		—		100
Balance, September 30, 2024	1,000	$	—	$	2,833	$	1,525	$	(1)	$	4,357
The accompanying notes are an integral part of these consolidated financial statements.

130

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2024		2023
Cash flows from operating activities:
Net income	$	323	$	281
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	279		323
Allowance for equity funds	(22)		(14)
Deferred energy	402		(184)
Amortization of deferred energy	(17)		70
Other changes in regulatory assets and liabilities	(21)		(31)
Deferred income taxes and amortization of investment tax credits	2		(18)
Changes in other operating assets and liabilities:
Trade receivables and other assets	(107)		(191)
Inventories	(43)		(34)
Accrued property, income and other taxes	(63)		68
Accounts payable and other liabilities	71		153
Net cash flows from operating activities	804		423
Cash flows from investing activities:
Capital expenditures	(842)		(1,102)
Proceeds from repayment of affiliate note receivable	—		100
Proceeds from sale of marketable securities	4		—
Net cash flows from investing activities	(838)		(1,002)
Cash flows from financing activities:
Proceeds from long-term debt	—		494
Repayments of long-term debt	—		(300)
Contributions from parent	100		400
Dividends paid	(30)		—
Other, net	(16)		(15)
Net cash flows from financing activities	54		579
Net change in cash and cash equivalents and restricted cash and cash equivalents	20		—
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	37		60
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	57	$	60
The accompanying notes are an integral part of these consolidated financial statements.

131

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, 2024, and for the three- and nine-month periods ended September 30, 2024 and 2023. 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, 2024 and 2023. The results of operations for the three- and nine-month periods ended September 30, 2024, are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2023, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Nevada Power's accounting policies or its assumptions regarding significant accounting estimates during the nine-month period ended September 30, 2024.

(2)    New Accounting Pronouncements

In November 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items, as well as incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. Nevada Power is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. Nevada Power is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

132

In March 2024, the United States Securities and Exchange Commission adopted final rules requiring disclosure of certain climate-related information in registrations statements and Form 10-Ks. The final rules require a registrant to disclose, among other things: material climate-related risks; activities to mitigate or adapt to such risks; information about the registrant's board of directors' oversight of climate-related risks and management's role in managing material climate-related risks; and information on any climate-related targets or goals that are material to the registrant's business, results of operations, or financial condition. Further, to facilitate investors' assessment of certain climate-related risks, the final rules require disclosure of Scope 1 and/or Scope 2 greenhouse gas emissions when those emissions are material and disclosure of the financial statement effects of severe weather events and other natural conditions. The final rules include phased-in compliance periods for all registrants, with the compliance date dependent on the registrant's filer status and the content of the disclosure. On April 4, 2024, the United States Securities and Exchange Commission voluntarily stayed implementation of the final rules, pending the completion of judicial review of consolidated challenges by the Court of Appeals for the Eighth Circuit. Nevada Power is currently evaluating the impact of adopting the final rules on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

(3)    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,
	2024		2023
Cash and cash equivalents	$	41	$	20
Restricted cash and cash equivalents included in other current assets	16		17
Total cash and cash equivalents and restricted cash and cash equivalents	$	57	$	37

(4)    Property, Plant and Equipment, Net

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

		As of
	Depreciable Life	September 30,		December 31,
		2024		2023
Utility plant:
Generation	30 - 65 years	$	5,360	$	4,476
Transmission	55 - 76 years	1,650		1,590
Distribution	24 - 70 years	4,672		4,451
Intangible plant and other	5 - 65 years	906		906
Utility plant		12,588		11,423
Accumulated depreciation and amortization		(4,038)		(3,856)
Utility plant, net		8,550		7,567
Nonregulated, net of accumulated depreciation and amortization	40 years	1		1
		8,551		7,568
Construction work-in-progress		612		1,090
Property, plant and equipment, net		$	9,163	$	8,658

133

During 2023, Nevada Power revised its electric and gas depreciation rates effective January 2024 based on the results of a new depreciation study, the most significant impact of which was longer lives for many production plants and other utility plant groups and shorter average service lives for intangible software. The net effect of these changes will decrease depreciation and amortization expense by $31 million annually based on depreciable plant balances at the time of the change.

(5)    Recent Financing Transactions

Credit Facilities

In June 2024, Nevada Power amended its existing $600 million secured credit facility expiring in June 2026. The amendment extended the expiration date to June 2027, updated lenders and amended certain provisions of the existing credit agreement.

(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,
	2024		2023		2024		2023
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Effects of ratemaking	(4)		(12)		(4)		(12)
Income tax credits	(3)		—		(4)		—
Other	—		—		1		—
Effective income tax rate	14	%	9	%	14	%	9	%

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.

Income tax credits relate to production tax credits ("PTCs") and investment tax credits ("ITCs") from Nevada Power's solar-powered generating facilities and energy storage properties. Federal renewable electricity PTCs are earned as energy from qualifying 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. Solar-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. Federal renewable electricity ITCs are tax credits that reduce the income tax liability by a percentage of the cost from certain qualifying solar-powered generating facilities or energy storage properties over their useful lives. The percentage of the credit varies depending on attributes of the project up to a maximum of 50 percent. PTCs recognized for the nine-month periods ended September 30, 2024 and 2023 totaled $8 million and $— million, respectively. ITCs recognized for the nine-month periods ended September 30, 2024 and 2023 totaled $5 million and $— million, respectively.

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. Nevada Power made cash payments for federal income tax to BHE of $112 million for the nine-month period ended September 30, 2024. Nevada Power received cash payments for federal income tax from BHE of $17 million for the nine-month period ended September 30, 2023.

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(7)    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,
	2024		2023
Qualified Pension Plan -
Other non-current assets	$	38	$	38
Non-Qualified Pension Plans:
Other current liabilities	(1)		(1)
Other long-term liabilities	(6)		(6)
Other Postretirement Plans -
Other non-current assets	11		10

(8)    Asset Retirement Obligations

In May 2024, the United States Environmental Protection Agency ("EPA") published its final rule on legacy coal combustion residuals ("CCR") surface impoundments and CCR management units ("CCRMUs") in the Federal Register. CCRMUs include CCR surface impoundments and landfills closed before October 19, 2015 and inactive CCR landfills. The final rule contains three main components: (1) a definition for legacy CCR surface impoundments, which are inactive surface impoundments at inactive generating facilities that must adhere to the same regulations as inactive CCR impoundments at active generating facilities, barring location restrictions and liner design criteria, with customized compliance deadlines; (2) groundwater monitoring, corrective action, closure, and post closure care requirements for CCRMUs, which may be located at active generating facilities and inactive generating facilities with a legacy CCR surface impoundment; and (3) the owners and operators of inactive generating facilities must identify the presence of legacy CCR surface impoundments and comply with all rule requirements for surface impoundments; and the owners and operators of active generating facilities and inactive generating facilities with a legacy CCR surface impoundment must prepare Facility Evaluation Reports ("FERs") that identify and describe the CCRMUs and determine whether closure is required. In a manner consistent with existing CCR rules, owners and operators must publish FERs on their CCR websites in two parts, within 15 months (Part 1) and 27 months (Part 2) of the final rule's effective date in November 2024. Nevada Power is currently evaluating the final rule and does not anticipate identifying any legacy surface impoundments, but does anticipate identifying CCRMUs subject to the rule. Due to the number of site investigations warranted by this rule and the nature of engineering and other studies required at each site, Nevada Power is unable to reasonably estimate the potential impact, which may be material, to its asset retirement obligations.

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(9)    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 10 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 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, 2024
Not designated as hedging contracts(1) -
Commodity liabilities	$	—	$	(50)	$	(6)	$	(56)
As of December 31, 2023
Not designated as hedging contracts(1) -
Commodity liabilities	$	—	$	(62)	$	(6)	$	(68)

(1)Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates. As of September 30, 2024 a regulatory asset of $56 million was recorded related to the net derivative liability of $56 million. As of December 31, 2023 a regulatory asset of $68 million was recorded related to the net derivative liability of $68 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	2024	2023
Electricity purchases	Megawatt hours	2	1
Natural gas purchases	Decatherms	158	132

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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, 2024, 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.

The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $5 million and $7 million as of September 30, 2024 and December 31, 2023, 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.

(10)    Fair Value Measurements

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

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

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

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

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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, 2024:
Assets:
Money market mutual funds	$	19	$	—	$	—	$	19
Investment funds	4		—		—		4
	$	23	$	—	$	—	$	23
Liabilities - commodity derivatives	$	—	$	—	$	(56)	$	(56)
As of December 31, 2023:
Assets:
Money market mutual funds	$	10	$	—	$	—	$	10
Investment funds	4		—		—		4
	$	14	$	—	$	—	$	14
Liabilities - commodity derivatives	$	—	$	—	$	(68)	$	(68)

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, 2024 and December 31, 2023, 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,
	2024		2023		2024		2023
Beginning balance	$	(101)	$	(126)	$	(68)	$	(52)
Changes in fair value recognized in regulatory assets	(29)		(31)		(87)		(150)
Settlements	74		99		99		144
Ending balance	$	(56)	$	(58)	$	(56)	$	(58)

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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, 2024				As of December 31, 2023
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	3,394	$	3,494	$	3,392	$	3,417

(11)    Commitments and Contingencies

Construction Commitments

During the nine-month period ended September 30, 2024, Nevada Power entered into engineering, procurement and construction agreements along with equipment and materials agreements totaling $1.5 billion through 2028 for the Greenlink Nevada transmission expansion program that will be developed in western and northern Nevada.

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.

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(12)    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,
	2024		2023		2024		2023
Customer Revenue:
Retail:
Residential	$	610	$	668	$	1,326	$	1,365
Commercial	162		199		460		512
Industrial	193		246		496		557
Other	3		6		5		16
Total fully bundled	968		1,119		2,287		2,450
Distribution only service	3		3		11		10
Total retail	971		1,122		2,298		2,460
Wholesale, transmission and other	21		18		54		51
Total Customer Revenue	992		1,140		2,352		2,511
Other revenue	1		5		3		14
Total operating revenue	$	993	$	1,145	$	2,355	$	2,525

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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 2024 and 2023

Overview

Net income for the third quarter of 2024 was $211 million which is consistent when compared to 2023 primarily due to higher utility margin and lower depreciation and amortization expense, partially offset by higher income tax expense, lower interest and dividend income, lower capitalized interest and allowance for equity funds, higher operations and maintenance expense and higher interest expense. Utility margin increased primarily due to higher retail customer volumes, higher retail rates from the 2023 regulatory rate review with new rates effective January 2024 and higher power purchase agreement sales, partially offset by lower regulatory-related revenue deferrals. Operations and maintenance expense increased primarily due to higher plant operations and maintenance costs, partially offset by the impact of regulatory amortizations approved in the 2023 regulatory rate review. Retail customer volumes, including distribution only service customers, increased 8.8% primarily due to the favorable impact of weather, favorable changes in customer usage patterns and an increase in the average number of customers. Energy generated volumes increased 21% for the third quarter of 2024 compared to 2023 primarily due to higher natural-gas fueled generation. Wholesale electricity sales volumes increased 103% and energy purchased volumes decreased 2%.

Net income for the first nine months of 2024 was $323 million, an increase of $42 million, compared to 2023 primarily due to higher utility margin, lower depreciation and amortization expense and higher capitalized interest and allowance for equity funds, partially offset by lower interest and dividend income, higher income tax expense and higher interest expense. Utility margin increased primarily due to higher retail customer volumes, higher retail rates from the 2023 regulatory rate review with new rates effective January 2024 and higher power purchase agreement sales, partially offset by lower regulatory-related revenue deferrals. Retail customer volumes, including distribution only service customers, increased 7.8% primarily due to the favorable impact of weather, favorable changes in customer usage patterns and an increase in the average number of customers. Energy generated volumes increased 16% for the first nine months of 2024 compared to 2023 primarily due to higher natural-gas fueled generation. Wholesale electricity sales volumes increased 122% and energy purchased volumes decreased 1%.

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
	2024		2023		Change				2024		2023		Change
Utility margin:
Operating revenue	$	993	$	1,145	$	(152)	(13)	%	$	2,355	$	2,525	$	(170)	(7)	%
Cost of fuel and energy	513		688		(175)		(25)		1,336		1,565		(229)		(15)
Utility margin	480		457		23		5		1,019		960		59		6
Operations and maintenance	90		85		5		6		237		236		1		—
Depreciation and amortization	95		109		(14)		(13)		279		323		(44)		(14)
Property and other taxes	15		14		1		7		44		42		2		5
Operating income	$	280	$	249	$	31	12	%	$	459	$	359	$	100	28	%

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Utility Margin

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

	Third Quarter								First Nine Months
	2024		2023		Change				2024		2023		Change
Utility margin (in millions):
Operating revenue	$	993	$	1,145	$	(152)	(13)	%	$	2,355	$	2,525	$	(170)	(7)	%
Cost of fuel and energy	513		688		(175)		(25)		1,336		1,565		(229)		(15)
Utility margin	$	480	$	457	$	23	5	%	$	1,019	$	960	$	59	6	%
Sales (GWhs):
Residential	4,438		3,993		445		11	%	8,678		7,897		781		10	%
Commercial	1,649		1,497		152		10		3,951		3,745		206		6
Industrial	1,888		1,716		172		10		4,844		4,414		430		10
Other	50		46		4		9		135		133		2		2
Total fully bundled(1)	8,025		7,252		773		11		17,608		16,189		1,419		9
Distribution only service	820		879		(59)		(7)		2,192		2,185		7		—
Total retail	8,845		8,131		714		9		19,800		18,374		1,426		8
Wholesale	128		63		65		*		429		193		236		*
Total GWhs sold	8,973		8,194		779		10	%	20,229		18,567		1,662		9	%
Average number of retail customers (in thousands)	1,040		1,018		22		2	%	1,032		1,014		18		2	%
Average revenue per MWh:
Retail - fully bundled(1)	$	120.51	$	154.23	$	(33.72)	(22)	%	$	129.87	$	151.33	$	(21.46)	(14)	%
Wholesale	$	35.78	$	55.88	$	(20.10)	(36)	%	$	29.89	$	66.80	$	(36.91)	(55)	%
Heating degree days	—		—		—		—	%	1,111		1,383		(272)		(20)	%
Cooling degree days	2,647		2,277		370		16	%	4,170		3,401		769		23	%
Sources of energy (GWhs)(2)(3):
Natural gas	4,705		3,989		716		18	%	11,592		10,183		1,409		14	%
Renewables	127		17		110		*		329		51		278		*
Total energy generated	4,832		4,006		826		21		11,921		10,234		1,687		16
Energy purchased	3,356		3,416		(60)		(2)		6,679		6,752		(73)		(1)
Total	8,188		7,422		766		10	%	18,600		16,986		1,614		10	%
Average cost of energy per MWh(2)(4):
Energy generated	$	18.76	$	35.61	$	(16.85)	(47)	%	$	36.35	$	60.30	$	(23.95)	(40)	%
Energy purchased	$	126.11	$	159.42	$	(33.31)	(21)	%	$	135.21	$	140.31	$	(5.10)	(4)	%

*    Not meaningful

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

(2)    The average cost of energy per MWh and sources of energy excludes 62 GWhs and 214 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2024 and 2023, respectively. The average cost of energy per MWh and sources of energy excludes 343 GWhs and 676 GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 2024 and 2023, 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, 2024 Compared to Quarter Ended September 30, 2023

Utility margin increased $23 million, or 5%, for the third quarter of 2024 compared to 2023 primarily due to:

•$34 million of higher electric retail utility margin primarily due to higher retail customer volumes and the 2023 regulatory rate review with new rates effective January 2024. Retail customer volumes, including distribution only service customers, increased 8.8% primarily due to favorable changes in weather and customer usage patterns and an increase in the average number of customers,

•$5 million of higher power purchase agreement sales,

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

•$2 million of higher transmission and wholesale revenue.

The increase in utility margin was partially offset by:

•$12 million of lower regulatory-related revenue deferrals,

•$8 million of lower other retail revenue from the impact of regulatory amortizations approved in the 2023 regulatory rate review and

•$4 million of lower other revenue from expiring regulatory amortizations.

Operations and maintenance increased $5 million, or 6%, for the third quarter of 2024 compared to 2023 primarily due to higher plant operations and maintenance costs, higher energy efficiency program costs (offset in revenue), higher general and administrative costs, higher technology costs and higher insurance premiums due to additional wildfire and general excess liability coverage, partially offset by the impact of regulatory amortizations approved in the 2023 regulatory rate review.

Depreciation and amortization decreased $14 million, or 13%, for the third quarter of 2024 compared to 2023 primarily due to lower regulatory amortizations, partially offset by higher amortization from an increased rate for intangible software approved in the 2023 regulatory rate review.

Interest expense increased $2 million, or 4%, for the third quarter of 2024 compared to 2023 primarily due to higher long-term debt and higher average interest rate.

Capitalized interest and allowance for equity funds decreased $6 million, or 46%, for the third quarter of 2024 compared to 2023 primarily due to lower construction work-in-progress.

Interest and dividend income decreased $13 million, or 72%, for the third quarter of 2024 compared to 2023 primarily due to unfavorable interest income, mainly from lower carrying charges on regulatory balances.

Other, net was favorable by $4 million for the third quarter of 2024 compared to 2023 primarily due to lower pension expense.

Income tax expense increased $14 million, or 67%, for the third quarter of 2024 compared to 2023 primarily due to the effects of ratemaking partially offset by higher federal income tax credits. The effective tax rate was 14% in 2024 and 9% in 2023 and increased primarily due to the effects of ratemaking, offset by higher federal tax credits.

First Nine Months of 2024 Compared to First Nine Months of 2023

Utility margin increased $59 million, or 6%, for the first nine months of 2024 compared to 2023 primarily due to:

•$84 million of higher electric retail utility margin primarily due to higher retail customer volumes and the 2023 regulatory rate review with new rates effective January 2024. Retail customer volumes, including distribution only service customers, increased 7.8% primarily due to favorable changes in weather and customer usage patterns and an increase in the average number of customers,

•$9 million of higher power purchase agreement sales,

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

•$4 million of higher energy efficiency implementation revenue and

•$4 million of higher transmission and wholesale revenue.

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The increase in utility margin was offset by:

•$26 million of lower regulatory-related revenue deferrals,

•$11 million of lower other retail revenue from the impact of regulatory amortizations approved in the 2023 regulatory rate review and

•$10 million of lower other revenue from expiring regulatory amortizations.

Operations and maintenance increased by $1 million for the first nine months of 2024 compared to 2023 primarily due to higher plant operations and maintenance costs, higher insurance premiums due to additional wildfire and general excess liability coverage, higher energy efficiency program costs (offset in revenue), higher general and administrative costs and higher technology costs, partially offset by the impact of regulatory amortizations approved in the 2023 regulatory rate review.

Depreciation and amortization decreased $44 million, or 14%, for the first nine months of 2024 compared to 2023 primarily due to lower regulatory amortizations, partially offset by higher amortization from an increased rate for intangible software approved in the 2023 regulatory rate review.

Interest expense increased $9 million, or 6%, for the first nine months of 2024 compared to 2023 primarily due to higher long-term debt and higher average interest rate.

Capitalized interest and allowance for equity funds increased $8 million, or 27%, for the first nine months of 2024 compared to 2023 primarily due to higher construction work-in-progress.

Interest and dividend income decreased $39 million, or 66%, for the first nine months of 2024 compared to 2023 primarily due to unfavorable interest income, mainly from lower carrying charges on regulatory balances.

Other, net was favorable by $5 million, or 56%, for the first nine months of 2024 compared to 2023 primarily due to lower pension expense.

Income tax expense increased $23 million, or 79%, for the first nine months of 2024 compared to 2023 primarily due to the effects of ratemaking and higher pretax income, partially offset by higher federal income tax credits. The effective tax rate was 14% in 2024 and 9% in 2023 and increased primarily due to the effects of ratemaking, offset by higher federal tax credits.

Liquidity and Capital Resources

As of September 30, 2024, Nevada Power's total net liquidity was as follows (in millions):

Cash and cash equivalents	$	41
Credit facility	600
Total net liquidity	$	641
Credit facility:
Maturity date	2027

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2024 and 2023, were $804 million and $423 million, respectively. The change was primarily due to lower payments related to fuel and energy costs and the timing of payments for operating costs, partially offset by higher income tax payments, lower collections from customers, decreased vendor deposits 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.

145

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2024 and 2023, were $(838) million and $(1,002) million, respectively. The change was primarily due to decreased capital expenditures, partially offset by decreased proceeds from 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, 2024 and 2023, were $54 million and $579 million, respectively. The change was primarily due to a decrease in proceeds from long-term debt, lower contributions from NV Energy, Inc. and higher dividends paid to NV Energy, Inc., partially offset by a decrease in repayments of long-term debt.

In October 2024, Nevada Power declared and paid a dividend to NV Energy, Inc. of $45 million.

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.

In August 2024, Nevada Power filed an application with the PUCN for authority to increase its debt ceiling from $3.8 billion to $5.5 billion for three years from January 1, 2025 to December 31, 2028 (excluding borrowings under Nevada Power's $600 million secured credit facility); and (2) maintain a revolving credit facility of up to $1.3 billion. An order approving the application was received in October 2024.

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. Expenditures for certain assets may ultimately include acquisition of existing assets.

146

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
	2023		2024		2024
Electric distribution	$	257	$	256	$	395
Electric transmission	110		97		247
Solar generation	257		19		21
Electric battery storage	104		12		17
Other	374		458		551
Total	$	1,102	$	842	$	1,231

Nevada Power received PUCN approval through its previous IRP filings for an increase in solar generation, electric transmission and peaking turbines at a generating facility. Nevada Power has included estimates from its previous and latest IRP filings in its forecast capital expenditures for 2024. 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. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.

•Solar generation includes two growth projects and other planned solar generating facilities. The first growth project consists of a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that was developed in Clark County, Nevada. Commercial operation occurred in May 2024. The second growth project consists of a 400-MW solar photovoltaic facility with an additional 400-MW of co-located battery storage that would be developed in Churchill County, Nevada with ownership share approved by the PUCN of 10% Nevada Power and 90% Sierra Pacific. Commercial operation of the solar is expected by early 2027.

•Electric battery storage includes two growth projects and other planned electric battery storage systems. The first project consists of a 100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that was developed in Clark County, Nevada. Commercial operation occurred in May 2024. The second growth project consists of a 400-MW battery energy storage system co-located with a 400MW solar photovoltaic facility that would be developed in Churchill County, Nevada with ownership share approved by the PUCN of 10% Nevada Power and 90% Sierra Pacific. Commercial operation of the battery energy storage system is expected by mid 2026.

•Other includes both growth projects and operating expenditures. Growth projects primarily consist of an additional 444 MW of peaking combustion turbines that were approved by the PUCN and are under development at the Silverhawk generating facility in Clark County, Nevada. Commercial operation occurred in July 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.

2024 Joint Integrated Resource Plan

In May 2024, the Nevada Utilities filed its Joint Application for approval of the 2024 Joint Integrated Resource Plan. The Joint Application seeks, in part (1) the addition of three power purchase agreements for solar generating resources totaling more than 1,000 MW, each with co-located battery storage systems; (2) the addition of 400 MW of company-owned hydrogen-capable natural gas simple cycle combustion turbine peakers at the North Valmy generation station; (3) to approve an update of the Greenlink Nevada transmission project costs; and (4) to construct the necessary transmission infrastructure to support growing customer demand. An order is expected by the end of 2024.

147

Material Cash Requirements

As of September 30, 2024, 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, 2023, other than those disclosed in Note 6 of the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q.

Regulatory Matters

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

Environmental Laws and Regulations

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

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

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of long-lived assets and income taxes. 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, 2023. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2023.

148

Sierra Pacific Power Company and its subsidiaries

Consolidated Financial Section

149

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, 2024, the related consolidated statements of operations, and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2024 and 2023, and of cash flows for the nine-month periods ended September 30, 2024 and 2023, 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, 2023, 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 23, 2024, 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, 2023, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

November 1, 2024

150

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)

	As of
	September 30,		December 31,
	2024		2023
ASSETS
Current assets:
Cash and cash equivalents	$	16	$	44
Trade receivables, net	148		180
Inventories	155		117
Regulatory assets	93		161
Prepayments	48		15
Other current assets	41		20
Total current assets	501		537
Property, plant and equipment, net	4,221		3,822
Regulatory assets	203		220
Other assets	205		193
Total assets	$	5,130	$	4,772
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	383	$	228
Accrued interest	16		18
Accrued property, income and other taxes	19		21
Regulatory liabilities	60		15
Customer deposits	42		21
Other current liabilities	65		46
Total current liabilities	585		349
Long-term debt	1,527		1,293
Regulatory liabilities	419		424
Deferred income taxes	382		404
Other long-term liabilities	253		237
Total liabilities	3,166		2,707
Commitments and contingencies (Note 12)
Shareholder's equity:
Common stock - $3.75 stated value, 1,000 shares authorized, issued and outstanding	—		—
Additional paid-in capital	1,606		1,576
Retained earnings	359		490
Accumulated other comprehensive loss, net	(1)		(1)
Total shareholder's equity	1,964		2,065
Total liabilities and shareholder's equity	$	5,130	$	4,772
The accompanying notes are an integral part of the consolidated financial statements.

151

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,
	2024		2023		2024		2023
Operating revenue:
Regulated electric	$	320	$	345	$	842	$	942
Regulated natural gas	18		27		138		167
Total operating revenue	338		372		980		1,109
Operating expenses:
Cost of fuel and energy	150		178		443		538
Cost of natural gas purchased for resale	7		17		96		123
Operations and maintenance	66		47		181		152
Depreciation and amortization	47		46		141		138
Property and other taxes	6		6		18		19
Total operating expenses	276		294		879		970
Operating income	62		78		101		139
Other income (expense):
Interest expense	(22)		(16)		(64)		(47)
Allowance for borrowed funds	2		—		5		5
Allowance for equity funds	6		5		16		10
Interest and dividend income	2		6		11		18
Other, net	3		1		8		3
Total other income (expense)	(9)		(4)		(24)		(11)
Income before income tax expense (benefit)	53		74		77		128
Income tax expense (benefit)	6		10		8		17
Net income	$	47	$	64	$	69	$	111
The accompanying notes are an integral part of these consolidated financial statements.

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SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)

								Accumulated
				Additional				Other		Total
	Common Stock			Paid-in		Retained		Comprehensive		Shareholder's
	Shares	Amount		Capital		Earnings		Loss, Net		Equity
Balance, 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
Balance, June 30, 2024	1,000	$	—	$	1,576	$	312	$	(1)	$	1,887
Net income	—	—		—		47		—		47
Contributions	—	—		30		—		—		30
Balance, September 30, 2024	1,000	$	—	$	1,606	$	359	$	(1)	$	1,964
Balance, December 31, 2023	1,000	$	—	$	1,576	$	490	$	(1)	$	2,065
Net income	—	—		—		69		—		69
Dividends declared	—	—		—		(200)		—		(200)
Contributions	—	—		30		—		—		30
Balance, September 30, 2024	1,000	$	—	$	1,606	$	359	$	(1)	$	1,964
The accompanying notes are an integral part of these consolidated financial statements.

153

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2024		2023
Cash flows from operating activities:
Net income	$	69	$	111
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	141		138
Allowance for equity funds	(16)		(10)
Deferred energy	86		40
Amortization of deferred energy	31		77
Other changes in regulatory assets and liabilities	2		6
Deferred income taxes and amortization of investment tax credits	(34)		(38)
Other, net	(2)		—
Changes in other operating assets and liabilities:
Trade receivables and other assets	6		(2)
Inventories	(38)		(31)
Accrued property, income and other taxes	(28)		(1)
Accounts payable and other liabilities	113		16
Net cash flows from operating activities	330		306
Cash flows from investing activities:
Capital expenditures	(433)		(284)
Proceeds from sale of marketable securities	1		—
Net cash flows from investing activities	(432)		(284)
Cash flows from financing activities:
Proceeds from long-term debt	233		394
Repayments of long-term debt	—		(250)
Proceeds from short-term debt	15		—
Dividends paid	(200)		(100)
Contributions from parent	30		—
Repayments of affiliate note payable	—		(70)
Other, net	(6)		(6)
Net cash flows from financing activities	72		(32)
Net change in cash and cash equivalents and restricted cash and cash equivalents	(30)		(10)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	52		56
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	22	$	46
The accompanying notes are an integral part of these consolidated financial statements.

154

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, 2024, and for the three- and nine-month periods ended September 30, 2024 and 2023. 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, 2024 and 2023. The results of operations for the three- and nine-month periods ended September 30, 2024, 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, 2023, 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, 2024.

(2)    New Accounting Pronouncements

In November 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items, as well as incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. Sierra Pacific is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. Sierra Pacific is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

155

In March 2024, the United States Securities and Exchange Commission adopted final rules requiring disclosure of certain climate-related information in registrations statements and Form 10-Ks. The final rules require a registrant to disclose, among other things: material climate-related risks; activities to mitigate or adapt to such risks; information about the registrant's board of directors' oversight of climate-related risks and management's role in managing material climate-related risks; and information on any climate-related targets or goals that are material to the registrant's business, results of operations, or financial condition. Further, to facilitate investors' assessment of certain climate-related risks, the final rules require disclosure of Scope 1 and/or Scope 2 greenhouse gas emissions when those emissions are material and disclosure of the financial statement effects of severe weather events and other natural conditions. The final rules include phased-in compliance periods for all registrants, with the compliance date dependent on the registrant's filer status and the content of the disclosure. On April 4, 2024, the United States Securities and Exchange Commission voluntarily stayed implementation of the final rules, pending the completion of judicial review of consolidated challenges by the Court of Appeals for the Eighth Circuit. Sierra Pacific is currently evaluating the impact of adopting the final rules on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

(3)    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,
	2024		2023
Cash and cash equivalents	$	16	$	44
Restricted cash and cash equivalents included in other current assets	6		8
Total cash and cash equivalents and restricted cash and cash equivalents	$	22	$	52

(4)    Property, Plant and Equipment, Net

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

		As of
	Depreciable Life	September 30,		December 31,
		2024		2023
Utility plant:
Generation	25 - 70 years	$	1,336	$	1,313
Transmission	50 - 76 years	1,047		1,023
Electric distribution	20 - 76 years	2,167		2,074
Electric intangible plant and other	5 - 65 years	252		247
Natural gas distribution	35 - 70 years	553		537
Natural gas intangible plant and other	5 - 65 years	18		17
Common other	5 - 65 years	377		376
Utility plant		5,750		5,587
Accumulated depreciation and amortization		(2,193)		(2,091)
		3,557		3,496
Construction work-in-progress		664		326
Property, plant and equipment, net		$	4,221	$	3,822

156

(5)    Regulatory Matters

In February 2024, Sierra Pacific filed electric and gas regulatory rate reviews with the PUCN that requested annual revenue increases of $95 million, or 8.8% and $11 million or 4.9%, respectively. Sierra Pacific filed the certification filing that updated the electric and gas filings to requested annual revenue increases of $96 million, or 9.5% and $12 million, or 6.4%, respectively. Hearings in the cost of capital phase were held in June 2024 and the hearings for the revenue requirement phase were held in July 2024. The hearings in the rate design phase were held in August 2024. In September 2024, the PUCN issued an order approving an increase in base rates for electric of $40 million and for gas of $8 million. In October 2024, Sierra Pacific filed a petition for reconsideration and clarification of the order. The petition for reconsideration is still pending a PUCN order.

(6)    Recent Financing Transactions

Long-Term Debt

In February 2024, Sierra Pacific entered into a re-offering of the following series of fixed-rate tax exempt bonds: $75 million of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $60 million of Washoe County, Nevada Gas and Water Facilities Refunding Revenue Bonds, Series 2016B, due 2036; $30 million of Humboldt County, Nevada Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029; $30 million of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $20 million of Humboldt County, Nevada Pollution Control Refunding Revenue Bonds, Series 2016A due 2029; and $20 million of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036. The Humboldt County Series 2016A and Series 2016B bonds were offered at a term rate of 3.550%. The Washoe County Series 2016B and Series 2016G bonds were offered at a fixed rate of 3.625% and the Washoe County Series 2016C and Series 2016F bonds were offered at a fixed rate of 4.125%. Sierra Pacific previously purchased the bonds as required by the bond indentures. Sierra Pacific used the net proceeds of the re-offering for general corporate purposes.

Credit Facilities

In June 2024, Sierra Pacific amended its existing $400 million secured credit facilities expiring in June 2026. The amendment extended the expiration date to June 2027, updated lenders and amended certain provisions of the existing credit agreement.

(7)    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,
	2024		2023		2024		2023
Federal statutory income tax rate	21	%	21	%	21	%	21	%
Effects of ratemaking	(10)		(8)		(11)		(8)
Other	—		1		—		—
Effective income tax rate	11	%	14	%	10	%	13	%

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. Sierra Pacific made cash payments for federal income tax to BHE of $67 million and $54 million for the nine-month periods ended September 30, 2024 and 2023, respectively.

157

(8)    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 Plan for the nine-month period ended September 30, 2024. 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,
	2024		2023
Qualified Pension Plan -
Other non-current assets	$	56	$	53
Non-Qualified Pension Plans:
Other current liabilities	(1)		(1)
Other long-term liabilities	(5)		(5)
Other Postretirement Plans -
Other non-current assets	3		1

(9)    Asset Retirement Obligations

In May 2024, the United States Environmental Protection Agency ("EPA") published its final rule on legacy coal combustion residuals ("CCR") surface impoundments and CCR management units ("CCRMUs") in the Federal Register. CCRMUs include CCR surface impoundments and landfills closed before October 19, 2015 and inactive CCR landfills. The final rule contains three main components: (1) a definition for legacy CCR surface impoundments, which are inactive surface impoundments at inactive generating facilities that must adhere to the same regulations as inactive CCR impoundments at active generating facilities, barring location restrictions and liner design criteria, with customized compliance deadlines; (2) groundwater monitoring, corrective action, closure, and post closure care requirements for CCRMUs, which may be located at active generating facilities and inactive generating facilities with a legacy CCR surface impoundment; and (3) the owners and operators of inactive generating facilities must identify the presence of legacy CCR surface impoundments and comply with all rule requirements for surface impoundments; and the owners and operators of active generating facilities and inactive generating facilities with a legacy CCR surface impoundment must prepare Facility Evaluation Reports ("FERs") that identify and describe the CCRMUs and determine whether closure is required. In a manner consistent with existing CCR rules, owners and operators must publish FERs on their CCR websites in two parts, within 15 months (Part 1) and 27 months (Part 2) of the final rule's effective date in November 2024. Sierra Pacific is currently evaluating the final rule and does not anticipate identifying any legacy surface impoundments, but does anticipate that it may identify CCRMUs subject to the rule. Due to the number of site investigations warranted by this rule and the nature of engineering and other studies required at each site, Sierra Pacific is unable to reasonably estimate the potential impact, which may be material, to its asset retirement obligations.

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(10)    Risk Management and Hedging Activities

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

Sierra Pacific has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Sierra Pacific may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Sierra Pacific's exposure to interest rate risk. Sierra Pacific does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in Sierra Pacific's accounting policies related to derivatives. Refer to Note 11 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		Long-term
	Assets		Liabilities		Liabilities		Total
As of September 30, 2024
Not designated as hedging contracts(1) -
Commodity assets	$	1	$	—	$	—	$	1
Commodity liabilities	—		(12)		(1)		(13)
Total derivative - net basis	$	1	$	(12)	$	(1)	$	(12)
As of December 31, 2023
Not designated as hedging contracts(1) -
Commodity liabilities	$	—	$	(16)	$	—	$	(16)

(1)Sierra Pacific's commodity derivatives not designated as hedging contracts are included in regulated rates. As of September 30, 2024 a net regulatory asset of $12 million was recorded related to the net derivative liability of $12 million. As of December 31, 2023 a net regulatory asset of $16 million was recorded related to the net derivative liability of $16 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	2024	2023
Natural gas purchases	Decatherms	70	55

159

Credit Risk

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

Collateral and Contingent Features

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in Sierra Pacific's creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2024, 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 as of September 30, 2024 and December 31, 2023, 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.

(11)    Fair Value Measurements

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

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

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

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

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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, 2024:
Assets:
Commodity derivatives	$	—	$	—	$	1	$	1
Money market mutual funds	10		—		—		10
Investment funds	1		—		—		1
	$	11	$	—	$	1	$	12
Liabilities - commodity derivatives	$	—	$	—	$	(13)	$	(13)
As of December 31, 2023:
Assets:
Money market mutual funds	$	41	$	—	$	—	$	41
Investment funds	1		—		—		1
	$	42	$	—	$	—	$	42
Liabilities - commodity derivatives	$	—	$	—	$	(16)	$	(16)

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, 2024 and December 31, 2023, 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.

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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,
	2024		2023		2024		2023
Beginning balance	$	(27)	$	(36)	$	(16)	$	(13)
Changes in fair value recognized in regulatory assets	(10)		(8)		(26)		(45)
Settlements	25		32		30		46
Ending balance	$	(12)	$	(12)	$	(12)	$	(12)

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

	As of September 30, 2024				As of December 31, 2023
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	1,527	$	1,576	$	1,293	$	1,311

(12)    Commitments and Contingencies

Construction Commitments

During the nine-month period ended September 30, 2024, Sierra Pacific entered into engineering, procurement and construction agreements along with equipment and materials agreements totaling $624 million through 2028 for the Greenlink Nevada transmission expansion program that will be developed in western and northern Nevada and agreements totaling $986 million for a 400-MW solar photovoltaic facility with an additional 400-MW of co-located battery storage that will be developed in Churchill County, Nevada.

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.

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(13)    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 14 (in millions):

	Three-Month Periods
	Ended September 30,
	2024						2023
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Customer Revenue:
Retail:
Residential	$	106	$	11	$	117	$	116	$	15	$	131
Commercial	101		4		105		111		6		117
Industrial	93		2		95		96		5		101
Other	1		1		2		—		1		1
Total fully bundled	301		18		319		323		27		350
Distribution only service	2		—		2		2		—		2
Total retail	303		18		321		325		27		352
Wholesale, transmission and other	16		—		16		20		—		20
Total Customer Revenue	319		18		337		345		27		372
Other revenue	1		—		1		—		—		—
Total operating revenue	$	320	$	18	$	338	$	345	$	27	$	372

	Nine-Month Periods
	Ended September 30,
	2024						2023
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Customer Revenue:
Retail:
Residential	$	296	$	85	$	381	$	326	$	100	$	426
Commercial	273		36		309		304		45		349
Industrial	213		15		228		241		20		261
Other	4		2		6		3		1		4
Total fully bundled	786		138		924		874		166		1,040
Distribution only service	4		—		4		4		—		4
Total retail	790		138		928		878		166		1,044
Wholesale, transmission and other	51		—		51		64		—		64
Total Customer Revenue	841		138		979		942		166		1,108
Other revenue	1		—		1		—		1		1
Total operating revenue	$	842	$	138	$	980	$	942	$	167	$	1,109

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(14)    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,
	2024		2023		2024		2023
Operating revenue:
Regulated electric	$	320	$	345	$	842	$	942
Regulated natural gas	18		27		138		167
Total operating revenue	$	338	$	372	$	980	$	1,109
Operating income:
Regulated electric	$	65	$	78	$	99	$	126
Regulated natural gas	(3)		—		2		13
Total operating income	62		78		101		139
Interest expense	(22)		(16)		(64)		(47)
Allowance for borrowed funds	2		—		5		5
Allowance for equity funds	6		5		16		10
Interest and dividend income	2		6		11		18
Other, net	3		1		8		3
Total income before income tax expense (benefit)	$	53	$	74	$	77	$	128

	As of
		September 30,		December 31,
		2024		2023
Assets:
Regulated electric		$	4,635	$	4,251
Regulated natural gas		450		454
Other(1)		45		67
Total assets		$	5,130	$	4,772

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

164

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 2024 and 2023

Overview

Net income for the third quarter of 2024 was $47 million, a decrease of $17 million, or 27%, compared to 2023 primarily due to increased operations and maintenance expenses, higher interest expense and lower interest and dividend income, partially offset by higher utility margin and lower income tax expense. Electric utility margin increased primarily due to higher customer volumes and favorable price impacts from changes in sales mix, partially offset by lower transmission and wholesale revenue and lower regulatory-related revenue deferrals. Electric retail customer volumes, including distribution only service customers, increased by 6.7% primarily due to customer usage patterns, favorable impact of weather and an increase in the average number of customers. Energy generated volumes increased 12% for the third quarter of 2024 compared to 2023. Wholesale electricity sales volumes increased 40% and energy purchased volumes decreased 32%.

Net income for the first nine months of 2024 was $69 million, a decrease of $42 million, or 38%, compared to 2023 primarily due to increased operations and maintenance expenses, higher interest expense, lower utility margin and lower interest and dividend income, partially offset by lower income tax expense and higher allowances for borrowed and equity funds from increased construction work-in-progress. Electric utility margin decreased primarily due to lower transmission and wholesale revenue and lower regulatory-related revenue deferrals, partially offset by higher retail customer volumes. Electric retail customer volumes, including distribution only service customers, increased by 3.9% primarily due to an increase in the average number of customers. Energy generated volumes increased 10% for the first nine months of 2024 compared to 2023. Wholesale electricity sales volumes increased 12% and energy purchased volumes decreased 17%.

Non-GAAP Financial Measure

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

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

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

	Third Quarter								First Nine Months
	2024		2023		Change				2024		2023		Change
Electric utility margin:
Operating revenue	$	320	$	345	$	(25)	(7)	%	$	842	$	942	$	(100)	(11)	%
Cost of fuel and energy	150		178		(28)		(16)		443		538		(95)		(18)
Electric utility margin	170		167		3		2	%	399		404		(5)		(1)	%
Natural gas utility margin:
Operating revenue	18		27		(9)		(33)	%	138		167		(29)		(17)	%
Natural gas purchased for resale	7		17		(10)		(59)		96		123		(27)		(22)
Natural gas utility margin	11		10		1		10	%	42		44		(2)		(5)	%
Utility margin	181		177		4		2	%	441		448		(7)		(2)	%
Operations and maintenance	66		47		19		40	%	181		152		29		19	%
Depreciation and amortization	47		46		1		2		141		138		3		2
Property and other taxes	6		6		—		—		18		19		(1)		(5)
Operating income	$	62	$	78	$	(16)	(21)	%	$	101	$	139	$	(38)	(27)	%

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Electric Utility Margin

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

	Third Quarter								First Nine Months
	2024		2023		Change				2024		2023		Change
Utility margin (in millions):
Operating revenue	$	320	$	345	$	(25)	(7)	%	$	842	$	942	$	(100)	(11)	%
Cost of fuel and energy	150		178		(28)		(16)		443		538		(95)		(18)
Utility margin	$	170	$	167	$	3	2	%	$	399	$	404	$	(5)	(1)	%
Sales (GWhs):
Residential	800		752		48		6	%	2,073		2,023		50		2	%
Commercial	895		847		48		6		2,385		2,303		82		4
Industrial	760		693		67		10		2,112		2,010		102		5
Other	2		3		(1)		(33)		7		9		(2)		(22)
Total fully bundled(1)	2,457		2,295		162		7		6,577		6,345		232		4
Distribution only service	786		744		42		6		2,180		2,082		98		5
Total retail	3,243		3,039		204		7		8,757		8,427		330		4
Wholesale	158		113		45		40		528		473		55		12
Total GWhs sold	3,401		3,152		249		8	%	9,285		8,900		385		4	%
Average number of retail customers (in thousands)	383		376		7		2	%	381		375		6		2	%
Average revenue per MWh:
Retail - fully bundled(1)	$	123.03	$	141.30	$	(18.27)	(13)	%	$	119.52	$	137.85	$	(18.33)	(13)	%
Wholesale	$	65.83	$	97.06	$	(31.23)	(32)	%	$	60.13	$	88.84	$	(28.71)	(32)	%
Heating degree days	52		56		(4)		(7)	%	2,642		3,294		(652)		(20)	%
Cooling degree days	994		956		38		4	%	1,381		1,091		290		27	%
Sources of energy (GWhs)(3):
Natural gas	1,348		1,200		148		12	%	3,399		3,161		238		8	%
Coal	256		225		31		14		716		578		138		24
Renewables	7		8		(1)		(13)		20		21		(1)		(5)
Total energy generated	1,611		1,433		178		12		4,135		3,760		375		10
Energy purchased	1,249		1,832		(583)		(32)		3,206		3,882		(676)		(17)
Total	2,860		3,265		(405)		(12)	%	7,341		7,642		(301)		(4)	%
Average cost of energy per MWh(2)(4):
Energy generated	$	22.23	$	31.94	$	(9.71)	(30)	%	$	38.86	$	64.29	$	(25.43)	(40)	%
Energy purchased	$	91.39	$	72.52	$	18.87	26	%	$	87.92	$	76.34	$	11.58	15	%

(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 — and (4) GWhs of coal and — and 4 GWhs of natural gas generated energy that is purchased at cost by related parties for the third quarter of 2024 and 2023, respectively. The average cost of energy per MWh and sources of energy excludes — and (4) GWhs of coal and 3 and 4 GWhs of natural gas generated energy that is purchased at cost by related parties for the first nine months of 2024 and 2023, 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.

167

Natural Gas Utility Margin

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

	Third Quarter								First Nine Months
	2024		2023		Change				2024		2023		Change
Utility margin (in millions):
Operating revenue	$	18	$	27	$	(9)	(33)	%	$	138	$	167	$	(29)	(17)	%
Natural gas purchased for resale	7		17		(10)		(59)		96		123		(27)		(22)
Utility margin	$	11	$	10	$	1	10	%	$	42	$	44	$	(2)	(5)	%
Sold (000's Dths):
Residential	811		838		(27)		(3)	%	7,132		8,547		(1,415)		(17)	%
Commercial	490		528		(38)		(7)		3,690		4,451		(761)		(17)
Industrial	369		472		(103)		(22)		1,688		2,119		(431)		(20)
Total retail	1,670		1,838		(168)		(9)	%	12,510		15,117		(2,607)		(17)	%
Average number of retail customers (in thousands)	186		183		3		2	%	185		183		2		1	%
Average revenue per retail Dth sold	$	10.70	$	14.81	$	(4.11)	(28)	%	$	11.00	$	11.04	$	(0.04)	—	%
Heating degree days	52		56		(4)		(7)	%	2,642		3,294		(652)		(20)	%
Average cost of natural gas per retail Dth sold	$	4.31	$	9.00	$	(4.69)	(52)	%	$	7.69	$	8.11	$	(0.41)	(5)	%

Quarter Ended September 30, 2024 Compared to Quarter Ended September 30, 2023

Electric utility margin increased $3 million, or 2%, for the third quarter of 2024 compared to 2023 primarily due to:

•$9 million of higher electric retail utility margin primarily due to higher retail customer volumes and favorable price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 6.7% primarily due to customer usage patterns, favorable impact of weather and an increase in the average number of customers.

The increase in electric utility margin was partially offset by:

•$4 million of lower transmission and wholesale revenue and

•$2 million of lower regulatory-related revenue deferrals.

Operations and maintenance increased $19 million, or 40%, for the third quarter of 2024 compared to 2023 primarily due to higher plant operations and maintenance expenses, higher insurance premiums due to additional wildfire and general excess liability coverage, regulatory impacts from the 2024 general rate review, higher regulatory expenses primarily related to mill tax and higher technology costs, partially offset by lower administrative and general costs.

Interest expense increased $6 million, or 38%, for the third quarter of 2024 compared to 2023 primarily due to higher long-term debt and higher average interest rate.

Allowance for borrowed and equity funds increased $3 million, or 60%, for the third quarter of 2024 compared to 2023 primarily due to higher construction work-in-progress.

Interest and dividend income decreased $4 million, or 67%, for the third quarter of 2024 compared to 2023 primarily due to unfavorable interest income, mainly from lower carrying charges on regulatory balances.

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Income tax expense decreased $4 million, or 40%, for the third quarter of 2024 compared to 2023 primarily due to lower pretax income. The effective tax rate was 11% in 2024 and 14% in 2023 and decreased primarily due to the effects of ratemaking.

First Nine Months of 2024 Compared to First Nine Months of 2023

Electric utility margin decreased $5 million, or 1%, for the first nine months of 2024 compared to 2023 primarily due to:

•$8 million of lower transmission and wholesale revenue and

•$2 million of lower regulatory-related revenue deferrals.

The decrease in electric utility margin was partially offset by:

•$5 million of higher electric retail utility margin primarily due to higher retail customer volumes, partially offset by unfavorable price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 3.9% primarily due to an increase in the average number of customers.

Natural gas utility margin decreased $2 million, or 5%, for the first nine months of 2024 compared to 2023 primarily due to lower customer volumes from the unfavorable impact of weather, partially offset by an increase in the average number of customers.

Operations and maintenance increased $29 million, or 19%, for the first nine months of 2024 compared to 2023 primarily due to higher insurance premiums due to additional wildfire and general excess liability coverage, regulatory impacts from the 2024 general rate review, higher plant operations and maintenance expenses, higher regulatory expenses primarily related to mill tax, higher technology costs and higher administrative and general costs.

Depreciation and amortization increased $3 million, or 2%, for the first nine months of 2024 compared to 2023 primarily due to higher plant placed in-service.

Interest expense increased $17 million, or 36%, for the first nine months of 2024 compared to 2023 primarily due to higher long-term debt and higher average interest rate.

Allowance for borrowed and equity funds increased $6 million, or 40%, for the first nine months of 2024 compared to 2023 primarily due to higher construction work-in-progress.

Interest and dividend income decreased $7 million, or 39%, for the first nine months of 2024 compared to 2023 primarily due to unfavorable interest income, mainly from lower carrying charges on regulatory balances.

Other, net was favorable by $5 million for the first nine months of 2024 compared to 2023 primarily due to lower pension expense.

Income tax expense decreased $9 million, or 53%, for the first nine months of 2024 compared to 2023 primarily due to lower pretax income, offset by the effects of ratemaking. The effective tax rate was 10% in 2024 and 13% in 2023 and decreased primarily due to the effects of ratemaking.

Liquidity and Capital Resources

As of September 30, 2024, Sierra Pacific's total net liquidity was as follows (in millions):

Cash and cash equivalents	$	16
Credit facility	385
Total net liquidity	$	401
Credit facility:
Maturity date	2027

169

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2024 and 2023, were $330 million and $306 million, respectively. The change was primarily due to lower payments related to fuel energy costs and increased customer deposits, partially offset by lower collections from customers, the timing of payments for operating costs, higher interest payments and higher income tax 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.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2024 and 2023, were $(432) million and $(284) 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, 2024 and 2023, were $72 million and $(32) million, respectively. The change was primarily due to a decrease in repayments of long-term debt, lower repayments of an affiliate note payable and higher contributions from NV Energy, Inc., partially offset by a decrease in proceeds from long-term debt and higher dividends paid to NV Energy, Inc.

In October 2024, Sierra Pacific received a contribution from NV Energy, Inc. of $45 million.

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

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.

In August 2024, Sierra Pacific filed an application with the PUCN for authority to increase its debt ceiling from $1.9 billion to $4.0 billion for three years from January 1, 2025 to December 31, 2028 (excluding borrowings under Sierra Pacific's $400 million secured credit facility); and (2) maintain a revolving credit facility of up to $600 million. An order approving the application was received in October 2024.

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. Expenditures for certain assets may ultimately include acquisition of existing assets.

170

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
	2023		2024		2024
Electric distribution	$	106	$	142	$	208
Electric transmission	66		86		120
Wildfire mitigation	15		21		56
Solar generation	1		95		112
Electric battery storage	2		86		108
Other	94		3		41
Total	$	284	$	433	$	645

Sierra Pacific received PUCN approval through its previous IRP filings for an increase in solar generation, electric transmission and a repower project at the Valmy generating station to convert existing coal-fired combustion to natural gas-fired combustion. Sierra Pacific has included estimates from its latest IRP filing in its forecast capital expenditures for 2024. 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. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.

•Wildfire mitigation includes operating expenditures for wildfire mitigation activities totaling $21 million and $15 million for the nine-month periods ended September 30, 2024 and 2023, respectively. Planned spending for wildfire mitigation totals $34 million for the remainder of 2024.

•Solar generation includes solar photovoltaic panels procured for future growth projects and a 400-MW solar photovoltaic facility with an additional 400-MW of co-located battery storage that would be developed in Churchill County, Nevada with ownership share approved by the PUCN of 10% Nevada Power and 90% Sierra Pacific. Commercial operation of the solar is expected by early 2027.

•Electric battery storage includes a 400-MW battery energy storage system co-located with a 400-MW solar photovoltaic facility that would be developed in Churchill County, Nevada with ownership share approved by the PUCN of 10% Nevada Power and 90% Sierra Pacific. Commercial operation of the battery energy storage system is expected by mid 2026.

•Other includes both growth projects and operating expenditures consisting of turbine upgrades at the Tracy generating facility, a repower project at the Valmy generating station to convert existing coal-fired combustion to natural gas-fired combustion that was approved by the PUCN, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.

2024 Joint Integrated Resource Plan

In May 2024, the Nevada Utilities filed its Joint Application for approval of the 2024 Joint Integrated Resource Plan. The Joint Application seeks, in part (1) the addition of three power purchase agreements for solar generating resources totaling more than 1,000 MW, each with co-located battery storage systems; (2) the addition of 400 MW of company-owned hydrogen-capable natural gas simple cycle combustion turbine peakers at the North Valmy generation station; (3) to approve an update of the Greenlink Nevada transmission project costs; and (4) to construct the necessary transmission infrastructure to support growing customer demand. An order is expected by the end of 2024.

171

Material Cash Requirements

As of September 30, 2024, 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, 2023, other than those disclosed in Note 6 of the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q.

Regulatory Matters

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

Environmental Laws and Regulations

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

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

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of long-lived assets and income taxes. 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, 2023. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2023.

172

Eastern Energy Gas Holdings, LLC and its subsidiaries

Consolidated Financial Section

173

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, 2024, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and nine-month periods ended September 30, 2024 and 2023, and of cash flows for the nine-month periods ended September 30, 2024 and 2023, 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, 2023, 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 23, 2024, 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, 2023, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Richmond, Virginia

November 1, 2024

174

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,		December 31,
	2024		2023
ASSETS
Current assets:
Cash and cash equivalents	$	117	$	62
Trade receivables, net	152		195
Receivables from affiliates	30		25
Inventories	153		142
Income taxes receivable	14		80
Prepayments and other deferred charges	51		76
Natural gas imbalances	21		39
Other current assets	40		51
Total current assets	578		670
Property, plant and equipment, net	10,354		10,343
Goodwill	1,286		1,286
Investments	261		281
Other assets	103		120
Total assets	$	12,582	$	12,700

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

175

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

	As of
	September 30,		December 31,
	2024		2023
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	82	$	89
Accounts payable to affiliates	44		45
Accrued property, income and other taxes	98		93
Notes payable to affiliates	—		400
Current portion of long-term debt	1,050		1,050
Other current liabilities	150		141
Total current liabilities	1,424		1,818
Long-term debt	2,211		2,204
Regulatory liabilities	622		623
Deferred income taxes	468		383
Other long-term liabilities	142		144
Total liabilities	4,867		5,172
Commitments and contingencies (Note 11)
Equity:
Member's equity:
Membership interests	6,480		6,273
Accumulated other comprehensive loss, net	(38)		(40)
Total member's equity	6,442		6,233
Noncontrolling interests	1,273		1,295
Total equity	7,715		7,528
Total liabilities and equity	$	12,582	$	12,700

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

176

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,
	2024		2023		2024		2023
Operating revenue	$	463	$	475	$	1,493	$	1,549
Operating expenses:
Cost of gas	8		6		6		31
Operations and maintenance	143		157		414		434
Depreciation and amortization	85		80		250		240
Property and other taxes	34		36		100		99
Total operating expenses	270		279		770		804
Operating income	193		196		723		745
Other income (expense):
Interest expense	(30)		(35)		(98)		(107)
Allowance for equity funds	4		2		7		6
Interest and dividend income	3		8		7		28
Other, net	1		(1)		2		—
Total other income (expense)	(22)		(26)		(82)		(73)
Income before income tax expense (benefit) and equity income (loss)	171		170		641		672
Income tax expense (benefit)	36		5		142		75
Equity income (loss)	6		5		55		43
Net income	141		170		554		640
Net income attributable to noncontrolling interests	27		78		101		327
Net income attributable to Eastern Energy Gas	$	114	$	92	$	453	$	313

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

177

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,
	2024		2023		2024		2023
Net income	$	141	$	170	$	554	$	640
Other comprehensive (loss) income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $—, $(1), $— and $(1)	—		(1)		1		(2)
Unrealized (losses) gains on cash flow hedges, net of tax of $(1), $—, $— and $3	(2)		1		1		6
Total other comprehensive (loss) income, net of tax	(2)		—		2		4
Comprehensive income	139		170		556		644
Comprehensive income attributable to noncontrolling interests	27		78		101		327
Comprehensive income attributable to Eastern Energy Gas	$	112	$	92	$	455	$	317

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

178

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, 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 3)	(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 3)	(559)		(1)		(2,620)		(3,180)
Balance, September 30, 2023	$	6,417	$	(39)	$	1,301	$	7,679
Balance, June 30, 2024	$	6,536	$	(36)	$	1,288	$	7,788
Net income	114		—		27		141
Other comprehensive loss	—		(2)		—		(2)
Distributions	(174)		—		(42)		(216)
Contributions	4		—		—		4
Balance, September 30, 2024	$	6,480	$	(38)	$	1,273	$	7,715
Balance, December 31, 2023	$	6,273	$	(40)	$	1,295	$	7,528
Net income	453		—		101		554
Other comprehensive income	—		2		—		2
Distributions	(352)		—		(123)		(475)
Contributions	106		—		—		106
Balance, September 30, 2024	$	6,480	$	(38)	$	1,273	$	7,715

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

179

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2024		2023
Cash flows from operating activities:
Net income	$	554	$	640
Adjustments to reconcile net income to net cash flows from operating activities:
Losses (gains) on other items, net	3		(5)
Depreciation and amortization	250		240
Allowance for equity funds	(7)		(6)
Equity (income) loss, net of distributions	20		16
Changes in regulatory assets and liabilities	(1)		(97)
Deferred income taxes	96		267
Other, net	1		(3)
Changes in other operating assets and liabilities:
Trade receivables and other assets	90		84
Receivables from affiliates	(5)		10
Gas balancing activities	3		22
Derivative collateral, net	—		1
Accrued property, income and other taxes	19		(194)
Accounts payable to affiliates	(1)		9
Accounts payable and other liabilities	16		(2)
Net cash flows from operating activities	1,038		982
Cash flows from investing activities:
Capital expenditures	(244)		(241)
Proceeds from assignment of shale development rights	—		8
Notes to affiliates	—		(198)
Repayment of notes by affiliates	—		734
Other, net	4		(2)
Net cash flows from investing activities	(240)		301
Cash flows from financing activities:
Repayments of long-term debt	—		(250)
Repayment of notes payable to affiliates, net	(400)		—
Proceeds from equity contributions	—		2,876
Purchase of Cove Point noncontrolling interest	—		(3,300)
Distributions to noncontrolling interests	(123)		(353)
Distributions to parent	(226)		(226)
Net cash flows from financing activities	(749)		(1,253)
Net change in cash and cash equivalents and restricted cash and cash equivalents	49		30
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	93		95
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	142	$	125

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

180

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    General

Eastern Energy Gas Holdings, LLC is a holding company, and together with its subsidiaries ("Eastern Energy Gas") conducts business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transmission systems and underground storage operations in the eastern region of the U.S. and operates Cove Point LNG, LP ("Cove Point"), a liquefied natural gas ("LNG") export, import and storage facility. Eastern Energy Gas owns 100% of the general partner interest and 75% of the limited partner interests of Cove Point. In addition, Eastern Energy Gas owns a 50% noncontrolling interest in Iroquois Gas Transmission System, L.P. ("Iroquois"), a 414-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, 2024, and for the three- and nine-month periods ended September 30, 2024 and 2023. The results of operations for the three- and nine-month periods ended September 30, 2024 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, 2023 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, 2024.

(2)    New Accounting Pronouncements

In November 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items, as well as incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. Eastern Energy Gas is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. Eastern Energy Gas is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

181

In March 2024, the United States Securities and Exchange Commission adopted final rules requiring disclosure of certain climate-related information in registrations statements and Form 10-Ks. The final rules require a registrant to disclose, among other things: material climate-related risks; activities to mitigate or adapt to such risks; information about the registrant's board of directors' oversight of climate-related risks and management's role in managing material climate-related risks; and information on any climate-related targets or goals that are material to the registrant's business, results of operations, or financial condition. Further, to facilitate investors' assessment of certain climate-related risks, the final rules require disclosure of Scope 1 and/or Scope 2 greenhouse gas emissions when those emissions are material and disclosure of the financial statement effects of severe weather events and other natural conditions. The final rules include phased-in compliance periods for all registrants, with the compliance date dependent on the registrant's filer status and the content of the disclosure. On April 4, 2024, the United States Securities and Exchange Commission voluntarily stayed implementation of the final rules, pending the completion of judicial review of consolidated challenges by the Court of Appeals for the Eighth Circuit. Eastern Energy Gas is currently evaluating the impact of adopting the final rules 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"), a wholly owned subsidiary of Eastern Energy Gas, completed the acquisition of DECP Holdings, Inc.'s, 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 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.

182

(4)    Property, Plant and Equipment, Net

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

		As of
		September 30,		December 31,
	Depreciable Life	2024		2023
Utility plant:
Interstate natural gas transmission and storage assets	23 - 49 years	$	9,501	$	9,318
Intangible plant	5 - 18 years	130		117
Utility plant in-service		9,631		9,435
Accumulated depreciation and amortization		(3,334)		(3,201)
Utility plant in-service, net		6,297		6,234
Nonutility plant:
LNG facility	40 years	4,551		4,533
Accumulated depreciation and amortization		(748)		(655)
Nonutility plant, net		3,803		3,878
		10,100		10,112
Construction work-in-progress		254		231
Property, plant and equipment, net		$	10,354	$	10,343

Construction work-in-progress includes $238 million and $223 million as of September 30, 2024 and December 31, 2023, 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.

(5)    Regulatory Matters

In November 2023, Carolina Gas Transmission, LLC ("CGT") filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective January 1, 2024. CGT's current rates were established by a 2011 settlement. CGT proposed an annual cost-of-service of $167 million, and requested increases in various rates, including Zone 1 general system transmission rates by 84% and Zone 2 general system transmission rates by 23%. In December 2023, the FERC suspended the rate changes for five months following the proposed effective date, until June 1, 2024, subject to refund. In August 2024, a settlement agreement was filed with the FERC, resolving CGT's general rate case for its FERC-jurisdictional services and providing for increased service rates and depreciation rates. Under the terms of the settlement agreement, CGT's rates result in an average annual increase to firm transmission revenues of $25 million over the settlement period and an increase in annual depreciation expense of $8 million, compared to the rates in effect prior to June 1, 2024. FERC approval of the settlement is expected late 2024 or early 2025.

183

(6)    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,
	2024		2023
Investments:
Investment funds	$	17	$	19
Equity method investments:
Iroquois	244		262
Total investments	261		281
Restricted cash and cash equivalents:
Customer deposits	25		31
Total restricted cash and cash equivalents	25		31
Total investments and restricted cash and cash equivalents	$	286	$	312
Reflected as:
Other current assets	$	25	$	31
Noncurrent assets	261		281
Total investments and restricted cash and cash equivalents	$	286	$	312

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, 2024 and December 31, 2023, 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 $75 million and $59 million for the nine-month periods ended September 30, 2024 and 2023, respectively.

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist of customer deposits as allowed under the FERC gas tariffs. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):

	As of
	September 30,		December 31,
	2024		2023
Cash and cash equivalents	$	117	$	62
Restricted cash and cash equivalents included in other current assets	25		31
Total cash and cash equivalents and restricted cash and cash equivalents	$	142	$	93

184

(7)    Recent Financing Transactions

In October 2024, Eastern Energy Gas issued $900 million of its 5.65% Senior Notes due 2054. Eastern Energy Gas intends to use the net proceeds from the sale of the notes to repay its $600 million Senior Notes due November 15, 2024 and $339 million Senior Notes due December 15, 2024.

(8)    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,
	2024		2023		2024		2023
Federal statutory income tax rate	21	%	21	%	21	%	21	%
State income tax, net of federal income tax impacts	2		(8)		3		(1)
Equity earnings	1		1		2		1
Noncontrolling interest	(3)		(10)		(3)		(10)
Other, net	—		(1)		(1)		—
Effective income tax rate	21	%	3	%	22	%	11	%

Berkshire Hathaway Inc. 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 $9 million and $67 million as of September 30, 2024 and December 31, 2023, respectively. The change is primarily due to the settlement of the income tax receivable balance through non-cash distributions in 2024.

(9)    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 to the MidAmerican Energy Company Retirement Plan for the nine-month periods ended September 30, 2024 and 2023, and $1 million to the MidAmerican Energy Company Welfare Benefit Plan for the nine-month periods ended September 30, 2024 and 2023. 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, 2024 and December 31, 2023, 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 $53 million.

(10)    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.

185

•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.

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, 2024:
Assets:
Money market mutual funds	$	117	$	—	$	—	$	117
Equity securities:
Investment funds	17		—		—		17
	$	134	$	—	$	—	$	134
Liabilities:
Foreign currency exchange rate derivatives	$	—	$	(5)	$	—	$	(5)
	$	—	$	(5)	$	—	$	(5)
As of December 31, 2023:
Assets:
Money market mutual funds	$	62	$	—	$	—	$	62
Equity securities:
Investment funds	19		—		—		19
	$	81	$	—	$	—	$	81
Liabilities:
Foreign currency exchange rate derivatives	$	—	$	(8)	$	—	$	(8)
	$	—	$	(8)	$	—	$	(8)

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.

186

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.

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 following table presents the carrying value and estimated fair value of Eastern Energy Gas' long-term debt (in millions):

	As of September 30, 2024				As of December 31, 2023
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term debt	$	3,261	$	3,073	$	3,254	$	2,968

(11)    Commitments and Contingencies

Environmental Laws and Regulations

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

Legal Matters

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

187

(12)    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,
	2024		2023			2024		2023
Customer Revenue:
Regulated:
Gas transmission and storage	$	274	$	281		$	883	$	907
Wholesale	7		5		—	7		5
Other	—		3			1		4
Total regulated	281		289			891		916
Nonregulated	182		187			602		630
Total Customer Revenue	463		476			1,493		1,546
Other revenue(1)	—		(1)			—		3
Total operating revenue	$	463	$	475		$	1,493	$	1,549

(1)Other revenue consists primarily of revenue recognized in accordance with Accounting Standards Codification 815, "Derivative and Hedging" which includes unrealized gains and losses for derivatives not designated as hedges related to natural gas sales contracts and the royalties from the conveyance of mineral rights accounted for under ASC 932 "Extractive Activities – Oil and Gas".

Eastern Energy Gas has recognized contract liabilities of $28 million and $40 million as of September 30, 2024 and December 31, 2023, 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 periods ended September 30, 2024 and 2023, Eastern Energy Gas recognized revenue of $13 million and $51 million, respectively, from the beginning contract liability balances.

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, 2024 (in millions):

	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total
Eastern Energy Gas	$	1,691	$	14,106	$	15,797

188

(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						Accumulated
	Amounts On		Unrealized				Other
	Retirement		Losses on Cash		Noncontrolling		Comprehensive
	Benefits		Flow Hedges		Interests		Loss, Net
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)
Balance, December 31, 2023	$	(3)	$	(38)	$	1	$	(40)
Other comprehensive income	1		1		—		2
Balance, September 30, 2024	$	(2)	$	(37)	$	1	$	(38)

189

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

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of 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 2024 and 2023

Overview

Net income attributable to Eastern Energy Gas for the third quarter of 2024 was $114 million, an increase of $22 million, compared to 2023. Net income increased primarily due to higher earnings from Cove Point of $39 million, largely due to the acquisition of an additional 50% limited partner interest in Cove Point, partially offset by one-time favorable income tax adjustments recorded in 2023 as a result of the acquisition of an additional 50% limited partner interest in Cove Point of $18 million.

Net income attributable to Eastern Energy Gas for the first nine months of 2024 was $453 million, an increase of $140 million, compared to 2023. Net income increased primarily due to higher earnings from Cove Point of $150 million, largely due to the acquisition of an additional 50% limited partner interest in Cove Point.

Quarter Ended September 30, 2024 Compared to Quarter Ended September 30, 2023

Operating revenue decreased $12 million, or 3%, for the third quarter of 2024 compared to 2023, primarily due to a decrease in Cove Point's storage-related service revenues of $9 million and a decrease in variable revenue related to park and loan activity of $4 million, partially offset by an increase in regulated gas transmission service revenues due to the settlement of CGT's general rate case of $5 million.

Operations and maintenance decreased $14 million, or 9%, for the third quarter of 2024 compared to 2023, primarily due to lower outside services.

Depreciation and amortization increased $5 million, or 6%, for the third quarter of 2024 compared to 2023, primarily due to higher plant placed in service of $3 million and the settlement of deprecation rates in CGT's general rate case of $2 million.

Interest expense decreased $5 million, or 14%, for the third quarter of 2024 compared to 2023, primarily due to the repayment of $400 million of long-term debt in the fourth quarter of 2023.

Interest and dividend income decreased $5 million, or 63%, for the third quarter of 2024 compared to 2023, primarily due to lower outstanding loans under BHE GT&S' intercompany revolving credit agreement.

Income tax expense increased $31 million for the third quarter of 2024 compared to 2023 and the effective tax rate was 21% for 2024 and 3% for 2023. The effective tax rate increased primarily due to one-time favorable adjustments recorded in 2023, which was a result of the acquisition of an additional 50% limited partner interest in Cove Point.

Net income attributable to noncontrolling interests decreased $51 million, or 65%, for the third quarter of 2024 compared to 2023, primarily due to the acquisition of an additional 50% limited partner interest in Cove Point.

First Nine Months of 2024 Compared to First Nine Months of 2023

Operating revenue decreased $56 million, or 4%, for the first nine months of 2024 compared to 2023, primarily due to a decrease in Cove Point LNG variable revenue of $21 million, a decrease in variable revenue related to park and loan activity of $20 million and a decrease in Cove Point's storage-related service revenues of $20 million, partially offset by an increase in EGTS' regulated gas transmission and storage services revenues primarily due to higher volumes of $12 million and an increase in regulated gas transmission service revenues due to the settlement of CGT's general rate case of $6 million.

Cost of gas decreased $25 million, or 81%, for the first nine months of 2024 compared to 2023, primarily due to the unfavorable revaluation of volumes retained in 2023.

190

Operations and maintenance decreased $20 million, or 5%, for the first nine months of 2024 compared to 2023, primarily due to lower technology and related charges of $13 million, lower outside services of $9 million due to the termination of Dominion Energy Inc.'s transition services agreement and a decrease in salary and benefit expenses of $4 million, partially offset by a gain in 2023 from an agreement to convey development rights underneath one of its natural gas storage fields of $8 million.

Depreciation and amortization increased $10 million, or 4%, for the first nine months of 2024 compared to 2023, primarily due to higher plant placed in service of $7 million and the settlement of deprecation rates in CGT's general rate case of $3 million.

Property and other taxes increased $1 million, or 1%, for the first nine months of 2024 compared to 2023, primarily due to an adjustment in 2023 due to lower than estimated 2022 tax assessments of $6 million, partially offset by the expiration of Cove Point's payment in lieu of taxes program and the start of Cove Point's property tax credit agreement of $4 million.

Interest expense decreased $9 million, or 8%, for the first nine months of 2024 compared to 2023, primarily due to the repayment of $250 million of long-term debt in the second quarter of 2023 and $400 million of long-term debt in the fourth quarter of 2023 of $17 million, partially offset by higher outstanding borrowings under BHE GT&S' intercompany revolving credit agreement of $8 million.

Interest and dividend income decreased $21 million, or 75%, for the first nine months of 2024 compared to 2023, primarily due to lower outstanding loans under BHE GT&S' intercompany revolving credit agreement.

Income tax expense increased $67 million, or 89%, for the first nine months of 2024 compared to 2023 and the effective tax rate was 22% for 2024 and 11% for 2023. The effective tax rate increased primarily due to one-time favorable adjustments recorded in 2023, which was a result of the acquisition of an additional 50% limited partner interest in Cove Point.

Equity income increased $12 million, or 28%, for the first nine months of 2024 compared to 2023, primarily due to higher earnings from Iroquois due to favorable fixed negotiated rate agreements.

Net income attributable to noncontrolling interests decreased $226 million, or 69%, for the first nine months of 2024 compared to 2023, primarily due to the acquisition of an additional 50% limited partner interest in Cove Point of $216 million and lower net income attributable to Cove Point of $10 million.

Liquidity and Capital Resources

As of September 30, 2024, Eastern Energy Gas' total net liquidity was as follows (in millions):

Cash and cash equivalents	$	117
Intercompany revolving credit agreement	400
Total net liquidity	$	517
Intercompany revolving credit agreement:
Maturity date	2025

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2024 and 2023 were $1.0 billion and $982 million, respectively. The change is primarily due to the repayment of EGTS rate refunds to customers in 2023, the timing of payments for operating costs and other changes in working capital, partially offset by unfavorable operating results.

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, 2024 and 2023 were $(240) million and $301 million, respectively. The change is primarily due to a decrease in repayments of notes by its parent under an intercompany revolving credit agreement of $734 million, proceeds from the assignment of shale development rights in 2023 of $8 million and an increase in capital expenditures of $3 million, partially offset by a decrease in notes issued to its parent under an intercompany revolving credit agreement of $198 million.

191

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2024 were $(749) million and consisted of net repayment of notes payable to affiliates of $400 million, distributions to noncontrolling interests from Cove Point of $123 million and distributions to its indirect parent, BHE, of $226 million.

Net cash flows from financing activities for the nine-month period ended September 30, 2023 were $(1.3) billion. Sources of cash totaled $2.9 billion and consisted of proceeds from equity contributions to fund the Transaction. 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.

Long-term debt

Eastern Energy Gas currently has an effective shelf registration statement with the SEC to issue an additional $1.6 billion of long-term debt securities through January 11, 2027.

For a discussion of recent financing transactions, refer to Note 7 of Notes to Consolidated Financial Statements in Part I, Item 1

of this Form 10-Q. In October 2024, EGTS entered into an agreement authorizing the issuance of $150 million of its 5.02% Senior Notes due 2034, subject to the satisfaction of certain customary terms and conditions, with an expected closing date in December 2024. EGTS intends to use the net proceeds from the sale of the notes to repay its $111 million Senior Notes due December 15, 2024, and for general corporate purposes.

Future Uses of Cash

Eastern Energy Gas has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, intercompany revolving credit agreements, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, investments, debt retirements and other capital requirements. The availability and terms under which Eastern Energy Gas and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, Eastern Energy Gas' credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the natural gas transmission and storage and LNG export, import and storage industries.

Capital Expenditures

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

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

	Nine-Month Periods				Annual
	Ended September 30,				Forecast
	2023		2024		2024
Natural gas transmission and storage	$	17	$	41	$	65
Other	224		203		292
Total	$	241	$	244	$	357

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.

192

Material Cash Requirements

As of September 30, 2024, 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, 2023.

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, 2023. There have been no significant changes in Eastern Energy Gas' assumptions regarding critical accounting estimates since December 31, 2023.

193

Eastern Gas Transmission and Storage, Inc. and its subsidiaries

Consolidated Financial Section

194

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, 2024, 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, 2024 and 2023, and of cash flows for the nine-month periods ended September 30, 2024 and 2023, 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, 2023 and the related consolidated statements of operations, comprehensive income, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 23, 2024 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, 2023, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Richmond, Virginia

November 1, 2024

195

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

	As of
	September 30,		December 31,
	2024		2023
ASSETS
Current assets:
Cash and cash equivalents	$	35	$	5
Restricted cash and cash equivalents	23		29
Trade receivables, net	71		104
Receivables from affiliates	14		9
Inventories	63		59
Income taxes receivable	29		70
Prepayments and other deferred charges	26		22
Natural gas imbalances	22		34
Other current assets	4		5
Total current assets	287		337
Property, plant and equipment, net	4,768		4,715
Other assets	85		92
Total assets	$	5,140	$	5,144

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

196

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions, except share data)

	As of
	September 30,		December 31,
	2024		2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	43	$	41
Accounts payable to affiliates	33		29
Accrued interest	23		7
Accrued property, income and other taxes	55		58
Accrued employee expenses	31		20
Notes payable to affiliates	—		2
Regulatory liabilities	14		22
Customer and security deposits	23		29
Current portion of long-term debt	111		111
Other current liabilities	10		21
Total current liabilities	343		340
Long-term debt	1,473		1,472
Regulatory liabilities	523		523
Other long-term liabilities	178		121
Total liabilities	2,517		2,456
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	1,339		1,304
Retained earnings	702		803
Accumulated other comprehensive loss, net	(27)		(28)
Total shareholder's equity	2,623		2,688
Total liabilities and shareholder's equity	$	5,140	$	5,144

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

197

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,
	2024		2023		2024		2023
Operating revenue	$	233	$	233	$	733	$	747
Operating expenses:
Cost of gas	8		6		6		31
Operations and maintenance	98		99		280		293
Depreciation and amortization	39		38		116		112
Property and other taxes	14		14		42		35
Total operating expenses	159		157		444		471
Operating income	74		76		289		276
Other income (expense):
Interest expense	(16)		(17)		(50)		(52)
Allowance for equity funds	2		1		5		4
Other, net	2		—		4		2
Total other income (expense)	(12)		(16)		(41)		(46)
Income before income tax expense (benefit)	62		60		248		230
Income tax expense (benefit)	15		16		63		59
Net income	$	47	$	44	$	185	$	171

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

198

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,
	2024		2023		2024		2023
Net income	$	47	$	44	$	185	$	171
Other comprehensive income, net of tax:
Unrealized gains on cash flow hedges, net of tax of $—, $1, $— and $1	—		—		1		1
Total other comprehensive income, net of tax	—		—		1		1
Comprehensive income	$	47	$	44	$	186	$	172

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

199

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, 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
Balance, June 30, 2024	60,101	$	609	$	1,339	$	664	$	(27)	$	2,585
Net income	—	—		—		47		—		47
Dividends declared	—	—		—		(9)		—		(9)
Balance, September 30, 2024	60,101	$	609	$	1,339	$	702	$	(27)	$	2,623
Balance, December 31, 2023	60,101	$	609	$	1,304	$	803	$	(28)	$	2,688
Net income	—	—		—		185		—		185
Other comprehensive income	—	—		—		—		1		1
Dividends declared	—	—		—		(286)		—		(286)
Contributions	—	—		35		—		—		35
Balance, September 30, 2024	60,101	$	609	$	1,339	$	702	$	(27)	$	2,623

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

200

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Ended September 30,
	2024		2023
Cash flows from operating activities:
Net income	$	185	$	171
Adjustments to reconcile net income to net cash flows from operating activities:
Gains on other items, net	(1)		(8)
Depreciation and amortization	116		112
Allowance for equity funds	(5)		(4)
Changes in regulatory assets and liabilities	(13)		(79)
Deferred income taxes	58		50
Other, net	(1)		(5)
Changes in other operating assets and liabilities:
Trade receivables and other assets	47		35
Receivables from affiliates	(5)		5
Gas balancing activities	6		26
Accrued property, income and other taxes	(19)		(21)
Accounts payable to affiliates	4		11
Accounts payable and other liabilities	19		24
Net cash flows from operating activities	391		317
Cash flows from investing activities:
Capital expenditures	(154)		(163)
Proceeds from assignment of shale development rights	—		8
Proceeds from sales of marketable securities	3		—
Other, net	1		(4)
Net cash flows from investing activities	(150)		(159)
Cash flows from financing activities:
Repayment of notes payable to affiliates, net	(2)		(21)
Dividends paid	(215)		(141)
Net cash flows from financing activities	(217)		(162)
Net change in cash and cash equivalents and restricted cash and cash equivalents	24		(4)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	34		45
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	58	$	41

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

201

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, 2024, and for the three- and nine-month periods ended September 30, 2024 and 2023. The results of operations for the three- and nine-month periods ended September 30, 2024 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in EGTS' Annual Report on Form 10-K for the year ended December 31, 2023 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in EGTS' accounting policies or its assumptions regarding significant accounting estimates during the nine-month period ended September 30, 2024.

(2)    New Accounting Pronouncements

In November 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items, as well as incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. EGTS is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. EGTS is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

202

In March 2024, the United States Securities and Exchange Commission adopted final rules requiring disclosure of certain climate-related information in registrations statements and Form 10-Ks. The final rules require a registrant to disclose, among other things: material climate-related risks; activities to mitigate or adapt to such risks; information about the registrant's board of directors' oversight of climate-related risks and management's role in managing material climate-related risks; and information on any climate-related targets or goals that are material to the registrant's business, results of operations, or financial condition. Further, to facilitate investors' assessment of certain climate-related risks, the final rules require disclosure of Scope 1 and/or Scope 2 greenhouse gas emissions when those emissions are material and disclosure of the financial statement effects of severe weather events and other natural conditions. The final rules include phased-in compliance periods for all registrants, with the compliance date dependent on the registrant's filer status and the content of the disclosure. On April 4, 2024, the United States Securities and Exchange Commission voluntarily stayed implementation of the final rules, pending the completion of judicial review of consolidated challenges by the Court of Appeals for the Eighth Circuit. EGTS is currently evaluating the impact of adopting the final rules on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

(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	2024		2023
Interstate natural gas transmission and storage assets	28 - 50 years	$	7,126	$	7,046
Intangible plant	12 - 20 years	94		80
Plant in-service		7,220		7,126
Accumulated depreciation and amortization		(2,662)		(2,563)
		4,558		4,563
Construction work-in-progress		210		152
Property, plant and equipment, net		$	4,768	$	4,715

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.

203

(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,
	2024		2023
Investments:
Investment funds	$	17	$	19
Restricted cash and cash equivalents:
Customer deposits	23		29
Total restricted cash and cash equivalents	23		29
Total investments and restricted cash and cash equivalents	$	40	$	48
Reflected as:
Current assets	$	23	$	29
Other assets	17		19
Total investments and restricted cash and cash equivalents	$	40	$	48

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,
	2024		2023
Cash and cash equivalents	$	35	$	5
Restricted cash and cash equivalents	23		29
Total cash and cash equivalents and restricted cash and cash equivalents	$	58	$	34

(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,
	2024		2023		2024		2023
Federal statutory income tax rate	21	%	21	%	21	%	21	%
State income tax, net of federal income tax impacts	4		6		4		5
Effects of ratemaking	(1)		—		—		—
Effective income tax rate	24	%	27	%	25	%	26	%

204

Berkshire Hathaway Inc. includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, EGTS' 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, EGTS had a receivable from BHE of $22 million and $57 million as of September 30, 2024 and December 31, 2023, respectively. The change is primarily due to the settlement of the income tax receivable balance through non-cash distributions in 2024.

(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 to the MidAmerican Energy Company Retirement Plan for the nine-month periods ended September 30, 2024 and 2023, and $1 million to the MidAmerican Energy Company Welfare Benefit Plan for the nine-month periods ended September 30, 2024 and 2023. 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, 2024 and December 31, 2023, EGTS' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets was $48 million.

(7)    Fair Value Measurements

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

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

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

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

205

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, 2024:
Assets:
Money market mutual funds	$	35	$	—	$	—	$	35
Equity securities:
Investment funds	17		—		—		17
	$	52	$	—	$	—	$	52
As of December 31, 2023:
Assets:
Money market mutual funds	$	5	$	—	$	—	$	5
Equity securities:
Investment funds	19		—		—		19
	$	24	$	—	$	—	$	24

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, 2024				As of December 31, 2023
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	1,584	$	1,443	$	1,583	$	1,386

(8)    Commitments and Contingencies

Environmental Laws and Regulations

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

206

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,
	2024		2023		2024		2023
Customer Revenue:
Regulated:
Gas transmission	$	142	$	144	$	475	$	486
Gas storage	69		69		210		206
Wholesale	7		5		7		5
Other	—		1		1		1
Total regulated	218		219		693		698
Management service and other revenues	15		14		40		46
Total Customer Revenue	233		233		733		744
Other revenue(1)	—		—		—		3
Total operating revenue	$	233	$	233	$	733	$	747

(1)Other revenue consists primarily of revenue recognized in accordance with Accounting Standards Codification 815, "Derivative and Hedging" which includes unrealized gains and losses for derivatives not designated as hedges related to natural gas sales contracts and the royalties from the conveyance of mineral rights accounted for under ASC 932 "Extractive Activities – Oil and Gas".

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, 2024 (in millions):

	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total
EGTS	$	795	$	3,084	$	3,879

207

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 2024 and 2023

Overview

Net income for the third quarter of 2024 was $47 million, an increase of $3 million, compared to 2023.

Net income for the first nine months of 2024 was $185 million, an increase of $14 million, compared to 2023. Net income increased primarily due to higher margin from regulated gas transmission and storage operations of $11 million, lower technology and related charges and lower outside services due to the termination of Dominion Energy Inc.'s transition services agreement, partially offset by a gain in 2023 from an agreement to convey development rights underneath one of its natural gas storage fields and an adjustment in 2023 due to lower than estimated 2022 tax assessments.

Quarter Ended September 30, 2024 Compared to Quarter Ended September 30, 2023

Operating revenue was flat for the third quarter of 2024 compared to 2023, primarily due to a decrease in variable revenue related to park and loan activity of $4 million, partially offset by an increase in regulated gas sales for operational and system balancing purposes primarily due to increased volumes of $2 million.

Income tax expense decreased $1 million, or 6%, for the third quarter of 2024 compared to 2023 and the effective tax rate was 24% for 2024 and 27% 2023. The effective tax rate decreased primarily due to the reduction in Pennsylvania's statutory rate.

First Nine Months of 2024 Compared to First Nine Months of 2023

Operating revenue decreased $14 million, or 2%, for the first nine months of 2024 compared to 2023, primarily due to a decrease in variable revenue related to park and loan activity of $20 million and a decrease in management services and other revenues of $6 million, partially offset by an increase in regulated gas transmission and storage services revenues primarily due to higher volumes of $12 million.

Cost of gas decreased $25 million, or 81%, for the first nine months of 2024 compared to 2023, primarily due to the unfavorable revaluation of volumes retained in 2023.

Operations and maintenance decreased $13 million, or 4%, for the first nine months of 2024 compared to 2023, primarily due to lower technology and related charges of $9 million, lower outside services of $7 million due to the termination of Dominion Energy Inc.'s transition services agreement and a decrease in services provided to affiliates of $2 million, partially offset by a gain in 2023 from an agreement to convey development rights underneath one of its natural gas storage fields of $8 million.

Property and other taxes increased $7 million, or 20%, for the first nine months of 2024 compared to 2023, primarily due to an adjustment in 2023 due to lower than estimated 2022 tax assessments of $6 million.

Income tax expense increased $4 million, or 7%, for the first nine months of 2024 compared to 2023 and the effective tax rate was 25% for 2024 and 26% for 2023.

208

Liquidity and Capital Resources

As of September 30, 2024, EGTS' total net liquidity was as follows (in millions):

Cash and cash equivalents	$	35
Intercompany revolving credit agreement	400
Total net liquidity	$	435
Intercompany revolving credit agreement:
Maturity date	2025

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2024 and 2023 were $391 million and $317 million, respectively. The change is primarily due to the repayment of EGTS rate refunds to customers in 2023 and favorable operating results, partially offset by other changes in working capital.

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

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2024 and 2023 were $(150) million and $(159) million, respectively. The change is primarily due to a decrease in capital expenditures of $9 million.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2024 were $(217) million and consisted of dividends paid to Eastern Energy Gas of $215 million and the net repayment of notes payable to Eastern Energy Gas of $2 million.

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 the net repayment of notes payable to Eastern Energy Gas of $21 million.

Long-term Debt

In October 2024, EGTS entered into an agreement authorizing the issuance of $150 million of its 5.02% Senior Notes due 2034, subject to the satisfaction of certain customary terms and conditions, with an expected closing date in December 2024. EGTS intends to use the net proceeds from the sale of the notes to repay its $111 million Senior Notes due December 15, 2024, and for general corporate purposes.

Future Uses of Cash

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

Capital Expenditures

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

209

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
	2023		2024		2024
Natural gas transmission and storage	$	11	$	17	$	34
Other	152		137		206
Total	$	163	$	154	$	240

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, 2024, 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, 2023.

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, 2023. There have been no significant changes in EGTS' assumptions regarding critical accounting estimates since December 31, 2023.

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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, 2023. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2023. Refer to Note 9 of the Notes to Consolidated Financial Statements of PacifiCorp, Note 9 of the Notes to Consolidated Financial Statements of Nevada Power and Note 10 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, 2024.

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, 2024 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, 2023.

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP

In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, including the 2020 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.

In July 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, burning over 60,000 acres. Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged; 185 structures destroyed, including residences; 12 injuries; and four fatalities.

As described below, a significant number of complaints and demands alleging similar claims have been filed in Oregon and California related to the Wildfires. As of September 30, 2024, amounts sought in outstanding complaints and demands filed in Oregon and in certain demands made in California totaled approximately $3 billion, excluding any doubling or trebling of damages included in the complaints and the mass complaints described below that seek $46 billion. Generally, the complaints filed in California do not specify damages sought and are excluded from this amount. For class actions, amounts specified by the plaintiffs in the complaints include amounts based on estimates of the potential class size, which ultimately may be significantly greater than estimated. Additionally, damages are not limited to the amounts specified in the initially filed complaints as plaintiffs are frequently allowed to amend their complaints to add additional damages and amounts awarded in a court proceeding may be significantly greater than the damages specified. Oregon law provides for doubling of economic and property damages in the event the defendant is found to have acted with gross negligence, recklessness, willfulness or malice. Oregon law provides for trebling of the damages associated with timber, shrubs and produce in the event the defendant is determined to have willfully and intentionally trespassed.

Investigations into the causes and origins of the 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 11 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q.

2020 Slater Fire California and Oregon Complaints and Demands

As described below, a significant number of complaints on behalf of plaintiffs associated with the Northern California and Southern Oregon Slater Fire ("Slater Fire") have been filed in Oregon and California. The complaints generally allege: (i) inverse condemnation; (ii) negligence; (iii) trespass; (iv) nuisance; and (v) violation of certain sections of the California Public Utilities Code and the California Health & Safety Code and request a jury trial and seek various damages, generally including: (i) economic damages; (ii) noneconomic damages; (iii) doubling of economic damages; (iv) punitive damages; (v) pre- and post-judgment interest; and (vi) attorneys' fees and other costs. Certain complaints include wrongful death claims as described below.

Other than the claims of three individual plaintiffs who are exploring resolution and the U.S. government claim described below, all complaints filed to date for the Slater Fire have been settled.

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Hitchcock et al. v. PacifiCorp and Consolidated California Slater Fire Cases

On December 16, 2020, a complaint against PacifiCorp was filed, captioned Hitchcock et al. v. PacifiCorp, Case No. 34-2020-00290833 ("Hitchcock") in California Superior Court, Sacramento County, California ("Sacramento County Superior Court California") by approximately 69 plaintiffs. The Hitchcock case makes similar allegations as those described above for the Slater Fire, includes a wrongful death claim for one of the two Slater Fire decedents and does not specify the amount of damages sought.

The following complaints also filed in Sacramento County Superior Court California have been consolidated into the Hitchcock case: Hillman complaint filed January 29, 2021, approximately 234 plaintiffs; Franklin complaint filed February 17, 2022, approximately 43 plaintiffs; Ormsby complaint filed April 18, 2022, approximately four plaintiffs; Hodges complaint filed August 23, 2022, approximately 26 plaintiffs; Nixon complaint filed August 31, 2022, approximately two plaintiffs; Bleeg complaint filed September 1, 2022, approximately 17 plaintiffs; Lemon complaint filed September 2, 2022, approximately 186 plaintiffs; Sanchez complaint filed September 7, 2022, approximately 10 plaintiffs; Duval complaint filed September 29, 2022, approximately 24 plaintiffs; Fernandez complaint filed August 17, 2023, approximately 51 plaintiffs; Thomason complaint filed September 7, 2023, approximately four plaintiffs; and Bledsoe complaint filed September 28, 2023, approximately three plaintiffs.

The complaints make similar allegations as those described above for the Slater Fire and do not specify the amount of damages sought.

In 2023, PacifiCorp settled certain claims in the consolidated Hitchcock case for $8 million representing three individual plaintiffs and one commercial timber plaintiff. In the three-month period ending March 31, 2024, PacifiCorp reached additional settlements totaling $60 million representing 165 plaintiffs, including settlement of the wrongful death claim and the Terran case described below. In April 2024, PacifiCorp reached additional settlements totaling $2 million representing 16 plaintiffs, including certain plaintiffs in the Franklin and Bleeg cases. In June 2024, PacifiCorp reached a settlement totaling $10 million for 54 plaintiffs in the California Slater Fire cases, as well as the Oregon Slater Fire cases described below. In June 2024, PacifiCorp reached additional settlements totaling $150 million representing 378 plaintiffs and resolving substantially all individual claims in the California Slater Fire cases. As a result of the settlements, the bellwether trial scheduled for October 7, 2024 was vacated.

Other Slater Fire Cases

On August 10, 2022, a complaint against PacifiCorp was filed, captioned Siskiyou County v. PacifiCorp, Case No. 34-2022-00324977 by one plaintiff in Sacramento County Superior Court California. The complaint makes similar allegations as those described above for the Slater Fire and does not specify the amount of damages sought. In April 2023, PacifiCorp received a mediation demand from Siskiyou County for approximately $6 million in damages. On May 15, 2024, the case settled for $2 million.

On July 12, 2023, a complaint against PacifiCorp was filed, captioned Susan Irene Terran et al. v. PacifiCorp, Case No. 23CV27759 ("Terran") in Oregon Circuit Court in Multnomah County, Oregon ("Multnomah County Circuit Court Oregon"), by approximately six plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and seeks various damages, including economic damages of approximately $10 million based on $1 million for each of the five individual plaintiffs and $5 million for the one non-individual plaintiff. The complaint seeks noneconomic damages to be determined at trial. The Terran case has settled.

On September 8, 2023, a subrogation complaint against PacifiCorp was filed, captioned Travelers Commercial Insurance Company et al. v. PacifiCorp, Case No. 23CV008226 in Sacramento County Superior Court California by four plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and does not specify the amount of damages sought. This case settled on February 12, 2024.

Black et al. v. PacifiCorp and Consolidated Oregon Slater Fire Cases

On March 10, 2022, a complaint against PacifiCorp was filed, captioned Susan Black et al. v. PacifiCorp, Case No. 22CV08622 ("Black") in Multnomah County Circuit Court Oregon by approximately 28 plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and seeks various damages, including economic damages of approximately $44 million based on $1 million for each of the 24 individual plaintiffs and $5 million for each of the four non-individual plaintiffs. The individual plaintiffs also seek unspecified noneconomic damages.

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The following complaints filed in Multnomah County Circuit Court Oregon have been consolidated into the Black case: Denny complaint filed August 31, 2022, approximately seven plaintiffs and Sparks amended complaint filed September 7, 2022, approximately five plaintiffs. The complaints make similar allegations as those described above for the Slater Fire and each seek various damages, including economic damages of approximately $16 million based on $1 million for each of the 11 individual plaintiffs and $5 million for the one non-individual plaintiff across both the Denny and Sparks complaints. The individual plaintiffs also seek unspecified noneconomic damages. As described above, in June 2024, PacifiCorp reached a settlement totaling $10 million for 54 plaintiffs in the California and Oregon Slater Fire cases, which resolved the remaining Oregon claims. As a result, the bellwether trial scheduled for September 23, 2024, was vacated.

United States – Loss and Damages to Federal Lands – Slater Fire

PacifiCorp received a notice of indebtedness from the U.S. Department of Agriculture Forest Service ("USFS") indicating that PacifiCorp owes $356 million for fire suppression costs, natural resource damages and burned area emergency response costs incurred by the USFS associated with the 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. In January 2024, PacifiCorp received correspondence from the U.S. Department of Justice ("USDOJ") indicating its intent to litigate the matter due to PacifiCorp not having paid the $356 million. PacifiCorp is actively cooperating with the USDOJ on resolving these alleged claims, including through the pursuit of alternative dispute resolution.

2020 Oregon Wildfires, Excluding Slater Fire

As described below, a significant number of complaints on behalf of plaintiffs associated with the 2020 Wildfires have been filed in Oregon in addition to those described above for the Slater Fire. The plaintiffs generally 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; (v) inverse condemnation; (vi) pre- and post-judgment interest; and (vii) reasonable attorney fees, investigation costs and expert witness fees. The complaints generally assert claims for: (i) noneconomic damages, including mental suffering, emotional distress, inconvenience and interference with normal and usual activities; (ii) damages for real and personal property and other economic losses; (iii) double the amount of property and economic damages; (iv) treble damages for specific costs associated with loss of forestry, trees and shrubbery; and (v) double the damages for the costs of litigation and reforestation. Certain complaints include wrongful death claims as described below. The plaintiffs generally demand a trial by jury and reserve their right to further amend their complaints to allege claims for punitive damages.

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, Case No. 20CV33885 ("James") in Multnomah County Circuit Court Oregon. 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 seeks damages similar to those described above, including not less than $600 million of economic damages and in excess of $1 billion of noneconomic damages for the plaintiffs and the class. Numerous cases have been consolidated into James as described below.

On April 29, 2024, May 16, 2024, May 31, 2024, July 31, 2024 and September 11, 2024, five separate mass complaints against PacifiCorp naming 1,000, 100, 265, 78 and 93 individual class members, respectively, were filed in Multnomah County Circuit Court Oregon captioned Shane A Henson et al. v. PacifiCorp, Karen Andersen et al. v. PacifiCorp, Vanessa Alexander et al. v. PacifiCorp, Emily Broderick et al. v. PacifiCorp and Sergio Garcia Montes et al. v. PacifiCorp, respectively, each referencing James Case No. 20CV33885 as the lead case. The James mass complaints make damages only allegations seeking for each individual class member $5 million of economic damages, $25 million of noneconomic damages and punitive damages equal to 0.25 times the amount of economic and noneconomic damages. The James mass complaints also assert doubling of economic damages for each individual class member. The class members demand a trial by jury. Refer to "James Court Activity" section below for information regarding additional damages phase trials.

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James Trial Activity

On April 24, 2023, the jury trial for James with respect to the 17 named plaintiffs began in Multnomah County Circuit Court Oregon. In June 2023, the jury issued its verdict finding PacifiCorp liable to the 17 named plaintiffs and to the class with respect to the four wildfires. The jury found PacifiCorp's conduct grossly negligent, reckless and willful as to each plaintiff and the entire class. The jury awarded the 17 named plaintiffs $90 million of damages, including $4 million of economic 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 Oregon ordered trial dates for three damages phase trials described below wherein plaintiffs in each of the three damages phase trials would present evidence regarding their damages.

In January 2024, the Multnomah County Circuit Court Oregon entered a limited judgment and money award for the June 2023 James verdict. The limited judgment awards $92 million of damages based on the amounts awarded by the jury, as well as doubling of the economic damages and offsetting of any insurance proceeds received by plaintiffs. The limited judgment created a lien against PacifiCorp, attaching a debt for the money awards. PacifiCorp posted a supersedeas bond, which stays any effort to seek payment of the judgment pending final resolution of any appeals. Under Oregon Revised Statutes 82.010, interest at a rate of 9% per annum will accrue on the judgment commencing at the date the judgment was entered until the entire money award is paid, amended or reversed by an appellate court. In January 2024, PacifiCorp filed a notice of appeal associated with the June 2023 verdict in James, including whether the case can proceed as a class action and filed a motion to stay further damages phase trials. On February 14, 2024, the Oregon Court of Appeals denied PacifiCorp's request to stay the damages phase trials. On February 13, 2024, the 17 named plaintiffs filed a notice of cross-appeal as to the January 2024 limited judgment and money award. The appeals process and further actions could take several years.

In January 2024, the jury for the first James damages phase trial awarded nine plaintiffs $62 million of damages, including $6 million of economic damages and $56 million of noneconomic damages. After the jury verdict, the Multnomah County Circuit Court Oregon doubled the economic damages to $12 million and added $16 million of punitive damages using the 0.25 multiplier determined by the jury for the June 2023 James verdict, bringing the total damages awarded to $84 million. PacifiCorp requested that the Multnomah County Circuit Court Oregon judge offset the damage awards by deducting insurance proceeds received by any of the nine plaintiffs, and on March 25, 2024, the Multnomah County Circuit Court Oregon granted in large part the offset request. In April 2024, the Multnomah County Circuit Court Oregon entered a limited judgment and money award for the January 2024 James verdict. The limited judgment awards $80 million of damages based on the amounts awarded by the jury and offsetting insurance proceeds received by plaintiffs. The limited judgment created a lien against PacifiCorp, attaching a debt for the money awards. In April 2024, PacifiCorp posted a supersedeas bond, which stays any effort to seek payment of the judgment pending final resolution of any appeals. PacifiCorp amended its January 2024 appeal of the June 2023 James verdict to include the January 2024 jury verdict.

In March 2024, the jury for the second James damages phase trial awarded ten plaintiffs $42 million of damages, including $12 million of doubled economic damages, $23 million of noneconomic damages and $7 million of punitive damages using the 0.25 multiplier determined by the jury for the June 2023 James verdict. PacifiCorp requested that the Multnomah County Circuit Court Oregon judge offset the damage awards by deducting insurance proceeds received by any of the ten plaintiffs and on May 6, 2024, the Multnomah County Circuit Court Oregon granted the offset request. In June 2024, the Multnomah County Circuit Court Oregon entered a limited judgment and money award for the March 2024 James verdict. The limited judgment awards $38 million of damages based on the amounts awarded by the jury and offsetting insurance proceeds received by plaintiffs. The limited judgment created a lien against PacifiCorp, attaching a debt for the money awards. In July 2024, PacifiCorp posted a supersedeas bond, which stays any effort to seek payment of the judgment pending final resolution of any appeals. PacifiCorp further amended its appeal of the June 2023 James verdict to include the March 2024 jury verdict.

Additional damages phase trials have been scheduled in 2025 as described below.

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James Court Activity

On May 31, 2024, plaintiffs' counsel in James filed a motion to enter a case management order that requests the creation of a special docket to establish a trial process through which up to five consolidated damages trials for collectively 50 class members would occur each month going forward. PacifiCorp opposed the motion and filed a competing motion on June 26, 2024. On October 2, 2024, the Multnomah County Circuit Court Oregon issued a case management order and identified discovery, pleading and other deadlines applicable to nine damages phase trials to be held in 2025. The trials will adjudicate the damages of 10 plaintiffs per trial starting February 3, March 24, April 21, May 12, June 2, July 7, September 9, October 6, and December 7, 2025. The case management order allows the plaintiffs to select three need-based plaintiffs per trial using the following criteria: (i) the plaintiff is of advanced age, specifically seventy years of age or older and/or (ii) the plaintiff is suffering from sickness or illness that may impede their ability to participate in a later trial. The Multnomah County Circuit Court Oregon will randomly select the other seven plaintiffs. Within ten days after the verdict is rendered in the April 21 trial, and within 30 days after the verdict is rendered in the July 7 and December 7 trials, respectively, the parties are required to engage in global mediation with the objective of resolving the claims of the remaining absent class members.

On June 13, 2024, plaintiffs' counsel for the plaintiffs who have opted out of the James class filed a motion for the court to issue an order clarifying the scope of lead counsel in the damages phase to unrepresented members of the James class members. The opt-out plaintiffs' counsel describes in the motion its ability to have negotiated settlements for opt-out plaintiffs, bringing immediate financial relief and indicates that lead counsel for the class has placed its interests above those of the individuals they represent. On September 6, 2024, the Multnomah County Circuit Court Oregon denied in part the opt-out plaintiffs' counsel's motion to clarify the scope of lead counsel in the damages phase. Specifically, the Multnomah County Circuit Court Oregon ruled that lead counsel continue to represent absent class members "regardless of whether or not the absent class members have signed a retainer agreement with lead counsel." However, the Multnomah County Circuit Court Oregon clarified that absent class members could choose different legal representation, but each absent class member would have to expressly apply to the Multnomah County Circuit Court Oregon to be excluded from further representation by lead counsel and to terminate any ongoing attorney-client relationship.

On September 13, 2024, PacifiCorp filed a motion to make the James mass complaints more definite and certain. On October 4, 2024, in response to PacifiCorp's motion, the Multnomah County Circuit Court Oregon issued an order granting, in part, the motion. The order requires the plaintiffs selected for the nine damages phase trials scheduled in 2025 to file amended complaints alleging the specific facts that support their claims for economic and noneconomic damages.

James Consolidated Cases

The following cases have been consolidated into the James case:

Amended Salter filed August 20, 2021, in Multnomah County Circuit Court Oregon by approximately 97 individuals. The complaint seeks damages similar to those described above, including economic damages not to exceed $150 million and noneconomic damages not to exceed $500 million.

Amended Allen filed September 2, 2021, in Multnomah County Circuit Court Oregon by approximately five individuals. The Allen case seeks damages similar to those described above, including $8 million in economic and $24 million in noneconomic damages related to the Beachie Creek Fire.

Cady filed April 26, 2022, in Multnomah County Circuit Court Oregon. The Cady case was filed by 21 individuals seeking approximately $105 million in economic damages based on $5 million per each of the 21 individual plaintiffs in connection with the Echo Mountain Complex Fire. The individual plaintiffs also seek noneconomic damages to be determined at trial. In March 2024, a settlement was reached resulting in cancellation of the jury trial that was previously scheduled to begin May 6, 2024.

Dietrich filed August 26, 2022, in Multnomah County Circuit Court Oregon. The complaint, as amended on September 6, 2022, was filed by six Oregon residents individually and on behalf of a class 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, Echo Mountain Complex, 242 or South Obenchain fires. The amended complaint seeks $400 million in economic damages and $500 million in noneconomic damages. The Dietrich case is currently stayed due to plaintiffs' motion to consolidate the case into James.

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Freres Timber filed September 1, 2022, in Multnomah County Circuit Court Oregon. The complaint, as amended on October 18, 2023, was filed by three commercial plaintiffs seeking approximately $7 million in economic damages and $2 million of punitive damages. In March 2024, a settlement was reached, and the jury trial scheduled for April 2024 was cancelled.

Logan filed September 2, 2022, in Multnomah County Circuit Court Oregon. The Logan case was filed by five individuals seeking approximately $35 million in economic damages based on $5 million for each of the four individual plaintiffs and $15 million for the one non-individual plaintiff. In March 2024, a settlement was reached resulting in cancellation of the jury trial that was previously scheduled to begin May 6, 2024.

Bell filed September 7, 2022, in Multnomah County Circuit Court Oregon by 59 plaintiffs seeking $35 million in damages, including economic and noneconomic damages.

CW Specialty Lumber, Inc. filed December 6, 2022, in Multnomah County Circuit Court Oregon. The complaint, as amended on October 17, 2023, was filed by two commercial timber plaintiffs each seeking approximately $10 million in economic damages and $3 million in punitive damages. In March 2024, a settlement was reached, and the jury trial scheduled for April 2024 was cancelled.

The settlements reached with plaintiffs in the various James consolidated cases in March 2024 described above totaled $29 million.

Ashley Andersen et al. v. PacifiCorp and Consolidated Cases

On November 16, 2021, a complaint against PacifiCorp was filed, captioned Ashley Andersen et al. v. PacifiCorp, Case No. 21CV36567 ("Andersen") in Multnomah County Circuit Court Oregon. The Andersen case was filed by approximately 50 Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex Fire. The Andersen case as amended on December 6, 2022 makes allegations similar to those described above and seeks economic damages of approximately $83 million and noneconomic damages of approximately $83 million. Multiple complaints have been consolidated into Andersen with all associated complaints filed to date settled but for one plaintiff as described below.

The following complaints also filed in Multnomah County Circuit Court Oregon have been consolidated into the Andersen case each with allegations and damages similar to those described above for the Andersen case and each seek economic damages of approximately $83 million and noneconomic damages of approximately $83 million unless otherwise noted: Sparks filed December 17, 2021 and amended on September 7, 2022, approximately 49 plaintiffs, various damages of approximately $125 million; Russie filed May 13, 2022, approximately 45 plaintiffs, various damages of approximately $125 million; Klinger filed September 1, 2022, approximately 49 plaintiffs; Bowen filed September 1, 2022, approximately 47 plaintiffs; Weathers filed September 1, 2022, approximately 46 plaintiffs; Barnholdt filed September 6, 2022, approximately 26 plaintiffs; Pratt filed September 7, 2022, approximately 16 plaintiffs; Thompson filed September 7, 2022, approximately 49 plaintiffs; Cohn filed September 7, 2022, approximately 6 plaintiffs, $5 million for a wrongful death claim, $15 million in economic damages and $15 million in noneconomic damages.

On June 9, 2023, a complaint against PacifiCorp was filed by the same plaintiff group as Andersen captioned Annamarie Miller et al. v. PacifiCorp, Case No. 23CV23104 in Multnomah County Circuit Court Oregon by approximately 10 plaintiffs, seeking approximately $42 million in economic damages and $42 million in noneconomic damages associated with the Echo Mountain Complex Fire and makes allegations similar to those described above.

On May 31, 2024, PacifiCorp reached a settlement totaling $178 million with approximately 400 plaintiffs associated with the Echo Mountain Complex and Beachie Creek fires who opted out of the James class. The settlement mostly resolved the Andersen consolidated cases and the O'Keefe consolidated cases described below but for one plaintiff in Andersen and one plaintiff in O'Keefe. The settlement payments were made in July 2024. The trial for the remaining plaintiff in Andersen is scheduled for February 2025.

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Judith O'Keefe v. PacifiCorp and Consolidated Cases

On April 23, 2021, a complaint against PacifiCorp was filed, captioned Judith O'Keefe v. PacifiCorp, Case No. 21CV15857 ("O'Keefe") in Multnomah County Circuit Court Oregon associated with the Beachie Creek Fire. The complaint, as amended on January 31, 2024, was filed by one individual plaintiff seeking damages similar to those described above, including approximately $1 million in economic damages and $1 million in noneconomic damages. The O'Keefe consolidated cases have been settled except for one outstanding plaintiff. A jury trial is scheduled for November 4, 2024, through November 29, 2024; however, the plaintiff and PacifiCorp agree that the trial date should be continued as the parties explore resolution.

The following cases also associated with the Beachie Creek Fire have been consolidated into the O'Keefe case: Macy-Wyngarden filed September 1, 2022, in Multnomah County Circuit Court Oregon by approximately 12 plaintiffs seeking economic damages of approximately $83 million and noneconomic damages of approximately $83 million; Bogle filed September 1, 2022, in Multnomah County Circuit Court Oregon by approximately 39 plaintiffs seeking economic damages of approximately $83 million and noneconomic damages of approximately $83 million; Dodge filed September 8, 2022, in Multnomah County Circuit Court Oregon by two plaintiffs seeking $3 million in economic damages and $3 million in noneconomic damages.

As described above, on May 31, 2024, PacifiCorp reached a settlement totaling $178 million with approximately 400 plaintiffs associated with the Echo Mountain Complex and Beachie Creek fires who opted out of the James class for $178 million, resolving the consolidated O'Keefe cases and the consolidated Andersen cases but for one remaining plaintiff in Andersen and one remaining plaintiff in O'Keefe as described above.

Other Cases

On October 7, 2021, a complaint against PacifiCorp was filed, captioned Estate of Cathy Lynn Cook et al. v. PacifiCorp et al., Case No. 21CV35076 ("Cook") in Multnomah County Circuit Court Oregon by approximately two plaintiffs, seeking a minor amount of economic damages and approximately $40 million in noneconomic damages associated with the Beachie Creek Fire, and makes allegations similar to those described above and includes wrongful death claims. On February 5, 2024, the complaint was amended to add a request for $200 million in punitive damages.

On October 7, 2021, a complaint against PacifiCorp was filed, captioned Angela Mosso et al. v. PacifiCorp et al., Case No. 21CV35069 ("Mosso") in Multnomah County Circuit Court Oregon by approximately four plaintiffs, seeking approximately $10 million in economic damages and $90 million in noneconomic damages associated with the Beachie Creek Fire, and makes allegations similar to those described above and includes wrongful death claims. On February 5, 2024, the complaint was amended to add a request for $400 million in punitive damages. On April 18, 2024, a second amended complaint was filed increasing noneconomic damages to $200 million and decreasing punitive damages to $330 million for total damages sought of $540 million.

In April 2024, the Multnomah County Circuit Court Oregon denied plaintiffs' motions for summary judgment in Cook and Mosso to utilize the June 2023 verdict in James to establish fire causation and negligence for the Cook and Mosso trials. In June 2024, PacifiCorp settled the Cook and Mosso cases and the associated jury trials previously scheduled in July and August 2024 were cancelled.

On September 1, 2022, a complaint against PacifiCorp associated with the Archie Creek Fire was filed, captioned Leonard Mitchell Lee et al. v. PacifiCorp, Case No. 22CV29685 ("Lee") in Multnomah County Circuit Court Oregon by approximately five plaintiffs, seeking approximately $25 million in economic and noneconomic damages and makes allegations similar to those described above. No trial date has been set. In June 2024, PacifiCorp reached an agreement in principle with three of the Lee plaintiffs, but the case remains pending while PacifiCorp and the court determine whether the remaining two plaintiffs wish to pursue their claims.

On September 2, 2022, a complaint against PacifiCorp associated with the Archie Creek Fire was filed, captioned Beamer et al. v. PacifiCorp, Case No. 22CV29851 ("Beamer") in Oregon Circuit Court in Douglas County, Oregon ("Douglas County Circuit Court Oregon"), by approximately 36 plaintiffs, seeking more than $190 million in economic damages based on $5 million for each of the 35 individual plaintiffs and $15 million for the one non-individual plaintiff and makes allegations similar to those described above. The individual plaintiffs also seek noneconomic damages to be determined at trial. In December 2023, claims associated with approximately 27 plaintiffs in the Beamer case were settled. In February 2024, the Douglas County Circuit Court Oregon dismissed all but one remaining plaintiff. In April 2024, in response to the one remaining plaintiff in Beamer filing a letter indicating the intent to dismiss their claims, the Douglas County Circuit Court Oregon entered the dismissal.

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A group of subrogation insurers that filed complaints against PacifiCorp associated with the Archie Creek Fire agreed to a mediator's proposal under which PacifiCorp will pay 51.75% of the total claims paid and to be paid by the carriers related to the Archie Creek Fire. In October 2022, PacifiCorp paid $24 million to the subrogation insurers. During 2023 and January 2024, PacifiCorp paid additional amounts to the subrogation insurers and ultimately expects to pay a total of $28 million to the subrogation insurers. While some of the subrogation complaints have been fully dismissed, the following remain active:

The Lexington complaint was filed against PacifiCorp by two insurers in Douglas County Circuit Court Oregon seeking $14 million in damages for negligence associated with the Archie Creek Fire and, as amended on February 3, 2022, makes allegations similar to those described above. The Lexington case was partially dismissed following settlement, but general judgment of dismissal has not yet been entered because certain plaintiffs remain active.

The Certain Underwriters complaint was filed against PacifiCorp by four insurers in Douglas County Circuit Court Oregon on April 28, 2022 by multiple insurers seeking $14 million in damages for negligence associated with the Archie Creek Fire. The Certain Underwriters case remains pending because general judgment of dismissal has not yet been entered because certain plaintiffs remain active.

The Ace American Insurance Co. complaint was filed against PacifiCorp in Douglas County Circuit Court Oregon on August 25, 2022, by 15 insurers seeking approximately $24 million for negligence. The Ace American Insurance case was partially dismissed following settlement, but general judgment of dismissal has not yet been entered because certain plaintiffs remain active.

On September 1, 2022, a complaint against PacifiCorp was filed, captioned Stroh Coastal Holdings LLC v. PacifiCorp, Case No. 22CV29695 ("Stroh Coastal") in Multnomah County Circuit Court Oregon by one plaintiff, seeking $1 million in economic damages associated with the Pike Road Fire and makes allegations similar to those described above. The Stroh Coastal case was previously set for trial starting September 3, 2024. On July 2, 2024, PacifiCorp settled the Stroh Coastal case.

In January 2024, PacifiCorp settled various claims for $3 million with approximately 14 plaintiffs associated with various 2020 Wildfire complaints in Oregon.

Winery Cases

Certain Oregon vineyards have filed five lawsuits alleging economic damages associated with the 2020 Labor Day Fires. See Cooper Mountain Winery LLC v. PacifiCorp, Case No. 23CV47202; Sokol Blosser, Ltd. et. al v. PacifiCorp, Case No. 24CV03044; Elk Cove Vineyards, Inc. v. PacifiCorp, Case No. 23CV28258; Willamette Valley Vineyards Inc v. PacifiCorp, Case No. 23CV29519; and Lange Winery LLC, et al. v. PacifiCorp, Case No. 24CV25661. Plaintiffs dismissed two earlier-filed cases (Retraite, LLC, et. al v. PacifiCorp, Case No. 23CV28213 and Brigadoon Vineyards, LLC v. PacifiCorp, Case No. 23CV28149) and refiled them in the Lange Winery case described below. All of the cases are in the initial stages of discovery. Additional details are provided below.

On July 14, 2023, a complaint against PacifiCorp was filed, captioned Elk Cove Vineyards, Inc. v. PacifiCorp, Case No. 23CV28258 in Oregon Circuit Court in Yamhill County, Oregon, by one plaintiff, seeking approximately $3 million in economic damages associated with multiple fires and makes allegations similar to those described above. On March 13, 2024, the complaint was amended to add 12 plaintiffs, with all plaintiffs collectively seeking approximately $25 million in economic damages. The Elk Cove Vineyards, Inc. case is set for trial starting April 1, 2025 through May 9, 2025.

On July 14, 2023, a complaint against PacifiCorp was filed, captioned Retraite, LLC et al. v. PacifiCorp, Case No. 23CV28213 in Oregon Circuit Court in Polk County, Oregon, by approximately four plaintiffs, seeking approximately $4 million in economic damages associated with multiple fires and makes allegations similar to those described above. Plaintiffs dismissed this case and included these wineries in the newly filed Lange Winery case described below.

On July 14, 2023, a complaint against PacifiCorp was filed, captioned Brigadoon Vineyards, LLC v. PacifiCorp, Case No. 23CV28149 in Oregon Circuit Court in Lane County, Oregon, seeking approximately $100,000 in economic damages associated with multiple fires and makes allegations similar to those described above. Plaintiffs dismissed this case and included these wineries in the newly filed Lange Winery case described below.

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On July 24, 2023, a complaint against PacifiCorp was filed, captioned Willamette Valley Vineyards Inc v. PacifiCorp, Case No. 23CV29519 in Oregon Circuit Court in Marion County, Oregon, seeking approximately $3 million in economic damages associated with multiple fires and makes allegations similar to those described above. On March 29, 2024, the complaint was amended to add four plaintiffs, with all plaintiffs collectively seeking approximately $4 million in economic damages. The Willamette Valley Vineyards Inc case is set for trial starting August 4, 2025 through August 29, 2025.

On November 7, 2023, a complaint against PacifiCorp was filed, captioned Cooper Mountain Winery LLC v. PacifiCorp, Case No. 23CV47202 in Oregon Circuit Court in Washington County, Oregon, seeking approximately $750,000 in economic damages associated with multiple fires and makes allegations similar to those described above. The Cooper Mountain Winery LLC case is set for trial November 4, 2025 through November 28, 2025.

On January 18, 2024, a complaint against PacifiCorp was filed, captioned Sokol Blosser, Ltd. et al. v. PacifiCorp, Case No. 24CV03044 in Multnomah County Circuit Court Oregon by approximately nine plaintiffs, seeking approximately $20 million in economic damages associated with multiple fires and makes allegations similar to those described above. On October 1, 2024, the complaint was amended to add 25 plaintiffs with all plaintiffs collectively seeking approximately $90 million in economic damages.

On May 24, 2024, a complaint against PacifiCorp was filed, captioned Lange Winery LLC et al. v. PacifiCorp, Case No. 24CV25661 ("Lange Winery") in Multnomah County Circuit Court Oregon by approximately 35 plaintiffs, seeking approximately $51 million in economic damages associated with multiple fires and makes allegations similar to those described above.

United States and State of Oregon – Loss and Damages to Federal and State Lands – Oregon Fires

PacifiCorp received correspondence from the USDOJ, representing the U.S. Department of the Interior, Bureau of Land Management, Bureau of Indian Affairs, USFS, 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 for mediation purposes only 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 $625 million. The amounts alleged for natural resource damage from these fires do not include intangible environmental and natural resource damages that the U.S. 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 for mediation purposes only 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 $109 million.

On October 12, 2023 and December 21, 2023, the Oregon Department of Forestry sent demand notices for fire suppression costs totaling $2 million for three separate ignition points associated with the 2020 Wildfires. On May 30, 2024, PacifiCorp reached settlement with the Oregon Department of Forestry for suppression costs associated with one of these ignition points for less than $1 million.

PacifiCorp is actively cooperating with both the USDOJ and ODOJ on resolving these alleged claims, including through the pursuit of alternative dispute resolution.

2022 McKinney Fire

Numerous complaints associated with the 2022 McKinney Fire have been filed in Sacramento County Superior Court California on behalf of over 300 plaintiffs, including multiple insurers, as described below. The complaints generally allege: (i) inverse condemnation; (ii) negligence; (iii) trespass; (iv) nuisance; and (v) violation of certain sections of the California Public Utilities Code and the California Health & Safety Code and seek various damages, generally including: (i) economic damages; (ii) noneconomic damages; (iii) doubling or trebling of timber damages; (iv) punitive damages; (v) prejudgment interest; and (vi) attorneys' fees and other costs. Certain complaints include wrongful death claims as described below. The complaints do not specify the amount of damages sought.

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On August 16, 2022, a complaint against PacifiCorp was filed, captioned Bridges et al. v. PacifiCorp, Case No. 34-2022-00325257 ("Bridges") in Sacramento County Superior Court California by approximately five plaintiffs. The following complaints were filed and subsequently consolidated into Bridges: Cogan filed August 23, 2022, approximately 12 plaintiffs, including a wrongful death claim; Shoopman filed August 26, 2022, approximately 61 plaintiffs, including a wrongful death claim; Lowe filed September 28, 2022, approximately two plaintiffs; Fraser filed November 9, 2022, approximately 180 plaintiffs; California Fair Plan Association, filed March 3, 2023, approximately 18 subrogation insurers; Corrales, filed April 6, 2023, approximately 30 plaintiffs; Murieen, filed April 20, 2023, approximately seven plaintiffs; Hickey, filed May 9, 2023, approximately five plaintiffs; Volckhausen, filed May 9, 2023, one plaintiff; Huber, filed August 21, 2023, approximately five plaintiffs, including two wrongful death claims; CSAA filed December 21, 2023, one subrogation insurer; Insurance Company of Hannover, filed January 8, 2024, one subrogation plaintiff; Bartlett, filed April 25, 2024, approximately 30 plaintiffs; Evanston Insurance Company, filed May 3, 2024, one subrogation plaintiff; Justice, filed July 15, 2024, approximately 194 plaintiffs; Coolidge, filed July 19, 2024, approximately two plaintiffs; Sharon Andersen, filed July 22, 2024, approximately 23 plaintiffs, including a wrongful death claim; Billingsley, filed July 25, 2024, approximately 22 plaintiffs, including a wrongful death claim; Howe, filed July 25, 2024, approximately 50 plaintiffs; Cloutman, filed July 26, 2024, approximately 112 plaintiffs; Bolden, filed July 26, 2024, approximately seven plaintiffs; Rainey, filed July 26, 2024, approximately 29 plaintiffs, including a wrongful death claim; Hegler, filed July 29, 2024, approximately three plaintiffs; Meier, filed July 29, 2024, approximately 204 plaintiffs; and Propp, filed August 5, 2024, approximately six plaintiffs. In May 2024, the CSAA complaint was settled as part of an aggregate settlement with subrogation insurers. A bellwether trial in Bridges is scheduled to begin March 10, 2025. Trial for the wrongful death claim in Huber is scheduled to begin April 28, 2025.

On December 21, 2022, a complaint against PacifiCorp was filed, captioned Siskiyou County v. PacifiCorp, Case No. 2:22‑CV‑02278‑DMC, in the U.S. District Court for the Eastern District of California on behalf of a single plaintiff. A jury trial is scheduled for September 22, 2025. On May 15, 2024, the case settled for $6 million and the trial date was vacated.

On March 4, 2024, a complaint against PacifiCorp was filed, captioned Gabriel Hamilton et al. v. PacifiCorp, Case No. 24CV004099 ("Hamilton") in Sacramento County Superior Court California by approximately 34 plaintiffs, including four insurance subrogation plaintiffs. In May 2024, the four insurance subrogation complaints in Hamilton were settled as part of an aggregate settlement with subrogation insurers.

On March 28, 2024, a complaint against PacifiCorp was filed, captioned Mark Crawford et al. v. PacifiCorp, Case No. 24CV006043 ("Crawford") in Sacramento County Superior Court California by approximately 37 plaintiffs. In May 2024, the Crawford complaint was settled.

On April 12, 2024, a complaint against PacifiCorp was filed, captioned Susanne White v. PacifiCorp, Case No. 2:24‑CV‑01112‑KJM‑DMC ("White") in U.S. District Court for the Eastern District of California by one plaintiff.

On April 26, 2024, a complaint against PacifiCorp was filed, captioned Lynette Marie Adams et al. v. PacifiCorp, Case No. 24CV008300 ("Adams") in Sacramento County Superior Court California by approximately 12 plaintiffs.

In September 2024, PacifiCorp settled various claims for $6 million with approximately 331 plaintiffs. There are approximately 700 active plaintiffs who have filed complaints relating to the McKinney Fire, excluding plaintiffs who appear to be duplicates where the same plaintiff appears in multiple complaints and plaintiffs who indicated they will dismiss their claims.

BERKSHIRE HATHAWAY ENERGY

HomeServices, a subsidiary of BHE, is currently defending against several antitrust cases, all in federal district courts. In each case, plaintiffs claim HomeServices and certain of its subsidiaries (in one instance, HomeServices and BHE) 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"). None of the complaints specify damages sought. However, two cases allege Texas state law deceptive trade practices claims, for which plaintiffs have provided written notice of the damages sought totaling approximately $9 billion by separate notice as required by Texas law. The cases are captioned as follows.

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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, 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 conspiracy 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. Joint and several liability applies for the co- defendants. Federal law authorizes trebling of damages and the award of pre-judgment interest and attorney fees. Prior to the trial, Anywhere Real Estate and RE/MAX, LLC reached settlement agreements with the plaintiffs. Subsequent to the trial, settlements were reached by Keller Williams, NAR and HomeServices on February 1, 2024, March 15, 2024, and April 25, 2024, respectively. The Anywhere Real Estate, RE/MAX, LLC and Keller Williams settlements received court approval on May 9, 2024, which has been appealed to the U.S. Court of Appeals for the Eighth Circuit. Appellant briefs were filed on October 3, 2024, with appellee briefs due November 8, 2024. The NAR and HomeServices settlements are subject to court approval, which is scheduled for November 26, 2024. Final judgment has not yet been entered by the U.S. District Court for the Western District of Missouri. In April 2024, HomeServices agreed to terms with the plaintiffs to settle all claims asserted against HomeServices, HSF Affiliates, LLC and BHH Affiliates, LLC in the Burnett case as part of a proposed nationwide class settlement. The final settlement agreement includes scheduled payments over the next four years aggregating $250 million. If the settlement is not approved by the court, 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.

In March 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, 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, 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. A motion by HomeServices' defendants for summary judgment remains pending based on resolution of the motion for multidistrict litigation. In June 2024, the court ordered the case stayed as to the HomeServices' defendants pending a decision on final approval of the HomeServices' nationwide settlement.

In November 2023, the QJ v. HomeServices of America, Inc. et al., Case No. 23CV01013, complaint was filed in the U.S. District Court for the Eastern District of Texas. This putative class action lawsuit was brought on behalf of named plaintiff QJ Team, LLC against the Texas Association of Realtors, Inc., HomeServices of America, Inc., ABA Management, L.L.C. (a HomeServices subsidiary), Ebby Halliday Real Estate, LLC (a HomeServices subsidiary), Keller Williams Realty, Inc. and additional named defendants. In June 2024, the court ordered the case stayed as to the HomeServices' defendants pending a decision on final approval of the HomeServices' nationwide settlement.

In December 2023, the Martin v. HomeServices of America, Inc. et al., Case No. 23CV01104, complaint was filed in the U.S. District Court for the Eastern District of Texas. This putative class action lawsuit was brought on behalf of named plaintiff Julie Martin against the Texas Association of Realtors, Inc., HomeServices of America, Inc., ABA Management, L.L.C., Ebby Halliday Real Estate, LLC, Keller Williams Realty, Inc. and additional named defendants. In June 2024, the court ordered the case stayed as to the HomeServices' defendants pending a decision on final approval of the HomeServices' nationwide settlement.

On March 21, 2024, the court granted plaintiffs' motion to consolidate the QJ case and the Martin case.

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In December 2023, the Umpa v. HomeServices of America, Inc. et al., Case No. 23CV00945, complaint was filed in the U.S. District Court for the Western District of Missouri. This putative class action lawsuit was brought on behalf of named plaintiff Daniel Umpa against the NAR, HomeServices of America, Inc., BHH Affiliates, LLC, HSF Affiliates, LLC, Long & Foster Companies, Inc., Keller Williams Realty, Inc. and additional named defendants. In April 2024, the court ordered the case stayed as to the HomeServices' defendants pending a decision on final approval of the HomeServices' nationwide settlement.

In January 2024, the Masiello v. Roy H. Long Realty, Inc. d/b/a Long Realty et al., Case No. 24CV00045, complaint was filed in the U.S. District Court for the District of Arizona. This putative class action lawsuit was brought on behalf of named plaintiff Joseph Masiello against the Arizona Association of Realtors, Roy H. Long Realty, Inc. d/b/a Long Realty (a HomeServices of America, Inc. subsidiary) and additional named defendants. In July 2024, the court ordered the case stayed as to defendant Long Realty, Inc. pending a decision on final approval of the HomeServices' nationwide settlement.

In January 2024, the Fierro v. BHH Affiliates, LLC, et al., Case No. 24CV00449, complaint was filed in the U.S. District Court for the Central District of California. This putative class action lawsuit was brought on behalf of named plaintiffs Gael Fierro and Patrick Thurber against the NAR, Berkshire Hathaway Inc., BHH Affiliates, LLC and additional named defendants. In April 2024, the court ordered the case stayed as to defendant BHH Affiliates, LLC pending a decision on final approval of the HomeServices' nationwide settlement.

In January 2024, the Whaley v. Berkshire Hathaway HomeServices Nevada Properties et al., Case No. 24CV00105, amended complaint was filed in the U.S. District Court for the District of Nevada. This putative class action lawsuit was brought on behalf of named plaintiff Nathaniel Whaley against the NAR, Berkshire Hathaway HomeServices Nevada Properties (a HomeServices of America, Inc. subsidiary) and additional named defendants. In May 2024, the court ordered the case stayed as to defendants Berkshire Hathaway HomeServices Nevada Properties and BHH Affiliates, LLC pending a decision on final approval of the HomeServices' nationwide settlement.

In February 2024, the Boykin v. BHH Affiliates, LLC, et al., Case No. 24CV00340, compliant was filed in the U.S. District Court for the District of Nevada. This putative class action lawsuit was brought on behalf of named plaintiff Angela Boykin against the NAR, BHH Affiliates, LLC and additional named defendants. In May 2024, the court ordered the case stayed as to defendants Berkshire Hathaway HomeServices Nevada Properties and BHH Affiliates, LLC pending a decision on final approval of the HomeServices' nationwide settlement.

On March 20, 2024, the court consolidated the Boykin case with the Whaley case.

In February 2024, the Jensen v. HomeServices of America, Inc., et al., Case No. 24CV00109, complaint was filed in the U.S. District Court for the District of Utah. The putative class action lawsuit was brought on behalf of named plaintiff Dalton Jensen against the NAR, Anywhere Real Estate, Inc., HomeServices of America, Inc., HSF Affiliates, LLC, BHH Affiliates, LLC and additional named defendants. The case was voluntarily dismissed in May 2024.

In March 2024, the Wang v. HomeServices of America, Inc. et al., Case No. 24CV02371, complaint was filed in the U.S. District Court for the Southern District of New York. This pro se action was filed against the NAR, the Real Estate Board of New York, Inc., and HomeServices of America, Inc., et al. In August 2024, the court ordered the case stayed until November 26, 2024.

In March 2024, the first amended complaint in the Gibson v. National Association of Realtors, et al., Case No. 23CV00788, complaint was filed in the U.S. District Court for the Western District of Missouri. The putative class action lawsuit was brought on behalf of named plaintiffs Don Gibson, Lauren Criss and John Meiners against the NAR, BHE and additional named defendants.

On April 23, 2024, the court consolidated the Gibson case with the Umpa case.

In April 2024, the Burton v. HomeServices of America, Inc., et al. Case No. 7:24CV01800, complaint was filed in the U.S. District Court for the District of South Carolina. This putative class action was brought on behalf of named plaintiffs Shauntell Burton, Benny D. Cheatham, Robert Douglass, Douglas Fender, and Dena Fender against HomeServices of America, Inc., HSF Affiliates, LLC, et al. This is the second complaint filed by these plaintiffs; the first complaint was filed against the National Association of Realtors, Keller Williams Realty, Inc. et al. ("Burton I") and is still pending. In June 2024, the court ordered the case stayed as to the HomeServices' defendants pending a decision on final approval of the HomeServices' nationwide settlement.

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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, 2023.

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

Not applicable.

Item 6.Exhibits

The following is a list of exhibits filed as part of this Quarterly Report.

224

Exhibit No. Description

BERKSHIRE HATHAWAY ENERGY

4.1	Twenty-Sixth Supplemental Indenture, dated as of May 22, 2024, by and between AltaLink, L.P., AltaLink Management Ltd., and BNY Trust Company of Canada, as trustee, relating to the C$325,000,000 in principal amount of the 4.742% Series 2024-1 Senior Secured Notes due 2054 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2024).
10.1	Sixth Amended and Restated Credit Agreement, dated as of March 22, 2024 among AltaLink Investments, L.P., as borrower, AltaLink Investment Management LTD., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (redacted) (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, 2024).
10.2	Second Amendment to the $3,500,000,000 Third Amended and Restated Credit Agreement, dated as of June 28, 2024, 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 10.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2024).
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	Fourth Restated Articles of Incorporation of PacifiCorp.
10.3	PacifiCorp's Amended Critical Personnel Agreement, dated as of May 23, 2024 (incorporated by reference to Exhibit 10.3 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2024).
10.4	Form of Settlement Agreement, dated May 31, 2024.
10.5	Form of Settlement Agreement, dated June 19, 2024.
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.

225

Exhibit No. Description

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP

10.6	$900,000,000 364-Day Credit Agreement, dated as of June 28, 2024, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.4 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2024).
10.7	Second Amendment to the $2,000,000,000 Third Amended and Restated Credit Agreement, dated as of June 28, 2024, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, JPMorgan 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, 2024).
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

10.8 Second Amendment to the $1,500,000,000 Third Amended and Restated Credit Agreement, dated as of June 28, 2024, 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, 2024).

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.

226

Exhibit No. Description

BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER

10.9 Second Amendment to the $600,000,000 Fifth Amended and Restated Credit Agreement, dated as of June 28, 2024, 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, 2024).

SIERRA PACIFIC

31.11	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.12	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.11	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.12	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC

4.2

Third Supplemental Indenture, dated as of May 31, 2022, by and between Sierra Pacific Power Company and the Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.3 to the Sierra Pacific Power Company Current Report on Form 8-K dated September 18, 2023).

10.10

Second Amendment to the $400,000,000 Fifth Amended and Restated Credit Agreement, dated as of June 28, 2024, 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, 2024).

EASTERN ENERGY GAS

15.5	Awareness Letter of Independent Registered Public Accounting Firm.
31.13	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.14	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.13	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.14	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND EASTERN ENERGY GAS

4.3 Sixteenth Supplemental Indenture, dated as of October 9, 2024, by and between Eastern Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as trustee, to the Indenture dated as of October 1, 2013, by and between Eastern Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas (incorporated by reference to Exhibit 4.2 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated October 9, 2024).

227

Exhibit No. Description

EASTERN GAS TRANSMISSION AND STORAGE

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, 2024, 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.

228

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 1, 2024	/s/ Charles C. Chang
	Charles C. Chang
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)
	PACIFICORP
Date: November 1, 2024	/s/ Nikki L. Kobliha
	Nikki L. Kobliha
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)
	MIDAMERICAN FUNDING, LLC
	MIDAMERICAN ENERGY COMPANY
Date: November 1, 2024	/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 1, 2024	/s/ Michael J. Behrens
	Michael J. Behrens
	Vice President and Chief Financial Officer
	(principal financial and accounting officer)
	SIERRA PACIFIC POWER COMPANY
Date: November 1, 2024	/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 1, 2024	/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 1, 2024	/s/ Scott C. Miller
	Scott C. Miller
	Vice President, Chief Financial Officer and Treasurer
	(principal financial and accounting officer)

229