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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, 2025

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)

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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 held by its parent company, Berkshire Hathaway Inc. As of October 30, 2025, 1 share of common stock, no par value, was outstanding.

All shares of outstanding common stock of PacifiCorp are indirectly held by Berkshire Hathaway Energy Company. As of October 30, 2025, 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 30, 2025.

All shares of outstanding common stock of MidAmerican Energy Company are held by its parent company, MHC Inc., which is a direct, wholly owned subsidiary of MidAmerican Funding, LLC. As of October 30, 2025, 70,980,203 shares of common stock, no par value, were outstanding.

All shares of outstanding common stock of Nevada Power Company are held by its parent company, NV Energy, Inc., which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of October 30, 2025, 1,000 shares of common stock, $1.00 stated value, were outstanding.

All shares of outstanding common stock of Sierra Pacific Power Company are held by its parent company, NV Energy, Inc. As of October 30, 2025, 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 30, 2025.

All shares of outstanding common stock of Eastern Gas Transmission and Storage, Inc. are held by its parent company, Eastern Energy Gas Holdings, LLC, which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of October 30, 2025, 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			209
Item 4.			Controls and Procedures			209

 

PART II

 

Item 1.			Legal Proceedings			210
Item 1A.			Risk Factors			218
Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds			219
Item 3.			Defaults Upon Senior Securities			219
Item 4.			Mine Safety Disclosures			219
Item 5.			Other Information			219
Item 6.			Exhibits			219
Signatures						224

i

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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. and its subsidiaries
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.

ii

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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
CCR						Coal Combustion Residuals
CPUC						California Public Utilities Commission
D.C. Circuit						United States Court of Appeals for the District of Columbia Circuit
Dth						Decatherm
EBA						Energy Balancing Account
ECAM						Energy Cost Adjustment Mechanism
EPA						United States Environmental Protection Agency
FERC						Federal Energy Regulatory Commission
GAAP						Accounting principles generally accepted in the United States of America
GTA						General Tariff Application
GWh						Gigawatt Hour
IPUC						Idaho Public Utilities Commission
IRP						Integrated Resource Plan
IUC						Iowa Utilities Commission
James						A class action complaint filed against PacifiCorp on September 30, 2020, captioned Jeanyne James et al. v. PacifiCorp, in Multnomah County Circuit Court Oregon and the associated consolidated cases
kV						Kilovolt
LNG						Liquefied Natural Gas
MISO						Midcontinent Independent System Operator, Inc.
MW						Megawatt
MWh						Megawatt Hour
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
RRA						Renewable Energy Credit and Sulfur Dioxide Revenue Adjustment Mechanism
SCR						Selective Catalytic Reduction
SEC						United States Securities and Exchange Commission
SIP						State Implementation Plan
UPSC						Utah Public Service Commission
WPSC						Wyoming Public Service Commission
WUTC						Washington Utilities and Transportation Commission

iii

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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 tariffs and 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, electromagnetic pulses, 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, including the effects of amounts to be paid to complainants as a result of settlements or final legal determinations and bonding requirements related to legal judgments that are being appealed 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 prevention plans; to retain or contract for the workforce necessary to execute its wildfire prevention 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;

iv

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

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

•changes in business strategy or development plans;

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

•changes in the respective Registrant's credit ratings, 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

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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						58
Consolidated Balance Sheets						59
Consolidated Statements of Operations						61
Consolidated Statements of Changes in Shareholders' Equity						62
Consolidated Statements of Cash Flows						63
Notes to Consolidated Financial Statements						64
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm						91
Balance Sheets						92
Statements of Operations						94
Statements of Changes in Shareholder's Equity						95
Statements of Cash Flows						96
Notes to Financial Statements						97
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm						106
Consolidated Balance Sheets						107
Consolidated Statements of Operations						109
Consolidated Statements of Changes in Member's Equity						110
Consolidated Statements of Cash Flows						111
Notes to Consolidated Financial Statements						112
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						149
Consolidated Balance Sheets						150
Consolidated Statements of Operations						151
Consolidated Statements of Changes in Shareholder's Equity						152
Consolidated Statements of Cash Flows						153
Notes to Consolidated Financial Statements						154
Eastern Energy Gas Holdings, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm						173
Consolidated Balance Sheets						174
Consolidated Statements of Operations						176
Consolidated Statements of Comprehensive Income						177
Consolidated Statements of Changes in Equity						178
Consolidated Statements of Cash Flows						179
Notes to Consolidated Financial Statements						180
Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Report of Independent Registered Public Accounting Firm						193
Consolidated Balance Sheets						194
Consolidated Statements of Operations						196
Consolidated Statements of Changes in Shareholder's Equity						198
Consolidated Statements of Cash Flows						199
Notes to Consolidated Financial Statements						200

1

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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						80
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company						117
Nevada Power Company and its subsidiaries						140
Sierra Pacific Power Company and its subsidiaries						164
Eastern Energy Gas Holdings, LLC and its subsidiaries						188
Eastern Gas Transmission and Storage, Inc. and its subsidiaries						206

2

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Berkshire Hathaway Energy Company and its subsidiaries

Consolidated Financial Section

3

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PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

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, 2025, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and nine-month periods ended September 30, 2025 and 2024, and of cash flows for the nine-month periods ended September 30, 2025 and 2024, 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, 2024, 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 21, 2025, 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, 2024, 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

October 31, 2025

4

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BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

			As of
			September 30,						December 31,
			2025						2024
ASSETS
Current assets:
Cash and cash equivalents			$	2,155					$	1,392
Investments and restricted cash and cash equivalents			303						216
Trade receivables, net			2,765						2,551
Inventories			2,073						1,962
Mortgage loans held for sale			663						528
Regulatory assets			1,022						1,136
Other current assets			1,082						1,314
Total current assets			10,063						9,099
Property, plant and equipment, net			109,754						103,769
Goodwill			11,500						11,413
Regulatory assets			4,181						4,213
Investments and restricted cash and cash equivalents and investments			7,707						8,635
Other assets			2,941						3,011
Total assets			$	146,146					$	140,140

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

5

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BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions, except share amounts)

			As of
			September 30,						December 31,
			2025						2024
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable			$	3,404					$	2,928
Accrued interest			761						728
Accrued property, income and other taxes			1,009						1,043
Accrued employee expenses			447						364
Short-term debt			1,719						1,123
Current portion of long-term debt			1,553						2,646
Other current liabilities			2,272						2,109
Total current liabilities			11,165						10,941
BHE senior debt			11,460						11,457
Subsidiary senior debt			41,807						41,154
Subsidiary junior subordinated debt			1,584						—
Regulatory liabilities			6,761						6,754
Deferred income taxes			12,805						12,628
Other long-term liabilities			5,904						5,917
Total liabilities			91,486						88,851
Commitments and contingencies (Note 9)
Equity:
BHE shareholder's equity:
Preferred stock - 100,000,000 shares authorized, $0.01 par value, — and 481,000 shares issued and outstanding			—						481
Common stock - 100 shares authorized, no par value, 1 share issued and outstanding			—						—
Additional paid-in capital			5,558						5,558
Retained earnings			49,683						46,311
Accumulated other comprehensive loss, net			(1,837)						(2,341)
Total BHE shareholder's equity			53,404						50,009
Noncontrolling interests			1,256						1,280
Total equity			54,660						51,289
Total liabilities and equity			$	146,146					$	140,140

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

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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,
			2025						2024						2025						2024
Operating revenue:
Energy			$	6,059					$	6,026					$	16,695					$	16,386
Real estate			1,185						1,179						3,309						3,334
Total operating revenue			7,244						7,205						20,004						19,720
Operating expenses:
Energy:
Cost of sales			1,876						1,902						4,841						5,099
Operations and maintenance			1,373						1,343						4,014						3,888
Wildfire losses (Note 9)			100						—						100						251
Depreciation and amortization			1,032						1,020						3,267						3,040
Property and other taxes			221						205						672						631
Real estate			1,146						1,151						3,227						3,477
Total operating expenses			5,748						5,621						16,121						16,386
Operating income			1,496						1,584						3,883						3,334
Other income (expense):
Interest expense			(707)						(679)						(2,102)						(2,045)
Capitalized interest			49						49						134						145
Allowance for equity funds			93						97						240						272
Interest and dividend income			60						112						185						362
Gains on marketable securities, net			13						268						132						474
Other, net			38						34						68						90
Total other income (expense)			(454)						(119)						(1,343)						(702)
Income before income tax expense (benefit) and equity income (loss)			1,042						1,465						2,540						2,632
Income tax expense (benefit)			(606)						(614)						(1,362)						(1,293)
Equity income (loss)			(129)						(73)						(409)						(237)
Net income			1,519						2,006						3,493						3,688
Net income attributable to noncontrolling interests			30						31						115						106
Net income attributable to BHE shareholders			1,489						1,975						3,378						3,582
Preferred dividends			—						—						3						—
Earnings on common shares			$	1,489					$	1,975					$	3,375					$	3,582

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

 

7

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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,
			2025						2024						2025						2024
Net income			$	1,519					$	2,006					$	3,493					$	3,688
Other comprehensive (loss) income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $5, $(7), $— and $(2)			17						(18)						(4)						(3)
Foreign currency translation adjustment			(192)						348						533						178
Unrealized (losses) gains on cash flow hedges, net of tax of $(3), $(7), $(8) and $1			(9)						(22)						(25)						4
Total other comprehensive (loss) income, net of tax			(184)						308						504						179
Comprehensive income			1,335						2,314						3,997						3,867
Comprehensive income attributable to noncontrolling interests			30						31						115						106
Comprehensive income attributable to BHE shareholders			$	1,305					$	2,283					$	3,882					$	3,761

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

8

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BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)

			BHE Shareholder's Equity
																											Accumulated
															Additional												Other
			Preferred						Common						Paid-in						Retained						Comprehensive						Noncontrolling						Total
			Stock						Stock						Capital						Earnings						Loss, Net						Interests						Equity
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

Balance, June 30, 2025			$	—					$	—					$	5,558					$	48,194					$	(1,653)					$	1,265					$	53,364
Net income			—						—						—						1,489						—						30						1,519
Other comprehensive loss			—						—						—						—						(184)						—						(184)
Distributions			—						—						—						—						—						(39)						(39)
Balance, September 30, 2025			$	—					$	—					$	5,558					$	49,683					$	(1,837)					$	1,256					$	54,660
Balance, December 31, 2024			$	481					$	—					$	5,558					$	46,311					$	(2,341)					$	1,280					$	51,289
Net income			—						—						—						3,378						—						115						3,493
Other comprehensive income			—						—						—						—						504						—						504
Preferred stock redemptions			(481)						—						—						—						—						—						(481)
Preferred stock dividend			—						—						—						(3)						—						—						(3)
Distributions			—						—						—						—						—						(135)						(135)
Other equity transactions			—						—						—						(3)						—						(4)						(7)
Balance, September 30, 2025			$	—					$	—					$	5,558					$	49,683					$	(1,837)					$	1,256					$	54,660

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

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BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

			Nine-Month Periods
			Ended September 30,
			2025						2024
Cash flows from operating activities:
Net income			$	3,493					$	3,688
Adjustments to reconcile net income to net cash flows from operating activities:
Gains on marketable securities, net			(132)						(474)
Depreciation and amortization			3,297						3,075
Allowance for equity funds			(240)						(272)
Equity (income) loss, net of distributions			479						334
Net power cost deferrals			(429)						(62)
Amortization of net power cost deferrals			726						389
Other changes in regulatory assets and liabilities			(105)						(82)
Deferred income taxes and investment tax credits, net			(97)						(181)
Other, net			53						(46)
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets			(262)						(771)
Derivative collateral, net			(10)						(23)
Pension and other postretirement benefit plans			(15)						(12)
Accrued property, income and other taxes, net			(62)						141
Accounts payable and other liabilities			254						400
Wildfires insurance receivable			98						365
Wildfires liability			(82)						(278)
Net cash flows from operating activities			6,966						6,191
Cash flows from investing activities:
Capital expenditures			(7,527)						(6,236)
Purchases of marketable securities			(373)						(258)
Proceeds from sales of marketable securities			943						1,841
Purchases of U.S. Treasury Bills			(39)						(1,651)
Proceeds from sales of U.S. Treasury Bills			—						1,975
Proceeds from maturities of U.S. Treasury Bills			—						723
Equity method investments			(39)						(14)
Other, net			15						20
Net cash flows from investing activities			(7,020)						(3,600)
Cash flows from financing activities:
Preferred stock redemptions			(481)						—
Preferred dividends			(3)						—
Common stock repurchases			—						(2,276)
Repayments of BHE senior debt			(1,650)						—
Repayments of BHE junior subordinated debentures			—						(91)
Proceeds from subsidiary debt			3,115						5,317
Repayments of subsidiary debt			(720)						(921)
Net proceeds from (repayments of) short-term debt			587						(3,380)
Distributions to noncontrolling interests			(136)						(129)
Other, net			131						(30)
Net cash flows from financing activities			843						(1,510)
Effect of exchange rate changes			11						2
Net change in cash and cash equivalents and restricted cash and cash equivalents			800						1,083
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period			1,586						1,811
Cash and cash equivalents and restricted cash and cash equivalents at end of period			$	2,386					$	2,894

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

10

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BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)    General

Berkshire Hathaway Energy Company ("BHE"), a wholly owned subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"), is a holding company headquartered in Iowa that has investments in a highly diversified portfolio of locally managed and operated businesses principally engaged in the energy industry (collectively with its subsidiaries, the "Company"). 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. and its subsidiaries ("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, has investments in 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 and interests in a liquefied natural gas ("LNG") export, import and storage facility in the U.S., an electric transmission business in Canada, interests in electric transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, 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, 2025, and for the three- and nine-month periods ended September 30, 2025 and 2024. The results of operations for the three- and nine-month periods ended September 30, 2025, 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, 2024, 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, 2025. Refer to Note 9 for discussion of loss contingencies related to the Oregon and Northern California 2020 wildfires (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."

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(2)    New Accounting Pronouncements

In December 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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 November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures Subtopic 220-40, "Disaggregation of Income Statement Expenses" which addresses requests from investors for more detailed information about certain expenses and requires disclosure of the amounts of purchases of inventory, employee compensation, depreciation and intangible asset amortization included in each relevant expense caption presented on the income statement. This guidance, as clarified in ASU 2025-01, is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. 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.

(3)    Property, Plant and Equipment, Net

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

									As of
			Depreciable						September 30,						December 31,
			Life						2025						2024
Regulated assets:
Utility generation, transmission and distribution systems			5-80 years						$	106,751					$	103,015
Interstate natural gas pipeline assets			3-80 years						20,646						20,237
									127,397						123,252
Accumulated depreciation and amortization									(40,554)						(38,940)
Regulated assets, net									86,843						84,312
Nonregulated assets:
Independent power plants			2-50 years						9,229						8,619
Cove Point LNG facility			40 years						3,457						3,455
Other assets			2-30 years						2,933						2,766
									15,619						14,840
Accumulated depreciation and amortization									(4,553)						(4,176)
Nonregulated assets, net									11,066						10,664
									97,909						94,976
Construction work-in-progress									11,845						8,793
Property, plant and equipment, net									$	109,754					$	103,769

Construction work-in-progress includes $10.8 billion as of September 30, 2025, and $8.0 billion as of December 31, 2024, related to the construction of regulated assets.

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(4)    Investments and Restricted Cash and Cash Equivalents and Investments

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

			As of
			September 30,						December 31,
			2025						2024
Investments:
BYD Company Limited common stock			$	—					$	415
U.S. Treasury Bills			40						—
Company-owned life insurance			563						525
Other			390						394
Total investments			993						1,334
Equity method investments:
BHE Renewables tax equity investments			4,079						4,773
Electric Transmission Texas, LLC			822						761
Iroquois Gas Transmission System, L.P.			581						580
Other			342						339
Total equity method investments			5,824						6,453
Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds			962						871
Other restricted cash and cash equivalents			231						194
Total restricted cash and cash equivalents and investments			1,193						1,065
Total investments and restricted cash and cash equivalents and investments			$	8,010					$	8,852
Reflected as:
Other current assets			$	303					$	217
Noncurrent assets			7,707						8,635
Total investments and restricted cash and cash equivalents and investments			$	8,010					$	8,852

Investments

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

			Three-Month Periods												Nine-Month Periods
			Ended September 30,												Ended September 30,
			2025						2024						2025						2024
Unrealized gains recognized on marketable securities held at the reporting date			$	13					$	166					$	20					$	234
Net gains recognized on marketable securities sold during the period			—						102						112						240
Gains on marketable securities, net			$	13					$	268					$	132					$	474

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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,
			2025						2024
Cash and cash equivalents			$	2,155					$	1,392
Investments and restricted cash and cash equivalents			216						177
Investments and restricted cash and cash equivalents and investments			15						17
Total cash and cash equivalents and restricted cash and cash equivalents			$	2,386					$	1,586

(5)    Recent Financing Transactions

Long-Term Debt

In September 2025, Sierra Pacific issued $450 million of its 6.20% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due December 2055. Sierra Pacific will pay interest on the notes at a rate of 6.20% through December 2030, subject to a reset every five years. Sierra Pacific intends to use the net proceeds from the sale of the notes to fund capital expenditures and for general corporate purposes.

In April 2025, Northern Powergrid (Yorkshire) plc issued £250 million of its 6.125% Bonds due April 2050 and intends to use the net proceeds for general corporate purposes.

In March 2025, PacifiCorp issued $850 million of its 7.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due September 2055. PacifiCorp will pay interest on the notes at a rate of 7.375% through September 2030, subject to a reset every five years, not to reset below 7.375%. 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 February 2025, Nevada Power issued $300 million of its 6.25% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due May 2055. Nevada Power will pay interest on the notes at a rate of 6.25% through May 2030, subject to a reset every five years. Nevada Power intends to use the net proceeds from the sale of the notes to fund capital expenditures and for general corporate purposes.

In January 2025, Eastern Energy Gas issued $700 million of 5.80% Senior Notes due January 2035 and $500 million of 6.20% Senior Notes due January 2055. Eastern Energy Gas used the net proceeds from the sale of the notes to rebalance its capitalization structure by returning a portion of the equity capital received from its indirect parent, BHE.

Credit Facilities

In June 2025, BHE amended its existing $3.5 billion unsecured credit facility expiring in June 2027. The amendment extended the expiration date to June 2028 and amended certain provisions of the existing credit agreement.

In June 2025, PacifiCorp amended its existing $2.0 billion unsecured credit facility expiring in June 2027. The amendment extended the expiration date to June 2028 and amended certain provisions of the existing credit agreement.

In June 2025, PacifiCorp amended its existing $900 million 364‑day unsecured credit facility expiring in June 2025. The amendment extended the expiration date to June 2026 and amended certain provisions of the existing credit agreement.

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In June 2025, MidAmerican Energy amended its existing $1.5 billion unsecured credit facility expiring in June 2027. The amendment extended the expiration date to June 2028 and amended certain provisions of the existing credit agreement.

In June 2025, Nevada Power and Sierra Pacific each amended its existing $600 million and $400 million secured credit facilities expiring in June 2027. The amendments extended the expiration date to June 2028 and amended certain provisions of the existing credit agreements.

In June 2025, HomeServices amended its existing $200 million secured credit facility expiring in September 2026. The amendment extended the expiration date to June 2030, increased the commitment of the lender to $350 million and amended certain provisions of the existing credit agreement.

In February 2025, BHE Canada amended its existing C$50 million unsecured revolving credit facility expiring December 2027. The amendment extended the expiration date to December 2028 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,
			2025						2024						2025						2024
Federal statutory income tax rate			21		%				21		%				21		%				21		%
Income tax credits			(70)						(55)						(66)						(60)
State income tax, net of federal income tax impacts			2						—						2						(1)
Income tax effect of foreign income			(1)						(1)						(2)						(2)
Effects of ratemaking(1)			(6)						(5)						(4)						(5)
Equity earnings			(3)						(1)						(3)						(2)
Noncontrolling interest			(1)						—						(1)						(1)
Other			—						(1)						(1)						1
Effective income tax rate			(58)		%				(42)		%				(54)		%				(49)		%

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

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, 2025 and 2024 totaled $1,673 million and $1,571 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, 2025 and 2024 totaling $1,255 million and $1,299 million, respectively.

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(7)    Employee Benefit Plans

Domestic Operations

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

			Three-Month Periods												Nine-Month Periods
			Ended September 30,												Ended September 30,
			2025						2024						2025						2024
Pension:
Service cost			$	4					$	3					$	10					$	11
Interest cost			25						25						79						78
Expected return on plan assets			(29)						(30)						(90)						(94)
Net amortization			1						3						5						7
Net periodic benefit cost			$	1					$	1					$	4					$	2
Other postretirement:
Service cost			$	1					$	3					$	3					$	5
Interest cost			7						7						21						22
Expected return on plan assets			(9)						(10)						(27)						(27)
Net amortization			(2)						—						(5)						(1)
Net periodic benefit credit			$	(3)					$	—					$	(8)					$	(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 $1 million, respectively, during 2025. As of September 30, 2025, $9 million and $1 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

Foreign Operations

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

			Three-Month Periods												Nine-Month Periods
			Ended September 30,												Ended September 30,
			2025						2024						2025						2024
Service cost			$	2					$	1					$	4					$	4
Interest cost			16						13						45						40
Expected return on plan assets			(22)						(20)						(63)						(59)
Net amortization			8						8						24						22
Net periodic benefit cost			$	4					$	2					$	10					$	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 £8 million during 2025. As of September 30, 2025, £6 million, or $8 million, of contributions had been made to the United Kingdom pension plan.

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(8)    Fair Value Measurements

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

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

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

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

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, 2025:
Assets:
Commodity derivatives						$	—					$	62					$	2					$	(10)					$	54
Foreign currency exchange rate derivatives						—						12						—						—						12
Interest rate derivatives						28						28						12						—						68
Mortgage loans held for sale						—						663						—						—						663
Money market mutual funds						1,919						—						—						—						1,919
Debt securities:
U.S. government obligations						318						—						—						—						318
Corporate obligations						—						128						—						—						128
Municipal obligations						—						2						—						—						2
Equity securities:
U.S. companies						539						—						—						—						539
International companies						9						—						—						—						9
Investment funds						287						—						—						—						287
						$	3,100					$	895					$	14					$	(10)					$	3,999
Liabilities:
Commodity derivatives						$	(12)					$	(103)					$	(44)					$	35					$	(124)
Interest rate derivatives						—						(4)						(1)						2						(3)
						$	(12)					$	(107)					$	(45)					$	37					$	(127)

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						Input Levels for Fair Value Measurements
						Level 1						Level 2						Level 3						Other(1)						Total
As of December 31, 2024:
Assets:
Commodity derivatives						$	—					$	81					$	2					$	(22)					$	61
Interest rate derivatives						33						42						7						—						82
Mortgage loans held for sale						—						528						—						—						528
Money market mutual funds						927						—						—						—						927
Debt securities:
U.S. government obligations						271						—						—						—						271
Corporate obligations						—						109						—						—						109
Municipal obligations						—						2						—						—						2
Equity securities:
U.S. companies						479						—						—						—						479
International companies						424						—						—						—						424
Investment funds						313						—						—						—						313
						$	2,447					$	762					$	9					$	(22)					$	3,196
Liabilities:
Commodity derivatives						$	(15)					$	(141)					$	(74)					$	31					$	(199)
Foreign currency exchange rate derivatives						—						(23)						—						—						(23)
Interest rate derivatives						—						(1)						(2)						—						(3)
						$	(15)					$	(165)					$	(76)					$	31					$	(225)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $27 million and $9 million as of September 30, 2025, and December 31, 2024, 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.

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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
2025:
Beginning balance			$	(100)					$	14					$	(72)					$	5
Changes included in earnings(1)			—						(3)						—						6
Changes in fair value recognized in net regulatory assets			(41)						—						(83)						—
Settlements			99						—						113						—
Ending balance			$	(42)					$	11					$	(42)					$	11

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

(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, 2025												As of December 31, 2024
			Carrying						Fair						Carrying						Fair
			Value						Value						Value						Value
Long-term debt			$	56,404					$	52,529					$	55,257					$	50,179

(9)    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, 2025, PacifiCorp entered into battery storage agreements with commitments totaling approximately $1.8 billion through 2048. In October 2025, an additional battery storage agreement became effective with commitments totaling approximately $343 million through 2046. The facilities associated with these contracts have not yet achieved commercial operation. To the extent these facilities do not achieve commercial operation, PacifiCorp has no obligation to the counterparty.

During the nine-month period ended September 30, 2025, PacifiCorp entered into certain coal supply and transportation agreements totaling $109 million through 2029.

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Construction Commitments

During the nine-month period ended September 30, 2025, PacifiCorp became committed under the terms of a previously existing construction funding agreement with Idaho Power Company to support the development of the Boardman to Hemingway 500‑kV transmission line. PacifiCorp is committed to contributing up to $460 million toward construction costs, representing PacifiCorp's share of the total estimated project cost of $843 million. In addition, PacifiCorp issued limited notice to proceed for construction contracts totaling $278 million through 2027 for service center and essential services buildings located in Salt Lake City, Utah. The projects are expected to be placed into service mid-2028.

During the nine-month period ended September 30, 2025, MidAmerican Energy entered into firm construction commitments totaling $73 million for the remainder of 2025 through 2028 related to the construction of wind-powered, solar-powered and other new generating facilities in Iowa.

In October 2025, MidAmerican Energy entered into firm construction commitments totaling $531 million for the remainder of 2025 through 2029 related to the construction of wind-powered, solar-powered and other new generating facilities in Iowa.

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.

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

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, PacifiCorp received correspondence from the U.S. and Oregon Departments of Justice regarding the potential recovery of certain costs and damages alleged to have occurred on federal and state lands in connection with certain of the 2020 Wildfires. In December 2024, the United States of America filed a complaint against PacifiCorp in conjunction with the correspondence from the U.S. Department of Justice. The civil cover sheet accompanying the complaint demands damages estimated to exceed $900 million. PacifiCorp is actively cooperating with the U.S. and Oregon Departments of Justice on resolving these alleged claims.

Amounts sought in outstanding complaints and demands filed in Oregon and in certain demands made in California totaled approximately $55 billion, excluding any doubling or trebling of damages or punitive damages included in the complaints and excluding damages that may be sought by additional plaintiffs granted substitution counsel in the James class action lawsuit described below. Generally, the complaints filed in California do not specify damages sought and are excluded from this amount. Of the $55 billion, $52 billion represents the economic and noneconomic damages sought in the James mass complaints described below. 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 damages associated with timber, shrubs and produce in the event the defendant is determined to have willfully and intentionally trespassed.

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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 damage.

Based on available information to date, losses have been and will likely continue to be incurred associated with the Wildfires. Final determinations of liability will only be made following the completion of comprehensive investigations, which may be or have been performed by various entities, including the U.S. Department of Agriculture Forest Service ("USFS"), the California Public Utilities Commission, the Oregon Department of Forestry ("ODF") and the Oregon Department of Justice, as well as 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 with 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 and include the Santiam Canyon, Beachie Creek, South Obenchain, Echo Mountain Complex, 242, Archie Creek, Slater and other fires. The Slater fire occurred in both Oregon and California. Third-party reports for these wildfires indicate over 2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities.

In May 2022, the USFS issued its report of investigation into the Archie Creek fire concluding that the probable cause of the fire was power lines owned and operated by PacifiCorp. The USFS report for the Archie Creek fire also states that evidence indicates failure of power line infrastructure. The USFS report of investigation into the Slater fire for the investigation period October 5, 2020, to December 8, 2020, concluded that the fire was caused by a downed power line owned and operated by PacifiCorp. The USFS report for the Slater fire also states that evidence indicates a tree fell onto the power line and that wind blew over the 137-foot tree with internal rot that showed no outward signs of distress and would not have been classified or identified as a hazard tree.

Settlements have been reached with substantially all individual plaintiffs, timber companies and insurance subrogation plaintiffs in both the Archie Creek and Slater fires with government timber and suppression cost claims remaining. Additionally, settlements have been reached for all wrongful death claims associated with the 2020 Wildfires.

In April 2023, the USFS issued its report of investigation into a wildland fire that began in the Opal Creek wilderness outside of the Santiam Canyon that was first reported on August 16, 2020 ("Beachie Creek Fire"), approximately three weeks prior to the September 2020 wind event described above. In March 2025, PacifiCorp received the ODF's final investigation report on the Santiam Canyon fires ("ODF's Report"), which concluded that embers from the pre-existing Beachie Creek Fire caused 12 fires within the Santiam Canyon. The ODF's Report also found that PacifiCorp's power lines did not contribute to the overall spread of fire into the Santiam Canyon even though its power lines ignited seven spot fires within the Santiam Canyon that were each suppressed.

The Beachie Creek fire that spread into the Santiam Canyon burned approximately 193,000 acres; the South Obenchain fire burned approximately 33,000 acres; the Echo Mountain Complex fire burned approximately 3,000 acres; and the 242 fire burned approximately 14,000 acres. The James cases described below are associated with the Beachie Creek (Santiam Canyon), South Obenchain, Echo Mountain Complex and 242 fires, which are four distinct fires located hundreds of miles apart.

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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 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. 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 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. Since filing of the original class action complaint, numerous James class members have been named and damages specified in various complaints as described below. Additionally, numerous cases were consolidated into the original James complaint

As of October 2025, various mass complaints against PacifiCorp naming approximately 1,700 class members have been filed referencing the James case as the lead case. These James mass complaints make damages-only allegations with substantially all plaintiffs individually seeking $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, as well as doubling of economic damages. An additional 1,500 plaintiffs have been granted the ability not to be represented by James lead counsel. A small portion of these additional plaintiffs have filed complaints seeking damages similar to those in the mass complaints. PacifiCorp expects additional complaints will be filed for these plaintiffs, including for the portion that are scheduled for trial under the July 2025 case management order described below.

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 below that are being appealed.

James Trial Activity

In June 2023, a jury verdict was issued in the first James trial finding PacifiCorp's conduct grossly negligent, reckless and willful as to each of the 17 named plaintiffs and the entire class. The jury awarded economic and noneconomic damages. After the jury verdict, the Multnomah County Circuit Court Oregon doubled the economic damages, in accordance with Oregon law, and added punitive damages by applying a 0.25 multiplier to the awarded economic and noneconomic damages. PacifiCorp filed a motion with the Multnomah County Circuit Court Oregon requesting the court offset the damage awards by deducting insurance proceeds received by any of the plaintiffs. In January 2024, PacifiCorp filed a notice of appeal associated with the June 2023 verdict, including whether the case can proceed as a class action.

Subsequent to the June 2023 James verdict, numerous damages phase trials were held with separate jury verdicts issued and damages awarded for each on a basis consistent with the initial trial and relying on the liability determination in the June 2023 James verdict. PacifiCorp amended its January 2024 appeal of the June 2023 James verdict to include the jury verdicts for the first two damages phase trials. PacifiCorp has filed notices of appeal for the subsequent jury verdicts in the damages phase trials once limited judgments are entered and any post-trial motions filed. Refer to "James Court Activity" below regarding the filing of PacifiCorp's appellate briefs. The appeals process and further actions could take several years.

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The James jury verdicts awarded various damages as follows (in millions):

						Number of Plaintiffs						Verdict / Limited Judgment Date						Damages(1)
James Trial																		Doubled Economic						Non-economic						Punitive						Insurance Offset(2)						Net Damages						Appeal Filed
Jury verdicts, limited judgments entered(3)
Initial James trial						17						June 2023 / January 2024						$	9					$	67					$	18					$	2					$	92					Yes
First damages						9						January 2024 / April 2024						12						56						16						4						80						Yes
Second damages						10						March 2024 / June 2024						12						23						7						4						38						Yes
Third damages						8						February 2025 / April 2025						8						32						9						4						45						Yes
Fourth damages						7						March 2025 / June 2025						5						34						9						1						47						Yes
Fifth damages						9						April 2025 / August 2025						5						11						3						1						18						Yes
Sixth damages						10						May 2025 / July 2025						11						30						9						2						48						Yes
Seventh damages						10						June 2025 / August 2025						8						28						8						1						43						Yes
Eighth damages						11						July 2025 / September 2025						10						36						10						3						53
Jury verdicts, limited judgments not yet entered
Ninth damages						10						September 2025						11						63						17						3						88
Tenth damages						8						October 2025						5						26						7						1						37
						109												$	96					$	406					$	113					$	26					$	589

(1)For jury verdicts where the limited judgment has not yet been entered, the doubling of economic damages and the application of punitive damages are estimates.

(2)For jury verdicts where limited judgment has been entered, the court offset the awards by the amount of insurance proceeds received by any of the plaintiffs. For jury verdicts where the limited judgment has not yet been entered, the insurance offset is an estimate.

(3)For each limited judgment entered in the court, PacifiCorp has posted or expects to post a supersedeas bond, which stays any effort to seek payment of the judgments pending final resolution of any appeals. Under Oregon Revised Statutes 82.010, interest at a rate of 9% per annum will accrue on the judgments commencing at the date the judgments were entered until the entire money award is paid, amended or reversed by an appellate court. The supersedeas bond posted for the June 2023 James verdict covers three years of post-judgment interest while amounts posted for the subsequent verdicts cover two years of post-judgment interest.

Through October 2025, jury verdict awards averaged approximately $5 million per plaintiff, including insurance offset. Additional damages phase trials are scheduled to occur in 2025 through 2028 as described below.

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James Court Activity

In April 2025, PacifiCorp filed its opening brief with the Oregon Court of Appeals in connection with its appeal of the June 2023 James verdict and the January and March 2024 verdicts for the first two James damages phase trials. In the opening brief, PacifiCorp addresses numerous procedural and legal issues, including that the class certification is improper due to the plaintiffs being impacted by distinct fires with independent ignition points that were hundreds of miles apart; awarding of non-economic damages is not allowed under Oregon law; plaintiffs failed to prove that PacifiCorp caused harm to every class member; and jury instructions applied incorrect legal standards in assessing class-wide evidence and individual claims. Additionally, PacifiCorp incorporated the ODF's Report into its opening appellate brief. Various parties who are not party to the James case have filed supportive amicus briefs with the court. Plaintiffs filed their combined answering and cross-appeal brief on August 21, 2025, after plaintiffs requested three delays from the Oregon Court of Appeals. PacifiCorp filed its combined reply brief and cross-appeal answering brief on October 17, 2025. Plaintiffs' reply brief is due on November 7, 2025, unless plaintiffs ask for additional extensions. On October 23, 2025, PacifiCorp filed a request with the Oregon Court of Appeals for an expedited oral argument, which, if granted, will facilitate a more prompt decision from the court.

Subsequent to the first two damages phase trials, nine damages phase trials were scheduled to be held in 2025 in accordance with the Multnomah County Circuit Court Oregon's October 2024 case management order. In March 2025, in consideration of the ODF's Report, PacifiCorp filed a motion to stay the remaining James damages phase trials scheduled under the October 2024 case management order. The motion was heard by the court and was denied in April 2025. The remaining damages phase trial ordered under the October 2024 case management order is scheduled to begin December 1, 2025.

On July 28, 2025, the Multnomah County Circuit Court Oregon issued Case Management Order No. 11 ("CMO No. 11") in response to the May 2025 hearing that was held to evaluate the scheduling of additional damages phase trials. As ordered, CMO No. 11 proposes to schedule dozens of trials in 2026 and over 100 more in 2027 and 2028, involving approximately 2,000 plaintiffs. Additionally, CMO No. 11 requires mediation every other month starting in October 2025.

On August 8, 2025, PacifiCorp filed a motion with the Oregon Court of Appeals to stay the James damages phase trials addressed in CMO No. 11 and to which plaintiffs' counsel responded on August 29, 2025. On September 23, 2025, the Appellate Commissioner of the Oregon Court of Appeals denied PacifiCorp's motion to stay. On September 26, 2025, PacifiCorp filed a request for reconsideration of the stay denial with the Chief Judge of the Oregon Court of Appeals. On October 13, 2025, the Oregon Court of Appeals issued an order denying PacifiCorp's request for reconsideration. PacifiCorp has 35 days from October 13, 2025, to petition the Oregon Supreme Court to review the Oregon Court of Appeals order.

Potential Effects of James CMO No. 11

To appeal the limited judgments, PacifiCorp is required to bond the judgments. As of the date of this filing, PacifiCorp has posted bonds totaling $479 million associated with the limited judgments entered to date for 91 plaintiffs. These bonding requirements will continue to apply to future judgments associated with the CMO No. 11 trial schedule beginning in 2026. As noted above, CMO No. 11 proposes to schedule dozens of trials in 2026 and over 100 more in 2027 and 2028, involving approximately 2,000 plaintiffs. Each trial is subject to and dependent on judicial resources and availability, which will be determined six weeks before each trial. The CMO No. 11 proposed schedule is likely to put significant strain on the Multnomah County Circuit Court system, and PacifiCorp believes this may challenge the court's ability to fulfill the schedule in CMO No. 11.

If, however, the trial schedule and caseload progress as proposed in CMO No. 11 and the future limited judgments follow current trends, PacifiCorp estimates damages awarded in the jury verdicts may exceed its available surety bond and letter of credit capacity, requiring cash to be posted with Multnomah County to stay payment of damages awarded in the subsequent damages trials. PacifiCorp expects additional debt financings, including potential borrowings under its $2.0 billion credit facility subject to its availability, or other sources of funding will be needed to provide liquidity to post cash for judgments. Maintaining this trial schedule will cause significant financial strain on PacifiCorp's liquidity and will put pressure on PacifiCorp's credit metrics due to bonding requirements. Weakening of PacifiCorp's credit metrics could result in a downgrade, potentially below investment grade. Such a downgrade may result in the loss of surety bond and letter of credit capacity; trigger cash collateral calls for surety bonds posted; and trigger additional cash collateral calls or other forms of security for wholesale energy agreements that contain credit-risk-related contingent features or rights to demand adequate assurance in the event of a material adverse change in PacifiCorp's creditworthiness. Additionally, a downgrade of PacifiCorp's senior secured debt below investment grade would require new regulatory applications and approvals due to certain authorizations or exemptions currently in place with certain regulatory commissions for the issuance of securities.

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PacifiCorp may be unable to obtain the required funding to meet its liquidity needs due to cash requirements for judgments if the trial schedule and case load progresses as proposed in CMO No. 11. Should PacifiCorp be downgraded below investment grade and unable to secure sufficient debt financings or alternative funding sources, it may have insufficient liquidity to support ongoing operations including the ability to absorb wholesale power volatility, pay suppliers and meet debt obligations, and such liquidity issues may impact transmission and generation development, purchasing power in the market, building and upgrading substations, connecting new customers, addressing outages and maintaining system resilience.

Litigation is inherently difficult to predict, and its potential financial impacts are therefore based on assumptions that will change. Furthermore, there may be judicial decisions and other events or circumstances that could improve or worsen the challenges PacifiCorp faces. PacifiCorp believes it will have sufficient liquidity to cover its operations and obligations beyond a year.

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 USFS issued a Wildland Fire Origin and Cause Supplemental Incident Report. The report concluded that a tree coming in contact with a power line is the probable cause of the 2022 McKinney Fire. Settlements have been reached with substantially all individual plaintiffs, timber companies and insurance subrogation plaintiffs in the 2022 McKinney Fire with government timber and suppression cost claims remaining. Additionally, PacifiCorp has settled or settled in principle all wrongful death claims associated with the 2022 McKinney Fire.

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 activities; (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 $2,853 million through September 30, 2025. 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, 2025, PacifiCorp paid $1,399 million in settlements associated with the Wildfires. As a result of the settlements, various trials have been cancelled. In October 2025 and through the date of this filing, PacifiCorp made additional settlement payments related to the Wildfires totaling $1 million.

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,
			2025						2024						2025						2024
Beginning balance			$	1,381					$	1,883					$	1,536					$	1,723
Accrued losses			100						—						100						251
Payments			(27)						(438)						(182)						(529)
Ending balance			$	1,454					$	1,445					$	1,454					$	1,445

As of September 30, 2025, and December 31, 2024, $580 million and $247 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, 2025, 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, 2025, and December 31, 2024, was included in other long-term 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,
			2025						2024						2025						2024
Beginning balance			$	—					$	139					$	98					$	499
Payments received			—						(5)						(98)						(365)
Ending balance			$	—					$	134					$	—					$	134

As of September 30, 2025, PacifiCorp had received all expected insurance recoveries. As of December 31, 2024, PacifiCorp's receivable for expected insurance recoveries was included in other current assets on the Consolidated Balance Sheets. No additional insurance recoveries beyond those 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 and the 2022 McKinney Fire, the variation in the types of properties and damages and the ultimate outcome of legal actions, including mediation, settlement negotiations, jury verdicts and the appeals process.

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 asserted damages totaling approximately $9 billion by separate written 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 final court approval on May 9, 2024, and the NAR and HomeServices settlements received final court approval on November 27, 2024. The U.S. District Court for the Western District of Missouri entered final judgment on the NAR and HomeServices settlements on January 15, 2025. All settlements have been appealed to the U.S. Court of Appeals for the Eighth Circuit. Initial briefing on all appeals was filed on April 21, 2025, and response briefs were filed on July 21, 2025. Reply briefs are due November 19, 2025.

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The final HomeServices settlement agreement with the plaintiffs settles all claims asserted against HomeServices, HSF Affiliates LLC and BHH Affiliates, LLC in the Burnett case and effectuates a nationwide class settlement. The final settlement agreement includes scheduled payments over four years aggregating $250 million, with payments of $10 million in September 2024 and $57 million in February 2025. HomeServices recognized an after-tax charge of approximately $140 million in the first quarter of 2024, and the liability outstanding as of September 30, 2025, and December 31, 2024, was $152 million and $194 million, respectively. If the settlement is not affirmed by the U.S. Court of Appeals for the Eighth Circuit, 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.

(10)    Revenue from Contracts with Customers

Energy Products and Services

The following table summarizes the Company's energy products and services revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business, including a reconciliation to the Company's reportable segment information included in Note 13 (in millions):

						For the Three-Month Period Ended September 30, 2025
						PacifiCorp						MidAmerican Funding						NV Energy						Northern Powergrid						BHE Pipeline Group						BHE Transmission						BHE Renewables						BHE and Other(1)						Total
Customer Revenue:
Regulated:
Retail electric						$	1,975					$	894					$	1,121					$	—					$	—					$	—					$	—					$	(1)					$	3,989
Retail gas						—						90						18						—						—						—						—						—						108
Wholesale						37						118						16						—						1						—						—						(2)						170
Transmission and distribution						46						14						22						260						—						162						—						2						506
Interstate pipeline						—						—						—						—						563						—						—						(31)						532
Other						31						—						—						—						—						—						—						—						31
Total Regulated						2,089						1,116						1,177						260						564						162						—						(32)						5,336
Nonregulated						—						—						1						20						269						16						287						(1)						592
Total Customer Revenue						2,089						1,116						1,178						280						833						178						287						(33)						5,928
Other revenue						24						10						(1)						29						2						2						64						1						131
Total						$	2,113					$	1,126					$	1,177					$	309					$	835					$	180					$	351					$	(32)					$	6,059

						For the Nine-Month Period Ended September 30, 2025
						PacifiCorp						MidAmerican Funding						NV Energy						Northern Powergrid						BHE Pipeline Group						BHE Transmission						BHE Renewables						BHE and Other(1)						Total
Customer Revenue:
Regulated:
Retail electric						$	5,333					$	2,073					$	2,556					$	—					$	—					$	—					$	—					$	(3)					$	9,959
Retail gas						—						504						89						—						—						—						—						—						593
Wholesale						65						322						45						—						2						—						—						(2)						432
Transmission and distribution						128						41						55						884						—						480						—						2						1,590
Interstate pipeline						—						—						—						—						1,994						—						—						(104)						1,890
Other						93						—						1						—						—						—						—						—						94
Total Regulated						5,619						2,940						2,746						884						1,996						480						—						(107)						14,558
Nonregulated						—						3						5						67						885						62						746						(3)						1,765
Total Customer Revenue						5,619						2,943						2,751						951						2,881						542						746						(110)						16,323
Other revenue						72						57						1						87						3						4						148						—						372
Total						$	5,691					$	3,000					$	2,752					$	1,038					$	2,884					$	546					$	894					$	(110)					$	16,695

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						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

(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,
			2025						2024						2025						2024
Customer Revenue:
Brokerage			$	1,089					$	1,084					$	3,031					$	3,068
Franchise			15						14						39						40
Total Customer Revenue			1,104						1,098						3,070						3,108
Mortgage and other revenue			81						81						239						226
Total			$	1,185					$	1,179					$	3,309					$	3,334

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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, 2025, by reportable segment (in millions):

			Performance obligations expected to be satisfied:
			Less than 12 months						More than 12 months						Total
BHE Pipeline Group			$	3,232					$	18,272					$	21,504
BHE Transmission			160						—						160
Total			$	3,392					$	18,272					$	21,664

(11)    BHE Shareholder's Equity

In February 2025, BHE redeemed at par 481,000 shares of its 4.00% Perpetual Preferred Stock from a subsidiary of Berkshire Hathaway Inc. for $481 million, plus an additional amount equal to the accrued dividends on the pro rata shares redeemed.

(12)    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, 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)
Balance, December 31, 2024			$	(421)					$	(1,999)					$	78					$	1					$	(2,341)
Other comprehensive (loss) income			(4)						533						(25)						—						504
Balance, September 30, 2025			$	(425)					$	(1,466)					$	53					$	1					$	(1,837)

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(13)    Segment Information

The Company's chief operating decision maker ("CODM") is its President and Chief Executive Officer. Earnings on common shares for each reportable segment are considered by the CODM in allocating resources and capital. The CODM generally considers actual results versus historical results, budgets or forecasts, as well as unique risks and opportunities, when making decisions about the allocation of resources and capital to each reportable segment. 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):

						For the Three-Month Period Ended September 30, 2025
						PacifiCorp						MidAmerican Funding						NV Energy						Northern Powergrid						BHE Pipeline Group						BHE Transmission						BHE Renewables(2)						HomeServices						BHE and Other(1)						Total
Operating revenue						$	2,113					$	1,126					$	1,177					$	309					$	835					$	180					$	351					$	1,185					$	(32)					$	7,244
Cost of sales						940						309						545						32						52						5						26						862						(33)						2,738
Operations and maintenance						548						241						164						68						314						36						92						271						10						1,744
Depreciation and amortization						304						209						143						92						153						54						78						10						(1)						1,042
Interest expense						199						104						81						39						72						39						33						1						139						707
Interest and dividend income						28						10						8						1						13						—						3						4						(7)						60
Income tax expense (benefit)						(102)						(66)						19						11						44						2						(196)						12						(330)						(606)
Equity income (loss)						—						—						1						—						7						20						(159)						2						—						(129)
Other segment items						5						(2)						22						(21)						(67)						(8)						(6)						(2)						18						(61)
Earnings on common shares						$	257					$	337					$	256					$	47					$	153					$	56					$	156					$	33					$	194					$	1,489
Capital expenditures						$	773					$	470					$	850					$	177					$	413					$	81					$	187					$	3					$	—					$	2,954

						For the Nine-Month Period Ended September 30, 2025
						PacifiCorp						MidAmerican Funding						NV Energy						Northern Powergrid						BHE Pipeline Group						BHE Transmission						BHE Renewables(2)						HomeServices						BHE and Other(1)						Total
Operating revenue						$	5,691					$	3,000					$	2,752					$	1,038					$	2,884					$	546					$	894					$	3,309					$	(110)					$	20,004
Cost of sales						2,381						889						1,319						94						173						14						80						2,391						(109)						7,232
Operations and maintenance						1,451						704						450						181						816						110						354						799						48						4,913
Depreciation and amortization						975						771						419						268						458						158						219						30						(1)						3,297
Interest expense						588						314						239						111						214						112						98						4						422						2,102
Interest and dividend income						89						24						19						5						50						1						10						12						(25)						185
Income tax expense (benefit)						(154)						(483)						31						52						239						9						(850)						21						(227)						(1,362)
Equity income (loss)						—						—						2						1						44						63						(525)						6						—						(409)
Other segment items						—						(21)						50						(65)						(254)						(28)						(21)						(19)						135						(223)
Earnings on common shares						$	539					$	808					$	365					$	273					$	824					$	179					$	457					$	63					$	(133)					$	3,375
Capital expenditures						$	2,179					$	1,210					$	1,996					$	505					$	867					$	263					$	407					$	6					$	94					$	7,527

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						For the Three-Month Period Ended September 30, 2024
						PacifiCorp						MidAmerican Funding						NV Energy						Northern Powergrid						BHE Pipeline Group						BHE Transmission						BHE Renewables(2)						HomeServices						BHE and Other(1)						Total
Operating revenue						$	1,923					$	907					$	1,332					$	421					$	817					$	203					$	457					$	1,179					$	(34)					$	7,205
Cost of sales						862						173						671						29						43						5						152						855						(33)						2,757
Operations and maintenance						421						230						155						58						291						48						128						283						12						1,626
Depreciation and amortization						287						230						142						87						148						58						68						11						—						1,031
Interest expense						193						109						73						36						43						39						34						1						151						679
Interest and dividend income						47						13						8						2						16						—						4						5						17						112
Income tax expense (benefit)						(79)						(162)						39						37						60						4						(169)						11						(355)						(614)
Equity income (loss)						—						—						1						—						10						21						(108)						3						—						(73)
Other segment items						39						(3)						3						(18)						(64)						(8)						(7)						(6)						274						210
Earnings on common shares						$	325					$	337					$	264					$	158					$	194					$	62					$	133					$	20					$	482					$	1,975
Capital expenditures						$	679					$	362					$	375					$	195					$	310					$	61					$	103					$	1					$	22					$	2,108

						For the Nine-Month Period Ended September 30, 2024
						PacifiCorp						MidAmerican Funding						NV Energy						Northern Powergrid						BHE Pipeline Group						BHE Transmission						BHE Renewables(2)						HomeServices						BHE and Other(1)						Total
Operating revenue						$	4,960					$	2,480					$	3,339					$	1,153					$	2,782					$	599					$	1,182					$	3,334					$	(109)					$	19,720
Cost of sales						2,076						580						1,875						86						142						17						430						2,407						(107)						7,506
Operations and maintenance						1,518						696						423						169						758						121						385						1,030						69						5,169
Depreciation and amortization						866						685						419						260						430						174						203						35						3						3,075
Interest expense						570						327						218						104						126						114						103						7						476						2,045
Interest and dividend income						156						32						32						5						49						2						11						18						57						362
Income tax expense (benefit)						(178)						(596)						58						90						273						14						(691)						(32)						(231)						(1,293)
Equity income (loss)						—						—						2						—						62						67						(375)						7						—						(237)
Other segment items						99						(14)						20						(56)						(237)						(31)						(16)						(8)						482						239
Earnings on common shares						$	363					$	806					$	400					$	393					$	927					$	197					$	372					$	(96)					$	220					$	3,582
Capital expenditures						$	2,157					$	1,100					$	1,274					$	474					$	713					$	181					$	283					$	4					$	50					$	6,236

(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.

(2)Income tax expense (benefit) 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.

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The following table summarizes the other segment items category by the Company's reportable segments:

PacifiCorp

MidAmerican Funding

NV Energy

Northern Powergrid

BHE Pipeline Group

BHE Transmission

BHE Renewables

HomeServices

Property and other taxes

X

X

X

X

X

X

X

X

Capitalized interest

X

X

X

X

X

X

X

Allowance for equity funds

X

X

X

X

X

Gains (losses) on marketable securities, net

X

X

X

X

X

X

X

Other income (expense), net

X

X

X

X

X

X

X

X

Net income attributable to noncontrolling interests

X

X

X

X

X

X

The following table summarizes the Company's total assets by reportable segment (in millions):

			As of
			September 30,						December 31,
			2025						2024
Assets:
PacifiCorp			$	37,291					$	36,134
MidAmerican Funding			29,392						28,203
NV Energy			20,737						18,708
Northern Powergrid			10,737						9,803
BHE Pipeline Group			22,578						22,114
BHE Transmission			9,561						9,098
BHE Renewables			11,778						11,963
HomeServices			3,525						3,382
BHE and Other(1)			547						735
Total assets			$	146,146					$	140,140

(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.

The following table shows the change in the carrying amount of goodwill by reportable segment for the nine-month period ended September 30, 2025 (in millions):

																											BHE Pipeline Group
			PacifiCorp						MidAmerican Funding						NV Energy						Northern Powergrid												BHE Transmission						BHE Renewables						HomeServices
																																																									Total
December 31, 2024			$	1,129					$	2,102					$	2,369					$	940					$	1,814					$	1,373					$	95					$	1,591											$	11,413
Foreign currency translation			—						—						—						49						—						46						—						—												95
Other			—						—						—						—						—						—						—						(8)												(8)
September 30, 2025			$	1,129					$	2,102					$	2,369					$	989					$	1,814					$	1,419					$	95					$	1,583											$	11,500

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

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

BHE, a wholly owned subsidiary of Berkshire Hathaway, is a holding company headquartered in Iowa that has investments in a highly diversified portfolio of locally managed and operated businesses principally engaged in the energy industry. The Company'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, has investments in 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 and interests in an LNG export, import and storage facility in the U.S., an electric transmission business in Canada, interests in electric transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects and one of the largest residential real estate brokerage firms and residential real estate brokerage franchise networks in the U.S. The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other corporate entities, corporate functions and intersegment eliminations.

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Results of Operations for the Third Quarter and First Nine Months of 2025 and 2024

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
			2025						2024						Change												2025						2024						Change
Operating revenue:
PacifiCorp			$	2,113					$	1,923					$	190					10		%				$	5,691					$	4,960					$	731					15		%
MidAmerican Funding			1,126						907						219						24						3,000						2,480						520						21
NV Energy			1,177						1,332						(155)						(12)						2,752						3,339						(587)						(18)
Northern Powergrid			309						421						(112)						(27)						1,038						1,153						(115)						(10)
BHE Pipeline Group			835						817						18						2						2,884						2,782						102						4
BHE Transmission			180						203						(23)						(11)						546						599						(53)						(9)
BHE Renewables			351						457						(106)						(23)						894						1,182						(288)						(24)
HomeServices			1,185						1,179						6						1						3,309						3,334						(25)						(1)
BHE and Other			(32)						(34)						2						6						(110)						(109)						(1)						(1)
Total operating revenue			$	7,244					$	7,205					$	39					1		%				$	20,004					$	19,720					$	284					1		%
Earnings on common shares:
PacifiCorp			$	257					$	325					$	(68)					(21)		%				$	539					$	363					$	176					48		%
MidAmerican Funding			337						337						—						—						808						806						2						—
NV Energy			256						264						(8)						(3)						365						400						(35)						(9)
Northern Powergrid			47						158						(111)						(70)						273						393						(120)						(31)
BHE Pipeline Group			153						194						(41)						(21)						824						927						(103)						(11)
BHE Transmission			56						62						(6)						(10)						179						197						(18)						(9)
BHE Renewables(1)			156						133						23						17						457						372						85						23
HomeServices			33						20						13						65						63						(96)						159						*
BHE and Other			194						482						(288)						(60)						(133)						220						(353)						*
Total earnings on common shares			$	1,489					$	1,975					$	(486)					(25)		%				$	3,375					$	3,582					$	(207)					(6)		%

*    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 decreased $486 million for the third quarter of 2025 compared to 2024. Included in these results was a pre-tax gain in the third quarter of 2024 of $255 million ($202 million after-tax) related to the Company's investment in BYD Company Limited. Excluding the impact of this item, earnings on common shares for the third quarter of 2025 decreased $284 million, or 16%, compared to adjusted earnings on common shares for the third quarter of 2024 of $1,773 million.

Earnings on common shares decreased $207 million for the first nine months of 2025 compared to 2024. Included in these results was a pre-tax gain in the first nine months of 2025 of $110 million ($87 million after-tax) compared to a pre-tax gain in the first nine months of 2024 of $444 million ($351 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 2025 was $3,288 million, an increase of $57 million, or 2%, compared to adjusted earnings on common shares for the first nine months of 2024 of $3,231 million.

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The changes in earnings on common shares for the third quarter and for the first nine months of 2025 compared to 2024 were primarily due to the following:

•The Utilities' earnings decreased $76 million for the third quarter and increased $143 million for the first nine months of 2025 compared to 2024, primarily due to higher electric utility margin and changes in wildfire loss accruals, which were $100 million higher for the third quarter of 2025 compared to 2024 and $151 million lower for the first nine months of 2025 compared to 2024. These items were partially offset by higher depreciation and amortization expense for the first nine months of 2025, increased operations and maintenance expense, lower interest and dividend income, lower allowances for equity and borrowed funds used during construction, higher interest expense and unfavorable income tax benefits, largely due to the effects of ratemaking and lower PTCs recognized. Electric retail customer volumes increased 2.7% for the first nine months of 2025 compared to 2024, 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 decreased $111 million for the third quarter and $120 million for the first nine months of 2025 compared to 2024, primarily due to lower distribution revenue, higher income tax expense from a charge related to the March 2025 enactment of a change in the Energy Profits Levy income tax and higher distribution-related costs, partially offset by lower income tax expense from higher utilization of tax losses from the upstream gas exploration and production business for the first nine months of 2025. Units distributed increased 1.4% for the first nine months of 2025 compared to 2024 mainly due to higher customer usage;

•BHE Pipeline Group's earnings decreased $41 million for the third quarter and $103 million for the first nine months of 2025 compared to 2024, primarily due to higher interest expense at BHE GT&S from debt issuances in January 2025 and debt refinancings in the fourth quarter of 2024 at higher interest rates, lower earnings at Northern Natural Gas from increased operations and maintenance expense and lower margin on gas sales and lower equity earnings at BHE GT&S, partially offset by higher transportation and storage revenues at Northern Natural Gas and BHE GT&S and higher variable revenue at Cove Point;

•BHE Renewables' earnings increased $23 million for the third quarter and $85 million for the first nine months of 2025 compared to 2024, primarily due to higher natural gas and geothermal earnings, higher solar earnings and higher earnings from the wind tax equity investment portfolio for the first nine months of 2025, partially offset by lower earnings from owned wind projects and lower earnings from the wind tax equity investment portfolio for the third quarter of 2025;

•HomeServices' earnings increased $13 million for the third quarter and $159 million for the first nine months of 2025 compared to 2024, primarily due to an after-tax 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 and favorable operating expenses; and

•BHE and Other's earnings decreased $288 million for the third quarter and $353 million for the first nine months of 2025 compared to 2024. The changes included an unfavorable comparative change of $202 million in the third quarter and $264 million for the first nine months of 2025 and lower net interest and dividend income of $26 million for the third quarter and $84 million for the first nine months of 2025, each related to the Company's investment in BYD Company Limited, lower federal income tax credits recognized on a consolidated basis and unfavorable consolidated income tax adjustments, partially offset by lower interest expense.

Reportable Segment Results

PacifiCorp

Operating revenue increased $190 million for the third quarter of 2025 compared to 2024, primarily due to higher retail revenue of $187 million. Retail revenue increased primarily due to price impacts of $151 million from higher average rates, largely from tariff changes, and $36 million from higher retail volumes. Retail customer volumes increased 2.0% primarily due to higher customer usage and an increase in the average number of customers, partially offset by the unfavorable impact of weather.

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Earnings decreased $68 million for the third quarter of 2025 compared to 2024, primarily due to higher wildfire loss accruals of $100 million, decreased allowances for equity and borrowed funds used during construction of $31 million, higher operations and maintenance expense of $26 million, lower interest and dividend income of $20 million and increased depreciation and amortization expense of $17 million. These items were partially offset by higher utility margin of $112 million. Operations and maintenance expense increased largely due to higher amortization of demand-side management costs, increased salary and benefit expenses, higher legal fees, increased insurance premiums and higher general and plant maintenance costs, partially offset by lower vegetation management and other wildfire prevention costs. Depreciation and amortization increased largely due to additional assets placed in-service. Utility margin increased primarily due to lower purchased electricity costs and higher retail rates and volumes, partially offset by unfavorable deferred net power costs and higher thermal generation costs.

Operating revenue increased $731 million for the first nine months of 2025 compared to 2024, primarily due to higher retail revenue of $705 million and higher wholesale and other revenue of $26 million. Retail revenue increased primarily due to price impacts of $604 million from higher average rates, largely from tariff changes and favorable adjustments of $87 million due to the buy-down of certain plant balances and regulatory assets pursuant to the Utah general rate case order (fully offset in depreciation and amortization expense), and $101 million from higher retail volumes. Retail customer volumes increased 2.0% primarily due to an increase in the average number of customers, higher customer usage and the favorable impact of weather. Wholesale and other revenue increased primarily due to higher wholesale volumes, partially offset by lower average wholesale prices.

Earnings increased $176 million for the first nine months of 2025 compared to 2024, primarily due to higher utility margin of $426 million, lower wildfire loss accruals of $151 million and a favorable income tax benefit from higher PTCs recognized of $44 million offset by the effects of ratemaking of $17 million. These items were partially offset by higher depreciation and amortization expense of $109 million, decreased allowance for equity and borrowed funds used during construction of $86 million, higher operations and maintenance expense of $84 million, lower interest and dividend income of $68 million and higher interest expense of $19 million. Utility margin increased primarily due to higher retail rates and volumes, lower purchased electricity costs and higher wholesale volumes, partially offset by unfavorable deferred net power costs, higher thermal generation costs and lower wholesale average prices. Depreciation and amortization increased largely due to the buy-down of certain plant balances and regulatory assets pursuant to the Utah general rate case order and additional assets placed in-service. Operations and maintenance expense increased mainly due to higher amortization of demand-side management costs, increased insurance premiums, higher general and plant maintenance costs and increased salary and benefit expenses, partially offset by lower vegetation management and other wildfire prevention costs and higher accruals of federal grant reimbursements. Interest expense increased primarily due to a March 2025 debt issuance.

MidAmerican Funding

Operating revenue increased $219 million for the third quarter of 2025 compared to 2024, primarily due to higher electric operating revenue of $212 million. Electric operating revenue increased due to higher retail revenue of $165 million and higher wholesale and other revenue of $47 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $101 million (fully offset in cost of sales, operations and maintenance expense and income tax benefit) and higher retail volumes of $66 million. Electric retail customer volumes increased 11.3%, primarily due to higher customer usage and the favorable impact of weather. Electric wholesale and other revenue increased mainly due to higher average wholesale prices of $43 million.

Earnings were unchanged for the third quarter of 2025 compared to 2024, primarily due to higher electric utility margin of $82 million and lower depreciation and amortization expense of $21 million, partially offset by an unfavorable income tax benefit, largely from lower PTCs recognized of $51 million and the effects of ratemaking of $14 million, and higher operations and maintenance expense of $11 million. Electric utility margin increased primarily due to higher retail and wholesale revenues, partially offset by higher purchased electricity and thermal generation costs. Depreciation and amortization expense decreased primarily due to the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Operations and maintenance expense increased primarily due to higher general and plant maintenance costs, partially offset by lower administrative and other costs.

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Operating revenue increased $520 million for the first nine months of 2025 compared to 2024, primarily due to higher electric operating revenue of $422 million and higher natural gas operating revenue of $99 million. Electric operating revenue increased due to higher retail revenue of $284 million and higher wholesale and other revenue of $138 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $165 million (fully offset in cost of sales, operations and maintenance expense and income tax benefit) and higher retail volumes of $125 million, partially offset by price impacts of $6 million from changes in sales mix. Electric retail customer volumes increased 9.8%, primarily due to higher customer usage and the favorable impact of weather. Electric wholesale and other revenue increased mainly due to higher average wholesale prices of $139 million. Natural gas operating revenue increased primarily due to higher energy-related rates of $92 million (fully offset in cost of sales) from a higher average per-unit cost of natural gas sold and the favorable impact of weather of $7 million.

Earnings increased $2 million for the first nine months of 2025 compared to 2024, primarily due to higher electric utility margin of $205 million, lower interest expense of $13 million and higher allowances for equity and borrowed funds used during construction of $12 million. These items were partially offset by an unfavorable income tax benefit, largely from lower PTCs recognized of $55 million and the effects of ratemaking of $18 million, higher depreciation and amortization expense of $86 million, higher operations and maintenance expense of $8 million, lower interest and dividend income of $8 million and unfavorable changes in the cash surrender value of corporate-owned life insurance policies of $8 million. Electric utility margin increased primarily due to higher retail and wholesale revenues, partially offset by higher purchased electricity and thermal generation costs. Interest expense decreased mainly due to lower outstanding long-term debt balances. Depreciation and amortization expense increased primarily due to the impacts of certain regulatory mechanisms and additional assets placed in-service. Operations and maintenance expense increased primarily due to higher general and plant maintenance costs, partially offset by lower technology, administrative and other costs.

NV Energy

Operating revenue decreased $155 million for the third quarter of 2025 compared to 2024, primarily due to lower electric operating revenue of $155 million. Electric operating revenue decreased primarily due to lower fully bundled energy rates (fully offset in cost of sales) of $123 million, lower customer volumes of $28 million, lower wholesale revenue of $17 million and lower revenue related to an accrual in connection with a potential customer refund arising from ongoing regulatory proceedings of $15 million, partially offset by higher base rates of $21 million at Sierra Pacific. Electric retail customer volumes decreased 4.7%, primarily due to the unfavorable impact of weather, partially offset by higher customer usage.

Earnings decreased $8 million for the third quarter of 2025 compared to 2024, primarily due to lower electric utility margin of $31 million, increased operations and maintenance expense of $9 million and higher interest expense of $8 million. These items were partially offset by higher allowances for borrowed and equity funds used during construction of $21 million and a favorable income tax expense, largely from the effects of ratemaking of $10 million and higher PTCs recognized of $3 million. Electric utility margin decreased primarily due to lower retail and wholesale volumes and lower revenue related to an accrual in connection with a potential customer refund arising from ongoing regulatory proceedings, partially offset by higher base rates at Sierra Pacific. Operations and maintenance expense increased primarily due to higher technology and other costs and impacts from the 2025 regulatory rate review at Nevada Power. Interest expense increased mainly due to higher outstanding long-term debt balances.

Operating revenue decreased $587 million for the first nine months of 2025 compared to 2024, primarily due to lower electric operating revenue of $540 million and lower natural gas operating revenue of $49 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 $501 million, lower revenue related to an accrual in connection with a potential customer refund arising from ongoing regulatory proceedings of $35 million, lower customer volumes of $30 million and lower wholesale revenue of $19 million, partially offset by higher base rates of $36 million at Sierra Pacific and higher energy efficiency program rates (fully offset in operations and maintenance expense) of $9 million. Electric retail customer volumes decreased 1.8%, primarily due to the unfavorable impact of weather, partially offset by higher customer usage.

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Earnings decreased $35 million for the first nine months of 2025 compared to 2024, primarily due to lower electric utility margin of $38 million, higher operations and maintenance expense of $27 million, increased interest expense of $21 million and lower interest and dividend income of $13 million. These items were partially offset by higher allowances for borrowed and equity funds used during construction of $32 million and a favorable income tax expense, largely from the effects of ratemaking of $10 million and higher PTCs recognized of $3 million. Electric utility margin decreased primarily due to lower retail and wholesale volumes and lower revenue related to an accrual in connection with a potential customer refund arising from ongoing regulatory proceedings, partially offset by higher base rates at Sierra Pacific. Operations and maintenance expense increased primarily due to higher insurance premiums, increased general and plant maintenance costs and impacts from the 2025 regulatory rate review at Nevada Power, partially offset by lower energy efficiency program costs (fully offset in operating revenue) and lower technology and other costs. Interest expense increased mainly due to higher outstanding long-term debt balances.

Northern Powergrid

Operating revenue decreased $112 million for the third quarter of 2025 compared to 2024, primarily due to lower distribution revenue of $116 million, partially offset by $11 million from the weaker U.S. dollar. Distribution revenue decreased primarily due to lower tariff rates of $119 million driven by the impacts of inflation, partially offset by an increase in units distributed of 2.6% mainly due to higher customer usage.

Earnings decreased $111 million for the third quarter of 2025 compared to 2024, primarily due to lower distribution revenue and higher distribution-related costs of $10 million.

Operating revenue decreased $115 million for the first nine months of 2025 compared to 2024, primarily due to lower distribution revenue of $122 million and decreased non-regulated meter rental revenue of $9 million, partially offset by $24 million from the weaker U.S. dollar. Distribution revenue decreased primarily due to lower tariff rates of $118 million driven by the impacts of inflation and lower recoveries of Supplier of Last Resort payments of $12 million (largely offset in cost of sales), partially offset by an increase in units distributed of 1.4% mainly due to higher customer usage.

Earnings decreased $120 million for the first nine months of 2025 compared to 2024, primarily due to lower distribution revenue, higher income tax expense from a charge related to the March 2025 enactment of a change in the Energy Profits Levy income tax of $14 million and higher distribution-related costs of $14 million, partially offset by lower income tax expense from higher utilization of tax losses from the upstream gas exploration and production business of $10 million.

BHE Pipeline Group

Operating revenue increased $18 million for the third quarter of 2025 compared to 2024, primarily due to higher operating revenue of $27 million at BHE GT&S and higher non-regulated revenues of $8 million from additional compressor units placed in-service, partially offset by lower operating revenue of $13 million at Kern River, largely due to a decline in variable transportation revenues from lower rates and volumes. The increase in operating revenue at BHE GT&S was primarily due to increased non-regulated revenues of $15 million (largely offset in cost of sales) primarily from higher volumes, higher regulated gas transmission and storage services revenue of $8 million largely from additional capacity contracts and favorable variable revenue at Cove Point of $8 million.

Earnings decreased $41 million for the third quarter of 2025 compared to 2024, primarily due to lower earnings of $27 million at Northern Natural Gas, lower earnings of $11 million at Kern River, largely due to a decline in variable transportation revenues, and lower earnings of $6 million at BHE GT&S. The decrease at Northern Natural Gas was primarily due to higher operations and maintenance expense of $19 million, largely from increased costs for operations projects, decreased interest and dividend income of $6 million and lower margin on gas sales of $5 million from system balancing activities. The decrease at BHE GT&S was primarily due to higher interest expense of $29 million, primarily from debt issuances in January 2025 and debt refinancings in the fourth quarter of 2024 at higher interest rates, partially offset by higher regulated gas transmission and storage services revenue, favorable variable revenue at Cove Point and increased interest and dividend income of $5 million.

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Operating revenue increased $102 million for the first nine months of 2025 compared to 2024, primarily due to higher operating revenue of $105 million at BHE GT&S and higher non-regulated revenues of $25 million from additional compressor units placed in-service, partially offset by lower operating revenue of $14 million at Northern Natural Gas and $13 million at Kern River, largely due to a decline in variable transportation revenues from lower rates and volumes. The increase in operating revenue at BHE GT&S was primarily due to favorable variable revenue at Cove Point of $51 million, increased non-regulated revenues of $41 million (largely offset in cost of sales) primarily from higher volumes and higher regulated gas transmission and storage services revenue of $30 million, largely from additional capacity contracts. The decrease in operating revenue at Northern Natural Gas was primarily due to lower gas sales of $28 million from system balancing activities, partially offset by higher transportation and storage revenues of $15 million due to higher volumes and rates.

Earnings decreased $103 million for the first nine months of 2025 compared to 2024, primarily due to lower earnings of $80 million at Northern Natural Gas, lower earnings of $21 million at BHE GT&S and lower earnings of $10 million at Kern River, largely due to a decline in variable transportation revenues, partially offset by higher non-regulated earnings of $8 million from additional compressor units placed in-service. The decrease at Northern Natural Gas was primarily due to higher operations and maintenance expense of $60 million, largely from increased costs for operations projects, lower margin on gas sales of $26 million from system balancing activities, decreased interest and dividend income of $20 million and higher depreciation and amortization expense of $8 million from additional assets placed in-service, partially offset by higher transportation and storage revenues. The decrease at BHE GT&S was primarily due to higher interest expense of $85 million, primarily from debt issuances in January 2025 and debt refinancings in the fourth quarter of 2024 at higher interest rates, lower equity earnings primarily at Iroquois of $18 million and higher depreciation and amortization expense of $14 million largely from additional assets placed in-service, partially offset by favorable variable revenue at Cove Point, higher regulated gas transmission and storage services revenue and increased interest and dividend income of $22 million.

BHE Transmission

Operating revenue decreased $23 million for the third quarter of 2025 compared to 2024, primarily due to the 2024 recovery of costs from the 2023 spring wildfire and storm events of $13 million (fully offset in operations and maintenance expense) and $11 million of lower revenue from non-regulated wind-powered generating facilities from lower generation and pricing.

Earnings decreased $6 million for the third quarter of 2025 compared to 2024, primarily due to lower revenue from non-regulated wind-powered generating facilities, lower equity earnings at ETT and the impact of the AUC's approved return on equity rate decrease at AltaLink.

Operating revenue decreased $53 million for the first nine months of 2025 compared to 2024, primarily due to $28 million of lower revenue from non-regulated wind-powered generating facilities from lower generation and pricing, $14 million from the stronger U.S. dollar and the 2024 recovery of costs from the 2023 spring wildfire and storm events of $13 million (fully offset in operations and maintenance expense).

Earnings decreased $18 million for the first nine months of 2025 compared to 2024, primarily due to lower revenue from non-regulated wind-powered generating facilities, lower equity earnings at ETT, the impact of the AUC's approved return on equity rate decrease at AltaLink and $4 million from the stronger U.S. dollar.

BHE Renewables

Operating revenue decreased $106 million for the third quarter of 2025 compared to 2024, primarily due to lower electric and natural gas retail energy services revenue of $142 million from the sale of customer contracts in December 2024 and lower wind revenue of $10 million from unfavorable changes in the valuation of certain derivative contracts, partially offset by higher natural gas and geothermal revenue of $45 million from higher generation and pricing.

Earnings increased $23 million for the third quarter of 2025 compared to 2024, primarily due to higher geothermal and natural gas earnings of $29 million due to higher generation and lower maintenance costs and higher solar earnings of $21 million from lower maintenance costs, partially offset by lower wind earnings of $23 million. Wind earnings decreased due to lower earnings from owned wind projects of $15 million from unfavorable changes in the valuation of certain derivative contracts and lower PTCs and lower earnings from the wind tax equity investment portfolio of $8 million.

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Operating revenue decreased $288 million for the first nine months of 2025 compared to 2024, primarily due to lower electric and natural gas retail energy services revenue of $384 million from the sale of customer contracts in December 2024 and lower wind revenue of $9 million from lower generation, partially offset by higher natural gas and geothermal revenue of $88 million from higher generation and pricing and higher solar revenue of $20 million from higher generation.

Earnings increased $85 million for the first nine months of 2025 compared to 2024, primarily due to higher natural gas and geothermal earnings of $48 million from higher generation and pricing, partially offset by higher costs associated with a joint venture formed in May 2024, higher solar earnings of $29 million from higher generation and lower maintenance costs and higher wind earnings of $17 million. Wind earnings increased due to higher earnings from the wind tax equity investment portfolio of $39 million, primarily due to the addition of eight tax equity investments from a common control merger completed in December 2024, partially offset by lower earnings from owned wind projects of $22 million mainly due to lower PTCs.

HomeServices

Operating revenue increased $6 million for the third quarter of 2025 compared to 2024, primarily due to higher brokerage and settlement services revenue of $4 million. The increase in brokerage and settlement services revenue resulted from a 2% increase in closed brokerage volume driven by a 5% increase in average sales price.

Earnings increased $13 million for the third quarter of 2025 compared to 2024, primarily due to favorable operating expenses.

Operating revenue decreased $25 million for the first nine months of 2025 compared to 2024, primarily due to lower brokerage and settlement services revenue of $41 million, partially offset by higher mortgage revenue of $13 million. The decrease in brokerage and settlement services revenue resulted from a 5% decrease in closed brokerage units driven by the continued slowdown of overall market activity due to increased interest rates and low inventory. The increase in mortgage revenue was due to a 12% increase in funded volume driven primarily by an 8% increase in average loan size.

Earnings increased $159 million for the first nine months of 2025 compared to 2024, primarily due to an after-tax 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 and favorable operating expenses.

BHE and Other

Earnings decreased $288 million for the third quarter of 2025 compared to 2024, primarily due to the $202 million unfavorable comparative change and lower net interest and dividend income of $26 million each related to the Company's investment in BYD Company Limited, $70 million of lower federal income tax credits recognized on a consolidated basis and unfavorable consolidated income tax adjustments totaling $9 million, partially offset by lower interest expense of $14 million, largely due to lower outstanding long-term debt balances.

Earnings decreased $353 million for the first nine months of 2025 compared to 2024, primarily due to the $264 million unfavorable comparative change and lower net interest and dividend income of $84 million each related to the Company's investment in BYD Company Limited, $36 million of lower federal income tax credits recognized on a consolidated basis and unfavorable consolidated income tax adjustments totaling $36 million, partially offset by lower interest expense of $56 million, largely due to lower outstanding long-term debt balances.

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, 2024, for further discussion regarding the limitation of distributions from BHE's subsidiaries.

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As of September 30, 2025, 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			$	185					$	52					$	934					$	188					$	16					$	90					$	374					$	316					$	2,155
Credit facilities(1)			3,500						2,900						1,509						1,000						370						665						1,950						—						11,894
Less:
Short-term debt			(710)						(75)						—						—						(156)						(91)						(687)						—						(1,719)
Tax-exempt bond support and letters of credit			—						(52)						(258)						—						—						(4)						—						—						(314)
Net credit facilities			2,790						2,773						1,251						1,000						214						570						1,263						—						9,861
Total net liquidity			$	2,975					$	2,825					$	2,185					$	1,188					$	230					$	660					$	1,637					$	316					$	12,016
Credit facilities:
Maturity dates			2028						2026, 2028						2026, 2028						2028						2026						2027, 2028, 2029						2026, 2030

(1)Includes $101 million drawn on capital expenditure and other uncommitted credit facilities at Northern Powergrid.

On July 4, 2025, the One Big Beautiful Bill Act (the "OBBBA") was enacted, introducing substantial revisions to federal energy-related tax policy. Among its provisions, the OBBBA accelerates the phase-out of clean electricity production and investment tax credits and establishes new sourcing requirements applicable to facilities commencing construction after December 31, 2025. On July 7, 2025, a federal executive order (the "Executive Order") was issued directing the Secretary of the Treasury to promulgate new or revised guidance consistent with applicable law to ensure that policies concerning the "beginning of construction" requirements are not circumvented for wind and solar-powered generating facilities. In response, the U.S. Secretary of the Treasury issued partial guidance on September 2, 2025, through Notice 2025-42. While the guidance largely reaffirmed existing standards, it notably eliminated the five percent safe harbor method for establishing the beginning of construction for projects commencing construction on or after September 2, 2025. The Company is currently evaluating the potential implications of the OBBBA and Notice 2025-42 on its future financial results and will assess its impact on the viability and economics of prospective renewable energy, storage and technology neutral projects.

The Company's future financial performance and capital expenditures related to renewable energy, storage and technology neutral projects may be affected by the combined effects of the OBBBA, the Executive Order, and broader macroeconomic and geopolitical conditions, including changes in international trade policies and tariff regimes. The pace of change in these areas has accelerated during 2025, and significant uncertainty persists regarding the scope and duration of these external factors. Accordingly, the Company is unable to estimate their impact on its business at this time.

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2025 and 2024, were $7.0 billion and $6.2 billion, respectively. The increase was primarily due to changes in working capital, including lower wildfire liability settlement payments, favorable operating results, partially offset by higher cash paid for interest and lower receipts of insurance reimbursements related to wildfire liabilities.

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, 2025 and 2024, were $(7.0) billion and $(3.6) billion, respectively. The change was primarily due to higher capital expenditures of $1.3 billion, lower proceeds from sales and maturities, net of purchases of U.S. Treasury bills of $1.1 billion and lower proceeds from sales, net of purchases of marketable securities of $1.0 billion. Refer to "Future Uses of Cash" for a discussion of capital expenditures.

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Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2025, was $843 million. Sources of cash totaled $3.8 billion and consisted mainly of proceeds from subsidiary debt issuances of $3.1 billion and net proceeds from short-term debt of $587 million. Uses of cash totaled $3.0 billion and consisted mainly of repayments of BHE senior debt of $1.7 billion, repayments of subsidiary debt of $720 million preferred stock redemptions of $481 million and distributions to noncontrolling interests of $136 million.

For a discussion of recent financing transactions and BHE shareholder's equity transactions, refer to Notes 5 and 11 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, 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 of $3.4 billion, repurchases of common stock totaling $2.3 billion, repayments of subsidiary debt of $921 million and distributions to noncontrolling interests of $129 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.

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

			Nine-Month Periods												Annual
			Ended September 30,												Forecast
			2024						2025						2025
Capital expenditures by business:
PacifiCorp			$	2,157					$	2,179					$	3,051
MidAmerican Funding			1,100						1,210						1,792
NV Energy			1,274						1,996						2,654
Northern Powergrid			474						505						706
BHE Pipeline Group			713						867						1,473
BHE Transmission			181						263						373
BHE Renewables			283						407						642
HomeServices			4						6						11
BHE and Other(1)			50						94						35
Total			$	6,236					$	7,527					$	10,737

Capital expenditures by type:
Electric distribution			$	1,618					$	1,756					$	2,366
Electric transmission			1,101						1,462						1,982
Natural gas transmission and storage			559						728						1,091
Wind generation			614						625						907
Solar generation			218						415						828
Wildfire prevention			314						622						729
Electric battery storage			134						466						550
Other			1,678						1,453						2,284
Total			$	6,236					$	7,527					$	10,737

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

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

•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 investment primarily reflects costs associated with major transmission projects totaling $153 million and $376 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending for major transmission projects that are expected to be placed in‑service through 2034 totals $104 million for the remainder of 2025.

◦Nevada Utilities' Greenlink Nevada transmission expansion program. Expenditures for the expansion program and other growth projects totaled $622 million and $162 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending for the expansion program estimated to be placed in-service in 2027 through 2028 and other growth projects totals $141 million for the remainder of 2025.

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•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.

•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 $182 million and $143 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending for the construction of additional wind-powered generating facilities totals $38 million for the remainder of 2025.

◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $198 million and $169 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending for the repowering of wind-powered generating facilities totals $186 million for the remainder of 2025. 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 $165 million and $249 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending for the construction of additional wind‑powered generating facilities and those at acquired sites totals $35 million for the remainder of 2025 and is primarily for the Rock Creek I and Rock Creek II wind‑powered generating facilities totaling approximately 529 MWs that are expected to be placed in‑service in 2025.

◦Repowering of wind-powered generating facilities at BHE Renewables totaling $5 million for the nine-month period ended September 30, 2024. Repowered facilities were placed in-service in the first quarter of 2024 and meet IRS guidelines for the re-establishment of PTCs for 10 years.

•Solar generation and electric battery storage include growth expenditures, including spending for the following:

◦Construction and operation of solar-powered generating facilities at MidAmerican Energy totaling $9 million and $1 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending totals $4 million for the remainder of 2025.

◦Construction of solar-powered generating facilities and co-located battery storage at the Nevada Utilities. Spending for the solar-powered generating facilities totaled $271 million and $114 million, respectively, while spending for the co-located battery storage totaled $378 million and $98 million, respectively, for the nine-month periods ended September 30, 2025 and 2024. Planned spending for the solar-powered generating facility and co-located battery storage total $205 million and $39 million, respectively, for the remainder of 2025. 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 MWs of co-located battery storage that is being 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 facility is expected by early 2027 and commercial operation of the co-located battery storage is expected by mid-2026.

◦Construction of solar-powered generating facilities and co-located battery storage at BHE Renewables. Spending for the solar-powered generating facilities totaled $40 million and $101 million, respectively, while spending for the co-located battery storage totaled $46 million and $34 million, respectively, for the nine-month periods ended September 30, 2025 and 2024. Planned spending for the solar-powered generating facilities and co-located battery storage total $56 million and $25 million, respectively, for the remainder of 2025. Construction includes expenditures for a 48-MW solar photovoltaic facility with an additional 46 MWs of co-located battery storage that will be developed in Kern County, California, with commercial operation expected in 2026 and a 106-MW solar photovoltaic facility with an additional 50 MWs of co-located battery storage located in Jackson County, West Virginia, with commercial operation being completed in three phases between 2026 and 2027.

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

◦Expenditures at PacifiCorp totaling $591 million and $264 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending for wildfire prevention totals $98 million for the remainder of 2025, and is comprised of reducing wildfire risk in the 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 $24 million and $33 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending for wildfire prevention totals $8 million for the remainder of 2025, 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, 2025, 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, 2024, other than those disclosed in Notes 5 and 9 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, 2024, and new regulatory matters occurring in 2025.

PacifiCorp

Utah

In May 2024, PacifiCorp filed its EBA application to recover deferred net power costs from 2023. In June 2024, the UPSC approved an interim rate increase of $256 million, or 11.6%, effective July 1, 2024, allowing for recovery of $432 million of deferred net power costs. In February 2025, the UPSC issued a final order reducing the total final EBA recovery by $24 million, primarily for costs related to the Washington Cap and Invest program. The reductions from the final order were reflected in the 2024 EBA filing made in May 2025. In March 2025, PacifiCorp filed a request for review or rehearing regarding the disallowed costs that was denied by the UPSC in April 2025. After the UPSC denied the rehearing, PacifiCorp filed for review with the Utah Supreme Court.

In June 2024, PacifiCorp filed a general rate case requesting a rate increase over two years that included increased net power 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 November and December 2024, PacifiCorp filed updated testimony that further revised the requested rate increase to $330 million, or 14.0%. In April 2025, the UPSC issued a final order approving a rate increase of $87 million, or 3.7%, effective April 25, 2025. Most significantly, the final order substantially limited PacifiCorp's recovery of costs associated with insurance premiums, lowered PacifiCorp's authorized return on equity and equity component of its capital structure, reduced forecast base net power costs, substantially limited recovery for amounts previously deferred under the wildland fire mitigation balancing account and disallowed recovery of Utah's share of PacifiCorp's investment in certain assets on the Klamath River hydroelectric system. In May 2025, PacifiCorp filed a request for rehearing that the UPSC denied in June 2025, except for a partial reconsideration of a mathematical error that granted an additional $7 million related to excess liability insurance premiums. PacifiCorp has filed for review of these decisions with the Utah Supreme Court.

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In May 2025, PacifiCorp filed its EBA application to recover deferred net power costs from 2024. The filing requests recovery of $472 million of deferred net power costs, effective on an interim basis July 1, 2025. The request would result in a rate increase of $40 million, or 1.6%. In June 2025, the UPSC approved the interim rate change, effective July 1, 2025.

Oregon

In February 2025, PacifiCorp filed an application for reconsideration or rehearing with the OPUC regarding the level of recovery provided for Oregon's share of wildfire mitigation investments and PacifiCorp's return on investment in its 416-mile, 500-kV high voltage transmission line set forth in the December 2024 general rate case order. In April 2025, the OPUC denied reconsideration, and PacifiCorp is pursuing review of this decision with the Oregon Court of Appeals.

In April 2025, PacifiCorp filed a renewable adjustment clause application with the OPUC to recover the full costs of certain wind‑powered generating facilities and associated transmission lines that are being only partially recovered as a result of the December 2024 general rate case order or that were placed into service subsequent to the rate effective date of the last general rate case. The application seeks a rate increase of $51 million, or 2.5%, effective January 1, 2026.

In August 2025, PacifiCorp filed an application to defer the costs of certain wind‑powered generating facilities and associated transmission lines not already in rates as of August 15, 2025 through December 31, 2025, when these projects would be included in rates through the renewable adjustment clause.

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. In November 2023, the WPSC approved a rate increase of $54 million, or 8.3%, effective January 1, 2024. In January 2024, PacifiCorp filed an application for rehearing requesting the WPSC consider three items, including the WPSC's adjustment to net power costs related to third-party wholesale reserves, 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. PacifiCorp is pursuing review of this decision in federal and Wyoming state courts. In September 2025, the U.S. District Court for the District of Wyoming granted PacifiCorp's motion for summary judgment ruling that the WPSC's net power costs adjustment intruded on the FERC's jurisdiction over third-party wholesale reserves. The WPSC and another intervening party have appealed the decision to the Tenth Circuit Court of Appeals.

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 ECAM. In January 2025, PacifiCorp filed updated testimony that reduced the requested rate increase to $110 million, or 13.1%. In March 2025, a multi‑party settlement stipulation was filed that requested a rate increase of $86 million, or 10.2%. In April 2025, the WPSC approved the stipulation as filed, with rates effective June 1, 2025.

In April 2025, PacifiCorp filed its ECAM and renewable revenue adjustment mechanism to recover deferred net power costs from 2024. The combined filing requests a rate decrease of $47 million, or 5.8%, to be effective on an interim basis on July 1, 2025. In June 2025, the WPSC approved the interim rate change, effective July 1, 2025.

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 March 2024, the WUTC accepted the multi-party settlement stipulation for which the first-year rate increase went into effect April 3, 2024. In March 2025, PacifiCorp submitted a compliance filing for the second year of the two-year rate plan, resulting in a rate increase of $16 million, or 3.8%, effective April 3, 2025. The compliance filing included updated net power cost forecasts that resulted in a $5 million decrease to the stipulated second year increase. In April 2025, the WUTC approved the second year increase as filed, effective April 3, 2025.

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As part of the stipulation in the above two-year general rate case, PacifiCorp agreed to file a review and potential refund of provisional capital not placed in-service. After the determination of any refund under the capital review process, PacifiCorp's restated actual rate of return will be compared against the authorized rate of return to determine if any deferral is necessary under Washington's multiyear rate plan legislation. In July 2024, PacifiCorp submitted a provisional capital report for calendar year 2023. During review of the provisional capital report in February 2025, the WUTC ordered a refund of $64,000 related to specific wind‑powered generating facilities.

In April 2025, PacifiCorp filed a power cost only rate case, as directed by the WUTC in the 2023 general rate case, to reset the baseline net power costs to remove coal-fueled resources from rates under the Washington 2026 Protocol also proposed in the filing. The filing requests a $34 million, or 7.9%, rate increase effective January 1, 2026. In September 2025, PacifiCorp submitted rebuttal testimony which reflected a lower proposed rate increase of $12 million, or 2.8%. The update is primarily due to Washington Engrossed House Bill 1329, enacted into law in May 2025, that updated types of wholesale power purchases allowed by electric utilities under Washington's Clean Energy Transformation Act.

In June 2025, PacifiCorp filed its power cost adjustment mechanism requesting recovery of deferred net power costs from 2024. The filing requests a rate increase of $56 million, or 10.0%, effective October 1, 2025. In September 2025, the WUTC approved recovery of $57 million, with an updated effective date of February 1, 2026, for most customer classes. Since the 2024 PCAM effective date coincides with the expiration of the larger 2023 PCAM surcharge, customers will experience an overall decrease in rates.

Idaho

In March 2025, PacifiCorp filed its ECAM to recover deferred net power costs from 2024. The filing requested a rate increase of $8 million, or 2.2%, effective June 1, 2025, that the IPUC approved in May 2025. The filing excluded costs associated with the Washington Cap and Invest program, for which PacifiCorp filed a deferral application in March 2025, for $2 million in costs incurred in 2024, since recovery of such costs under the 2023 ECAM filing are under appeal in the Idaho Supreme Court. In June 2025, the IPUC approved PacifiCorp's request for deferral of the 2024 costs associated with the Washington Cap and Invest program.

California

In May 2022, PacifiCorp filed a general rate case requesting an overall rate change to become effective January 1, 2023. In November 2022, the CPUC granted the requested rate effective date and directed PacifiCorp to establish a memorandum account to track the change in rates beginning January 1, 2023, until the new rates become effective. In February 2023, the CPUC issued a ruling requesting additional information on PacifiCorp's wildfire and risk analyses and requested additional information regarding wildfire memorandum accounts and in March 2023, the CPUC split the general rate case into two tracks. The first track addressed the general rate case and the second track addresses the wildfire memorandum accounts. In December 2023, the CPUC issued an order for the first track approving a rate increase effective January 12, 2024 and recovery of the aforementioned memorandum account over three years. In the second track of the general rate case, PacifiCorp filed the independent audit of the wildfire memorandum accounts in January 2024, indicating no findings. In January 2025, the CPUC issued a proposed decision authorizing PacifiCorp to recover $36 million related to historic wildfire mitigation costs. In February 2025, the CPUC issued a final decision authorizing PacifiCorp to recover these costs over six years, effective April 15, 2025.

In September 2024, PacifiCorp filed to recover costs associated with an event that occurred in 2023 recorded in the catastrophic events memorandum account requesting recovery of $30 million over a two-year period, resulting in an annual rate increase of $15 million, or 10.2%, effective March 1, 2025. In August 2025, parties filed a motion for the CPUC to adopt a joint settlement agreement for $29 million amortized over three years. PacifiCorp anticipates a proposed decision from the CPUC in the fourth quarter of 2025.

In June 2025, the CPUC issued a proposed administrative enforcement order against PacifiCorp for its 2020 wildfire mitigation plan compliance. The order alleges that PacifiCorp did not meet targets in the approved wildfire mitigation plan and did not provide sufficient data to support PacifiCorp's compliance or corrective actions. The order proposes a $27 million penalty. In July 2025, PacifiCorp filed a request for hearing which will take place in May 2026.

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FERC

PacifiCorp's wholesale transmission rates are set annually using formula rates approved by the FERC and are updated annually. In May 2024, PacifiCorp published the 2024 annual update of its transmission formula rate in the FERC Docket No. ER24-2004-000 pursuant to its formula rate implementation protocols. The 2024 formula rate update included the impacts of approximately $1,677 million of accrued losses, net of expected insurance recoveries associated with the Wildfires recognized during the year ended December 31, 2023, among other adjustments. Pursuant to the formula rate implementation protocols, PacifiCorp transmission customers are permitted to lodge "preliminary challenges" to the formula rate updates, which provides an informal basis upon which PacifiCorp and the transmission customers may exchange certain information and engage in discussions in order to provide further context to the rates resulting from the updates. Transmission customers are ultimately permitted to lodge "formal challenges" to the formula rate update with the FERC in the event preliminary discussions are not fruitful or do not resolve outstanding issues, and the FERC has an established process to resolve formal challenges. In June 2025, several PacifiCorp transmission customers filed such formal challenges with the FERC, largely seeking to disallow PacifiCorp's recovery of the portion of losses associated with the Wildfires allocable to transmission customers through the formula rate and other, less substantive expenses. In August 2025, PacifiCorp filed a response and procedural motion with the FERC to dismiss the formal challenges on the basis that the formal challenges lack merit and do not support finding that PacifiCorp's Wildfires losses were imprudently incurred. In September 2025, those transmission customers who filed the formal challenges filed responses to PacifiCorp's filing. In October 2025, PacifiCorp filed an additional response with the FERC. PacifiCorp will continue to utilize the FERC-established process to resolve all outstanding issues related to its 2024 annual update.

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. In September 2025, the CPUC approved the request to track these costs.

In August 2023, PacifiCorp filed a deferral applications with the WUTC for costs associated with increased insurance premium costs associated with third-party liability coverage. In September 2025, the WUTC approved the request to defer these costs.

2026 PacifiCorp Inter-Jurisdictional Allocation Protocol

In August, PacifiCorp filed applications with the UPSC, the OPUC, the WPSC and the IPUC for approval of PacifiCorp's 2026 Inter-Jurisdictional Cost Allocation Protocol ("2026 Protocol"). The 2026 Protocol is intended to supersede the 2020 PacifiCorp Inter-Jurisdictional Allocation Protocol for Utah, Oregon, Wyoming, Idaho and California, and align with the changes proposed in the Washington 2026 Protocol, filed with the April 2025 power cost only rate case. This filing is the first phase in a multi-phased process to transition PacifiCorp's cost-allocation methodology to accommodate diverging resource portfolios and changes to operations needed to address individual state energy policies. If approved, the 2026 Protocol will be effective for new regulatory filings beginning January 1, 2026. The CPUC will consider the 2026 Protocol as part of PacifiCorp's next general rate case filed in California.

MidAmerican Energy

2025 Solar Reliability Project

In February 2025, MidAmerican Energy filed an application with the IUC for advance ratemaking principles for MidAmerican Energy's 2025 Solar Reliability Project. The application asks the IUC to approve installation of up to 800 MWs of new solar generation in Iowa to meet capacity needs driven by load growth and regional capacity requirements. In July 2025, MidAmerican Energy filed a unanimous settlement with all parties. On September 11, 2025, the IUC issued its final order, approving the unanimous settlement without modification. MidAmerican Energy accepted the ratemaking principles on September 12, 2025, and expects to begin construction in 2025 and place the project's facilities in-service through 2027 and 2028.

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Iowa Transmission Legislation

In 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.

In May 2024, while the appeal was pending, MISO initiated 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. In August 2024, MISO announced the outcome of its variance analysis, which implemented a mitigation plan 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 affirmed that, pursuant to its tariff, MidAmerican Energy and ITC Midwest remain obligated to construct the projects assigned to each company.

The Iowa Supreme Court held oral arguments in the appeal on April 16, 2025. On May 30, 2025, the Iowa Supreme Court issued its opinion. The Iowa Supreme Court held that the district court's injunction properly restricted the parties from taking any additional action, or relying on prior actions, related to any and all electric transmission line projects in Iowa that were claimed pursuant to, under or in reliance on Iowa's ROFR law. However, the Iowa Supreme Court advised that any relief related to the application of the MISO tariff or the assignment of projects under MISO's variance analysis should be sought from the FERC.

Following the Iowa Supreme Court's opinion, the IUC requested additional briefing in a docket involving an LRTP Tranche 1 project to be constructed by ITC Midwest. The IUC advised that it needed to address "existing barriers to resolution of this and other proposed transmission projects," noting that the Iowa Supreme Court "provided acute clarity with respect to Iowa law and how the Commission should act, or not act, in regard to projects tainted by ROFR" but left unresolved "the impact of federal determinations on these proceedings." MidAmerican Energy filed comments that support the right to proceed with projects assigned under MISO's variance analysis and mitigation plan. At a July 22, 2025 hearing in the ITC Midwest docket, the IUC held that the variance analysis and mitigation plan allowed the project to proceed and encouraged any party that disagreed to "seek appropriate relief from MISO or FERC". No party has taken any action to contest this bench ruling but may still appeal after the IUC issues a final order in ITC Midwest's docket. In the meantime, MidAmerican Energy continues to progress with a franchise petition for its first LRTP Tranche 1 project, consistent with the position taken in ITC Midwest's docket.

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.

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NV Energy (Nevada Power and Sierra Pacific)

Regulatory Rate Review

In February 2025, Nevada Power filed an electric regulatory rate review with the PUCN that requested an annual revenue increase of $215 million, or 9.0%. Nevada Power filed its certification filing in April 2025 that updated the requested annual revenue increase to $224 million, or 9.4%. In May 2025, a settlement was reached in the cost of capital phase, resulting in the return on equity remaining at 9.5% and the capital structure as well as the cost of debt being approved as filed. Hearings for the revenue requirement and rate design phases were held in July 2025. In September 2025, the PUCN issued an order approving an increase in the revenue requirement of $118 million, which includes 50% of construction work in progress in rate base for the Greenlink project, with rates effective October 1, 2025. In October, 2025. Nevada Power filed a petition for reconsideration and clarification of the order. The petition for reconsideration is still pending a PUCN order.

Wildfire Self-Insurance Policy Filing

In January 2025, the Nevada Utilities filed applications for approval of the establishment and associated cost recovery of a Wildfire Self-Insurance Policy. The applications request that the PUCN issue an order determining that it is reasonable and prudent for the Nevada Utilities to establish a $500 million wildfire self-insurance policy (the "Policy") in order to have additional wildfire liability insurance in place in the event that a catastrophic wildfire in Nevada is alleged to be caused or exacerbated by the utilities equipment. The Policy would provide $500 million in additional coverage for the Nevada Utilities for third-party claims, and it would be in excess to the commercial wildfire liability insurance the Nevada Utilities possess. In addition, the applications request approval to collect the costs for the Policy in rates over a ten-year period. Hearings before the Commission concluded in June 2025. In July 2025, the PUCN issued an order that approved the application in part and denied the application in part. The PUCN found that the Nevada Utilities need additional wildfire liability insurance in an amount of at least $500 million. However, the PUCN also determined that additional information is necessary to assess whether the self-insurance policy proposed by the Nevada Utilities is prudent under the circumstances and reasonable considering other options, if any. The Nevada Utilities filed the additional information requested by the PUCN in October 2025. The PUCN will schedule additional proceedings to assess the prudency of self-insurance.

BHE Pipeline Group

Northern Natural Gas

In July 2025, Northern Natural Gas filed a general rate case that proposed an overall annual cost-of-service of $1.6 billion. This is an increase of $286 million above the cost-of-service filed in its 2022 rate case of $1.3 billion, largely due to higher depreciation expense and return allowance of $165 million from increased rate base and an increase in depreciation and negative salvage rates, and increased operations and maintenance expenses of $96 million. Northern Natural Gas requested increases in various rates, including transportation reservation rates ranging from 85% in the Market Area to 130% in the Field Area to be implemented, subject to refund, on August 1, 2025. In July 2025, the FERC issued an order that suspended the rates proposed for five months following the proposed effective date, until January 1, 2026, subject to refund and the outcome of hearing procedures.

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BHE Transmission

AltaLink

In May 2025, AltaLink filed its 2026-2027 General Tariff Application and 2023-2024 Deferral Accounts Reconciliation Application with the AUC. In August 2025, AltaLink advised the AUC that it reached a negotiated settlement with customer groups for substantially all its 2026-2027 GTA revenue and the entirety of the 2023-2024 Deferral Accounts Reconciliation Application. AltaLink filed its revised GTA reflecting the terms of the negotiated settlement agreement with total amended revenue requirements of C$919 million and C$960 million for 2026 and 2027, respectively. Under the agreement, AltaLink reduced its applied-for operating expenses by C$4 million and sustaining capital expenditures by C$67 million for the 2026-2027 test period. The agreement does not include, among other items, AltaLink's 2026-2027 Wildfire Mitigation Plan and the execution and costs of the 2024-2025 Wildfire Mitigation Plan, insurance premiums, depreciation on certain asset classes, the regulatory accounting and income tax treatment of certain costs, the proposal of two deferral accounts, and compliance with prior commission decisions. These items will be heard in an AUC hearing in November 2025, with a decision expected in the first quarter of 2026. In September 2025, the AUC approved the negotiated settlement agreement. The AUC will issue the reasons for its approval at a later date. The approved negotiated settlement marks AltaLink's fourth successful negotiated settlement over the past decade, and it secures revenue for AltaLink to balance safety, reliability and affordability for customers.

BHE U.S. Transmission

In January 2025, ETT filed a request with the Public Utilities Commission of Texas ("PUCT") for a $57 million annual base rate increase over its adjusted test year revenues which includes interim transmission rate updates. The rate case sought a prudence review determination on cumulative capital additions included in interim rates since the initial base regulatory review in 2007. In June 2025, ETT filed a unanimous and unopposed settlement with the PUCT with a base rate increase of approximately $20 million. The settlement also included a determination that ETT's invested capital and rate base are prudent and properly included in rates. A motion to approve interim rates was granted in June 2025. In October 2025, the PUCT issued an order approving the June 2025 settlement. The rates approved by the order are identical to the rates approved on an interim basis.

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, 2024, and new environmental matters occurring in 2025.

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Environmental Deregulation

On March 12, 2025, the EPA announced a significant deregulatory effort focused on climate change and measures that impact the energy sector. At the core of the deregulatory effort is the plan to reconsider the EPA's 2009 endangerment finding on greenhouse gases. That finding gives the EPA its authority to regulate greenhouse gas emissions by finding they threaten public health. Because the endangerment finding underpins most climate rules, rewriting the scientific finding can streamline the process of undoing those rules for power plants, motor vehicles and other sectors. In addition to the endangerment finding, the EPA announced it will review the following rules and policies relevant to the Registrants: greenhouse gas standards for power plants; methane standards for the oil and natural gas sector; greenhouse gas reporting rule; mercury and air toxics standards; steam electric effluent limitation guidelines; oil and natural gas effluent limitation guidelines; risk management program; hydrofluorocarbon phase-out rule; National Ambient Air Quality Standards for fine particulate matter; regional haze program; state and tribe implementation plans for a variety of air quality rules; exceptional events policy; coal combustion residuals rule; and the definition of waters of the U.S. The EPA has taken the following actions to implement the announcement:

•The EPA quickly issued guidance narrowing the definition of when a wetland has a "continuous surface connection" to a "water of the United States" and is thus jurisdictional. The guidance aligns with the EPA's view of the U.S. Supreme Court's Sackett et ux. v. Environmental Protection Agency et al. decision and supports plans to revise the definitional rule. The EPA said it will pursue a definition that is simple and durable and withstands the test of time. The rulemaking will be the fourth major rewrite of the definition in the last 10 years.

•On June 11, 2025, the EPA issued a proposal to rescind the 2024 rules establishing greenhouse gas emissions limits for existing coal-fueled power plants and new natural gas-fueled power plants. The rule contains two co-proposals: The lead proposal would exclude the power sector from Clean Air Act regulation for greenhouse gas emissions on the grounds that the sector does not significantly contribute to dangerous air pollution; the secondary proposal would eliminate the carbon capture and sequestration-based standards and other requirements from the 2024 rules. The effect of the secondary proposal for new natural gas-fueled plants is to leave in place the efficiency-based Phase 1 standards while removing the carbon capture and sequestration-based Phase 2 standards. For existing coal-fueled plants, the removal of carbon capture and sequestration-based and natural gas co-firing-based requirements means that no greenhouse gas emissions requirements would be in place. The proposed rescission could affect facilities at BHE Renewables, MidAmerican Energy, NV Energy and PacifiCorp. The EPA accepted comments on the proposal through August 7, 2025. Until the rulemaking process is complete and litigation exhausted, full impacts to the affected Registrants cannot be determined.

•On June 11, 2025, the EPA issued a proposal to repeal the 2024 amendments to the Mercury and Air Toxics Standards, specifically addressing the residual risk and technology review that informed the amendments. The repeal includes the filterable particulate matter emission standard as a surrogate for non-mercury hazardous air pollutants; the requirement to use continuous emission monitoring systems for measuring and reporting particulate matter emissions; and the mercury emissions standard for existing lignite-fueled electric generating units. The rescission of the first two limits would affect facilities at MidAmerican Energy and PacifiCorp. The EPA accepted comments on the proposal through August 11, 2025. Until the rulemaking process is complete and litigation exhausted, full impacts to the affected Registrants cannot be determined.

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•The EPA finalized its approval of West Virginia's second planning period regional haze plan, setting a precedent for other states seeking to meet haze reduction goals for 156 national parks and wilderness areas using a more gradual reduction timeline, which often means new pollution control requirements are not necessary. The EPA's approval hinges on a reframing of what states need to do to make reasonable progress toward the objective of restoring natural visibility to those lands by 2064. If states meet what is known as the "uniform rate of progress" on the way to that target, they would be deemed in compliance. The EPA believes that the policy meshes with the purpose of regional haze program regulations to achieve reasonable progress towards Congress' natural visibility goal. Several states have regional haze implementation plans pending with the EPA that are expected to be impacted by this policy which are relevant to the relevant Registrants, including Texas, Arizona, Utah, Wyoming and Nevada. Based on the uniform rate of progress policy, the EPA proposed to approve Texas' SIP for the second planning period in May 2025 and accepted comments through July 23, 2025. The EPA partially disapproved SIPs for Arizona, Utah and Wyoming in December 2024. Wyoming and PacifiCorp filed petitions for reconsideration in January 2025 and remain in coordination with the EPA. PacifiCorp filed a petition for reconsideration of the Utah plan denial in January 2025 and remains in coordination with Utah and the EPA. On April 30, 2025, the EPA granted PacifiCorp's petition for reconsideration on its disapproval of the Utah Regional Haze SIP for the second planning period, as well as PacifiCorp's and Wyoming's petitions for reconsideration on the EPA's disapproval of the second planning period Wyoming Regional Haze SIP. On August 7, 2025, the EPA finalized approval of Wyoming's revision of its first planning period regional haze implementation plan for Jim Bridger Units 1 and 2. On January 30, 2014, the EPA disapproved Wyoming's first planning period regional haze SIP for Dave Johnston Unit 3 and imposed a federal plan that effectively required Unit 3 to shut down by the end of 2027. On September 25, 2025, PacifiCorp and Wyoming filed petitions for reconsideration, requesting that the EPA reconsider the specific part of the SIP disapproval that resulted in the federal plan shutdown requirement. PacifiCorp and Wyoming remain in coordination with the EPA. Both the Utah and Wyoming plan denials were also petitioned to the Tenth Circuit Court of Appeals; the suits are abated while the EPA reviews those underlying decisions.

•On July 17, 2025, the EPA issued a direct final rule and companion proposal that would extend the compliance deadlines for coal combustion residual management units set forth in the legacy CCR rule. The rule would (1) establish an additional option that will allow the phase one and phase two facility evaluation reports to be prepared concurrently so long as both reports are submitted no later than February 8, 2027; (2) extend by 15 months the deadline for CCR management units to comply with the groundwater monitoring provisions, which would make the new compliance deadline August 8, 2029; and (3) make conforming changes to the remaining CCR management unit deadlines that will be impacted by the extended facility evaluation report deadline, including the deadlines to install the groundwater monitoring system, develop the groundwater monitoring sampling and analysis program, initiate detection monitoring and assessment monitoring, complete the initial annual report, prepare written closure and post-closure plans and initiate closure. The EPA will accept comments on the direct final rule and co-proposal through September 15, 2025. Because the package was issued as a direct final rule and a co-proposal, any specific provision that does not receive adverse comment will automatically take effect six months following the end of the 30-day comment period. However, adverse comments were submitted, so the direct final rule will be withdrawn and the EPA will proceed to consider that change under the co-proposal. The EPA anticipates finalizing the CCRMU Deadline Extension Rule by December 15, 2025. Until the rulemaking process is complete and litigation exhausted, full impacts to the affected Registrants cannot be determined.

•On July 29, 2025, the EPA extended several compliance deadlines for the 2024 methane regulation, which covers new and modified oil and gas facilities, including transmission and storage assets. The interim rule was effective immediately. Most compliance deadlines for newly regulated sources, including equipment leaks, tank controls, pneumatic controllers, and super-emitter programs, have been extended by 18 months. Monitoring requirements for flares and enclosed combustion have a shorter, 120-day extension. States were given an additional 10 months to submit plans, now due November 9, 2026. The extension rule provides short-term operational relief for the Registrant BHE Pipeline Group, with additional time to plan and implement compliance measures for new and modified sources affected by the rule. However, the extension rule does not alter the substance of obligations under the methane rule. Additional rulemaking to address the substantive elements of the rule is anticipated in 2026.

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•On July 29, 2025, the EPA released a proposed rule titled "Reconsideration of 2009 Endangerment Finding and Greenhouse Gas Vehicle Standards." This proposal would repeal the EPA's 2009 Endangerment Finding, a determination that greenhouse gas emissions qualify as air pollution that endangers human health or the environment. The proposed rescission offers several differing and potentially exclusive approaches to reach a new conclusion. The lead proposal would find that Clean Air Act section 202(a) (the section that authorizes regulation of motor vehicle emissions) does not authorize the EPA to prescribe emission standards based on global climate change concerns. The first alternative proposal would repeal the Endangerment Finding by casting doubt on the underlying record and scientific evidence. A second alternative proposal would not withdraw or repeal the Endangerment Finding but instead would reopen the standards the EPA established in 2024 for greenhouse gas emissions from light, medium, and heavy-duty motor vehicles and would find that there are no requisite emissions control technologies for motor vehicle greenhouse emissions that would meaningfully address global climate change without imposing a greater public health burden by presumed economic loss. Depending on which version of the proposal the EPA chooses to finalize, a primary effect could be to remove the legal basis for Clean Air Act regulation of greenhouse gas emissions for power plants and the natural gas pipeline sector. Specifically, if the EPA finalizes either of the first two alternatives, it may no longer have the necessary predicate to consider greenhouse gas emissions a regulated pollutant for purposes of New Source Performance Standards under CAA section 111 or for New Source Review permitting, based on the scope of the authority the EPA is claiming to repeal. The EPA accepted public comments on the proposal through September 22, 2025. A final decision will likely be challenged in the D.C. Circuit and is expected to land at the U.S. Supreme Court for final adjudication. The legal process could take several years, with significant uncertainty in the short term. Until the rulemaking process is complete and litigation has been exhausted, impacts on the relevant Registrants cannot be determined.

•On September 12, 2025, the EPA issued a proposed rule to rescind its greenhouse gas reporting requirements for nearly all industrial sectors currently subject to its Greenhouse Gas Reporting Program and to suspend until 2034 most oil and gas sector rules, while also repealing mandates for gas distribution operations. If finalized, the proposal would remove reporting obligations for most large facilities; all fuel and industrial gas suppliers; and carbon dioxide injection sites. The agency said that no sector would need to submit reports with 2025 data. However, the proposal would extend the March 31, 2026, deadline for such reports until June 10, 2026, which would "allow the EPA time to issue a final rule prior to the regulatory deadline for reporting year 2025." While power plants would no longer be subject to reporting emissions under the greenhouse gas reporting program, Section 821 of the Clean Air Act Amendments of 1990 established a separate statutory requirement that sources subject to the Title IV Acid Rain Program, principally power plants, must monitor and report carbon dioxide. That obligation is carried out through separate regulations that are not affected by the current proposal. Until the rulemaking process is complete and litigation has been exhausted, impacts on the relevant Registrants cannot be determined.

•On September 29, 2025, the EPA issued a proposed and direct final rule that would extend deadlines for coal-fueled power plants to comply with its Effluent Limitations Guidelines and Standards rule that was finalized in April 2024. The rule has been challenged in court, but the case was put on hold in August 2025 so the EPA could reconsider the rule. The direct final rule would give coal-fueled plants an additional six years, until 2032, to assess compliance pathways, as well as an additional five years, until 2035, to comply with several discharge limits. The proposed rule covers a broader set of topics, including proposals to extend compliance deadlines for the zero-discharge requirements in the 2024 rule and to revise provisions to authorize permitting authorities to exercise site-specific discretion in extending deadlines in response to unforeseen demand. The EPA will accept comments on the direct final rule and proposed rule through November 3, 2025. If no adverse comments are received, the direct final rule extending compliance deadlines will take effect December 1, 2025. If adverse comments are received, the direct final rule will not take effect, and the EPA will consider compliance extensions via the companion proposed rule and comment process. PacifiCorp's Dave Johnston Plant is currently operating under a notice of plan participation, submitted in 2021, which committed to permanent cessation of coal combustion at Dave Johnston Units 1, 2 and 3 by December 31, 2028. The proposed rule presents the opportunity to opt out of the subcategory presented in a notice of plan participation and obtain an alternative applicability date to continue burning coal based on changed circumstances. PacifiCorp is evaluating the proposed rule and changed circumstances for applicability to the Dave Johnston Plant. Until the rulemaking process is complete and litigation has been exhausted, impacts on the relevant Registrants cannot be determined.

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Air Quality Regulations

Cross-State Air Pollution Rule

On June 18, 2025, the U.S. Supreme Court issued a unanimous decision in favor of Utah and PacifiCorp in the ozone transport case titled Oklahoma v. U.S. Environmental Protection Agency, in which the state and company were parties. The case addressed the proper court venue for the EPA's disapproval of Oklahoma and Utah state ozone transport plans. The court's ruling provides needed clarity and confirms that while SIPs require a careful balance of federal and state collaboration, the Clean Air Act clearly directs that regional courts are the proper court venue for disagreements over the details of those plans. By recognizing that state plans are "undisputedly locally or regionally applicable actions," the court preserved important legal rights for states to have disagreements over their plans heard in the appropriate regional federal circuit court. This enables regional court consideration of the plans and arguments rather than grouping multiple state plans under a national review in the D.C. Circuit. The cases have been transferred back to the Tenth Circuit Court of Appeals, the regional court where they were originally filed. The Tenth Circuit Court of Appeals agreed to abate further litigation while the EPA reconsiders both its earlier disapproval of the state plans and the federal plan it promulgated. To date, the EPA has not taken action on either the state or federal plans.

Regional Haze

On August 5, 2025, the EPA approved Iowa's SIP for the regional haze second planning period. The state's plan requires operational improvements to existing control equipment at MidAmerican Energy's Louisa Generation Station and Walter Scott Jr. Energy Center Unit 3. These improvements were permitted by the Iowa Department of Natural Resources and implemented by MidAmerican prior to EPA's approval of the plan.

On September 29, 2025, the EPA issued an advanced notice of proposed rulemaking to solicit information from the public to help develop regulatory changes on the implementation and structure of the Clean Air Act's Regional Haze Rule. The advanced notice does not impose any requirements, but requests input about how the agency can revise the regional haze rule to streamline regulatory requirements impacting states' visibility improvement obligations. The advanced notice requests information regarding (1) development and use of a reasonable progress metric and consideration of the four statutory reasonable progress factors state regulators must take into account when deciding whether to impose further pollution controls on sources such as coal plants; (2) development of SIP obligation criteria used to determine when a plan revision is required; and (3) determining SIP requirements for states that are required to submit plan revisions. As part of these deliberations, the EPA will also consider whether to keep or extend the existing deadline of 2064 for states to attain natural visibility conditions in their Class I areas – national parks and wilderness areas. The EPA will accept comments on the advance notice through December 1, 2025. Until the rulemaking process is complete and litigation has been exhausted, impacts on the relevant Registrants cannot be determined.

Coal Combustion Residuals

On August 28, 2025, the EPA proposed to approve Wyoming's coal combustion residuals permit program. A final determination is expected in early 2026. If finalized as proposed, the state will have authority to manage disposal of coal combustion residuals in surface impoundments and landfills in Wyoming, replacing the current federal self-implementing program and bringing PacifiCorp coal ash units at Jim Bridger, Dave Johnston and Naughton under the state program. The pending approval excludes provisions related to legacy CCR units, suspension of groundwater monitoring and alternate groundwater protection standards for constituents without maximum contaminant levels. As a result, facilities must comply with both Wyoming's rules and applicable federal requirements for these excluded provisions. PacifiCorp will submit comments in support of EPA's proposed approval of the state of Wyoming's Coal Combustion Residuals permit program by the November 3, 2025, deadline.

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Mandatory Climate Change Disclosures

In October 2023, California enacted three climate-related disclosure laws. Because Berkshire Hathaway Energy does business in California and exceeds certain applicability thresholds, it is subject to all three laws. Reporting under all three statutes covers Berkshire Hathaway Energy's global operations, including operating companies that otherwise do not do business in California. Under California's Voluntary Market Disclosure Act, authorized by Assembly Bill 1305, companies must make certain disclosures if they make claims in California regarding greenhouse gas emissions reductions or if they market, sell, purchase or use voluntary carbon offsets. Berkshire Hathaway Energy posted its disclosure on December 31, 2024 on its company website, with the required information concerning its greenhouse gas emissions reduction goals. Berkshire Hathaway Energy is preparing consolidated disclosures of its scopes 1 and 2 greenhouse gas emissions and the financial risks of climate change to the business. Under California's Corporate Greenhouse Gas Reporting Program, authorized by Senate Bill 253, as amended, Scope 1 and Scope 2 emissions must be reported to California beginning in 2026. While a reporting timeline has not been finalized, the Company anticipates a compliance deadline of June 30, 2026. Scope 3 emissions are not required to be reported until 2027. Under California's Climate-Related Financial Risk Disclosure Program, authorized by Senate Bill 261, as amended, a report discussing the financial impacts of climate change to the business, consistent with the Task Force on Climate-Related Financial Disclosures (TCFD) framework, must be posted to the Company's public website by January 1, 2026. The Company is monitoring litigation challenging both SB 253 and SB 261 to assess impacts on compliance obligations.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and 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, 2024. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2024. Refer to Note 9 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for discussion of loss contingencies related to the Wildfires.

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PacifiCorp and its subsidiaries

Consolidated Financial Section

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PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder 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, 2025, the related consolidated statements of operations, and changes in shareholders' equity for the three-month and nine-month periods ended September 30, 2025 and 2024, and of cash flows for the nine-month periods ended September 30, 2025 and 2024, 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, 2024, and the related consolidated statements of operations, comprehensive income (loss), changes in shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 21, 2025, 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, 2024, 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

October 31, 2025

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

			As of
			September 30,						December 31,
			2025						2024
ASSETS
Current assets:
Cash and cash equivalents			$	46					$	46
Trade receivables, net			1,039						960
Other receivables, net			159						245
Inventories			893						828
Regulatory assets			753						891
Prepaid expenses			173						283
Other current assets			50						44
Total current assets			3,113						3,297
Property, plant and equipment, net			30,564						29,120
Regulatory assets			1,897						2,026
Other assets			583						561
Total assets			$	36,157					$	35,004

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

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PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

			As of
			September 30,						December 31,
			2025						2024
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable			$	1,412					$	1,462
Accrued interest			212						239
Accrued property, income and other taxes			244						85
Accrued employee expenses			159						96
Short-term debt			75						240
Current portion of long-term debt			152						302
Regulatory liabilities			63						92
Wildfires liabilities (Note 10)			580						247
Other current liabilities			442						466
Total current liabilities			3,339						3,229
Senior debt			13,191						13,286
Junior subordinated debt			841						—
Regulatory liabilities			2,568						2,550
Deferred income taxes			3,205						3,222
Wildfires liabilities (Note 10)			874						1,289
Other long-term liabilities			1,092						916
Total liabilities			25,110						24,492
Commitments and contingencies (Note 10)
Shareholders' equity:
Preferred stock			—						2
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding			—						—
Additional paid-in capital			4,479						4,479
Retained earnings			6,577						6,040
Accumulated other comprehensive loss, net			(9)						(9)
Total shareholders' equity			11,047						10,512
Total liabilities and shareholders' equity			$	36,157					$	35,004

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,
			2025						2024						2025						2024
Operating revenue			$	2,113					$	1,923					$	5,691					$	4,960
Operating expenses:
Cost of fuel and energy			940						862						2,381						2,076
Operations and maintenance			448						422						1,351						1,248
Wildfires losses (Note 10)			100						—						100						251
Depreciation and amortization			304						287						975						866
Property and other taxes			58						55						177						161
Total operating expenses			1,850						1,626						4,984						4,602
Operating income			263						297						707						358
Other income (expense):
Interest expense			(199)						(193)						(588)						(570)
Allowance for borrowed funds			24						33						70						92
Allowance for equity funds			33						56						91						156
Interest and dividend income			28						47						88						155
Other, net			6						4						17						11
Total other income (expense)			(108)						(53)						(322)						(156)
Income before income tax expense (benefit)			155						244						385						202
Income tax expense (benefit)			(102)						(80)						(154)						(174)
Net income			$	257					$	324					$	539					$	376

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, 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
Balance, June 30, 2025			$	—					$	—					$	4,479					$	6,320					$	(9)					$	10,790
Net income			—						—						—						257						—						257
Balance, September 30, 2025			$	—					$	—					$	4,479					$	6,577					$	(9)					$	11,047
Balance, December 31, 2024			$	2					$	—					$	4,479					$	6,040					$	(9)					$	10,512
Net income			—						—						—						539						—						539
Preferred stock redemptions			(2)						—						—						(2)						—						(4)
Balance, September 30, 2025			$	—					$	—					$	4,479					$	6,577					$	(9)					$	11,047

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,
			2025						2024
Cash flows from operating activities:
Net income			$	539					$	376
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization			975						866
Allowance for equity funds			(91)						(156)
Net power cost deferrals			(270)						(549)
Amortization of net power cost deferrals			694						373
Other changes in regulatory assets and liabilities			(149)						(35)
Deferred income taxes and amortization of investment tax credits			(96)						22
Other, net			12						—
Changes in other operating assets and liabilities:
Trade receivables, other receivables and other assets			(72)						(123)
Inventories			(65)						(231)
Derivative collateral, net			(16)						(30)
Prepaid expenses			98						(174)
Accrued property, income and other taxes, net			163						128
Accounts payable and other liabilities			19						117
Wildfires insurance receivable			98						365
Wildfires liability			(82)						(278)
Net cash flows from operating activities			1,757						671
Cash flows from investing activities:
Capital expenditures			(2,179)						(2,157)
Other, net			8						7
Net cash flows from investing activities			(2,171)						(2,150)
Cash flows from financing activities:
Proceeds from senior debt			—						3,762
Proceeds from junior subordinated debt			841						—
Repayments of senior debt			(250)						(425)
Net repayments of short-term debt			(165)						(1,604)
Redemptions and repurchases of preferred stock			(4)						—
Other, net			(4)						(4)
Net cash flows from financing activities			418						1,729
Net change in cash and cash equivalents and restricted cash and cash equivalents			4						250
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period			61						192
Cash and cash equivalents and restricted cash and cash equivalents at end of period			$	65					$	442

 

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 headquartered in Iowa that has investments in subsidiaries principally engaged in energy businesses. BHE is a wholly owned 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, 2025, and for the three- and nine-month periods ended September 30, 2025 and 2024. 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, 2025 and 2024. The results of operations for the three- and nine-month periods ended September 30, 2025, 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, 2024, 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, 2025. Refer to Note 10 for discussion of loss contingencies related to the Oregon and Northern California 2020 wildfires (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."

Segment Information

PacifiCorp currently has one reportable segment, its regulated electric utility operations, which derives its revenue from regulated retail sales of electricity to residential, commercial, industrial and irrigation customers and from wholesale sales. PacifiCorp's chief operating decision maker ("CODM") is its Chief Executive Officer. The CODM uses net income, as reported on the Consolidated Statements of Operations, and generally considers actual results versus historical results, budgets or forecasts, as well as unique risks and opportunities, when making decisions about the allocation of resources and capital. The segment expenses regularly provided to the CODM align with the captions presented on the Consolidated Statements of Operations. PacifiCorp's segment capital expenditures are reported on the Consolidated Statements of Cash Flows as capital expenditures. PacifiCorp's segment assets are reported on the Consolidated Balance Sheet as total assets.

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(2)    New Accounting Pronouncements

In December 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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.

In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures Subtopic 220-40, "Disaggregation of Income Statement Expenses" which addresses requests from investors for more detailed information about certain expenses and requires disclosure of the amounts of purchases of inventory, employee compensation, depreciation and intangible asset amortization included in each relevant expense caption presented on the income statement. This guidance, as clarified in ASU 2025-01, is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. 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.

(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,
			2025						2024
Cash and cash equivalents			$	46					$	46
Restricted cash and cash equivalents included in other current assets			16						12
Restricted cash included in other assets			3						3
Total cash and cash equivalents and restricted cash and cash equivalents			$	65					$	61

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(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						2025						2024
Utility plant:
Generation			15 - 59 years						$	15,142					$	14,316
Transmission			60 - 90 years						11,490						10,939
Distribution			20 - 75 years						10,674						9,842
Intangible plant and other			2 - 75 years						2,622						2,958
Utility plant in-service									39,928						38,055
Accumulated depreciation and amortization									(13,146)						(12,504)
Utility plant in-service, net									26,782						25,551
Nonregulated, net of accumulated depreciation and amortization			34 - 75 years						19						19
									26,801						25,570
Construction work-in-progress									3,763						3,550
Property, plant and equipment, net									$	30,564					$	29,120

In April 2025, PacifiCorp recorded $87 million in depreciation expense associated with the buy-down of certain plant balances and regulatory assets pursuant to the Utah general rate case order.

Government Grants

On January 20, 2025, U.S. federal executive order entitled Unleashing American Energy was issued requiring federal agencies to immediately pause disbursement of federal funds appropriated under the Inflation Reduction Act of 2022 and the Infrastructure Investment and Jobs Act, subject to respective agency review within 90 days of the date of the order of the agency's processes, policies and programs for issuing grants consistent with the policies stated in the executive order. The pause was lifted on federal funding disbursements in April 2025 and the invoice process resumed.

As of September 30, 2025, and December 31, 2024, approximately $46 million and $11 million, respectively, of federal grant funds reduced additions to property, plant and equipment – net on the Consolidated Balance Sheets. During the nine-month period ended September 30, 2025, approximately $17 million of federal grant funds reduced operating expenses on the Consolidated Statements of Operations. Federal grant funds received during the nine-month period ended September 30, 2024, were insignificant.

(5)    Recent Financing Transactions

Junior Subordinated Debt

In March 2025, PacifiCorp issued $850 million of its 7.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due September 2055. PacifiCorp will pay interest on the notes at a rate of 7.375% through September 2030, subject to a reset every five years, not to reset below 7.375%. 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 2025, PacifiCorp amended its existing $2.0 billion unsecured credit facility expiring in June 2027. The amendment extended the expiration date to June 2028 and amended certain provisions of the existing credit agreement.

In June 2025, PacifiCorp amended its existing $900 million 364‑day unsecured credit facility expiring in June 2025. The amendment extended the expiration date to June 2026 and amended certain provisions of the existing credit agreement.

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(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,
			2025						2024						2025						2024
Federal statutory income tax rate			21		%				21		%				21		%				21		%
State income tax, net of federal income tax impacts			4						3						5						4
Income tax credits			(69)						(37)						(50)						(74)
Effects of ratemaking(1)			(21)						(18)						(15)						(35)
Other			(1)						(2)						(1)						(2)
Effective income tax rate			(66)		%				(33)		%				(40)		%				(86)		%

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

Income tax credits relate primarily to production tax credits ("PTC") from PacifiCorp's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the three-month periods ended September 30, 2025 and 2024, totaled $107 million and $92 million, respectively. PTCs recognized for the nine-month periods ended September 30, 2025 and 2024, totaled $194 million and $150 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 period ended September 30, 2025 and 2024, PacifiCorp received net cash payments for federal and state income taxes from BHE totaling $136 million and $240 million, respectively. As of September 30, 2025, net income taxes payable to BHE were $86 million. As of December 31, 2024, federal income taxes receivable from BHE were $3 million and state income taxes payable to BHE were $11 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,
			2025						2024						2025						2024
Pension:
Interest cost			$	9					$	9					$	28					$	27
Expected return on plan assets			(11)						(11)						(34)						(35)
Net amortization			1						2						5						7
Net periodic benefit credit			$	(1)					$	—					$	(1)					$	(1)
Other postretirement:
Service cost			$	—					$	—					$	—					$	—
Interest cost			3						3						8						9
Expected return on plan assets			(3)						(4)						(9)						(10)
Net amortization			(1)						—						(2)						(2)
Net periodic benefit credit			$	(1)					$	(1)					$	(3)					$	(3)

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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 2025. As of September 30, 2025, $3 million of contributions had been made to the pension plans.

(8)    Risk Management and Hedging Activities

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

PacifiCorp has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices. Refer to Note 9 for additional information related to the fair value measurements associated with 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):

			Other												Other						Other
			Current						Other						Current						Long-term
			Assets						Assets						Liabilities						Liabilities						Total
As of September 30, 2025
Not designated as hedging contracts(1):
Commodity assets			$	13					$	1					$	2					$	2					$	18
Commodity liabilities			(2)						—						(72)						(16)						(90)
Total			11						1						(70)						(14)						(72)
Total derivatives			11						1						(70)						(14)						(72)
Cash collateral receivable			—						—						22						—						22
Total derivatives - net basis			$	11					$	1					$	(48)					$	(14)					$	(50)
As of December 31, 2024
Not designated as hedging contracts(1):
Commodity assets			$	10					$	—					$	16					$	1					$	27
Commodity liabilities			(1)						—						(105)						(18)						(124)
Total			9						—						(89)						(17)						(97)
Total derivatives			9						—						(89)						(17)						(97)
Cash collateral receivable			—						—						6						—						6
Total derivatives - net basis			$	9					$	—					$	(83)					$	(17)					$	(91)

(1)PacifiCorp's commodity derivatives are generally included in rates. As of September 30, 2025, a regulatory asset of $72 million was recorded related to the net derivative liability of $72 million. As of December 31, 2024, a regulatory asset of $97 million was recorded related to the net derivative liability of $97 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,
			2025						2024						2025						2024
Beginning balance			$	53					$	139					$	97					$	76
Changes in fair value recognized in regulatory assets			82						101						85						265
Net gains reclassified to operating revenue			7						12						17						15
Net losses reclassified to energy costs			(70)						(173)						(127)						(277)
Ending balance			$	72					$	79					$	72					$	79

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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						2025						2024
Electricity sales, net			Megawatt hours						(1)						(1)
Natural gas purchases			Decatherms						151						124

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 energy agreements, including contracts for purchases, sales and transportation of electricity, natural gas, and coal, some of which are accounted for as derivatives, 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, 2025, PacifiCorp's 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 $90 million and $123 million as of September 30, 2025, and December 31, 2024, respectively, for which PacifiCorp had posted collateral of $22 million and $6 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, 2025, and December 31, 2024, PacifiCorp would have been required to post $62 million and $100 million, respectively, of additional collateral.

PacifiCorp's collateral requirements associated with wholesale energy agreements could fluctuate considerably due to market price volatility; changes in credit ratings; changes in legislation or regulation or other factors; and if counterparties demand adequate assurance in the event of a material adverse change in PacifiCorp's creditworthiness.

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(9)    Fair Value Measurements

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

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

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

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

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, 2025:
Assets:
Commodity derivatives			$	—					$	18					$	—					$	(6)					$	12
Money market mutual funds			37						—						—						—						37
Investment funds			28						—						—						—						28
			$	65					$	18					$	—					$	(6)					$	77
Liabilities:
Commodity derivatives			$	—					$	(90)					$	—					$	28					$	(62)
As of December 31, 2024:
Assets:
Commodity derivatives			$	—					$	27					$	—					$	(18)					$	9
Money market mutual funds			34						—						—						—						34
Investment funds			29						—						—						—						29
			$	63					$	27					$	—					$	(18)					$	72
Liabilities:
Commodity derivatives			$	—					$	(124)					$	—					$	24					$	(100)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $22 million and $6 million as of September 30, 2025, and December 31, 2024, respectively.

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Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. 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 8 for further discussion regarding PacifiCorp's risk management and hedging activities.

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

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

			As of September 30, 2025												As of December 31, 2024
			Carrying						Fair						Carrying						Fair
			Value						Value						Value						Value
Long-term debt			$	14,184					$	13,457					$	13,588					$	12,580

(10)    Commitments and Contingencies

Commitments

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

Purchased Electricity Contracts - Non-Commercially Operable

During the nine-month period ended September 30, 2025, PacifiCorp entered into battery storage agreements with commitments totaling approximately $1.8 billion through 2048. In October 2025, an additional battery storage agreement became effective with commitments totaling approximately $343 million through 2046. The facilities associated with these contracts have not yet achieved commercial operation. To the extent these facilities do not achieve commercial operation, PacifiCorp has no obligation to the counterparty.

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Construction Commitments

During the nine-month period ended September 30, 2025, PacifiCorp became committed under the terms of a previously existing construction funding agreement with Idaho Power Company to support the development of the Boardman to Hemingway 500‑kV transmission line. PacifiCorp is committed to contributing up to $460 million toward construction costs, representing PacifiCorp's share of the total estimated project cost of $843 million. In addition, PacifiCorp issued limited notice to proceed for construction contracts totaling $278 million through 2027 for service center and essential services buildings located in Salt Lake City, Utah. The projects are expected to be placed into service mid-2028.

Fuel Contracts

During the nine-month period ended September 30, 2025, PacifiCorp entered into certain coal supply and transportation agreements totaling $109 million through 2029.

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 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. 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. In October 2024, PacifiCorp provided approximately $11 million in supplemental funding to the KRRC. As of October 2024, removal of the Lower Klamath Project dams was complete.

Legal Matters

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

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.

Wildfires

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, PacifiCorp received correspondence from the U.S. and Oregon Departments of Justice regarding the potential recovery of certain costs and damages alleged to have occurred on federal and state lands in connection with certain of the 2020 Wildfires. In December 2024, the United States of America filed a complaint against PacifiCorp in conjunction with the correspondence from the U.S. Department of Justice. The civil cover sheet accompanying the complaint demands damages estimated to exceed $900 million. PacifiCorp is actively cooperating with the U.S. and Oregon Departments of Justice on resolving these alleged claims.

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Amounts sought in outstanding complaints and demands filed in Oregon and in certain demands made in California totaled approximately $55 billion, excluding any doubling or trebling of damages or punitive damages included in the complaints and excluding damages that may be sought by additional plaintiffs granted substitution counsel in the James class action lawsuit described below. Generally, the complaints filed in California do not specify damages sought and are excluded from this amount. Of the $55 billion, $52 billion represents the economic and noneconomic damages sought in the James mass complaints described below. 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 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 damage.

Based on available information to date, losses have been and will likely continue to be incurred associated with the Wildfires. Final determinations of liability will only be made following the completion of comprehensive investigations, which may be or have been performed by various entities, including the U.S. Department of Agriculture Forest Service ("USFS"), the California Public Utilities Commission, the Oregon Department of Forestry ("ODF") and the Oregon Department of Justice, as well as 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 with 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 and include the Santiam Canyon, Beachie Creek, South Obenchain, Echo Mountain Complex, 242, Archie Creek, Slater and other fires. The Slater fire occurred in both Oregon and California. Third-party reports for these wildfires indicate over 2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities.

In May 2022, the USFS issued its report of investigation into the Archie Creek fire concluding that the probable cause of the fire was power lines owned and operated by PacifiCorp. The USFS report for the Archie Creek fire also states that evidence indicates failure of power line infrastructure. The USFS report of investigation into the Slater fire for the investigation period October 5, 2020, to December 8, 2020, concluded that the fire was caused by a downed power line owned and operated by PacifiCorp. The USFS report for the Slater fire also states that evidence indicates a tree fell onto the power line and that wind blew over the 137-foot tree with internal rot that showed no outward signs of distress and would not have been classified or identified as a hazard tree.

Settlements have been reached with substantially all individual plaintiffs, timber companies and insurance subrogation plaintiffs in both the Archie Creek and Slater fires with government timber and suppression cost claims remaining. Additionally, settlements have been reached for all wrongful death claims associated with the 2020 Wildfires.

In April 2023, the USFS issued its report of investigation into a wildland fire that began in the Opal Creek wilderness outside of the Santiam Canyon that was first reported on August 16, 2020 ("Beachie Creek Fire"), approximately three weeks prior to the September 2020 wind event described above. In March 2025, PacifiCorp received the ODF's final investigation report on the Santiam Canyon fires ("ODF's Report"), which concluded that embers from the pre-existing Beachie Creek Fire caused 12 fires within the Santiam Canyon. The ODF's Report also found that PacifiCorp's power lines did not contribute to the overall spread of fire into the Santiam Canyon even though its power lines ignited seven spot fires within the Santiam Canyon that were each suppressed.

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The Beachie Creek fire that spread into the Santiam Canyon burned approximately 193,000 acres; the South Obenchain fire burned approximately 33,000 acres; the Echo Mountain Complex fire burned approximately 3,000 acres; and the 242 fire burned approximately 14,000 acres. The James cases described below are associated with the Beachie Creek (Santiam Canyon), South Obenchain, Echo Mountain Complex and 242 fires, which are four distinct fires located hundreds of miles apart.

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 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. 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 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. Since filing of the original class action complaint, numerous James class members have been named and damages specified in various complaints as described below. Additionally, numerous cases were consolidated into the original James complaint.

As of October 2025, various mass complaints against PacifiCorp naming approximately 1,700 class members have been filed referencing the James case as the lead case. These James mass complaints make damages-only allegations with substantially all plaintiffs individually seeking $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, as well as doubling of economic damages. An additional 1,500 plaintiffs have been granted the ability not to be represented by James lead counsel. A small portion of these additional plaintiffs have filed complaints seeking damages similar to those in the mass complaints. PacifiCorp expects additional complaints will be filed for these plaintiffs, including for the portion that are scheduled for trial under the July 2025 case management order described below.

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 below that are being appealed.

James Trial Activity

In June 2023, a jury verdict was issued in the first James trial finding PacifiCorp's conduct grossly negligent, reckless and willful as to each of the 17 named plaintiffs and the entire class. The jury awarded economic and noneconomic damages. After the jury verdict, the Multnomah County Circuit Court Oregon doubled the economic damages, in accordance with Oregon law, and added punitive damages by applying a 0.25 multiplier to the awarded economic and noneconomic damages. PacifiCorp filed a motion with the Multnomah County Circuit Court Oregon requesting the court offset the damage awards by deducting insurance proceeds received by any of the plaintiffs. In January 2024, PacifiCorp filed a notice of appeal associated with the June 2023 verdict, including whether the case can proceed as a class action.

Subsequent to the June 2023 James verdict, numerous damages phase trials were held with separate jury verdicts issued and damages awarded for each on a basis consistent with the initial trial and relying on the liability determination in the June 2023 James verdict. PacifiCorp amended its January 2024 appeal of the June 2023 James verdict to include the jury verdicts for the first two damages phase trials. PacifiCorp has filed notices of appeal for the subsequent jury verdicts in the damages phase trials once limited judgments are entered and any post-trial motions filed. Refer to "James Court Activity" below regarding the filing of PacifiCorp's appellate briefs. The appeals process and further actions could take several years.

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The James jury verdicts awarded various damages as follows (in millions):

						Number of Plaintiffs						Verdict / Limited Judgment Date						Damages(1)
James Trial																		Doubled Economic						Non-economic						Punitive						Insurance Offset(2)						Net Damages						Appeal Filed
Jury verdicts, limited judgments entered(3)
Initial James trial						17						June 2023 / January 2024						$	9					$	67					$	18					$	2					$	92					Yes
First damages						9						January 2024 / April 2024						12						56						16						4						80						Yes
Second damages						10						March 2024 / June 2024						12						23						7						4						38						Yes
Third damages						8						February 2025 / April 2025						8						32						9						4						45						Yes
Fourth damages						7						March 2025 / June 2025						5						34						9						1						47						Yes
Fifth damages						9						April 2025 / August 2025						5						11						3						1						18						Yes
Sixth damages						10						May 2025 / July 2025						11						30						9						2						48						Yes
Seventh damages						10						June 2025 / August 2025						8						28						8						1						43						Yes
Eighth damages						11						July 2025 / September 2025						10						36						10						3						53
Jury verdicts, limited judgments not yet entered
Ninth damages						10						September 2025						11						63						17						3						88
Tenth damages						8						October 2025						5						26						7						1						37
						109												$	96					$	406					$	113					$	26					$	589

(1)For jury verdicts where the limited judgment has not yet been entered, the doubling of economic damages and the application of punitive damages are estimates.

(2)For jury verdicts where limited judgment has been entered, the court offset the awards by the amount of insurance proceeds received by any of the plaintiffs. For jury verdicts where the limited judgment has not yet been entered, the insurance offset is an estimate.

(3)For each limited judgment entered in the court, PacifiCorp has posted or expects to post a supersedeas bond, which stays any effort to seek payment of the judgments pending final resolution of any appeals. Under Oregon Revised Statutes 82.010, interest at a rate of 9% per annum will accrue on the judgments commencing at the date the judgments were entered until the entire money award is paid, amended or reversed by an appellate court. The supersedeas bond posted for the June 2023 James verdict covers three years of post-judgment interest while amounts posted for the subsequent verdicts cover two years of post-judgment interest.

Through October 2025, jury verdict awards averaged approximately $5 million per plaintiff, including insurance offset. Additional damages phase trials are scheduled to occur in 2025 through 2028 as described below.

James Court Activity

In April 2025, PacifiCorp filed its opening brief with the Oregon Court of Appeals in connection with its appeal of the June 2023 James verdict and the January and March 2024 verdicts for the first two James damages phase trials. In the opening brief, PacifiCorp addresses numerous procedural and legal issues, including that the class certification is improper due to the plaintiffs being impacted by distinct fires with independent ignition points that were hundreds of miles apart; awarding of non-economic damages is not allowed under Oregon law; plaintiffs failed to prove that PacifiCorp caused harm to every class member; and jury instructions applied incorrect legal standards in assessing class-wide evidence and individual claims. Additionally, PacifiCorp incorporated the ODF's Report into its opening appellate brief. Various parties who are not party to the James case have filed supportive amicus briefs with the court. Plaintiffs filed their combined answering and cross-appeal brief on August 21, 2025, after plaintiffs requested three delays from the Oregon Court of Appeals. PacifiCorp filed its combined reply brief and cross-appeal answering brief on October 17, 2025. Plaintiffs' reply brief is due on November 7, 2025, unless plaintiffs ask for additional extensions. On October 23, 2025, PacifiCorp filed a request with the Oregon Court of Appeals for an expedited oral argument, which, if granted, will facilitate a more prompt decision from the court.

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Subsequent to the first two damages phase trials, nine damages phase trials were scheduled to be held in 2025 in accordance with the Multnomah County Circuit Court Oregon's October 2024 case management order. In March 2025, in consideration of the ODF's Report, PacifiCorp filed a motion to stay the remaining James damages phase trials scheduled under the October 2024 case management order. The motion was heard by the court and was denied in April 2025. The remaining damages phase trial ordered under the October 2024 case management order is scheduled to begin December 1, 2025.

On July 28, 2025, the Multnomah County Circuit Court Oregon issued Case Management Order No. 11 ("CMO No. 11") in response to the May 2025 hearing that was held to evaluate the scheduling of additional damages phase trials. As ordered, CMO No. 11 proposes to schedule dozens of trials in 2026 and over 100 more in 2027 and 2028, involving approximately 2,000 plaintiffs. Additionally, CMO No. 11 requires mediation every other month starting in October 2025.

On August 8, 2025, PacifiCorp filed a motion with the Oregon Court of Appeals to stay the James damages phase trials addressed in CMO No. 11 and to which plaintiffs' counsel responded on August 29, 2025. On September 23, 2025, the Appellate Commissioner of the Oregon Court of Appeals denied PacifiCorp's motion to stay. On September 26, 2025, PacifiCorp filed a request for reconsideration of the stay denial with the Chief Judge of the Oregon Court of Appeals. On October 13, 2025, the Oregon Court of Appeals issued an order denying PacifiCorp's request for reconsideration. PacifiCorp has 35 days from October 13, 2025, to petition the Oregon Supreme Court to review the Oregon Court of Appeals order.

Potential Effects of James CMO No. 11

To appeal the limited judgments, PacifiCorp is required to bond the judgments. As of the date of this filing, PacifiCorp has posted bonds totaling $479 million associated with the limited judgments entered to date for 91 plaintiffs. These bonding requirements will continue to apply to future judgments associated with the CMO No. 11 trial schedule beginning in 2026. As noted above, CMO No. 11 proposes to schedule dozens of trials in 2026 and over 100 more in 2027 and 2028, involving approximately 2,000 plaintiffs. Each trial is subject to and dependent on judicial resources and availability, which will be determined six weeks before each trial. The CMO No. 11 proposed schedule is likely to put significant strain on the Multnomah County Circuit Court system, and PacifiCorp believes this may challenge the court's ability to fulfill the schedule in CMO No. 11.

If, however, the trial schedule and caseload progress as proposed in CMO No. 11 and the future limited judgments follow current trends, PacifiCorp estimates damages awarded in the jury verdicts may exceed its available surety bond and letter of credit capacity, requiring cash to be posted with Multnomah County to stay payment of damages awarded in the subsequent damages trials. PacifiCorp expects additional debt financings, including potential borrowings under its $2.0 billion credit facility subject to its availability, or other sources of funding will be needed to provide liquidity to post cash for judgments. Maintaining this trial schedule will cause significant financial strain on PacifiCorp's liquidity and will put pressure on PacifiCorp's credit metrics due to bonding requirements. Weakening of PacifiCorp's credit metrics could result in a downgrade, potentially below investment grade. Such a downgrade may result in the loss of surety bond and letter of credit capacity; trigger cash collateral calls for surety bonds posted; and trigger additional cash collateral calls or other forms of security for wholesale energy agreements that contain credit-risk-related contingent features or rights to demand adequate assurance in the event of a material adverse change in PacifiCorp's creditworthiness. Additionally, a downgrade of PacifiCorp's senior secured debt below investment grade would require new regulatory applications and approvals due to certain authorizations or exemptions currently in place with certain regulatory commissions for the issuance of securities.

PacifiCorp may be unable to obtain the required funding to meet its liquidity needs due to cash requirements for judgments if the trial schedule and case load progresses as proposed in CMO No. 11. Should PacifiCorp be downgraded below investment grade and unable to secure sufficient debt financings or alternative funding sources, it may have insufficient liquidity to support ongoing operations including the ability to absorb wholesale power volatility, pay suppliers and meet debt obligations, and such liquidity issues may impact transmission and generation development, purchasing power in the market, building and upgrading substations, connecting new customers, addressing outages and maintaining system resilience.

Litigation is inherently difficult to predict, and its potential financial impacts are therefore based on assumptions that will change. Furthermore, there may be judicial decisions and other events or circumstances that could improve or worsen the challenges PacifiCorp faces. PacifiCorp believes it will have sufficient liquidity to cover its operations and obligations beyond a year.

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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 USFS issued a Wildland Fire Origin and Cause Supplemental Incident Report. The report concluded that a tree coming in contact with a power line is the probable cause of the 2022 McKinney Fire. Settlements have been reached with substantially all individual plaintiffs, timber companies and insurance subrogation plaintiffs in the 2022 McKinney Fire with government timber and suppression cost claims remaining. Additionally, PacifiCorp has settled or settled in principle all wrongful death claims associated with the 2022 McKinney Fire.

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 activities; (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 $2,853 million through September 30, 2025. 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, 2025, PacifiCorp paid $1,399 million in settlements associated with the Wildfires. As a result of the settlements, various trials have been cancelled. In October 2025 and through the date of this filing, PacifiCorp made additional settlement payments related to the Wildfires totaling $1 million.

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,
			2025						2024						2025						2024
Beginning balance			$	1,381					$	1,883					$	1,536					$	1,723
Accrued losses			100						—						100						251
Payments			(27)						(438)						(182)						(529)
Ending balance			$	1,454					$	1,445					$	1,454					$	1,445

As of September 30, 2025, and December 31, 2024, $580 million and $247 million of PacifiCorp's liability for estimated losses associated with the Wildfires was classified as a current liability captioned Wildfires liabilities on the Consolidated Balance Sheets. The amounts reflected as current as of September 30, 2025, 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, 2025, and December 31, 2024, was classified as a noncurrent liability captioned Wildfires 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,
			2025						2024						2025						2024
Beginning balance			$	—					$	139					$	98					$	499
Payments received			—						(5)						(98)						(365)
Ending balance			$	—					$	134					$	—					$	134

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As of September 30, 2025, PacifiCorp had received all expected insurance recoveries. As of December 31, 2024, PacifiCorp's receivable for expected insurance recoveries was included in other receivables, net on the Consolidated Balance Sheets. No additional insurance recoveries beyond those 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 and the 2022 McKinney Fire, the variation in the types of properties and damages and the ultimate outcome of legal actions, including mediation, settlement negotiations, jury verdicts and the appeals process.

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.

(11)    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,
			2025						2024						2025						2024
Customer Revenue:
Retail:
Residential			$	750					$	680					$	2,022					$	1,786
Commercial			677						605						1,844						1,566
Industrial			381						361						1,095						987
Other retail			167						143						372						289
Total retail			1,975						1,789						5,333						4,628
Wholesale			37						25						65						67
Transmission			46						54						128						137
Other Customer Revenue			31						26						93						81
Total Customer Revenue			2,089						1,894						5,619						4,913
Other revenue			24						29						72						47
Total operating revenue			$	2,113					$	1,923					$	5,691					$	4,960

(12)    Preferred Stock

On April 23, 2025, PacifiCorp repurchased the sole outstanding share of its 7.00% Serial Preferred Stock from PPW Holdings LLC, for a purchase price of $1,800,000. As of the date of this filing, there are no shares of PacifiCorp Serial Preferred Stock outstanding.

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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 2025 and 2024

Overview

Net income for the third quarter of 2025 was $257 million, a decrease of $67 million, compared to 2024. The decrease in net income was primarily due to $100 million of higher wildfire loss accruals, lower allowances for equity and borrowed funds used during construction, increased operations and maintenance expense, lower interest and dividend income, increased depreciation and amortization expense and higher interest expense, partially offset by higher utility margin and a favorable income tax benefit. Utility margin increased primarily due to lower purchased electricity costs from lower volumes and average market prices, higher retail prices and volumes, higher wholesale sales volumes and lower natural gas-fueled generation volumes, partially offset by lower net power costs deferrals, driven by lower current quarter deferrals and higher amortization of prior deferrals, higher coal-fueled generation costs, primarily from higher volumes, lower wholesale market prices, and lower wheeling revenues. Retail customer volumes increased 2.0%, primarily due to higher customer usage and an increase in the average number of customers, partially offset by the unfavorable impact of weather. Energy generated volumes increased 1,404 gigawatt-hours, or 12%, for the third quarter of 2025 compared to 2024 primarily due to higher coal-fueled generation and higher wind-powered generation, partially offset by lower natural gas-fueled generation and lower hydro-powered generation. Wholesale electricity sales volumes increased 289 gigawatt-hours, or 43%, and energy purchased volumes decreased 910 gigawatt-hours, or 14%.

Net income for the first nine months of 2025 was $539 million, an increase of $163 million, compared to 2024. The increase in net income was primarily due to higher utility margin and $151 million of lower wildfire loss accruals, partially offset by higher depreciation and amortization expense, increased operations and maintenance expense, lower allowances for equity and borrowed funds used during construction, decreased interest and dividend income, increased interest expense, higher property and other taxes and an unfavorable income tax benefit. Utility margin increased primarily due to higher retail prices and volumes, lower purchased electricity costs from lower volumes and average market prices, higher wholesale volumes and lower natural gas-fueled generation volumes, partially offset by lower net power costs deferrals, driven by lower current year deferrals and higher amortization of prior deferrals, higher coal-fueled generation volumes and prices, lower wholesale average market prices and higher wheeling expenses. Retail customer volumes increased 2.0%, primarily due to an increase in the average number of customers, higher customer usage and the favorable impact of weather. Energy generated volumes increased 4,310 gigawatt-hours, or 13% for the first nine months of 2025 compared to 2024 primarily due to higher coal-fueled generation and higher wind-powered generation, partially offset by lower gas-fueled generation and lower hydro-powered generation. Wholesale electricity sales volumes increased 940 gigawatt-hours, or 55%, and energy purchased volumes decreased 2,543 gigawatt-hours, or 15%.

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 retail customers through regulatory recovery mechanisms and as a result, changes in PacifiCorp's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains results of operations 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 understanding 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
			2025						2024						Change												2025						2024						Change
Utility margin:
Operating revenue			$	2,113					$	1,923					$	190					10		%				$	5,691					$	4,960					$	731					15		%
Cost of fuel and energy			940						862						78						9						2,381						2,076						305						15
Utility margin			1,173						1,061						112						11						3,310						2,884						426						15
Operations and maintenance			448						422						26						6						1,351						1,248						103						8
Wildfires losses			100						—						100						*						100						251						(151)						(60)
Depreciation and amortization			304						287						17						6						975						866						109						13
Property and other taxes			58						55						3						5						177						161						16						10
Operating income			$	263					$	297					$	(34)					(11)		%				$	707					$	358					$	349					97		%

*    Not meaningful

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Utility Margin

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

			Third Quarter																								First Nine Months
			2025						2024						Change												2025						2024						Change
Utility margin (in millions):
Operating revenue			$	2,113					$	1,923					$	190					10		%				$	5,691					$	4,960					$	731					15		%
Cost of fuel and energy			940						862						78						9						2,381						2,076						305						15
Utility margin			$	1,173					$	1,061					$	112					11		%				$	3,310					$	2,884					$	426					15		%
Sales (GWhs):
Residential			5,014						4,994						20						—		%				13,918						13,728						190						1		%
Commercial(1)			6,153						5,749						404						7						17,048						16,104						944						6
Industrial(1)			4,153						4,240						(87)						(2)						12,501						12,824						(323)						(3)
Other(1)			828						855						(27)						(3)						1,488						1,417						71						5
Total retail			16,148						15,838						310						2						44,955						44,073						882						2
Wholesale			967						678						289						43						2,655						1,715						940						55
Total sales			17,115						16,516						599						4		%				47,610						45,788						1,822						4		%
Average number of retail customers (in thousands)			2,140						2,108						32						2		%				2,133						2,099						34						2		%
Average revenue per MWh:
Retail			$	122.52					$	113.11					$	9.41					8		%				$	118.77					$	105.16					$	13.61					13		%
Wholesale			$	58.83					$	73.12					$	(14.29)					(20)		%				$	46.98					$	58.86					$	(11.88)					(20)		%
Heating degree days			103						125						(22)						(18)		%				5,911						5,907						4						—		%
Cooling degree days			1,706						1,762						(56)						(3)		%				2,264						2,276						(12)						(1)		%
Sources of energy (GWhs)(1):
Coal			6,634						4,856						1,778						37		%				17,768						12,795						4,973						39		%
Natural gas			4,586						4,964						(378)						(8)						11,552						12,413						(861)						(7)
Wind(2)			1,281						1,186						95						8						5,278						4,932						346						7
Hydroelectric and other(2)			406						497						(91)						(18)						2,086						2,234						(148)						(7)
Total energy generated			12,907						11,503						1,404						12						36,684						32,374						4,310						13
Energy purchased			5,491						6,401						(910)						(14)						14,679						17,222						(2,543)						(15)
Total			18,398						17,904						494						3		%				51,363						49,596						1,767						4		%
Average cost of energy per MWh:
Energy generated(3)			$	26.60					$	24.52					$	2.08					8		%				$	25.44					$	24.10					$	1.34					6		%
Energy purchased			$	69.36					$	94.81					$	(25.45)					(27)		%				$	60.14					$	78.09					$	(17.95)					(23)		%

(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, 2025, compared to Quarter Ended September 30, 2024

Utility margin increased $112 million for the third quarter of 2025 compared to 2024 primarily due to:

•$226 million of lower purchased electricity costs from lower volumes and lower average market prices;

•$187 million increase in retail revenue due to higher average prices and higher volumes. Retail revenue increased primarily due to price impacts of $151 million from higher average rates, largely from tariff changes and $36 million from higher retail volumes. Retail customer volumes increased 2.0%, primarily due to an increase in Utah and Oregon commercial customer usage, an increase in the average number of commercial and residential customers across the service territory, mainly in Utah and Oregon and an increase in Oregon and Washington residential customer usage, partially offset by a decrease in Wyoming, Utah, Washington and California industrial customer usage, unfavorable weather related impacts on residential and commercial customers in Utah and Oregon, unfavorable Idaho and California irrigation customer usage and unfavorable Wyoming, Utah, Idaho and California residential customer usage;

•$8 million of lower natural gas-fueled generation costs from lower volumes, partially offset by higher prices; and

•$7 million increase in wholesale revenue due to higher volumes, partially offset by lower average market prices.

The increases above were partially offset by:

•$240 million of lower net power costs deferrals in accordance with established adjustment mechanisms driven by lower current quarter deferrals and higher amortization of prior deferrals; and

•$69 million of higher coal-fueled generation costs, primarily from higher volumes.

Operations and maintenance increased $26 million, or 6%, for the third quarter of 2025 compared to 2024 primarily due to:

•$11 million of higher demand side management amortization driven by increased spend;

•$10 million increase in salary and benefit expenses;

•$8 million of higher insurance expense due to higher premiums associated with third-party liability coverage;

•$7 million of higher legal fees; and

•$7 million of higher general plant and maintenance costs.

The increases above were partially offset by:

•$19 million of lower vegetation management and wildfire mitigation costs, primarily from lower gross costs and lower amortization of prior deferrals.

Wildfires losses increased $100 million for the third quarter of 2025 compared to 2024 due to an increase in loss accruals associated with the 2020 Wildfires.

Depreciation and amortization increased $17 million, or 6%, for the third quarter of 2025 compared to 2024, primarily due to higher average in-service plant, partially offset by current year extension of depreciable lives for certain plants as a result of the Oregon 2025 general rate case order.

Property and other taxes increased $3 million, or 5%, for the third quarter of 2025 compared to 2024, primarily due to higher franchise taxes primarily in Oregon, and higher Washington public utility taxes.

Interest expense increased $6 million, or 3%, for the third quarter of 2025 compared to 2024, primarily due to the issuance of $850 million of junior subordinated notes in March 2025.

Allowance for borrowed and equity funds decreased $32 million, or 36%, for the third quarter of 2025 compared to 2024, primarily due to lower qualified construction work-in-progress balances and lower rates.

Interest and dividend income decreased $19 million, or 40%, for the third quarter of 2025 compared to 2024, primarily due to lower current year cash equivalents and lower interest rates.

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Income tax benefit increased $22 million, or 28%, for the third quarter of 2025 compared to 2024, and the effective tax rate was (66)% for 2025 and (33)% for 2024. The $22 million increase is primarily due to higher loss accruals associated with the 2020 Wildfires, higher PTCs from PacifiCorp's wind-powered generating facilities, partially offset by lower benefit from the effects of ratemaking.

First Nine Months of 2025 compared to First Nine Months of 2024

Utility margin increased $426 million for the first nine months of 2025 compared to 2024 primarily due to:

•$705 million increase in retail revenue due to higher average prices and higher retail volumes. Retail revenue increased primarily due to price impacts of $604 million from higher average rates, largely from tariff changes and favorable adjustments of $87 million due to the buy-down of certain plant balances and regulatory assets pursuant to the Utah general rate case order (fully offset in depreciation and amortization expense) and $101 million from higher retail volumes. Retail customer volumes increased 2.0%, primarily due to higher Utah and Oregon commercial customer usage, an increase in the average number of commercial and residential customers across the service territory, mainly in Utah and Oregon, favorable weather related impacts on residential and commercial customers and an increase in irrigation customer usage across the service territory, except in California, partially offset by a decrease in industrial customer usage across the service territory, except in Idaho and Oregon and a decrease in residential customer usage across the service territory, except in Oregon and Idaho;

•$462 million of lower purchased electricity costs from lower volumes and prices;

•$24 million of higher wholesale revenue from higher volumes, partially offset by lower average market prices; and

•$21 million of lower natural gas-fueled generation costs from lower volumes, partially offset by higher prices.

The increases above were partially offset by:

•$600 million of lower net power costs deferrals in accordance with established adjustment mechanisms driven by higher amortization of prior deferrals and lower current year deferrals;

•$174 million of higher coal-fueled generation costs due to higher volumes and prices; and

•$15 million of higher wheeling expense.

Operations and maintenance increased $103 million, or 8%, for the first nine months of 2025 compared to 2024 primarily due to:

•$46 million of higher demand side management amortization driven by increased spend;

•$39 million of higher insurance expense due to higher premiums associated with third-party liability coverage;

•$37 million of higher general plant and maintenance costs;

•$30 million increase in salary and benefit expenses;

•$17 million of higher legal fees; and

•$15 million of disallowance loss of Utah's share of certain assets on the Klamath River hydroelectric system as a result of the 2025 Utah general rate case.

The increases above were partially offset by:

•$66 million of lower vegetation management and wildfire mitigation costs primarily from higher current year cost deferrals in Oregon and California, lower amortization of prior deferrals and lower gross costs;

•$15 million due to higher accruals of federal grant reimbursements;

•$11 million decrease associated with prior year accrual of the Lower Klamath Project, net of reserve; and

•$6 million of lower injuries and damages expenses, excluding the Wildfires.

Wildfire losses decreased $151 million, or 60% for the first nine months of 2025 compared to 2024 due to a decrease in loss accruals associated with the 2020 Wildfires.

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Depreciation and amortization increased $109 million, or 13%, for the first nine months of 2025 compared to 2024 primarily due to the second quarter 2025 buy-down of certain plant and regulatory asset balances pursuant to the 2025 Utah general rate case order of $87 million (fully offset in retail revenue) and higher average in-service plant, partially offset by current year extension of depreciable lives for certain plants as a result of the Oregon 2025 general rate case order, and a $12 million decrease due to change in allocation adjustment compounded by prior year allocation adjustment increase of $5 million.

Interest expense increased $18 million, or 3%, for the first nine months of 2025 compared to 2024, primarily due to the issuance of $850 million of junior subordinated notes in March 2025.

Property and other taxes increased $16 million, or 10%, for the first nine months of 2025 compared to 2024 primarily due to higher property taxes in Utah and Washington, higher franchise taxes primarily in Oregon, higher federal excise tax expense and higher Washington public utility taxes.

Allowance for borrowed and equity funds decreased $87 million, or 35%, for the first nine months of 2025 compared to 2024 primarily due to lower qualified construction work-in-progress balances and lower rates.

Interest and dividend income decreased $67 million, or 43%, for the first nine months of 2025 compared to 2024 primarily due to lower current year cash equivalents, lower interest rates and lower interest income on regulatory assets.

Other, net increased $6 million or 55%, for the first nine months of 2025 compared to 2024, primarily due to an increase in income tax gross up billings on customer contributions in aid of construction.

Income tax benefit decreased $20 million, or 11%, for the first nine months of 2025 compared to 2024 and the effective tax rate was (40)% for 2025 and (86)% for 2024. The $20 million decrease is primarily due to lower loss accruals associated with the 2020 Wildfires and lower benefit from the effects of ratemaking, partially offset by higher PTCs from PacifiCorp's wind-powered generating facilities.

Liquidity and Capital Resources

Overview

PacifiCorp's liquidity has been materially impacted by the Wildfires, and it may be unable to maintain sufficient levels of cash or obtain necessary short- and long-term financing to fund its operations, implement its business strategy, make interest payments, make scheduled repayments of long-term debt, finance its capital investments and fund potential future settlements associated with the Wildfires. To help mitigate PacifiCorp's liquidity pressures, BHE has indicated that it will suspend dividends for the next several years in order to allow PacifiCorp to accumulate cash that may be necessary in the event of additional future settlements associated with the Wildfires.

Additionally, to the extent PacifiCorp is unable to obtain additional surety bonds in the event of further unfavorable trial verdicts associated with the Wildfires, it may be required to post letters of credit or cash to secure such judgments. Such requirements could further reduce PacifiCorp's liquidity and availability under its revolving credit facility as further described in the "Potential Effects of James CMO No. 11" section in Note 10 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q. PacifiCorp believes it will have sufficient liquidity to cover its operations and obligations beyond a year.

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As of September 30, 2025, PacifiCorp's total net liquidity was as follows (in millions):

Cash and cash equivalents						$	46
Credit facilities(1)						2,900
Less:
Short-term debt						(75)
Tax-exempt bond support and letters of credit						(52)
Net credit facility						2,773
Total net liquidity						$	2,819
Maturity dates						2026, 2028

(1)Refer to "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, 2025 and 2024 were $1,757 million and $671 million, respectively. The increase is primarily due to lower wholesale purchases, higher collections from retail customers and lower cash paid for wildfire liability settlement payments, partially offset by lower insurance reimbursements related to wildfire liabilities and higher cash paid for income taxes and interest.

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, 2025 and 2024 were $(2,171) million and $(2,150) million, respectively. The change is primarily due to an increase in capital expenditures of $22 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, 2025, were $418 million. Sources of cash consisted of net proceeds from the issuance of junior subordinated notes of $841 million. Uses of cash consisted primarily of $250 million for the repayment of long-term debt and $165 million for the repayment of short-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, 2024, were $1.7 billion. Sources of cash consisted of net proceeds from the issuance of long‑term debt of $3.8 billion. 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.

Short-term Debt

Regulatory authorities limit PacifiCorp to $3.0 billion of short-term debt. As of September 30, 2025, PacifiCorp had $75 million of short-term debt outstanding at a weighted average rate of 4.38%. As of December 31, 2024, PacifiCorp had $240 million of short-term debt outstanding at a weighted average rate of 4.65%.

Long-term Debt Authorizations

PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $4.15 billion of long-term debt. PacifiCorp's authorization from the IPUC is through April 2029. PacifiCorp must make a notice filing with the WUTC prior to any future 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.

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Credit Facilities and Letters of Credit

In June 2025, PacifiCorp amended its existing $2.0 billion unsecured credit facility expiring in June 2027. The amendment extended the expiration date to June 2028 and amended certain provisions of the existing credit agreement. As of September 30, 2025, PacifiCorp had no letters of credit outstanding under its $2.0 billion revolving credit facility and had an additional $59 million of letters of credit outstanding in support of certain transactions required by third parties.

In June 2025, PacifiCorp amended its existing $900 million 364‑day unsecured credit facility expiring in June 2025. The amendment extended the expiration date to June 2026 and amended certain provisions of the existing credit agreement. As of September 30, 2025, PacifiCorp's $900 million 364‑day unsecured credit facility was fully available.

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 depend 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, including the impacts of the recent James case management order on PacifiCorp's liquidity; changes in income tax laws; general business conditions; new customer requests; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

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

			Nine-Month Periods												Annual
			Ended September 30,												Forecast
			2024						2025						2025
Electric distribution			$	567					$	569					$	801
Electric transmission			612						472						714
Wildfire prevention			264						591						689
Wind generation			268						184						228
Other			446						363						619
Total			$	2,157					$	2,179					$	3,051

PacifiCorp's historical and forecast capital expenditures include the following:

•Electric distribution includes both growth projects and operating expenditures. Growth expenditures include spending on new customer connections totaling $243 million and $253 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending for new customer connections totals $127 million for the remainder of 2025. The remaining investments primarily relate to expenditures for distribution operations.

•Electric transmission includes both growth projects and operating expenditures. Transmission growth primarily reflects costs associated with major transmission projects totaling $153 million and $376 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending for major transmission projects that are expected to be placed in‑service through 2034 totals $104 million for the remainder of 2025.

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•Wildfire prevention includes operating expenditures totaling $591 million and $264 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending for wildfire prevention totals $98 million for the remainder of 2025.

•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 $165 million and $249 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending for the construction of additional wind‑powered generating facilities and those at acquired sites totals $35 million for the remainder of 2025 and is primarily for the Rock Creek I and Rock Creek II wind‑powered generating facilities totaling approximately 529 MWs that are expected to be placed in‑service in 2025.

•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $96 million and $125 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned information technology spending totals $56 million for the remainder of 2025. The remaining investments relate to operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing and expected demand.

Energy Supply Planning

As required by certain state regulations, PacifiCorp uses an IRP to develop a long-term resource plan to ensure that PacifiCorp can continue to provide reliable and cost-effective electric service to its customers while maintaining compliance with existing and evolving environmental laws and regulations. PacifiCorp files its IRP biennially with the state commissions in each of the six states where PacifiCorp operates. Five states indicate whether the IRP meets the state commission's IRP standards and guidelines, a process referred to as "acknowledgment" in some states. Acknowledgment by a state commission does not address cost recovery or prudency of resources ultimately selected.

In March 2025, PacifiCorp filed its 2025 IRP in Utah, Oregon, Wyoming, Washington, Idaho and California. The 2025 IRP highlights a need for investment in transmission infrastructure, renewable solar and wind resources, new energy storage, conversion of coal-fueled generating units to natural gas, demand response and energy efficiency programs and carbon capture technology.

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.

In April 2025, PacifiCorp filed an expedited application with the OPUC seeking approval to issue to market an RFP for new generating and energy storage resources that will serve Oregon customers and be recovered through Oregon retail rates. In May 2025, the OPUC issued an order for a partial waiver of competitive bidding rules but still requiring PacifiCorp to go through the formal approval process. The OPUC approved the RFP in August 2025, with certain conditions. Those conditions were satisfied in October 2025, when it was issued to market.

In June 2025, PacifiCorp filed an expedited application with the WUTC seeking approval to issue to market an RFP for new generating and energy storage resources that will serve Washington customers and be recovered through Washington retail rates. The WUTC approved the RFP in August 2025, and it was issued to market in September 2025.

Material Cash Requirements

As of September 30, 2025, 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, 2024, other than those disclosed in Notes 5 and 10 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Regulatory Matters

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

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Environmental Laws and Regulations

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

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

Collateral and Contingent Features

Debt securities of PacifiCorp are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of PacifiCorp's ability to, in general, meet the obligations of its issued debt securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. As of September 30, 2025, PacifiCorp's issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.

PacifiCorp has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt and a change in ratings is not an event of default under the applicable debt instruments. PacifiCorp's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities. Certain authorizations or exemptions by regulatory commissions for the issuance of securities are valid as long as PacifiCorp maintains investment grade ratings on senior secured debt. A downgrade below that level would necessitate new regulatory applications and approvals.

In accordance with industry practice, certain wholesale energy agreements, including contracts for purchases, sales, and transportation of electricity, natural gas, and coal, some of which are accounted for as derivatives, 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. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of September 30, 2025, PacifiCorp would have been required to post $187 million of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, outstanding accounts payable and receivable or other factors. Refer to Note 8 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for a discussion of PacifiCorp's collateral requirements specific to PacifiCorp's derivative contracts.

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, 2024. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2024. Refer to Note 10 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for discussion of loss contingencies related to the Wildfires.

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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, 2025, the related statements of operations, and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2025 and 2024, and of cash flows for the nine-month periods ended September 30, 2025 and 2024, 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, 2024, 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 21, 2025, 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, 2024, 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

October 31, 2025

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MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)

			As of
			September 30,						December 31,
			2025						2024
ASSETS
Current assets:
Cash and cash equivalents			$	933					$	549
Trade receivables, net			457						230
Income tax receivable			—						2
Inventories			314						369
Prepayments			128						117
Other current assets			66						63
Total current assets			1,898						1,330
Property, plant and equipment, net			23,246						22,765
Regulatory assets			663						622
Investments and restricted investments			1,253						1,147
Other assets			249						252
Total assets			$	27,309					$	26,116

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,
			2025						2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable			$	386					$	375
Accrued interest			92						117
Accrued property, income and other taxes			261						192
Current portion of long-term debt			4						17
Other current liabilities			148						91
Total current liabilities			891						792
Long-term debt			8,810						8,807
Regulatory liabilities			1,320						1,264
Deferred income taxes			3,721						3,626
Asset retirement obligations			851						823
Other long-term liabilities			718						623
Total liabilities			16,311						15,935
Commitments and contingencies (Note 9)
Shareholder's equity:
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding			—						—
Additional paid-in capital			561						561
Retained earnings			10,437						9,620
Total shareholder's equity			10,998						10,181
Total liabilities and shareholder's equity			$	27,309					$	26,116

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,
			2025						2024						2025						2024
Operating revenue:
Regulated electric			$	1,026					$	814					$	2,436					$	2,014
Regulated natural gas and other			100						93						564						466
Total operating revenue			1,126						907						3,000						2,480
Operating expenses:
Cost of fuel and energy			266						136						543						326
Cost of natural gas purchased for resale and other			43						37						346						254
Operations and maintenance			241						230						703						696
Depreciation and amortization			209						230						771						685
Property and other taxes			45						40						133						124
Total operating expenses			804						673						2,496						2,085
Operating income			322						234						504						395
Other income (expense):
Interest expense			(100)						(106)						(301)						(315)
Allowance for borrowed funds			9						8						24						21
Allowance for equity funds			23						19						62						53
Other, net			22						25						50						69
Total other income (expense)			(46)						(54)						(165)						(172)
Income before income tax expense (benefit)			276						180						339						223
Income tax expense (benefit)			(65)						(160)						(479)						(592)
Net income			$	341					$	340					$	818					$	815

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, 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
Balance, June 30, 2025			$	—					$	561					$	10,097					$	10,658
Net income			—						—						341						341
Other equity transactions			—						—						(1)						(1)
Balance, September 30, 2025			$	—					$	561					$	10,437					$	10,998
Balance, December 31, 2024			$	—					$	561					$	9,620					$	10,181
Net income			—						—						818						818
Other equity transactions			—						—						(1)						(1)
Balance, September 30, 2025			$	—					$	561					$	10,437					$	10,998

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,
			2025						2024
Cash flows from operating activities:
Net income			$	818					$	815
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization			771						685
Amortization of utility plant to other operating expenses			27						26
Allowance for equity funds			(62)						(53)
Deferred income taxes and investment tax credits, net			65						84
Other, net			(37)						(22)
Changes in other operating assets and liabilities:
Trade receivables and other assets			(231)						(9)
Inventories			55						(21)
Accrued property, income and other taxes, net			67						31
Accounts payable and other liabilities			(4)						(167)
Net cash flows from operating activities			1,469						1,369
Cash flows from investing activities:
Capital expenditures			(1,210)						(1,100)
Purchases of marketable securities			(340)						(234)
Proceeds from sales of marketable securities			339						224
Other, net			5						10
Net cash flows from investing activities			(1,206)						(1,100)
Cash flows from financing activities:
Common stock dividends			—						(425)
Proceeds from long-term debt			—						592
Repayments of long-term debt			(16)						(2)
Other, net			137						(2)
Net cash flows from financing activities			121						163
Net change in cash and cash equivalents and restricted cash and cash equivalents			384						432
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period			555						642
Cash and cash equivalents and restricted cash and cash equivalents at end of period			$	939					$	1,074

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 headquartered in Iowa, that has investments in subsidiaries principally engaged in energy businesses. BHE is a wholly owned 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, 2025, and for the three- and nine-month periods ended September 30, 2025 and 2024. The results of operations for the three- and nine-month periods ended September 30, 2025, 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, 2024, 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, 2025.

(2)    New Accounting Pronouncements

In December 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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.

In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures Subtopic 220-40, "Disaggregation of Income Statement Expenses" which addresses requests from investors for more detailed information about certain expenses and requires disclosure of the amounts of purchases of inventory, employee compensation, depreciation and intangible asset amortization included in each relevant expense caption presented on the income statement. This guidance, as clarified in ASU 2025-01, is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. 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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(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,
			2025						2024
Cash and cash equivalents			$	933					$	549
Restricted cash and cash equivalents in other current assets			6						6
Total cash and cash equivalents and restricted cash and cash equivalents			$	939					$	555

(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						2025						2024
Utility plant:
Generation			20-62 years						$	17,908					$	18,446
Transmission			55-80 years						3,038						3,029
Electric distribution			15-80 years						6,280						5,890
Natural gas distribution			30-75 years						2,447						2,413
Utility plant in-service									29,673						29,778
Accumulated depreciation and amortization									(8,500)						(8,572)
Utility plant in-service, net									21,173						21,206
Nonregulated, net of accumulated depreciation and amortization			20-50 years						6						6
									21,179						21,212
Construction work-in-progress									2,067						1,553
Property, plant and equipment, net									$	23,246					$	22,765

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, 2025 and 2024, $38 million and $— million, respectively, is reflected in depreciation and amortization expense on the Statements of Operations.

(5)    Recent Financing Transactions

Credit Facilities

In June 2025, MidAmerican Energy amended its existing $1.5 billion unsecured credit facility expiring in June 2027. The amendment extended the expiration date to June 2028 and amended certain provisions of the existing credit agreement.

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(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,
			2025						2024						2025						2024
Federal statutory income tax rate			21		%				21		%				21		%				21		%
Income tax credits			(42)						(94)						(160)						(270)
State income tax, net of federal income tax impacts			(1)						(9)						(1)						(9)
Effects of ratemaking			(1)						(6)						(1)						(5)
Other, net			(1)						(1)						—						(2)
Effective income tax rate			(24)		%				(89)		%				(141)		%				(265)		%

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, 2025 and 2024, totaled $547 million and $602 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 $634 million and $736 million for the nine-month periods ended September 30, 2025 and 2024, respectively.

(7)    Employee Benefit Plans

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

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

			Three-Month Periods												Nine-Month Periods
			Ended September 30,												Ended September 30,
			2025						2024						2025						2024
Pension:
Service cost			$	2					$	2					$	6					$	7
Interest cost			7						7						23						23
Expected return on plan assets			(7)						(8)						(23)						(24)
Net amortization			—						1						—						—
Net periodic benefit cost			$	2					$	2					$	6					$	6
Other postretirement:
Service cost			$	1					$	2					$	3					$	4
Interest cost			3						3						9						9
Expected return on plan assets			(5)						(4)						(14)						(12)
Net amortization			(1)						—						(2)						1
Net periodic benefit (credit) cost			$	(2)					$	1					$	(4)					$	2

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 2025 are expected to be $7 million and $1 million, respectively. As of September 30, 2025, $5 million and $1 million of contributions had been made to the pension and other postretirement benefit plans, respectively.

(8)    Fair Value Measurements

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

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

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

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

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

						Input Levels for Fair Value Measurements
						Level 1						Level 2						Level 3						Other(1)						Total
As of September 30, 2025:
Assets:
Commodity derivatives						$	—					$	7					$	1					$	(3)					$	5
Money market mutual funds						876						—						—						—						876
Debt securities:
U.S. government obligations						278						—						—						—						278
Corporate obligations						—						128						—						—						128
Municipal obligations						—						2						—						—						2
Equity securities:
U.S. companies						539						—						—						—						539
International companies						9						—						—						—						9
Investment funds						20						—						—						—						20
						$	1,722					$	137					$	1					$	(3)					$	1,857
Liabilities:
Commodity derivatives						$	—					$	(12)					$	(5)					$	7					$	(10)

						Input Levels for Fair Value Measurements
						Level 1						Level 2						Level 3						Other(1)						Total
As of December 31, 2024:
Assets:
Commodity derivatives						$	—					$	5					$	1					$	(3)					$	3
Money market mutual funds						538						—						—						—						538
Debt securities:
U.S. government obligations						271						—						—						—						271
Corporate obligations						—						109						—						—						109
Municipal obligations						—						2						—						—						2
Equity securities:
U.S. companies						479						—						—						—						479
International companies						9						—						—						—						9
Investment funds						23						—						—						—						23
						$	1,320					$	116					$	1					$	(3)					$	1,434
Liabilities:
Commodity derivatives						$	—					$	(15)					$	(3)					$	6					$	(12)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $4 million and $3 million as of September 30, 2025, and December 31, 2024, 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.

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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,
			2025						2024						2025						2024
Beginning balance			$	—					$	(2)					$	(2)					$	(11)
Changes in fair value recognized in net regulatory assets			(6)						(11)						(6)						(17)
Settlements			2						5						4						20
Ending balance			$	(4)					$	(8)					$	(4)					$	(8)

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, 2025												As of December 31, 2024
			Carrying Value						Fair Value						Carrying Value						Fair Value
Long-term debt			$	8,814					$	8,130					$	8,824					$	7,911

(9)    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, 2025, MidAmerican Energy entered into firm construction commitments totaling $73 million for the remainder of 2025 through 2028 related to the construction of wind-powered, solar-powered and other new generating facilities in Iowa.

In October 2025, MidAmerican Energy entered into firm construction commitments totaling $531 million for the remainder of 2025 through 2029 related to the construction of wind-powered, solar-powered and other new 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.

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(10)    Revenue from Contracts with Customers

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

			For the Three-Month Period Ended September 30, 2025																								For the Nine-Month Period Ended September 30, 2025
			Electric						Natural Gas						Other						Total						Electric						Natural Gas						Other						Total
Customer Revenue:
Retail:
Residential			$	279					$	55					$	—					$	334					$	637					$	324					$	—					$	961
Commercial			121						17						—						138						290						119						—						409
Industrial			444						5						—						449						1,020						19						—						1,039
Natural gas transportation services			—						12						—						12						—						39						—						39
Other retail			50						1						—						51						126						3						—						129
Total retail			894						90						—						984						2,073						504						—						2,577
Wholesale			109						9						—						118						266						56						—						322
Multi-value transmission projects			14						—						—						14						41						—						—						41
Other Customer Revenue			—						—						—						—						—						—						3						3
Total Customer Revenue			1,017						99						—						1,116						2,380						560						3						2,943
Other revenue			9						1						—						10						56						1						—						57
Total operating revenue			$	1,026					$	100					$	—					$	1,126					$	2,436					$	561					$	3					$	3,000

			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

(11)    Segment Information

MidAmerican Energy's chief operating decision maker ("CODM") is its President and Chief Executive Officer. Net income for each reportable segment is considered by the CODM in allocating resources and capital. The CODM generally considers actual results versus historical results, budgets or forecasts, as well as unique risks and opportunities, when making decisions about the allocation of resources and capital to each reportable segment.

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MidAmerican Energy 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 regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs 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):

			For the Three-Month Period Ended September 30, 2025
			Electric						Natural Gas						Other(1)						Total
Operating revenue			$	1,026					$	100					$	—					$	1,126
Cost of sales			266						43						—						309
Operations and maintenance			205						36						—						241
Depreciation and amortization			191						18						—						209
Property and other taxes			41						4						—						45
Operating income			323						(1)						—						322
Interest expense			(92)						(8)						—						(100)
Interest and dividend income			9						1						—						10
Income tax expense (benefit)			(62)						(2)						(1)						(65)
Other segment items(2)			40						4						—						44
Net income (loss)			$	342					$	(2)					$	1					$	341
Capital expenditures			$	435					$	35					$	—					$	470

			For the Nine-Month Period Ended September 30, 2025
			Electric						Natural Gas						Other(1)						Total
Operating revenue			$	2,436					$	561					$	3					$	3,000
Cost of sales			543						345						1						889
Operations and maintenance			599						103						1						703
Depreciation and amortization			719						52						—						771
Property and other taxes			122						11						—						133
Operating income			453						50						1						504
Interest expense			(278)						(23)						—						(301)
Interest and dividend income			22						2						—						24
Income tax expense (benefit)			(488)						8						1						(479)
Other segment items(2)			104						10						(2)						112
Net income (loss)			$	789					$	31					$	(2)					$	818
Capital expenditures			$	1,118					$	91					$	1					$	1,210

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			For the Three-Month Period Ended September 30, 2024
			Electric						Natural Gas						Other(1)						Total
Operating revenue			$	814					$	91					$	2					$	907
Cost of sales			136						37						—						173
Operations and maintenance			190						39						1						230
Depreciation and amortization			214						16						—						230
Property and other taxes			37						3						—						40
Operating income			237						(4)						1						234
Interest expense			(98)						(8)						—						(106)
Interest and dividend income			12						1						—						13
Income tax expense (benefit)			(153)						(3)						(4)						(160)
Other segment items(2)			33						6						—						39
Net income (loss)			$	337					$	(2)					$	5					$	340
Capital expenditures			$	344					$	18					$	—					$	362

			For the Nine-Month Period Ended September 30, 2024
			Electric						Natural Gas						Other(1)						Total
Operating revenue			$	2,014					$	462					$	4					$	2,480
Cost of sales			326						254						—						580
Operations and maintenance			592						103						1						696
Depreciation and amortization			636						49						—						685
Property and other taxes			113						11						—						124
Operating income			347						45						3						395
Interest expense			(292)						(23)						—						(315)
Interest and dividend income			29						3						—						32
Income tax expense (benefit)			(597)						6						(1)						(592)
Other segment items(2)			105						10						(4)						111
Net income (loss)			$	786					$	29					$	—					$	815
Capital expenditures			$	1,038					$	61					$	1					$	1,100

			As of
			September 30,						December 31,
			2025						2024
Assets:
Regulated electric			$	25,260					$	24,159
Regulated natural gas			2,048						1,956
Other(1)			1						1
Total assets			$	27,309					$	26,116

(1)The differences between the reportable segment amounts and the consolidated amounts, described as Other, relate to nonregulated activities of MidAmerican Energy.

(2)Other segment items include allowance for borrowed and equity funds, gains (losses) on marketable securities and other income (expense).

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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, 2025, the related consolidated statements of operations, and changes in member's equity for the three-month and nine-month periods ended September 30, 2025 and 2024, and of cash flows for the nine-month periods ended September 30, 2025 and 2024, 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, 2024, 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 21, 2025, 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, 2024, 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

October 31, 2025

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MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

			As of
			September 30,						December 31,
			2025						2024
ASSETS
Current assets:
Cash and cash equivalents			$	934					$	552
Trade receivables, net			457						230
Income tax receivable			—						2
Inventories			314						369
Prepayments			128						117
Other current assets			66						62
Total current assets			1,899						1,332
Property, plant and equipment, net			23,247						22,766
Goodwill			1,270						1,270
Regulatory assets			663						622
Investments and restricted investments			1,254						1,149
Other assets			249						251
Total assets			$	28,582					$	27,390

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

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MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

			As of
			September 30,						December 31,
			2025						2024
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable			$	385					$	375
Accrued interest			93						122
Accrued property, income and other taxes			261						192
Note payable to affiliate			26						13
Current portion of long-term debt			4						17
Other current liabilities			148						92
Total current liabilities			917						811
Long-term debt			9,050						9,047
Regulatory liabilities			1,320						1,264
Deferred income taxes			3,719						3,624
Asset retirement obligations			851						823
Other long-term liabilities			718						622
Total liabilities			16,575						16,191
Commitments and contingencies (Note 9)
Member's equity:
Paid-in capital			1,679						1,679
Retained earnings			10,328						9,520
Total member's equity			12,007						11,199
Total liabilities and member's equity			$	28,582					$	27,390

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

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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,
			2025						2024						2025						2024
Operating revenue:
Regulated electric			$	1,026					$	814					$	2,436					$	2,014
Regulated natural gas and other			100						93						564						466
Total operating revenue			1,126						907						3,000						2,480
Operating expenses:
Cost of fuel and energy			266						136						543						326
Cost of natural gas purchased for resale and other			43						37						346						254
Operations and maintenance			241						230						704						696
Depreciation and amortization			209						230						771						685
Property and other taxes			45						40						133						124
Total operating expenses			804						673						2,497						2,085
Operating income			322						234						503						395
Other income (expense):
Interest expense			(104)						(109)						(314)						(327)
Allowance for borrowed funds			9						8						24						21
Allowance for equity funds			23						19						62						53
Other, net			21						23						50						68
Total other income (expense)			(51)						(59)						(178)						(185)
Income before income tax expense (benefit)			271						175						325						210
Income tax expense (benefit)			(66)						(162)						(483)						(596)
Net income			$	337					$	337					$	808					$	806

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

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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, 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
Balance, June 30, 2025			$	1,679					$	9,990					$	11,669
Net income			—						337						337
Other equity transactions			—						1						1
Balance, September 30, 2025			$	1,679					$	10,328					$	12,007
Balance, December 31, 2024			$	1,679					$	9,520					$	11,199
Net income			—						808						808
Balance, September 30, 2025			$	1,679					$	10,328					$	12,007

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,
			2025						2024
Cash flows from operating activities:
Net income			$	808					$	806
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization			771						685
Amortization of utility plant to other operating expenses			27						26
Allowance for equity funds			(62)						(53)
Deferred income taxes and investment tax credits, net			65						84
Other, net			(36)						(22)
Changes in other operating assets and liabilities:
Trade receivables and other assets			(231)						(9)
Inventories			55						(21)
Accrued property, income and other taxes, net			67						32
Accounts payable and other liabilities			(10)						(173)
Net cash flows from operating activities			1,454						1,355
Cash flows from investing activities:
Capital expenditures			(1,210)						(1,100)
Purchases of marketable securities			(340)						(234)
Proceeds from sales of marketable securities			339						224
Other, net			5						10
Net cash flows from investing activities			(1,206)						(1,100)
Cash flows from financing activities:
Distribution to member			—						(425)
Proceeds from long-term debt			—						592
Repayments of long-term debt			(16)						(2)
Net change in note payable to affiliate			13						13
Other, net			137						(2)
Net cash flows from financing activities			134						176
Net change in cash and cash equivalents and restricted cash and cash equivalents			382						431
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period			558						643
Cash and cash equivalents and restricted cash and cash equivalents at end of period			$	940					$	1,074

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

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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 headquartered in Iowa, that has investments in subsidiaries principally engaged in energy businesses. BHE is a wholly owned 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, 2025, and for the three- and nine-month periods ended September 30, 2025 and 2024. The results of operations for the three- and nine-month periods ended September 30, 2025, 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, 2024, 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, 2025.

(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,
			2025						2024
Cash and cash equivalents			$	934					$	552
Restricted cash and cash equivalents in other current assets			6						6
Total cash and cash equivalents and restricted cash and cash equivalents			$	940					$	558

(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,
			2025						2024						2025						2024
Federal statutory income tax rate			21		%				21		%				21		%				21		%
Income tax credits			(43)						(96)						(167)						(287)
State income tax, net of federal income tax impacts			(1)						(9)						(1)						(10)
Effects of ratemaking			(1)						(6)						(1)						(5)
Other, net			—						(3)						(1)						(3)
Effective income tax rate			(24)		%				(93)		%				(149)		%				(284)		%

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, 2025 and 2024, totaled $547 million and $602 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 $637 million and $739 million for the nine-month periods ended September 30, 2025 and 2024, respectively.

(7)    Employee Benefit Plans

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

(8)    Fair Value Measurements

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

			As of September 30, 2025												As of December 31, 2024
			Carrying Value						Fair Value						Carrying Value						Fair Value
Long-term debt			$	9,054					$	8,387					$	9,064					$	8,166

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(9)    Commitments and Contingencies

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

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

(10)    Revenue from Contracts with Customers

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

(11)    Segment Information

MidAmerican Funding's chief operating decision maker ("CODM") is its President. Net income for each reportable segment is considered by the CODM in allocating resources and capital. The CODM generally considers actual results versus historical results, budgets or forecasts, as well as unique risks and opportunities, when making decisions about the allocation of resources and capital to each reportable segment.

MidAmerican Funding 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 regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs 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):

			For the Three-Month Period Ended September 30, 2025
			Electric						Natural Gas						Other(1)						Total
Operating revenue			$	1,026					$	100					$	—					$	1,126
Cost of sales			266						43						—						309
Operations and maintenance			205						36						—						241
Depreciation and amortization			191						18						—						209
Property and other taxes			41						4						—						45
Operating income (loss)			323						(1)						—						322
Interest expense			(92)						(8)						(4)						(104)
Interest and dividend income			9						1						—						10
Income tax expense (benefit)			(62)						(2)						(2)						(66)
Other segment items(2)			40						4						(1)						43
Net income (loss)			$	342					$	(2)					$	(3)					$	337
Capital expenditures			$	435					$	35					$	—					$	470

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			For the Nine-Month Period Ended September 30, 2025
			Electric						Natural Gas						Other(1)						Total
Operating revenue			$	2,436					$	561					$	3					$	3,000
Cost of sales			543						345						1						889
Operations and maintenance			599						103						2						704
Depreciation and amortization			719						52						—						771
Property and other taxes			122						11						—						133
Operating income			453						50						—						503
Interest expense			(278)						(23)						(13)						(314)
Interest and dividend income			22						2						—						24
Income tax expense (benefit)			(488)						8						(3)						(483)
Other segment items(2)			104						10						(2)						112
Net income (loss)			$	789					$	31					$	(12)					$	808
Capital expenditures			$	1,118					$	91					$	1					$	1,210

			For the Three-Month Period Ended September 30, 2024
			Electric						Natural Gas						Other(1)						Total
Operating revenue			$	814					$	91					$	2					$	907
Cost of sales			136						37						—						173
Operations and maintenance			190						39						1						230
Depreciation and amortization			214						16						—						230
Property and other taxes			37						3						—						40
Operating income			237						(4)						1						234
Interest expense			(98)						(8)						(3)						(109)
Interest and dividend income			12						1						—						13
Income tax expense (benefit)			(153)						(3)						(6)						(162)
Other segment items(2)			33						6						(2)						37
Net income (loss)			$	337					$	(2)					$	2					$	337
Capital expenditures			$	344					$	18					$	—					$	362

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			For the Nine-Month Period Ended September 30, 2024
			Electric						Natural Gas						Other(1)						Total
Operating revenue			$	2,014					$	462					$	4					$	2,480
Cost of sales			326						254						—						580
Operations and maintenance			592						103						1						696
Depreciation and amortization			636						49						—						685
Property and other taxes			113						11						—						124
Operating income			347						45						3						395
Interest expense			(292)						(23)						(12)						(327)
Interest and dividend income			29						3						—						32
Income tax expense (benefit)			(597)						6						(5)						(596)
Other segment items(2)			105						10						(5)						110
Net income (loss)			$	786					$	29					$	(9)					$	806
Capital expenditures			$	1,038					$	61					$	1					$	1,100

			As of
			September 30,						December 31,
			2025						2024
Assets:
Regulated electric			$	26,451					$	25,350
Regulated natural gas			2,127						2,035
Other(1)			4						5
Total assets			$	28,582					$	27,390
Goodwill:
Regulated electric			$	1,191					$	1,191
Regulated natural gas			79						79
Total goodwill			$	1,270					$	1,270

(1)The differences between the reportable segment amounts and the consolidated amounts, described as Other, consists of the nonregulated subsidiaries of MidAmerican Funding not engaged in the energy business.

(2)Other segment items include allowance for borrowed and equity funds, gains (losses) on marketable securities and other income (expense).

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

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

Results of Operations for the Third Quarter and First Nine Months of 2025 and 2024

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the third quarter of 2025 was $341 million, an increase of $1 million, or 0.3%, compared to 2024, primarily due to higher electric utility margin, decreased depreciation and amortization expense, lower interest expense, and higher allowances for equity and borrowed funds used during construction, partially offset by an unfavorable income tax benefit, increased operations and maintenance expense and higher property and other taxes. Electric utility margin increased primarily due to higher electric retail customer usage, higher recoveries through bill riders, the favorable impact of weather and higher wholesale margin. Electric retail customer volumes increased 11.3% primarily due to higher customer usage for certain industrial customers and the favorable impact of weather. Wholesale electricity sales volumes increased 12% due to favorable market conditions. Energy generated increased 5% primarily due to higher coal-fueled generation, partially offset by lower renewable-powered generation. Energy purchased volumes increased 61% primarily due to the increase in total sales of 11% with only a 5% increase in energy generated. Natural gas retail customer volumes increased 11% due to higher sales to industrial customers.

MidAmerican Energy's net income for the first nine months of 2025 was $818 million, an increase of $3 million, or 0.4%, compared to 2024, primarily due to higher electric utility margin, lower interest expense, higher allowances for equity and borrowed funds used during construction and higher natural gas utility margin, partially offset by an unfavorable income tax benefit, increased depreciation and amortization expense, higher property and other taxes, lower interest income, unfavorable changes in the cash surrender value of corporate-owned life insurance policies and higher operations and maintenance expense. Electric utility margin increased primarily due to higher electric retail customer usage, higher wholesale margin, the favorable impact of weather and higher recoveries through bill riders, partially offset by lower wind-turbine performance settlements and price impacts from changes in sales mix. Natural gas utility margin increased primarily due to the favorable impact of weather, partially offset by lower base rates. Electric retail customer volumes increased 9.8% primarily due to higher customer usage for certain industrial customers and the favorable impact of weather. Wholesale electricity sales volumes increased 3% due to favorable market conditions. Energy generated increased 5% primarily due to higher coal-fueled generation, partially offset by lower renewable-powered generation and natural gas-fueled generation. Energy purchased volumes increased 30% primarily due to the increase in total sales of 8% with only a 5% increase in energy generated. Natural gas retail customer volumes increased 14% due to higher sales to customers and the favorable impact of weather.

MidAmerican Funding -

MidAmerican Funding's net income for the third quarter of 2025 was $337 million, which was equal to 2024. MidAmerican Funding's net income for the first nine months of 2025 was $808 million, an increase of $2 million, or 0.2%, compared to 2024. The variance in net income was primarily due to the changes in MidAmerican Energy's earnings discussed above.

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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 expenses 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 results of operations 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 understanding 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
						2025						2024						Change									2025						2024						Change
Electric utility margin:
Operating revenue						$	1,026					$	814					$	212		26		%				$	2,436					$	2,014					$	422		21		%
Cost of fuel and energy						266						136						130			96						543						326						217			67
Electric utility margin						760						678						82			12		%				1,893						1,688						205			12		%
Natural gas utility margin:
Operating revenue						100						91						9			10		%				561						462						99			21		%
Natural gas purchased for resale						43						37						6			16						345						254						91			36
Natural gas utility margin						57						54						3			6		%				216						208						8			4		%
Utility margin						817						732						85			12		%				2,109						1,896						213			11		%
Other operating revenue						—						2						(2)			100		%				3						4						(1)			(25)		%
Other cost of sales						—						—						—			*						1						—						1			*
Operations and maintenance						241						230						11			5						703						696						7			1
Depreciation and amortization						209						230						(21)			(9)						771						685						86			13
Property and other taxes						45						40						5			13						133						124						9			7
Operating income						$	322					$	234					$	88		38		%				$	504					$	395					$	109		28		%

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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
			2025						2024						Change												2025						2024						Change
Utility margin (in millions):
Operating revenue			$	1,026					$	814					$	212					26		%				$	2,436					$	2,014					$	422					21		%
Cost of fuel and energy			266						136						130						96						543						326						217						67
Utility margin			$	760					$	678					$	82					12		%				$	1,893					$	1,688					$	205					12		%
Sales (GWhs):
Residential			2,171						2,010						161						8		%				5,529						5,207						322						6		%
Commercial			1,108						1,053						55						5						3,098						2,962						136						5
Industrial			5,141						4,471						670						15						14,859						13,144						1,715						13
Other			455						441						14						3						1,291						1,250						41						3
Total retail			8,875						7,975						900						11						24,777						22,563						2,214						10
Wholesale			2,293						2,044						249						12						10,229						9,893						336						3
Total sales			11,168						10,019						1,149						11		%				35,006						32,456						2,550						8		%
Average number of retail customers (in thousands)			839						830						9						1		%				837						828						9						1		%
Average revenue per MWh:
Retail			$	100.79					$	92.02					$	8.77					10		%				$	83.65					$	79.71					$	3.94					5		%
Wholesale			$	45.58					$	25.09					$	20.49					82		%				$	27.82					$	13.44					$	14.38					107		%
Heating degree days			44						22						22						100		%				3,636						3,127						509						16		%
Cooling degree days			802						772						30						4		%				1,156						1,154						2						—		%
Sources of energy (GWhs)(1):
Wind, solar and hydroelectric(2)			3,785						4,262						(477)						(11)		%				18,615						19,243						(628)						(3)		%
Coal			4,073						3,148						925						29						8,632						6,125						2,507						41
Nuclear			998						999						(1)						—						2,749						2,860						(111)						(4)
Natural gas			838						845						(7)						(1)						1,527						1,766						(239)						(14)
Total energy generated			9,694						9,254						440						5						31,523						29,994						1,529						5
Energy purchased			1,631						1,014						617						61						3,905						3,005						900						30
Total			11,325						10,268						1,057						10		%				35,428						32,999						2,429						7		%
Average cost of energy per MWh:
Energy generated(3)			$	11.74					$	8.55					$	3.19					37		%				$	7.90					$	5.69					$	2.21					39		%
Energy purchased			$	93.34					$	56.34					$	37.00					66		%				$	75.27					$	51.76					$	23.51					45		%

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

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

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

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Natural Gas Utility Margin

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

			Third Quarter																								First Nine Months
			2025						2024						Change												2025						2024						Change
Utility margin (in millions):
Operating revenue			$	100					$	91					$	9					10		%				$	561					$	462					$	99					21		%
Natural gas purchased for resale			43						37						6						16						345						254						91						36
Utility margin			$	57					$	54					$	3					6		%				$	216					$	208					$	8					4		%
Throughput (000's Dths):
Residential			2,635						2,601						34						1		%				33,743						29,683						4,060						14		%
Commercial			1,547						1,517						30						2						16,474						14,521						1,953						13
Industrial			1,314						853						461						54						4,390						3,607						783						22
Other			6						8						(2)						(25)						61						61						—						—
Total retail sales			5,502						4,979						523						11						54,668						47,872						6,796						14
Wholesale sales			3,529						5,044						(1,515)						(30)						17,902						22,304						(4,402)						(20)
Total sales			9,031						10,023						(992)						(10)						72,570						70,176						2,394						3
Natural gas transportation service			28,149						26,811						1,338						5						83,051						80,407						2,644						3
Total throughput			37,180						36,834						346						1		%				155,621						150,583						5,038						3		%
Average number of retail customers (in thousands)			803						798						5						1		%				804						798						6						1		%
Average revenue per retail Dth sold			$	14.28					$	14.16					$	0.12					1		%				$	8.53					$	8.10					$	0.43					5		%
Heating degree days			38						26						12						46		%				3,775						3,261						514						16		%
Average cost of natural gas per retail Dth sold			$	6.30					$	5.80					$	0.50					9		%				$	5.30					$	4.53					$	0.77					17		%
Combined retail and wholesale average cost of natural gas per Dth sold			$	4.88					$	3.74					$	1.14					30		%				$	4.77					$	3.62					$	1.15					32		%

Quarter Ended September 30, 2025, Compared to Quarter Ended September 30, 2024

MidAmerican Energy -

Electric utility margin increased $82 million, or 12%, for the third quarter of 2025 compared to 2024 primarily due to:

•$76 million increase in retail utility margin primarily due to $60 million from higher customer usage, $17 million, net of energy costs, from higher recoveries through bill riders (partially offset in operations and maintenance expense and income tax benefit) and $6 million from the favorable impact of weather, partially offset by $4 million from lower wind-turbine performance settlements and $2 million due to price impacts from changes in sales mix. Retail customer volumes increased 11.3%; and

•$6 million increase in wholesale utility margin due to higher volumes of $7 million, or 12.2%, partially offset by lower margin per unit of $1 million, reflecting lower market prices.

Natural gas utility margin increased $3 million, or 6%, for the third quarter of 2025 compared to 2024 primarily due to:

•$2 million increase from higher base rates.

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Operations and maintenance increased $11 million, or 5%, for the third quarter of 2025 compared to 2024 primarily due to higher electric distribution costs of $13 million and higher other power generation costs of $6 million, partially offset by lower administrative and other costs of $9 million.

Depreciation and amortization decreased $21 million, or 9%, for the third quarter of 2025 compared to 2024 primarily due to $36 million from lower Iowa revenue sharing accruals, partially offset by $8 million related to additional assets placed in-service and $5 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects.

Property and other taxes increased $5 million, or 13%, for the third quarter of 2025 compared to 2024 primarily due to $3 million from higher wind turbine property taxes and $2 million from higher replacement taxes.

Interest expense decreased $6 million, or 6%, for the third quarter of 2025 compared to 2024 primarily due to lower outstanding long-term debt balances.

Allowance for borrowed and equity funds increased $5 million, or 19%, for the third quarter of 2025 compared to 2024 primarily due to higher construction work-in-progress balances related to wind- and solar-powered generation projects.

Other, net decreased $3 million, or 12%, for the third quarter of 2025 compared to 2024 primarily due to $3 million from lower interest and dividend income, partially offset by $3 million from favorable investment earnings, largely attributable to higher cash surrender values of corporate-owned life insurance policies from favorable market performance.

Income tax benefit decreased $95 million, or 59%, for the third quarter of 2025 compared to 2024 primarily due to $51 million of lower PTCs, $34 million from higher pre-tax income and $8 million from a lower accelerated tax depreciation benefit. PTCs for the third quarter of 2025 and 2024 totaled $120 million and $168 million, respectively.

MidAmerican Funding -

Income tax benefit decreased $96 million, or 59%, for the third quarter of 2025 compared to 2024 primarily due to the changes in MidAmerican Energy's income tax benefit discussed above.

First Nine Months of 2025 Compared to First Nine Months of 2024

MidAmerican Energy -

Electric utility margin increased $205 million, or 12%, for the first nine months of 2025 compared to 2024 primarily due to:

•$120 million increase in retail utility margin primarily due to $113 million from higher customer usage, $12 million from the favorable impact of weather and $11 million, net of energy costs, from higher recoveries through bill riders (partially offset in operations and maintenance expense and income tax benefit), partially offset by $9 million from lower wind-turbine performance settlements and $6 million due to price impacts from changes in sales mix. Retail customer volumes increased 9.8%; and

•$86 million increase in wholesale utility margin due to higher margin per unit of $78 million, reflecting higher market prices, and higher volumes of $8 million, or 3.4%.

Natural gas utility margin increased $8 million, or 4%, for the first nine months of 2025 compared to 2024 primarily due to:

•$7 million increase due to the favorable impact of weather; and

•$1 million increase from higher natural gas transportation margin; partially offset by

•$3 million decrease from lower base rates.

Operations and maintenance increased $7 million, or 1%, for the first nine months of 2025 compared to 2024 primarily due to higher electric distribution costs of $21 million, higher steam power generation costs of $16 million, higher gas distribution costs of $9 million, higher transmission costs of $9 million, higher general plant maintenance costs of $4 million and higher other power generation costs of $4 million, partially offset by lower administrative, technology and other costs of $53 million and lower nuclear power generation costs of $7 million.

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Depreciation and amortization increased $86 million, or 13%, for the first nine months of 2025 compared to 2024 primarily due to $38 million from higher Iowa revenue sharing accruals, $25 million related to additional assets placed in-service and $22 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects.

Property and other taxes increased $9 million, or 7%, for the first nine months of 2025 compared to 2024 primarily due to $4 million from higher wind turbine property taxes, $3 million from higher replacement taxes and $2 million from higher real estate taxes.

Interest expense decreased $14 million, or 4%, for the first nine months of 2025 compared to 2024 primarily due to lower outstanding long-term debt balances.

Allowance for borrowed and equity funds increased $12 million, or 16%, for the first nine months of 2025 compared to 2024 primarily due to higher construction work-in-progress balances related to wind- and solar-powered generation projects.

Other, net decreased $19 million, or 28%, for the first nine months of 2025 compared to 2024 primarily due to $8 million from lower interest income and $8 million from unfavorable investment earnings, largely attributable to lower cash surrender values of corporate-owned life insurance policies from unfavorable market performance.

Income tax benefit decreased $113 million, or 19%, for the first nine months of 2025 compared to 2024 primarily due to $55 million of lower PTCs, $39 million from higher pre-tax income and $12 million from a lower accelerated tax depreciation benefit. PTCs for the first nine months of 2025 and 2024 totaled $547 million and $602 million, respectively.

MidAmerican Funding -

Income tax benefit decreased $113 million, or 19%, for the first nine months of 2025 compared to 2024 primarily due to the changes in MidAmerican Energy's income tax benefit discussed above.

Liquidity and Capital Resources

As of September 30, 2025, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):

MidAmerican Energy:
Cash and cash equivalents						$	933
Credit facilities, maturing 2026 and 2028						1,505
Less:
Tax-exempt bond support						(258)
Net credit facilities						1,247
MidAmerican Energy total net liquidity						$	2,180
MidAmerican Funding:
MidAmerican Energy total net liquidity						$	2,180
Cash and cash equivalents						1
MHC, Inc. credit facility, maturing 2026						4
MidAmerican Funding total net liquidity						$	2,185

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On July 4, 2025, the One Big Beautiful Bill Act (the "OBBBA") was enacted, introducing substantial revisions to federal energy-related tax policy. Among its provisions, the OBBBA accelerates the phase-out of clean electricity production and investment tax credits and establishes new sourcing requirements applicable to facilities commencing construction after December 31, 2025. On July 7, 2025, a federal executive order (the "Executive Order") was issued directing the Secretary of the Treasury to promulgate new or revised guidance consistent with applicable law to ensure that policies concerning the "beginning of construction" requirements are not circumvented for wind and solar-powered generating facilities. In response, the U.S. Secretary of the Treasury issued partial guidance on September 2, 2025, through Notice 2025-42. While the guidance largely reaffirmed existing standards, it notably eliminated the five percent safe harbor method for establishing the beginning of construction for projects commencing construction on or after September 2, 2025. MidAmerican Energy is currently evaluating the potential implications of the OBBBA and Notice 2025-42 on its future financial results and will assess its impact on the viability and economics of prospective renewable energy, storage and technology neutral projects.

MidAmerican Energy's future financial performance and capital expenditures related to renewable energy, storage and technology neutral projects may be affected by the combined effects of the OBBBA, the Executive Order, and broader macroeconomic and geopolitical conditions, including changes in international trade policies and tariff regimes. The pace of change in these areas has accelerated during 2025, and significant uncertainty persists regarding the scope and duration of these external factors. Accordingly, MidAmerican Energy is unable to estimate their impact on its business at this time.

Operating Activities

MidAmerican Energy's net cash flows from operating activities for the nine-month periods ended September 30, 2025 and 2024, were $1.5 billion and $1.4 billion, respectively. MidAmerican Funding's net cash flows from operating activities for the nine-month periods ended September 30, 2025 and 2024, were $1.5 billion and $1.4 billion, respectively. Cash flows from operating activities reflect higher collections from electric and natural gas customers and lower payments to vendors, partially offset by higher payments related to fuel and energy costs, lower income tax receipts and higher property tax payments.

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, 2025 and 2024, were $(1.2) billion and $(1.1) billion, respectively. MidAmerican Funding's net cash flows from investing activities for the nine-month periods ended September 30, 2025 and 2024, were $(1.2) billion and $(1.1) billion, 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, 2025 and 2024 were $121 million and $163 million, respectively. MidAmerican Funding's net cash flows from financing activities for the nine-month periods ended September 30, 2025 and 2024, were $134 million and $176 million, respectively. In February 2024, MidAmerican Funding paid $425 million 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. In 2025 and 2024, MidAmerican Energy repaid $16 million and $2 million of long-term debt, respectively. In 2025 and 2024, MidAmerican Funding received $13 million through its note payable with BHE. In 2025, MidAmerican Energy received $138 million of refundable contributions in aid of construction.

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 2028. 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.

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Long-term Debt and Preferred Stock

MidAmerican Energy currently has an effective shelf registration statement filed with the SEC to issue an indeterminate amount of long-term debt securities and preferred stock through October 2028. MidAmerican Energy has authorization from the FERC to issue, through June 30, 2027, long-term debt securities up to an aggregate of $2.5 billion and preferred stock up to an aggregate of $500 million. MidAmerican Energy has authorization from the Illinois Commerce Commission through April 24, 2028, to issue long-term debt securities up to an aggregate of $3.15 billion and preferred stock up to an aggregate of $500 million.

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
			2024						2025						2025
Wind generation			$	341					$	428					$	667
Electric distribution			239						249						340
Electric transmission			170						154						227
Solar generation			1						9						13
Other			349						370						545
Total			$	1,100					$	1,210					$	1,792

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 $182 million and $143 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending for the construction of additional wind-powered generating facilities totals $38 million for the remainder of 2025.

◦Repowering of wind-powered generating facilities totaling $198 million and $169 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending for the repowering of wind-powered generating facilities totals $186 million for the remainder of 2025. 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.

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•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 totaling $9 million and $1 million for the nine-month periods ended September 30, 2025 and 2024, respectively. Planned spending totals $4 million for the remainder of 2025.

•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, 2025, 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, 2024, other than those disclosed in Note 9 of the Notes to Financial Statements in Part I, Item 1 of this Form 10-Q.

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, 2024. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2024.

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Nevada Power Company and its subsidiaries

Consolidated Financial Section

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PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

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, 2025, the related consolidated statements of operations, and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2025 and 2024, and of cash flows for the nine-month periods ended September 30, 2025 and 2024, 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, 2024, 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 21, 2025, 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, 2024, 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

October 31, 2025

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NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)

			As of
			September 30,						December 31,
			2025						2024
ASSETS
Current assets:
Cash and cash equivalents			$	31					$	23
Trade receivables, net			369						314
Inventories			225						190
Regulatory assets			167						124
Prepayments			77						67
Income taxes receivable			—						77
Other current assets			20						23
Total current assets			889						818
Property, plant and equipment, net			10,104						9,401
Regulatory assets			405						459
Other assets			381						400
Total assets			$	11,779					$	11,078
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable			$	538					$	343
Accrued interest			45						46
Accrued property, income and other taxes			41						34
Regulatory liabilities			46						41
Customer deposits			56						93
Derivative contracts			27						53
Other current liabilities			102						50
Total current liabilities			855						660
Senior debt			3,397						3,395
Junior subordinated debt			297						—
Finance lease obligations			250						266
Regulatory liabilities			956						997
Deferred income taxes			826						802
Other long-term liabilities			518						510
Total liabilities			7,099						6,630
Commitments and contingencies (Note 10)
Shareholder's equity:
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding			—						—
Additional paid-in capital			3,123						2,943
Retained earnings			1,558						1,506
Accumulated other comprehensive loss, net			(1)						(1)
Total shareholder's equity			4,680						4,448
Total liabilities and shareholder's equity			$	11,779					$	11,078
The accompanying notes are an integral part of the consolidated financial statements.

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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,
			2025						2024						2025						2024
Operating revenue			$	865					$	993					$	1,893					$	2,355
Operating expenses:
Cost of fuel and energy			419						513						932						1,336
Operations and maintenance			97						90						265						237
Depreciation and amortization			103						95						300						279
Property and other taxes			14						15						43						44
Total operating expenses			633						713						1,540						1,896
Operating income			232						280						353						459
Other income (expense):
Interest expense			(56)						(51)						(167)						(156)
Capitalized interest			5						2						15						16
Allowance for equity funds			10						5						30						22
Interest and dividend income			3						5						9						20
Other, net			5						5						13						14
Total other income (expense)			(33)						(34)						(100)						(84)
Income before income tax expense (benefit)			199						246						253						375
Income tax expense (benefit)			11						35						16						52
Net income			$	188					$	211					$	237					$	323
The accompanying notes are an integral part of these consolidated financial statements.

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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, 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
Balance, June 30, 2025						1,000						$	—					$	3,023					$	1,370					$	(1)					$	4,392
Net income						—						—						—						188						—						188
Contributions						—						—						100						—						—						100
Balance, September 30, 2025						1,000						$	—					$	3,123					$	1,558					$	(1)					$	4,680
Balance, December 31, 2024						1,000						$	—					$	2,943					$	1,506					$	(1)					$	4,448
Net income						—						—						—						237						—						237
Dividends declared						—						—						—						(185)						—						(185)
Contributions						—						—						180						—						—						180
Balance, September 30, 2025						1,000						$	—					$	3,123					$	1,558					$	(1)					$	4,680
The accompanying notes are an integral part of these consolidated financial statements.

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NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

			Nine-Month Periods
			Ended September 30,
			2025						2024
Cash flows from operating activities:
Net income			$	237					$	323
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization			300						279
Allowance for equity funds			(30)						(22)
Deferred energy			(97)						402
Amortization of deferred energy			51						(17)
Other changes in regulatory assets and liabilities			(3)						(21)
Deferred income taxes and amortization of investment tax credits			(4)						2
Other, net			(1)						—
Changes in other operating assets and liabilities:
Trade receivables and other assets			(28)						(107)
Inventories			(36)						(43)
Accrued property, income and other taxes			79						(63)
Accounts payable and other liabilities			173						71
Net cash flows from operating activities			641						804
Cash flows from investing activities:
Capital expenditures			(912)						(842)
Proceeds from sale of marketable securities			—						4
Net cash flows from investing activities			(912)						(838)
Cash flows from financing activities:
Proceeds from long-term debt			297						—
Contributions from parent			180						100
Dividends paid			(185)						(30)
Other, net			(20)						(16)
Net cash flows from financing activities			272						54
Net change in cash and cash equivalents and restricted cash and cash equivalents			1						20
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period			42						37
Cash and cash equivalents and restricted cash and cash equivalents at end of period			$	43					$	57
The accompanying notes are an integral part of these consolidated financial statements.

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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 headquartered in Iowa that has investments in subsidiaries principally engaged in energy businesses. BHE is a wholly owned 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, 2025, and for the three- and nine-month periods ended September 30, 2025 and 2024. 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, 2025 and 2024. The results of operations for the three- and nine-month periods ended September 30, 2025, 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, 2024, 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, 2025.

Segment Information

Nevada Power currently has one reportable segment, its regulated electric utility operations, which derives its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. Nevada Power's chief operating decision maker ("CODM") is its President and Chief Executive Officer. The CODM uses net income, as reported on the Consolidated Statements of Operations, and generally considers actual results versus historical results, budgets or forecasts, and state regulatory ratemaking results as well as unique risks and opportunities, when making decisions about the allocation of resources and capital. The significant segment expenses regularly provided to the CODM align with the captions presented on the Consolidated Statements of Operations. Nevada Power's segment capital expenditures are reported on the Consolidated Statements of Cash Flows as capital expenditures. Nevada Power's segment assets are reported on the Consolidated Balance Sheets as total assets.

(2)    New Accounting Pronouncements

In December 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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.

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In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures Subtopic 220-40, "Disaggregation of Income Statement Expenses" which addresses requests from investors for more detailed information about certain expenses and requires disclosure of the amounts of purchases of inventory, employee compensation, depreciation and intangible asset amortization included in each relevant expense caption presented on the income statement. This guidance, as clarified in ASU 2025-01, is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. 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.

(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,
			2025						2024
Cash and cash equivalents			$	31					$	23
Restricted cash and cash equivalents included in other current assets			12						19
Total cash and cash equivalents and restricted cash and cash equivalents			$	43					$	42

(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,
									2025						2024
Utility plant:
Generation			30 - 65 years						$	5,483					$	5,369
Transmission			55 - 75 years						1,778						1,660
Distribution			24 - 70 years						4,942						4,754
Intangible plant and other			5 - 65 years						926						900
Utility plant									13,129						12,683
Accumulated depreciation and amortization									(4,292)						(4,093)
Utility plant, net									8,837						8,590
Nonregulated, net of accumulated depreciation and amortization			40 years						1						1
									8,838						8,591
Construction work-in-progress									1,266						810
Property, plant and equipment, net									$	10,104					$	9,401

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(5)    Recent Financing Transactions

Junior Subordinated Debt

In February 2025, Nevada Power issued $300 million of its 6.25% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due May 2055. Nevada Power will pay interest on the notes at a rate of 6.25% through May 2030, subject to a reset every five years. Nevada Power intends to use the net proceeds from the sale of the notes to fund capital expenditures and for general corporate purposes.

Credit Facilities

In June 2025, Nevada Power amended its existing $600 million secured credit facility expiring in June 2027. The amendment extended the expiration date to June 2028 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,
			2025						2024						2025						2024
Federal statutory income tax rate			21		%				21		%				21		%				21		%
Effects of ratemaking(1)			(9)						(4)						(8)						(4)
Income tax credits			(6)						(3)						(7)						(4)
Other			—						—						—						1
Effective income tax rate			6		%				14		%				6		%				14		%

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

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.

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 received cash refunds for federal income tax from BHE of $59 million for the nine-month periods ended September 30, 2025. Nevada Power made cash payments for federal income tax to BHE of $112 million for the nine-month periods ended September 30, 2024.

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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. Nevada Power contributed $1 million to the Non-Qualified Pension Plans for the nine-month period ended September 30, 2025. 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,
			2025						2024
Qualified Pension Plan:
Other non-current assets			$	38					$	39
Non-Qualified Pension Plans:
Other current liabilities			(1)						(1)
Other long-term liabilities			(6)						(6)
Other Postretirement Plans:
Other non-current assets			17						19

(8)    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 9 for additional information related to the fair value measurements associated with derivative contracts.

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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, 2025
Not designated as hedging contracts(1):
Commodity liabilities			$	—											$	(27)					$	(5)					$	(32)
As of December 31, 2024
Not designated as hedging contracts(1):
Commodity liabilities			$	—											$	(53)					$	(4)					$	(57)

(1)Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates. As of September 30, 2025, a regulatory asset of $32 million was recorded related to the net derivative liability of $32 million. As of December 31, 2024, a regulatory asset of $57 million was recorded related to the net derivative liability of $57 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						2025						2024
Electricity purchases			Megawatt hours						2						2
Natural gas purchases			Decatherms						162						127

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, 2025, Nevada Power's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.

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The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $7 million and $13 million as of September 30, 2025, and December 31, 2024, 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.

(9)    Fair Value Measurements

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

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

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

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

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

			Input Levels for Fair Value Measurements
			Level 1						Level 2						Level 3						Total
As of September 30, 2025:
Assets:
Money market mutual funds			$	37					$	—					$	—					$	37
Investment funds			5						—						—						5
			$	42					$	—					$	—					$	42
Liabilities:
Commodity derivatives			$	—					$	—					$	(32)					$	(32)
As of December 31, 2024:
Assets:
Money market mutual funds			$	15					$	—					$	—					$	15
Investment funds			4						—						—						4
			$	19					$	—					$	—					$	19
Liabilities:
Commodity derivatives			$	—					$	—					$	(57)					$	(57)

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Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of September 30, 2025, and December 31, 2024, 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,
			2025						2024						2025						2024
Beginning balance			$	(78)					$	(101)					$	(57)					$	(68)
Changes in fair value recognized in regulatory assets			(25)						(29)						(57)						(87)
Settlements			71						74						82						99
Ending balance			$	(32)					$	(56)					$	(32)					$	(56)

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 following table presents the carrying value and estimated fair value of Nevada Power's debts (in millions):

			As of September 30, 2025												As of December 31, 2024
			Carrying						Fair						Carrying						Fair
			Value						Value						Value						Value
Long-term debt			$	3,694					$	3,715					$	3,395					$	3,299

(10)    Commitments and Contingencies

Environmental Laws and Regulations

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

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Accrual for Customer Refund

In September 2025, Nevada Power recorded an additional $12 million accrual totaling $29 million in connection with a potential customer refund arising from ongoing regulatory proceedings. The estimated accrual is based on currently available information to date and Nevada Power believes it is probable that losses will be incurred associated with the ongoing regulatory proceedings which reflects Nevada Power's commitment to transparency and regulatory compliance. Nevada Power will continue to assess the matter and final determination of the liability will be made after the completion of the regulatory proceedings and the accrued liability will be updated as warranted.

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.

(11)    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,
			2025						2024						2025						2024
Customer Revenue:
Retail:
Residential			$	481					$	610					$	1,012					$	1,326
Commercial			158						162						384						460
Industrial			199						193						429						496
Other			2						3						3						5
Total fully bundled			840						968						1,828						2,287
Distribution only service			4						3						12						11
Total retail			844						971						1,840						2,298
Wholesale, transmission and other			21						21						52						54
Total Customer Revenue			865						992						1,892						2,352
Other revenue			—						1						1						3
Total operating revenue			$	865					$	993					$	1,893					$	2,355

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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 2025 and 2024

Overview

Net income for the third quarter of 2025 was $188 million, a decrease of $23 million compared to 2024 primarily due to lower electric utility margin, higher operations and maintenance expense, increased depreciation and amortization expense, higher interest expense and lower interest and dividend income. These items were partially offset by favorable income tax expense and higher capitalized interest and allowance for equity funds. Utility margin decreased primarily due to unfavorable price impacts from changes in sales mix, an accrual in connection with a potential customer refund arising from ongoing regulatory proceedings and lower transmission and wholesale revenue, partially offset by higher energy efficiency implementation revenue. Retail customer volumes, including distribution only service customers, decreased 6.2% primarily due to the unfavorable impact of weather and customer usage patterns, offset by an increase in the average number of customers. Energy generated volumes decreased 11% for the third quarter of 2025 compared to 2024 primarily due to lower natural gas-fueled generation. Wholesale electricity sales volumes decreased 7% and energy purchased volumes decreased 3%.

Net income for the first nine months of 2025 was $237 million, a decrease of $86 million compared to 2024 primarily due to lower electric utility margin, higher operations and maintenance expense, increased depreciation and amortization expense, lower interest and dividend income and higher interest expense. These items were partially offset by favorable income tax expense and higher allowance for equity funds. Utility margin decreased primarily due to an accrual in connection with a potential customer refund arising from ongoing regulatory proceedings, unfavorable price impacts from changes in sales mix, an accrual in connection with a potential customer refund arising from ongoing regulatory proceedings, lower transmission and wholesale revenue and lower energy efficiency implementation revenue, partially offset by higher power purchase agreement sales from the Dry Lake renewable generation facility. Retail customer volumes, including distribution only service customers, decreased 2.9% primarily due to the unfavorable impact of weather and customer usage patterns, offset by an increase in the average number of customers. Energy generated volumes decreased 4% for the first nine months of 2025 compared to 2024 primarily due to lower natural gas-fueled and renewable generation. Wholesale electricity sales volumes decreased 19% and energy purchased volumes increased 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 is generally recovered from its retail customers through regulatory recovery mechanisms and as a result, changes in Nevada Power's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains results of operations 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 understanding 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
						2025						2024						Change									2025						2024						Change
Utility margin:
Operating revenue						$	865					$	993					$	(128)		(13)		%				$	1,893					$	2,355					$	(462)		(20)		%
Cost of fuel and energy						419						513						(94)			(18)						932						1,336						(404)			(30)
Utility margin						446						480						(34)			(7)						961						1,019						(58)			(6)
Operations and maintenance						97						90						7			8						265						237						28			12
Depreciation and amortization						103						95						8			8						300						279						21			8
Property and other taxes						14						15						(1)			(7)						43						44						(1)			(2)
Operating income						$	232					$	280					$	(48)		(17)		%				$	353					$	459					$	(106)		(23)		%

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Utility Margin

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

						Third Quarter																					First Nine Months
						2025						2024						Change									2025						2024						Change
Utility margin (in millions):
Operating revenue						$	865					$	993					$	(128)		(13)		%				$	1,893					$	2,355					$	(462)		(20)		%
Cost of fuel and energy						419						513						(94)			(18)						932						1,336						(404)			(30)
Utility margin						$	446					$	480					$	(34)		(7)		%				$	961					$	1,019					$	(58)		(6)		%
Sales (GWhs):
Residential						4,002						4,438						(436)			(10)		%				8,164						8,678						(514)			(6)		%
Commercial						1,508						1,649						(141)			(9)						3,823						3,951						(128)			(3)
Industrial						1,897						1,888						9			—						4,912						4,844						68			1
Other						50						50						—			—						131						135						(4)			(3)
Total fully bundled(1)						7,457						8,025						(568)			(7)						17,030						17,608						(578)			(3)
Distribution only service						844						820						24			3						2,202						2,192						10			—
Total retail						8,301						8,845						(544)			(6)						19,232						19,800						(568)			(3)
Wholesale						119						128						(9)			(7)						349						429						(80)			(19)
Total GWhs sold						8,420						8,973						(553)			(6)		%				19,581						20,229						(648)			(3)		%
Average number of retail customers (in thousands)						1,056						1,040						16			2		%				1,051						1,032						19			2		%
Average revenue per MWh:
Retail - fully bundled(1)						$	112.56					$	120.51					$	(7.95)		(7)		%				$	107.31					$	129.87					$	(22.56)		(17)		%
Wholesale						$	48.59					$	35.78					$	12.81		36		%				$	42.56					$	29.89					$	12.67		42		%
Heating degree days						—						—						—			—		%				973						1,111						(138)			(12)		%
Cooling degree days						2,315						2,647						(332)			(13)		%				3,764						4,170						(406)			(10)		%
Sources of energy (GWhs)(2)(3):
Natural gas						4,157						4,705						(548)			(12)		%				11,135						11,592						(457)			(4)		%
Renewables						125						127						(2)			(2)						351						329						22			7
Total energy generated						4,282						4,832						(550)			(11)						11,486						11,921						(435)			(4)
Energy purchased						3,248						3,356						(108)			(3)						6,742						6,679						63			1
Total						7,530						8,188						(658)			(8)		%				18,228						18,600						(372)			(2)		%
Average cost of energy per MWh(2)(4):
Energy generated						$	25.25					$	18.76					$	6.49		35		%				$	28.15					$	36.35					$	(8.20)		(23)		%
Energy purchased						$	95.84					$	126.11					$	(30.27)		(24)		%				$	90.28					$	135.21					$	(44.93)		(33)		%

(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 149 GWhs and 62 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2025 and 2024, respectively. The average cost of energy per MWh and sources of energy excludes 303 GWhs and 343 GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 2025 and 2024, 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, 2025, Compared to Quarter Ended September 30, 2024

Utility margin decreased $34 million, or 7%, for the third quarter of 2025 compared to 2024 primarily due to:

•$24 million of lower electric retail utility margin primarily due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, decreased 6.2% primarily due to unfavorable changes in weather and customer usage patterns, offset by an increase in the average number of customers;

•$12 million of lower revenue related to an accrual in connection with a potential customer refund arising from ongoing regulatory proceedings and

•$1 million of lower transmission and wholesale revenue.

The decrease in utility margin was partially offset by:

•$2 million of higher energy efficiency implementation revenue and

•$1 million of higher energy efficiency program revenue (offset in operations and maintenance expense).

Operations and maintenance increased $7 million, or 8%, for the third quarter of 2025 compared to 2024 primarily due to regulatory impacts from the 2025 regulatory rate review, higher administrative and general costs and increased technology costs, partially offset by lower energy efficiency program costs (offset in operating revenue) and lower plant operations and maintenance costs.

Depreciation and amortization increased $8 million, or 8%, for the third quarter of 2025 compared to 2024 primarily due to higher plant placed in-service and higher amortizations from intangible plant software.

Interest expense increased $5 million, or 10%, for the third quarter of 2025 compared to 2024 primarily due to higher long-term debt outstanding.

Capitalized interest and allowance for equity funds increased $8 million, or 114%, for the third quarter of 2025 compared to 2024 primarily due to higher construction work-in-progress.

Interest and dividend income decreased $2 million, or 40%, for the third quarter of 2025 compared to 2024 primarily due to lower interest income, mainly from lower carrying charges on regulatory balances.

Income tax expense decreased $24 million, or 69%, for the third quarter of 2025 compared to 2024 primarily due to lower pretax income and higher federal income tax credits, partially offset by the effects of ratemaking. The effective tax rate was 6% in 2025 and 14% in 2024 and decreased primarily due to the effects of ratemaking and higher tax credits.

First Nine Months of 2025 Compared to First Nine Months of 2024

Utility margin decreased $58 million, or 6%, for the first nine months of 2025 compared to 2024 primarily due to:

•$33 million of lower electric retail utility margin primarily due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, decreased 2.9% primarily due to unfavorable changes in weather and customer usage patterns, offset by an increase in the average number of customers;

•$29 million of lower revenue related to an accrual in connection with a potential customer refund arising from ongoing regulatory proceedings;

•$4 million of lower transmission and wholesale revenue and

•$2 million of lower energy efficiency implementation revenue.

The decrease in utility margin was offset by:

•$5 million of higher power purchase agreement sales from the Dry Lake renewable generation facility and

•$6 million of increased energy efficiency program revenue (offset in operations and maintenance expense).

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Operations and maintenance increased by $28 million for the first nine months of 2025 compared to 2024 primarily due to increased technology costs, higher plant operations and maintenance costs, higher customer service costs, regulatory impacts from the 2025 regulatory rate review and higher insurance expense due to higher premiums associated with third-party liability coverage, partially offset by lower administrative and general costs and lower energy efficiency program costs (offset in revenue).

Depreciation and amortization increased $21 million, or 8%, for the first nine months of 2025 compared to 2024 primarily due to higher plant placed in-service.

Interest expense increased $11 million, or 7%, for the first nine months of 2025 compared to 2024 primarily due to higher long-term debt.

Capitalized interest and allowance for equity funds increased $7 million, or 18%, for the first nine months of 2025 compared to 2024 primarily due to higher construction work-in-progress.

Interest and dividend income decreased $11 million, or 55%, for the first nine months of 2025 compared to 2024 primarily due to unfavorable interest income, mainly from lower carrying charges on regulatory balances.

Income tax expense decreased $36 million, or 69%, for the first nine months of 2025 compared to 2024 primarily due to lower pretax income and higher federal income tax credits, partially offset by the effects of ratemaking. The effective tax rate was 6% in 2025 and 14% in 2024 and decreased primarily due to the effects of ratemaking and higher federal tax credits.

Liquidity and Capital Resources

As of September 30, 2025, Nevada Power's total net liquidity was as follows (in millions):

Cash and cash equivalents						$	31
Credit facility						600
Total net liquidity						$	631
Credit facility:
Maturity date						2028

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2025 and 2024, were $641 million and $804 million, respectively. The change was primarily due to higher payments related to fuel and energy costs and higher interest payments, partially offset by lower income tax payments, the timing of payments for operating costs and higher customer deposits.

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

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2025 and 2024, were $(912) million and $(838) 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, 2025 and 2024, were $272 million and $54 million, respectively. The change was primarily due to higher net proceeds from the issuance of junior subordinated debt and higher contributions from NV Energy, Inc., partially offset by higher dividends paid to NV Energy, Inc.

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.

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Debt Authorizations

Nevada Power currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $5.5 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 filed with the SEC to issue an additional $1.8 billion of general and refunding mortgage securities and unsecured debt securities through December 2027.

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.

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
			2024						2025						2025
Electric transmission			$	97					$	387					$	457
Electric distribution			245						271						332
Solar generation			19						48						62
Electric battery storage			12						9						22
Wildfire prevention			11						11						14
Other			458						186						252
Total			$	842					$	912					$	1,139

Nevada Power receives PUCN approval through its IRP filings for various projects. Nevada Power has included estimates from these IRP filings in its forecast capital expenditures for 2025. These estimates can change as a result of the RFP process, continued evaluation and future IRP filing refinements. Nevada Power's capital expenditures include the following:

•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.

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

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•Solar generation and electric battery storage primarily consist of 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 MWs of co-located battery storage that is being 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 facility is expected by early 2027 and commercial operation of the co-located battery storage is expected by mid-2026.

•Wildfire prevention includes both growth and operating expenditures related to projects included in a comprehensive natural disaster protection plan filed and approved by the PUCN. These projects include, but are not limited to, rebuilding distribution lines with covered conductor, converting overhead distribution lines to underground and copper wire and pole replacement projects.

•Other includes both growth projects and operating expenditures. Growth projects primarily consist of additional completion costs for the peaking combustion turbines developed at the Silverhawk generating facility in Clark County, Nevada. Operating expenditures consist of turbine upgrades at several generating facilities, information technology expenditures, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.

2024 Joint Integrated Resource Plan

In October 2025, the Nevada Utilities submitted a Joint Application for approval of the First Amendment to the 2024 Joint Integrated Resource Plan. The First Amendment seeks approval to enter into a 20-year power purchase agreement with the developer for an additional 150-MW battery energy storage system that will reduce the Nevada Utilities' open position beginning in the summer of 2027. The battery energy storage system will be co-located with the existing Dodge Flat solar and battery facility in Washoe County, Nevada. An order is expected in 2026.

Material Cash Requirements

As of September 30, 2025, there have been no material changes outside the normal course of business in material cash requirements from the information provided in Item 7 of Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2024, other than those disclosed in Note 5 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Regulatory Matters

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

Environmental Laws and Regulations

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

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

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Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, 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, 2024. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2024.

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Sierra Pacific Power Company and its subsidiaries

Consolidated Financial Section

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PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of September 30, 2025, the related consolidated statements of operations, and changes in shareholder's equity for the three-month and six-month periods ended September 30, 2025 and 2024, and of cash flows for the nine-month periods ended September 30, 2025 and 2024, 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, 2024, 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 21, 2025, 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, 2024, 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

October 31, 2025

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SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)

			As of
			September 30,						December 31,
			2025						2024
ASSETS
Current assets:
Cash and cash equivalents			$	37					$	17
Trade receivables, net			184						138
Inventories			161						161
Regulatory assets			63						90
Prepayments			34						54
Other current assets			34						22
Total current assets			513						482
Property, plant and equipment, net			5,647						4,439
Regulatory assets			198						202
Other assets			204						204
Total assets			$	6,562					$	5,327
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable			$	554					$	410
Accrued interest			18						19
Accrued property, income and other taxes			18						16
Current portion of long-term debt			400						—
Regulatory liabilities			83						106
Customer deposits			40						42
Other current liabilities			53						50
Total current liabilities			1,166						643
Long-term debt			1,127						1,527
Junior subordinated debt			446						—
Regulatory liabilities			408						416
Deferred income taxes			385						369
Other long-term liabilities			318						272
Total liabilities			3,850						3,227
Commitments and contingencies (Note 10)
Shareholder's equity:
Common stock - $3.75 stated value, 1,000 shares authorized, issued and outstanding			—						—
Additional paid-in capital			2,321						1,726
Retained earnings			392						375
Accumulated other comprehensive loss, net			(1)						(1)
Total shareholder's equity			2,712						2,100
Total liabilities and shareholder's equity			$	6,562					$	5,327
The accompanying notes are an integral part of the consolidated financial statements.

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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,
			2025						2024						2025						2024
Operating revenue:
Regulated electric			$	294					$	320					$	765					$	842
Regulated natural gas			17						18						89						138
Total operating revenue			311						338						854						980
Operating expenses:
Cost of fuel and energy			121						150						346						443
Cost of natural gas purchased for resale			5						7						42						96
Operations and maintenance			66						66						187						181
Depreciation and amortization			41						47						121						141
Property and other taxes			6						6						18						18
Total operating expenses			239						276						714						879
Operating income			72						62						140						101
Other income (expense):
Interest expense			(25)						(22)						(73)						(64)
Allowance for borrowed funds			5						2						11						5
Allowance for equity funds			16						6						35						16
Interest and dividend income			3						2						9						11
Other, net			4						3						8						8
Total other income (expense)			3						(9)						(10)						(24)
Income before income tax expense (benefit)			75						53						130						77
Income tax expense (benefit)			7						6						13						8
Net income			$	68					$	47					$	117					$	69
The accompanying notes are an integral part of these consolidated financial statements.

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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, 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
Balance, June 30, 2025						1,000						$	—					$	2,121					$	425					$	(1)					$	2,545
Net income						—						—						—						68						—						68
Dividends declared						0						—						—						(100)						—						(100)
Contributions						—						—						200						—						—						200
Other equity transactions						—						—						—						(1)						—						(1)
Balance, September 30, 2025						1,000						$	—					$	2,321					$	392					$	(1)					$	2,712
Balance, December 31, 2024						1,000						$	—					$	1,726					$	375					$	(1)					$	2,100
Net income						—						—						—						117						—						117
Dividends declared						—						—						—						(100)						—						(100)
Contributions						—						—						595						—						—						595
Balance, September 30, 2025						1,000						$	—					$	2,321					$	392					$	(1)					$	2,712
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 CASH FLOWS (Unaudited)

(Amounts in millions)

			Nine-Month Periods
			Ended September 30,
			2025						2024
Cash flows from operating activities:
Net income			$	117					$	69
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization			121						141
Allowance for equity funds			(35)						(16)
Deferred energy			(62)						86
Amortization of deferred energy			(19)						31
Other changes in regulatory assets and liabilities			81						2
Deferred income taxes and amortization of investment tax credits			(3)						(34)
Other, net			(3)						(2)
Changes in other operating assets and liabilities:
Trade receivables and other assets			(17)						6
Inventories			(1)						(38)
Accrued property, income and other taxes			(15)						(28)
Accounts payable and other liabilities			(34)						113
Net cash flows from operating activities			130						330
Cash flows from investing activities:
Capital expenditures			(1,084)						(433)
Proceeds from sale of marketable securities			—						1
Net cash flows from investing activities			(1,084)						(432)
Cash flows from financing activities:
Proceeds from long-term debt			446						233
Proceeds from short-term debt			—						15
Dividends paid			(100)						(200)
Contributions from parent			595						30
Other, net			30						(6)
Net cash flows from financing activities			971						72
Net change in cash and cash equivalents and restricted cash and cash equivalents			17						(30)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period			24						52
Cash and cash equivalents and restricted cash and cash equivalents at end of period			$	41					$	22
The accompanying notes are an integral part of these consolidated financial statements.

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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 headquartered in Iowa that has investments in subsidiaries principally engaged in energy businesses. BHE is a wholly owned 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, 2025, and for the three- and nine-month periods ended September 30, 2025 and 2024. 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, 2025 and 2024. The results of operations for the three- and nine-month periods ended September 30, 2025, 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, 2024, 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, 2025.

(2)    New Accounting Pronouncements

In December 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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.

In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures Subtopic 220-40, "Disaggregation of Income Statement Expenses" which addresses requests from investors for more detailed information about certain expenses and requires disclosure of the amounts of purchases of inventory, employee compensation, depreciation and intangible asset amortization included in each relevant expense caption presented on the income statement. This guidance, as clarified in ASU 2025-01, is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. 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.

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(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,
			2025						2024
Cash and cash equivalents			$	37					$	17
Restricted cash and cash equivalents included in other current assets			4						7
Total cash and cash equivalents and restricted cash and cash equivalents			$	41					$	24

(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,
									2025						2024
Utility plant:
Generation			25 - 70 years						$	1,369					$	1,339
Transmission			50 - 76 years						1,129						1,071
Electric distribution			20 - 76 years						2,265						2,224
Electric intangible plant and other			5 - 65 years						190						254
Natural gas distribution			35 - 70 years						571						563
Natural gas intangible plant and other			5 - 65 years						17						18
Common other			5 - 65 years						446						377
Utility plant									5,987						5,846
Accumulated depreciation and amortization									(2,250)						(2,208)
									3,737						3,638
Construction work-in-progress									1,910						801
Property, plant and equipment, net									$	5,647					$	4,439

(5)    Recent Financing Transactions

Junior Subordinated Debt

In September 2025, Sierra Pacific issued $450 million of its 6.20% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due December 2055. Sierra Pacific will pay interest on the notes at a rate of 6.20% through December 2030, subject to a reset every five years. Sierra Pacific intends to use the net proceeds from the sale of the notes to fund capital expenditures and for general corporate purposes.

Credit Facilities

In June 2025, Sierra Pacific amended its existing $400 million secured credit facility expiring in June 2027. The amendment extended the expiration date to June 2028 and amended certain provisions of the existing credit agreement.

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(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,
			2025						2024						2025						2024
Federal statutory income tax rate			21		%				21		%				21		%				21		%
Effects of ratemaking(1)			(12)						(10)						(11)						(11)
Other			—						—						—						—
Effective income tax rate			9		%				11		%				10		%				10		%

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

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 $28 million and $67 million for the nine-month periods ended September 30, 2025 and 2024, respectively.

(7)    Employee Benefit Plans

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

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

			As of
			September 30,						December 31,
			2025						2024
Qualified Pension Plan:
Other non-current assets			$	61					$	59
Non-Qualified Pension Plans:
Other current liabilities			(1)						(1)
Other long-term liabilities			(5)						(5)
Other Postretirement Plans:
Other non-current assets			4						5

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(8)    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 9 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												Other
			Current						Long-term						Current						Long-term
			Assets						Assets						Liabilities						Liabilities						Total
As of September 30, 2025
Not designated as hedging contracts(1):
Commodity assets			$	1					$	—					$	—					$	—					$	1
Commodity liabilities			—						—						(8)						(1)						(9)
Total derivative - net basis			$	1					$	—					$	(8)					$	(1)					$	(8)
As of December 31, 2024
Not designated as hedging contracts(1):
Commodity assets			$	—					$	1					$	—					$	—					$	1
Commodity liabilities			—						—						(14)						—						(14)
Total derivative - net basis			$	—					$	1					$	(14)					$	—					$	(13)

(1)Sierra Pacific's commodity derivatives not designated as hedging contracts are included in regulated rates. As of September 30, 2025, a net regulatory asset of $8 million was recorded related to the net derivative liability of $8 million. As of December 31, 2024, a net regulatory asset of $13 million was recorded related to the net derivative liability of $13 million.

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

			Unit of						September 30,						December 31,
			Measure						2025						2024
Electricity purchases			Megawatt hours						1						1
Natural gas purchases			Decatherms						91						57

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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, 2025, 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, 2025, and $— December 31, 2024, 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.

(9)    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, 2025:
Assets:
Commodity derivatives			$	—					$	—					$	1					$	1
Money market mutual funds			51						—						—						51
Investment funds			1						—						—						1
			$	52					$	—					$	1					$	53
Liabilities:
Commodity derivatives			$	—					$	—					$	(9)					$	(9)
As of December 31, 2024:
Assets:
Commodity derivatives			$	—					$	—					$	1					$	1
Money market mutual funds			12						—						—						12
Investment funds			1						—						—						1
			$	13					$	—					$	1					$	14
Liabilities:
Commodity derivatives			$	—					$	—					$	(14)					$	(14)

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, 2025, and December 31, 2024, 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,
			2025						2024						2025						2024
Beginning balance			$	(22)					$	(27)					$	(13)					$	(16)
Changes in fair value recognized in regulatory assets			(10)						(10)						(20)						(26)
Settlements			24						25						25						30
Ending balance			$	(8)					$	(12)					$	(8)					$	(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 following table presents the carrying value and estimated fair value of Sierra Pacific's long-term debt (in millions):

			As of September 30, 2025												As of December 31, 2024
			Carrying						Fair						Carrying						Fair
			Value						Value						Value						Value
Long-term debt			$	1,973					$	1,989					$	1,527					$	1,506

(10)    Commitments and Contingencies

Environmental Laws and Regulations

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

Accrual for Customer Refund

In September 2025, Sierra Pacific recorded an additional $3 million accrual totaling $6 million as of September 30, 2025 in connection with a potential customer refund arising from ongoing regulatory proceedings. The estimated accrual is based on currently available information to date and Sierra Pacific believes it is probable that losses will be incurred associated with the ongoing regulatory proceedings which reflects Sierra Pacific's commitment to transparency and regulatory compliance. Sierra Pacific will continue to assess the matter and final determination of the liability will be made after the completion of the regulatory proceedings and the accrued liability will be updated as warranted.

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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(11)    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 12 (in millions):

			Three-Month Periods
			Ended September 30,
			2025																		2024
			Electric						Natural Gas						Total						Electric						Natural Gas						Total
Customer Revenue:
Retail:
Residential			$	98					$	12					$	110					$	106					$	11					$	117
Commercial			94						3						97						101						4						105
Industrial			81						1						82						93						2						95
Other			2						1						3						1						1						2
Total fully bundled			275						17						292						301						18						319
Distribution only service			2						—						2						2						—						2
Total retail			277						17						294						303						18						321
Wholesale, transmission and other			17						—						17						16						—						16
Total Customer Revenue			294						17						311						319						18						337
Other revenue			—						—						—						1						—						1
Total operating revenue			$	294					$	17					$	311					$	320					$	18					$	338

			Nine-Month Periods
			Ended September 30,
			2025																		2024
			Electric						Natural Gas						Total						Electric						Natural Gas						Total
Customer Revenue:
Retail:
Residential			$	271					$	59					$	330					$	296					$	85					$	381
Commercial			250						21						271						273						36						309
Industrial			185						7						192						213						15						228
Other			4						2						6						4						2						6
Total fully bundled			710						89						799						786						138						924
Distribution only service			6						—						6						4						—						4
Total retail			716						89						805						790						138						928
Wholesale, transmission and other			48						—						48						51						—						51
Total Customer Revenue			764						89						853						841						138						979
Other revenue			1						—						1						1						—						1
Total operating revenue			$	765					$	89					$	854					$	842					$	138					$	980

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(12)    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):

			For the Three-Month Period Ended September 30, 2025
			Regulated Electric						Regulated Natural Gas						Total
Operating revenue			$	294					$	17					$	311
Cost of sales			121						5						126
Operations and maintenance			62						4						66
Depreciation and amortization			36						5						41
Interest expense			24						1						25
Interest and dividend income			3						—						3
Income tax expense (benefit)			7						—						7
Other segment items (1)			19						—						19
Net income			$	66					$	2					$	68
Capital expenditures			$	533					$	37					$	570

			For the Nine-Month Period Ended September 30, 2025
			Regulated Electric						Regulated Natural Gas						Total
Operating revenue			$	765					$	89					$	854
Cost of sales			346						42						388
Operations and maintenance			170						17						187
Depreciation and amortization			106						15						121
Interest expense			68						5						73
Interest and dividend income			9						—						9
Income tax expense (benefit)			13						—						13
Other segment items (1)			37						(1)						$	36
Net Income			$	108					$	9					$	117
Capital expenditures			$	1,007					$	77					$	1,084

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						For the Three-Month Period Ended September 30, 2024
						Regulated Electric						Regulated Natural Gas						Total
Operating revenue						$	320					$	18					$	338
Cost of sales						150						7						157
Operations and maintenance						57						9						66
Depreciation and amortization						41						6						47
Interest expense						22						—						22
Interest and dividend income						2						—						2
Income tax expense (benefit)						9						(3)						6
Other segment items (1)						5						—						5
Net income						$	48					$	(1)					$	47
Capital expenditures						$	125					$	11					$	136

						For the Nine-Month Period Ended September 30, 2024
						Regulated Electric						Regulated Natural Gas						Total
Operating revenue						$	842					$	138					$	980
Cost of sales						443						96						539
Operations and maintenance						157						24						181
Depreciation and amortization						127						14						141
Interest expense						59						5						64
Interest and dividend income						11						—						11
Income tax expense (benefit)						11						(3)						8
Other segment items (1)						12						(1)						$	11
Net Income						$	68					$	1					$	69
Capital expenditures						$	395					$	38					$	433

									As of
															September 30,						December 31,
															2025						2024
Assets:
Regulated electric															$	6,023					$	4,767
Regulated natural gas															490						518
Regulated common assets(2)															49						42
Total assets															$	6,562					$	5,327

(1)    Consists principally of property and other taxes, allowance for borrowed and equity funds and other income (expenses).

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

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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 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 2025 and 2024

Overview

Net income for the third quarter of 2025 was $68 million, an increase of $21 million compared to 2024 primarily due to higher allowance for borrowed and equity funds, lower depreciation and amortization expense and higher utility margin. These items are partially offset by higher interest expense. Electric utility margin increased primarily due to higher retail rates from the 2024 regulatory rate review with new rates effective October 2024 and price impacts from changes in sales mix, offset by an accrual in connection with a potential customer refund arising from ongoing regulatory proceedings. Electric retail customer volumes, including distribution only service customers, decreased by 0.7% primarily due to the unfavorable impact of weather, partially offset by an increase in the average number of customers. Natural gas utility margin increased primarily due to higher retail rates from the 2024 regulatory rate review with new rates effective October 2024 and an increase in the average number of customers. Energy generated volumes decreased 2% for the third quarter of 2025 compared to 2024 primarily due to lower natural gas-fueled generation. Wholesale electricity sales volumes decreased 15% and energy purchased volumes increased 17%.

Net income for the first nine months of 2025 was $117 million, an increase of $48 million compared to 2024 primarily due to higher utility margin, higher allowance for borrowed and equity funds and lower depreciation and amortization expense. These items are partially offset by higher interest expense, higher operations and maintenance expense, unfavorable income tax expense and lower interest and dividend income. Electric utility margin increased primarily due to higher retail rates from the 2024 regulatory rate review with new rates effective October 2024 and price impacts from changes in sales mix, offset by an accrual in connection with a potential customer refund arising from ongoing regulatory proceedings. Electric retail customer volumes, including distribution only service customers, increased by 0.6% primarily due to an increase in the average number of customers, partially offset by the unfavorable impact of weather. Natural gas utility margin increased primarily due to higher retail rates from the 2024 regulatory rate review with new rates effective October 2024 and an increase in the average number of customers. Energy generated volumes are consistent for the first nine months of 2025 compared to 2024. Wholesale electricity sales volumes decreased 11% and energy purchased volumes decreased 2%.

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 retail customers through regulatory recovery mechanisms and as a result, changes in Sierra Pacific's expenses included in 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 results of operations 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 understanding 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
						2025						2024						Change									2025						2024						Change
Electric utility margin:
Operating revenue						$	294					$	320					$	(26)		(8)		%				$	765					$	842					$	(77)		(9)		%
Cost of fuel and energy						121						150						(29)			(19)						346						443						(97)			(22)
Electric utility margin						173						170						3			2		%				419						399						20			5		%
Natural gas utility margin:
Operating revenue						17						18						(1)			(6)		%				89						138						(49)			(36)		%
Natural gas purchased for resale						5						7						(2)			(29)						42						96						(54)			(56)
Natural gas utility margin						12						11						1			9		%				47						42						5			12		%
Utility margin						185						181						4			2		%				466						441						25			6		%
Operations and maintenance						66						66						—			—		%				187						181						6			3		%
Depreciation and amortization						41						47						(6)			(13)						121						141						(20)			(14)
Property and other taxes						6						6						—			—						18						18						—			—
Operating income						$	72					$	62					$	10		16		%				$	140					$	101					$	39		39		%

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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
						2025						2024						Change									2025						2024						Change
Utility margin (in millions):
Operating revenue						$	294					$	320					$	(26)		(8)		%				$	765					$	842					$	(77)		(9)		%
Cost of fuel and energy						121						150						(29)			(19)						346						443						(97)			(22)
Utility margin						$	173					$	170					$	3		2		%				$	419					$	399					$	20		5		%
Sales (GWhs):
Residential						773						800						(27)			(3)		%				2,050						2,073						(23)			(1)		%
Commercial						898						895						3			—						2,408						2,385						23			1
Industrial						784						760						24			3						2,193						2,112						81			4
Other						2						2						—			—						6						7						(1)			(14)
Total fully bundled(1)						2,457						2,457						—			—						6,657						6,577						80			1
Distribution only service						764						786						(22)			(3)						2,156						2,180						(24)			(1)
Total retail						3,221						3,243						(22)			(1)						8,813						8,757						56			1
Wholesale						135						158						(23)			(15)						472						528						(56)			(11)
Total GWhs sold						3,356						3,401						(45)			(1)		%				9,285						9,285						—			—		%
Average number of retail customers (in thousands)						387						383						4			1		%				386						381						5			1		%
Average revenue per MWh:
Retail - fully bundled(1)						$	111.57					$	123.03					$	(11.46)		(9)		%				$	106.54					$	119.52					$	(12.98)		(11)		%
Wholesale						$	80.12					$	65.83					$	14.29		22		%				$	64.19					$	60.13					$	4.06		7		%
Heating degree days						12						52						(40)			(77)		%				2,621						2,642						(21)			(1)		%
Cooling degree days						876						994						(118)			(12)		%				1,198						1,381						(183)			(13)		%
Sources of energy (GWhs)(2):
Natural gas						1,264						1,348						(84)			(6)		%				3,339						3,399						(60)			(2)		%
Coal						307						256						51			20						744						716						28			4
Renewables						3						7						(4)			(57)						7						20						(13)			(65)
Total energy generated						1,574						1,611						(37)			(2)						4,090						4,135						(45)			(1)
Energy purchased						1,459						1,249						210			17						3,126						3,206						(80)			(2)
Total						3,033						2,860						173			6		%				7,216						7,341						(125)			(2)		%
Average cost of energy per MWh(3):
Energy generated						$	30.92					$	22.23					$	8.69		39		%				$	36.45					$	38.86					$	(2.41)		(6)		%
Energy purchased						$	49.53					$	91.39					$	(41.86)		(46)		%				$	62.87					$	87.92					$	(25.05)		(28)		%

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

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

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

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Natural Gas Utility Margin

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

						Third Quarter																					First Nine Months
						2025						2024						Change									2025						2024						Change
Utility margin (in millions):
Operating revenue						$	17					$	18					$	(1)		(6)		%				$	89					$	138					$	(49)		(36)		%
Natural gas purchased for resale						5						7						(2)			(29)						42						96						(54)			(56)
Utility margin						$	12					$	11					$	1		9		%				$	47					$	42					$	5		12		%
Sold (000's Dths):
Residential						794						811						(17)			(2)		%				7,097						7,132						(35)			—		%
Commercial						536						490						46			9						3,819						3,690						129			3
Industrial						335						369						(34)			(9)						1,607						1,688						(81)			(5)
Total retail						1,665						1,670						(5)			—		%				12,523						12,510						13			—		%
Average number of retail customers (in thousands)						188						186						2			1		%				187						185						2			1		%
Average revenue per retail Dth sold						$	10.21					$	10.70					$	(0.49)		(5)		%				$	7.12					$	11.00					$	(3.88)		(35)		%
Heating degree days						12						52						(40)			(77)		%				2,621						2,642						(21)			(1)		%
Average cost of natural gas per retail Dth sold						$	2.71					$	4.31					$	(1.60)		(37)		%				$	3.32					$	7.69					$	(4.37)		(57)		%

Quarter Ended September 30, 2025, Compared to Quarter Ended September 30, 2024

Electric utility margin increased $3 million, or 2%, for the third quarter of 2025 compared to 2024 primarily due to:

•$21 million of higher electric retail utility margin primarily due to higher retail rates from the 2024 regulatory rate review with new rates effective October 2024 and price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, decreased 0.7% primarily due to the unfavorable impact of weather and

•$2 million of higher energy efficiency program revenue (offset in operations and maintenance expense).

The increase in electric utility margin was partially offset by:

•$17 million of lower transmission and wholesale revenue and

•$3 million of lower revenue related to an accrual in connection with a potential customer refund arising from ongoing regulatory proceedings.

Natural gas utility margin increased $1 million, or 9%, for the third quarter of 2025 compared to 2024 primarily due to higher retail rates from the 2024 regulatory rate review with new rates effective October 2024 and an increase in the average number of customers.

Operations and maintenance is consistent for the third quarter of 2025 compared to 2024 primarily due to higher technology costs, higher insurance expense due to higher premiums associated with third-party liability coverage and higher general and administrative costs, offset by lower energy efficiency program costs (offset in operating revenue), lower regulatory impacts from the 2024 general rate review and lower plant operations and maintenance costs.

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Depreciation and amortization decreased $6 million, or 13%, for the third quarter of 2025 compared to 2024 primarily due to lower depreciation rates as a result of extending the life of the Valmy generation facility with the conversion to natural gas.

Interest expense increased $3 million, or 14%, for the third quarter of 2025 compared to 2024 primarily due to higher carrying charges on regulatory balances and higher long-term debt.

Allowance for borrowed and equity funds increased $13 million, for the third quarter of 2025 compared to 2024 primarily due to higher construction work-in-progress.

Interest and dividend income increased $1 million, or 50%, for the third quarter of 2025 compared to 2024 primarily due to favorable interest income, mainly from higher carrying charges on regulatory balances.

Income tax expense increased $1 million, or 17%, for the third quarter of 2025 compared to 2024 primarily due to higher pretax income, offset by the effects of ratemaking. The effective tax rate was 9% in 2025 and 11% in 2024 and decreased primarily due to the effects of ratemaking.

First Nine Months of 2025 Compared to First Nine Months of 2024

Electric utility margin increased $20 million, or 5%, for the first nine months of 2025 compared to 2024 primarily due to:

•$41 million of higher electric retail utility margin primarily due to higher retail rates from the 2024 regulatory rate review with new rates effective October 2024 and price impacts from changes in sales mix, offset by an accrual in connection with a potential customer refund arising from ongoing regulatory proceedings. Retail customer volumes, including distribution only service customers, increased 0.6% primarily due to an increase in the average number of customers and

• $4 million of higher energy efficiency program revenue (offset in operations and maintenance expense).

The increase in electric utility margin was partially offset by:

•$21 million of lower wholesale and transmission revenue and

•$6 million of lower revenue related to an accrual in connection with a potential customer refund arising from ongoing regulatory proceedings.

Natural gas utility margin increased $5 million, or 12%, for the first nine months of 2025 compared to 2024 primarily due to higher retail rates from the 2024 regulatory rate review with new rates effective October 2024 and an increase in the average number of customers.

Operations and maintenance increased $6 million, or 3%, for the first nine months of 2025 compared to 2024 primarily due to higher insurance expense due to higher premiums associated with third-party liability coverage and higher technology costs, partially offset by lower administrative and general costs, lower regulatory impacts from the 2024 general rate review and lower energy efficiency program costs (offset in revenue).

Depreciation and amortization decreased $20 million, or 14%, for the first nine months of 2025 compared to 2024 primarily due to lower depreciation rates and regulatory amortizations as a result of extending the life of the Valmy generation facility with the conversion to natural gas.

Interest expense increased $9 million, or 14%, for the first nine months of 2025 compared to 2024 primarily due to higher carrying charges on regulatory balances and higher long-term debt.

Allowance for borrowed and equity funds increased $25 million for the first nine months of 2025 compared to 2024 primarily due to higher construction work-in-progress.

Interest and dividend income decreased $2 million, or 18%, for the first nine months of 2025 compared to 2024 primarily due to unfavorable interest income, mainly from lower carrying charges on regulatory balances.

Income tax expense increased $5 million, or 63%, for the first nine months of 2025 compared to 2024 primarily due to higher pretax income, offset by the effects of ratemaking. The effective tax rate was 10% in 2025 and in 2024 due to the effects of ratemaking.

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Liquidity and Capital Resources

As of September 30, 2025, Sierra Pacific's total net liquidity was as follows (in millions):

Cash and cash equivalents						$	37
Credit facility						400
Total net liquidity						$	437
Credit facility:
Maturity date						2028

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2025 and 2024, were $130 million and $330 million, respectively. The change was primarily due to higher payments related to fuel and energy costs, the timing of payments for operating costs and decreased customer deposits, partially offset by lower 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, 2025 and 2024, were $(1,084) million and $(432) 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, 2025 and 2024, were $971 million and $72 million, respectively. The change was primarily due to higher contributions from NV Energy, Inc., higher proceeds from the issuance of junior subordinated debt and lower dividends paid to NV Energy, Inc.

Debt Authorizations

Sierra Pacific currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $4.0 billion (excluding borrowings under Sierra Pacific's $400 million secured credit facility); and (2) maintain a revolving credit facility of up to $600 million. Sierra Pacific currently has an effective shelf registration statement filed with the SEC to issue an additional $2.1 billion of general and refunding mortgage securities and unsecured debt securities through April 2028.

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.

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Capital Expenditures

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

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
			2024						2025						2025
Solar generation			$	95					$	222					$	414
Electric battery storage			86						369						396
Electric transmission			86						263						345
Electric distribution			142						146						190
Wildfire prevention			21						14						18
Other			3						70						152
Total			$	433					$	1,084					$	1,515

Sierra Pacific receives PUCN approval through its IRP filings for various projects. Sierra Pacific has included estimates from these IRP filings in its forecast capital expenditures for 2025. These estimates can change as a result of the RFP process, continued evaluation and future IRP filing refinements. Sierra Pacific's capital expenditures include the following:

•Solar generation and electric battery storage primarily consist of a 400-MW solar photovoltaic facility with an additional 400 MWs of co-located battery storage that is being developed in Churchill County, Nevada with ownership share approved by the PUCN of 90% Sierra Pacific and 10% Nevada Power. Commercial operation of the solar facility is expected by early 2027 and commercial operation of the co-located battery storage is expected by mid-2026.

•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.

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

•Wildfire prevention includes both growth and operating capital that include expenditures contained in a comprehensive natural disaster protection plan filed and approved by the PUCN. These projects include, but are not limited to, rebuilding distribution lines with covered conductor, converting overhead distribution lines to underground and copper wire and pole replacement projects.

•Other includes both growth projects and operating expenditures. Growth projects primarily consist of a repower project at the Valmy generating facility to convert existing coal-fueled combustion to natural gas-fueled combustion that was approved by the PUCN and a hydrogen-capable natural gas simple cycle combustion turbine peakers project at the Valmy generating facility. Operating expenditures consist of information technology expenditures, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.

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2024 Joint Integrated Resource Plan

In October 2025, the Nevada Utilities submitted a Joint Application for approval of the First Amendment to the 2024 Joint Integrated Resource Plan. The First Amendment seeks approval to enter into a 20-year power purchase agreement with the developer for an additional 150-MW battery energy storage system that will reduce the Nevada Utilities' open position beginning in the summer of 2027. The battery energy storage system will be co-located with the existing Dodge Flat solar and battery facility in Washoe County, Nevada. An order is expected in 2026.

Material Cash Requirements

As of September 30, 2025, 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, 2024, other than those disclosed in Note 5 of the Notes to Consolidated Financial Statements in Part I, 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, 2024. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2024.

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Eastern Energy Gas Holdings, LLC and its subsidiaries

Consolidated Financial Section

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PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors 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, 2025, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and nine-month periods ended September 30, 2025 and 2024, and of cash flows for the nine-month periods ended September 30, 2025 and 2024, 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, 2024, 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 21, 2025, 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, 2024, 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

October 31, 2025

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EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

			As of
			September 30,						December 31,
			2025						2024
ASSETS
Current assets:
Cash and cash equivalents			$	105					$	34
Trade receivables, net			155						189
Receivables from affiliates			42						33
Notes receivable from affiliates			525						—
Inventories			158						143
Prepayments and other deferred charges			94						85
Natural gas imbalances			29						71
Other current assets			74						52
Total current assets			1,182						607
Property, plant and equipment, net			10,356						10,338
Goodwill			1,286						1,286
Investments			256						261
Other assets			98						85
Total assets			$	13,178					$	12,577

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

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EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)

			As of
			September 30,						December 31,
			2025						2024
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable			$	71					$	86
Accounts payable to affiliates			38						33
Accrued interest			72						25
Accrued property, income and other taxes			89						291
Accrued employee expenses			42						21
Regulatory liabilities			31						29
Current portion of long-term debt			293						—
Other current liabilities			46						62
Total current liabilities			682						547
Long-term debt			4,161						3,231
Regulatory liabilities			622						627
Deferred income taxes			602						498
Other long-term liabilities			118						139
Total liabilities			6,185						5,042
Commitments and contingencies (Note 9)
Equity:
Member's equity:
Membership interests			5,772						6,300
Accumulated other comprehensive loss, net			(31)						(35)
Total member's equity			5,741						6,265
Noncontrolling interests			1,252						1,270
Total equity			6,993						7,535
Total liabilities and equity			$	13,178					$	12,577

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

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EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

			Three-Month Periods												Nine-Month Periods
			Ended September 30,												Ended September 30,
			2025						2024						2025						2024
Operating revenue			$	478					$	463					$	1,563					$	1,493
Operating expenses:
Cost of gas			1						8						2						6
Operations and maintenance			152						143						420						414
Depreciation and amortization			87						85						261						250
Property and other taxes			36						34						106						100
Total operating expenses			276						270						789						770
Operating income			202						193						774						723
Other income (expense):
Interest expense, net			(55)						(30)						(163)						(98)
Allowance for equity funds			4						4						9						7
Interest and dividend income			7						3						14						7
Other, net			2						1						4						2
Total other income (expense)			(42)						(22)						(136)						(82)
Income before income tax expense (benefit) and equity income (loss)			160						171						638						641
Income tax expense (benefit)			30						36						127						142
Equity income (loss)			5						6						36						55
Net income			135						141						547						554
Net income attributable to noncontrolling interests			28						27						110						101
Net income attributable to Eastern Energy Gas			$	107					$	114					$	437					$	453

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

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EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)

			Three-Month Periods												Nine-Month Periods
			Ended September 30,												Ended September 30,
			2025						2024						2025						2024
Net income			$	135					$	141					$	547					$	554
Other comprehensive (loss) income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $—, $—, $— and $—			—						—						1						1
Unrealized (losses) gains on cash flow hedges, net of tax of $(1), $(1), $1 and $—			(2)						(2)						3						1
Total other comprehensive (loss) income, net of tax			(2)						(2)						4						2
Comprehensive income			133						139						551						556
Comprehensive income attributable to noncontrolling interests			28						27						110						101
Comprehensive income attributable to Eastern Energy Gas			$	105					$	112					$	441					$	455

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

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EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)

																																	Accumulated
																																	Other
																											Membership						Comprehensive						Noncontrolling						Total
																											Interests						Loss, Net						Interests						Equity
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
Balance, June 30, 2025																											$	5,665					$	(29)					$	1,260					$	6,896
Net income																											107						—						28						135
Other comprehensive loss																											—						(2)						—						(2)
Distributions																											(1)						—						(36)						(37)
Contributions																											1						—						—						1
Balance, September 30, 2025																											$	5,772					$	(31)					$	1,252					$	6,993
Balance, December 31, 2024																											$	6,300					$	(35)					$	1,270					$	7,535
Net income																											437						—						110						547
Other comprehensive income																											—						4						—						4
Distributions																											(1,190)						—						(128)						(1,318)
Contributions																											225						—						—						225
Balance, September 30, 2025																											$	5,772					$	(31)					$	1,252					$	6,993

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

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EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

			Nine-Month Periods
			Ended September 30,
			2025						2024
Cash flows from operating activities:
Net income			$	547					$	554
Adjustments to reconcile net income to net cash flows from operating activities:
Losses on other items, net			4						3
Depreciation and amortization			261						250
Allowance for equity funds			(9)						(7)
Equity (income) loss, net of distributions			—						20
Changes in regulatory assets and liabilities			(20)						(1)
Deferred income taxes			100						96
Other, net			—						1
Changes in other operating assets and liabilities:
Trade receivables and other assets			39						90
Receivables from affiliates			(9)						(5)
Gas balancing activities			5						3
Accrued property, income and other taxes			(12)						19
Accounts payable to affiliates			5						(1)
Accounts payable and other liabilities			56						16
Net cash flows from operating activities			967						1,038
Cash flows from investing activities:
Capital expenditures			(245)						(244)
Proceeds from sales of marketable securities			8						3
Notes to affiliates			(530)						—
Repayment of notes by affiliates			5						—
Other, net			—						1
Net cash flows from investing activities			(762)						(240)
Cash flows from financing activities:
Proceeds from long-term debt			1,187						—
Repayment of notes payable to affiliates, net			—						(400)
Distributions to noncontrolling interests			(128)						(123)
Distributions to parent			(1,189)						(226)
Net cash flows from financing activities			(130)						(749)
Net change in cash and cash equivalents and restricted cash and cash equivalents			75						49
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period			61						93
Cash and cash equivalents and restricted cash and cash equivalents at end of period			$	136					$	142

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

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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 holds 100% of the general partner interest and 75% of the limited partner interests of Cove Point. In addition, Eastern Energy Gas holds 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 headquartered in Iowa that has investments in subsidiaries principally engaged in energy businesses. BHE is a wholly owned 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, 2025, and for the three- and nine-month periods ended September 30, 2025 and 2024. The results of operations for the three- and nine-month periods ended September 30, 2025, 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, 2024, 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, 2025.

Segment Information

Eastern Energy Gas currently has one reportable segment, which includes its natural gas transmission, storage and LNG operations. Eastern Energy Gas' chief operating decision maker ("CODM") is the BHE Pipeline Group (which consists primarily of BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company) President and Chief Executive Officer. The CODM uses net income attributable to Eastern Energy Gas, as reported on the Consolidated Statements of Operations, and generally considers actual results versus historical results, budgets or forecast, as well as unique risks and opportunities, when making decisions about the allocation of resources and capital. The segment expenses regularly provided to the CODM align with the captions presented on the Consolidated Statements of Operations. The measure of segment assets is reported on the Consolidated Balance Sheets as total assets.

(2)    New Accounting Pronouncements

In December 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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.

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In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures Subtopic 220-40, "Disaggregation of Income Statement Expenses" which addresses requests from investors for more detailed information about certain expenses and requires disclosure of the amounts of purchases of inventory, employee compensation, depreciation and intangible asset amortization included in each relevant expense caption presented on the income statement. This guidance, as clarified in ASU 2025-01, is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. 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.

(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						2025						2024
Utility plant:
Interstate natural gas transmission assets			34 - 51 years						$	6,552					$	6,461
Storage assets			47 - 79 years						2,807						2,767
Intangible plant and other assets			4 - 53 years						509						482
Utility plant in-service									9,868						9,710
Accumulated depreciation and amortization									(3,511)						(3,381)
Utility plant in-service, net									6,357						6,329
Nonutility plant:
LNG facility			40 years						4,567						4,565
Accumulated depreciation and amortization									(869)						(779)
Nonutility plant, net									3,698						3,786
									10,055						10,115
Construction work-in-progress									301						223
Property, plant and equipment, net									$	10,356					$	10,338

Construction work-in-progress includes $283 million and $213 million as of September 30, 2025, and December 31, 2024, respectively, related to the construction of utility plant.

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(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,
			2025						2024
Investments:
Investment funds			$	11					$	18
Equity method investments:
Iroquois			245						243
Total investments			256						261
Restricted cash and cash equivalents:
Customer deposits			31						27
Total restricted cash and cash equivalents			31						27
Total investments and restricted cash and cash equivalents			$	287					$	288
Reflected as:
Other current assets			$	31					$	27
Noncurrent assets			256						261
Total investments and restricted cash and cash equivalents			$	287					$	288

Equity Method Investments

Eastern Energy Gas, through subsidiaries, holds 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, 2025, and December 31, 2024, 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 $36 million and $75 million for the nine-month periods ended September 30, 2025 and 2024, 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,
			2025						2024
Cash and cash equivalents			$	105					$	34
Restricted cash and cash equivalents included in other current assets			31						27
Total cash and cash equivalents and restricted cash and cash equivalents			$	136					$	61

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(5)    Recent Financing Transactions

In January 2025, Eastern Energy Gas issued $700 million of 5.80% Senior Notes due January 2035 and $500 million of 6.20% Senior Notes due January 2055. Eastern Energy Gas used the net proceeds from the sale of the notes to rebalance its capitalization structure by returning a portion of the equity capital received from its indirect parent, BHE.

(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,
			2025						2024						2025						2024
Federal statutory income tax rate			21		%				21		%				21		%				21		%
State income tax, net of federal income tax impacts			1						2						2						3
Equity earnings			1						1						1						2
Noncontrolling interest			(4)						(3)						(4)						(3)
Other, net			—						—						—						(1)
Effective income tax rate			19		%				21		%				20		%				22		%

Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, Eastern Energy Gas' provision for federal and state income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. For current federal and state income taxes, Eastern Energy Gas had a receivable from BHE of $6 million as of September 30, 2025, and a payable to BHE of $188 million as of December 31, 2024. The change is primarily due to the settlement of the income tax payable balance through non-cash contributions in 2025.

(7)    Employee Benefit Plans

Eastern Energy Gas is a participant in benefit plans sponsored by MidAmerican Energy Company ("MidAmerican Energy"), an affiliate. The MidAmerican Energy Company Retirement Plan includes a qualified pension plan that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain postretirement health care and life insurance benefits for eligible retirees on behalf of Eastern Energy Gas. Eastern Energy Gas contributed $4 million and $6 million to the MidAmerican Energy Company Retirement Plan for the nine-month periods ended September 30, 2025 and 2024, respectively, and $1 million to the MidAmerican Energy Company Welfare Benefit Plan for the nine-month period ended September 30, 2024. 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, 2025, and December 31, 2024, Eastern Energy Gas' amount due to MidAmerican Energy associated with these plans and included in other long-term liabilities on the Consolidated Balance Sheets was $40 million and $39 million, respectively.

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(8)    Fair Value Measurements

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

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

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

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

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, 2025:
Assets:
Foreign currency exchange rate derivatives						$	—					$	12					$	—					$	12
Money market mutual funds						105						—						—						105
Equity securities:
Investment funds						11						—						—						11
						$	116					$	12					$	—					$	128
As of December 31, 2024:
Assets:
Money market mutual funds						$	34					$	—					$	—					$	34
Equity securities:
Investment funds						18						—						—						18
						$	52					$	—					$	—					$	52
Liabilities:
Foreign currency exchange rate derivatives						$	—					$	(23)					$	—					$	(23)

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.

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Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal 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, 2025												As of December 31, 2024
						Carrying						Fair						Carrying						Fair
						Value						Value						Value						Value
Long-term debt						$	4,454					$	4,310					$	3,231					$	2,919

(9)    Commitments and Contingencies

Environmental Laws and Regulations

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

Legal Matters

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

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(10)    Revenue from Contracts with Customers

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

			Three-Month Periods												Nine-Month Periods
			Ended September 30,												Ended September 30,
			2025						2024						2025						2024
Customer Revenue:
Regulated:
Gas transmission and storage			$	284					$	274					$	901					$	883
Wholesale			1						7						2						7
Other			—						—						—						1
Total regulated			285						281						903						891
Nonregulated			192						182						658						602
Total Customer Revenue			477						463						1,561						1,493
Other revenue(1)			1						—						2						—
Total operating revenue			$	478					$	463					$	1,563					$	1,493

(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, contingent fees from certain farmout agreements recognized in accordance with ASC 450, "Contingencies" and the royalties from the conveyance of mineral rights accounted for under Accounting Standards Codification 932, "Extractive Activities – Oil and Gas".

Eastern Energy Gas has recognized contract liabilities of $28 million and $40 million as of September 30, 2025, and December 31, 2024, 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 each of the nine-month periods ended September 30, 2025 and 2024, Eastern Energy Gas recognized revenue of $13 million 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, 2025 (in millions):

			Performance obligations expected to be satisfied:
			Less than 12 months						More than 12 months						Total
Eastern Energy Gas			$	1,769					$	13,373					$	15,142

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(11)    Components of Accumulated Other Comprehensive Loss, Net

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

						Unrecognized																		Accumulated
						Amounts On						Unrealized												Other
						Retirement						Losses on Cash						Noncontrolling						Comprehensive
						Benefits						Flow Hedges						Interests						Loss, Net
Balance, December 31, 2023						$	(3)					$	(38)					$	1					$	(40)
Other comprehensive income						1						1						—						2
Balance, September 30, 2024						$	(2)					$	(37)					$	1					$	(38)
Balance, December 31, 2024						$	(2)					$	(34)					$	1					$	(35)
Other comprehensive income						1						3						—						4
Balance, September 30, 2025						$	(1)					$	(31)					$	1					$	(31)

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

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

Results of Operations for the Third Quarter and First Nine Months of 2025 and 2024

Overview

Net income attributable to Eastern Energy Gas for the third quarter of 2025 was $107 million, a decrease of $7 million, compared to 2024. Net income decreased primarily due to an increase in interest expense, partially offset by higher margin from regulated gas transmission and storage operations of $15 million.

Net income attributable to Eastern Energy Gas for the first nine months of 2025 was $437 million, a decrease of $16 million, compared to 2024. Net income decreased primarily due to an increase in interest expense and a decrease in equity income, partially offset by higher margin from regulated gas transmission and storage operations of $28 million and higher earnings from Cove Point of $21 million, largely due to an increase in variable revenue.

Quarter Ended September 30, 2025, Compared to Quarter Ended September 30, 2024

Operating revenue increased $15 million, or 3%, for the third quarter of 2025 compared to 2024, primarily due to an increase in Cove Point LNG variable revenue of $8 million, an increase in regulated gas transmission and storage services revenues primarily due to additional capacity contracts of $8 million, an increase in services provided to affiliates of $3 million and an increase in variable revenue related to park and loan activity of $2 million, partially offset by a decrease in regulated gas sales for operational and system balancing purposes primarily due to decreased volumes of $6 million.

Cost of gas decreased $7 million, or 88%, for the third quarter of 2025 compared to 2024, primarily due to a decrease in volumes sold.

Operations and maintenance increased $9 million, or 6%, for the third quarter of 2025 compared to 2024, primarily due to higher plant operations and maintenance costs of $8 million and an increase in services provided to affiliates of $3 million, partially offset by lower salary and benefit expenses of $4 million.

Interest expense, net increased $25 million, or 83%, for the third quarter of 2025 compared to 2024, primarily due to the issuances of $1.2 billion of long-term debt in the first quarter of 2025 of $18 million and higher interest rates on $1.0 billion of long-term debt refinanced during 2024 of $7 million.

Interest and dividend income increased $4 million for the third quarter of 2025 compared to 2024, primarily due to interest income from higher outstanding loans under BHE GT&S' intercompany revolving credit agreement.

Income tax expense decreased $6 million, or 17%, for the third quarter of 2025 compared to 2024 and the effective tax rate was 19% for 2025 and 21% for 2024. The effective tax rate decreased primarily due to various changes in the state effective rate.

First Nine Months of 2025 Compared to First Nine Months of 2024

Operating revenue increased $70 million, or 5%, for the first nine months of 2025 compared to 2024, primarily due to an increase in Cove Point LNG variable revenue of $51 million, an increase in CGT's regulated gas transmission service revenues of $16 million primarily due to additional capacity contracts of $9 million and the settlement of its general rate case of $8 million, an increase in EGTS' regulated gas transmission and storage services revenues primarily due to additional capacity contracts of $16 million and an increase in services provided to affiliates of $3 million, partially offset by a decrease in Cove Point's storage-related service revenues of $7 million, a decrease in variable revenue related to park and loan activity of $5 million and a decrease in regulated gas sales for operational and system balancing purposes primarily due to decreased volumes of $5 million.

Cost of gas decreased $4 million, or 67%, for the first nine months of 2025 compared to 2024, primarily due to a decrease in volumes sold.

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Operations and maintenance increased $6 million, or 1%, for the first nine months of 2025 compared to 2024, primarily due to an increase in services provided to affiliates of $3 million and an increase in charges from affiliates of $1 million.

Depreciation and amortization increased $11 million, or 4%, for the first nine months of 2025 compared to 2024, primarily due to higher plant placed in service of $8 million and the settlement of deprecation rates in CGT's general rate case of $3 million.

Interest expense, net increased $65 million, or 66%, for the first nine months of 2025 compared to 2024, primarily due to the issuances of $1.2 billion of long-term debt in the first quarter of 2025 of $50 million and higher interest rates on $1.0 billion of long-term debt refinanced during 2024 of $21 million, partially offset by lower lending activity under BHE GT&S' intercompany revolving credit agreement of $8 million.

Interest and dividend income increased $7 million for the first nine months of 2025 compared to 2024, primarily due to interest income from higher outstanding loans under BHE GT&S' intercompany revolving credit agreement.

Income tax expense decreased $15 million, or 11%, for the first nine months of 2025 compared to 2024 and the effective tax rate was 20% for 2025 and 22% for 2024. The effective tax rate decreased primarily due to various changes in the state effective rate and lower equity earnings from Iroquois.

Equity income decreased $19 million, or 35%, for the first nine months of 2025 compared to 2024, primarily due to lower variable revenues at Iroquois, largely from unfavorable pricing.

Net income attributable to noncontrolling interests increased $9 million, or 9%, for the first nine months of 2025 compared to 2024, primarily due to higher net income attributable to Cove Point.

Liquidity and Capital Resources

As of September 30, 2025, Eastern Energy Gas' total net liquidity was as follows (in millions):

Cash and cash equivalents						$	105
Intercompany revolving credit agreement						400
Total net liquidity						$	505
Intercompany revolving credit agreement:
Maturity date						2026

Eastern Energy Gas' future financial performance and capital expenditures related to certain projects may be affected by the combined effects of ongoing macroeconomic and geopolitical conditions, including changes in international trade policies and tariff regimes. The pace of change in these areas has accelerated during 2025, and significant uncertainty persists regarding the scope and duration of these external factors. Accordingly, Eastern Energy Gas is unable to estimate their impact on its business at this time.

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2025 and 2024 were $967 million and $1.0 billion, respectively. The change is primarily due to lower distributions from Iroquois, the timing of the Cove Point's payment in lieu of taxes program and higher cash paid for interest, partially offset by the timing of payments for operating costs and other working capital adjustments.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2025 and 2024 were $(762) million and $(240) million, respectively. The change is primarily due to an increase in notes issued to its parent under an intercompany revolving credit agreement of $530 million and an increase in capital expenditures of $1 million, partially offset by an increase in proceeds from sales of marketable securities of $5 million and an increase the repayment of notes by its parent under an intercompany revolving credit agreement of $5 million.

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Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2025 were $(130) million. Sources of cash totaled $1.2 billion and consisted of proceeds from the issuance of long-term debt. Uses of cash totaled $1.3 billion and consisted of distributions to its indirect parent, BHE, of $1.2 billion and distributions to noncontrolling interests from Cove Point of $128 million.

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 its indirect parent, BHE, of $226 million and distributions to noncontrolling interests from Cove Point of $123 million.

Long-term debt

Eastern Energy Gas currently has an effective shelf registration statement filed with the SEC to issue an additional $400 million of long-term debt securities through January 2027.

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
			2024						2025						2025
Natural gas transmission and storage			$	41					$	45					$	65
Other			203						200						295
Total			$	244					$	245					$	360

Natural gas transmission and storage primarily includes growth capital expenditures related to planned regulated projects. Other includes primarily nonregulated and routine capital expenditures for natural gas transmission, storage and LNG terminalling infrastructure needed to serve existing and expected demand.

Material Cash Requirements

As of September 30, 2025, 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, 2024, other than those disclosed in Note 5 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

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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, 2024. There have been no significant changes in Eastern Energy Gas' assumptions regarding critical accounting estimates since December 31, 2024.

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Eastern Gas Transmission and Storage, Inc. and its subsidiaries

Consolidated Financial Section

192

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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, 2025, 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, 2025 and 2024, and of cash flows for the nine-month periods ended September 30, 2025 and 2024, 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, 2024, 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 21, 2025 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, 2024, 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

October 31, 2025

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EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)

			As of
			September 30,						December 31,
			2025						2024
ASSETS
Current assets:
Cash and cash equivalents			$	35					$	8
Restricted cash and cash equivalents			27						24
Trade receivables, net			74						93
Receivables from affiliates			28						17
Notes receivable from affiliates			143						—
Inventories			58						55
Prepayments and other deferred charges			29						28
Natural gas imbalances			29						72
Other current assets			12						10
Total current assets			435						307
Property, plant and equipment, net			4,878						4,771
Other assets			66						73
Total assets			$	5,379					$	5,151

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

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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,
			2025						2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable			$	42					$	55
Accounts payable to affiliates			30						27
Accrued interest			24						7
Accrued property, income and other taxes			63						68
Accrued employee expenses			34						18
Regulatory liabilities			15						13
Customer deposits			27						24
Other current liabilities			12						18
Total current liabilities			247						230
Long-term debt			1,623						1,622
Regulatory liabilities			518						527
Deferred income taxes			141						85
Other long-term liabilities			81						81
Total liabilities			2,610						2,545
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			1,377						1,352
Retained earnings			807						671
Accumulated other comprehensive loss, net			(24)						(26)
Total shareholder's equity			2,769						2,606
Total liabilities and shareholder's equity			$	5,379					$	5,151

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

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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,
			2025						2024						2025						2024
Operating revenue			$	237					$	233					$	741					$	733
Operating expenses:
Cost of gas			1						8						2						6
Operations and maintenance			102						98						286						280
Depreciation and amortization			40						39						120						116
Property and other taxes			15						14						44						42
Total operating expenses			158						159						452						444
Operating income			79						74						289						289
Other income (expense):
Interest expense, net			(17)						(16)						(52)						(50)
Allowance for equity funds			3						2						7						5
Other, net			3						2						8						4
Total other income (expense)			(11)						(12)						(37)						(41)
Income before income tax expense (benefit)			68						62						252						248
Income tax expense (benefit)			17						15						63						63
Net income			$	51					$	47					$	189					$	185

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

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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,
			2025						2024						2025						2024
Net income			$	51					$	47					$	189					$	185
Other comprehensive income, net of tax:
Unrealized gains on cash flow hedges, net of tax of $1, $—, $1 and $—			1						—						2						1
Total other comprehensive income, net of tax			1						—						2						1
Comprehensive income			$	52					$	47					$	191					$	186

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

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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, 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
Balance, June 30, 2025			60,101						$	609					$	1,376					$	809					$	(25)					$	2,769
Net income			—						—						—						51						—						51
Other comprehensive income			—						—						—						—						1						1
Dividends declared			—						—						—						(53)						—						(53)
Contributions			—						—						1						—						—						1
Balance, September 30, 2025			60,101						$	609					$	1,377					$	807					$	(24)					$	2,769
Balance, December 31, 2024			60,101						$	609					$	1,352					$	671					$	(26)					$	2,606
Net income			—						—						—						189						—						189
Other comprehensive income			—						—						—						—						2						2
Dividends declared			—						—						—						(53)						—						(53)
Contributions			—						—						25						—						—						25
Balance, September 30, 2025			60,101						$	609					$	1,377					$	807					$	(24)					$	2,769

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

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EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

			Nine-Month Periods
			Ended September 30,
			2025						2024
Cash flows from operating activities:
Net income			$	189					$	185
Adjustments to reconcile net income to net cash flows from operating activities:
Gains on other items, net			—						(1)
Depreciation and amortization			120						116
Allowance for equity funds			(7)						(5)
Changes in regulatory assets and liabilities			(6)						(13)
Deferred income taxes			53						58
Other, net			(1)						(1)
Changes in other operating assets and liabilities:
Trade receivables and other assets			34						47
Receivables from affiliates			(11)						(5)
Gas balancing activities			4						6
Accrued property, income and other taxes			(16)						(19)
Accounts payable to affiliates			3						4
Accounts payable and other liabilities			28						19
Net cash flows from operating activities			390						391
Cash flows from investing activities:
Capital expenditures			(188)						(154)
Proceeds from sales of marketable securities			8						3
Notes to affiliates			(153)						—
Repayment of notes by affiliates			10						—
Other, net			—						1
Net cash flows from investing activities			(323)						(150)
Cash flows from financing activities:
Repayment of notes payable to affiliates, net			—						(2)
Dividends paid			(37)						(215)
Net cash flows from financing activities			(37)						(217)
Net change in cash and cash equivalents and restricted cash and cash equivalents			30						24
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period			32						34
Cash and cash equivalents and restricted cash and cash equivalents at end of period			$	62					$	58

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

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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 headquartered in Iowa that has investments in subsidiaries principally engaged in energy businesses. BHE is a wholly owned 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, 2025, and for the three- and nine-month periods ended September 30, 2025 and 2024. The results of operations for the three- and nine-month periods ended September 30, 2025, 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, 2024, 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, 2025.

Segment Information

EGTS currently has one reportable segment, which includes its natural gas transmission and storage operations. EGTS' chief operating decision maker ("CODM") is the BHE Pipeline Group (which consists primarily of BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company) President and Chief Executive Officer. The CODM uses net income, as reported on the Consolidated Statements of Operations, and generally considers actual results versus historical results, budgets or forecast, as well as unique risks and opportunities, when making decisions about the allocation of resources and capital. The segment expenses regularly provided to the CODM align with the captions presented on the Consolidated Statements of Operations. The measure of segment assets is reported on the Consolidated Balance Sheets as total assets.

(2)    New Accounting Pronouncements

In December 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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.

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In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures Subtopic 220-40, "Disaggregation of Income Statement Expenses" which addresses requests from investors for more detailed information about certain expenses and requires disclosure of the amounts of purchases of inventory, employee compensation, depreciation and intangible asset amortization included in each relevant expense caption presented on the income statement. This guidance, as clarified in ASU 2025-01, is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. 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.

(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						2025						2024
Interstate natural gas transmission assets			47 - 51 years						$	5,179					$	5,093
Storage assets			47 - 51 years						1,837						1,803
Intangible plant and other assets			12 - 53 years						404						386
Plant in-service									7,420						7,282
Accumulated depreciation and amortization									(2,791)						(2,699)
									4,629						4,583
Construction work-in-progress									249						188
Property, plant and equipment, net									$	4,878					$	4,771

(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,
			2025						2024
Investments:
Investment funds			$	11					$	18
Restricted cash and cash equivalents:
Customer deposits			27						24
Total restricted cash and cash equivalents			27						24
Total investments and restricted cash and cash equivalents			$	38					$	42
Reflected as:
Current assets			$	27					$	24
Other assets			11						18
Total investments and restricted cash and cash equivalents			$	38					$	42

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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,
			2025						2024
Cash and cash equivalents			$	35					$	8
Restricted cash and cash equivalents			27						24
Total cash and cash equivalents and restricted cash and cash equivalents			$	62					$	32

(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,
			2025						2024						2025						2024
Federal statutory income tax rate			21		%				21		%				21		%				21		%
State income tax, net of federal income tax impacts			4						4						4						4
Effects of ratemaking			(1)						(1)						(1)						—
Other, net			1						—						1						—
Effective income tax rate			25		%				24		%				25		%				25		%

(6)    Employee Benefit Plans

EGTS is a participant in benefit plans sponsored by MidAmerican Energy Company ("MidAmerican Energy"), an affiliate. The MidAmerican Energy Company Retirement Plan includes a qualified pension plan that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain postretirement health care and life insurance benefits for eligible retirees on behalf of EGTS. EGTS contributed $4 million and $5 million to the MidAmerican Energy Company Retirement Plan for the nine-month periods ended September 30, 2025 and 2024, respectively, and $1 million to the MidAmerican Energy Company Welfare Benefit Plan for the nine-month period ended September 30, 2024. 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, 2025, and December 31, 2024, EGTS' amount due to MidAmerican Energy associated with these plans and included in other long-term liabilities on the Consolidated Balance Sheets was $35 million.

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(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.

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, 2025:
Assets:
Money market mutual funds						$	35					$	—					$	—					$	35
Equity securities:
Investment funds						11						—						—						11
						$	46					$	—					$	—					$	46
As of December 31, 2024:
Assets:
Money market mutual funds						$	8					$	—					$	—					$	8
Equity securities:
Investment funds						18						—						—						18
						$	26					$	—					$	—					$	26

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.

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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, 2025												As of December 31, 2024
			Carrying Value						Fair Value						Carrying Value						Fair Value
Long-term debt			$	1,623					$	1,453					$	1,622					$	1,409

(8)    Commitments and Contingencies

Environmental Laws and Regulations

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

Legal Matters

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

(9)    Revenue from Contracts with Customers

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

			Three-Month Periods												Nine-Month Periods
			Ended September 30,												Ended September 30,
			2025						2024						2025						2024
Customer Revenue:
Regulated:
Gas transmission			$	148					$	142					$	484					$	475
Gas storage			70						69						212						210
Wholesale			1						7						2						7
Other			—						—						—						1
Total regulated			219						218						698						693
Management service and other revenues			17						15						41						40
Total Customer Revenue			236						233						739						733
Other revenue(1)			1						—						2						—
Total operating revenue			$	237					$	233					$	741					$	733

(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, contingent fees from certain farmout agreements recognized in accordance with ASC 450, "Contingencies" and the royalties from the conveyance of mineral rights accounted for under Accounting Standards Codification 932, "Extractive Activities – Oil and Gas".

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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, 2025 (in millions):

			Performance obligations expected to be satisfied:
			Less than 12 months						More than 12 months						Total
EGTS			$	827					$	3,131					$	3,958

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

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

Results of Operations for the Third Quarter and First Nine Months of 2025 and 2024

Overview

Net income for the third quarter of 2025 was $51 million, an increase of $4 million, compared to 2024. Net income increased primarily due to higher margin from regulated gas transmission and storage operations of $11 million, partially offset by higher operations and maintenance expense.

Net income for the first nine months of 2025 was $189 million, an increase of $4 million, compared to 2024. Net income increased primarily due to higher margin from regulated gas transmission and storage operations of $12 million, partially offset by higher operations and maintenance expense.

Quarter Ended September 30, 2025, Compared to Quarter Ended September 30, 2024

Operating revenue increased $4 million, or 2%, for the third quarter of 2025 compared to 2024, primarily due to an increase in regulated gas transmission and storage services revenues primarily due to additional capacity contracts of $5 million, an increase in variable revenue related to park and loan activity of $2 million and an increase in services provided to affiliates of $2 million, partially offset by a decrease in regulated gas sales for operational and system balancing purposes primarily due to decreased volumes of $6 million.

Cost of gas decreased $7 million, or 88%, for the third quarter of 2025 compared to 2024, primarily due to a decrease in volumes sold.

Operations and maintenance increased $4 million, or 4%, for the third quarter of 2025 compared to 2024, primarily due to higher plant operations and maintenance costs of $5 million and an increase in services provided to affiliates of $2 million, partially offset by lower salary and benefit expenses of $5 million.

Income tax expense increased $2 million, or 13%, for the third quarter of 2025 compared to 2024 and the effective tax rate was 25% for 2025 and 24% for 2024.

First Nine Months of 2025 Compared to First Nine Months of 2024

Operating revenue increased $8 million, or 1%, for the first nine months of 2025 compared to 2024, primarily due to an increase in regulated gas transmission and storage services revenues primarily due to additional capacity contracts of $16 million, partially offset by a decrease in variable revenue related to park and loan activity of $5 million and a decrease in regulated gas sales for operational and system balancing purposes primarily due to decreased volumes of $5 million.

Cost of gas decreased $4 million, or 67%, for the first nine months of 2025 compared to 2024, primarily due to a decrease in volumes sold.

Operations and maintenance increased $6 million, or 2%, for the first nine months of 2025 compared to 2024, primarily due to an increase in charges from affiliates.

Income tax expense was flat for the first nine months of 2025 compared to 2024 and the effective tax rate was 25% for 2025 and 2024.

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Liquidity and Capital Resources

As of September 30, 2025, 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						2026

EGTS' future financial performance and capital expenditures related to certain projects may be affected by the combined effects of ongoing macroeconomic and geopolitical conditions, including changes in international trade policies and tariff regimes. The pace of change in these areas has accelerated during 2025, and significant uncertainty persists regarding the scope and duration of these external factors. Accordingly, EGTS is unable to estimate their impact on its business at this time.

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2025 and 2024 were $390 million and $391 million, respectively. The change is primarily due to lower collections from customers, partially offset by other working capital adjustments.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2025 and 2024 were $(323) million and $(150) million, respectively. The change is primarily due to an increase in notes issued to Eastern Energy Gas under an intercompany revolving credit agreement of $153 million and an increase in capital expenditures of $34 million, partially offset by an increase the repayment of notes by Eastern Energy Gas under an intercompany revolving credit agreement of $10 million and an increase in proceeds from sales of marketable securities of $5 million.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2025 were $(37) million and consisted of dividends paid to Eastern Energy Gas.

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.

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.

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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
			2024						2025						2025
Natural gas transmission and storage			$	17					$	40					$	56
Other			137						148						229
Total			$	154					$	188					$	285

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, 2025, 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, 2024.

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, 2024. There have been no significant changes in EGTS' assumptions regarding critical accounting estimates since December 31, 2024.

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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, 2024. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2024. Refer to Note 8 of the Notes to Consolidated Financial Statements of PacifiCorp, Note 8 of the Notes to Consolidated Financial Statements of Nevada Power and Note 8 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, 2025.

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, 2025, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting except for Nevada Power Company and Sierra Pacific Power Company. In July 2025, Nevada Power Company and Sierra Pacific Power Company completed implementation of a new enterprise resource planning system, which was designed to replace or enhance certain internal financial and operating systems. In connection with the enterprise resource planning implementation, Nevada Power Company and Sierra Pacific Power Company updated the processes and controls that constitute the internal control over financial reporting, as necessary, to accommodate related changes to the accounting procedures and business processes. There have been no other changes in internal control over financial reporting during the quarter ended September 30, 2025, that have materially affected, or are reasonably likely to materially affect, the Nevada Power Company and Sierra Pacific Power Company internal control over financial reporting environments.

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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, 2024.

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP

In September 2020, a severe weather event with 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. Amounts sought in outstanding complaints and demands filed in Oregon and in certain demands made in California totaled approximately $55 billion, excluding any doubling or trebling of damages or punitive damages included in the complaints and excluding damages that may be sought by additional plaintiffs granted substitution counsel in the James class action lawsuit described below. Generally, the complaints filed in California do not specify damages sought and are excluded from this amount. Of the $55 billion, $52 billion represents the economic and noneconomic damages sought in the James mass complaints described below. 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 damages associated with timber, shrubs and produce in the event the defendant is determined to have willfully and intentionally trespassed.

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The following map illustrates the general vicinity of the Wildfires.

Investigations

In April 2023, the U.S. Department of Agriculture Forest Service ("USFS") issued its report of investigation into a wildland fire that began in the Opal Creek wilderness outside of the Santiam Canyon that was first reported on August 16, 2020 ("Beachie Creek Fire"), approximately three weeks prior to the September 2020 wind event described above. In March 2025, PacifiCorp received the Oregon Department of Forestry's final investigation report on the Santiam Canyon fires ("ODF's Report"), which concluded that embers from the pre-existing Beachie Creek Fire caused 12 fires within the Santiam Canyon. The ODF's Report also found that PacifiCorp's power lines did not contribute to the overall spread of fire into the Santiam Canyon even though its power lines ignited seven spot fires within the Santiam Canyon that were each suppressed.

The Beachie Creek fire that spread into the Santiam Canyon burned approximately 193,000 acres; the South Obenchain fire burned approximately 33,000 acres; the Echo Mountain Complex fire burned approximately 3,000 acres; and the 242 fire burned approximately 14,000 acres. The James cases described below are associated with the Beachie Creek (Santiam Canyon), South Obenchain, Echo Mountain Complex and 242 fires, which are four distinct fires located hundreds of miles apart.

For more information regarding certain investigative reports from the USFS and the Oregon Department of Forestry ("ODF") and certain legal proceedings affecting Berkshire Hathaway Energy, refer to Note 9 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q, and PacifiCorp, refer to Note 10 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q.

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Wildfire Settlements

PacifiCorp has settled various claims associated with the Wildfires as described below and has settled or settled in principle all wrongful death claims associated with the Wildfires. Additionally, settlements have been reached with substantially all individual plaintiffs, timber companies and insurance subrogation plaintiffs in the Archie Creek fire, Slater fire and the 2022 McKinney Fire with government timber and suppression cost claims remaining.

2020 Wildfires

As of the date of this filing, PacifiCorp has made settlement payments associated with individual plaintiffs, wrongful death claims, insurance subrogation claims, commercial timber claims and certain government claims associated with the 2020 Wildfires totaling $1,184 million. The $1,184 million in settlements were comprised of $324 million associated with the James related fires for plaintiffs who opted out of the James class, insurance subrogation claims and for plaintiffs to certain of the consolidated cases; $253 million associated with the Slater fire; $605 million associated with the Archie Creek fire; and $2 million associated with other fires. For more information, refer to description of the 2020 Wildfires complaints and specific wildfires below.

2022 McKinney Fire

As of the date of this filing, PacifiCorp has made settlement payments associated with individual plaintiffs, wrongful death claims, insurance subrogation claims, commercial timber claims, private timber claims and certain government claims associated with the 2022 McKinney Fire totaling $216 million. For more information, refer to description of the 2022 McKinney Fire complaints below.

2020 Oregon Wildfires, Excluding the Northern California and Southern Oregon Slater Fire ("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 below 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 amount of 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.

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 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. 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 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. Since filing of the original class action complaint, numerous James class members have been named and damages specified in various complaints as described below. Additionally, numerous cases were consolidated into the original James complaint as described below under "James Consolidated Cases."

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In April, May, July and September 2024, and January, May and September 2025, eight separate mass complaints against PacifiCorp naming 1,000, 100, 265, 78, 93, 55, 99 and 34 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, Sergio Garcia Montes et al. v. PacifiCorp, Butte Falls Family Ranch, LLC et al. v. PacifiCorp, Amanda Bateman et al. v. PacifiCorp and Philip Estes et al. v. PacifiCorp, respectively, each referencing the original James case as the lead case. Complaints for some of the plaintiffs in the mass complaints were subsequently dismissed with approximately 1,700 remaining. 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, as well as doubling of economic damages. The class members demand a trial by jury. Refer to "James Court Activity" section below for information regarding additional damages phase trials.

On December 31, 2024, a complaint against PacifiCorp was filed, captioned Frank Timber Resources, Inc. et al. v. PacifiCorp, referencing the original James case as the lead case, ("Frank Timber") in Multnomah County Circuit Court Oregon by four plaintiffs. Similar to the mass complaints described above, the complaint makes damages-only allegations seeking approximately $12 million of economic damages, doubling of economic damages and punitive damages equal to 0.25 times the amount of economic damages. The plaintiffs demand a trial by jury and a trial has been set for January 5, 2026.

On December 31, 2024, a complaint against PacifiCorp was filed, captioned Theodore and Deana Freres et al. v. PacifiCorp, referencing the original James case as the lead case, ("Theodore and Deana Freres") in Multnomah County Circuit Court Oregon by four plaintiffs. Similar to the mass complaints described above, the complaint makes damages-only allegations seeking approximately $1 million of economic damages, doubling of economic damages and punitive damages equal to 0.25 times the amount of economic damages. The plaintiffs demand a trial by jury and a trial has been set for January 5, 2026.

From October 2024 through March 2025, various plaintiffs' counsel filed motions with the Multnomah County Circuit Court Oregon for substitution of lead counsel in the James case for approximately 1,500 plaintiffs, including a minor number of plaintiffs included in the approximately 1,700 plaintiffs in the James mass complaints described above. To date, substitution motions covering substantially all of the approximately 1,500 plaintiffs have been granted. In October 2025, complaints against PacifiCorp naming a small portion of the approximately 1,500 plaintiffs granted substitution counsel were filed in Multnomah County Circuit Court Oregon, referencing the original James case as the lead case. These plaintiffs seek for each individual class member either $2 million or $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, as well as doubling of economic damages. A portion of the 1,500 plaintiffs granted substitution counsel are included in trials scheduled under the July 2025 case management order described below although specific complaints have not yet been filed.

As described below under "James Court Activity," class plaintiffs selected for trial are required to amend their complaints to address facts specific to their complaints, generally resulting in updates to the amount of economic and noneconomic damages sought that are no greater than the amounts specified in the original mass complaints.

As described above under "Investigations," in March 2025, PacifiCorp received the ODF's Report, which concluded that while PacifiCorp's power lines ignited various spot fires within the Santiam Canyon, every such ignition was suppressed and did not contribute to the overall spread of the Beachie Creek Fire into the Santiam Canyon. Approximately 60% of the named plaintiffs in the James mass complaints are associated with the Santiam Canyon fires. Refer to "James Court Activity" below for information regarding PacifiCorp's filings of motions to stay further James damages phase trials in consideration of the ODF's Report described above under "Investigations."

James Trial Activity

In June 2023, a jury verdict was issued in the first James trial finding PacifiCorp's conduct grossly negligent, reckless and willful as to each of the 17 named plaintiffs and the entire class. The jury awarded economic and noneconomic damages. After the jury verdict, the Multnomah County Circuit Court Oregon doubled the economic damages, in accordance with Oregon law, and added punitive damages by applying a 0.25 multiplier to the awarded economic and noneconomic damages. PacifiCorp filed a motion with the Multnomah County Circuit Court Oregon requesting the court offset the damage awards by deducting insurance proceeds received by any of the plaintiffs. In January 2024, PacifiCorp filed a notice of appeal associated with the June 2023 verdict, including whether the case can proceed as a class action.

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Subsequent to the June 2023 James verdict, numerous damages phase trials were held with separate jury verdicts issued and damages awarded for each on a basis consistent with the initial trial and relying on the liability determination in the June 2023 James verdict. PacifiCorp amended its January 2024 appeal of the June 2023 James verdict to include the jury verdicts for the first two damages phase trials. PacifiCorp has filed notices of appeal for the subsequent jury verdicts in the damages phase trials once limited judgments are entered and any post-trial motions filed. Refer to "James Court Activity" below regarding the filing of PacifiCorp's opening appellate brief. The appeals process and further actions could take several years.

The James jury verdicts to date have awarded total net damages of $589 million, including $96 million of doubled economic damages, $406 million of noneconomic damages, $113 million of punitive damages and partially offset by estimated insurance offsets of $26 million. Refer to additional details by trial in Note 10 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q.

Through October 2025, jury verdict awards averaged approximately $5 million per plaintiff, including insurance offset. Additional damages phase trials are scheduled to occur in 2025 through 2028 as described below.

James Court Activity

In April 2025, PacifiCorp filed its opening brief with the Oregon Court of Appeals in connection with its appeal of the June 2023 James verdict and the January and March 2024 verdicts for the first two James damages phase trials. In the opening brief, PacifiCorp addresses numerous procedural and legal issues, including that the class certification is improper due to the plaintiffs being impacted by distinct fires with independent ignition points that were hundreds of miles apart; awarding of non-economic damages is not allowed under Oregon law; plaintiffs failed to prove that PacifiCorp caused harm to every class member; and jury instructions applied incorrect legal standards in assessing class-wide evidence and individual claims. Additionally, PacifiCorp incorporated the ODF's Report into its opening appellate brief. Various parties who are not party to the James case have filed supportive amicus briefs with the court. Plaintiffs filed their combined answering and cross-appeal brief on August 21, 2025, after plaintiffs requested three delays from the Oregon Court of Appeals. PacifiCorp filed its combined reply brief and cross-appeal answering brief on October 17, 2025. Plaintiffs' reply brief is due on November 7, 2025, unless plaintiffs ask for additional extensions. On October 23, 2025, PacifiCorp filed a request with the Oregon Court of Appeals for an expedited oral argument, which, if granted, will facilitate a more prompt decision from the court.

Subsequent to the first two damages phase trials, nine damages phase trials were scheduled to be held in 2025 in accordance with the Multnomah County Circuit Court Oregon's October 2024 case management order, adjudicating the damages of approximately 10 plaintiffs per trial. The first eight of these trials have been held, while the remaining trial is scheduled to begin December 1, 2025. Plaintiffs have been selected for all nine trials. The jury verdicts for the first eight of the damages phase trials were issued in February, March, April, May, June, July, September and October 2025, as described above. Also in accordance with the October 2024 case management order, the parties engaged in an unsuccessful global mediation on May 5 and July 28, 2025, and are further required to engage in global mediation within 30 days after the verdict is rendered in the December 1, 2025, trial with the objective of resolving the claims of the remaining absent class members. In March 2025, PacifiCorp filed a motion to stay the additional damages phase trials scheduled under the October 2024 case management order in consideration of the ODF's Report. This motion was denied on April 18, 2025.

On July 28, 2025, the Multnomah County Circuit Court Oregon issued Case Management Order No. 11 ("CMO No. 11") in response to the May 2025 hearing that was held to evaluate the scheduling of additional damages phase trials. As ordered, CMO No. 11 proposes to schedule dozens of trials in 2026 and over 100 more in 2027 and 2028, involving approximately 2,000 plaintiffs. Additionally, CMO No. 11 requires mediation every other month starting in October 2025.

On August 8, 2025, PacifiCorp filed a motion with the Oregon Court of Appeals to stay the James damages phase trials addressed in CMO No. 11 and to which plaintiffs' counsel responded on August 29, 2025. On September 23, 2025, the Appellate Commissioner of the Oregon Court of Appeals denied PacifiCorp's motion to stay. On September 26, 2025, PacifiCorp filed a request for reconsideration of the stay denial with the Chief Judge of the Oregon Court of Appeals. On October 13, 2025, the Oregon Court of Appeals issued an order denying PacifiCorp's request for reconsideration. PacifiCorp has 35 days from October 13, 2025, to petition the Oregon Supreme Court to review the Oregon Court of Appeals order.

Refer to "Potential Effects of James CMO No. 11" in Note 10 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q for additional information.

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In September 2024, PacifiCorp filed a motion to make the James mass complaints more definite and certain. In October 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. To date, no amended complaints seek damages in excess of the amounts sought in the original mass complaints.

James Consolidated Cases

The following cases were consolidated into the original 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 damages and $24 million in noneconomic damages related to the Beachie Creek Fire.

Amended Dietrich filed September 6, 2022, in Multnomah County Circuit Court Oregon 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.

Bell filed September 7, 2022, in Multnomah County Circuit Court Oregon by 59 plaintiffs seeking $35 million in damages, including economic and noneconomic damages.

Ashley Andersen et al. v. PacifiCorp and Judith O'Keefe v. PacifiCorp and Consolidated Cases

As a result of settlements reached in 2024 for the Andersen et al. v. PacifiCorp consolidated cases and the Judith O'Keefe v. PacifiCorp consolidated cases, the complaints have been resolved but for one remaining plaintiff in Andersen and two remaining plaintiffs in O'Keefe in the complaints described below.

The Weathers complaint was filed in Multnomah County Circuit Court Oregon by approximately 46 plaintiffs and consolidated into the Andersen case with allegations and damages similar to those described above for the Andersen case, seeking economic damages of approximately $83 million and noneconomic damages of approximately $83 million. As described above, settlement was reached for all but one plaintiff in Weathers.

The Bogle complaint was 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 and consolidated into the O'Keefe case. As described above, settlement was reached for all but two of the plaintiffs in Bogle.

Other Cases

Several other complaints were filed against PacifiCorp associated with the 2020 Wildfires for which several settlements were reached as described above. However, certain complaints remain outstanding as described below.

On September 1, 2022, a complaint against PacifiCorp associated with the Archie Creek Fire was filed, captioned Leonard Mitchell Lee et al. v. PacifiCorp, ("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. In 2025, the court dismissed the complaints for the remaining two plaintiffs.

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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. During 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 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 Ace American Insurance Co. complaint was filed against PacifiCorp by 15 insurers in Douglas County Circuit Court Oregon on August 25, 2022, seeking approximately $24 million in damages for negligence. The Ace American Insurance Co. case was partially dismissed following settlement, but general judgment of dismissal has not yet been entered because certain plaintiffs remain active.

Winery Cases

Certain Oregon vineyards have filed lawsuits alleging economic damages associated with the 2020 Wildfires, as described below. In October 2025, PacifiCorp settled in principle all claims made by Oregon vineyards. As a result, PacifiCorp expects the upcoming trials to be canceled and the associated complaints dismissed.

On July 14, 2023, a complaint against PacifiCorp was filed, captioned Elk Cove Vineyards, Inc. v. PacifiCorp, in Oregon Circuit Court in Yamhill County, Oregon, by one plaintiff, seeking approximately $3 million in economic damages associated with the Santiam Canyon, South Obenchain, Echo Mountain Complex, 242 and Archie Creek 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 March 2, 2026 through March 31, 2026.

On July 24, 2023, a complaint against PacifiCorp was filed, captioned Willamette Valley Vineyards Inc v. PacifiCorp, in Oregon Circuit Court in Marion County, Oregon, ("Marion County Circuit Court Oregon") seeking approximately $3 million in economic damages associated with the Santiam Canyon, South Obenchain, Echo Mountain Complex, 242 and Archie Creek 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. On February 3, 2025, the complaint was further amended to add an unspecified amount of punitive damages. The Marion County Circuit Court Oregon denied plaintiffs' motion to apply the negligence finding from the June 2023 James verdict to the Willamette Valley Vineyards Inc case but provided plaintiffs the option to refile the motion in the future. The Willamette Valley Vineyards Inc case is set for trial January 12, 2026 through February 6, 2026.

On January 18, 2024, a complaint against PacifiCorp was filed, captioned Sokol Blosser, Ltd. et al. v. PacifiCorp, ("Sokol Blosser") in Multnomah County Circuit Court Oregon by approximately nine plaintiffs, seeking approximately $20 million in economic damages associated with the Santiam Canyon, South Obenchain, Echo Mountain Complex, 242 and Archie Creek 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 April 7, 2025, the complaint was further amended to add punitive damages in an unspecified amount. On April 4, 2025, the Multnomah County Circuit Court Oregon denied plaintiffs' motion to apply the negligence finding from the June 2023 James verdict to the Sokol Blosser case, indicating that plaintiffs have the burden of proof to demonstrate causation. In May 2025, three plaintiffs were voluntarily dismissed without prejudice. The Sokol Blosser case is set for trial November 3, 2025, through December 9, 2025.

On May 24, 2024, a complaint against PacifiCorp was filed, captioned Lange Winery LLC et al. v. PacifiCorp, ("Lange Winery") in Multnomah County Circuit Court Oregon by approximately 36 plaintiffs, seeking approximately $51 million in economic damages associated with the Santiam Canyon, South Obenchain, Echo Mountain Complex, 242 and Archie Creek fires and makes allegations similar to those described above. On April 10, 2025, the Multnomah County Circuit Court Oregon denied plaintiffs' motion to apply the negligence finding from the June 2023 James verdict to the Lange Winery case. While the court did not rule on the admissibility of the ODF's Report, it acknowledged that inconsistent findings exist as to the causation of the Santiam Canyon fires as a result of the report. The court also noted that the plaintiffs are wineries located many miles away from the wildfires who allege that their grape harvests were damaged or destroyed by the traveling smoke, far outside the wildfire boundaries at issue in James. The Lange Winery case is set for trial May 4, 2026, through June 12, 2026.

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On October 31, 2024, a complaint against PacifiCorp was filed, captioned The Lumos Wine Co. et al. v. PacifiCorp, ("Lumos") in Multnomah County Circuit Court Oregon by approximately six plaintiffs, seeking approximately $2 million in economic damages associated with the Santiam Canyon, South Obenchain, Echo Mountain Complex, 242 and Archie Creek 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

In 2023, PacifiCorp received correspondence from the U.S. Department of Justice ("USDOJ"), representing the U.S. Department of the Interior, Bureau of Land Management, Bureau of Indian Affairs and USFS, regarding the potential recovery of certain costs and damages alleged to have occurred to federal lands from the Archie Creek and Susan Creek fires. The USDOJ provided a damages estimate of approximately $625 million for mediation purposes only, which included costs and damages relating to damaged timber and improvements; reforestation; coordination with hydropower license, suppression costs and other assessment costs; and cleanup and rehabilitation costs. 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. While PacifiCorp participated in mediation with the USDOJ and continues to seek resolution of the dispute, the USDOJ filed a formal complaint against PacifiCorp as described below.

In 2023, 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 provided a damage estimate of approximately $109 million for mediation purposes only, which included losses and damages relating to the sheltering of, and assistance to, affected Oregonians; fire control and extinguishment costs; timber damage across 39 acres of Oregon forestland; losses and damages at the Rock Creek Fish Hatchery; road and highway damages; and other costs.

In 2023, the ODF 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 ODF for suppression costs associated with one of these ignition points for less than $1 million.

In December 2024, in conjunction with the USDOJ correspondence for the Archie Creek fire described above, a complaint against PacifiCorp was filed, captioned the United States of America v. PacifiCorp, in U.S. District Court, District of Oregon, Portland Division, seeking various unquantified damages and a jury trial. The civil cover sheet accompanying the complaint demands damages estimated to exceed $900 million, which is greater than the damages included in the original correspondence from the USDOJ due to the addition of estimates for intangible environmental and natural resource damages. PacifiCorp responded to the complaint on February 18, 2025.

On February 19, 2025, PacifiCorp received a demand from the ODF for $2 million in fire suppression costs incurred by the ODF associated with the Oregon portion of the Slater Fire. On May 5, 2025, PacifiCorp received a demand from the ODOJ for $5 million of suppression costs incurred by the Oregon State Fire Marshal associated with the Oregon portion of the Slater Fire.

On April 4, 2025, PacifiCorp received a demand from the ODF for $11 million in fire suppression costs associated with the South Obenchain fire.

On April 21, 2025, PacifiCorp received a demand from the ODF for $4 million in fire suppression costs associated with the Echo Mountain and Kimberling Mountain fires.

PacifiCorp is actively cooperating with both the USDOJ and ODOJ on resolving these alleged claims.

2020 Slater Fire California and Oregon Complaints and Demands

A significant number of complaints on behalf of plaintiffs associated with the Slater Fire were 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. The damages sought generally include: (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. Substantially all of the complaints have been resolved.

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In May 2025, PacifiCorp settled claims with one plaintiff in the Hillman complaint filed January 29, 2021, and with one plaintiff in the Nixon complaint filed August 31, 2022, against PacifiCorp in California Superior Court, Sacramento County, California ("Sacramento County Superior Court California") and previously part of the resolved consolidated Hitchcock et al. v. PacifiCorp cases. All settled cases are expected to be dismissed.

United States – Loss and Damages to Federal Lands – Slater Fire

PacifiCorp received a notice of indebtedness from the 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 USDOJ indicating its intent to litigate the matter because PacifiCorp has not paid the $356 million demand. PacifiCorp is actively cooperating with the USDOJ on resolving these alleged claims, including through the pursuit of alternative dispute resolution.

2022 McKinney Fire

Numerous complaints associated with the 2022 McKinney Fire were filed in Sacramento County Superior Court California on behalf of approximately 1,200 plaintiffs. Certain complaints include wrongful death claims associated with the four fatalities. 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. The damages sought generally include: (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. The complaints do not specify the amount of damages sought.

On August 16, 2022, a complaint against PacifiCorp was filed, captioned Bridges et al. v. PacifiCorp, ("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 14 plaintiffs, including a wrongful death claim; Shoopman filed August 26, 2022, amended January 10, 2023, approximately 124 plaintiffs, including a wrongful death claim; Lowe filed September 28, 2022, approximately two plaintiffs; Fraser filed November 9, 2022, approximately 180 plaintiffs; Corrales, filed April 6, 2023, approximately 30 plaintiffs; Murieen, filed April 20, 2023, approximately seven plaintiffs; Huber, filed August 21, 2023, approximately five plaintiffs, including two wrongful death claims; Insurance Company of Hannover, filed January 8, 2024, one subrogation plaintiff; Crawford, filed March 28, 2024, approximately 37 plaintiffs; Bartlett, filed April 25, 2024, approximately 30 plaintiffs; Adams, filed April 26, 2024, approximately 12 plaintiffs; Justice, filed July 15, 2024, approximately 194 plaintiffs; Coolidge, filed July 19, 2024, approximately two plaintiffs; Sharon Andersen, filed July 22, 2024, approximately 24 plaintiffs, including a wrongful death claim; Billingsley, filed July 25, 2024, approximately 21 plaintiffs, including a wrongful death claim; Howe, filed July 25, 2024, approximately 51 plaintiffs; Cloutman, filed July 26, 2024, approximately 114 plaintiffs; Bolden, filed July 26, 2024, approximately seven plaintiffs; Rainey, filed July 26, 2024, approximately 26 plaintiffs, including a wrongful death claim; Hegler, filed July 29, 2024, approximately three plaintiffs; Meier, filed July 29, 2024, approximately 204 plaintiffs; Propp, filed August 5, 2024, approximately six plaintiffs; Griffith, filed May 21, 2025, approximately 63 plaintiffs; Schumack, filed July 21, 2025, approximately three plaintiffs; and Shott, filed July 31, 2025, approximately three plaintiffs. To date, settlements have been reached with substantially all the plaintiffs associated with the 2022 McKinney Fire, and PacifiCorp believes that there are approximately 50 plaintiffs remaining to settle. While only a portion of the associated complaints have been dismissed as a result of the settlements, the remaining settled complaints are also expected to be dismissed. Additionally, the bellwether trial in Bridges and the trial for the wrongful death claim in Huber were cancelled as a result of settlements reached in May 2025. No other trials have been scheduled.

On April 12, 2024, a complaint against PacifiCorp was filed, captioned Susanne White v. PacifiCorp in U.S. District Court for the Eastern District of California by one plaintiff.

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, 2024.

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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.

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Exhibit No.			Description

BERKSHIRE HATHAWAY ENERGY

3.1			Amended and Restated Bylaws of Berkshire Hathaway Energy Company.
4.1			Trust Deed, dated as of March 21, 2025, among Northern Powergrid (Yorkshire) plc, Northern Powergrid (Northeast) plc and HSBC Corporate Trustee Company (UK) Limited, relating to the £1,000,000,000 Euro Medium Term Note Programme (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2025).
4.2			Subscription Agreement, dated as of March 28, 2025, among Northern Powergrid (Yorkshire) plc, Barclays Bank PLC, HSBC Bank plc, Lloyds Bank Corporate Markets plc and RBC Europe Limited, relating to the £250,000,000 in principal amount of the 6.125% Fixed Rate Notes due 2050 (incorporated by reference to Exhibit 4.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2025).
10.1			First Amending Agreement to the Credit Agreement, dated as of February 4, 2025, among BHE Canada Holdings Corporation, as borrower, Bank of Montreal, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2025).
10.2			Berkshire Hathaway Energy Company Long-Term Incentive Partnership Plan as Amended and Restated December 1, 2024 (incorporated by reference to Exhibit 10.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2025).
10.3			Third Amendment to the $3,500,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, 2025, among Berkshire Hathaway Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Lenders, MUFG Bank, LTD., as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2025).
15.1			Awareness Letter of Independent Registered Public Accounting Firm.
31.1			Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2			Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1			Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2			Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

PACIFICORP

15.2			Awareness Letter of Independent Registered Public Accounting Firm.
31.3			Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4			Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.3			Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.4			Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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Exhibit No.			Description

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP

4.3			Indenture, dated as of March 20, 2025, between PacifiCorp and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the PacifiCorp Current Report on Form 8-K dated March 20, 2025).
4.4			First Supplemental Indenture, dated as of March 20, 2025, between PacifiCorp and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 7.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2055 (including the form of the Notes) (incorporated by reference to Exhibit 4.2 to the PacifiCorp Current Report on Form 8-K dated March 20, 2025).
10.4			Third Amendment to the $2,000,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, 2025, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Lenders, JPMorgan Chase Bank, N.A., as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.4 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2025).
10.5			First Amendment to the $900,000,000 364-Day Credit Agreement, dated as of June 27, 2025, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.5 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2025).
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

10.6			Third Amendment to the $1,500,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, 2025, among MidAmerican Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as 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, 2025).

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Exhibit No.			Description

NEVADA POWER

15.4			Awareness Letter of Independent Registered Public Accounting Firm.
31.9			Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.10			Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.9			Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.10			Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER

10.7			Third Amendment to the $600,000,000 Fifth Amended and Restated Credit Agreement, dated as of June 30, 2025, among Nevada Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as 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, 2025).

SIERRA PACIFIC

15.5			Awareness Letter of Independent Registered Public Accounting Firm.
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

4.5			Indenture, dated as of September 8, 2025, by and between Sierra Pacific Power Company and The Bank of New York Mellon Trust Company, N.A., as trustee.
4.6			First Supplemental Indenture, dated as of September 8, 2025, by and between Sierra Pacific Power Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 6.200% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2055.
10.8			Third Amendment to the $400,000,000 Fifth Amended and Restated Credit Agreement, dated as of June 30, 2025, among Sierra Pacific Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as 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, 2025).

EASTERN ENERGY GAS

15.6			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.

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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, 2025, is formatted in iXBRL (Inline eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail.
104			Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

			BERKSHIRE HATHAWAY ENERGY COMPANY
Date: October 31, 2025			/s/ Charles C. Chang
			Charles C. Chang
			Senior Vice President and Chief Financial Officer
			(principal financial and accounting officer)
			PACIFICORP
Date: October 31, 2025			/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: October 31, 2025			/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: October 31, 2025			/s/ Michael J. Behrens
			Michael J. Behrens
			Vice President and Chief Financial Officer
			(principal financial and accounting officer)
			SIERRA PACIFIC POWER COMPANY
Date: October 31, 2025			/s/ Michael J. Behrens
			Michael J. Behrens
			Vice President and Chief Financial Officer
			(principal financial and accounting officer)
			EASTERN ENERGY GAS HOLDINGS, LLC
Date: October 31, 2025			/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: October 31, 2025			/s/ Scott C. Miller
			Scott C. Miller
			Vice President, Chief Financial Officer and Treasurer
			(principal financial and accounting officer)

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