bhe-20260630

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2026

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

For the transition period from ______ to _______

Exact name of registrant as specified in its charter

State or other jurisdiction of incorporation or organization

Commission

Address of principal executive offices

IRS Employer

File Number

Registrant's telephone number, including area code

Identification No.

001-14881

BERKSHIRE HATHAWAY ENERGY COMPANY

94-2213782

(An Iowa Corporation)

1615 Locust Street

Des Moines, Iowa 50309-3037

515-242-4300

001-05152

PACIFICORP

93-0246090

(An Oregon Corporation)

825 N.E. Multnomah Street

Portland, Oregon 97232

888-221-7070

333-90553

MIDAMERICAN FUNDING, LLC

47-0819200

(An Iowa Limited Liability Company)

1615 Locust Street

Des Moines, Iowa 50309-3037

515-242-4300

333-15387

MIDAMERICAN ENERGY COMPANY

42-1425214

(An Iowa Corporation)

1615 Locust Street

Des Moines, Iowa 50309-3037

515-242-4300

000-52378

NEVADA POWER COMPANY

88-0420104

(A Nevada Corporation)

6226 West Sahara Avenue

Las Vegas, Nevada 89146

702-402-5000

000-00508

SIERRA PACIFIC POWER COMPANY

88-0044418

(A Nevada Corporation)

6100 Neil Road

Reno, Nevada 89511

775-834-4011

001-37591

EASTERN ENERGY GAS HOLDINGS, LLC

46-3639580

(A Virginia Limited Liability Company)

10700 Energy Way

Glen Allen, Virginia 23060

804-613-5100

333-266049

EASTERN GAS TRANSMISSION AND STORAGE, INC.

55-0629203

(A Delaware Corporation)

10700 Energy Way

Glen Allen, Virginia 23060

804-613-5100

N/A

(Former name, former address and former fiscal year, if changed since last report)


Registrant			Securities registered pursuant to Section 12(b) of the Act:
BERKSHIRE HATHAWAY ENERGY COMPANY			None
PACIFICORP			None
MIDAMERICAN FUNDING, LLC			None
MIDAMERICAN ENERGY COMPANY			None
NEVADA POWER COMPANY			None
SIERRA PACIFIC POWER COMPANY			None
EASTERN ENERGY GAS HOLDINGS, LLC			None
EASTERN GAS TRANSMISSION AND STORAGE, INC.			None


Registrant			Name of exchange on which registered:
BERKSHIRE HATHAWAY ENERGY COMPANY			None
PACIFICORP			None
MIDAMERICAN FUNDING, LLC			None
MIDAMERICAN ENERGY COMPANY			None
NEVADA POWER COMPANY			None
SIERRA PACIFIC POWER COMPANY			None
EASTERN ENERGY GAS HOLDINGS, LLC			None
EASTERN GAS TRANSMISSION AND STORAGE, INC.			None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.


Registrant	Yes	No
BERKSHIRE HATHAWAY ENERGY COMPANY	☒
PACIFICORP	☒
MIDAMERICAN FUNDING, LLC		☒
MIDAMERICAN ENERGY COMPANY	☒
NEVADA POWER COMPANY	☒
SIERRA PACIFIC POWER COMPANY	☒
EASTERN ENERGY GAS HOLDINGS, LLC	☒
EASTERN GAS TRANSMISSION AND STORAGE, INC.	☒

Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Registrant

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

BERKSHIRE HATHAWAY ENERGY COMPANY

☐

☒

☐

PACIFICORP

☐

☒

☐

MIDAMERICAN FUNDING, LLC

☐

☒

☐

MIDAMERICAN ENERGY COMPANY

☐

☒

☐

NEVADA POWER COMPANY

☐

☒

☐

SIERRA PACIFIC POWER COMPANY

☐

☒

☐

EASTERN ENERGY GAS HOLDINGS, LLC

☐

☒

☐

EASTERN GAS TRANSMISSION AND STORAGE, INC.

☐

☒

☐

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

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

Yes ☐ No x

All shares of outstanding common stock of Berkshire Hathaway Energy Company are held by its parent company, Berkshire Hathaway Inc. As of August 6, 2026, 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 August 6, 2026, 357,060,915 shares of common stock, no par value, were outstanding.

All of the member's equity of MidAmerican Funding, LLC is held by its parent company, Berkshire Hathaway Energy Company, as of August 6, 2026.

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 August 6, 2026, 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 August 6, 2026, 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 August 6, 2026, 1,000 shares of common stock, $3.75 par value, were outstanding.

All of the member's equity of Eastern Energy Gas Holdings, LLC is held indirectly by its parent company, Berkshire Hathaway Energy Company, as of August 6, 2026.

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 August 6, 2026, 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	1
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	212
Item 4.	Controls and Procedures	212

PART II


Item 1.	Legal Proceedings	213
Item 1A.	Risk Factors	217
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	217
Item 3.	Defaults Upon Senior Securities	217
Item 4.	Mine Safety Disclosures	218
Item 5.	Other Information	218
Item 6.	Exhibits	218
Signatures		222

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.


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


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
ICC						Illinois Commerce Commission
IPUC						Idaho Public Utilities Commission
IRP						Integrated Resource Plan
ITC						Investment Tax Credits
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


MW						Megawatt
MWh						Megawatt Hour
NAAQS						National Ambient Air Quality Standards
NOx						Nitrogen Oxides

Ofgem						Office of Gas and Electric Markets
OPUC						Oregon Public Utility Commission

PTC						Production Tax Credit
PUCN						Public Utilities Commission of Nevada


RFP						Request for Proposals
RPS						Renewable Portfolio Standards


SEC						United States Securities and Exchange Commission
SIP						State Implementation Plan
SO2						Sulfur Dioxide

UPSC						Utah Public Service Commission
WPSC						Wyoming Public Service Commission
WUTC						Washington Utilities and Transportation Commission

iii

Forward-Looking Statements

This report contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon the relevant Registrant's current intentions, estimates, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control of each Registrant and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:

•general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including trade policy, 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 or decelerate 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 or at all;

•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 have been appealed, including potential collateral triggers, 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 outlined 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;

•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, placement on negative outlook or credit watch and downgrades to below investment grade;

•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 ability to successfully close on planned dispositions and the ultimate regulatory treatment of amounts related to such transactions;

•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 and LNG in applicable geographic regions and demand for natural gas and LNG supply;

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

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

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

Item 1.Financial Statements


Berkshire Hathaway Energy Company and its subsidiaries						3
PacifiCorp and its subsidiaries						54
MidAmerican Energy Company						87
MidAmerican Funding, LLC and its subsidiaries						103
Nevada Power Company and its subsidiaries						126
Sierra Pacific Power Company and its subsidiaries						149
Eastern Energy Gas Holdings, LLC and its subsidiaries						175
Eastern Gas Transmission and Storage, Inc. and its subsidiaries						195

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						76
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company						116
Nevada Power Company and its subsidiaries						141
Sierra Pacific Power Company and its subsidiaries						166
Eastern Energy Gas Holdings, LLC and its subsidiaries						191
Eastern Gas Transmission and Storage, Inc. and its subsidiaries						209

Berkshire Hathaway Energy Company and its subsidiaries

Consolidated Financial Section

PART I

Item 1.Financial Statements


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
General						11
New Accounting Pronouncements						12
Dispositions						12
Property, Plant and Equipment, Net						14
Investments and Restricted Cash and Cash Equivalents and Investments						15
Recent Financing Transactions						16
Income Taxes						17
Employee Benefit Plans						19

Fair Value Measurements						20
Commitments and Contingencies						22
Revenue from Contracts with Customers						27

Components of Accumulated Other Comprehensive Loss, Net						29
Segment Information						30

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Berkshire Hathaway Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of June 30, 2026, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and six-month periods ended June 30, 2026 and 2025, and of cash flows for the six-month periods ended June 30, 2026 and 2025, 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, 2025, 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 27, 2026, 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, 2025, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Des Moines, Iowa

August 7, 2026

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	June 30,		December 31,
	2026		2025
ASSETS
Current assets:
Cash and cash equivalents	$	4,072	$	1,695
Investments and restricted cash and cash equivalents	479		254
Trade receivables, net	2,746		2,678

Inventories	2,183		2,105
Mortgage loans held for sale	889		698
Regulatory assets	429		892

Prepayments	723		546
Assets held for sale (Note 3)	2,008		—
Other current assets	381		769
Total current assets	13,910		9,637

Property, plant and equipment, net	113,039		112,368
Goodwill	11,374		11,521
Regulatory assets	3,956		3,929
Investments and restricted cash and cash equivalents and investments	7,336		7,608
Other assets	4,414		3,264

Total assets	$	154,029	$	148,327

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions, except share amounts)


	As of
	June 30,		December 31,
	2026		2025
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	3,029	$	3,389
Accrued interest	877		797
Accrued property, income and other taxes	812		745
Accrued employee expenses	455		345
Short-term debt	1,374		1,997
Current portion of long-term debt	628		1,455
Wildfires liabilities (Note 10)	155		734
Liabilities held for sale (Note 3)	246		—
Other current liabilities	2,078		1,930
Total current liabilities	9,654		11,392

BHE senior debt	11,463		11,461

Subsidiary senior debt	45,036		42,759
Subsidiary junior subordinated debt	3,266		1,584
Regulatory liabilities	6,646		6,772
Deferred income taxes	13,114		12,999
Wildfires liabilities (Note 10)	417		427
Other long-term liabilities	7,312		5,624
Total liabilities	96,908		93,018

Commitments and contingencies (Note 10)

Equity:
BHE shareholder's equity:
Preferred stock - 100,000,000 shares authorized, $0.01 par value, 0 and — shares issued and outstanding	—		—
Common stock - 100 shares authorized, no par value, 1 share issued and outstanding	—		—
Additional paid-in capital	5,563		5,558
Retained earnings	52,355		50,351
Accumulated other comprehensive loss, net	(2,035)		(1,844)
Total BHE shareholder's equity	55,883		54,065
Noncontrolling interests	1,238		1,244
Total equity	57,121		55,309

Total liabilities and equity	$	154,029	$	148,327

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025
Operating revenue:
Energy	$	5,413	$	5,130	$	11,223	$	10,636
Real estate	1,273		1,264		2,135		2,124
Total operating revenue	6,686		6,394		13,358		12,760

Operating expenses:
Energy:
Cost of sales	1,376		1,434		3,046		2,965
Operations and maintenance	1,412		1,392		2,710		2,641

Depreciation and amortization	1,131		1,129		2,257		2,235
Property and other taxes	239		225		480		451
Real estate	1,250		1,210		2,129		2,081
Total operating expenses	5,408		5,390		10,622		10,373

Operating income	1,278		1,004		2,736		2,387

Other income (expense):
Interest expense	(791)		(709)		(1,537)		(1,395)
Capitalized interest	47		45		92		85
Allowance for equity funds	94		81		174		147
Interest and dividend income	67		63		121		125
Gains on marketable securities, net	20		16		15		119
Other, net	61		45		53		30
Total other income (expense)	(502)		(459)		(1,082)		(889)

Income before income tax expense (benefit) and equity income (loss)	776		545		1,654		1,498
Income tax expense (benefit)	(333)		(357)		(763)		(756)
Equity income (loss)	(172)		(160)		(306)		(280)
Net income	937		742		2,111		1,974
Net income attributable to noncontrolling interests	46		40		106		85
Net income attributable to BHE shareholders	891		702		2,005		1,889
Preferred dividends	—		—		—		3
Earnings on common shares	$	891	$	702	$	2,005	$	1,886

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025

Net income	$	937	$	742	$	2,111	$	1,974

Other comprehensive (loss) income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $1, $(7), $8 and $(5)	4		(21)		21		(21)
Foreign currency translation adjustment	(64)		556		(207)		725
Unrealized gains (losses) on cash flow hedges, net of tax of $1, $(3), $(3) and $(5)	1		(10)		(5)		(16)
Total other comprehensive (loss) income, net of tax	(59)		525		(191)		688

Comprehensive income	878		1,267		1,920		2,662
Comprehensive income attributable to noncontrolling interests	46		40		106		85
Comprehensive income attributable to BHE shareholders	$	832	$	1,227	$	1,814	$	2,577

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)


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

Balance, March 31, 2025	$	—	$	—	$	5,558	$	47,493	$	(2,178)	$	1,276	$	52,149
Net income	—		—		—		702		—		40		742
Other comprehensive income	—		—		—		—		525		—		525



Distributions	—		—		—		—		—		(50)		(50)


Other equity transactions	—		—		—		(1)		—		(1)		(2)
Balance, June 30, 2025	$	—	$	—	$	5,558	$	48,194	$	(1,653)	$	1,265	$	53,364

Balance, December 31, 2024	$	481	$	—	$	5,558	$	46,311	$	(2,341)	$	1,280	$	51,289
Net income	—		—		—		1,889		—		85		1,974
Other comprehensive income	—		—		—		—		688		—		688
Preferred stock redemptions	(481)		—		—		—		—		—		(481)
Preferred stock dividend	—		—		—		(3)		—		—		(3)

Distributions	—		—		—		—		—		(96)		(96)


Other equity transactions	—		—		—		(3)		—		(4)		(7)
Balance, June 30, 2025	$	—	$	—	$	5,558	$	48,194	$	(1,653)	$	1,265	$	53,364


Balance, March 31, 2026	$	—	$	—	$	5,563	$	51,465	$	(1,976)	$	1,240	$	56,292
Net income	—		—		—		891		—		46		937
Other comprehensive loss	—		—		—		—		(59)		—		(59)



Distributions	—		—		—		—		—		(46)		(46)


Other equity transactions	—		—		—		(1)		—		(2)		(3)
Balance, June 30, 2026	$	—	$	—	$	5,563	$	52,355	$	(2,035)	$	1,238	$	57,121

Balance, December 31, 2025	$	—	$	—	$	5,558	$	50,351	$	(1,844)	$	1,244	$	55,309
Net income	—		—		—		2,005		—		106		2,111
Other comprehensive loss	—		—		—		—		(191)		—		(191)



Distributions	—		—		—		—		—		(114)		(114)


Other equity transactions	—		—		5		(1)		—		2		6
Balance, June 30, 2026	$	—	$	—	$	5,563	$	52,355	$	(2,035)	$	1,238	$	57,121

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Six-Month Periods
	Ended June 30,
	2026		2025
Cash flows from operating activities:
Net income	$	2,111	$	1,974
Adjustments to reconcile net income to net cash flows from operating activities:
Gains on marketable securities, net	(15)		(119)
Depreciation and amortization	2,275		2,255
Allowance for equity funds	(174)		(147)
Equity (income) loss, net of distributions	332		332
Net power cost deferrals	(73)		(61)
Amortization of net power cost deferrals	458		430
Other changes in regulatory assets and liabilities	118		(162)
Deferred income taxes and investment tax credits, net	323		(107)
Other, net	21		158
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(509)		(405)
Derivative collateral, net	(15)		14
Pension and other postretirement benefit plans	(6)		(6)
Accrued property, income and other taxes, net	293		107
Accounts payable and other liabilities	123		114
Wildfires insurance receivable	—		98
Wildfires liability	(589)		(155)
Net cash flows from operating activities	4,673		4,320

Cash flows from investing activities:
Capital expenditures	(4,949)		(4,573)

Purchases of marketable securities	(280)		(238)
Proceeds from sales of marketable securities	351		811
Purchases of U.S. Treasury Bills	(289)		(39)

Proceeds from maturities of U.S. Treasury Bills	43		—
Equity method investments	(20)		(45)
Other, net	35		13
Net cash flows from investing activities	(5,109)		(4,071)

Cash flows from financing activities:

Preferred stock redemptions	—		(481)
Preferred dividends	—		(3)


Repayments of BHE senior debt	—		(1,650)

Proceeds from subsidiary debt	4,564		2,670
Repayments of subsidiary debt	(1,253)		(388)
Net (repayments of) proceeds from short-term debt	(609)		551


Distributions to noncontrolling interests	(115)		(96)

Other, net	219		(31)
Net cash flows from financing activities	2,806		572

Effect of exchange rate changes	(10)		13

Net change in cash and cash equivalents and restricted cash and cash equivalents	2,360		834
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	1,878		1,586
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	4,238	$	2,420

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

Berkshire Hathaway Energy Company ("BHE"), 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")), BHE U.S. Transmission, LLC and its subsidiaries) and BHE Montana, 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 in the U.S. and a residential real estate brokerage franchise business in the U.S.

The accompanying Consolidated Financial Statements and Notes to Consolidated Financial Statements should be read in conjunction with the Company's Annual Report on Form 10-K for the year ended December 31, 2025. The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of June 30, 2026, and for the three- and six-month periods ended June 30, 2026 and 2025. The results of operations for the three- and six-month periods ended June 30, 2026, 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, 2025, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in the Company's accounting policies or its assumptions regarding significant accounting estimates during the six-month period ended June 30, 2026. 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."

(2) New Accounting Pronouncements

In November 2024, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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.

In December 2025, the FASB issued ASU No. 2025-10, Government Grants Topic 832, "Accounting for Government Grants Received by Business Entities" which establishes accounting for government grants received by an entity, including guidance for a grant related to an asset and a grant related to income. This guidance also requires, consistent with current disclosure requirements, that an entity provide disclosures including the nature of the government grant received, the accounting policies used to account for the grant, and significant terms and conditions of the grant. This guidance is effective for interim and annual reporting periods beginning after December 15, 2028. Early adoption is permitted and can be applied using either a modified prospective approach, a modified retrospective approach or a retrospective approach. 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 May 2026, the FASB issued ASU No. 2026-02, Environmental Credits and Environmental Credit Obligations Topic 818 which establishes guidance on the recognition, measurement, presentation and disclosure of environmental credits and related regulatory obligations. This guidance provides a framework for accounting for environmental credit assets, including those generated, purchased or received and environmental credit obligations. It also requires entities to assess the intended use of environmental credits, and, in certain cases, evaluate such credits for impairment. ASU 2026-02 introduces enhanced annual disclosure requirements related to environmental credits and associated obligations. The guidance is effective for annual periods beginning after December 15, 2027. Early adoption is permitted and should be applied on a retrospective basis through a cumulative effect adjustment to the opening balance of retained earnings. 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) Dispositions

On February 15, 2026, PacifiCorp and Portland General Electric Company and an affiliate of Portland General Electric Company (together, the "PGE Entities") entered into an Asset Purchase and Service Area Transfer Agreement (the "Sale Agreement") to sell to the PGE Entities certain PacifiCorp assets and liabilities associated with PacifiCorp's Washington operations for a sales price of $1.9 billion in cash plus additional cash consideration for the value of specified assets to be delivered at closing, subject to customary purchase price adjustments (the "Transaction").

The Transaction assets and liabilities are associated with PacifiCorp's retail service area in Washington and include certain related distribution assets and infrastructure, as well as PacifiCorp's Chehalis combined cycle natural gas-fueled generating facility located in Chehalis, Washington, Goodnoe Hills wind-powered generating facility located in Goldendale, Washington, and Marengo wind-powered generating facility located in Dayton, Washington.

The Transaction has been approved by PacifiCorp's board of directors but is subject to customary closing conditions including (i) the expiration or termination of the waiting period and other required approvals under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and (ii) the receipt of all necessary approvals, waivers and rulings from the Federal Energy Regulatory Commission ("FERC") and each of PacifiCorp's six state public utility commissions. In March and April 2026, PacifiCorp filed for approval of the Transaction and associated disposition of assets with each of its state public utility commissions, requesting approval by March 1, 2027. On July 15, 2026, PacifiCorp filed with the FERC for approval under applicable sections of the Federal Power Act, requesting an order by December 15, 2026. The Transaction is expected to close in the first half of 2027.

The Sale Agreement contains certain termination rights, including if the Transaction is not consummated by August 15, 2027, (subject to a six-month extension to the extent certain regulatory approvals have not been received as of such date), and provides that upon termination of the Sale Agreement under certain specified circumstances, the terminating party would be required to pay the other party a termination fee of $35 million.

As a result of the Transaction, PacifiCorp has presented the associated assets and liabilities as held for sale as of June 30, 2026, on the Consolidated Balance Sheets within current assets and current liabilities due to the expected timing of close of the Transaction. As the Transaction does not represent a strategic shift that will have a major impact on PacifiCorp's operations or financial results based on the scale of PacifiCorp's Washington operations and retail service territory relative to its overall operations and retail service territory, the Transaction does not qualify for presentation as discontinued operations.

As the carrying value of the associated assets and liabilities are less than fair value less costs to sell, no loss has been recorded as a result of the Transaction. PacifiCorp continues to depreciate the property, plant and equipment included in the Transaction as it will continue to operate the assets and serve PacifiCorp's Washington customers through closing of the Transaction, during which time it will continue to recover in retail rates the associated depreciation expense and return on investment, and the continued depreciation will be reflected in the carry-over basis of the assets upon closing.

The assets and liabilities held for sale as presented in Assets held for sale and Liabilities held for sale on the Consolidated Balance Sheets as of June 30, 2026, are as follows:


Assets held for sale:
Trade receivables, net		$	109
Property, plant and equipment, net:
Utility generation, transmission and distribution systems	2,005
Accumulated depreciation and amortization	(465)
Construction work-in-progress	45
Property, plant and equipment, net		1,585
Regulatory assets		143
Goodwill		89
Other assets		82
Total assets held for sale		$	2,008

Liabilities held for sale:
Regulatory liabilities		$	202
Other liabilities		44
Total liabilities held for sale		$	246

Regulatory assets include amounts associated with deferred net power costs and unrealized loss on regulated derivative contracts for which the underlying contracts will transfer to the Buyer. Other assets and other liabilities include inventories, certain prepaid expenses, derivative balances, lease balances, asset retirement obligation balances and transmission deposits. Regulatory liabilities include amounts associated with cost of removal and excess deferred income tax liability balances.

(4) Property, Plant and Equipment, Net

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


		As of
	Depreciable	June 30,		December 31,
	Life	2026		2025
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	109,292	$	109,815
Interstate natural gas pipeline assets	3-80 years	21,683		21,334
		130,975		131,149
Accumulated depreciation and amortization		(40,672)		(40,365)
Regulated assets, net		90,303		90,784

Nonregulated assets:
Independent power plants	2-50 years	9,632		9,242
Cove Point LNG facility	40 years	3,479		3,476
Other assets	2-30 years	2,588		2,912
		15,699		15,630
Accumulated depreciation and amortization		(4,887)		(4,637)
Nonregulated assets, net		10,812		10,993

		101,115		101,777
Construction work-in-progress		11,924		10,591
Property, plant and equipment, net		$	113,039	$	112,368

Construction work-in-progress includes $10.7 billion as of June 30, 2026, and $9.5 billion as of December 31, 2025, related to the construction of regulated assets.

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

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


	As of
	June 30,		December 31,
	2026		2025
Investments:

U.S. Treasury Bills	$	289	$	42
Company-owned life insurance	600		572
Other	362		386
Total investments	1,251		1,000

Equity method investments:
BHE Renewables tax equity investments	3,540		3,945
Electric Transmission Texas, LLC	877		835
Iroquois Gas Transmission System, L.P.	597		584
Other	342		336
Total equity method investments	5,356		5,700

Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds	1,042		979
Other restricted cash and cash equivalents	166		183
Total restricted cash and cash equivalents and investments	1,208		1,162

Total investments and restricted cash and cash equivalents and investments	$	7,815	$	7,862

Reflected as:
Other current assets	$	479	$	254
Noncurrent assets	7,336		7,608
Total investments and restricted cash and cash equivalents and investments	$	7,815	$	7,862

Investments

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


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025

Unrealized gains recognized on marketable securities held at the reporting date	$	20	$	15	$	12	$	7
Net gains recognized on marketable securities sold during the period	—		1		3		112
Gains on marketable securities, net	$	20	$	16	$	15	$	119

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

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


	As of
	June 30,		December 31,
	2026		2025

Cash and cash equivalents	$	4,072	$	1,695
Investments and restricted cash and cash equivalents	151		168
Investments and restricted cash and cash equivalents and investments	15		15
Total cash and cash equivalents and restricted cash and cash equivalents	$	4,238	$	1,878

(6) Recent Financing Transactions

Long-Term Debt

Senior Debt

In July 2026, AltaLink, L.P. issued C$350 million of its 5.111% Senior Secured Notes, Series 2026-1 due July 2056.

In March 2026, PacifiCorp issued $300 million of its 4.65% First Mortgage Bonds due April 2029, $550 million of its 5.10% First Mortgage Bonds due April 2031, $800 million of its 5.45% First Mortgage Bonds due April 2033, and $850 million of its 5.80% First Mortgage Bonds due April 2036.

In February 2026, PacifiCorp issued $400 million of 4.25% First Mortgage Bonds due March 2029.

Junior Subordinated Debt

In March 2026, Sierra Pacific issued $600 million of its 6.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due September 2056. Sierra Pacific will pay interest on the junior subordinated notes at a rate of 6.375% through September 2031, subject to a reset every five years not to reset below 6.375%.

In February 2026, PacifiCorp issued $1.1 billion of its 7.125% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due August 2056. PacifiCorp will pay interest on the junior subordinated notes at a rate of 7.125% through August 2031, subject to a reset every five years, not to reset below 7.125%.

Credit Facilities

In June 2026, BHE amended its existing $3.5 billion unsecured credit facility expiring in June 2028. The amendment extended the expiration date to June 2029 and amended certain provisions of the existing credit agreement.

In June 2026, PacifiCorp amended its existing $2.0 billion unsecured credit facility expiring in June 2028. The amendment increased the commitment of the lenders to $3.0 billion, extended the expiration date to June 2029 and amended certain provisions of the existing credit agreement. PacifiCorp's $900 million 364-day unsecured credit facility expired in June 2026.

In June 2026, MidAmerican Energy amended its existing $1.5 billion unsecured credit facility expiring in June 2028. The amendment extended the expiration date to June 2029 and amended certain provisions of the existing credit agreement.

In June 2026, Nevada Power and Sierra Pacific each amended its existing $600 million and $400 million secured credit facilities expiring in June 2028. The amendments extended the expiration date to June 2029 and amended certain provisions of the existing credit agreements.

In April 2026, PacifiCorp entered into a letter of credit agreement, effective May 18, 2026, under which letters of credit will be made available solely to provide collateral support for surety bonds issued pursuant to a corresponding surety arrangement for supersedeas undertakings to secure the performance and stay enforcement of trial court judgments entered against PacifiCorp relating to the James case, in each case while such judgments remain pending appeal by PacifiCorp in the Oregon Court of Appeals or the Oregon Supreme Court. Refer to Note 10 for information regarding the Oregon Court of Appeals opinion issued in April 2026 associated with the James case. The letter of credit agreement provides for a two-year standby letter of credit facility for PacifiCorp in an aggregate stated amount of up to $2.55 billion. In conjunction with the letter of credit agreement, PacifiCorp entered into a committed surety facility set forth in a term sheet with an initial aggregate capacity of $2.55 billion, not to exceed availability under the letter of credit agreement, and related indemnity agreement under which the surety party is committed to issue surety bonds from time to time for PacifiCorp to secure the supersedeas undertakings described above. The surety facility must be fully secured by letters of credit. If 91 days prior to the applicable termination date of any letter of credit issued under the arrangements described above, any letter of credit obligations remain outstanding, PacifiCorp will be required to provide cash collateral to secure outstanding letter of credit obligations in an amount equal to 103% of such obligations. In April 2026, PacifiCorp received the necessary approvals from the Oregon Public Utility Commission and the Idaho Public Utilities Commission.

(7) Income Taxes

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, pursuant to a tax allocation agreement. The Company had a current income tax receivable from Berkshire Hathaway of $9 million and $282 million for federal income tax as of June 30, 2026 and December 31, 2025, respectively. The Company received net cash payments for federal income taxes from Berkshire Hathaway for the six-month periods ended June 30, 2026 and 2025 totaling $1,393 million and $803 million, respectively.

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 (amounts in millions):


	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2026				2025				2026				2025
	Amount		Percent		Amount		Percent		Amount		Percent		Amount		Percent

U.S. federal statutory income tax rate	$	163	21.0	%	$	115	21.0	%	$	347	21.0	%	$	315	21.0	%
State and local income taxes, net of federal income tax	11		1.4		18		3.3		29		1.7		32		2.2
Foreign tax effects:
United Kingdom

Other	(5)		(0.6)		(30)		(5.5)		(7)		(0.4)		(15)		(1.0)
Canada
Foreign regulated flow-thru	(11)		(1.4)		(11)		(2.0)		(22)		(1.3)		(21)		(1.4)
Other	1		0.1		—		—		2		0.1		1		0.1

Effects of changes in tax laws or rates enacted in the current period	—		—		1		0.1		—		—		1		0.1
Effect of cross-border tax laws	—		—		—		—		—		—		(1)		(0.1)
Energy-related tax credits	(415)		(53.5)		(390)		(71.5)		(979)		(59.2)		(950)		(63.4)

Nontaxable or nondeductible items:
Equity earnings	(37)		(4.7)		(34)		(6.2)		(65)		(3.9)		(59)		(4.0)
Noncontrolling interest	(10)		(1.2)		(8)		(1.5)		(22)		(1.3)		(17)		(1.2)
Other, net	(5)		(0.7)		(2)		(0.3)		(3)		(0.2)		—		—
Changes in unrecognized tax benefits	—		—		—		—		1		0.1		1		0.1
Other adjustments:
Effects of ratemaking(1)	(30)		(3.7)		(20)		(3.7)		(49)		(2.9)		(45)		(3.0)
Other	5		0.4		4		0.7		5		0.2		2		0.1
Effective income tax rate	$	(333)	(42.9)	%	$	(357)	(65.6)	%	$	(763)	(46.1)	%	$	(756)	(50.5)	%

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

Energy-related 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.

(8) Employee Benefit Plans

Domestic Operations

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


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025
Pension:
Service cost	$	3	$	3	$	6	$	6
Interest cost	25		28		50		54
Expected return on plan assets	(29)		(31)		(60)		(61)

Net amortization	3		2		5		4
Net periodic benefit cost	$	2	$	2	$	1	$	3

Other postretirement:
Service cost	$	1	$	1	$	2	$	2
Interest cost	6		7		13		14
Expected return on plan assets	(8)		(9)		(18)		(18)
Net amortization	(1)		(2)		(2)		(3)
Net periodic benefit credit	$	(2)	$	(3)	$	(5)	$	(5)

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 $4 million, respectively, during 2026. As of June 30, 2026, $7 million and $4 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

Foreign Operations

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


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025

Service cost	$	2	$	1	$	3	$	2
Interest cost	16		15		32		29
Expected return on plan assets	(20)		(21)		(41)		(41)

Net amortization	10		8		18		16
Net periodic benefit cost	$	8	$	3	$	12	$	6

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 £5 million during 2026. As of June 30, 2026, £2 million, or $2 million, of contributions had been made to the United Kingdom pension plan.

(9) 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 June 30, 2026:
Assets:
Commodity derivatives	$	—	$	44	$	3	$	(6)	$	41

Interest rate derivatives	10		27		13		—		50
Mortgage loans held for sale	—		889		—		—		889
Money market mutual funds	3,613		—		—		—		3,613
Debt securities:
U.S. government obligations	840		—		—		—		840

Corporate obligations	—		127		—		—		127
Municipal obligations	—		1		—		—		1

Equity securities:
U.S. companies	560		—		—		—		560
International companies	7		—		—		—		7
Investment funds	265		—		—		—		265
	$	5,295	$	1,088	$	16	$	(6)	$	6,393
Liabilities:
Commodity derivatives	$	(13)	$	(134)	$	(68)	$	58	$	(157)

Interest rate derivatives	—		(2)		—		1		(1)
	$	(13)	$	(136)	$	(68)	$	59	$	(158)


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2025:
Assets:
Commodity derivatives	$	—	$	47	$	2	$	(8)	$	41
Foreign currency exchange rate derivatives	—		11		—		—		11
Interest rate derivatives	12		25		8		—		45
Mortgage loans held for sale	—		698		—		—		698
Money market mutual funds	1,469		—		—		—		1,469
Debt securities:
U.S. government obligations	326		—		—		—		326

Corporate obligations	—		133		—		—		133
Municipal obligations	—		2		—		—		2

Equity securities:
U.S. companies	549		—		—		—		549
International companies	9		—		—		—		9
Investment funds	283		—		—		—		283
	$	2,648	$	916	$	10	$	(8)	$	3,566
Liabilities:
Commodity derivatives	$	(13)	$	(169)	$	(56)	$	83	$	(155)

Interest rate derivatives	—		(3)		—		1		(2)
	$	(13)	$	(172)	$	(56)	$	84	$	(157)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $53 million and $76 million as of June 30, 2026, and December 31, 2025, 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.

The following table reconciles the beginning and ending balances of the Company's financial assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions). Transfers out of Level 3 occur primarily due to increased price observability.


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
			Interest				Interest
	Commodity		Rate		Commodity		Rate
	Derivatives		Derivatives		Derivatives		Derivatives
2026:
Beginning balance	$	(67)	$	10	$	(54)	$	8
Changes included in earnings(1)	—		3		—		5

Changes in fair value recognized in net regulatory assets	(2)		—		(21)		—



Settlements	4		—		10		—


Ending balance	$	(65)	$	13	$	(65)	$	13







2025:
Beginning balance	$	(92)	$	14	$	(72)	$	5
Changes included in earnings(1)	—		—		—		9

Changes in fair value recognized in net regulatory assets	(11)		—		(42)		—


Settlements	3		—		14		—

Ending balance	$	(100)	$	14	$	(100)	$	14

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

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


	As of June 30, 2026				As of December 31, 2025
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	60,393	$	55,466	$	57,259	$	52,665

(10) Commitments and Contingencies

Commitments

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

Construction Commitments

During the six-month period ended June 30, 2026, MidAmerican Energy entered into firm construction commitments totaling $717 million for the remainder of 2026 through 2029 related to the construction of wind-powered, solar-powered and natural gas-powered generating facilities in Iowa.

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.

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

2020 Wildfires and 2022 McKinney Fire

The 2020 Wildfires occurred in September 2020, when a severe weather event with high winds contributed to several major wildfires, resulting 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, 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.

Both the U.S. Department of Agriculture Forest Service ("USFS") and the Oregon Department of Forestry ("ODF") completed investigation reports related to a wildland fire that was first reported outside the Santiam Canyon on August 16, 2020 ("Beachie Creek Fire"), approximately three weeks before the severe weather event described above. The ODF's report 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 PacifiCorp's 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.

The 2022 McKinney Fire occurred on July 29, 2022, when a wildfire began in Siskiyou County, California within 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.

Complaints and Demands Associated with the 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 the 2020 Wildfires (the "James" case) 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 also filed subrogation complaints in Oregon and California with similar allegations. 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. As described below, substantially all outstanding complaints and demands are associated with the 2020 Wildfires, specifically the James case and the state of Oregon demands.

Substantially all amounts sought in outstanding complaints and demands filed in Oregon are associated with the James mass complaints described below, as well as stayed cases for which motions have been filed for consolidation into the James case and the state of Oregon demands. 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. 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.

PacifiCorp has settled various claims associated with the Wildfires, including all wrongful death claims and federal government demands and complaints associated with the Wildfires. For the Archie Creek Fire, Slater Fire and 2022 McKinney Fire, settlements have been reached with substantially all plaintiffs. For the Santiam Canyon, Echo Mountain Complex, South Obenchain and 242 fires, while PacifiCorp has settled claims with individual plaintiffs who were granted substitution of counsel in the James case, with the Oregon wineries and with the federal government, claims remain outstanding for a substantial number of plaintiffs associated with the James case. PacifiCorp is also actively cooperating with the Oregon Department of Justice on resolving its alleged claims.

The James Case

On September 30, 2020, a class action complaint against PacifiCorp captioned Jeanyne James et al. v. PacifiCorp, ("James") was filed 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 the filing of the original class action complaint, several cases have been stayed pending consolidation into James and numerous James class members have been named and damages specified in various complaints.

The Multnomah County Circuit Court Oregon determined that the James case would be divided into a liability phase ("Phase I") and a damages phase ("Phase II"). In June 2023, a jury in the Phase I liability trial found 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, as well as punitive damages. After the jury verdict, the Multnomah County Circuit Court Oregon doubled the Phase I plaintiffs' economic damages, in accordance with Oregon law, and added punitive damages by applying a 0.25 multiplier to the awarded economic and noneconomic damages. The Multnomah County Circuit Court Oregon granted PacifiCorp's subsequent motion to offset the damage awards by deducting insurance proceeds received by any of the plaintiffs.

Following the Phase I liability verdict, 1,760 James class members filed nine separate mass complaints from April 2024 through January 2026 in Multnomah County Circuit Court Oregon, each premised on the Phase I liability verdict and referencing the original James case as the lead case. The James mass complaints make damages-only allegations seeking for each individual class member $5 million of economic damages, $25 million of noneconomic damages and punitive damages equal to 0.25 times the amount of economic and noneconomic damages, as well as doubling of economic damages. Complaints for some of the plaintiffs in the mass complaints have been dismissed, amended or re-filed.

While PacifiCorp's appeal of the Phase I liability verdict was pending, the Multnomah County Circuit Court Oregon held numerous Phase II damages trials, in which a series of juries awarded damages to groups of James class members. The majority of these trials were scheduled pursuant to a case management order called "CMO No. 11." PacifiCorp filed notices of appeal for the subsequent jury verdicts in the Phase II damages trials once limited judgments were entered and any post-trial motions filed. The James jury verdicts to date have awarded total net damages of $1,252 million to 201 plaintiffs, including $133 million of doubled economic damages, $910 million of noneconomic damages, $244 million of punitive damages and partially offset by estimated insurance offsets of $35 million. To date, PacifiCorp has been required to bond the amounts awarded by the James limited judgments in order to stay payment of damages while on appeal. As of the date of this filing, PacifiCorp has posted bonds totaling $719 million associated with the limited judgments entered to date for 129 plaintiffs. As a result of the April 2026 Oregon Court of Appeals opinion, as described in more detail below, in May 2026, PacifiCorp filed a motion for discharge and release of existing bonds, which remains pending.

The Oregon Court of Appeals' opinion, issued on April 8, 2026, reversing the Phase I liability verdict explained that the Multnomah County Circuit Court Oregon erred in instructing the jury that they could "assume that the evidence at the trial applies to all class members." The Oregon Court of Appeals further concluded that the erroneous jury instruction "was prejudicial to PacifiCorp" because it "gave rise to some likelihood that the jury reached an erroneous result." Because the Oregon Court of Appeals reversed and remanded on the instructional error issue presented in PacifiCorp's appellate brief, it did not address the majority of PacifiCorp's other appealed issues. However, the Oregon Court of Appeals emphasized that the Multnomah County Circuit Court Oregon has the authority on remand to reconsider its class certification decision and reconsider whether a single class is appropriate in this case. The Oregon Court of Appeals determined PacifiCorp was the prevailing party and awarded costs to PacifiCorp.

On May 13, 2026, the James plaintiffs filed a petition with the Oregon Supreme Court for review of the April 2026 Oregon Court of Appeals opinion. On June 25, 2026, the Oregon Supreme Court issued an order allowing the petition for review and scheduling oral argument for November 3, 2026.

At a May 2026, hearing, the Multnomah County Circuit Court Oregon granted PacifiCorp's request to stay the remaining scheduled James Phase II damages trials, but permitted certain pre-trial activities, such as damages discovery and mediation, to continue, as well as scheduled a trial beginning September 2027 for 21 plaintiffs, all of whom live in a single geographic area. The stay is in effect until issuance of an appellate judgment by the Oregon Court of Appeals in James following (i) a decision on the merits by the Oregon Supreme Court affirming the Oregon Court of Appeals April 2026 opinion or (ii) at least 14 days following a decision by the Oregon Supreme Court reversing the Oregon Court of Appeals April 2026 opinion. Certain damages discovery related to previously scheduled CMO No. 11 trials will resume on August 10, 2026. The Multnomah County Circuit Court Oregon granted plaintiffs' request to enter limited judgments on the already completed Phase II damages trials but granted PacifiCorp's request to waive bonding requirements on those judgments.

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) 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 June 30, 2026. 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 June 30, 2026, PacifiCorp paid $2,281 million in settlements associated with the Wildfires. As a result of the settlements, various trials have been cancelled. In July 2026 and through the date of this filing, PacifiCorp made additional settlement payments related to the Wildfires totaling $4 million.

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


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025

Beginning balance	$	577	$	1,422	$	1,161	$	1,536

Payments	(5)		(41)		(589)		(155)
Ending balance	$	572	$	1,381	$	572	$	1,381

As of June 30, 2026 and December 31, 2025, $155 million and $734 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 June 30, 2026, 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 June 30, 2026 and December 31, 2025, was included in other long-term liabilities on the Consolidated Balance Sheets.

As of March 31, 2025, PacifiCorp had received all expected insurance recoveries with the final $98 million of proceeds received during the three-month period ended March 31, 2025. 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, the variation in the types of properties and damages and the ultimate outcome of legal actions, including mediation, settlement negotiations, jury verdicts and the James appeals process, including the April 2026 Oregon Court of Appeals opinion and the plaintiffs' appeal at the Oregon Supreme Court.

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, 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 and settlements were reached by Keller Williams, NAR and HomeServices subsequent to the trial. All settlements received court approval, had final judgments entered by the court and were appealed to the U.S. Court of Appeals for the Eighth Circuit. All appeals were fully briefed by December 19, 2025, and oral arguments took place on January 14, 2026. A ruling from the court on the appeals is pending.

The final HomeServices settlement agreement with the plaintiffs reached on April 25, 2024, 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. HomeServices has made payments of $10 million in September 2024, $57 million in February 2025 and $63 million in February 2026. HomeServices recognized an after-tax charge of approximately $140 million in the first quarter of 2024, and the liability outstanding as of June 30, 2026, and December 31, 2025, was $103 million and $158 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.

(11) 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 June 30, 2026
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	1,683	$	669	$	927	$	—	$	—	$	—	$	—	$	(1)	$	3,278
Retail gas	—		101		18		—		—		—		—		—		119
Wholesale	31		71		8		—		—		—		—		1		111
Transmission and distribution	34		13		20		278		—		162		—		—		507
Interstate pipeline	—		—		—		—		652		—		—		(30)		622
Other	43		—		1		—		(3)		—		—		(1)		40
Total Regulated	1,791		854		974		278		649		162		—		(31)		4,677
Nonregulated	—		1		3		18		333		21		255		(6)		625
Total Customer Revenue	1,791		855		977		296		982		183		255		(37)		5,302
Other revenue	10		17		—		29		10		2		43		—		111
Total	$	1,801	$	872	$	977	$	325	$	992	$	185	$	298	$	(37)	$	5,413


	For the Six-Month Period Ended June 30, 2026
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	3,369	$	1,258	$	1,621	$	—	$	—	$	—	$	—	$	(2)	$	6,246
Retail gas	—		433		55		—		—		—		—		—		488
Wholesale	52		257		23		—		2		—		—		—		334
Transmission and distribution	69		26		36		566		—		326		—		—		1,023
Interstate pipeline	—		—		—		—		1,645		—		—		(87)		1,558
Other	85		—		1		—		—		—		—		—		86
Total Regulated	3,575		1,974		1,736		566		1,647		326		—		(89)		9,735
Nonregulated	—		4		7		36		716		44		443		(7)		1,243
Total Customer Revenue	3,575		1,978		1,743		602		2,363		370		443		(96)		10,978
Other revenue	34		34		—		59		14		4		100		—		245
Total	$	3,609	$	2,012	$	1,743	$	661	$	2,377	$	374	$	543	$	(96)	$	11,223



	For the Three-Month Period Ended June 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	$	1,711	$	634	$	802	$	—	$	—	$	—	$	—	$	(1)	$	3,146
Retail gas	—		105		22		—		—		—		—		—		127
Wholesale	15		88		13		—		—		—		—		—		116
Transmission and distribution	34		13		16		252		—		163		—		—		478
Interstate pipeline	—		—		—		—		572		—		—		(27)		545
Other	35		—		1		—		—		—		—		—		36
Total Regulated	1,795		840		854		252		572		163		—		(28)		4,448
Nonregulated	—		1		2		22		301		17		248		(2)		589
Total Customer Revenue	1,795		841		856		274		873		180		248		(30)		5,037
Other revenue	15		19		1		29		(9)		1		38		(1)		93
Total	$	1,810	$	860	$	857	$	303	$	864	$	181	$	286	$	(31)	$	5,130


	For the Six-Month Period Ended June 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	$	3,358	$	1,179	$	1,435	$	—	$	—	$	—	$	—	$	(2)	$	5,970
Retail gas	—		414		71		—		—		—		—		—		485
Wholesale	28		204		29		—		1		—		—		—		262
Transmission and distribution	82		27		33		624		—		318		—		—		1,084
Interstate pipeline	—		—		—		—		1,431		—		—		(73)		1,358
Other	62		—		1		—		—		—		—		—		63
Total Regulated	3,530		1,824		1,569		624		1,432		318		—		(75)		9,222
Nonregulated	—		3		4		47		616		46		459		(2)		1,173
Total Customer Revenue	3,530		1,827		1,573		671		2,048		364		459		(77)		10,395
Other revenue	48		47		2		58		1		2		84		(1)		241
Total	$	3,578	$	1,874	$	1,575	$	729	$	2,049	$	366	$	543	$	(78)	$	10,636

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

Real Estate Services

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


	HomeServices
	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025
Customer Revenue:
Brokerage	$	1,169	$	1,161	$	1,947	$	1,942
Franchise	15		14		28		24
Total Customer Revenue	1,184		1,175		1,975		1,966
Mortgage and other revenue	89		89		160		158
Total	$	1,273	$	1,264	$	2,135	$	2,124

Remaining Performance Obligations

The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of June 30, 2026, by reportable segment (in millions):


	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total

BHE Pipeline Group	$	3,502	$	19,313	$	22,815
BHE Transmission	682		328		1,010
Total	$	4,184	$	19,641	$	23,825

(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, 2024	$	(421)	$	(1,999)	$	78	$	1	$	(2,341)
Other comprehensive (loss) income	(21)		725		(16)		—		688

Balance, June 30, 2025	$	(442)	$	(1,274)	$	62	$	1	$	(1,653)

Balance, December 31, 2025	$	(482)	$	(1,409)	$	46	$	1	$	(1,844)
Other comprehensive income (loss)	21		(207)		(5)		—		(191)

Balance, June 30, 2026	$	(461)	$	(1,616)	$	41	$	1	$	(2,035)

(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 June 30, 2026
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables(2)		HomeServices		BHE and Other(1)		Total

Operating revenue	$	1,801	$	872	$	977	$	325	$	992	$	185	$	298	$	1,273	$	(37)	$	6,686
Cost of sales	640		196		462		26		79		7		2		933		(36)		2,309
Operations and maintenance	474		231		164		69		290		44		110		306		30		1,718
Depreciation and amortization	315		282		151		93		164		50		76		9		—		1,140
Interest expense	270		111		91		48		74		38		30		—		129		791
Interest and dividend income	43		6		6		—		15		1		2		3		(9)		67
Income tax expense (benefit)	(53)		(193)		13		8		72		1		(309)		7		121		(333)
Equity income (loss)	—		—		—		1		5		21		(202)		3		—		(172)
Other segment items	(3)		9		40		(27)		(91)		(12)		(8)		(4)		31		(65)
Earnings on common shares	$	195	$	260	$	142	$	55	$	242	$	55	$	181	$	20	$	(259)	$	891

Capital expenditures	$	726	$	470	$	764	$	176	$	264	$	65	$	80	$	6	$	(20)	$	2,531



	For the Six-Month Period Ended June 30, 2026
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables(2)		HomeServices		BHE and Other(1)		Total

Operating revenue	$	3,609	$	2,012	$	1,743	$	661	$	2,377	$	374	$	543	$	2,135	$	(96)	$	13,358
Cost of sales	1,395		680		833		53		130		12		37		1,538		(94)		4,584
Operations and maintenance	937		451		324		138		523		83		207		569		47		3,279
Depreciation and amortization	625		559		299		191		329		102		152		18		—		2,275
Interest expense	497		220		176		96		147		75		61		—		265		1,537
Interest and dividend income	70		12		14		1		26		1		4		7		(14)		121
Income tax expense (benefit)	(74)		(411)		17		23		254		5		(628)		3		48		(763)
Equity income (loss)	—		—		1		1		33		43		(387)		3		—		(306)
Other segment items	(33)		(20)		76		(44)		(205)		(22)		(22)		(9)		23		(256)
Earnings on common shares	$	266	$	505	$	185	$	118	$	848	$	119	$	309	$	8	$	(353)	$	2,005

Capital expenditures	$	1,443	$	888	$	1,395	$	347	$	479	$	173	$	249	$	9	$	(34)	$	4,949


	For the Three-Month Period Ended June 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	$	1,810	$	860	$	857	$	303	$	864	$	181	$	286	$	1,264	$	(31)	$	6,394
Cost of sales	723		211		417		33		67		3		9		924		(29)		2,358
Operations and maintenance	479		236		149		58		278		39		128		274		25		1,666
Depreciation and amortization	372		255		138		89		153		49		73		10		—		1,139
Interest expense	202		105		79		39		72		37		34		2		139		709
Interest and dividend income	33		8		5		1		14		1		3		4		(6)		63
Income tax expense (benefit)	(33)		(181)		9		(16)		51		3		(318)		15		113		(357)
Equity income (loss)	—		—		—		1		10		20		(194)		3		—		(160)
Other segment items	4		1		17		(21)		(84)		(10)		(8)		(1)		22		(80)
Earnings on common shares	$	104	$	243	$	87	$	81	$	183	$	61	$	161	$	45	$	(263)	$	702

Capital expenditures	$	718	$	335	$	690	$	171	$	266	$	101	$	108	$	2	$	54	$	2,445



	For the Six-Month Period Ended June 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	$	3,578	$	1,874	$	1,575	$	729	$	2,049	$	366	$	543	$	2,124	$	(78)	$	12,760
Cost of sales	1,441		580		774		62		121		9		54		1,529		(76)		4,494
Operations and maintenance	903		463		286		113		502		74		262		528		38		3,169
Depreciation and amortization	671		562		276		176		305		104		141		20		—		2,255
Interest expense	389		210		158		72		142		73		65		3		283		1,395
Interest and dividend income	61		14		11		4		37		1		7		8		(18)		125
Income tax expense (benefit)	(52)		(417)		12		41		195		7		(654)		9		103		(756)
Equity income (loss)	—		—		1		1		37		43		(366)		4		—		(280)
Other segment items	(5)		(19)		28		(44)		(187)		(20)		(15)		(17)		117		(162)
Earnings on common shares	$	282	$	471	$	109	$	226	$	671	$	123	$	301	$	30	$	(327)	$	1,886

Capital expenditures	$	1,406	$	740	$	1,146	$	328	$	454	$	182	$	220	$	3	$	94	$	4,573

(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.

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

Capitalized interest

Allowance for equity funds

Gains (losses) on marketable securities, net

Other income (expense), net

Net income attributable to noncontrolling interests

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


	As of
	June 30,		December 31,
	2026		2025
Assets:
PacifiCorp	$	42,405	$	38,323
MidAmerican Funding	30,173		29,712
NV Energy	22,687		21,118
Northern Powergrid	10,827		10,819
BHE Pipeline Group	23,233		22,977
BHE Transmission	9,633		9,762
BHE Renewables	11,249		11,644
HomeServices	3,606		3,449
BHE and Other(1)	216		523
Total assets	$	154,029	$	148,327

The following table shows the change in the carrying amount of goodwill by reportable segment for the six-month period ended June 30, 2026 (in millions):


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

December 31, 2025	$	1,129	$	2,102	$	2,369	$	990	$	1,814	$	1,439	$	95	$	1,583	$	11,521

Foreign currency translation	—		—		—		(11)		—		(47)		—		—		(58)
Dispositions	(89)		—		—		—		—		—		—		—		(89)

June 30, 2026	$	1,040	$	2,102	$	2,369	$	979	$	1,814	$	1,392	$	95	$	1,583	$	11,374

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, one of the largest residential real estate brokerage firms in the U.S. and a residential real estate brokerage franchise business 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.

Results of Operations for the Second Quarter and First Six Months of 2026 and 2025

Overview

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


	Second Quarter								First Six Months
	2026		2025		Change				2026		2025		Change
Operating revenue:
PacifiCorp	$	1,801	$	1,810	$	(9)	—	%	$	3,609	$	3,578	$	31	1	%
MidAmerican Funding	872		860		12		1		2,012		1,874		138		7
NV Energy	977		857		120		14		1,743		1,575		168		11
Northern Powergrid	325		303		22		7		661		729		(68)		(9)
BHE Pipeline Group	992		864		128		15		2,377		2,049		328		16
BHE Transmission	185		181		4		2		374		366		8		2
BHE Renewables	298		286		12		4		543		543		—		—
HomeServices	1,273		1,264		9		1		2,135		2,124		11		1
BHE and Other	(37)		(31)		(6)		(19)		(96)		(78)		(18)		(23)
Total operating revenue	$	6,686	$	6,394	$	292	5	%	$	13,358	$	12,760	$	598	5	%

Earnings on common shares:
PacifiCorp	$	195	$	104	$	91	88	%	$	266	$	282	$	(16)	(6)	%
MidAmerican Funding	260		243		17		7		505		471		34		7
NV Energy	142		87		55		63		185		109		76		70
Northern Powergrid	55		81		(26)		(32)		118		226		(108)		(48)
BHE Pipeline Group	242		183		59		32		848		671		177		26
BHE Transmission	55		61		(6)		(10)		119		123		(4)		(3)
BHE Renewables(1)	181		161		20		12		309		301		8		3
HomeServices	20		45		(25)		(56)		8		30		(22)		(73)
BHE and Other	(259)		(263)		4		2		(353)		(327)		(26)		(8)
Total earnings on common shares	$	891	$	702	$	189	27	%	$	2,005	$	1,886	$	119	6	%

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

Earnings on common shares increased $119 million for the first six months of 2026 compared to 2025. Included in these results was a pre-tax gain in the first six months of 2025 of $110 million ($87 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 first six months of 2026 increased $206 million, or 11%, compared to adjusted earnings on common shares for the first six months of 2025 of $1,799 million.

The changes in earnings on common shares for the second quarter and for the first six months of 2026 compared to 2025 were primarily due to the following:

•The Utilities' earnings increased $163 million for the second quarter and $94 million for the first six months of 2026 compared to 2025, primarily due to higher electric utility margin, increased allowances for equity and borrowed funds used during construction, lower depreciation and amortization expense and higher PTCs recognized, partially offset by increased interest expense and higher operations and maintenance expense. Electric retail customer volumes increased 3.1% for the first six months of 2026 compared to 2025, 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 $26 million for the second quarter and $108 million for the first six months of 2026 compared to 2025, primarily due to higher distribution revenue for the first six months of 2025, higher interest expense and higher distribution-related operating and depreciation costs, partially offset by higher income tax expense from prior year utilization of tax losses from the upstream gas exploration and production business. Units distributed increased 0.7% for the first six months of 2026 compared to 2025 mainly due to higher customer usage;

•BHE Pipeline Group's earnings increased $59 million for the second quarter and $177 million for the first six months of 2026 compared to 2025, primarily due to higher transportation revenues at Northern Natural Gas and higher variable revenue at Cove Point;

•BHE Renewables' earnings increased $20 million for the second quarter and $8 million for the first six months of 2026 compared to 2025, primarily due to higher geothermal and natural gas earnings and higher solar earnings, partially offset by lower wind earnings largely from the tax equity investment portfolio;

•HomeServices' earnings decreased $25 million for the second quarter and $22 million for the first six months of 2026 compared to 2025, primarily due to an after-tax charge of $22 million associated with a settlement reached in the ongoing real estate industry litigation matters; and

•BHE and Other's earnings decreased $26 million for the first six months of 2026 compared to 2025, primarily due to the $87 million after-tax gain recognized in the first quarter of 2025 related to the Company's investment in BYD Company Limited, partially offset by higher federal income tax credits recognized on a consolidated basis, lower interest expense and favorable consolidated income tax adjustments.

Reportable Segment Results

PacifiCorp

Operating revenue decreased $9 million for the second quarter of 2026 compared to 2025, primarily due to lower retail revenue of $26 million, partially offset by higher wholesale and other revenue of $17 million. Retail revenue decreased primarily due to price impacts of $73 million from lower average rates, largely from $87 million of prior year utilization of certain existing regulatory liabilities due to the buy-down of certain plant balances pursuant to the Utah general rate case order (fully offset in depreciation and amortization expense), partially offset by $47 million from higher retail volumes. Retail customer volumes increased 2.7% primarily due to higher customer usage and an increase in the average number of customers, partially offset by the unfavorable impact of weather. Wholesale and other revenue increased primarily due to higher wholesale volumes and higher average wholesale prices.

Earnings increased $91 million for the second quarter of 2026 compared to 2025, primarily due to higher utility margin of $74 million, lower depreciation and amortization expense of $57 million and higher PTCs recognized of $36 million, partially offset by increased interest expense of $68 million. Utility margin increased primarily due to favorable deferred net power costs, higher retail volumes, lower thermal generation costs and higher wholesale volumes and average prices, partially offset by lower retail rates and higher purchased electricity costs. Depreciation and amortization decreased primarily due to the prior year buy-down of certain plant balances pursuant to the Utah general rate case order (fully offset in operating revenue), partially offset by additional assets placed in-service. Interest expense increased mainly due to higher average outstanding long-term debt balances.

Operating revenue increased $31 million for the first six months of 2026 compared to 2025, primarily due to higher retail revenue of $18 million and higher wholesale and other revenue of $13 million. Retail revenue increased primarily due to $16 million from higher retail volumes and price impacts of $2 million from higher average rates. Average rates were favorably impacted by tariff changes and product mix, largely offset by $87 million of prior year utilization of certain existing regulatory liabilities due to the buy-down of certain plant balances pursuant to the Utah general rate case order (fully offset in depreciation and amortization expense). Retail customer volumes increased by 0.8%, primarily due to higher customer usage and an increase in the average number of customers, partially offset by the unfavorable impact of weather. Wholesale and other revenue increased primarily due to higher wholesale volumes, partially offset by lower average wholesale prices.

Earnings decreased $16 million for the first six months of 2026 compared to 2025, primarily due to increased interest expense of $108 million, higher operations and maintenance expense of $34 million and lower allowances for equity and borrowed funds used during construction of $14 million, partially offset by higher utility margin of $77 million, lower depreciation and amortization expense of $46 million and higher PTCs recognized of $19 million. Interest expense increased mainly due to higher average outstanding long-term debt balances. Operations and maintenance expense increased due to higher injuries and damages costs, increased vegetation management and other wildfire prevention costs and lower federal grant reimbursements, partially offset by lower general plant and maintenance costs and lower insurance premiums. Utility margin increased primarily due to lower thermal generation costs, higher retail and wholesale volumes and favorable deferred net power costs, partially offset by higher purchased electricity costs and lower wholesale average prices. Depreciation and amortization decreased primarily due to the prior year buy-down of certain plant balances pursuant to the Utah general rate case order (fully offset in operating revenue), partially offset by additional assets placed in-service.

MidAmerican Funding

Operating revenue increased $12 million for the second quarter of 2026 compared to 2025, primarily due to higher electric operating revenue of $17 million, partially offset by lower natural gas operating revenue of $5 million. Electric operating revenue increased due to higher retail revenue of $36 million, partially offset by lower wholesale and other revenue of $19 million. Electric retail revenue increased primarily due to higher retail volumes of $29 million and higher recoveries through adjustment clauses of $11 million (fully offset in cost of sales, operations and maintenance expense and income tax benefit). Electric retail customer volumes increased 7.6%, primarily due to higher customer usage. Electric wholesale and other revenue decreased mainly due to lower average wholesale prices of $15 million. Natural gas operating revenue decreased primarily due to lower energy-related rates of $6 million (fully offset in cost of sales) from a lower average per-unit cost of natural gas sold.

Earnings increased $17 million for the second quarter of 2026 compared to 2025, primarily due to higher electric utility margin of $24 million and increased PTCs recognized of $13 million, partially offset by higher depreciation and amortization expense of $27 million. Electric utility margin increased primarily due to higher retail revenue and lower thermal generation costs, partially offset by lower wholesale revenue. Depreciation and amortization expense increased primarily due to additional assets placed in-service and the impacts of certain regulatory mechanisms.

Operating revenue increased $138 million for the first six months of 2026 compared to 2025, primarily due to higher electric operating revenue of $97 million and higher natural gas operating revenue of $40 million. Electric operating revenue increased due to higher retail revenue of $79 million and higher wholesale and other revenue of $18 million. Electric retail revenue increased primarily due to higher retail volumes of $41 million and higher recoveries through adjustment clauses of $38 million (fully offset in cost of sales, operations and maintenance expense and income tax benefit). Electric retail customer volumes increased 6.0%, primarily due to higher customer usage. Electric wholesale and other revenue increased primarily due to higher average wholesale prices of $26 million, partially offset by lower wholesale volumes of $8 million. Natural gas operating revenue increased primarily due to higher energy-related rates of $38 million (fully offset in cost of sales) from a higher average per-unit cost of natural gas sold.

Earnings increased $34 million for the first six months of 2026 compared to 2025, primarily due to higher electric utility margin of $34 million and lower operations and maintenance expense of $11 million, partially offset by higher interest expense of $10 million. Electric utility margin increased primarily due to higher retail and wholesale revenues and lower thermal generation costs, partially offset by higher purchased electricity costs. Operations and maintenance expense decreased mainly due to lower general and plant maintenance costs. Interest expense increased largely due to higher average outstanding long-term debt balances.

NV Energy

Operating revenue increased $120 million for the second quarter of 2026 compared to 2025, primarily due to higher electric operating revenue of $123 million. Electric operating revenue increased primarily due to higher fully bundled energy rates (fully offset in cost of sales) of $46 million, increased base rates of $38 million at Nevada Power, lower prior year revenue related to an accrual in connection with customer refunds arising from regulatory proceedings of $20 million and higher customer volumes of $11 million. Electric retail customer volumes increased 4.4%, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers.

Earnings increased $55 million for the second quarter of 2026 compared to 2025, primarily due to higher electric utility margin of $73 million and increased allowances for borrowed and equity funds of $24 million, partially offset by higher operations and maintenance expense of $15 million, increased depreciation and amortization expense of $13 million and higher interest expense of $11 million. Electric utility margin increased primarily due to increased base rates at Nevada Power, lower prior year revenue related to an accrual in connection with customer refunds arising from regulatory proceedings and higher retail volumes. Operations and maintenance expenses increased primarily due to higher administrative costs and increased insurance premiums. Depreciation and amortization expense increased primarily due to additional assets placed in-service. Interest expense increased mainly due to higher average outstanding long-term debt balances.

Operating revenue increased $168 million for the first six months of 2026 compared to 2025, primarily due to higher electric operating revenue of $182 million, partially offset by lower natural gas operating revenue of $17 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 increased primarily due to higher fully bundled energy rates (fully offset in cost of sales) of $71 million, increased base rates of $56 million at Nevada Power, lower prior year revenue related to an accrual in connection with customer refunds arising from regulatory proceedings of $20 million and higher customer volumes of $18 million. Electric retail customer volumes increased 4.3%, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers.

Earnings increased $76 million for the first six months of 2026 compared to 2025, primarily due to higher electric utility margin of $107 million and increased allowances for borrowed and equity funds of $48 million, partially offset by higher operations and maintenance expense of $38 million, increased depreciation and amortization expense of $23 million and higher interest expense of $17 million. Electric utility margin increased primarily due to higher base rates at Nevada Power, lower prior year revenue related to an accrual in connection with customer refunds arising from regulatory proceedings and higher retail volumes. Operations and maintenance expenses increased primarily due to higher administrative costs and increased insurance premiums. Depreciation and amortization expense increased primarily due to additional assets placed in-service. Interest expense increased mainly due to higher average outstanding long-term debt balances.

Northern Powergrid

Operating revenue increased $22 million for the second quarter of 2026 compared to 2025, primarily due to higher distribution revenue of $23 million. Distribution revenue increased primarily due to higher tariff rates driven by the impacts of inflation. Units distributed increased 1.8% mainly due to higher customer usage.

Earnings decreased $26 million for the second quarter of 2026 compared to 2025, primarily due to higher income tax expense from prior year utilization of tax losses from the upstream gas exploration and production business of $19 million, higher distribution-related operating and depreciation costs and increased interest expense of $9 million, partially offset by higher distribution revenue. Interest expense increased mainly due to higher average outstanding long-term debt balances.

Operating revenue decreased $68 million for the first six months of 2026 compared to 2025, primarily due to lower distribution revenue of $82 million, partially offset by $26 million from the weaker U.S. dollar. Distribution revenue decreased primarily due to higher revenue driven by the inflation adjustment mechanism in the first quarter of 2025. Units distributed increased 0.7% mainly due to higher customer usage.

Earnings decreased $108 million for the first six months of 2026 compared to 2025, primarily due to higher distribution revenue in the first quarter of 2025 driven by the inflation adjustment mechanism, higher interest expense of $25 million, increased distribution-related operating and depreciation costs and higher income tax expense from prior year utilization of tax losses from the upstream gas exploration and production business of $13 million. Interest expense increased mainly due to higher average outstanding long-term debt balances.

BHE Pipeline Group

Operating revenue increased $128 million for the second quarter of 2026 compared to 2025, primarily due to higher operating revenue of $76 million at Northern Natural Gas and higher operating revenue of $42 million at BHE GT&S. The increase in operating revenue at Northern Natural Gas was primarily due to higher transportation revenue in the Field Area of $48 million, largely from higher variable rates, the impacts of a general rate case of $20 million and higher gas sales of $10 million (largely offset in cost of sales) from system balancing activities. The increase in operating revenue at BHE GT&S was primarily due to favorable variable revenues at Cove Point of $20 million, higher regulated gas transmission and storage services revenue of $11 million, largely from additional capacity contracts, and an increase in variable revenue related to natural gas storage park and loan activity of $6 million at EGTS.

Earnings increased $59 million for the second quarter of 2026 compared to 2025, primarily due to higher earnings of $43 million at Northern Natural Gas and higher earnings of $16 million at BHE GT&S. The increase at Northern Natural Gas was primarily due to higher transportation revenues, partially offset by higher depreciation and amortization expense of $5 million from additional assets placed in-service. The increase at BHE GT&S was primarily due to favorable variable revenue at Cove Point and higher regulated gas transmission and storage services revenue.

Operating revenue increased $328 million for the first six months of 2026 compared to 2025, primarily due to higher operating revenue of $191 million at Northern Natural Gas and higher operating revenue of $118 million at BHE GT&S. The increase in operating revenue at Northern Natural Gas was primarily due to the impacts of a general rate case of $90 million, higher transportation revenue in the Field Area of $83 million, largely from higher variable rates, and higher gas sales of $13 million from system balancing activities. The increase in operating revenue at BHE GT&S was primarily due to favorable variable revenue at Cove Point of $79 million, largely due to higher volumes and higher prices from extremely cold weather in the first quarter of 2026, higher regulated gas transmission and storage services revenue of $14 million, largely from additional capacity contracts, and an increase in variable revenue related to natural gas storage park and loan activity of $10 million at EGTS.

Earnings increased $177 million for the first six months of 2026 compared to 2025, primarily due to higher earnings of $123 million at Northern Natural Gas and higher earnings of $52 million at BHE GT&S. The increase at Northern Natural Gas was primarily due to higher transportation revenues and higher margin on gas sales of $12 million from system balancing activities, partially offset by higher depreciation and amortization expense of $11 million from additional assets placed in-service. The increase at BHE GT&S was primarily due to favorable variable revenue at Cove Point, a gain from the initial conveyance of development rights under one of its natural gas storage fields at EGTS of $16 million, higher regulated gas transmission and storage services revenue and an increase in variable revenue related to natural gas storage park and loan activity at EGTS, partially offset by higher operations and maintenance expense of $18 million, largely due to increased plant operations and maintenance costs, and decreased interest and dividend income of $9 million.

BHE Transmission

Operating revenue increased $4 million for the second quarter of 2026 compared to 2025, primarily due to $8 million of higher revenue from non-regulated wind-powered generating facilities from higher generation and pricing, partially offset by lower costs recovered in operating revenue at AltaLink of $7 million.

Earnings decreased $6 million for the second quarter of 2026 compared to 2025, primarily due to the disallowance of certain wildfire costs at AltaLink.

Operating revenue increased $8 million for the first six months of 2026 compared to 2025, primarily due to $7 million from the weaker U.S. dollar.

Earnings decreased $4 million for the first six months of 2026 compared to 2025, primarily due to the disallowance of certain wildfire costs at AltaLink.

BHE Renewables

Operating revenue increased $12 million for the second quarter of 2026 compared to 2025, primarily due to higher solar revenue from higher generation.

Earnings increased $20 million for the second quarter of 2026 compared to 2025, primarily due to higher solar earnings of $23 million largely due to higher generation, partially offset by lower wind earnings of $3 million. Wind earnings decreased due to lower earnings from the tax equity investment portfolio of $7 million largely due to timing of equity earnings, partially offset by higher earnings from owned projects of $4 million, mainly from lower interest expense due to lower average outstanding long-term debt balances.

Operating revenue was unchanged for the first six months of 2026 compared to 2025, primarily due to lower electric and natural gas retail energy services revenue of $25 million and lower wind revenue of $18 million, partially offset by higher natural gas and geothermal revenue of $31 million, from higher natural gas pricing and higher geothermal generation, and higher solar revenue of $11 million from higher generation and pricing. Wind revenue decreased due to lower generation and unfavorable changes in the valuation of certain derivative contracts.

Earnings increased $8 million for the first six months of 2026 compared to 2025, primarily due to higher geothermal and natural gas earnings of $36 million from lower maintenance costs, higher natural gas pricing and higher geothermal generation, higher solar earnings of $24 million largely due to higher generation and pricing, partially offset by lower wind earnings of $46 million. Wind earnings decreased due to lower earnings from the tax equity investment portfolio of $28 million, largely due to timing of equity earnings and lower PTCs of $13 million, and lower earnings from owned projects of $18 million primarily from lower revenue.

HomeServices

Operating revenue increased $9 million for the second quarter of 2026 compared to 2025, primarily due to higher brokerage and settlement services revenue from a 2% increase in average sales price.

Earnings decreased $25 million for the second quarter of 2026 compared to 2025, primarily due to an after-tax charge of $22 million associated with a settlement reached in the ongoing real estate industry litigation matters.

Operating revenue increased $11 million for the first six months of 2026 compared to 2025, primarily due to higher mortgage, franchise and other revenue.

Earnings decreased $22 million for the first six months of 2026 compared to 2025, primarily due to an after-tax charge of $22 million associated with a settlement reached in the ongoing real estate industry litigation matters.

BHE and Other

Earnings increased $4 million for the second quarter of 2026 compared to 2025, primarily due to favorable consolidated income tax adjustments of $16 million, lower interest expense of $9 million largely due to lower average outstanding long-term debt balances and favorable changes in the cash surrender value of corporate-owned life insurance policies of $7 million, partially offset by $24 million of lower federal income tax credits recognized on a consolidated basis.

Earnings decreased $26 million for the first six months of 2026 compared to 2025, primarily due to the $87 million after-tax gain recognized in 2025 related to the Company's investment in BYD Company Limited, partially offset by $24 million of higher federal income tax credits recognized on a consolidated basis, lower interest expense of $18 million largely due to lower average outstanding long-term debt balances, favorable consolidated income tax adjustments of $14 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $6 million.

Liquidity and Capital Resources

Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The Company's long-term debt may include provisions that allow BHE or its subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 18 of Notes to Consolidated Financial Statements in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2025, for further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of June 30, 2026, 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(1)	$	122	$	2,075	$	681	$	367	$	40	$	138	$	312	$	337	$	4,072

Credit facilities(2)(3)	3,500		3,000		1,509		1,000		376		863		1,600		—		11,848
Less:
Short-term debt	—		—		—		—		(236)		(309)		(829)		—		(1,374)
Tax-exempt bond support and letters of credit	—		—		(258)		—		—		(6)		—		—		(264)
Net credit facilities	3,500		3,000		1,251		1,000		140		548		771		—		10,210

Total net liquidity	$	3,622	$	5,075	$	1,932	$	1,367	$	180	$	686	$	1,083	$	337	$	14,282
Credit facilities:
Maturity dates	2029		2029		2027, 2029		2029		2026, 2028		2028, 2029, 2030		2026, 2027, 2030

(1)Excludes a $245 million U.S. Treasury Bill at PacifiCorp included in investments and restricted cash and cash equivalents on the Consolidated Balance Sheets.

(2)Includes $110 million drawn on capital expenditure and other uncommitted credit facilities at Northern Powergrid.

(3)Includes $211 million of temporary short-term credit facility capacity at AltaLink, providing additional support for the unsecured commercial paper program, which was used to fund the maturity of C$350 million of long-term debt in May 2026. In July 2026, the commercial paper borrowed was repaid and the $211 million short-term credit facility was terminated.

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2026 and 2025, were $4.7 billion and $4.3 billion, respectively. The increase was primarily due to higher income tax receipts and favorable operating results, partially offset by higher wildfire liability settlement payments.

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

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2026 and 2025, were $(5.1) billion and $(4.1) billion, respectively. The change was primarily due to lower proceeds from sales of BYD Company Limited common stock of $525 million, higher capital expenditures of $376 million and higher net purchases of U.S. Treasury Bills of $207 million. Refer to "Future Uses of Cash" for a discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2026, was $2,806 million. Sources of cash totaled $4.8 billion and consisted mainly of proceeds from subsidiary debt issuances of $4.6 billion, primarily at PacifiCorp. Uses of cash totaled $2.0 billion and consisted mainly of repayments of subsidiary debt of $1.3 billion, net repayments of short-term debt of $609 million, and distributions to noncontrolling interests of $115 million.

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

Net cash flows from financing activities for the six-month period ended June 30, 2025, was $0.6 billion. Sources of cash totaled $3.2 billion and consisted of proceeds from subsidiary debt issuances of $2.7 billion and net proceeds from short-term debt of $551 million. Uses of cash totaled $2.6 billion and consisted mainly repayments of BHE senior debt of $1.7 billion, preferred stock redemptions of $481 million and repayments of subsidiary debt of $388 million.

Letters of Credit

In April 2026, PacifiCorp entered into a $2.55 billion letter of credit agreement, effective May 18, 2026, under which letters of credit will be made available solely to provide collateral support for surety bonds issued pursuant to a corresponding surety arrangement for supersedeas undertakings to secure the performance and stay enforcement of trial court judgments entered against PacifiCorp relating to the James case. Refer to Note 6 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding this arrangement.

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

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

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


	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2025		2026		2026
Capital expenditures by business:
PacifiCorp	$	1,406	$	1,443	$	2,888
MidAmerican Funding	740		888		2,530
NV Energy	1,146		1,395		3,212
Northern Powergrid	328		347		839
BHE Pipeline Group	454		479		1,370
BHE Transmission	182		173		377
BHE Renewables	220		249		407
HomeServices	3		9		34
BHE and Other(1)	94		(34)		(19)
Total	$	4,573	$	4,949	$	11,638





Capital expenditures by type:
Electric distribution	$	1,182	$	1,196	$	2,791
Electric transmission	887		963		2,635
Natural gas transmission and storage	335		458		1,260
Solar generation	220		258		730
Wind generation	329		242		728
Wildfire prevention	383		309		601
Electric battery storage	103		139		236
Other	1,134		1,384		2,657
Total	$	4,573	$	4,949	$	11,638

(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 $180 million and $91 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for major transmission projects that are expected to be placed in‑service through 2032 totals $250 million for the remainder of 2026.

◦Nevada Utilities' Greenlink Nevada transmission expansion program. Expenditures for the expansion program and other growth projects totaled $402 million and $347 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for the expansion program estimated to be placed in-service in 2027 through 2028 and other growth projects totals $759 million for the remainder of 2026.

•Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, spending for customer driven expansion projects. Operating expenditures include spending for pipeline integrity projects, automation and controls upgrades, corrosion control, unit exchanges, compressor modifications, projects related to Pipeline and Hazardous Materials Safety Administration natural gas storage rules and natural gas transmission, storage, LNG terminalling infrastructure needs to serve existing and expected demand and asset modernization programs.

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

◦Construction and operation of solar-powered generating facilities at MidAmerican Energy totaling $60 million and $1 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending totals $252 million for the remainder of 2026.

◦Construction at the Nevada Utilities 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 10% for Nevada Power and 90% for Sierra Pacific. Commercial operation of the solar facility is expected by early 2027 and the co-located battery storage reached commercial operation in March 2026. Spending for the solar-powered generating facilities totaled $31 million and $163 million, respectively, while spending for the co-located battery storage totaled $118 million and $30 million, respectively, for the six-month periods ended June 30, 2026 and 2025. Planned spending for the solar-powered generating facility totals $50 million for the remainder of 2026.

◦Construction at BHE Renewables of a 48-MW solar photovoltaic facility with an additional 46 MWs of co-located battery storage that is being developed in Kern County, California, with commercial operation expected in 2026 and a 106-MW solar photovoltaic facility with an additional 20 MWs of co-located battery storage located in Jackson County, West Virginia, with commercial operations expected to be complete in 2027. Spending for the solar-powered generating facilities totaled $16 million and $32 million, respectively, while spending for the co-located battery storage totaled $11 million and $36 million, respectively, for the six-month periods ended June 30, 2026 and 2025. Planned spending for the solar-powered generating facilities and co-located battery storage total $70 million and $33 million, respectively, for the remainder of 2026.

◦Construction at BHE Montana of a 130-MW solar photovoltaic facility with commercial operation expected in 2026 and a 75 MWs of battery storage that was put into service in January 2026 located in Glacier and Toole Counties in Montana and Ethridge, Montana, respectively. Spending for the solar-powered generating facilities totaled $62 million and $1 million, respectively, while spending for the co-located battery storage totaled $10 million and $36 million, respectively, for the six-month periods ended June 30, 2026 and 2025. Planned spending for the solar-powered generating facility totals $96 million for the remainder of 2026.

•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 $2 million and $124 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for the construction of additional wind-powered generating facilities totals $43 million for the remainder of 2026.

◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $180 million and $85 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for the repowering of wind-powered generating facilities totals $395 million for the remainder of 2026. 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.

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

◦Expenditures at PacifiCorp totaling $281 million and $365 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for wildfire prevention totals $209 million for the remainder of 2026, 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, replacing traditional fuses with non-expulsion fuses 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 $14 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for wildfire prevention totals $73 million for the remainder of 2026, and is comprised of 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 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 June 30, 2026, 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, 2025, other than those disclosed in Notes 6 and 10 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, 2025, and new regulatory matters occurring in 2026.

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. 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. Refer to the June 2026 Utah joint settlement agreement below.

In June 2024, PacifiCorp filed a general rate case requesting a rate increase and subsequently filed an amended application and updated testimony requesting a revised rate increase of $330 million, or 14.0%, effective February 23, 2025. In April 2025, the UPSC issued a final order approving a rate increase of $87 million, or 3.7%, effective April 25, 2025. 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 filed for review of these decisions with the Utah Supreme Court. Refer to the June 2026 Utah joint settlement agreement below.

In November 2025, PacifiCorp filed an application to create a catastrophic wildfire fund authorized by Utah statute. The fire fund would serve as a supplement to other forms of insurance to manage liabilities associated with catastrophic fire events in Utah that are not otherwise covered by insurance. In March 2026, the UPSC issued a notice of legal conclusion that determined that the surcharge for a fire fund could not be implemented outside of a general rate case. This docket will remain active to make findings and determinations regarding the catastrophic wildfire fund in advance of the next general rate case.

In May 2026, PacifiCorp filed its EBA application to recover deferred net power costs from 2025. The filing requests a rate decrease of $375 million, or 12.5%, to be effective on an interim basis on July 1, 2026. In June 2026, the UPSC approved the interim rate change, effective July 1, 2026.

In June 2026, PacifiCorp reached a joint settlement subject to the UPSC's approval resolving all matters in the above-mentioned consolidated appeals at the Utah Supreme Court. The joint settlement agreement, if approved, will, among other things: (i) result in an annual rate increase of $93 million subject to sharing under an asymmetrical earnings test; (ii) require PacifiCorp to invest $2 billion in infrastructure projects located in Utah through December 31, 2028; and (iii) require PacifiCorp to not file a general rate case with a rate effective date prior to January 1, 2029. In July 2026, the UPSC approved the joint settlement and in August 2026, PacifiCorp made the compliance filing to make rates effective August 10, 2026.

Oregon

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 sought a rate increase of $51 million, or 2.5%, effective January 1, 2026. In December 2025, the OPUC approved recovery of the wind-powered generating facilities but not the associated transmission lines, citing that the transmission costs could only be recovered in a general rate case. The filing resulted in a rate increase of $40 million, which is a 2.2% increase for non-residential customers effective January 1, 2026, and a 1.7% increase for residential customers effective April 1, 2026. In February 2026, PacifiCorp filed an application for reconsideration with the OPUC regarding the decision to exclude recovery of the transmission lines that the OPUC denied in March 2026.

In May 2026, PacifiCorp filed a general rate case requesting an overall rate increase of $171 million, or 8.6%. To address near-term financial needs, PacifiCorp requested an interim rate increase effective June 4, 2026, with the remaining increase effective July 15, 2027. If interim rates were denied, PacifiCorp requested the entirety of the rate increase to be effective April 5, 2027. In May 2026, the OPUC denied PacifiCorp's request for interim rates. The general rate case request includes recovery of capital investments, including full recovery of the transmission lines for which recovery was limited in the December 2024 general rate case order, and increased operating and maintenance expenses, including increased insurance premiums.

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, and subsequently filed to update net power costs and increase third-party liability insurance premium costs. 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 of multiple items, including the WPSC's adjustment to net power costs related to third-party wholesale reserves and costs associated with the Washington Cap and Invest program. In an April 2024 open meeting, the WPSC denied rehearing, and PacifiCorp pursued review in both federal and Wyoming state courts. In September 2025, the U.S. District Court for the District of Wyoming ruled that WPSC's net power costs adjustment intruded on the FERC's jurisdiction over third-party wholesale reserves, and the WPSC subsequently appealed the ruling to the Tenth Circuit Court of Appeals. In July 2026, the District Court for the First Judicial District of Wyoming affirmed the WPSC disallowance of costs associated with the Washington Cap and Invest program.

In January 2026, PacifiCorp filed an application to establish a temporary balancing account to track the excess liability insurance premium expenses currently included in rates and 80% of the cost of claims and outside legal defense costs related to wildfires that occur in Wyoming while pursuing a self-insurance reserve fund for wildfire liability. The WPSC approved the application in May 2026.

In April 2026, PacifiCorp filed its energy cost adjustment mechanism and renewable energy credit and sulfur dioxide revenue credit mechanism combined application to recover deferred net power costs from 2025. The filing requests a rate decrease of $51 million, or 6.0%, to be effective on an interim basis on July 1, 2026. In June 2026, the WPSC approved the interim rate change, effective July 1, 2026.

In May 2026, PacifiCorp filed a general rate case requesting a two-step rate increase of $70 million, or 8.8%. The request seeks an increase of $68 million, of 8.5%, effective March 15, 2027, and a second increase of $2 million, or 0.3%, effective April 1, 2027, dependent on the approval of the Washington service area transfer discussed below. If the Washington service area transfer is approved, the new rates will capture the impacts of the sale due to changes in allocation factors and any sharing of the excess of the value of the amount received over the net assets to be sold. The request includes recovery of capital investments and increased net power costs. The general rate case also requests revisions to the energy cost adjustment mechanism to allow for quarterly updates and funding for a wildfire self-insurance reserve fund.

Idaho

In January 2026, PacifiCorp filed an application to establish a temporary balancing account to track the excess liability insurance premium expenses currently included in rates and 80% of the cost of claims and outside legal defense costs related to wildfires that occur in Idaho while pursuing a self-insurance reserve fund for wildfire liability. The IPUC approved the application in April 2026.

California

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. In June 2026, the CPUC approved the joint settlement, and on July 10, 2026, PacifiCorp made the compliance filing to make the catastrophic events memorandum account rate increase effective.

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 was originally scheduled to take place in May 2026. However, due to scheduling issues, hearings began in June 2026 and will continue through November 2026.

In February 2026, PacifiCorp filed an application to recover over $340 million associated with the wildfire expense memorandum account representing claims costs paid and legal expense incurred to resolve third-party claims arising from the California portion of the Slater Fire and the 2022 McKinney Fire.

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 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. In June 2025, several PacifiCorp transmission customers filed 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. Subsequently in 2025, PacifiCorp and those transmission customers filed responses with the FERC. In April 2026, PacifiCorp filed a motion to lodge the Oregon Court of Appeals opinion reversing and remanding the James liability verdict. PacifiCorp will continue to utilize the FERC-established process to resolve all outstanding issues related to its 2024 annual update. The matter is pending before the FERC.

In May 2025, PacifiCorp published the 2025 annual update of its transmission formula rate in FERC Docket No. ER25-2221-000, which included the impacts of approximately $346 million of accrued losses associated with the Wildfires recognized during the year ended December 31, 2024, among other adjustments. In January 2026, several PacifiCorp transmission customers lodged preliminary challenges to the 2025 formula rate update, and in June 2026, those transmission customers filed formal challenges with the FERC. PacifiCorp will utilize the FERC-established process to resolve outstanding issues related to its 2025 annual update. The matter is pending before the FERC.

2026 PacifiCorp Inter-Jurisdictional Allocation Protocol

In August 2025, 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. The CPUC will consider the 2026 Protocol as part of PacifiCorp's next general rate case filed in California. In December 2025, PacifiCorp filed deferral applications with the UPSC, the OPUC, the WPSC and the IPUC for net impacts of the reallocation of resources required to implement the 2026 Protocol as of January 1, 2026, while approval of the 2026 Protocol is pending in the respective states. In February 2026, PacifiCorp filed motions to suspend the procedural schedules in the respective states to assess the effects of the Washington service area sale described below on the proposed 2026 Protocol that were granted by the four commissions in February and March 2026.

Sale of Washington Service Area and Certain Washington-based Assets

In March and April 2026, PacifiCorp filed applications and supporting testimony with the UPSC, the OPUC, the WPSC, the WUTC, the IPUC and the CPUC for authority to sell PacifiCorp's Washington service area and certain Washington-based generation, transmission and distribution assets, as applicable, to Portland General Electric Company and its affiliate Gem Sub LLC. The WUTC application was filed jointly with the buyer, committing to provide $84 million of rate credits to Washington customers to help offset the incremental costs of a temporary power purchase agreement between PacifiCorp and Gem Sub LLC that will support system reliability and continuity of operations following the close of the transaction and to address the change in rate base associated with the transaction. In the filings, PacifiCorp proposes to assign customers a portion of each state's allocated share of the amount received in excess of the value of the net assets to be sold. PacifiCorp has requested each commission's approval by March 1, 2027. In July 2026, PacifiCorp and Portland General Electric filed for approval from the FERC under certain requirements of the Federal Power Act, requesting an order by December 15, 2026. Refer to Note 3 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q, and to Note 3 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q for additional information regarding the transaction.

MidAmerican Energy

Illinois

In March 2026, MidAmerican Energy filed a request with the ICC seeking an increase in its Illinois retail electric rates based on a future test year. If approved as filed, the request would increase annual revenues by approximately $41 million, or 26.0%. The filing includes recovery of investments related to system reliability, new systems and technologies, and compliance with evolving safety and regulatory standards. MidAmerican Energy has requested that any approved increase be phased in over a two-year period. The filing also proposes a revenue adjustment mechanism intended to reduce revenue volatility associated with weather and usage variability. The outcome and timing of the proceeding are subject to ICC review and approval and could differ materially from MidAmerican Energy's request.

In March 2026, MidAmerican Energy filed a request with the ICC seeking an increase in its Illinois natural gas rates based on a future test year. If approved as filed, the request would increase annual revenues by approximately $9 million, or 12.2%. The filing includes recovery of investments related to system reliability, new systems and technologies, and compliance with evolving safety and regulatory standards. The filing also proposes a revenue adjustment mechanism intended to reduce revenue volatility associated with weather and usage variability. The outcome and timing of the proceeding are subject to ICC review and approval and could differ materially from MidAmerican Energy's request.

Iowa

In July 2026, MidAmerican Energy filed a request with the IUC seeking an increase in its Iowa natural gas delivery rates based on a future test year. If approved as filed, the request would increase annual revenues by approximately $55 million, or 9.7%. The filing includes recovery of investments related to system reliability, new systems and technologies, and compliance with evolving safety and regulatory standards. As allowed by Iowa law, MidAmerican Energy will implement a temporary natural gas delivery rate increase of approximately $44 million, or 7.7% of total annual revenue in July 2026. The filing also proposes a revenue adjustment mechanism intended to reduce revenue volatility associated with weather and usage variability. The outcome and timing of the proceeding are subject to IUC review and approval and could differ materially from MidAmerican Energy's request.

NV Energy (Nevada Power and Sierra Pacific)

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 utility 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 $1.0-$1.5 billion in insurance coverage is a prudent range for the Nevada Utilities based on its wildfire risk profile and that the Nevada Utilities sufficiently supported its initial request for an additional $500 million of excess insurance. 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. In June 2026, a hearing was held to assess the prudency of self-insurance. On July 28, 2026, the PUCN voted to approve a modified Policy. As approved by the Commission, the modified Policy provides $275 million of additional coverage. The modified Policy includes a $25 million deductible and a 10 percent coinsurance requirement, both of which are nonrecoverable expenses. In addition, the order authorizes recovery of $180 million through rates over a ten-year period, requiring the Nevada Utilities to provide $45 million of nonrecoverable contributions to a captive insurance company.

Petition for Authority to Defer Specific Wildfire Insurance Premium Payments

In March 2026, the Nevada Utilities filed a petition requesting PUCN authorization to defer expenses associated with premium payments for a new property-damage-only excess wildfire liability insurance policy. On July 28, 2026, the PUCN voted to grant the petition.

Natural Disaster Protection Plan (NDPP)

In February 2026, the Nevada Utilities filed with the PUCN a joint application for approval of their Joint Natural Disaster Protection Plan for the period 2027-2029. The plan outlines proposed investments and initiatives of approximately $410 million for 2027 through 2029 to mitigate wildfire and other natural disaster risks, strengthen system reliability, and build a more resilient energy future. The plan prioritizes public safety, long-term risk reduction, rapid response and greater resilience for customers and the communities the company serves. The Natural Disaster Protection Plan details the Nevada Utilities' proposals and programs across several key areas to include: risk-based decision-making, situational awareness, operational practices and emergency response, inspections and corrections, vegetation management, system hardening, and community engagement. These efforts are designed to help the Nevada Utilities mitigate wildfire and other natural disaster risks, strengthen system reliability and continue building a more resilient energy future for Nevada. A hearing on the joint application is scheduled for August 2026. In May 2026, the PUCN issued an Amended Notice of Hearing; the hearing is scheduled for September 2026.

Northern Powergrid

Northern Powergrid is currently working on its business plan for the five-year RIIO-ED3 price control, which will become effective April 1, 2028, based on guidance published by Ofgem in May 2026. Northern Powergrid will be required to submit its final business plan in November 2026, ahead of Ofgem's Final Determination scheduled for December 2027.

BHE Pipeline Group

BHE GT&S

In June 2026, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective August 1, 2026. EGTS' current rates were established by a 2022 settlement. EGTS proposed an annual cost-of-service of approximately $1.2 billion, and requested increases in various rates, including general system transportation rates by 43% and general system storage rates by 37%. In July 2026, the FERC issued an order that accepted the August 1, 2026 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until January 1, 2027, subject to refund and the outcome of hearing procedures. This matter is pending.

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 and storage reservation rates. In January 2026, the FERC approved Northern Natural Gas' filing to implement interim rates effective January 1, 2026, subject to refund and the outcome of hearing procedures. In March 2026, a settlement agreement supported by a vast majority of participating parties was filed with the FERC to resolve all pending issues in the rate case; however, certain other parties, none of which hold long-term firm capacity on Northern's system, have contested the settlement agreement. The settlement agreement provides for increased Market Area transportation reservation rates of 30%, increased Field Area transportation reservation rates of 37%, and increased storage reservation rates of 13% from the rates that were in effect in 2025. The settlement also provides for a moratorium on Section 4 and Section 5 rate actions until July 1, 2027. The settlement rates were implemented on an interim basis effective February 1, 2026, and Northern Natural Gas' provision for rate refunds for January 2026 totaled $27 million. In June 2026, the presiding administrative law judge severed the contesting parties from the settlement, certified the settlement to the FERC as uncontested, and recommended that the FERC conclude the partial uncontested settlement is fair, reasonable and in the public interest. In July 2026, a revised procedural schedule to resolve contested issues was adopted and rates applicable to the contesting parties were established. Pursuant to the revised procedural schedule, the hearing must be convened by December 2026, and an initial decision is due in February 2027. Each of the contesting parties has subsequently filed a notice withdrawing their opposition to the settlement.

BHE Transmission

AltaLink

In May 2025, AltaLink filed its 2026-2027 General Tariff Application and 2023-2024 Deferral Accounts Reconciliation Application with the AUC. AltaLink amended its application in July 2025. 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. In September 2025, the AUC approved the negotiated settlement agreement. The approved negotiated settlement marks AltaLink's fourth successful negotiated settlement over the past decade.

The negotiated settlement 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 and the proposal of two deferral accounts. These items were heard in an AUC hearing in November 2025.

In March 2026, the AUC issued its decision with respect to AltaLink's 2026-2027 GTA, which provided directions on the matters excluded from the previously approved negotiated settlement agreement. The AUC approved the 2026-2027 wildfire mitigation plan capital forecast at C$41 million, representing a 39% increase from the 2024-2025 GTA decision. In April 2026, AltaLink filed its compliance filing with total revised revenue requirements of C$904 million and C$939 million for 2026 and 2027, respectively. The total revenue requirement of C$904 million for 2026, pending final AUC approval, will enable AltaLink to continue to achieve revenue requirement at or below the 2018 approved revenue requirement for eight years.

In June 2026, the AUC approved AltaLink's 2026-2027 GTA compliance filing as filed. The AUC will finalize AltaLink's 2026-2027 transmission tariff in due course, following the outcome of the 2025 Extreme Weather Events Self-Insurance Application proceeding which is anticipated in the fourth quarter of 2026.

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, 2025, and new environmental matters occurring in 2026.

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 tribal 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:

•On February 19, 2026, the EPA released its final rule repealing the 2024 amendments to the Mercury and Air Toxics Standards, specifically addressing the residual risk and technology review that informed the amendments. The final rule repeals 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 filterable particulate matter emission standard and the requirement to use continuous emission monitoring systems reduces regulatory impacts for facilities at MidAmerican Energy and PacifiCorp. The repeal of the 2024 amendments reverts the Mercury and Air Toxics Standards to the 2012 requirements of the rule. The final repeal rule has been challenged in the D.C. Circuit by environmental and health groups, 22 states and other parties. Until litigation is completed, impacts on the relevant Registrants cannot be determined.

•On June 8, 2026, the EPA proposed revisions to a Federal Implementation Plan addressing regional haze in Wyoming to remove a requirement that Dave Johnston Unit 3 shut down by December 31, 2027. The action also revises the NOx Best Available Control Technology determination for the unit that incorporates an emissions limit that reflects the installation of NOx controls on that unit in 2010. Until rulemaking is completed, impacts on the relevant Registrants cannot be determined.

Coal Ash Disposal

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

On April 9, 2026, the EPA released a proposal to amend the legacy CCR rule promulgated in 2024. The EPA proposed to revise the rule by exempting CCR dewatering structures; modifying the legacy CCR surface impoundment deferral criteria; eliminating the CCR management unit provisions; establishing new site-specific compliance pathway considerations for permitting groundwater monitoring points of compliance, corrective action cleanup levels, closure performance standards, closure timelines and CCR extraction for beneficial use during post-closure care; revising the definition of beneficial use; proposing a definition of CCR storage pile; and excluding specific beneficial uses from federal CCR regulations. As an alternative to full rescission of the CCR management unit provisions, the EPA also sought comment on several alternative approaches that would modify the definition and applicability of CCR management unit and the rule's associated requirements. The EPA accepted comments on the proposed amendments through June 29, 2026. On June 9, 2026, the EPA also reopened the public comment period for the 2020 proposed rule regarding a federal CCR permit program. That rule would require owners and operators of CCR surface impoundments and landfills to obtain federal CCR permits for units located in a state without an EPA-approved state CCR permit program. The EPA will accept public comments on the federal CCR permit program through July 29, 2026. On July 14, 2026, the EPA solicited public input on an advanced notice of proposed rulemaking as it considers whether a general permit program could be developed to allow facilities to temporarily obtain permit coverage until an individual permit issued by the EPA or an approved state CCR permit program is in effect. The EPA will accept comments on a potential general permit program through October 12, 2026. Until rulemaking is completed and litigation completed, impacts on the relevant Registrants cannot be determined.

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

Federal Permitting Moratoria for Renewable Energy

On January 20, 2025, the Trump Administration released a Presidential Memorandum temporarily placing a halt on offshore wind leasing and on federal permitting for onshore wind facilities. The memorandum calls for a "temporary cessation and immediate review" of federal wind permitting for onshore wind. This directive covers "new or renewed approvals, rights of way, permits, leases, or loans for onshore or offshore wind projects" pending the completion of a comprehensive assessment and review of federal wind leasing and permitting practices. The memorandum does not provide a timeline for the Secretary of the Interior to complete its review. It also does not provide any guidance on the alleged deficiencies in the permitting process that are to be addressed. Between January and August 2025, the U.S. Department of Interior ("DOI') issued a number of orders to implement the Presidential Memorandum and enact a significant federal policy shift concerning renewable energy. Seventeen states, the District of Columbia, and the Alliance for Clean Energy New York challenged the Presidential Memorandum in U.S. District Court for the District of Massachusetts. On December 8, 2025, the court found the memorandum to be arbitrary and capricious and contrary to law and directed that it be vacated in full, meaning the ruling applies nationwide. However, the various directives issued by federal agencies limiting access to federal permits or increasing the regulatory requirements for wind and solar projects do not rely on the Presidential Memorandum, so the district court's order is not expected to directly affect them. On December 23, 2025, eight regional renewable energy trade associations filed suit in Massachusetts district court challenging six actions by federal agencies that have blocked or curtailed permitting for renewable energy projects and have requested a preliminary injunction of these actions. Applicable to the relevant Registrants, the challenged administrative actions include the DOI's policy requiring review and approval by three of the department's most senior officials for each discretionary action related to wind and solar projects; a memorandum from the Army Corps of Engineers requiring consideration of capacity density when reviewing applications for individual permits under Section 404 of the Clean Water Act and Section 10 of the Rivers and Harbors Act; and the U.S. Fish and Wildlife Service's prohibition on wind facilities obtaining permits authorizing the take of eagles under the Bald and Golden Eagle Protection Act. On April 21, 2026, the U.S. District Court for the District of Massachusetts issued a preliminary injunction blocking implementation of five of the six challenged actions, including the DOI's policy requiring three levels of review for wind and solar projects; the memoranda requiring the DOI and the Army Corps of Engineers to use a new capacity density metric when evaluating wind and solar projects on federal lands; and the DOI action restricting wind and solar projects from using the Fish and Wildlife Service's IPAC website for preliminary environmental screening. The court's order provides plaintiffs' members immediate relief from the administrative actions at issue. The U.S. Government filed a notice of appeal of the preliminary injunction June 17, 2026. Until litigation is completed, impacts on the relevant Registrants cannot be determined.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, 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, 2025. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2025. 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.

PacifiCorp and its subsidiaries

Consolidated Financial Section

PART I

Item 1.Financial Statements


Report of Independent Registered Public Accounting Firm						55
Consolidated Balance Sheets						56
Consolidated Statements of Operations						58
Consolidated Statements of Changes in Shareholder's Equity						59
Consolidated Statements of Cash Flows						60
Notes to Consolidated Financial Statements
General						61
New Accounting Pronouncements						62
Dispositions						62
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents						64
Property, Plant and Equipment, Net						64
Finance L eases						65
Recent Financing Transactions						65
Income Taxes						66
Employee Benefit Plans						67
Risk Management and Hedging Activities						67
Fair Value Measurements						69
Commitments and Contingencies						71
Revenue from Contracts with Customers						75

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 June 30, 2026, the related consolidated statements of operations, and changes in shareholders' equity for the three-month and six-month periods ended June 30, 2026 and 2025, and of cash flows for the six-month periods ended June 30, 2026 and 2025, 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, 2025, 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 27, 2026, 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, 2025, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

/s/ Deloitte & Touche LLP

Portland, Oregon

August 7, 2026

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	June 30,		December 31,
	2026		2025
ASSETS
Current assets:
Cash and cash equivalents	$	2,068	$	73
Trade receivables, net	872		1,032
Other receivables, net	159		212
Inventories	964		920


Regulatory assets	345		669
Prepayments	208		148
Assets held for sale (Note 3)	1,919		—
Other current assets	302		138
Total current assets	6,837		3,192

Property, plant and equipment, net	30,337		31,113
Regulatory assets	1,878		1,891
Other assets	2,221		994

Total assets	$	41,273	$	37,190

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	June 30,		December 31,
	2026		2025
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	1,346	$	1,378
Accrued interest	328		260
Accrued property, income and other taxes	143		96

Accrued employee expenses	138		105
Short-term debt	—		1,000
Current portion of long-term debt	—		100
Regulatory liabilities	70		80
Wildfires liabilities (Note 12)	155		734
Liabilities held for sale (Note 3)	246		—
Other current liabilities	523		529
Total current liabilities	2,949		4,282

Senior debt	16,078		13,193
Junior subordinated debt	1,930		841
Regulatory liabilities	2,440		2,577
Deferred income taxes	3,425		3,274
Finance lease liabilities (Note 6)	1,650		393
Wildfires liabilities (Note 12)	417		427
Other long-term liabilities	971		1,056
Total liabilities	29,860		26,043

Commitments and contingencies (Note 12)

Shareholders' equity:

Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding	—		—
Additional paid-in capital	4,479		4,479
Retained earnings	6,944		6,678
Accumulated other comprehensive loss, net	(10)		(10)
Total shareholders' equity	11,413		11,147

Total liabilities and shareholders' equity	$	41,273	$	37,190

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025

Operating revenue	$	1,801	$	1,810	$	3,609	$	3,578

Operating expenses:
Cost of fuel and energy	640		723		1,395		1,441
Operations and maintenance	474		479		937		903

Depreciation and amortization	315		372		625		671
Property and other taxes	63		60		130		119
Total operating expenses	1,492		1,634		3,087		3,134

Operating income	309		176		522		444

Other income (expense):
Interest expense	(270)		(202)		(497)		(389)
Allowance for borrowed funds	22		24		43		46
Allowance for equity funds	27		31		47		58
Interest and dividend income	42		32		69		60
Other, net	12		11		8		11
Total other income (expense)	(167)		(104)		(330)		(214)

Income before income tax expense (benefit)	142		72		192		230
Income tax expense (benefit)	(53)		(33)		(74)		(52)
Net income	$	195	$	105	$	266	$	282

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)

(Amounts in millions)


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

Balance, March 31, 2025	$	1	$	—	$	4,479	$	6,216	$	(9)	$	10,687
Net income	—		—		—		105		—		105
Preferred stock redemption	(1)		—		—		(1)		—		(2)


Balance, June 30, 2025	$	—	$	—	$	4,479	$	6,320	$	(9)	$	10,790

Balance, December 31, 2024	$	2	$	—	$	4,479	$	6,040	$	(9)	$	10,512
Net income	—		—		—		282		—		282
Preferred stock redemption	(2)		—		—		(2)		—		(4)


Balance, June 30, 2025	$	—	$	—	$	4,479	$	6,320	$	(9)	$	10,790

Balance, March 31, 2026	$	—	$	—	$	4,479	$	6,749	$	(10)	$	11,218
Net income	—		—		—		195		—		195



Balance, June 30, 2026	$	—	$	—	$	4,479	$	6,944	$	(10)	$	11,413

Balance, December 31, 2025	$	—	$	—	$	4,479	$	6,678	$	(10)	$	11,147
Net income	—		—		—		266		—		266



Balance, June 30, 2026	$	—	$	—	$	4,479	$	6,944	$	(10)	$	11,413

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Six-Month Periods
	Ended June 30,
	2026		2025
Cash flows from operating activities:
Net income	$	266	$	282
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	625		671
Allowance for equity funds	(47)		(58)
Net power cost deferrals	(176)		(150)
Amortization of net power cost deferrals	429		409
Other changes in regulatory assets and liabilities	(9)		(156)
Deferred income taxes and amortization of investment tax credits	125		(14)
Other, net	2		16
Changes in other operating assets and liabilities:
Trade receivables, other receivables and other assets	121		(58)
Inventories	(79)		(65)
Derivative collateral, net	(12)		6
Prepayments	(69)		73
Accrued property, income and other taxes, net	125		58
Accounts payable and other liabilities	116		106
Wildfires insurance receivable	—		98
Wildfires liability	(589)		(155)
Net cash flows from operating activities	828		1,063

Cash flows from investing activities:
Capital expenditures	(1,443)		(1,406)
Purchases of U.S. Treasury Bills	(245)		—
Other, net	10		7
Net cash flows from investing activities	(1,678)		(1,399)

Cash flows from financing activities:
Proceeds from senior debt	2,881		—
Proceeds from junior subordinated debt	1,088		842
Repayments of senior debt	(100)		—
Net repayments of short-term debt	(1,000)		(240)


Repayments of finance leases	(11)		(2)
Redemption of preferred stock	—		(4)
Other, net	(13)		(2)
Net cash flows from financing activities	2,845		594

Net change in cash and cash equivalents and restricted cash and cash equivalents	1,995		258
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	95		61
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	2,090	$	319

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

PACIFICORP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

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

The accompanying Consolidated Financial Statements and Notes to Consolidated Financial Statements should be read in conjunction with PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2025. The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of June 30, 2026, and for the three- and six-month periods ended June 30, 2026 and 2025. The Consolidated Statements of Comprehensive Income (Loss) have been omitted as net income (loss) materially equals comprehensive income (loss) for the three- and six-month periods ended June 30, 2026 and 2025. The results of operations for the three- and six-month periods ended June 30, 2026, 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, 2025, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in PacifiCorp's accounting policies or its assumptions regarding significant accounting estimates during the six-month period ended June 30, 2026. Refer to Note 12 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." Refer to Note 3 for information regarding assets and liabilities held for sale.

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. Net income, as reported on the Consolidated Statements of Operations, is considered by the CODM in allocating resources and capital. When making decisions about the allocation of resources and capital, the CODM generally considers actual results versus historical results, budgets or forecasts, as well as unique risks and opportunities. The segment expense information regularly provided to the CODM aligns 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.

(2) New Accounting Pronouncements

In November 2024, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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.

In December 2025, the FASB issued ASU No. 2025-10, Government Grants Topic 832, "Accounting for Government Grants Received by Business Entities" which establishes accounting for government grants received by an entity, including guidance for a grant related to an asset and a grant related to income. This guidance also requires, consistent with current disclosure requirements, that an entity provide disclosures including the nature of the government grant received, the accounting policies used to account for the grant, and significant terms and conditions of the grant. This guidance is effective for interim and annual reporting periods beginning after December 15, 2028. Early adoption is permitted and can be applied using either a modified prospective approach, a modified retrospective approach or a retrospective approach. 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 May 2026, the FASB issued ASU No. 2026-02, Environmental Credits and Environmental Credit Obligations Topic 818 which establishes guidance on the recognition, measurement, presentation and disclosure of environmental credits and related regulatory obligations. This guidance provides a framework for accounting for environmental credit assets, including those generated, purchased or received and environmental credit obligations. It also requires entities to assess the intended use of environmental credits, and, in certain cases, evaluate such credits for impairment. ASU 2026-02 introduces enhanced annual disclosure requirements related to environmental credits and associated obligations. The guidance is effective for annual periods beginning after December 15, 2027. Early adoption is permitted and should be applied on a retrospective basis through a cumulative effect adjustment to the opening balance of retained earnings. 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) Dispositions

The assets and liabilities held for sale as presented in Assets held for sale and Liabilities held for sale on the Consolidated Balance Sheets as of June 30, 2026, are as follows:


Assets held for sale:
Trade receivables, net		$	109
Property, plant and equipment, net:
Generation	861
Transmission	322
Distribution	756
Intangible plant and other	66
Accumulated depreciation and amortization	(465)
Construction work-in-progress	45
Property, plant and equipment, net		1,585
Regulatory assets		143
Other assets		82
Total assets held for sale		$	1,919

Liabilities held for sale:
Regulatory liabilities		$	202
Other liabilities		44
Total liabilities held for sale		$	246

(4) 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 environmental remediation funds. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):


	As of
	June 30,		December 31,
	2026		2025

Cash and cash equivalents	$	2,068	$	73
Restricted cash and cash equivalents included in other current assets	19		19
Restricted cash included in other assets	3		3
Total cash and cash equivalents and restricted cash and cash equivalents	$	2,090	$	95

As of June 30, 2026, PacifiCorp held a $245 million six-month U.S. Treasury Bill included in other current assets on the Consolidated Balance Sheets in addition to the cash and cash equivalents and restricted cash and cash equivalents presented above.

(5) Property, Plant and Equipment, Net

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


		As of
		June 30,		December 31,
	Depreciable Life	2026		2025
Utility plant:
Generation	15 - 59 years	$	14,408	$	15,114
Transmission	60 - 90 years	11,508		11,732
Distribution	20 - 75 years	10,941		11,127
Intangible plant and other	2 - 75 years	2,633		2,667
Utility plant in-service		39,490		40,640
Accumulated depreciation and amortization		(12,747)		(12,875)
Utility plant in-service, net		26,743		27,765
Nonregulated, net of accumulated depreciation and amortization	34 - 75 years	18		18
		26,761		27,783
Construction work-in-progress		3,576		3,330
Property, plant and equipment, net		$	30,337	$	31,113

Government Grants

As of June 30, 2026, and December 31, 2025, approximately $67 million and $50 million, respectively, of federal grant funds reduced additions to property, plant and equipment – net on the Consolidated Balance Sheets. During the six-month periods ended June 30, 2026 and 2025, approximately $3 million and $16 million, respectively, of federal grant funds reduced operating expenses on the Consolidated Statements of Operations.

(6) Finance Leases

During the six-month period ended June 30, 2026, facilities associated with previously executed energy storage agreements achieved commercial operation, resulting in additional finance lease liabilities as presented below. There were no material changes to PacifiCorp's operating leases during 2026.

The following table summarizes PacifiCorp's finance leases recorded on the Consolidated Balance Sheets (in millions):


	As of
	June 30,		December 31,
	2026		2025
Right-of-use assets:

Finance leases(1)	$	1,686	$	427


Lease liabilities:

Finance leases(1)	$	1,699	$	432

(1)Includes amounts associated with energy storage facilities for which the associated costs will be subject to recovery as part of regulated net power costs and PacifiCorp's deferred net power cost mechanisms.

PacifiCorp has the following remaining finance lease commitments as of June 30, 2026 (in millions):


	Finance
	PPAs/Energy Storage Agreements		Other

2026	$	71	$	5
2027	142		11
2028	142		10
2029	142		10
2030	142		10
Thereafter	2,233		19
Total undiscounted lease payments	2,872		65
Less - amounts representing interest	(1,226)		(12)
Lease liabilities	$	1,646	$	53

(7) Recent Financing Transactions

Senior Debt

In February 2026, PacifiCorp issued $400 million of 4.25% First Mortgage Bonds due March 2029.

Junior Subordinated Debt

Credit Facilities

In April 2026, PacifiCorp entered into a letter of credit agreement, effective May 18, 2026, under which letters of credit will be made available solely to provide collateral support for surety bonds issued pursuant to a corresponding surety arrangement for supersedeas undertakings to secure the performance and stay enforcement of trial court judgments entered against PacifiCorp relating to the James case, in each case while such judgments remain pending appeal by PacifiCorp in the Oregon Court of Appeals or the Oregon Supreme Court. Refer to Note 12 for information regarding the Oregon Court of Appeals opinion issued in April 2026 associated with the James case. The letter of credit agreement provides for a two-year standby letter of credit facility for PacifiCorp in an aggregate stated amount of up to $2.55 billion. In conjunction with the letter of credit agreement, PacifiCorp entered into a committed surety facility set forth in a term sheet with an initial aggregate capacity of $2.55 billion, not to exceed availability under the letter of credit agreement, and related indemnity agreement under which the surety party is committed to issue surety bonds from time to time for PacifiCorp to secure the supersedeas undertakings described above. The surety facility must be fully secured by letters of credit. If 91 days prior to the applicable termination date of any letter of credit issued under the arrangements described above, any letter of credit obligations remain outstanding, PacifiCorp will be required to provide cash collateral to secure outstanding letter of credit obligations in an amount equal to 103% of such obligations. In April 2026, PacifiCorp received the necessary approvals from the Oregon Public Utility Commission and the Idaho Public Utilities Commission.

(8) Income Taxes

Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return and BHE includes its subsidiaries in certain state income tax returns. 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 pursuant to a tax allocation agreement. As of June 30, 2026, federal income taxes payable to BHE were $27 million and state income taxes receivable from BHE were $16 million. As of December 31, 2025, federal income taxes receivable from BHE were $94 million and state income taxes payable to BHE were $16 million. PacifiCorp received net cash payments for federal and state income taxes from BHE totaling $289 million and $62 million for the six-month periods ended June 30, 2026 and 2025, respectively.

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 (amounts in millions):


	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2026				2025				2026				2025
	Amount		Percent		Amount		Percent		Amount		Percent		Amount		Percent

U.S. federal statutory income tax rate	$	30	21.0	%	$	15	21.0	%	$	40	21.0	%	$	48	21.0	%
State and local income taxes, net of federal income tax	7		4.8		4		5.5		11		5.7		12		5.1
Energy-related tax credits	(76)		(53.6)		(40)		(55.9)		(106)		(55.3)		(87)		(38.0)

Effects of ratemaking(1)	(14)		(9.6)		(12)		(16.4)		(19)		(10.1)		(25)		(10.7)
Effective income tax rate	$	(53)	(37.4)	%	$	(33)	(45.8)	%	$	(74)	(38.7)	%	$	(52)	(22.6)	%

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

Energy-related tax credits relate primarily to production tax credits ("PTC") earned by PacifiCorp's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.

(9) Employee Benefit Plans

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


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025
Pension:

Interest cost	$	8	$	10	$	17	$	19
Expected return on plan assets	(10)		(12)		(21)		(23)

Net amortization	3		2		5		4
Net periodic benefit cost	$	1	$	—	$	1	$	—

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

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in other, net on the Consolidated Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $— million, respectively, during 2026. As of June 30, 2026, $2 million of contributions had been made to the pension plans.

(10) 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 11 for additional information related to the fair value measurements associated with derivative contracts.

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


	Other				Other		Other
	Current		Other		Current		Long-term
	Assets		Assets		Liabilities		Liabilities		Total
As of June 30, 2026
Not designated as hedging contracts(1):
Commodity assets	$	2	$	—	$	3	$	—	$	5
Commodity liabilities	—		—		(89)		(18)		(107)
Total	2		—		(86)		(18)		(102)


Cash collateral receivable	—		—		49		—		49
Total derivatives - net basis	$	2	$	—	$	(37)	$	(18)	$	(53)

As of December 31, 2025
Not designated as hedging contracts(1):
Commodity assets	$	5	$	—	$	4	$	1	$	10
Commodity liabilities	—		—		(119)		(28)		(147)
Total	5		—		(115)		(27)		(137)


Cash collateral receivable	—		—		67		4		71
Total derivatives - net basis	$	5	$	—	$	(48)	$	(23)	$	(66)

(1)PacifiCorp's commodity derivatives are generally included in rates. As of June 30, 2026, a regulatory asset of $102 million was recorded related to the net derivative liability of $102 million. As of December 31, 2025, a regulatory asset of $137 million was recorded related to the net derivative liability of $137 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				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025

Beginning balance	$	111	$	81	$	137	$	97
Changes in fair value recognized in regulatory assets	21		(7)		55		3
Net gains reclassified to operating revenue	—		2		7		10
Net losses reclassified to cost of fuel and energy	(30)		(23)		(97)		(57)
Ending balance	$	102	$	53	$	102	$	53

Derivative Contract Volumes

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


	Unit of	June 30,	December 31,
	Measure	2026	2025

Electricity sales, net	Megawatt hours	(1)	—
Natural gas purchases	Decatherms	119	147

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

The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $106 million and $145 million as of June 30, 2026, and December 31, 2025, respectively, for which PacifiCorp had posted collateral of $49 million and $71 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 June 30, 2026, and December 31, 2025, PacifiCorp would have been required to post $54 million and $69 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.

(11) Fair Value Measurements

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

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

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

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


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of June 30, 2026:
Assets:
Commodity derivatives	$	—	$	5	$	—	$	(3)	$	2
Money market mutual funds	1,820		—		—		—		1,820
Debt securities:
U.S. government obligations	493		—		—		—		493
Investment funds	24		—		—		—		24
	$	2,337	$	5	$	—	$	(3)	$	2,339

Liabilities:
Commodity derivatives	$	—	$	(107)	$	—	$	52	$	(55)

As of December 31, 2025:
Assets:
Commodity derivatives	$	—	$	10	$	—	$	(5)	$	5
Money market mutual funds	84		—		—		—		84
Investment funds	28		—		—		—		28
	$	112	$	10	$	—	$	(5)	$	117

Liabilities:
Commodity derivatives	$	—	$	(147)	$	—	$	76	$	(71)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $49 million and $71 million as of June 30, 2026, and December 31, 2025, respectively.

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. A discounted cash flow valuation method was used to estimate fair value. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. Refer to Note 10 for further discussion regarding PacifiCorp's risk management and hedging activities.

PacifiCorp's investments in money market mutual funds, debt securities 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 following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt (in millions):


	As of June 30, 2026				As of December 31, 2025
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value



Long-term debt	$	18,008	$	16,995	$	14,134	$	13,005

(12) Commitments and Contingencies

Commitments

Energy Storage Contracts

Facilities associated with certain energy storage agreements previously disclosed as commitments in Note 14 of the Notes to Consolidated Financial Statements included in PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2025, achieved commercial operation during the six-month period ended June 30, 2026. Refer to Note 6 for information related to the resulting finance lease obligations associated with these agreements.

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.

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.

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

2020 Wildfires and 2022 McKinney Fire

Complaints and Demands Associated with the Wildfires

The James Case

Following the Phase I liability verdict, 1,760 James class members filed nine separate mass complaints from April 2024 through January 2026 in Multnomah County Circuit Court Oregon, each premised on the Phase I liability verdict and referencing the original James case as the lead case. The James mass complaints make damages-only allegations seeking for each individual class member $5 million of economic damages, $25 million of noneconomic damages and punitive damages equal to 0.25 times the amount of economic and noneconomic damages, as well as doubling of economic damages. Complaints for some of the plaintiffs in the mass complaints have been dismissed, amended or re-filed.

Estimated Losses for and Settlements Associated with the Wildfires

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


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025

Beginning balance	$	577	$	1,422	$	1,161	$	1,536

Payments	(5)		(41)		(589)		(155)
Ending balance	$	572	$	1,381	$	572	$	1,381

As of June 30, 2026 and December 31, 2025, $155 million and $734 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 June 30, 2026, 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 June 30, 2026 and December 31, 2025, was classified as a noncurrent liability captioned Wildfires liabilities on the Consolidated Balance Sheets.

(13) Revenue from Contracts with Customers

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




	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025
Customer Revenue:
Retail:
Residential	$	573	$	600	$	1,240	$	1,272
Commercial	629		603		1,226		1,167
Industrial	350		370		697		714
Other retail	131		138		206		205
Total retail	1,683		1,711		3,369		3,358
Wholesale	31		15		52		28
Transmission	34		34		69		82
Other Customer Revenue	43		35		85		62
Total Customer Revenue	1,791		1,795		3,575		3,530
Other revenue	10		15		34		48
Total operating revenue	$	1,801	$	1,810	$	3,609	$	3,578

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

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

Results of Operations for the Second Quarter and First Six Months of 2026 and 2025

Overview

Net income for the second quarter of 2026 was $195 million, an increase of $90 million, compared to 2025. The increase in net income was primarily due to higher utility margin, lower depreciation and amortization expense, higher income tax benefit and slightly lower operations and maintenance expense, partially offset by higher net interest expense, higher property taxes and lower allowances for borrowed and equity funds used during construction. Utility margin increased primarily due to higher net power costs deferrals, lower thermal fuel expense and higher wholesale sales, partially offset by lower retail revenues and higher purchased electricity expense. Retail customer volumes increased 2.7%, primarily due to increases in customer usage and in the average number of customers, partially offset by unfavorable impacts of weather. Energy generated volumes decreased 729 gigawatt-hours, or 7%, for the second quarter of 2026 compared to 2025 primarily due to lower coal-fueled generation and lower hydro-powered generation, partially offset by higher wind-powered generation and natural-gas fueled generation. Wholesale electricity sales volumes increased 285 gigawatt-hours, or 43%, and energy purchased volumes increased 1,008 gigawatt-hours, or 20%.

Net income for the first six months of 2026 was $266 million, a decrease of $16 million, compared to 2025. The decrease in net income was primarily due to higher net interest expense, higher operations and maintenance expense, lower allowance for borrowed and equity funds used during construction, and higher property taxes, partially offset by lower depreciation and amortization expense, higher utility margin and higher income tax benefit. Utility margin increased primarily due to lower thermal fuel expense, higher retail revenues and higher net power costs deferrals, partially offset by higher purchased electricity expense. Retail customer volumes increased 1%, primarily due to an increase in customer usage and an increase in the average number of customers, partially offset by unfavorable impacts of weather. Energy generated volumes decreased 1,902 gigawatt-hours, or 8%, for the first six months of 2026 compared to 2025 primarily due to lower coal-fueled generation and lower hydro-powered generation, partially offset by higher wind-powered generation and natural-gas fueled generation. Wholesale electricity sales volumes increased 304 gigawatt-hours, or 18%, and energy purchased volumes increased 1,848 gigawatt-hours, or 20%.

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.

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


	Second Quarter								First Six Months
	2026		2025		Change				2026		2025		Change
Utility margin:
Operating revenue	$	1,801	$	1,810	$	(9)	—	%	$	3,609	$	3,578	$	31	1	%
Cost of fuel and energy	640		723		(83)		(11)		1,395		1,441		(46)		(3)
Utility margin	1,161		1,087		74		7		2,214		2,137		77		4
Operations and maintenance	474		479		(5)		(1)		937		903		34		4

Depreciation and amortization	315		372		(57)		(15)		625		671		(46)		(7)
Property and other taxes	63		60		3		5		130		119		11		9
Operating income	$	309	$	176	$	133	76	%	$	522	$	444	$	78	18	%

Utility Margin

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


	Second Quarter								First Six Months
	2026		2025		Change				2026		2025		Change
Utility margin (in millions):
Operating revenue	$	1,801	$	1,810	$	(9)	—	%	$	3,609	$	3,578	$	31	1	%
Cost of fuel and energy	640		723		(83)		(11)		1,395		1,441		(46)		(3)
Utility margin	$	1,161	$	1,087	$	74	7	%	$	2,214	$	2,137	$	77	4	%

Sales (GWhs):
Residential	3,940		3,987		(47)		(1)	%	8,545		8,904		(359)		(4)	%
Commercial(1)	5,870		5,366		504		9		11,557		10,895		662		6
Industrial(1)	4,120		4,221		(101)		(2)		8,236		8,348		(112)		(1)
Other(1)	641		610		31		5		687		660		27		4
Total retail	14,571		14,184		387		3		29,025		28,807		218		1
Wholesale	942		657		285		43		1,992		1,688		304		18
Total sales	15,513		14,841		672		5	%	31,017		30,495		522		2	%


Average number of retail customers (in thousands)	2,162		2,133		29		1	%	2,159		2,130		29		1	%

Average revenue per MWh:
Retail	$	115.81	$	120.80	$	(4.99)	(4)	%	$	116.41	$	116.68	$	(0.27)	—	%
Wholesale	$	37.84	$	35.61	$	2.23	6	%	$	36.73	$	40.18	$	(3.45)	(9)	%

Heating degree days	1,188		1,193		(5)		—	%	5,180		5,808		(628)		(11)	%
Cooling degree days	472		557		(85)		(15)	%	478		558		(80)		(14)	%


Sources of energy (GWhs)(1):
Coal	3,844		5,166		(1,322)		(26)	%	8,010		11,134		(3,124)		(28)	%
Natural gas	3,498		3,128		370		12		7,223		6,966		257		4
Wind(2)	2,194		1,697		497		29		5,256		3,997		1,259		31
Hydroelectric and other(2)	527		801		(274)		(34)		1,386		1,680		(294)		(18)
Total energy generated	10,063		10,792		(729)		(7)		21,875		23,777		(1,902)		(8)
Energy purchased	6,177		5,169		1,008		20		11,036		9,188		1,848		20
Total	16,240		15,961		279		2	%	32,911		32,965		(54)		—	%

Average cost of energy per MWh:
Energy generated(3)	$	21.99	$	23.38	$	(1.39)	(6)	%	$	23.23	$	24.81	$	(1.58)	(6)	%
Energy purchased	$	45.24	$	50.77	$	(5.53)	(11)	%	$	48.12	$	54.62	$	(6.50)	(12)	%

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

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

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

Quarter Ended June 30, 2026, compared to Quarter Ended June 30, 2025

Utility margin increased $74 million for the second quarter of 2026 compared to 2025 primarily due to:

•$80 million of higher net power cost deferrals in accordance with established adjustment mechanisms driven by higher current quarter deferrals and lower amortization of prior deferrals;

•$24 million of lower coal-fueled generation costs from lower volumes, partially offset by higher prices;

•$12 million increase in wholesale revenue due to higher volumes and average market prices; and

•$7 million of lower natural gas-fueled generation costs from lower prices, partially offset by higher volumes.

The increases above were partially offset by:

•$26 million decrease in retail revenue due to lower average prices, partially offset by higher volumes. Retail prices decreased primarily due to $87 million of prior year utilization of certain existing regulatory liabilities due to the buy-down of certain plant balances pursuant to the Utah general rate case order (fully offset in depreciation and amortization expense), partially offset by favorable product mix. Retail customer volumes increased $47 million, or 2.7%, primarily due to favorable Utah and Oregon commercial customer usage, primarily due to data centers, increase in average number of customers in Utah, partially offset by unfavorable weather-related impacts on Utah residential and commercial customers, unfavorable Utah industrial customer usage and unfavorable residential customer usage across the service territory, except in Utah; and

•$17 million of higher purchased electricity costs from higher volumes, partially offset by lower average market prices.

Operations and maintenance decreased $5 million, or 1%, for the second quarter of 2026 compared to 2025 primarily due to:

•$18 million of lower general plant and maintenance costs;

•$15 million of plant 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 order;

•$6 million of lower legal fees; and

•$6 million of lower expense due to lower amortization associated with the Utah electric vehicle infrastructure program (offset in retail revenue).

The decreases above were partially offset by:

•$26 million of higher costs associated with injuries and damages and related settlements, excluding the Wildfires;

•$5 million of higher vegetation management and wildfire mitigation costs, primarily from higher gross costs and higher amortization of prior year deferrals;

•$5 million of higher demand side management amortization driven by increased spend (offset in retail revenue); and

•$4 million increase due to lower capitalized labor costs.

Depreciation and amortization decreased $57 million, or 15%, for the second quarter of 2026 compared to 2025, primarily due to the prior year buy-down of certain plant balances pursuant to the Utah general rate case order (fully offset in retail revenue), partially offset by higher average in-service plant, the change in the annual allocation adjustment for Oregon incremental depreciation of coal plants and higher depreciation associated with energy storage agreements accounted for as finance leases.

Property and other taxes increased $3 million, or 5%, for the second quarter of 2026 compared to 2025, primarily due to higher property taxes in Oregon.

Interest expense increased $68 million, or 34%, for the second quarter of 2026 compared to 2025, primarily due to higher average long-term debt balances due to the issuance of $850 million and $1.1 billion of junior subordinated notes in March 2025 and February 2026, respectively, the issuance of $400 million and $2.5 billion of first mortgage bonds in February 2026 and March 2026, respectively, and higher interest expense associated with energy storage agreements accounted for as finance leases.

Allowance for borrowed and equity funds decreased $6 million, or 11%, for the second quarter of 2026 compared to 2025, primarily due to lower qualified construction work-in-progress balances, partially offset by higher rates.

Interest and dividend income increased $10 million, or 31%, for the second quarter of 2026 compared to 2025, primarily due to higher investment income from higher cash investment balances.

Income tax benefit increased $20 million, or 61%, for the second quarter of 2026 compared to 2025. The effective tax rate was (37)% and (46)% for the three-month periods ended June 30, 2026 and 2025, respectively. The $20 million increase was primarily due to higher PTCs from PacifiCorp's wind-powered generating facilities, partially offset by higher pre-tax income.

First Six Months of 2026 compared to First Six Months of 2025

Utility margin increased $77 million for the first six months of 2026 compared to 2025 primarily due to:

•$63 million of lower coal-fueled generation costs due to lower volumes, partially offset by higher prices;

•$20 million of lower natural gas-fueled generation costs from lower prices, partially offset by higher volumes;

•$18 million increase in retail revenue due to higher average retail volumes and slightly higher prices. Retail prices increased primarily due to favorable tariff changes and product mix, partially offset by $87 million of prior year utilization of certain existing regulatory liabilities due to the buy-down of certain plant balances pursuant to the Utah general rate case order (fully offset in depreciation and amortization expense). Retail customer volumes increased 0.8%, primarily due to favorable Oregon, Utah and Washington commercial customer usage, mainly due to data centers, increase in the average number of commercial and residential customers across the service territory, mainly in Utah and Oregon, favorable irrigation customer usage across the eastern service territory, partially offset by unfavorable weather-related impacts on residential and commercial customers, mainly in Utah and Oregon, unfavorable residential customer usage across the territory and unfavorable Utah, Washington and Idaho industrial customer usage;

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

•$5 million of higher wholesale revenue primarily due to higher volumes, partially offset by lower average market prices.

The increases above were partially offset by:

•$29 million of higher purchased electricity costs from higher volumes, partially offset by lower average market prices.

Operations and maintenance increased $34 million, or 4%, for the first six months of 2026 compared to 2025 primarily due to:

•$26 million of higher costs associated with injuries and damages and related settlements, excluding the Wildfires;

•$21 million of higher vegetation management and wildfire mitigation costs, primarily from higher amortization of prior year deferrals, higher gross costs and lower current year cost deferrals;

•$13 million due to lower federal grant reimbursements;

•$12 million of higher demand side management amortization driven by increased spend (offset in retail revenue); and

•$6 million increase due to lower capitalized labor costs.

The increases above were partially offset by:

•$15 million of plant 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 order;

•$14 million of lower general plant and maintenance costs;

•$9 million of lower insurance expense due to lower liability insurance premiums and lower amortization of prior deferrals; and

•$8 million of lower expense primarily due to lower amortization associated with the Utah electric vehicle infrastructure program (offset in retail revenue).

Depreciation and amortization decreased $46 million, or 7%, for the first six months of 2026 compared to 2025 primarily due to the prior year buy-down of certain plant balances pursuant to the Utah general rate case order (fully offset in retail revenue), partially offset by higher average in-service plant, the change in the annual allocation adjustment for Oregon incremental depreciation of coal plants in the prior year and higher depreciation associated with energy storage agreements accounted for as finance leases.

Property and other taxes increased $11 million, or 9%, for the first six months of 2026 compared to 2025, primarily due to higher property taxes in Oregon.

Interest expense increased $108 million, or 28%, for the first six months of 2026 compared to 2025 primarily due to higher average long-term debt balances due to the issuance of $850 million and $1.1 billion of junior subordinated notes in March 2025 and February 2026, respectively, the issuance of $400 million and $2.5 billion of first mortgage bonds in February 2026 and March 2026, respectively, and higher interest expense associated with energy storage agreements accounted for as finance leases.

Allowance for borrowed and equity funds decreased $14 million, or 13%, for the first six months of 2026 compared to 2025 primarily due to lower qualified construction work-in-progress balances, partially offset by higher rates.

Interest and dividend income increased $9 million, or 15%, for the first six months of 2026 compared to 2025 primarily due to higher investment income from higher cash investment balances.

Income tax benefit increased $22 million, or 42%, for the first six months of 2026 compared to 2025 and the effective tax rate was (39)% for 2026 and (23)% for 2025. The $22 million increase is primarily due to higher recognized PTCs from PacifiCorp's wind-powered generating facilities and lower pre-tax income.

Liquidity and Capital Resources

Overview

PacifiCorp's liquidity has been impacted by the Wildfires, resulting in increased debt and additional financing activities 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 and to improve its capital structure.

As of June 30, 2026, PacifiCorp's total net liquidity was as follows (in millions):


Cash and cash equivalents(1)	$	2,068

Credit facility, maturing 2029	3,000
Less:
Short-term debt	—

Net credit facility	3,000

Total net liquidity	$	5,068

(1) Excludes a $245 million U.S. Treasury Bill included in other current assets on the Consolidated Balance Sheets.

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 six-month periods ended June 30, 2026 and 2025 were $828 million and $1,063 million, respectively. The decrease is primarily due to higher cash paid for wildfire settlements, lower insurance reimbursements related to wildfires, higher operating expenses and higher wholesale purchases, partially offset by higher collections from retail customers and lower cash paid for income taxes.

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 selected and assumptions made for each payment date.

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2026 and 2025 were $(1,678) million and $(1,399) million, respectively. The change is primarily due to purchase of a $245 million six-month U.S Treasury Bill and an increase in capital expenditures of $37 million. Refer to "Future Uses of Cash" for discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2026, were $2.8 billion. Sources of cash consisted of net proceeds from the issuance of senior secured debt of $2.9 billion and junior subordinated notes of $1.1 billion. Uses of cash consisted primarily of $1.0 billion for the net repayment of short-term debt, $100 million for the repayment of long-term debt and $11 million for the repayment of financing leases.

For a discussion of recent financing transactions, refer to Note 7 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Net cash flows from financing activities for the six-month period ended June 30, 2025, were $594 million. Sources of cash consisted of net proceeds from the issuance of junior subordinated debt of $842 million. Uses of cash consisted primarily of $240 million for the repayment of short-term debt.

Debt Restrictions

During the first quarter of 2026, certain state regulatory orders that authorized BHE's acquisition of PacifiCorp were modified for a limited term to indirectly limit PacifiCorp's capital structure by requiring the consolidated equity of PPW Holdings LLC as a percentage of total consolidated PPW Holdings LLC capitalization, excluding short-term debt and current maturities of long-term debt, to be no less than 40.00% for the Washington and Wyoming commitments and no less than 35.00% for the Oregon, Idaho and California commitments. The modifications will be in place for three years with options to extend. As of June 30, 2026, consolidated PPW Holdings LLC equity exceeded these thresholds.

Short-term Debt

Regulatory authorities limit PacifiCorp to $3.0 billion of short-term debt. As of June 30, 2026, PacifiCorp had no short-term debt outstanding.

Long-term Debt Authorizations

PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $150 million 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.

Credit Facilities and Letters of Credit

In April 2026, PacifiCorp entered into a $2.55 billion letter of credit agreement, effective May 18, 2026, under which letters of credit will be made available solely to provide collateral support for surety bonds issued pursuant to a corresponding surety arrangement for supersedeas undertakings to secure the performance and stay enforcement of trial court judgments entered against PacifiCorp relating to the James case. Refer to Note 7 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding this arrangement.

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

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

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


	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2025		2026		2026

Electric transmission	$	292	$	331	$	887
Electric distribution	417		352		809



Wildfire prevention	365		281		490
Wind generation	86		14		38
Other	246		465		664
Total	$	1,406	$	1,443	$	2,888

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

•Electric transmission includes both growth projects and operating expenditures. Transmission growth primarily reflects costs associated with major transmission projects totaling $180 million and $91 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for major transmission projects that are expected to be placed in‑service through 2032 totals $250 million for the remainder of 2026.

•Electric distribution includes both growth projects and operating expenditures. Growth expenditures include spending on new customer connections totaling $185 million and $197 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for new customer connections totals $275 million for the remainder of 2026. The remaining investments primarily relate to expenditures for distribution operations.

•Wildfire prevention includes operating expenditures totaling $281 million and $365 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for wildfire prevention totals $209 million for the remainder of 2026.

•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $42 million and $73 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned information technology spending totals $65 million for the remainder of 2026. 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. In December 2025, the IPUC acknowledged the 2025 IRP. In March 2026, PacifiCorp filed its 2025 IRP Update in all states. In June 2026, the UPSC acknowledged the 2025 IRP.

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.

Material Cash Requirements

As of June 30, 2026, 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, 2025, other than those disclosed in Notes 6, 7 and 12 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Regulatory Matters

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

Environmental Laws and Regulations

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

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

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 June 30, 2026, 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 June 30, 2026, PacifiCorp would have been required to post $172 million 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. Refer to Note 10 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.

As described in Note 12 to the Consolidated Financial Statements in Item 1 of this Form 10-Q, PacifiCorp had posted surety bonds totaling $719 million as of June 30, 2026, to stay payment of damages in the James case pending appeals. A limited number of the surety bond agreements include contingent features associated with PacifiCorp's financial condition. If all financial condition-related contingent features associated with the surety bonds had been triggered as of June 30, 2026, PacifiCorp would have been required to post $135 million of cash collateral.

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, 2025. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2025. Refer to Note 12 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.

MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company

Consolidated Financial Section

PART I

Item 1.Financial Statements


Report of Independent Registered Public Accounting Firm						88
Balance Sheets						89
Statements of Operations						91
Statements of Changes in Shareholder's Equity						92
Statements of Cash Flows						93
Notes to Consolidated Financial Statements
General						94
New Accounting Pronouncements						94
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents						95
Property, Plant and Equipment, Net						95
Recent Financing Transactions						95
Income Taxes						96
Employee Benefit Plans						96

Fair Value Measurements						97
Commitments and Contingencies						99
Revenue from Contracts with Customers						100
Shareholder's Equity						100
Segment Information						101

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

MidAmerican Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of June 30, 2026, the related statements of operations, and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2026 and 2025, and of cash flows for the six-month periods ended June 30, 2026 and 2025, 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, 2025, 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 27, 2026, 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, 2025, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

Basis for Review Results

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

/s/ Deloitte & Touche LLP

Des Moines, Iowa

August 7, 2026

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	June 30,		December 31,
	2026		2025
ASSETS
Current assets:
Cash and cash equivalents	$	678	$	670
Trade receivables, net	546		453
Income tax receivable	—		82
Inventories	341		334
Prepayments	162		119
Other current assets	72		63
Total current assets	1,799		1,721

Property, plant and equipment, net	24,360		24,056
Regulatory assets	293		304
Investments and restricted investments	1,344		1,274
Other assets	287		288

Total assets	$	28,083	$	27,643

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

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	June 30,		December 31,
	2026		2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	388	$	505
Accrued interest	119		120
Accrued property, income and other taxes	240		198

Current portion of long-term debt	379		4
Other current liabilities	111		96
Total current liabilities	1,237		923

Long-term debt	8,829		9,203
Regulatory liabilities	1,345		1,323
Deferred income taxes	3,810		3,760
Asset retirement obligations	889		870
Other long-term liabilities	920		822
Total liabilities	17,030		16,901

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	10,492		10,181

Total shareholder's equity	11,053		10,742

Total liabilities and shareholder's equity	$	28,083	$	27,643

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

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025
Operating revenue:
Regulated electric	$	760	$	743	$	1,507	$	1,410
Regulated natural gas and other	112		117		505		464
Total operating revenue	872		860		2,012		1,874

Operating expenses:
Cost of fuel and energy	146		153		340		277
Cost of natural gas purchased for resale and other	50		58		340		303
Operations and maintenance	231		235		451		462
Depreciation and amortization	282		255		559		562
Property and other taxes	42		44		90		88
Total operating expenses	751		745		1,780		1,692

Operating income	121		115		232		182

Other income (expense):
Interest expense	(106)		(100)		(211)		(201)
Allowance for borrowed funds	7		8		13		15
Allowance for equity funds	19		21		36		39
Other, net	29		23		32		28
Total other income (expense)	(51)		(48)		(130)		(119)

Income before income tax expense (benefit)	70		67		102		63
Income tax expense (benefit)	(193)		(178)		(409)		(414)

Net income	$	263	$	245	$	511	$	477

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

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions)


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

Balance, March 31, 2025	$	—	$	561	$	9,851	$	10,412
Net income	—		—		245		245

Other equity transactions	—		—		1		1
Balance, June 30, 2025	$	—	$	561	$	10,097	$	10,658

Balance, December 31, 2024	$	—	$	561	$	9,620	$	10,181
Net income	—		—		477		477


Balance, June 30, 2025	$	—	$	561	$	10,097	$	10,658

Balance, March 31, 2026	$	—	$	561	$	10,429	$	10,990
Net income	—		—		263		263
Common stock dividend	—		—		(200)		(200)

Balance, June 30, 2026	$	—	$	561	$	10,492	$	11,053

Balance, December 31, 2025	$	—	$	561	$	10,181	$	10,742
Net income	—		—		511		511
Common stock dividend	—		—		(200)		(200)

Balance, June 30, 2026	$	—	$	561	$	10,492	$	11,053

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

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Six-Month Periods
	Ended June 30,
	2026		2025
Cash flows from operating activities:
Net income	$	511	$	477
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	559		562
Amortization of utility plant to other operating expenses	20		17
Allowance for equity funds	(36)		(39)
Deferred income taxes and investment tax credits, net	35		(4)

Other, net	(2)		58
Changes in other operating assets and liabilities:
Trade receivables and other assets	(125)		(143)
Inventories	(7)		60


Accrued property, income and other taxes, net	121		71
Accounts payable and other liabilities	(90)		58
Net cash flows from operating activities	986		1,117

Cash flows from investing activities:
Capital expenditures	(888)		(740)
Purchases of marketable securities	(268)		(225)
Proceeds from sales of marketable securities	304		225
Other, net	(29)		5
Net cash flows from investing activities	(881)		(735)

Cash flows from financing activities:
Common stock dividends	(200)		—

Repayments of long-term debt	(2)		(15)

Other, net	102		(1)
Net cash flows from financing activities	(100)		(16)

Net change in cash and cash equivalents and restricted cash and cash equivalents	5		366
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	676		555
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	681	$	921

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

MIDAMERICAN ENERGY COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

(1) General

MidAmerican Energy Company ("MidAmerican Energy") is a public utility with electric and natural gas operations and is the principal subsidiary of MHC Inc. ("MHC"). MHC is a holding company that conducts no business other than the ownership of its subsidiaries. MHC's nonregulated subsidiary is Midwest Capital Group, Inc. MHC is the direct wholly owned subsidiary of MidAmerican Funding, LLC ("MidAmerican Funding"), which is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company 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 accompanying Financial Statements and Notes to Financial Statements should be read in conjunction with MidAmerican Energy's Annual Report on Form 10-K for the year ended December 31, 2025. The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of June 30, 2026, and for the three- and six-month periods ended June 30, 2026 and 2025. The results of operations for the three- and six-month periods ended June 30, 2026, 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, 2025, describes the most significant accounting policies used in the preparation of the unaudited Financial Statements. There have been no significant changes in MidAmerican Energy's accounting policies or its assumptions regarding significant accounting estimates during the six-month period ended June 30, 2026.

(2) New Accounting Pronouncements

In November 2024, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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.

In May 2026, the FASB issued ASU No. 2026-02, Environmental Credits and Environmental Credit Obligations Topic 818 which establishes guidance on the recognition, measurement, presentation and disclosure of environmental credits and related regulatory obligations. This guidance provides a framework for accounting for environmental credit assets, including those generated, purchased or received and environmental credit obligations. It also requires entities to assess the intended use of environmental credits, and, in certain cases, evaluate such credits for impairment. ASU 2026-02 introduces enhanced annual disclosure requirements related to environmental credits and associated obligations. The guidance is effective for annual periods beginning after December 15, 2027. Early adoption is permitted and should be applied on a retrospective basis through a cumulative effect adjustment to the opening balance of retained earnings. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to Financial Statements.

(3) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

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


	As of
	June 30,		December 31,
	2026		2025

Cash and cash equivalents	$	678	$	670
Restricted cash and cash equivalents in other current assets	3		6
Total cash and cash equivalents and restricted cash and cash equivalents	$	681	$	676

(4) Property, Plant and Equipment, Net

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


		As of
		June 30,		December 31,
	Depreciable Life	2026		2025
Utility plant:
Generation	20-62 years	$	18,255	$	18,804
Transmission	55-80 years	3,358		3,297
Electric distribution	15-80 years	6,472		6,326
Natural gas distribution	30-75 years	2,627		2,600
Utility plant in-service		30,712		31,027
Accumulated depreciation and amortization		(8,220)		(8,304)
Utility plant in-service, net		22,492		22,723



Nonregulated, net of accumulated depreciation and amortization	20-50 years	10		10
		22,502		22,733
Construction work-in-progress		1,858		1,323
Property, plant and equipment, net		$	24,360	$	24,056

Under a revenue sharing arrangement in Iowa, MidAmerican Energy accrues throughout the year a regulatory liability based on the extent to which its anticipated annual equity return exceeds specified thresholds, with an equal amount recorded in depreciation and amortization expense. The annual regulatory liability accrual reduces utility plant upon final determination of the amount. For the six-month periods ended June 30, 2026 and 2025, $32 million and $74 million, respectively, is reflected in depreciation and amortization expense on the Statements of Operations.

(5) Recent Financing Transactions

Credit Facilities

(6) Income Taxes

Berkshire Hathaway includes BHE and subsidiaries in its U.S. federal income tax return and BHE includes its subsidiaries in certain 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 pursuant to a tax allocation agreement. For current federal and state income taxes, MidAmerican Energy had a net payable to BHE of $37 million and a net receivable from BHE of $79 million as of June 30, 2026 and December 31, 2025, respectively. MidAmerican Energy received net cash payments for income tax from BHE totaling $557 million and $472 million for the six-month periods ended June 30, 2026 and 2025, respectively.

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 (amounts in millions):


	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2026				2025				2026				2025
	Amount		Percent		Amount		Percent		Amount		Percent		Amount		Percent

U.S. federal statutory income tax rate	$	14	21.0	%	$	14	21.0	%	$	21	21.0	%	$	13	21.0	%
State income tax, net of federal income tax	(1)		(2.9)		(1)		(1.5)		(2)		(2.0)		(1)		(1.6)
Energy-related tax credits	(205)		(292.9)		(191)		(285.1)		(427)		(418.6)		(427)		(677.8)


Other adjustments:
Effects of ratemaking	(1)		(1.4)		—		—		(1)		(1.0)		1		1.6

Effective income tax rate	$	(193)	(276.2)	%	$	(178)	(265.6)	%	$	(409)	(400.6)	%	$	(414)	(656.8)	%

Energy-related 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.

(7) Employee Benefit Plans

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

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


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025
Pension:
Service cost	$	2	$	2	$	4	$	4
Interest cost	8		8		15		16
Expected return on plan assets	(8)		(8)		(16)		(16)
Settlement	—		—		—		—
Net amortization	—		—		—		—
Net periodic benefit cost	$	2	$	2	$	3	$	4

Other postretirement:
Service cost	$	1	$	1	$	2	$	2
Interest cost	3		3		6		6
Expected return on plan assets	(5)		(4)		(10)		(9)
Net amortization	(1)		(1)		(1)		(1)
Net periodic benefit credit	$	(2)	$	(1)	$	(3)	$	(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 2026 are expected to be $7 million and $1 million, respectively. As of June 30, 2026, $4 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 3 — Unobservable inputs reflect MidAmerican Energy's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. MidAmerican Energy develops these inputs based on the best information available, including its own data.

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


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of June 30, 2026:
Assets:
Commodity derivatives	$	—	$	5	$	3	$	(3)	$	5
Money market mutual funds	680		—		—		—		680
Debt securities:
U.S. government obligations	303		—		—		—		303

Corporate obligations	—		127		—		—		127
Municipal obligations	—		1		—		—		1

Equity securities:
U.S. companies	560		—		—		—		560
International companies	7		—		—		—		7
Investment funds	15		—		—		—		15
	$	1,565	$	133	$	3	$	(3)	$	1,698

Liabilities:
Commodity derivatives	$	—	$	(15)	$	(5)	$	5	$	(15)


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2025:
Assets:
Commodity derivatives	$	—	$	3	$	1	$	(2)	$	2
Money market mutual funds	622		—		—		—		622
Debt securities:
U.S. government obligations	284		—		—		—		284

Corporate obligations	—		133		—		—		133
Municipal obligations	—		2		—		—		2

Equity securities:
U.S. companies	548		—		—		—		548
International companies	9		—		—		—		9
Investment funds	20		—		—		—		20
	$	1,483	$	138	$	1	$	(2)	$	1,620

Liabilities:
Commodity derivatives	$	—	$	(18)	$	(3)	$	7	$	(14)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $2 million and $5 million as of June 30, 2026, and December 31, 2025, respectively.

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

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


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025

Beginning balance	$	(1)	$	1	$	(2)	$	(2)
Changes in fair value recognized in net regulatory assets	(3)		(1)		(4)		—
Settlements	2		—		4		2
Ending balance	$	(2)	$	—	$	(2)	$	—

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


	As of June 30, 2026				As of December 31, 2025
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	9,208	$	8,296	$	9,207	$	8,416

(9) Commitments and Contingencies

Commitments

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

Construction Commitments

Environmental Laws and Regulations

Legal Matters

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

(10) Revenue from Contracts with Customers

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


	For the Three-Month Period Ended June 30, 2026								For the Six-Month Period Ended June 30, 2026
	Electric		Natural Gas		Other		Total		Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential	$	183	$	65	$	—	$	248	$	364	$	282	$	—	$	646
Commercial	87		20		—		107		169		108		—		277
Industrial	358		4		—		362		651		13		—		664
Natural gas transportation services	—		12		—		12		—		28		—		28
Other retail	41		—		—		41		74		2		—		76
Total retail	669		101		—		770		1,258		433		—		1,691
Wholesale	61		10		—		71		189		68		—		257
Multi-value transmission projects	13		—		—		13		26		—		—		26
Other Customer Revenue	—		—		1		1		—		—		4		4
Total Customer Revenue	743		111		1		855		1,473		501		4		1,978
Other revenue	17		—		—		17		34		—		—		34
Total operating revenue	$	760	$	111	$	1	$	872	$	1,507	$	501	$	4	$	2,012


	For the Three-Month Period Ended June 30, 2025								For the Six-Month Period Ended June 30, 2025
	Electric		Natural Gas		Other		Total		Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential	$	177	$	67	$	—	$	244	$	358	$	269	$	—	$	627
Commercial	89		22		—		111		169		102		—		271
Industrial	325		5		—		330		576		14		—		590
Natural gas transportation services	—		11		—		11		—		27		—		27
Other retail	43		—		—		43		76		2		—		78
Total retail	634		105		—		739		1,179		414		—		1,593
Wholesale	77		11		—		88		157		47		—		204
Multi-value transmission projects	13		—		—		13		27		—		—		27
Other Customer Revenue	—		—		1		1		—		—		3		3
Total Customer Revenue	724		116		1		841		1,363		461		3		1,827
Other revenue	19		—		—		19		47		—		—		47
Total operating revenue	$	743	$	116	$	1	$	860	$	1,410	$	461	$	3	$	1,874

(11) Shareholder's Equity

In June 2026, MidAmerican Energy paid $200 million in a cash dividend to its parent company, MHC.

100

(12) 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. When making decisions about the allocation of resources and capital to each reportable segment, the CODM generally considers actual results versus historical results, budgets or forecasts, as well as unique risks and opportunities.

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 June 30, 2026
	Electric		Natural Gas		Other(1)		Total

Operating revenue	$	760	$	111	$	1	$	872
Cost of sales	146		50		—		196

Operations and maintenance	185		46		—		231
Depreciation and amortization	264		18		—		282
Property and other taxes	38		4		—		42
Operating income (loss)	127		(7)		1		121
Interest expense	(98)		(8)		—		(106)
Interest and dividend income	6		—		—		6
Income tax expense (benefit)	(190)		(3)		—		(193)
Other segment items(2)	42		8		(1)		49
Net income (loss)	$	267	$	(4)	$	—	$	263

Capital expenditures	$	441	$	29	$	—	$	470


	For the Six-Month Period Ended June 30, 2026
	Electric		Natural Gas		Other(1)		Total

Operating revenue	$	1,507	$	501	$	4	$	2,012
Cost of sales	340		340		—		680

Operations and maintenance	366		85		—		451
Depreciation and amortization	523		36		—		559
Property and other taxes	81		9		—		90
Operating income	197		31		4		232
Interest expense	(194)		(17)		—		(211)
Interest and dividend income	11		1		—		12
Income tax expense (benefit)	(414)		4		1		(409)
Other segment items(2)	65		5		(1)		69
Net income	$	493	$	16	$	2	$	511

Capital expenditures	$	835	$	53	$	—	$	888

101


	For the Three-Month Period Ended June 30, 2025
	Electric		Natural Gas		Other(1)		Total

Operating revenue	$	743	$	116	$	1	$	860
Cost of sales	153		57		1		211

Operations and maintenance	201		34		—		235
Depreciation and amortization	238		17		—		255
Property and other taxes	41		3		—		44
Operating income	110		5		—		115
Interest expense	(93)		(7)		—		(100)
Interest and dividend income	7		—		—		7
Income tax expense (benefit)	(180)		—		2		(178)
Other segment items(2)	41		5		(1)		45
Net income (loss)	$	245	$	3	$	(3)	$	245

Capital expenditures	$	309	$	25	$	1	$	335


	For the Six-Month Period Ended June 30, 2025
	Electric		Natural Gas		Other(1)		Total

Operating revenue	$	1,410	$	461	$	3	$	1,874
Cost of sales	277		302		1		580

Operations and maintenance	394		67		1		462
Depreciation and amortization	528		34		—		562
Property and other taxes	81		7		—		88
Operating income	130		51		1		182
Interest expense	(186)		(15)		—		(201)
Interest and dividend income	13		1		—		14
Income tax expense (benefit)	(426)		10		2		(414)
Other segment items(2)	64		6		(2)		68
Net income (loss)	$	447	$	33	$	(3)	$	477

Capital expenditures	$	683	$	56	$	1	$	740


	As of
	June 30,		December 31,
	2026		2025
Assets:
Regulated electric	$	25,980	$	25,495
Regulated natural gas	2,102		2,145
Other(1)	1		3
Total assets	$	28,083	$	27,643

(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).

102

PART I

Item 1.Financial Statements


Report of Independent Registered Public Accounting Firm						104
Consolidated Balance Sheets						105
Consolidated Statements of Operations						107
Consolidated Statements of Changes in Member's Equity						108
Consolidated Statements of Cash Flows						109
Notes to Consolidated Financial Statements
General						110
New Accounting Pronouncements						110
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents						110
Property, Plant and Equipment, Net						111
Recent Financing Transactions						111
Income Taxes						111
Employee Benefit Plans						111

Fair Value Measurements						112
Commitments and Contingencies						112
Revenue from Contracts with Customers						112
Member's Equity						112
Segment Information						112

103

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers and Member of

MidAmerican Funding, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of June 30, 2026, the related consolidated statements of operations, and changes in member's equity for the three-month and six-month periods ended June 30, 2026 and 2025, and of cash flows for the six-month periods ended June 30, 2026 and 2025, 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, 2025, 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 27, 2026, 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, 2025, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Des Moines, Iowa

August 7, 2026

104

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	June 30,		December 31,
	2026		2025
ASSETS
Current assets:
Cash and cash equivalents	$	681	$	672
Trade receivables, net	546		453
Income tax receivable	—		82
Inventories	341		334
Prepayments	162		119
Other current assets	70		57
Total current assets	1,800		1,717

Property, plant and equipment, net	24,369		24,065
Goodwill	1,270		1,270
Regulatory assets	293		304
Investments and restricted investments	1,345		1,276
Other assets	286		286

Total assets	$	29,363	$	28,918

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

105

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	June 30,		December 31,
	2026		2025
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	386	$	498
Accrued interest	125		126
Accrued property, income and other taxes	240		198
Note payable to affiliate	—		7

Current portion of long-term debt	379		4
Other current liabilities	111		96
Total current liabilities	1,241		929

Long-term debt	9,069		9,443
Regulatory liabilities	1,345		1,323
Deferred income taxes	3,808		3,758
Asset retirement obligations	889		870
Other long-term liabilities	920		822
Total liabilities	17,272		17,145

Commitments and contingencies (Note 9)

Member's equity:
Paid-in capital	1,679		1,679
Retained earnings	10,412		10,094

Total member's equity	12,091		11,773

Total liabilities and member's equity	$	29,363	$	28,918

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

106

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025
Operating revenue:
Regulated electric	$	760	$	743	$	1,507	$	1,410
Regulated natural gas and other	112		117		505		464
Total operating revenue	872		860		2,012		1,874

Operating expenses:
Cost of fuel and energy	146		153		340		277
Cost of natural gas purchased for resale and other	50		58		340		303
Operations and maintenance	231		236		451		463
Depreciation and amortization	282		255		559		562
Property and other taxes	42		44		90		88
Total operating expenses	751		746		1,780		1,693

Operating income	121		114		232		181

Other income (expense):
Interest expense	(111)		(105)		(220)		(210)
Allowance for borrowed funds	7		8		13		15
Allowance for equity funds	19		21		36		39
Other, net	31		24		33		29
Total other income (expense)	(54)		(52)		(138)		(127)

Income before income tax expense (benefit)	67		62		94		54
Income tax expense (benefit)	(193)		(181)		(411)		(417)

Net income	$	260	$	243	$	505	$	471

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

107

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

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

(Amounts in millions)


	Paid-in Capital		Retained Earnings		Total Member's Equity

Balance, March 31, 2025	$	1,679	$	9,748	$	11,427
Net income	—		243		243

Other equity transactions	—		(1)		(1)
Balance, June 30, 2025	$	1,679	$	9,990	$	11,669

Balance, December 31, 2024	$	1,679	$	9,520	$	11,199
Net income	—		471		471

Other equity transactions	—		(1)		(1)
Balance, June 30, 2025	$	1,679	$	9,990	$	11,669

Balance, March 31, 2026	$	1,679	$	10,339	$	12,018
Net income	—		260		260
Distribution to member	—		(187)		(187)

Balance, June 30, 2026	$	1,679	$	10,412	$	12,091

Balance, December 31, 2025	$	1,679	$	10,094	$	11,773
Net income	—		505		505
Distribution to member	—		(187)		(187)

Balance, June 30, 2026	$	1,679	$	10,412	$	12,091

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

108

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Six-Month Periods
	Ended June 30,
	2026		2025
Cash flows from operating activities:
Net income	$	505	$	471
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	559		562
Amortization of utility plant to other operating expenses	20		17
Allowance for equity funds	(36)		(39)
Deferred income taxes and investment tax credits, net	35		(4)


Other, net	(2)		57
Changes in other operating assets and liabilities:
Trade receivables and other assets	(129)		(143)
Inventories	(7)		60


Accrued property, income and other taxes, net	121		71
Accounts payable and other liabilities	(85)		42
Net cash flows from operating activities	981		1,094

Cash flows from investing activities:
Capital expenditures	(888)		(740)
Purchases of marketable securities	(268)		(225)
Proceeds from sales of marketable securities	304		225

Other, net	(29)		5
Net cash flows from investing activities	(881)		(735)

Cash flows from financing activities:
Distribution to member	(187)		—

Repayments of long-term debt	(2)		(15)
Net change in note payable to affiliate	(7)		20

Other, net	102		(1)
Net cash flows from financing activities	(94)		4

Net change in cash and cash equivalents and restricted cash and cash equivalents	6		363
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	678		558
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	684	$	921

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

109

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 accompanying Consolidated Financial Statements and Notes to Consolidated Financial Statements should be read in conjunction with MidAmerican Funding's Annual Report on Form 10-K for the year ended December 31, 2025. The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of June 30, 2026, and for the three- and six-month periods ended June 30, 2026 and 2025. The results of operations for the three- and six-month periods ended June 30, 2026, are not necessarily indicative of the results to be expected for the full year.

(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
	June 30,		December 31,
	2026		2025

Cash and cash equivalents	$	681	$	672
Restricted cash and cash equivalents in other current assets	3		6
Total cash and cash equivalents and restricted cash and cash equivalents	$	684	$	678

110

(4) Property, Plant and Equipment, Net

Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements. In addition to MidAmerican Energy's property, plant and equipment, net, MidAmerican Funding had nonregulated property, plant and equipment, net, of $9 million as of June 30, 2026 and December 31, 2025.

(5) Recent Financing Transactions

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

(6) Income Taxes

Berkshire Hathaway includes BHE and subsidiaries in its U.S. federal income tax return and BHE includes its subsidiaries in certain state income tax returns. Consistent with established regulatory practice, MidAmerican Funding's provisions 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 pursuant to a tax allocation agreement. For current federal and state income taxes, MidAmerican Funding had a net payable to BHE of $37 million and a net receivable from BHE of $79 million as of June 30, 2026 and December 31, 2025, respectively. MidAmerican Funding received net cash payments for income tax from BHE totaling $559 million and $475 million for each of the six-month periods ended June 30, 2026 and 2025, respectively.

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 (amounts in millions):


	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2026				2025				2026				2025
	Amount		Percent		Amount		Percent		Amount		Percent		Amount		Percent

U.S federal statutory income tax rate	$	14	21.0	%	$	13	21.0	%	$	20	21.0	%	$	11	21.0	%
State income tax, net of federal income tax	(2)		(3.0)		(1)		(1.6)		(3)		(3.2)		(1)		(1.9)
Energy-related tax credits	(205)		(305.9)		(191)		(309.7)		(427)		(454.1)		(427)		(790.7)


Other adjustments:
Effects of ratemaking	(1)		(0.5)		—		—		(1)		(1.1)		1		0.9
Other, net	1		0.5		(2)		(1.2)		—		—		(1)		(0.9)
Effective income tax rate	$	(193)	(287.9)	%	$	(181)	(291.5)	%	$	(411)	(437.4)	%	$	(417)	(771.6)	%

Energy-related 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.

(7) Employee Benefit Plans

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

111

(8) Fair Value Measurements

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


	As of June 30, 2026				As of December 31, 2025
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	9,448	$	8,547	$	9,447	$	8,672

(9) Commitments and Contingencies

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

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

(10) Revenue from Contracts with Customers

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

(11) Member's Equity

In June 2026, MidAmerican Funding paid $187 million in a cash distribution to its parent company, BHE.

(12) 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. When making decisions about the allocation of resources and capital to each reportable segment, the CODM generally considers actual results versus historical results, budgets or forecasts, as well as unique risks and opportunities.

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.

112

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


	For the Three-Month Period Ended June 30, 2026
	Electric		Natural Gas		Other(1)		Total

Operating revenue	$	760	$	111	$	1	$	872
Cost of sales	146		50		—		196

Operations and maintenance	185		46		—		231
Depreciation and amortization	264		18		—		282
Property and other taxes	38		4		—		42
Operating income (loss)	127		(7)		1		121
Interest expense	(98)		(8)		(5)		(111)
Interest and dividend income	6		—		—		6
Income tax expense (benefit)	(190)		(3)		—		(193)
Other segment items(2)	42		8		1		51
Net income (loss)	$	267	$	(4)	$	(3)	$	260

Capital expenditures	$	441	$	29	$	—	$	470


	For the Six-Month Period Ended June 30, 2026
	Electric		Natural Gas		Other(1)		Total

Operating revenue	$	1,507	$	501	$	4	$	2,012
Cost of sales	340		340		—		680

Operations and maintenance	366		85		—		451
Depreciation and amortization	523		36		—		559
Property and other taxes	81		9		—		90
Operating income	197		31		4		232
Interest expense	(194)		(17)		(9)		(220)
Interest and dividend income	11		1		—		12
Income tax expense (benefit)	(414)		4		(1)		(411)
Other segment items(2)	65		5		—		70
Net income (loss)	$	493	$	16	$	(4)	$	505

Capital expenditures	$	835	$	53	$	—	$	888

113


	For the Three-Month Period Ended June 30, 2025
	Electric		Natural Gas		Other(1)		Total

Operating revenue	$	743	$	116	$	1	$	860
Cost of sales	153		57		1		211

Operations and maintenance	201		34		1		236
Depreciation and amortization	238		17		—		255
Property and other taxes	41		3		—		44
Operating income (loss)	110		5		(1)		114
Interest expense	(93)		(7)		(5)		(105)
Interest and dividend income	7		—		—		7
Income tax expense (benefit)	(180)		—		(1)		(181)
Other segment items(2)	41		5		—		46
Net income (loss)	$	245	$	3	$	(5)	$	243

Capital expenditures	$	309	$	25	$	1	$	335


	For the Six-Month Period Ended June 30, 2025
	Electric		Natural Gas		Other(1)		Total

Operating revenue	$	1,410	$	461	$	3	$	1,874
Cost of sales	277		302		1		580

Operations and maintenance	394		67		2		463
Depreciation and amortization	528		34		—		562
Property and other taxes	81		7		—		88
Operating income	130		51		—		181
Interest expense	(186)		(15)		(9)		(210)
Interest and dividend income	13		1		—		14
Income tax expense (benefit)	(426)		10		(1)		(417)
Other segment items(2)	64		6		(1)		69
Net income (loss)	$	447	$	33	$	(9)	$	471

Capital expenditures	$	683	$	56	$	1	$	740

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	As of
	June 30,		December 31,
	2026		2025
Assets:
Regulated electric	$	27,171	$	26,686
Regulated natural gas	2,181		2,224
Other(1)	11		8
Total assets	$	29,363	$	28,918

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 Second Quarter and First Six Months of 2026 and 2025

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the second quarter of 2026 was $263 million, an increase of $18 million, or 7%, compared to 2025, primarily due to higher electric utility margin and a higher income tax benefit, partially offset by higher depreciation and amortization expense. Electric utility margin increased primarily due to higher usage and higher recoveries through bill riders (partially offset in operations and maintenance expense and income tax benefit), offset by lower wholesale margin. Electric retail customer volumes increased 8% primarily due to higher customer usage for industrial customers. Wholesale electricity sales volumes decreased 5% due to unfavorable market conditions. Energy generated increased 5% primarily due to higher renewable-powered and coal-fueled generation, which contributed to lower energy purchased volumes of 10%. Natural gas retail customer sales increased 5% due to customer growth and higher usage for residential and commercial customers.

MidAmerican Energy's net income for the first six months of 2026 was $511 million, an increase of $34 million, or 7%, compared to 2025, primarily due to higher electric utility margin and lower operations and maintenance expense, partially offset by higher interest expense. Electric utility margin increased primarily due to higher usage and higher recoveries through bill riders (partially offset in operations and maintenance expense and income tax benefit), offset by lower wholesale margin. Electric retail customer volumes increased 6% primarily due to higher customer usage for industrial customers. Lower renewable-powered generation from a lower wind resource resulted in decreased wholesale volumes of 4% and increased coal-fueled generation and energy purchased volumes. Natural gas retail customer sales decreased 5% due to the unfavorable impacts of weather.

MidAmerican Funding -

MidAmerican Funding's net income for the second quarter of 2026 was $260 million, an increase of $17 million, or 7%, compared to 2025. MidAmerican Funding's net income for the first six months of 2026 was $505 million, an increase of $34 million, or 7%, compared to 2025. The variance in net income was primarily due to the changes in MidAmerican Energy's earnings discussed above.

Non-GAAP Financial Measure

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

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MidAmerican Energy's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms, and as a result, changes in MidAmerican Energy's 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):


	Second Quarter								First Six Months
	2026		2025		Change				2026		2025		Change
Electric utility margin:
Operating revenue	$	760	$	743	$	17	2	%	$	1,507	$	1,410	$	97	7	%
Cost of fuel and energy	146		153		(7)		(5)		340		277		63		23
Electric utility margin	614		590		24		4	%	1,167		1,133		34		3	%

Natural gas utility margin:
Operating revenue	111		116		(5)		(4)	%	501		461		40		9	%
Natural gas purchased for resale	50		57		(7)		(12)		340		302		38		13
Natural gas utility margin	61		59		2		3	%	161		159		2		1	%

Utility margin	675		649		26		4	%	1,328		1,292		36		3	%

Other operating revenue	1		1		—		—	%	4		3		1		33	%
Other cost of sales	—		1		(1)		100		—		1		(1)		100
Operations and maintenance	231		235		(4)		(2)		451		462		(11)		(2)
Depreciation and amortization	282		255		27		11		559		562		(3)		(1)
Property and other taxes	42		44		(2)		(5)		90		88		2		2
Operating income	$	121	$	115	$	6	5	%	$	232	$	182	$	50	27	%

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Electric Utility Margin

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


	Second Quarter								First Six Months
	2026		2025		Change				2026		2025		Change
Utility margin (in millions):
Operating revenue	$	760	$	743	$	17	2	%	$	1,507	$	1,410	$	97	7	%
Cost of fuel and energy	146		153		(7)		(5)		340		277		63		23
Utility margin	$	614	$	590	$	24	4	%	$	1,167	$	1,133	$	34	3	%

Sales (GWhs):
Residential	1,521		1,454		67		5	%	3,367		3,358		9		—	%
Commercial	931		953		(22)		(2)		1,970		1,990		(20)		(1)
Industrial	5,620		5,076		544		11		10,702		9,718		984		10
Other	426		417		9		2		817		836		(19)		(2)
Total retail	8,498		7,900		598		8		16,856		15,902		954		6
Wholesale	3,379		3,563		(184)		(5)		7,605		7,936		(331)		(4)
Total sales	11,877		11,463		414		4	%	24,461		23,838		623		3	%

Average number of retail customers (in thousands)	844		837		7		1	%	843		836		7		1	%

Average revenue per MWh:
Retail	$	78.67	$	80.10	$	(1.43)	(2)	%	$	74.65	$	74.08	$	0.57	1	%
Wholesale	$	19.76	$	23.87	$	(4.11)	(17)	%	$	25.91	$	22.69	$	3.22	14	%

Heating degree days	486		511		(25)		(5)	%	3,246		3,592		(346)		(10)	%
Cooling degree days	364		348		16		5	%	371		354		17		5	%

Sources of energy (GWhs)(1):
Wind, solar and hydroelectric(2)	6,966		6,493		473		7	%	14,556		14,830		(274)		(2)	%
Coal	2,609		2,282		327		14		5,263		4,559		704		15
Nuclear	817		928		(111)		(12)		1,788		1,751		37		2
Natural gas	306		464		(158)		(34)		700		689		11		2
Total energy generated	10,698		10,167		531		5		22,307		21,829		478		2
Energy purchased	1,246		1,391		(145)		(10)		2,455		2,274		181		8
Total	11,944		11,558		386		3	%	24,762		24,103		659		3	%

Average cost of energy per MWh:
Energy generated(3)	$	3.96	$	6.74	$	(2.78)	(41)	%	$	5.07	$	6.20	$	(1.13)	(18)	%
Energy purchased	$	82.63	$	61.32	$	21.31	35	%	$	92.21	$	62.30	$	29.91	48	%

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

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

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Natural Gas Utility Margin

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


	Second Quarter								First Six Months
	2026		2025		Change				2026		2025		Change
Utility margin (in millions):
Operating revenue	$	111	$	116	$	(5)	(4)	%	$	501	$	461	$	40	9	%
Natural gas purchased for resale	50		57		(7)		(12)		340		302		38		13
Utility margin	$	61	$	59	$	2	3	%	$	161	$	159	$	2	1	%

Throughput (000's Dths):
Residential	5,837		5,543		294		5	%	29,493		31,108		(1,615)		(5)	%
Commercial	2,994		2,832		162		6		14,199		14,927		(728)		(5)
Industrial	1,282		1,299		(17)		(1)		2,869		3,076		(207)		(7)
Other	13		14		(1)		(7)		85		55		30		55
Total retail sales	10,126		9,688		438		5		46,646		49,166		(2,520)		(5)
Wholesale sales	4,494		3,977		517		13		16,352		14,373		1,979		14
Total sales	14,620		13,665		955		7		62,998		63,539		(541)		(1)
Natural gas transportation service	25,849		24,261		1,588		7		57,340		54,902		2,438		4
Total throughput	40,469		37,926		2,543		7	%	120,338		118,441		1,897		2	%

Average number of retail customers (in thousands)	820		804		16		2	%	820		805		15		2	%

Average revenue per retail Dth sold	$	8.90	$	9.73	$	(0.83)	(9)	%	$	8.71	$	7.89	$	0.82	10	%

Heating degree days	516		544		(28)		(5)	%	3,448		3,737		(289)		(8)	%

Average cost of natural gas per retail Dth sold	$	3.93	$	4.70	$	(0.77)	(16)	%	$	5.85	$	5.19	$	0.66	13	%

Combined retail and wholesale average cost of natural gas per Dth sold	$	3.42	$	4.12	$	(0.70)	(17)	%	$	5.40	$	4.75	$	0.65	14	%

Quarter Ended June 30, 2026, Compared to Quarter Ended June 30, 2025

MidAmerican Energy -

Electric utility margin increased $24 million, or 4%, for the second quarter of 2026 compared to 2025 primarily due to:

•a $38 million increase in retail utility margin primarily due to $26 million from higher customer usage and $13 million from higher recoveries through bill riders (partially offset in operations and maintenance expense and income tax benefit), offset by $4 million from price impacts related to changes in sales mix. Retail customer volumes increased 7.6%.

•This favorable variance was partially offset by a $13 million decrease in wholesale utility margin primarily due to a $10 million decrease in margin per unit reflecting lower market prices and a $3 million, or 5.2%, decrease in sales volumes.

Natural gas utility margin increased $2 million, or 3%, for the second quarter of 2026 compared to 2025 primarily due to customer growth and higher usage.

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Operations and maintenance decreased $4 million, or 2%, for the second quarter of 2026 compared to 2025 primarily due to lower steam and natural gas generation costs of $20 million, partially offset by higher gas distribution costs of $5 million, higher nuclear generation costs of $4 million, higher renewable generation costs of $2 million, and higher technology costs of $2 million.

Depreciation and amortization increased $27 million, or 11%, for the second quarter of 2026 compared to 2025 primarily due to $18 million related to additional assets placed in-service and $9 million from higher Iowa revenue sharing accruals.

Property and other taxes decreased $2 million, or 5%, for the second quarter of 2026 compared to 2025 primarily due to lower replacement and wind turbine property taxes.

Interest expense increased $6 million, or 6%, for the second quarter of 2026 compared to 2025 primarily due to the debt issuance in November 2025.

Allowance for borrowed and equity funds decreased $3 million, or 10%, for the second quarter of 2026 compared to 2025 primarily due to lower construction work-in-progress balances related to wind-powered generation projects.

Other, net increased $6 million, or 26%, for the second quarter of 2026 compared to 2025 primarily due to higher cash surrender values of corporate-owned life insurance policies from favorable market performance.

Income tax benefit increased $15 million, or 8%, for the second quarter of 2026 compared to 2025. The effective tax rate was (276)% and (266)% for the three-month periods ended June 30, 2026 and 2025, respectively. The $15 million increase was primarily due to higher PTCs from higher wind generation of $17 million.

MidAmerican Funding -

Income tax benefit increased $12 million, or 7%, for the second quarter of 2026 compared to 2025. The effective tax rate was (288)% and (292)% for the three-month periods ended June 30, 2026 and 2025, respectively. The $12 million increase was primarily due to the factors discussed for MidAmerican Energy.

First Six Months of 2026 Compared to First Six Months of 2025

MidAmerican Energy -

Electric utility margin increased $34 million, or 3%, for the first six months of 2026 compared to 2025 primarily due to:

•$49 million increase in retail utility margin primarily due to $45 million from higher customer usage and $8 million from higher recoveries through bill riders (partially offset in operations and maintenance expense and income tax benefit), offset by $4 million from the unfavorable impact of weather. Retail customer volumes increased 6.0%; partially offset by

•a $14 million decrease in wholesale utility margin due to a $7 million decrease in margin per unit reflecting lower market prices and a $7 million, or 4.2%, decrease in sales volumes.

Natural gas utility margin increased $2 million, or 1%, for the first six months of 2026 compared to 2025 primarily due to:

•$3 million increase from higher base rates and $3 million from customer growth, partially offset by

•a $6 million decrease from the unfavorable impacts of weather.

Operations and maintenance decreased $11 million, or 2%, for the first six months of 2026 compared to 2025 primarily due to lower steam and natural gas generation costs of $17 million and lower electric distribution costs of $6 million, partially offset by higher gas distribution costs of $5 million and higher renewable generation costs of $5 million.

Depreciation and amortization decreased $3 million, or 1%, for the first six months of 2026 compared to 2025 primarily due to $42 million from lower Iowa revenue sharing accruals, partially offset by $33 million related to additional assets placed in-service and $6 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects.

Property and other taxes increased $2 million, or 2%, for the first six months of 2026 compared to 2025 primarily due to higher wind turbine property taxes, partially offset by lower replacement taxes.

120

Interest expense increased $10 million, or 5%, for the first six months of 2026 compared to 2025 primarily due to the debt issuance in November 2025.

Allowance for borrowed and equity funds decreased $5 million, or 9%, for the first six months of 2026 compared to 2025 primarily due to lower construction work-in-progress balances related to wind-powered generation projects.

Other, net increased $4 million, or 14%, for the first six months of 2026 compared to 2025 primarily due to higher cash surrender values of corporate-owned life insurance policies from favorable market performance.

Income tax benefit decreased $5 million, or 1%, for the first six months of 2026 compared to 2025. The effective tax rate was (288)% and (292)% for the six-month periods ended June 30, 2026 and 2025, respectively. The $5 million decrease was primarily due to higher pre-tax income.

MidAmerican Funding -

Income tax benefit decreased $6 million, or 1%, for the first six months of 2026 compared to 2025. The effective tax rate was (437)% and (772)% for the six-month periods ended June 30, 2026 and 2025, respectively. The $6 million decrease was primarily due to the factors discussed for MidAmerican Energy.

Liquidity and Capital Resources

As of June 30, 2026, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):


MidAmerican Energy:
Cash and cash equivalents	$	678

Credit facilities, maturing 2027 and 2029	1,505
Less:

Tax-exempt bond support	(258)
Net credit facilities	1,247

MidAmerican Energy total net liquidity	$	1,925

MidAmerican Funding:
MidAmerican Energy total net liquidity	$	1,925
Cash and cash equivalents	3
MHC, Inc. credit facility, maturing 2027	4
MidAmerican Funding total net liquidity	$	1,932

Operating Activities

MidAmerican Energy's net cash flows from operating activities for the six-month periods ended June 30, 2026 and 2025, were $986 million and $1,117 million, respectively. MidAmerican Funding's net cash flows from operating activities for the six-month periods ended June 30, 2026 and 2025, were $981 million and $1,094 million, respectively. Cash flows from operating activities reflect higher payments to vendors, higher payments related to fuel and energy costs, higher interest payments, and higher property tax payments, partially offset by higher collections from natural gas and electric customers and higher income tax receipts.

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.

121

Investing Activities

MidAmerican Energy's net cash flows from investing activities for the six-month periods ended June 30, 2026 and 2025, were $(881) million and $(735) million, respectively. MidAmerican Funding's net cash flows from investing activities for the six-month periods ended June 30, 2026 and 2025, were $(881) million and $(735) million, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures. Purchases and proceeds related to marketable securities substantially consist of activity within the Quad Cities Generating Station nuclear decommissioning trust and other trust investments.

Financing Activities

MidAmerican Energy's net cash flows from financing activities for the six-month periods ended June 30, 2026 and 2025 were $(100) million and $(16) million, respectively. MidAmerican Funding's net cash flows from financing activities for the six-month periods ended June 30, 2026 and 2025, were $(94) million and $4 million, respectively. In June 2026, MidAmerican Funding paid $187 million in cash distributions to its sole member, BHE. In 2026 and 2025, MidAmerican Energy repaid $2 million and $15 million of long-term debt, respectively. MidAmerican Funding paid $7 million in 2026 and received $20 million in 2025 through its note payable with BHE.

Debt Authorizations and Related Matters

Short-term Debt

MidAmerican Energy has authority from the FERC to issue, through April 2028, commercial paper and bank notes aggregating $1.5 billion. MidAmerican Energy has a $1.5 billion unsecured credit facility expiring in June 2029. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Secured Overnight Financing Rate, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.

Long-term Debt and Preferred Stock

MidAmerican Energy currently has an effective shelf registration statement filed with the SEC to issue an unspecified amount of long-term debt securities and preferred stock through October 2028. MidAmerican Energy has authorization from the FERC to issue, through June 2027, long-term debt securities up to an aggregate of $2.1 billion and preferred stock up to an aggregate of $500 million. MidAmerican Energy has authorization from the Illinois Commerce Commission through April 2028, to issue long-term debt securities up to an aggregate of $2.75 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

122

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


	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2025		2026		2026

Wind generation	$	231	$	228	$	689
Electric distribution	154		156		417
Electric transmission	103		116		328
Solar generation	1		60		312
Other	251		328		784
Total	$	740	$	888	$	2,530

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 $2 million and $124 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for the construction of additional wind-powered generating facilities totals $43 million for the remainder of 2026.

◦Repowering of wind-powered generating facilities totaling $180 million and $85 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for the repowering of wind-powered generating facilities totals $395 million for the remainder of 2026. MidAmerican Energy expects its repowered facilities to meet Internal Revenue Service guidelines for the re-establishment of PTCs under the prevailing wage and apprenticeship guidelines for 10 years from the date the facilities are placed in-service.

•Electric distribution includes expenditures for new facilities to meet retail demand growth and for replacement of existing facilities to maintain system reliability.

•Electric transmission includes expenditures to meet retail demand growth, upgrades to accommodate third-party generator requirements and replacement of existing facilities to maintain system reliability.

•Solar generation includes the construction and operation of solar-powered generating facilities totaling $60 million and $1 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending totals $252 million for the remainder of 2026.

•Other expenditures primarily relate to the construction of new natural gas-powered generating facilities in Iowa and routine projects for other generation, natural gas distribution, technology, facilities and other operational needs to serve existing and expected demand.

Material Cash Requirements

As of June 30, 2026, 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, 2025, 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.

123

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, 2025. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2025.

124

Nevada Power Company and its subsidiaries

Consolidated Financial Section

125

PART I

Item 1.Financial Statements


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
General						132
New Accounting Pronouncements						132
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents						133
Property, Plant and Equipment, Net						134
Recent Financing Transactions						134
Income Taxes						135
Employee Benefit Plans						135

Risk Management and Hedging Activities						136
Fair Value Measurements						138
Commitments and Contingencies						139
Revenue from Contracts with Customers						140

126

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Nevada Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of June 30, 2026, the related consolidated statements of operations, and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2026 and 2025, and of cash flows for the six-month periods ended June 30, 2026 and 2025, 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, 2025, 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 27, 2026, 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, 2025, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

August 7, 2026

127

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)


	As of
	June 30,		December 31,
	2026		2025
ASSETS
Current assets:
Cash and cash equivalents	$	204	$	22
Trade receivables, net	360		243
Amounts due from affiliate	15		40
Inventories	231		230

Regulatory assets	12		120
Prepayments	76		60

Other current assets	13		25
Total current assets	911		740

Property, plant and equipment, net	10,792		10,423

Regulatory assets	405		433
Other assets	376		379

Total assets	$	12,484	$	11,975

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	404	$	536
Amounts due to affiliates	135		88
Accrued interest	48		48
Accrued property, income and other taxes	52		23
Accrued employee expenses	24		79
Short-term debt	—		50
Current portion of long-term debt	—		93
Regulatory liabilities	134		33
Customer deposits	75		56


Other current liabilities	128		61
Total current liabilities	1,000		1,067

Senior debt	3,306		3,305
Junior subordinated debt	297		297
Finance lease obligations	242		248
Regulatory liabilities	951		980
Deferred income taxes	808		837
Other long-term liabilities	688		551
Total liabilities	7,292		7,285

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	3,598		3,123
Retained earnings	1,595		1,568
Accumulated other comprehensive loss, net	(1)		(1)
Total shareholder's equity	5,192		4,690

Total liabilities and shareholder's equity	$	12,484	$	11,975

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

128

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025

Operating revenue	$	694	$	597	$	1,185	$	1,028

Operating expenses:
Cost of fuel and energy	332		300		572		513
Operations and maintenance	92		90		182		168
Depreciation and amortization	103		99		207		197
Property and other taxes	17		15		31		29
Total operating expenses	544		504		992		907

Operating income	150		93		193		121

Other income (expense):
Interest expense	(55)		(56)		(109)		(111)
Allowance for borrowed funds	5		6		10		10
Allowance for equity funds	12		12		22		20
Interest and dividend income	3		3		7		6
Other, net	5		5		10		8
Total other income (expense)	(30)		(30)		(60)		(67)

Income before income tax expense (benefit)	120		63		133		54
Income tax expense (benefit)	14		6		16		5
Net income	$	106	$	57	$	117	$	49

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

129

NEVADA POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)


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

Balance, March 31, 2025	1,000	$	—	$	2,943	$	1,313	$	(1)	$	4,255
Net income	—	—		—		57		—		57

Contributions	—	—		80		—		—		80
Balance, June 30, 2025	1,000	$	—	$	3,023	$	1,370	$	(1)	$	4,392

Balance, December 31, 2024	1,000	$	—	$	2,943	$	1,506	$	(1)	$	4,448
Net income	—	—		—		49		—		49
Dividends declared	—	—		—		(185)		—		(185)
Contributions	—	—		80		—		—		80
Balance, June 30, 2025	1,000	$	—	$	3,023	$	1,370	$	(1)	$	4,392

Balance, March 31, 2026	1,000	$	—	$	3,323	$	1,579	$	(1)	$	4,901
Net income	—	—		—		106		—		106
Dividends declared	—	—		—		(90)		—		(90)
Contributions	—	—		275		—		—		275

Balance, June 30, 2026	1,000	$	—	$	3,598	$	1,595	$	(1)	$	5,192

Balance, December 31, 2025	1,000	$	—	$	3,123	$	1,568	$	(1)	$	4,690
Net income	—	—		—		117		—		117
Dividends declared	—	—		—		(90)		—		(90)
Contributions	—	—		475		—		—		475

Balance, June 30, 2026	1,000	$	—	$	3,598	$	1,595	$	(1)	$	5,192

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

130

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Six-Month Periods
	Ended June 30,
	2026		2025
Cash flows from operating activities:
Net income	$	117	$	49
Adjustments to reconcile net income to net cash flows from operating activities:


Depreciation and amortization	207		197
Allowance for equity funds	(22)		(20)
Deferred energy	68		46
Amortization of deferred energy	40		27
Other changes in regulatory assets and liabilities	109		(17)
Deferred income taxes and amortization of investment tax credits	(18)		(10)
Other, net	6		(1)
Changes in other operating assets and liabilities:
Trade receivables and other assets	(37)		(7)
Inventories	(1)		(26)
Accrued property, income and other taxes	10		103
Accounts payable and other liabilities	29		166
Net cash flows from operating activities	508		507

Cash flows from investing activities:
Capital expenditures	(679)		(632)



Proceeds from sale of assets	21		—

Net cash flows from investing activities	(658)		(632)

Cash flows from financing activities:
Proceeds from long-term debt	—		297
Repayments of long-term debt	(93)		—
Net repayment of short-term debt	(50)		—


Contributions from parent	475		80
Dividends paid	(90)		(185)
Other, net	85		(11)
Net cash flows from financing activities	327		181

Net change in cash and cash equivalents and restricted cash and cash equivalents	177		56
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	35		42
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	212	$	98

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

131

NEVADA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

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

The accompanying Consolidated Financial Statements and Notes to Consolidated Financial Statements should be read in conjunction with Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2025. The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of June 30, 2026, and for the three- and six-month periods ended June 30, 2026 and 2025. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and six-month periods ended June 30, 2026 and 2025. The results of operations for the three- and six-month periods ended June 30, 2026, are not necessarily indicative of the results to be expected for the full year.

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. Net income, as reported on the Consolidated Statements of Operations, is considered by the CODM in allocating resources and capital. When making decisions about the allocation of resources and capital, the CODM generally considers actual results versus historical results, budgets or forecasts, and state regulatory ratemaking results as well as unique risks and opportunities. The significant segment expense information regularly provided to the CODM aligns 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 November 2024, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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.

132

In December 2025, the FASB issued ASU No. 2025-10, Government Grants Topic 832, "Accounting for Government Grants Received by Business Entities" which establishes accounting for government grants received by an entity, including guidance for a grant related to an asset and a grant related to income. This guidance also requires, consistent with current disclosure requirements, that an entity provide disclosures including the nature of the government grant received, the accounting policies used to account for the grant, and significant terms and conditions of the grant. This guidance is effective for interim and annual reporting periods beginning after December 15, 2028. Early adoption is permitted and can be applied using either a modified prospective approach, a modified retrospective approach or a retrospective approach. Nevada Power is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In May 2026, the FASB issued ASU No. 2026-02, Environmental Credits and Environmental Credit Obligations Topic 818 which establishes guidance on the recognition, measurement, presentation and disclosure of environmental credits and related regulatory obligations. This guidance provides a framework for accounting for environmental credit assets, including those generated, purchased or received and environmental credit obligations. It also requires entities to assess the intended use of environmental credits, and, in certain cases, evaluate such credits for impairment. ASU 2026-02 introduces enhanced annual disclosure requirements related to environmental credits and associated obligations. The guidance is effective for annual periods beginning after December 15, 2027. Early adoption is permitted and should be applied on a retrospective basis through a cumulative effect adjustment to the opening balance of retained earnings. 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
	June 30,		December 31,
	2026		2025

Cash and cash equivalents	$	204	$	22
Restricted cash and cash equivalents included in other current assets	8		13
Total cash and cash equivalents and restricted cash and cash equivalents	$	212	$	35

133

(4) Property, Plant and Equipment, Net

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


		As of
	Depreciable Life	June 30,		December 31,
		2026		2025
Utility plant:
Generation	30 - 65 years	$	5,619	$	5,542
Transmission	55 - 75 years	1,879		1,886
Distribution	24 - 70 years	5,190		5,031
Intangible plant and other	5 - 65 years	1,000		951
Utility plant		13,688		13,410
Accumulated depreciation and amortization		(4,547)		(4,383)
Utility plant, net		9,141		9,027
Nonregulated, net of accumulated depreciation and amortization	40 years	1		1
		9,142		9,028
Construction work-in-progress		1,650		1,395
Property, plant and equipment, net		$	10,792	$	10,423

(5) Recent Financing Transactions

Tax Exempt Bonds

In March 2026, Nevada Power repurchased the following series of fixed-rate tax-exempt bonds: $40 million of its Clark County, Nevada Revenue Bonds Series 2017, due 2036, $40 million of its Coconino County, Arizona Pollution Control Corporation Revenue Bonds, Series 2017A, due 2032, and $13 million of its Coconino County, Arizona Pollution Control Corporate Revenue Bonds, Series 2017B, due 2039. Nevada Power purchased these bonds as required by the bond indentures. Nevada Power is holding these bonds and can re-offer them at a future date.

Credit Facilities

In June 2026, Nevada Power amended its existing $600 million secured credit facility expiring in June 2028. The amendment extended the expiration date to June 2029 and amended certain provisions of the existing credit agreement.

134

(6) Income Taxes

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 pursuant to a tax allocation agreement. For current federal and state income taxes, Nevada Power had a net payable to BHE of $7 million and a net receivable of $3 million as of June 30, 2026 and December 31, 2025, respectively. Nevada Power made net cash payments for federal income taxes to BHE of $18 million and received cash refunds for federal income taxes from BHE of $93 million for the six-month periods ended June 30, 2026 and 2025, respectively.

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 (amounts in millions):


	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2026				2025				2026				2025
	Amount		Percent		Amount		Percent		Amount		Percent		Amount		Percent

U.S. Federal statutory income tax rate	$	25	21.0	%	$	13	21.0	%	$	28	21.0	%	$	11	21.0	%
Energy-related tax credits	(7)		(5.9)		(4)		(6.7)		(8)		(5.9)		(4)		(7.3)
Effects of ratemaking(1)	(4)		(3.3)		(3)		(5.3)		(4)		(3.2)		(2)		(4.5)



Effective income tax rate	$	14	11.8	%	$	6	9.0	%	$	16	11.9	%	$	5	9.2	%

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

Energy-related 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.

(7) Employee Benefit Plans

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

135

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


	As of
	June 30,		December 31,
	2026		2025
Qualified Pension Plan:
Other assets	$	47	$	46



Non-Qualified Pension Plans:

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

Other Postretirement Plans:
Other assets	17		16

(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.

136

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
	Contracts -		Other
	Current		Long-term
	Liabilities		Liabilities		Total
As of June 30, 2026
Not designated as hedging contracts(1):

Commodity liabilities	$	(31)	$	(18)	$	(49)







As of December 31, 2025
Not designated as hedging contracts(1):






Commodity liabilities	$	(27)	$	(14)	$	(41)

(1)Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates. As of June 30, 2026, a regulatory asset of $49 million was recorded related to the net derivative liability of $49 million. As of December 31, 2025, a regulatory asset of $41 million was recorded related to the net derivative liability of $41 million.

Derivative Contract Volumes

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


	Unit of	June 30,	December 31,
	Measure	2026	2025

Electricity purchases	Megawatt hours	4	2
Natural gas purchases	Decatherms	143	131

Credit Risk

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

Collateral and Contingent Features

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in Nevada Power's creditworthiness. These rights can vary by contract and by counterparty. As of June 30, 2026, Nevada Power's credit ratings for its senior secured debt and its issuer credit ratings for subordinated debt from the recognized credit rating agencies were investment grade.

137

The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $3 million and $5 million as of June 30, 2026, and December 31, 2025, 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 3 — Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including its own data.

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


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Total
As of June 30, 2026:
Assets:

Money market mutual funds	$	189	$	—	$	—	$	189
Investment funds	6		—		—		6
	$	195	$	—	$	—	$	195

Liabilities:
Commodity derivatives	$	—			$	(49)	$	(49)

As of December 31, 2025:
Assets:

Money market mutual funds	$	19	$	—	$	—	$	19
Investment funds	5		—		—		5
	$	24	$	—	$	—	$	24

Liabilities:
Commodity derivatives	$	—	$	—	$	(41)	$	(41)

138

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of June 30, 2026, and December 31, 2025, had an immaterial impact to the fair value of its derivative contracts. As such, Nevada Power considers its derivative contracts to be valued using Level 3 inputs.

Nevada Power's investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.

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


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025

Beginning balance	$	(51)	$	(73)	$	(41)	$	(57)
Changes in fair value recognized in regulatory assets	1		(8)		(13)		(32)

Settlements	1		3		5		11
Ending balance	$	(49)	$	(78)	$	(49)	$	(78)

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 June 30, 2026				As of December 31, 2025
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	3,603	$	3,557	$	3,695	$	3,688

(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.

139

Accrual for Customer Refunds

Nevada Power's accrual in connection with customer refunds arising from regulatory proceedings, reflecting its commitment to transparency and regulatory compliance, was $46 million as of June 30, 2026 and December 31, 2025. Nevada Power filed an Offer of Compromise with the PUCN in January 2026 to settle the regulatory proceedings, inclusive of the amount accrued in 2025, that was accepted by the PUCN in February 2026. Refunds were made in July 2026.

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				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025
Customer Revenue:
Retail:
Residential	$	370	$	314	$	604	$	531
Commercial	146		128		264		226
Industrial	155		133		273		230
Other	4		1		8		1
Total fully bundled	675		576		1,149		988
Distribution only service	3		4		7		8
Total retail	678		580		1,156		996
Wholesale, transmission and other	15		16		27		31
Total Customer Revenue	693		596		1,183		1,027
Other revenue	1		1		2		1
Total operating revenue	$	694	$	597	$	1,185	$	1,028

140

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

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

Results of Operations for the Second Quarter and First Six Months of 2026 and 2025

Overview

Net income for the second quarter of 2026 was $106 million, an increase of $49 million compared to 2025 primarily due to higher electric utility margin. These items were partially offset by increased income tax expense, increased depreciation and amortization expense and higher operations and maintenance expense. Utility margin increased primarily due to higher retail rates, lower prior year revenue related to an accrual in connection with customer refunds arising from regulatory proceedings and higher other retail revenue. Retail customer volumes, including distribution only service customers, increased 2% primarily due to the favorable impact of weather, customer usage patterns and an increase in the average number of customers. Energy generated volumes decreased 1% for the second quarter of 2026 compared to 2025 primarily due to lower natural gas-fueled generation. Wholesale electricity sales volumes decreased 7% and energy purchased volumes increased 8%.

Net income for the first six months of 2026 was $117 million, an increase of $68 million compared to 2025 primarily due to higher electric utility margin, higher allowance for equity funds and lower interest expense. These items were partially offset by higher operations and maintenance expense, increased depreciation and amortization expense and increased income tax expense. Utility margin increased primarily due to higher retail rates lower prior year revenue related to an accrual in connection with customer refunds arising from regulatory proceedings and other retail revenue. Retail customer volumes, including distribution only service customers, increased 3% primarily due to the favorable impact of weather, customer usage patterns and an increase in the average number of customers. Energy generated volumes decreased 4% for the first six months of 2026 compared to 2025 primarily due to lower natural gas-fueled generation. Wholesale electricity sales volumes decreased 24% and energy purchased volumes were consistent with the prior year.

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.

141

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


	Second Quarter								First Six Months
	2026		2025		Change				2026		2025		Change
Utility margin:
Operating revenue	$	694	$	597	$	97	16	%	$	1,185	$	1,028	$	157	15	%
Cost of fuel and energy	332		300		32		11		572		513		59		12
Utility margin	362		297		65		22		613		515		98		19
Operations and maintenance	92		90		2		2		182		168		14		8
Depreciation and amortization	103		99		4		4		207		197		10		5
Property and other taxes	17		15		2		13		31		29		2		7
Operating income	$	150	$	93	$	57	61	%	$	193	$	121	$	72	60	%

142

Utility Margin

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


	Second Quarter								First Six Months
	2026		2025		Change				2026		2025		Change
Utility margin (in millions):
Operating revenue	$	694	$	597	$	97	16	%	$	1,185	$	1,028	$	157	15	%
Cost of fuel and energy	332		300		32		11		572		513		59		12
Utility margin	$	362	$	297	$	65	22	%	$	613	$	515	$	98	19	%

Sales (GWhs):
Residential	2,757		2,629		128		5	%	4,401		4,162		239		6	%
Commercial	1,305		1,318		(13)		(1)		2,346		2,315		31		1
Industrial	1,655		1,618		37		2		3,083		3,015		68		2
Other	43		42		1		2		87		81		6		7
Total fully bundled(1)	5,760		5,607		153		3		9,917		9,573		344		4
Distribution only service	709		708		1		—		1,382		1,358		24		2
Total retail	6,469		6,315		154		2		11,299		10,931		368		3
Wholesale	125		134		(9)		(7)		175		230		(55)		(24)
Total GWhs sold	6,594		6,449		145		2	%	11,474		11,161		313		3	%

Average number of retail customers (in thousands)	1,063		1,051		12		1	%	1,061		1,049		12		1	%





Average revenue per MWh:
Retail - fully bundled(1)	$	117.07	$	102.72	$	14.35	14	%	$	115.90	$	103.23	$	12.67	12	%

Wholesale	$	18.35	$	35.53	$	(17.18)	(48)	%	$	22.83	$	39.44	$	(16.61)	(42)	%

Heating degree days	19		56		(37)		(66)	%	615		973		(358)		(37)	%
Cooling degree days	1,374		1,389		(15)		(1)	%	1,667		1,449		218		15	%

Sources of energy (GWhs)(2)(3):
Natural gas	3,633		3,655		(22)		(1)	%	6,730		6,978		(248)		(4)	%

Renewables	133		135		(2)		(1)		210		226		(16)		(7)
Total energy generated	3,766		3,790		(24)		(1)		6,940		7,204		(264)		(4)
Energy purchased	2,371		2,202		169		8		3,480		3,493		(13)		—
Total	6,137		5,992		145		2	%	10,420		10,697		(277)		(3)	%

Average cost of energy per MWh(2)(4):
Energy generated	$	17.01	$	25.93	$	(8.92)	(34)	%	$	29.24	$	29.87	$	(0.63)	(2)	%
Energy purchased	$	112.88	$	91.39	$	21.49	24	%	$	105.95	$	85.13	$	20.82	24	%

(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 266 GWhs and 42 GWhs of gas generated energy that is purchased at cost by related parties for the second quarter of 2026 and 2025, respectively. The average cost of energy per MWh and sources of energy excludes 500 GWhs and 154 GWhs of gas generated energy that is purchased at cost by related parties for the first six months of 2026 and 2025, 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.

143

Quarter Ended June 30, 2026, Compared to Quarter Ended June 30, 2025

Utility margin increased $65 million, or 22%, for the second quarter of 2026 compared to 2025 primarily due to:

•$46 million of higher electric retail utility margin primarily due to higher retail rates from the 2025 regulatory rate review with new rates effective October 2025 and higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 2.4% primarily due to favorable changes in weather, customer usage patterns and an increase in the average number of customers;

•$16 million lower prior year revenue related to an accrual in connection with customer refunds arising from regulatory proceedings; and

•$3 million of higher other retail revenue from lower regulatory amortizations.

Operations and maintenance increased $2 million, or 2%, for the second quarter of 2026 compared to 2025 primarily due to higher plant operations and maintenance and higher regulatory amortizations from the 2025 regulatory rate review, partially offset by lower general and administrative costs primarily from decreased technology costs.

Depreciation and amortization increased $4 million, or 4%, for the second quarter of 2026 compared to 2025 primarily due to higher plant placed in-service and higher amortizations from intangible plant software.

Income tax expense increased $8 million for the second quarter of 2026 compared to 2025. The effective tax rate was 12% and 10% for the three-month periods ended June 30, 2026 and 2025, respectively. The $8 million increase was primarily due to higher pre-tax income, partially offset by higher PTCs and ITCs and the effects of ratemaking.

First Six Months of 2026 Compared to First Six Months of 2025

Utility margin increased $98 million, or 19%, for the first six months of 2026 compared to 2025 primarily due to:

•$72 million of higher electric retail utility margin primarily due to higher retail rates from the 2025 regulatory rate review with new rates effective October 2025 and higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 3.4% primarily due to favorable changes in weather, customer usage patterns and an increase in the average number of customers;

•$16 million lower prior year revenue related to an accrual in connection with customer refunds arising from regulatory proceedings;

•$6 million of higher other retail revenue from lower regulatory amortizations; and

•$4 million of higher energy efficiency implementation revenue.

Operations and maintenance increased by $14 million, or 8%, for the first six months of 2026 compared to 2025 primarily due to increased plant operations and maintenance and increased regulatory amortizations from the 2025 regulatory rate review, partially offset by decreased general and administrative costs primarily from decreased technology costs.

Depreciation and amortization increased $10 million, or 5%, for the first six months of 2026 compared to 2025 primarily due to higher plant placed in-service and higher amortizations from intangible plant software.

Interest expense decreased $2 million, or 2%, for the first six months of 2026 compared to 2025 primarily due to lower lease interest expense and lower carrying charges on regulatory balances.

Allowance for borrowed funds and allowance for equity funds increased $2 million, or 7%, for the first six months of 2026 compared to 2025 primarily due to higher construction work-in-progress.

Income tax expense increased $11 million for the first six months of 2026 compared to 2025. The effective tax rate was 12% in 2026 and 9% in 2025. The $11 million increase was primarily due to higher pre-tax income, partially offset by higher PTCs and ITCs and the effects of ratemaking.

144

Liquidity and Capital Resources

As of June 30, 2026, Nevada Power's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	204

Credit facility, maturing 2029	600
Less:
Short-term debt	—

Net credit facility	600

Total net liquidity	$	804

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2026 and 2025, were $508 million and $507 million, respectively. The change was primarily due to the timing of payments for operating costs and lower payments related to fuel and energy costs, partially offset by lower collections from customers and higher income tax payments.

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

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2026 and 2025, were $(658) million and $(632) million, respectively. The change was primarily due to increased capital expenditures, partially offset by proceeds from sale of assets. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the six-month periods ended June 30, 2026 and 2025, were $327 million and $181 million, respectively. The change was primarily due to higher contributions from NV Energy, Inc., lower dividends paid to NV Energy, Inc. and higher customer receipts from contributions in aid of construction, partially offset by lower net proceeds from the issuance of junior subordinated debt and higher payments of 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.

In July 2026, Nevada Power paid a dividend to NV Energy, Inc. of $100 million.

Debt Authorizations

Nevada Power currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $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. As of June 30, 2026, approximately $1.8 billion of debt capacity remains available under this authorization. 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 Nevada Power's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

145

Capital Expenditures

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution control technologies, replacement generation and associated operating costs are generally incorporated into Nevada Power's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.

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


	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2025		2026		2026

Electric transmission	$	233	$	194	$	640
Electric distribution	182		188		428
Solar generation and electric battery storage	19		25		37
Wildfire prevention	7		12		28
Other	191		260		464
Total	$	632	$	679	$	1,597

Nevada Power receives PUCN approval through its IRP filings for various projects and has included estimates from IRP filings as well as potential future filings in its forecast capital expenditures for 2026. These estimates are likely to 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 totaling $170 million and $218 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for the Greenlink Nevada transmission expansion program expected to be placed in-service in 2027 and 2028 totals $410 million for the remainder of 2026. 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. Growth expenditures include spending on new customer connections totaling $71 million and $74 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for new customer connections totals $64 million for the remainder of 2026.

•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 10% for Nevada Power and 90% for Sierra Pacific. Commercial operation of the solar facility is expected by early 2027 and the co-located battery storage reached commercial operation in March 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 and operating expenditures including spending for infrastructure needed to serve existing and expected demand, routine capital expenditures for generation, information technology expenditures and other operating projects.

146

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. In January 2026, the Nevada Utilities filed a stipulation with the PUCN that reflected a settlement among participating parties and largely accepted the First Amendment as filed, including approval of the 150-MW battery energy storage system power purchase agreement. A final order approving the stipulation was received in February 2026.

2026 Joint Triennial Integrated Resource Plan

In May 2026, the Nevada Utilities filed with the PUCN a joint application for approval of their 2027-2046 Triennial Integrated Resource Plan and 2027-2029 Energy Supply Plan. The joint application seeks approval of 23 third-party power purchase agreements which consists of approximately 4,550 megawatts of renewable generation and 5,405 megawatts of battery storage, 1,223 megawatts of thermal generation and related transmission facilities to address anticipated load growth. Hearings are scheduled in September, October and November 2026.

Material Cash Requirements

As of June 30, 2026, 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, 2025, 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

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

Environmental Laws and Regulations

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

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

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of long-lived assets and income taxes. For additional discussion of Nevada Power's critical accounting estimates, see Item 7 of Nevada Power's Annual Report on Form 10‑K for the year ended December 31, 2025. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2025.

147

Sierra Pacific Power Company and its subsidiaries

Consolidated Financial Section

148

PART I

Item 1.Financial Statements


Report of Independent Registered Public Accounting Firm						150
Consolidated Balance Sheets						151
Consolidated Statements of Operations						152
Consolidated Statements of Changes in Shareholder's Equity						153
Consolidated Statements of Cash Flows						154
Notes to Consolidated Financial Statements
General						155
New Accounting Pronouncements						155
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents						156
Property, Plant and Equipment, Net						156
Recent Financing Transactions						157
Income Taxes						157
Employee Benefit Plans						157

Risk Management and Hedging Activities						158
Fair Value Measurements						160
Commitments and Contingencies						161
Revenue from Contracts with Customers						162
Segment Information						163

149

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of June 30, 2026, the related consolidated statements of operations, and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2026 and 2025, and of cash flows for the six-month periods ended June 30, 2026 and 2025, 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, 2025, 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 27, 2026, 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, 2025, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

August 7, 2026

150

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)


	As of
	June 30,		December 31,
	2026		2025
ASSETS
Current assets:
Cash and cash equivalents	$	124	$	5
Trade receivables, net	118		108
Income taxes receivable	121		—
Amounts due from affiliates	98		196
Inventories	156		151
Regulatory assets	54		56
Prepayments	64		20
Other current assets	10		19
Total current assets	745		555

Property, plant and equipment, net	6,788		6,056

Regulatory assets	217		218
Other assets	224		216

Total assets	$	7,974	$	7,045

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	456	$	519
Amounts due to affiliate	69		208



Accrued employee expenses	18		85
Current portion of long-term debt	—		410

Regulatory liabilities	92		72
Customer deposits	64		45

Other current liabilities	94		40
Total current liabilities	793		1,379

Long-term debt	1,117		1,116
Junior subordinated debt	1,039		446

Regulatory liabilities	433		391
Deferred income taxes	359		390
Other long-term liabilities	698		342
Total liabilities	4,439		4,064

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	3,051		2,561
Retained earnings	485		421
Accumulated other comprehensive loss, net	(1)		(1)
Total shareholder's equity	3,535		2,981

Total liabilities and shareholder's equity	$	7,974	$	7,045

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

151

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025
Operating revenue:
Regulated electric	$	262	$	235	$	497	$	471
Regulated natural gas	18		23		55		72
Total operating revenue	280		258		552		543

Operating expenses:
Cost of fuel and energy	127		110		240		225
Cost of natural gas purchased for resale	4		9		22		37
Operations and maintenance	69		61		140		121
Depreciation and amortization	48		40		93		80
Property and other taxes	6		6		13		12
Total operating expenses	254		226		508		475

Operating income	26		32		44		68

Other income (expense):
Interest expense	(36)		(24)		(67)		(48)
Allowance for borrowed funds	9		3		17		6
Allowance for equity funds	28		9		53		19
Interest and dividend income	3		3		7		6
Other, net	3		2		7		4
Total other income (expense)	7		(7)		17		(13)

Income before income tax expense (benefit)	33		25		61		55
Income tax expense (benefit)	(3)		3		(2)		6
Net income	$	36	$	22	$	63	$	49

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

152

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)


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

Balance, March 31, 2025	1,000	$	—	$	2,001	$	402	$	(1)	$	2,402
Net income	—	—		—		22		—		22

Contributions	—	—		120		—		—		120
Other equity transactions	—	—		—		1		—		1
Balance, June 30, 2025	1,000	$	—	$	2,121	$	425	$	(1)	$	2,545

Balance, December 31, 2024	1,000	$	—	$	1,726	$	375	$	(1)	$	2,100
Net income	—	—		—		49		—		49

Contributions	—	—		395		—		—		395
Other equity transactions	—	—		—		1		—		1
Balance, June 30, 2025	1,000	$	—	$	2,121	$	425	$	(1)	$	2,545

Balance, March 31, 2026	1,000	$	—	$	2,861	$	449	$	(1)	$	3,309
Net income	—	—		—		36		—		36

Contributions	—	—		190		—		—		190

Balance, June 30, 2026	1,000	$	—	$	3,051	$	485	$	(1)	$	3,535

Balance, December 31, 2025	1,000	$	—	$	2,561	$	421	$	(1)	$	2,981
Net income	—	—		—		63		—		63

Contributions	—	—		490		—		—		490
Other equity transactions	—	—		—		1		—		1
Balance, June 30, 2026	1,000	$	—	$	3,051	$	485	$	(1)	$	3,535

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

153

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Six-Month Periods
	Ended June 30,
	2026		2025
Cash flows from operating activities:
Net income	$	63	$	49
Adjustments to reconcile net income to net cash flows from operating activities:
Loss on nonrecurring items	(1)		—
Depreciation and amortization	93		80
Allowance for equity funds	(53)		(19)
Deferred energy	34		43
Amortization of deferred energy	(11)		(6)
Other changes in regulatory assets and liabilities	4		12
Deferred income taxes and amortization of investment tax credits	188		(14)
Other, net	4		(2)
Changes in other operating assets and liabilities:
Trade receivables and other assets	61		33
Inventories	(6)		(7)
Accrued property, income and other taxes	(118)		(7)
Accounts payable and other liabilities	(166)		(26)
Net cash flows from operating activities	92		136

Cash flows from investing activities:
Capital expenditures	(715)		(514)
Proceeds from sale of asset	5		—


Net cash flows from investing activities	(710)		(514)

Cash flows from financing activities:
Proceeds from long-term debt	595		—
Repayments of long-term debt	(410)		—





Contributions from parent	490		395

Other, net	60		(5)
Net cash flows from financing activities	735		390

Net change in cash and cash equivalents and restricted cash and cash equivalents	117		12
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	10		24
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	127	$	36

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

154

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company and its subsidiaries ("Nevada Power") and certain other subsidiaries. Sierra Pacific is a U.S. regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that has investments in subsidiaries principally engaged in energy businesses. BHE is a wholly owned subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The accompanying Consolidated Financial Statements and Notes to Consolidated Financial Statements should be read in conjunction with Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2025. The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of June 30, 2026, and for the three- and six-month periods ended June 30, 2026 and 2025. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and six-month periods ended June 30, 2026 and 2025. The results of operations for the three- and six-month periods ended June 30, 2026, are not necessarily indicative of the results to be expected for the full year.

(2) New Accounting Pronouncements

In November 2024, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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.

In December 2025, the FASB issued ASU No. 2025-10, Government Grants Topic 832, "Accounting for Government Grants Received by Business Entities" which establishes accounting for government grants received by an entity, including guidance for a grant related to an asset and a grant related to income. This guidance also requires, consistent with current disclosure requirements, that an entity provide disclosures including the nature of the government grant received, the accounting policies used to account for the grant, and significant terms and conditions of the grant. This guidance is effective for interim and annual reporting periods beginning after December 15, 2028. Early adoption is permitted and can be applied using either a modified prospective approach, a modified retrospective approach or a retrospective approach. Sierra Pacific is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

155

In May 2026, the FASB issued ASU No. 2026-02, Environmental Credits and Environmental Credit Obligations Topic 818 which establishes guidance on the recognition, measurement, presentation and disclosure of environmental credits and related regulatory obligations. This guidance provides a framework for accounting for environmental credit assets, including those generated, purchased or received and environmental credit obligations. It also requires entities to assess the intended use of environmental credits, and, in certain cases, evaluate such credits for impairment. ASU 2026-02 introduces enhanced annual disclosure requirements related to environmental credits and associated obligations. The guidance is effective for annual periods beginning after December 15, 2027. Early adoption is permitted and should be applied on a retrospective basis through a cumulative effect adjustment to the opening balance of retained earnings. 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.

(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
	June 30,		December 31,
	2026		2025

Cash and cash equivalents	$	124	$	5
Restricted cash and cash equivalents included in other current assets	3		5
Total cash and cash equivalents and restricted cash and cash equivalents	$	127	$	10

(4) Property, Plant and Equipment, Net

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


		As of
	Depreciable Life	June 30,		December 31,
		2026		2025
Utility plant:
Generation	25 - 70 years	$	1,862	$	1,413
Transmission	50 - 76 years	1,385		1,321
Electric distribution	20 - 76 years	2,378		2,298
Electric intangible plant and other	5 - 65 years	197		189
Natural gas distribution	35 - 70 years	614		591
Natural gas intangible plant and other	5 - 65 years	19		19
Common other	5 - 65 years	475		461
Utility plant		6,930		6,292
Accumulated depreciation and amortization		(2,285)		(2,296)
		4,645		3,996


Construction work-in-progress		2,143		2,060
Property, plant and equipment, net		$	6,788	$	6,056

156

(5) Recent Financing Transactions

Junior Subordinated Debt

Credit Facilities

In June 2026, Sierra Pacific amended its existing $400 million secured credit facility expiring in June 2028. The amendment extended the expiration date to June 2029 and amended certain provisions of the existing credit agreement.

(6) Income Taxes

Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return and BHE includes its subsidiaries in certain state income tax returns. 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 pursuant to a tax allocation agreement. For current federal and state income taxes, Sierra Pacific had a net receivable from BHE of $121 million and $— million as of June 30, 2026 and December 31, 2025, respectively. Sierra Pacific received net cash refunds for federal income taxes from BHE of $70 million and made net cash payments for federal income tax to BHE of $30 million for the six-month periods ended June 30, 2026 and 2025, respectively.

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 (amounts in millions):


	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2026				2025				2026				2025
	Amount		Percent		Amount		Percent		Amount		Percent		Amount		Percent

U.S. federal statutory income tax rate	$	7	21.0	%	$	6	21.0	%	$	13	21.0	%	$	12	21.0	%
Energy-related tax credits	(2)		(7.0)		—		—		(2)		(3.8)		—		—
Effects of ratemaking(1)	(8)		(22.5)		(3)		(9.9)		(13)		(20.8)		(6)		(9.6)



Effective income tax rate	$	(3)	(8.5)	%	$	3	11.1	%	$	(2)	(3.6)	%	$	6	11.4	%

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

(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.

157

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


	As of
	June 30,		December 31,
	2026		2025
Qualified Pension Plan:

Other assets	$	75	$	72



Non-Qualified Pension Plans:


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

Other Postretirement Plans:

Other assets	5		2

(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.

158

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
	Long-term		Current		Long-term
	Assets		Liabilities		Liabilities		Total
As of June 30, 2026
Not designated as hedging contracts(1):

Commodity liabilities	$	—	$	(9)	$	(5)	$	(14)






As of December 31, 2025
Not designated as hedging contracts(1):
Commodity assets	$	1	$	—	$	—	$	1
Commodity liabilities	—		(8)		(4)		(12)
Total derivative - net basis	$	1	$	(8)	$	(4)	$	(11)

(1)Sierra Pacific's commodity derivatives not designated as hedging contracts are included in regulated rates. As of June 30, 2026, a net regulatory asset of $14 million was recorded related to the net derivative liability of $14 million. As of December 31, 2025, a net regulatory asset of $11 million was recorded related to the net derivative liability of $11 million.

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


	Unit of	June 30,	December 31,
	Measure	2026	2025

Electricity purchases	Megawatt hours	1	1
Natural gas purchases	Decatherms	75	75

Credit Risk

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

Collateral and Contingent Features

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in Sierra Pacific's creditworthiness. These rights can vary by contract and by counterparty. As of June 30, 2026, Sierra Pacific's credit ratings for its senior secured debt and its issuer credit ratings for subordinated 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 $— million as of June 30, 2026, and $1 million December 31, 2025, 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.

159

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

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


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Total
As of June 30, 2026:
Assets:

Money market mutual funds	$	156	$	—	$	—	$	156
Investment funds	1		—		—		1
	$	157	$	—	$	—	$	157

Liabilities:
Commodity derivatives	$	—	$	—	$	(14)	$	(14)

As of December 31, 2025:
Assets:
Commodity derivatives	$	—	$	—	$	1	$	1
Money market mutual funds	14		—		—		14
Investment funds	1		—		—		1
	$	15	$	—	$	1	$	16

Liabilities:
Commodity derivatives	$	—	$	—	$	(12)	$	(12)

160

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Sierra Pacific transacts. When quoted prices for identical contracts are not available, Sierra Pacific uses forward price curves. Forward price curves represent Sierra Pacific's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Sierra Pacific bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Sierra Pacific uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Sierra Pacific's nonperformance risk on its liabilities, which as of June 30, 2026, and December 31, 2025, had an immaterial impact to the fair value of its derivative contracts. As such, Sierra Pacific considers its derivative contracts to be valued using Level 3 inputs.

Sierra Pacific's investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.

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


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025

Beginning balance	$	(15)	$	(19)	$	(11)	$	(13)
Changes in fair value recognized in regulatory assets	—		(3)		(4)		(10)

Settlements	1		—		1		1
Ending balance	$	(14)	$	(22)	$	(14)	$	(22)

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 June 30, 2026				As of December 31, 2025
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	2,156	$	2,152	$	1,972	$	1,967

(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.

161

Accrual for Customer Refunds

Sierra Pacific's accrual in connection with customer refunds arising from regulatory proceedings, reflecting its commitment to transparency and regulatory compliance, was $14 million as of June 30, 2026 and December 31, 2025. Sierra Pacific filed an Offer of Compromise with the PUCN in January 2026 to settle the regulatory proceedings, inclusive of the amount accrued in 2025, that was accepted by the PUCN in February 2026. Refunds were made in July 2026.

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.

(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 June 30,
	2026						2025
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Customer Revenue:
Retail:
Residential	$	88	$	14	$	102	$	80	$	15	$	95
Commercial	87		4		91		83		5		88
Industrial	70		2		72		56		2		58

Other	1		1		2		—		1		1
Total fully bundled	246		21		267		219		23		242
Distribution only service	2		—		2		2		—		2
Total retail	248		21		269		221		23		244
Wholesale, transmission and other	13		(3)		10		13		—		13
Total Customer Revenue	261		18		279		234		23		257
Other revenue	1		—		1		1		—		1
Total operating revenue	$	262	$	18	$	280	$	235	$	23	$	258

162


	Six-Month Periods
	Ended June 30,
	2026						2025
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Customer Revenue:
Retail:
Residential	$	177	$	37	$	214	$	173	$	47	$	220
Commercial	159		13		172		156		18		174
Industrial	122		4		126		104		6		110
Other	2		1		3		2		1		3
Total fully bundled	460		55		515		435		72		507
Distribution only service	4		—		4		4		—		4
Total retail	464		55		519		439		72		511
Wholesale, transmission and other	32		—		32		31		—		31
Total Customer Revenue	496		55		551		470		72		542
Other revenue	1		—		1		1		—		1
Total operating revenue	$	497	$	55	$	552	$	471	$	72	$	543

(12) Segment Information

Sierra Pacific'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. When making decisions about the allocation of resources and capital to each reportable segment, the CODM generally considers actual results versus historical results, budgets or forecasts, and state regulatory ratemaking results as well as unique risks and opportunities.

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 June 30, 2026
	Regulated Electric		Regulated Natural Gas		Total

Operating revenue	$	262	$	18	$	280
Cost of sales	127		4		131
Operations and maintenance	63		6		69
Depreciation and amortization	44		4		48
Interest expense	34		2		36
Interest and dividend income	3		—		3
Income tax expense (benefit)	(4)		1		(3)
Other segment items(1)	34		—		34
Net income	$	35	$	1	$	36

Capital expenditures	$	433	$	31	$	464

163


	For the Six-Month Period Ended June 30, 2026
	Regulated Electric		Regulated Natural Gas		Total

Operating revenue	$	497	$	55	$	552
Cost of sales	240		22		262
Operations and maintenance	130		10		140
Depreciation and amortization	84		9		93
Interest expense	62		5		67
Interest and dividend income	7		—		7
Income tax expense (benefit)	(4)		2		(2)
Other segment items(1)	63		1		64
Net income	$	55	$	8	$	63

Capital expenditures	$	668	$	47	$	715


	For the Three-Month Period Ended June 30, 2025
	Regulated Electric		Regulated Natural Gas		Total

Operating revenue	$	235	$	23	$	258
Cost of sales	110		9		119
Operations and maintenance	54		7		61
Depreciation and amortization	35		5		40
Interest expense	22		2		24
Interest and dividend income	3		—		3
Income tax expense (benefit)	3		—		3
Other segment items(1)	8		—		8
Net income	$	22	$	—	$	22

Capital expenditures	$	315	$	26	$	341


	For the Six-Month Period Ended June 30, 2025
	Regulated Electric		Regulated Natural Gas		Total

Operating revenue	$	471	$	72	$	543
Cost of sales	225		37		262
Operations and maintenance	107		14		121
Depreciation and amortization	70		10		80
Interest expense	44		4		48
Interest and dividend income	6		—		6
Income tax expense (benefit)	6		—		6
Other segment items(1)	18		(1)		17
Net income	$	43	$	6	$	49

Capital expenditures	$	474	$	40	$	514

164










	As of
		June 30,		December 31,
		2026		2025
Assets:
Regulated electric		$	7,286	$	6,541
Regulated natural gas		552		485
Regulated common assets(2)		136		19
Total assets		$	7,974	$	7,045

(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.

165

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

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

Results of Operations for the Second Quarter and First Six Months of 2026 and 2025

Overview

Net income for the second quarter of 2026 was $36 million, an increase of $14 million compared to 2025 primarily due to higher allowance for borrowed and equity funds, an increase in electric utility margin and lower tax expense. These items are partially offset by higher interest expense, higher depreciation and amortization expense and higher operations and maintenance expense. Electric utility margin increased primarily due to increased retail customer volumes, lower prior year revenue related to an accrual in connection with customer refunds arising from regulatory proceedings and higher transmission and wholesale revenue. Electric retail customer volumes, including distribution only service customers, increased by 9% primarily due to favorable usage patterns and an increase in the average number of customers. Energy generated volumes decreased 21% for the second quarter of 2026 compared to 2025 primarily due to lower coal generation. Wholesale electricity sales volumes decreased 19% and energy purchased volumes increased 42%.

Net income for the first six months of 2026 was $63 million, an increase of $14 million compared to 2025 primarily due to higher allowance for borrowed and equity funds, an increase in electric utility margin and lower tax expense. These items are partially offset by higher operations and maintenance, higher interest expense, higher depreciation and amortization expense and a decrease in gas utility margin. Electric utility margin increased primarily due to lower prior year revenue related to an accrual in connection with customer refunds arising from regulatory proceedings, increased retail customer volumes and higher transmission and wholesale revenue. Electric retail customer volumes, including distribution only service customers, increased by 6% primarily due to favorable usage patterns and an increase in the average number of customers. Natural gas utility margin decreased primarily due to the unfavorable impact of weather. Energy generated volumes decreased 8% for the first six months of 2026 compared to 2025 primarily due to lower coal generation. Wholesale electricity sales volumes decreased 17% and energy purchased volumes increased 27%.

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.

166

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


	Second Quarter								First Six Months
	2026		2025		Change				2026		2025		Change
Electric utility margin:
Operating revenue	$	262	$	235	$	27	11	%	$	497	$	471	$	26	6	%
Cost of fuel and energy	127		110		17		15		240		225		15		7
Electric utility margin	135		125		10		8	%	257		246		11		4	%

Natural gas utility margin:
Operating revenue	18		23		(5)		(22)	%	55		72		(17)		(24)	%
Natural gas purchased for resale	4		9		(5)		(56)		22		37		(15)		(41)
Natural gas utility margin	14		14		—		—	%	33		35		(2)		(6)	%

Utility margin	149		139		10		7	%	290		281		9		3	%

Operations and maintenance	69		61		8		13	%	140		121		19		16	%
Depreciation and amortization	48		40		8		20		93		80		13		16
Property and other taxes	6		6		—		—		13		12		1		8
Operating income	$	26	$	32	$	(6)	(19)	%	$	44	$	68	$	(24)	(35)	%

167

Electric Utility Margin

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


	Second Quarter								First Six Months
	2026		2025		Change				2026		2025		Change
Utility margin (in millions):
Operating revenue	$	262	$	235	$	27	11	%	$	497	$	471	$	26	6	%
Cost of fuel and energy	127		110		17		15		240		225		15		7
Utility margin	$	135	$	125	$	10	8	%	$	257	$	246	$	11	4	%

Sales (GWhs):
Residential	626		607		19		3	%	1,273		1,277		(4)		—	%
Commercial	805		799		6		1		1,524		1,510		14		1
Industrial	886		718		168		23		1,673		1,409		264		19
Other	2		2		—		—		4		4		—		—
Total fully bundled(1)	2,319		2,126		193		9		4,474		4,200		274		7
Distribution only service	743		686		57		8		1,468		1,392		76		5
Total retail	3,062		2,812		250		9		5,942		5,592		350		6
Wholesale	113		139		(26)		(19)		281		337		(56)		(17)
Total GWhs sold	3,175		2,951		224		8	%	6,223		5,929		294		5	%

Average number of retail customers (in thousands)	390		385		5		1	%	389		385		4		1	%





Average revenue per MWh:
Retail - fully bundled(1)	$	106.24	$	103.19	$	3.05	3	%	$	102.84	$	103.53	$	(0.69)	(1)	%

Wholesale	$	53.61	$	54.64	$	(1.03)	(2)	%	$	67.76	$	57.80	$	9.96	17	%

Heating degree days	526		485		41		8	%	2,223		2,609		(386)		(15)	%
Cooling degree days	315		322		(7)		(2)	%	317		322		(5)		(2)	%

Sources of energy (GWhs)(2):
Natural gas	1,076		1,096		(20)		(2)	%	2,306		2,075		231		11	%
Coal	—		264		(264)		(100)		5		437		(432)		(99)
Renewables	2		3		(1)		(33)		3		4		(1)		(25)
Total energy generated	1,078		1,363		(285)		(21)		2,314		2,516		(202)		(8)
Energy purchased	1,375		971		404		42		2,126		1,668		458		27
Total	2,453		2,334		119		5	%	4,440		4,184		256		6	%

Average cost of energy per MWh(3):
Energy generated	$	22.51	$	34.40	$	(11.89)	(35)	%	$	32.52	$	39.91	$	(7.39)	(19)	%
Energy purchased	$	74.97	$	64.50	$	10.47	16	%	$	77.66	$	74.51	$	3.15	4	%

(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.

168

Natural Gas Utility Margin

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


	Second Quarter								First Six Months
	2026		2025		Change				2026		2025		Change
Utility margin (in millions):
Operating revenue	$	18	$	23	$	(5)	(22)	%	$	55	$	72	$	(17)	(24)	%
Natural gas purchased for resale	4		9		(5)		(56)		22		37		(15)		(41)
Utility margin	$	14	$	14	$	—	—	%	$	33	$	35	$	(2)	(6)	%

Sold (000's Dths):
Residential	1,597		1,575		22		1	%	5,571		6,303		(732)		(12)	%
Commercial	873		856		17		2		2,943		3,283		(340)		(10)
Industrial	377		454		(77)		(17)		1,172		1,272		(100)		(8)
Total retail	2,847		2,885		(38)		(1)	%	9,686		10,858		(1,172)		(11)	%

Average number of retail customers (in thousands)	189		187		2		1	%	189		187		2		1	%

Average revenue per retail Dth sold	$	6.31	$	7.98	$	(1.67)	(21)	%	$	5.69	$	6.65	$	(0.96)	(14)	%

Heating degree days	526		485		41		8	%	2,223		2,609		(386)		(15)	%

Average cost of natural gas per retail Dth sold	$	1.21	$	3.00	$	(1.79)	(60)	%	$	2.21	$	3.41	$	(1.20)	(35)	%

Quarter Ended June 30, 2026, Compared to Quarter Ended June 30, 2025

Electric utility margin increased $10 million, or 8%, for the second quarter of 2026 compared to 2025 primarily due to:

•$6 million of higher electric retail utility margin primarily due to increased retail customer volumes. Retail customer volumes, including distribution only service customers, increased 8.9% primarily due to favorable customer usage patterns and an increase in the average number of customers;

•$3 million lower prior year revenue related to an accrual in connection with customer refunds arising from regulatory proceedings; and

•$2 million of higher transmission and wholesale margin primarily related to a decrease in deferred energy costs.

The increase in electric utility margin was partially offset by:

•$1 million reduction of revenue for a regulatory liability recorded for the Tracy Area Master Plan (TAMP) project as directed by the 2024 Sierra Pacific regulatory rate review.

Operations and maintenance increased $8 million, or 13%, for the second quarter of 2026 compared to 2025 primarily due to increased insurance expense due to additional wildfire coverage and higher premiums associated with third-party liability coverage, increased plant operations and maintenance, partially offset by decreased general and administrative costs primarily from decreased technology costs.

Depreciation and amortization increased $8 million, or 20%, for the second quarter of 2026 compared to 2025 primarily due to higher plant placed in-service and higher amortizations from intangible plant software.

Interest expense increased $12 million, or 50%, for the second quarter of 2026 compared to 2025 primarily due to higher long-term debt.

Allowance for borrowed and equity funds increased $25 million, for the second quarter of 2026 compared to 2025 primarily due to higher construction work-in-progress.

169

Income tax expense decreased $6 million for the second quarter of 2026 compared to 2025. The effective tax rate was (9)% and 12% for the three-month periods ended June 30, 2026 and 2025, respectively. The $6 million decrease was primarily due to higher benefits from the effects of ratemaking and higher ITCs.

First Six Months of 2026 Compared to First Six Months of 2025

Electric utility margin increased $11 million, or 4%, for the first six months of 2026 compared to 2025 primarily due to:

•$6 million of higher wholesale and transmission margin primarily related to a decrease in deferred energy costs;

•$4 million of higher electric retail utility margin primarily due to increased retail customer volumes. Retail customer volumes, including distribution only service customers, increased 6.3% primarily due to favorable customer usage patterns and an increase in the average number of customers; and

•$3 million lower prior year revenue related to an accrual in connection with customer refunds arising from regulatory proceedings.

The increase in electric utility margin was partially offset by:

•$2 million reduction of revenue for a regulatory liability recorded for the Tracy Area Master Plan (TAMP) project as directed by the 2024 Sierra Pacific regulatory rate review.

Natural gas utility margin decreased $2 million, or 6%, for the first six months of 2026 compared to 2025 primarily due to unfavorable customer usage patterns and impact of weather.

Operations and maintenance increased $19 million, or 16%, for the first six months of 2026 compared to 2025 primarily due to increased insurance expense due to additional wildfire coverage and higher premiums associated with third-party liability coverage and increased plant operations and maintenance, partially offset by decreased regulatory amortizations, decreased general and administrative costs primarily from decreased technology costs.

Depreciation and amortization increased $13 million, or 16%, for the first six months of 2026 compared to 2025 primarily due to higher plant placed in-service and higher amortizations from intangible plant software.

Interest expense increased $19 million, or 40%, for the first six months of 2026 compared to 2025 primarily due to higher long-term debt.

Allowance for borrowed and equity funds increased $45 million for the first six months of 2026 compared to 2025 primarily due to higher construction work-in-progress.

Income tax expense decreased $8 million for the first six months of 2026 compared to 2025. The effective tax rate was (3)% in 2026 and 11% in 2025. The $8 million decrease was primarily due to higher benefits from the effects of ratemaking and higher ITCs.

Liquidity and Capital Resources

As of June 30, 2026, Sierra Pacific's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	124

Credit facility, maturing 2029	400
Less:

Short-term debt	—
Net credit facility	400

Total net liquidity	$	524

170

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2026 and 2025, were $92 million and $136 million, respectively. The change was primarily due to the timing of payments for operating costs and higher payments related to fuel and energy costs, partially offset by increased collections from customers and lower interest payments.

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

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2026 and 2025, were $(710) million and $(514) 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 six-month periods ended June 30, 2026 and 2025, were $735 million and $390 million, respectively. The change was primarily due to higher proceeds from the issuance of junior subordinated debt, higher contributions from NV Energy, Inc. and higher customer receipts from contributions in aid of construction, offset by higher repayment of debt.

Debt Authorizations

Sierra Pacific currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $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. As of June 30, 2026, approximately $1.7 billion of debt capacity remains available under this authorization. Sierra Pacific currently has an effective shelf registration statement filed with the SEC to issue an additional $1.5 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 secured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Sierra Pacific has access to external financing depends on a variety of factors, including Sierra Pacific's credit ratings, investors' judgment of risk associated with Sierra Pacific and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into Sierra Pacific's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.

171

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


	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2025		2026		2026


Electric transmission	$	129	$	232	$	574
Electric distribution	88		127		293
Solar generation and electric battery storage	175		124		166
Wildfire prevention	7		11		68
Other	115		221		514
Total	$	514	$	715	$	1,615

Sierra Pacific receives PUCN approval through its IRP filings for various projects and has included estimates from IRP filings as well as potential future filings in its forecast capital expenditures for 2026. These estimates are likely to change as a result of the RFP process, continued evaluation and future IRP filing refinements. Sierra Pacific'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 totaling $180 million and $102 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for the expansion program expected to be placed in-service in 2027 and 2028 totals $305 million for the remainder of 2026. 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. Growth expenditures include spending on new customer connections totaling $30 million and $21 million for the six-month periods ended June 30, 2026 and 2025, respectively. Planned spending for new customer connections totals $31 million for the remainder of 2026.

•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 the co-located battery storage reached commercial operation in March 2026.

•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 and operating expenditures including spending for infrastructure needed to serve existing and expected demand, information technology expenditures, routine expenditures for generation and other operating projects.

2024 Joint Integrated Resource Plan

172

2025 Natural Gas Triennial Integrated Resource Plan

In October 2025, Sierra Pacific filed its 2025 Natural Gas Triennial Integrated Resource Plan (the "2025 NGIRP") with the PUCN, covering the 2026 through 2028 action plan period. The filling seeks approval of forecasted natural gas demand, ten significant operational and capital projects, the 2025 DSM Plan, and related findings regarding the reasonableness of the forecast methodology, projected demand, cost-effectiveness of proposed investments, resource mix, greenhouse gas considerations, and impacts on low-income and historically underserved communities. The application also requests authorization to establish a regulatory asset account to record costs associated with a proposed Plexco Service Tee Cap Replacement Program addressing premature failures of certain service tee caps installed between 1990 and 1996, with recovery of amounts recorded in the regulatory asset account to be sought in a future general rate case. In January 2026, Sierra Pacific filed a stipulation with the PUCN that reflected a settlement among participating parties and largely accepted the NGIRP as filed with removal of the requested regulatory asset account to record costs associated with the Plexco Service Tee CAP Replacement Program. A final order approving the stipulation was received in February 2026.

2026 Joint Triennial Integrated Resource Plan

Material Cash Requirements

As of June 30, 2026, 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, 2025, 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

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, 2025. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2025.

173

Eastern Energy Gas Holdings, LLC and its subsidiaries

Consolidated Financial Section

174

PART I

Item 1.Financial Statements


Report of Independent Registered Public Accounting Firm						176
Consolidated Balance Sheets						177
Consolidated Statements of Operations						179
Consolidated Statements of Comprehensive Income						180
Consolidated Statements of Changes in Equity						181
Consolidated Statements of Cash Flows						182
Notes to Consolidated Financial Statements
General						183
New Accounting Pronouncements						184
Property, Plant and Equipment, Net						184
R egu latory Matters						185
Investments and Restricted Cash and Cash Equivalents						185
Income Taxes						186
Employee Benefit Plans						187
Fair Value Measurements						187
Commitments and Contingencies						189
Revenue from Contracts with Customers						189
Components of Accumulated Other Comprehensive Loss, Net						190

175

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Eastern Energy Gas Holdings, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Eastern Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of June 30, 2026, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and six-month periods ended June 30, 2026 and 2025, and of cash flows for the six-month periods ended June 30, 2026 and 2025, 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, 2025, 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 27, 2026, 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, 2025, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

/s/ Deloitte & Touche LLP

Richmond, Virginia

August 7, 2026

176

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	June 30,		December 31,
	2026		2025
ASSETS
Current assets:
Cash and cash equivalents	$	126	$	80

Trade receivables, net	166		191
Receivables from affiliates	24		20
Notes receivable from affiliates	259		513
Inventories	162		155

Prepayments and other deferred charges	56		78
Natural gas imbalances	43		66
Other current assets	70		92
Total current assets	906		1,195

Property, plant and equipment, net	10,490		10,363
Goodwill	1,286		1,286

Investments	266		255

Other assets	106		98

Total assets	$	13,054	$	13,197

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

177

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	June 30,		December 31,
	2026		2025
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	123	$	87
Accounts payable to affiliates	37		27
Accrued interest	53		58
Accrued property, income and other taxes	101		141
Accrued employee expenses	32		22

Regulatory liabilities	39		46

Current portion of long-term debt	—		293
Customer deposits	28		33
Other current liabilities	14		26
Total current liabilities	427		733

Long-term debt	4,162		4,161


Regulatory liabilities	609		620
Deferred income taxes	707		621
Other long-term liabilities	130		115
Total liabilities	6,035		6,250

Commitments and contingencies (Note 9)

Equity:
Member's equity:

Membership interests	5,814		5,736


Accumulated other comprehensive loss, net	(29)		(31)
Total member's equity	5,785		5,705
Noncontrolling interests	1,234		1,242
Total equity	7,019		6,947

Total liabilities and equity	$	13,054	$	13,197

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

178

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025




Operating revenue	$	551	$	507	$	1,203	$	1,085

Operating expenses:

Cost of gas	1		1		2		1
Operations and maintenance	146		138		272		268
Depreciation and amortization	88		87		177		174
Property and other taxes	36		35		71		70

Total operating expenses	271		261		522		513

Operating income	280		246		681		572

Other income (expense):
Interest expense, net	(54)		(56)		(109)		(108)

Allowance for equity funds	4		3		8		5
Interest and dividend income	7		5		15		7

Other, net	1		2		1		2
Total other income (expense)	(42)		(46)		(85)		(94)

Income before income tax expense (benefit) and equity income (loss)	238		200		596		478
Income tax expense (benefit)	46		38		126		97
Equity income (loss)	6		5		33		31


Net income	198		167		503		412
Net income attributable to noncontrolling interests	42		37		100		82
Net income attributable to Eastern Energy Gas	$	156	$	130	$	403	$	330

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

179

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025

Net income	$	198	$	167	$	503	$	412

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


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

Comprehensive income	198		173		505		418
Comprehensive income attributable to noncontrolling interests	42		37		100		82
Comprehensive income attributable to Eastern Energy Gas	$	156	$	136	$	405	$	336

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

180

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)


			Accumulated
			Other
	Membership		Comprehensive		Noncontrolling		Total
	Interests		Loss, Net		Interests		Equity

Balance, March 31, 2025	$	5,311	$	(35)	$	1,272	$	6,548
Net income	130		—		37		167
Other comprehensive income	—		6		—		6
Distributions	—		—		(49)		(49)
Contributions	224		—		—		224
Balance, June 30, 2025	$	5,665	$	(29)	$	1,260	$	6,896

Balance, December 31, 2024	$	6,300	$	(35)	$	1,270	$	7,535
Net income	330		—		82		412
Other comprehensive income	—		6		—		6
Distributions	(1,189)		—		(92)		(1,281)
Contributions	224		—		—		224
Balance, June 30, 2025	$	5,665	$	(29)	$	1,260	$	6,896

Balance, March 31, 2026	$	5,731	$	(29)	$	1,236	$	6,938
Net income	156		—		42		198

Distributions	(146)		—		(44)		(190)
Contributions	73		—		—		73
Balance, June 30, 2026	$	5,814	$	(29)	$	1,234	$	7,019

Balance, December 31, 2025	$	5,736	$	(31)	$	1,242	$	6,947
Net income	403		—		100		503
Other comprehensive income	—		2		—		2
Distributions	(398)		—		(108)		(506)
Contributions	73		—		—		73
Balance, June 30, 2026	$	5,814	$	(29)	$	1,234	$	7,019

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

181

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Six-Month Periods
	Ended June 30,
	2026		2025
Cash flows from operating activities:
Net income	$	503	$	412
Adjustments to reconcile net income to net cash flows from operating activities:

(Gains) losses on other items, net	(15)		2
Depreciation and amortization	177		174
Allowance for equity funds	(8)		(5)
Equity (income) loss, net of distributions	(15)		(6)
Changes in regulatory assets and liabilities	(8)		(11)
Deferred income taxes	83		76
Other, net	4		3
Changes in other operating assets and liabilities:
Trade receivables and other assets	63		40
Receivables from affiliates	(4)		(6)
Gas balancing activities	(13)		3


Accrued property, income and other taxes	19		(10)
Accounts payable to affiliates	10		(7)
Accounts payable and other liabilities	(6)		20
Net cash flows from operating activities	790		685

Cash flows from investing activities:
Capital expenditures	(236)		(131)
Proceeds from assignment of shale development rights	16		—
Proceeds from sales of marketable securities	3		8
Issuance of notes receivable to affiliates	(117)		(388)
Repayment of notes receivable by affiliates	371		—


Net cash flows from investing activities	37		(511)

Cash flows from financing activities:
Proceeds from long-term debt	—		1,187
Repayment of long-term debt	(280)		—






Distributions to noncontrolling interests	(108)		(92)
Distributions to parent	(398)		(1,189)

Net cash flows from financing activities	(786)		(94)



Net change in cash and cash equivalents and restricted cash and cash equivalents	41		80
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	113		61
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	154	$	141

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

182

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 Des Moines, Iowa that has investments in subsidiaries principally engaged in energy businesses. BHE is a wholly owned subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The accompanying Consolidated Financial Statements and Notes to Consolidated Financial Statements should be read in conjunction with Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2025. The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of June 30, 2026, and for the three- and six-month periods ended June 30, 2026 and 2025. The results of operations for the three- and six-month periods ended June 30, 2026, are not necessarily indicative of the results to be expected for the full year.

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 President and Chief Executive Officer of the BHE Pipeline Group (which consists primarily of BHE GT&S, LLC ("BHE GT&S"), Northern Natural Gas Company and Kern River Gas Transmission Company). Net income attributable to Eastern Energy Gas, as reported on the Consolidated Statements of Operations, is considered by the CODM in allocating resources and capital. When making decisions about the allocation of resources and capital, the CODM generally considers actual results versus historical results, budgets or forecast, as well as unique risks and opportunities. The segment expense information regularly provided to the CODM aligns 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.

183

(2) New Accounting Pronouncements

In November 2024, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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
		June 30,		December 31,
	Depreciable Life	2026		2025
Utility plant:
Interstate natural gas transmission assets	34 - 51 years	$	6,737	$	6,599
Storage assets	47 - 79 years	2,890		2,856
Intangible plant and other assets	4 - 53 years	534		514
Utility plant in-service		10,161		9,969
Accumulated depreciation and amortization		(3,646)		(3,555)
Utility plant in-service, net		6,515		6,414

Nonutility plant:

LNG facility	40 years	4,588		4,585
Accumulated depreciation and amortization		(965)		(901)
Nonutility plant, net		3,623		3,684

		10,138		10,098
Construction work-in-progress		352		265
Property, plant and equipment, net		$	10,490	$	10,363

Construction work-in-progress includes $341 million and $255 million as of June 30, 2026 and December 31, 2025, respectively, related to the construction of utility plant.

Assignment of Shale Development Rights

In September 2025, Eastern Gas Transmission and Storage, Inc. ("EGTS") signed an agreement to convey development rights over time to a natural gas producer for approximately 23,000 acres of Utica Shale and Point Pleasant formations underneath one of its natural gas storage fields. The agreement provides for payments to EGTS of approximately $49 million over a period of three years, and an overriding royalty interest in gas produced from the acreage. In January 2026, EGTS conveyed approximately 7,600 acres and received proceeds of $16 million from the initial conveyance. This transaction resulted in a $16 million ($12 million after-tax) gain recorded in operations and maintenance expense in its Consolidated Statements of Operations.

184

(4) Regulatory Matters

(5) Investments and Restricted Cash and Cash Equivalents

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


	As of
	June 30,		December 31,
	2026		2025
Investments:
Investment funds	$	5	$	8


Equity method investments:
Iroquois	261		247




Restricted cash and cash equivalents:
Customer deposits	28		33


Total investments and restricted cash and cash equivalents	$	294	$	288

Reflected as:
Other current assets	$	28	$	33
Noncurrent assets	266		255
Total investments and restricted cash and cash equivalents	$	294	$	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 June 30, 2026, and December 31, 2025, 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 $18 million and $25 million for the six-month periods ended June 30, 2026 and 2025, respectively.

185

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

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


	As of
	June 30,		December 31,
	2026		2025

Cash and cash equivalents	$	126	$	80
Restricted cash and cash equivalents included in other current assets	28		33
Total cash and cash equivalents and restricted cash and cash equivalents	$	154	$	113

(6) Income Taxes

Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return and BHE includes its subsidiaries in certain state income tax returns. 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 pursuant to a tax allocation agreement. For current federal and state income taxes, Eastern Energy Gas had a payable to BHE of $10 million and $39 million as of June 30, 2026 and December 31, 2025, respectively. Pursuant to a tax allocation agreement, BHE GT&S makes cash payments for income taxes, net of refunds, on behalf of Eastern Energy Gas for federal income taxes and certain state income taxes. Eastern Energy Gas received net non-cash equity contributions from BHE GT&S for federal income taxes and certain state income taxes totaling $73 million and $224 million for the six-month periods ended June 30, 2026 and 2025, respectively.

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 (amounts in millions):


	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2026				2025				2026				2025
	Amount		Percent		Amount		Percent		Amount		Percent		Amount		Percent

U.S. federal statutory income tax rate	$	50	21.0	%	$	42	21.0	%	$	125	21.0	%	$	100	21.0	%
State and local income taxes, net of federal income tax	5		2.0		2		1.5		17		2.8		8		1.7


Nontaxable or nondeductible items:
Equity earnings	1		0.5		2		0.5		7		1.2		7		1.4
Non-controlling interest	(9)		(3.7)		(8)		(4.0)		(21)		(3.5)		(17)		(3.6)
Other, net	—		—		—		—		(1)		(0.1)		—		—






Other adjustments	(1)		(0.5)		—		—		(1)		(0.3)		(1)		(0.2)
Effective income tax rate	$	46	19.3	%	$	38	19.0	%	$	126	21.1	%	$	97	20.3	%

186

(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 $3 million to the MidAmerican Energy Company Retirement Plan for each of the six-month periods ended June 30, 2026 and 2025. Contributions related to these plans are reflected as net periodic benefit cost in operations and maintenance expense on the Consolidated Statements of Operations. Amounts attributable to Eastern Energy Gas were allocated from MidAmerican Energy in accordance with the intercompany administrative service agreement. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net. As of June 30, 2026, and December 31, 2025, 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.

(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 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.

187

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


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Total
As of June 30, 2026:
Assets:


Money market mutual funds	$	126	$	—	$	—	$	126
Equity securities:
Investment funds	5		—		—		5
	$	131	$	—	$	—	$	131







As of December 31, 2025:
Assets:
Foreign currency exchange rate derivatives	$	—	$	11	$	—	$	11
Money market mutual funds	80		—		—		80
Equity securities:
Investment funds	8		—		—		8
	$	88	$	11	$	—	$	99

Eastern Energy Gas' investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.

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

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 June 30, 2026				As of December 31, 2025
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	4,162	$	3,953	$	4,454	$	4,276

188

(9) Commitments and Contingencies

Environmental Laws and Regulations

Legal Matters

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

(10) Revenue from Contracts with Customers

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


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025
Customer Revenue:
Regulated:
Gas transmission and storage	$	301	$	285	$	640	$	617
Wholesale	—		—		2		1

Total regulated	301		285		642		618




Nonregulated	247		222		552		466
Total Customer Revenue	548		507		1,194		1,084
Other revenue(1)	3		—		9		1
Total operating revenue	$	551	$	507	$	1,203	$	1,085

(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 $30 million and $43 million as of June 30, 2026, and December 31, 2025, respectively, due to the relationship between Eastern Energy Gas' performance and the customer's payment. Eastern Energy Gas recognizes revenue as it fulfills its obligations to provide services to its customers. During the six-month periods ended June 30, 2026 and 2025, Eastern Energy Gas recognized revenue of $17 million and $12 million, respectively, from the beginning contract liability balances.

Remaining Performance Obligations

The following table summarizes Eastern Energy Gas' revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of June 30, 2026 (in millions):


	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total

Eastern Energy Gas	$	1,878	$	12,789	$	14,667

189

(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, 2024	$	(2)	$	(34)	$	1	$	(35)
Other comprehensive income	1		5		—		6
Balance, June 30, 2025	$	(1)	$	(29)	$	1	$	(29)

Balance, December 31, 2025	$	(1)	$	(31)	$	1	$	(31)
Other comprehensive (loss) income	(1)		3		—		2

Balance, June 30, 2026	$	(2)	$	(28)	$	1	$	(29)

190

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

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

Results of Operations for the Second Quarter and First Six Months of 2026 and 2025

Overview

Net income attributable to Eastern Energy Gas for the second quarter of 2026 was $156 million, an increase of $26 million compared to 2025. Net income increased primarily due to higher margin from regulated gas transmission and storage operations of $17 million and higher earnings from Cove Point of $10 million.

Net income attributable to Eastern Energy Gas for the first six months of 2026 was $403 million, an increase of $73 million compared to 2025. Net income increased primarily due to higher earnings from Cove Point of $42 million, largely due to an increase in variable revenue, higher margin from regulated gas transmission and storage operations of $33 million and a gain from an agreement to convey development rights underneath one of its natural gas storage fields.

Quarter Ended June 30, 2026, Compared to Quarter Ended June 30, 2025

Operating revenue increased $44 million, or 9%, for the second quarter of 2026 compared to 2025, primarily due to an increase in Cove Point LNG variable revenue of $20 million, higher regulated gas transmission and storage services revenue of $11 million, largely from additional capacity contracts, and an increase in variable revenue related to park and loan activity of $6 million.

Operations and maintenance increased $8 million, or 6%, for the second quarter of 2026 compared to 2025, primarily due to higher plant operations and maintenance costs of $6 million and an increase in services provided to affiliates of $4 million (largely offset in operating revenue), partially offset by lower employee costs of $4 million.

Income tax expense increased $8 million, or 21%, for the second quarter of 2026 compared to 2025. The effective tax rate was 19% for each of the three-month periods ended June 30, 2026 and 2025. The $8 million increase was primarily due to higher pre-tax income and higher state income taxes.

Net income attributable to noncontrolling interests increased $5 million, or 14%, for the second quarter of 2026 compared to 2025, primarily due to higher net income attributable to Cove Point.

First Six Months of 2026 Compared to First Six Months of 2025

Operating revenue increased $118 million, or 11%, for the first six months of 2026 compared to 2025, primarily due to an increase in Cove Point LNG variable revenue of $79 million, largely due to higher volumes and higher prices from extremely cold weather in the first quarter of 2026, higher regulated gas transmission and storage services revenue of $14 million, primarily due to additional capacity contracts, and an increase in variable revenue related to park and loan activity of $10 million.

Operations and maintenance increased $4 million, or 1%, for the first six months of 2026 compared to 2025, primarily due to higher plant operations and maintenance costs of $9 million, an increase in services provided to affiliates of $6 million (largely offset in operating revenue) and an increase in charges from affiliates of $5 million, partially offset by a gain from an agreement to convey development rights underneath one of its natural gas storage fields of $16 million.

Interest and dividend income increased $8 million for the first six months of 2026 compared to 2025, primarily due to higher lending activity under BHE GT&S' intercompany revolving credit agreement.

Income tax expense increased $29 million, or 30%, for the first six months of 2026 compared to 2025. The effective tax rate was 21% and 20% for the six-month periods ended June 30, 2026 and 2025, respectively. The $29 million increase was primarily due to higher pre-tax income and higher state income taxes.

191

Net income attributable to noncontrolling interests increased $18 million, or 22%, for the first six months of 2026 compared to 2025, primarily due to higher net income attributable to Cove Point.

Liquidity and Capital Resources

As of June 30, 2026, Eastern Energy Gas' total net liquidity was as follows (in millions):


Cash and cash equivalents	$	126

Intercompany revolving credit agreement, maturing 2027	400




Total net liquidity	$	526

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2026 and 2025 were $790 million and $685 million, respectively. The change is primarily due to favorable operating results, the timing of payments for operating costs and other working capital adjustments, partially offset by higher cash paid for interest and lower distributions from Iroquois.

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2026 and 2025 were $37 million and $(511) million, respectively. The change is primarily due to repayments of notes by its parent under an intercompany revolving credit agreement of $371 million, a decrease in notes issued to its parent under an intercompany revolving credit agreement of $271 million and proceeds from the assignment of shale development rights of $16 million, partially offset by an increase in capital expenditures of $105 million and a decrease in proceeds from sales of marketable securities of $5 million.

Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2026 were $(786) million and consisted of distributions to its indirect parent, BHE, of $398 million, repayment of long-term debt of $280 million and distributions to noncontrolling interests from Cove Point of $108 million.

Net cash flows from financing activities for the six-month period ended June 30, 2025 were $(94) 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 $92 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.

192

Capital Expenditures

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

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


	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2025		2026		2026

Natural gas transmission and storage	$	27	$	72	$	160
Other	104		164		467
Total	$	131	$	236	$	627

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 June 30, 2026, 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, 2025.

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, 2025. There have been no significant changes in Eastern Energy Gas' assumptions regarding critical accounting estimates since December 31, 2025.

193

Eastern Gas Transmission and Storage, Inc. and its subsidiaries

Consolidated Financial Section

194

PART I

Item 1.Financial Statements


Report of Independent Registered Public Accounting Firm						196
Consolidated Balance Sheets						197
Consolidated Statements of Operations						199
Consolidated Statements of Comprehensive Income						200
Consolidated Statements of Changes in Shareholder's Equity						201
Consolidated Statements of Cash Flows						202
Notes to Consolidated Financial Statements
General						203
New Accounting Pronouncements						203
Property, Plant and Equipment, Net						203
R egula tory M atters						204

Investments and Restricted Cash and Cash Equivalents						205

Income Taxes						206
Employee Benefit Plans						206
Fair Value Measurements						206
Commitments and Contingencies						208
Revenue from Contracts with Customers						208

195

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Eastern Gas Transmission and Storage, Inc.

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Eastern Gas Transmission and Storage, Inc. and subsidiaries ("EGTS") as of June 30, 2026, the related consolidated statements of operations, comprehensive income, and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2026 and 2025, and of cash flows for the six-month periods ended June 30, 2026 and 2025, 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, 2025, 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 27, 2026 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, 2025, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

/s/ Deloitte & Touche LLP

Richmond, Virginia

August 7, 2026

196

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	June 30,		December 31,
	2026		2025
ASSETS
Current assets:
Cash and cash equivalents	$	18	$	10
Restricted cash and cash equivalents	24		29
Trade receivables, net	70		97
Receivables from affiliates	9		5
Notes receivable from affiliates	244		131
Inventories	62		58

Prepayments and other deferred charges	31		30
Natural gas imbalances	40		73
Other current assets	18		24
Total current assets	516		457

Property, plant and equipment, net	5,104		4,909



Other assets	64		61

Total assets	$	5,684	$	5,427

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

197

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions, except share data)


	As of
	June 30,		December 31,
	2026		2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	101	$	57
Accounts payable to affiliates	27		20

Accrued property, income and other taxes	68		75
Accrued employee expenses	26		19

Regulatory liabilities	16		19
Customer deposits	24		29


Other current liabilities	24		33
Total current liabilities	286		252

Long-term debt	1,624		1,623
Regulatory liabilities	503		514
Deferred income taxes	211		167
Other long-term liabilities	78		77
Total liabilities	2,702		2,633

Commitments and contingencies (Note 9)

Shareholder's equity:
Common stock - 75,000 shares authorized, $10,000 par value, 60,101 issued and outstanding	609		609
Additional paid-in capital	1,409		1,380
Retained earnings	987		829
Accumulated other comprehensive loss, net	(23)		(24)
Total shareholder's equity	2,982		2,794

Total liabilities and shareholder's equity	$	5,684	$	5,427

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

198

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025

Operating revenue	$	246	$	229	$	535	$	504

Operating expenses:
Cost of gas	1		1		2		1
Operations and maintenance	95		95		176		184
Depreciation and amortization	40		40		81		80
Property and other taxes	15		15		30		29
Total operating expenses	151		151		289		294

Operating income	95		78		246		210

Other income (expense):
Interest expense, net	(18)		(17)		(35)		(35)

Allowance for equity funds	5		2		8		4

Other, net	3		4		6		5
Total other income (expense)	(10)		(11)		(21)		(26)

Income before income tax expense (benefit)	85		67		225		184
Income tax expense (benefit)	21		17		55		46
Net income	$	64	$	50	$	170	$	138

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

199

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025

Net income	$	64	$	50	$	170	$	138

Other comprehensive income, net of tax:
Unrealized gains on cash flow hedges, net of tax of $—, $—, $— and $—	—		1		1		1

Total other comprehensive income, net of tax	—		1		1		1
Comprehensive income	$	64	$	51	$	171	$	139

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

200

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

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

(Amounts in millions, except shares)


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

Balance, March 31, 2025	60,101	$	609	$	1,352	$	759	$	(26)	$	2,694
Net income	—	—		—		50		—		50
Other comprehensive income	—	—		—		—		1		1

Contributions	—	—		24		—		—		24

Balance, June 30, 2025	60,101	$	609	$	1,376	$	809	$	(25)	$	2,769

Balance, December 31, 2024	60,101	$	609	$	1,352	$	671	$	(26)	$	2,606
Net income	—	—		—		138		—		138
Other comprehensive income	—	—		—		—		1		1

Contributions	—	—		24		—		—		24
Balance, June 30, 2025	60,101	$	609	$	1,376	$	809	$	(25)	$	2,769

Balance, March 31, 2026	60,101	$	609	$	1,380	$	923	$	(23)	$	2,889
Net income	—	—		—		64		—		64


Contributions	—	—		29		—		—		29

Balance, June 30, 2026	60,101	$	609	$	1,409	$	987	$	(23)	$	2,982

Balance, December 31, 2025	60,101	$	609	$	1,380	$	829	$	(24)	$	2,794
Net income	—	—		—		170		—		170
Other comprehensive income	—	—		—		—		1		1
Dividends declared	—	—		—		(12)		—		(12)
Contributions	—	—		29		—		—		29

Balance, June 30, 2026	60,101	$	609	$	1,409	$	987	$	(23)	$	2,982

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

201

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Six-Month Periods
	Ended June 30,
	2026		2025
Cash flows from operating activities:
Net income	$	170	$	138
Adjustments to reconcile net income to net cash flows from operating activities:
Gains on other items, net	(17)		—
Depreciation and amortization	81		80
Allowance for equity funds	(8)		(4)
Changes in regulatory assets and liabilities	(1)		(7)
Deferred income taxes	42		37
Other, net	2		—
Changes in other operating assets and liabilities:
Trade receivables and other assets	39		24
Receivables from affiliates	(4)		(7)
Gas balancing activities	(10)		5

Accrued property, income and other taxes	1		(5)
Accounts payable to affiliates	7		(5)
Accounts payable and other liabilities	9		(6)
Net cash flows from operating activities	311		250

Cash flows from investing activities:
Capital expenditures	(202)		(98)
Proceeds from assignment of shale development rights	16		—

Proceeds from sales of marketable securities	3		8
Issuance of notes receivable to affiliates	(164)		(153)
Repayment of notes receivable by affiliates	51		—

Net cash flows from investing activities	(296)		(243)

Cash flows from financing activities:







Dividends paid	(12)		—


Net cash flows from financing activities	(12)		—



Net change in cash and cash equivalents and restricted cash and cash equivalents	3		7
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	39		32
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	42	$	39

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

202

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 Des Moines, Iowa that has investments in subsidiaries principally engaged in energy businesses. BHE is a wholly owned subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The accompanying Consolidated Financial Statements and Notes to Consolidated Financial Statements should be read in conjunction with EGTS' Annual Report on Form 10-K for the year ended December 31, 2025. The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of June 30, 2026, and for the three- and six-month periods ended June 30, 2026 and 2025. The results of operations for the three- and six-month periods ended June 30, 2026, are not necessarily indicative of the results to be expected for the full year.

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 President and Chief Executive Officer of the BHE Pipeline Group (which consists primarily of BHE GT&S, LLC ("BHE GT&S"), Northern Natural Gas Company and Kern River Gas Transmission Company). Net income, as reported on the Consolidated Statements of Operations, is considered by the CODM in allocating resources and capital. When making decisions about the allocation of resources and capital, the CODM generally considers actual results versus historical results, budgets or forecast, as well as unique risks and opportunities. The segment expense information regularly provided to the CODM aligns 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 November 2024, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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.

203

(3) Property, Plant and Equipment, Net

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


		As of
		June 30,		December 31,
	Depreciable Life	2026		2025

Interstate natural gas transmission assets	47 - 51 years	$	5,336	$	5,213
Storage assets	47 - 51 years	1,910		1,884
Intangible plant and other assets	12 - 53 years	426		408
Plant in-service		7,672		7,505
Accumulated depreciation and amortization		(2,890)		(2,824)
		4,782		4,681










Construction work-in-progress		322		228
Property, plant and equipment, net		$	5,104	$	4,909

Assignment of Shale Development Rights

In September 2025, EGTS signed an agreement to convey development rights over time to a natural gas producer for approximately 23,000 acres of Utica Shale and Point Pleasant formations underneath one of its natural gas storage fields. The agreement provides for payments to EGTS of approximately $49 million over a period of three years, and an overriding royalty interest in gas produced from the acreage. In January 2026, EGTS conveyed approximately 7,600 acres and received proceeds of $16 million from the initial conveyance. This transaction resulted in a $16 million ($12 million after-tax) gain recorded in operations and maintenance expense in its Consolidated Statements of Operations.

(4) Regulatory Matters

204

(5) Investments and Restricted Cash and Cash Equivalents

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


	As of
	June 30,		December 31,
	2026		2025
Investments:
Investment funds	$	5	$	8


Restricted cash and cash equivalents:
Customer deposits	24		29


Total investments and restricted cash and cash equivalents	$	29	$	37

Reflected as:
Current assets	$	24	$	29
Other assets	5		8
Total investments and restricted cash and cash equivalents	$	29	$	37

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

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


	As of
	June 30,		December 31,
	2026		2025

Cash and cash equivalents	$	18	$	10
Restricted cash and cash equivalents	24		29
Total cash and cash equivalents and restricted cash and cash equivalents	$	42	$	39

205

(6) Income Taxes

Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return and BHE includes its subsidiaries in certain state income tax returns. Consistent with established regulatory practice, EGTS' provision for federal and state income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE pursuant to a tax allocation agreement. For current federal and state income taxes, EGTS had a receivable from BHE of $8 million as of June 30, 2026 and a payable to BHE of $11 million as of December 31, 2025. Pursuant to a tax allocation agreement, BHE GT&S makes cash payments for income taxes, net of refunds, on behalf of EGTS for federal income taxes and certain state income taxes. EGTS received net non-cash equity contributions from Eastern Energy Gas for federal income taxes and certain state income taxes totaling $29 million and $24 million for the six-month periods ended June 30, 2026 and 2025, respectively.

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 (amounts in millions):


	Three-Month Periods								Six-Month Periods
	Ended June 30,								Ended June 30,
	2026				2025				2026				2025
	Amount		Percent		Amount		Percent		Amount		Percent		Amount		Percent

U.S. federal statutory income tax rate	$	18	21.0	%	$	14	21.0	%	$	47	21.0	%	$	38	21.0	%
State and local income taxes, net of federal income tax	3		3.7		3		4.4		8		3.4		8		4.0













Effective income tax rate	$	21	24.7	%	$	17	25.4	%	$	55	24.4	%	$	46	25.0	%

(7) 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 $2 million to the MidAmerican Energy Company Retirement Plan for each of the six-month periods ended June 30, 2026 and 2025. Contributions related to these plans are reflected as net periodic benefit cost in operations and maintenance expense on the Consolidated Statements of Operations. Amounts attributable to EGTS were allocated from MidAmerican Energy in accordance with the intercompany administrative service agreement. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. As of June 30, 2026, and December 31, 2025, EGTS' amount due to MidAmerican Energy associated with these plans and included in other long-term liabilities on the Consolidated Balance Sheets was $36 million and $35 million, respectively.

(8) Fair Value Measurements

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

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

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

206

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


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Total
As of June 30, 2026:
Assets:

Money market mutual funds	$	18	$	—	$	—	$	18
Equity securities:
Investment funds	5		—		—		5
	$	23	$	—	$	—	$	23







As of December 31, 2025:
Assets:


Money market mutual funds	$	10	$	—	$	—	$	10
Equity securities:
Investment funds	8		—		—		8
	$	18	$	—	$	—	$	18

EGTS' investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.

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

EGTS' long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of EGTS' long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The following table presents the carrying value and estimated fair value of EGTS' long-term debt (in millions):


	As of June 30, 2026				As of December 31, 2025
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	1,624	$	1,438	$	1,623	$	1,442

207

(9) Commitments and Contingencies

Environmental Laws and Regulations

Legal Matters

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

(10) Revenue from Contracts with Customers

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


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2026		2025		2026		2025
Customer Revenue:
Regulated:
Gas transmission	$	155	$	146	$	350	$	336
Gas storage	71		71		142		142
Wholesale	—		—		2		1

Total regulated	226		217		494		479
Management service and other revenues	17		12		32		24
Total Customer Revenue	243		229		526		503
Other revenue(1)	3		—		9		1
Total operating revenue	$	246	$	229	$	535	$	504

Remaining Performance Obligations

The following table summarizes EGTS' revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of June 30, 2026 (in millions):


	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total

EGTS	$	926	$	2,677	$	3,603

208

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

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

Results of Operations for the Second Quarter and First Six Months of 2026 and 2025

Overview

Net income for the second quarter of 2026 was $64 million, an increase of $14 million compared to 2025. Net income increased primarily due to higher margin from regulated gas transmission and storage operations of $17 million.

Net income for the first six months of 2026 was $170 million, an increase of $32 million compared to 2025. Net income increased primarily due to higher margin from regulated gas transmission and storage operations of $30 million and a gain from an agreement to convey development rights underneath one of its natural gas storage fields.

Quarter Ended June 30, 2026, Compared to Quarter Ended June 30, 2025

Operating revenue increased $17 million, or 7%, for the second quarter of 2026 compared to 2025, primarily due to an increase in variable revenue related to park and loan activity of $6 million, an increase in services provided to affiliates of $6 million, an increase in royalties and other contingent fees from farmout agreements of $3 million and an increase in regulated gas transmission and storage services revenue of $3 million, primarily due to additional capacity contracts.

Operations and maintenance was flat for the second quarter of 2026 compared to 2025, primarily due to an increase in services provided to affiliates of $6 million, partially offset by lower employee costs of $4 million and lower plant operations and maintenance costs of $2 million.

Income tax expense increased $4 million, or 24%, for the second quarter of 2026 compared to 2025. The effective tax rate was 25% for each of the three-month periods ended June 30, 2026 and 2025. The $4 million increase was primarily due to higher pre-tax income.

First Six Months of 2026 Compared to First Six Months of 2025

Operating revenue increased $31 million, or 6%, for the first six months of 2026 compared to 2025, primarily due to an increase in variable revenue related to park and loan activity of $10 million, an increase in royalties and other contingent fees from farmout agreements of $8 million, an increase in services provided to affiliates of $8 million and an increase in regulated gas transmission and storage services revenue of $5 million, primarily due to additional capacity contracts.

Operations and maintenance decreased $8 million, or 4%, for the first six months of 2026 compared to 2025, primarily due to a gain from an agreement to convey development rights underneath one of its natural gas storage fields of $16 million and lower employee costs of $2 million, partially offset by an increase in services provided to affiliates of $8 million and an increase in charges from affiliates of $4 million.

Income tax expense increased $9 million, or 20%, for the first six months of 2026 compared to 2025. The effective tax rate was 24% and 25% for the six-month periods ended June 30, 2026 and 2025, respectively. The $9 million increase was primarily due to higher pre-tax income.

Liquidity and Capital Resources

As of June 30, 2026, EGTS' total net liquidity was as follows (in millions):


Cash and cash equivalents	$	18

Intercompany revolving credit agreement, maturing 2027	400





Total net liquidity	$	418

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Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2026 and 2025 were $311 million and $250 million, respectively. The change is primarily due to the timing of payments for operating costs, favorable operating results and higher collections from customers, partially offset by other working capital adjustments.

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2026 and 2025 were $(296) million and $(243) million, respectively. The change is primarily due to an increase in capital expenditures of $104 million, an increase in notes issued to Eastern Energy Gas under an intercompany revolving credit agreement of $11 million and a decrease in proceeds from sales of marketable securities of $5 million, partially offset by an increase in repayments of notes by Eastern Energy Gas under an intercompany revolving credit agreement of $51 million and proceeds from the assignment of shale development rights of $16 million.

Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2026 were $(12) million and consisted of dividends paid to Eastern Energy Gas.

Future Uses of Cash

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

Capital Expenditures

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


	Six-Month Periods				Annual
	Ended June 30,				Forecast
	2025		2026		2026

Natural gas transmission and storage	$	24	$	72	$	158
Other	74		130		383
Total	$	98	$	202	$	541

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.

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Material Cash Requirements

As of June 30, 2026, 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, 2025.

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, 2025. There have been no significant changes in EGTS' assumptions regarding critical accounting estimates since December 31, 2025.

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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, 2025. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2025. Refer to Note 10 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 June 30, 2026.

Item 4.Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q, each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company, Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. carried out separate evaluations, under the supervision and with the participation of each such entity's management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended). Based upon these evaluations, management of each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures for such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended June 30, 2026, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

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PART II

Item 1.Legal Proceedings

The following disclosures reflect material updates to legal proceedings and should be read in conjunction with Item 3 of Berkshire Hathaway Energy's and PacifiCorp's Annual Reports on Form 10-K for the year ended December 31, 2025.

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP

In September 2020, a severe weather event with high winds contributed to several major wildfires, including the 2020 Wildfires, resulting 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, 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 Siskiyou County, California, within 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 related to the Wildfires have been filed in Oregon and California, including the James class action complaint in Oregon associated with the 2020 Wildfires for which certain jury verdicts were issued as described below. The James case is the most significant remaining litigation related to the Wildfires and concerns four Oregon fires hundreds of miles apart: the Beachie Creek Fire (which spread into the Santiam Canyon), the Echo Mountain Complex Fire, the South Obenchain Fire, and the 242 Fire.

The following map illustrates the general vicinity of the Wildfires.

Wildfires map (screenclip with scale).jpg

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Investigations

Both the U.S. Department of Agriculture Forest Service ("USFS") and the Oregon Department of Forestry ("ODF") completed investigation reports related to the Beachie Creek Fire that was first reported outside the Santiam Canyon on August 16, 2020, approximately three weeks before the severe weather event described above. The ODF's report concerning the Beachie Creek Fire 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 PacifiCorp's power lines ignited seven spot fires within the Santiam Canyon that were each suppressed.

Wildfire Settlements

PacifiCorp has settled various claims associated with the Wildfires as described below and has settled all wrongful death claims and federal government demands and complaints associated with the Wildfires. For the Archie Creek Fire, Slater Fire and 2022 McKinney Fire, settlements have been reached with substantially all plaintiffs. For the Santiam Canyon, Echo Mountain Complex, South Obenchain and 242 fires, while PacifiCorp has settled claims with individual plaintiffs who were granted substitution of counsel in the James case, with the Oregon wineries and with the federal government as described below, claims remain outstanding for a substantial number of plaintiffs associated with the James case.

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 $2,016 million, including $614 million associated with the James related fires for plaintiffs who opted out of the James class, plaintiffs granted substitution counsel in the James case, Oregon wineries, insurance subrogation claims and for plaintiffs in certain of the James consolidated cases and $535 million associated with the federal government demands settled in February 2026. For more information, refer to description of the 2020 Wildfires complaints and specific wildfires below.

2022 McKinney Fire

2020 Oregon Wildfires, Excluding the Northern California and Southern Oregon Slater Fire ("Slater Fire")

A significant number of complaints on behalf of plaintiffs associated with the 2020 Wildfires were filed in Oregon. Although many of these complaints have been resolved and dismissed, a significant portion remain outstanding relating to the James case as described below. 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. The plaintiffs generally demand a trial by jury and reserve their right to further amend their complaints to allege claims for punitive damages.

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The James Case

Following the Phase I liability verdict, 1,760 James class members filed nine separate mass complaints from April 2024 through January 2026 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, Philip Estes et al. v. PacifiCorp and Stephen Becker et al. v. PacifiCorp, respectively, each premised on the Phase I liability verdict and referencing the original James case as the lead case. The James mass complaints make damages-only allegations seeking for each individual class member $5 million of economic damages, $25 million of noneconomic damages and punitive damages equal to 0.25 times the amount of economic and noneconomic damages, as well as doubling of economic damages. Complaints for some of the plaintiffs in the mass complaints have been dismissed, amended or re-filed.

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In May and June 2026, plaintiffs' counsel filed motions with the Multnomah County Circuit Court Oregon for substitution of lead counsel in the James case for approximately 250 plaintiffs, certain of which are scheduled for stayed trials under CMO No. 11.

James Consolidated Cases

The following cases have been stayed pending consolidation into the original James case:

The amended Salter complaint was filed August 20, 2021, in Multnomah County Circuit Court Oregon by approximately 97 individuals seeking damages similar to those described above, including economic damages not to exceed $150 million and noneconomic damages not to exceed $500 million. A portion of these plaintiffs are included in the James mass complaints and either already have verdicts or had trials scheduled under CMO No. 11 (before the recent stay). The Salter case is currently stayed due to plaintiffs' motion to consolidate the case into James.

The amended Allen complaint was filed September 2, 2021, in Multnomah County Circuit Court Oregon by approximately five individuals seeking damages similar to those described above, including $8 million in economic damages and $24 million in noneconomic damages related to the Beachie Creek Fire. All five of these plaintiffs are included in the James mass complaints and either already have verdicts or had trials scheduled under CMO No. 11 (before the recent stay). The Allen case is currently stayed due to plaintiffs' motion to consolidate the case into James.

The amended Dietrich complaint was filed September 6, 2022, in Multnomah County Circuit Court Oregon by six Oregon residents individually and on behalf of a proposed 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 on behalf of the proposed class. The Dietrich case is currently stayed due to plaintiffs' motion to consolidate the case into James.

The Bell complaint was filed September 7, 2022, in Multnomah County Circuit Court Oregon by 59 plaintiffs seeking $35 million in damages, including economic and noneconomic damages. A portion of these plaintiffs had trials scheduled under CMO No. 11 (before the recent stay). The Bell case is currently stayed due to plaintiffs' motion to consolidate the case into James.

Ashley Andersen et al. v. PacifiCorp and Consolidated Cases

As a result of settlements reached in 2024 for the Andersen et al. v. PacifiCorp consolidated cases, the complaints have been resolved but for one remaining plaintiff from the consolidated Weathers complaint. The Weathers complaint was filed September 1, 2022, in Multnomah County Circuit Court Oregon by approximately 46 plaintiffs seeking damages associated with the Echo Mountain Complex fires, including economic damages of approximately $83 million and noneconomic damages of approximately $83 million.

Other Cases

In April 2026, the Lexington and Ace American Insurance Co. complaints were fully dismissed as a result of the Rock Creek Fish Hatchery settlement described below under "State of Oregon – Loss and Damages to State Lands – Oregon Fires." These complaints were filed against PacifiCorp in Douglas County Circuit Court Oregon in 2022 and were previously partially dismissed following settlement with subrogation insurers across 2022, 2023 and early 2024.

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State of Oregon – Loss and Damages to State Lands – Oregon Fires

In 2023, PacifiCorp 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 November 2025, PacifiCorp reached settlement for the Rock Creek Fish Hatchery component of this matter.

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 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 Complex and Kimberling Mountain fires.

On May 5, 2025, PacifiCorp received a demand from the Oregon State Fire Marshal for $5 million in fire suppression costs associated with the Slater Fire.

PacifiCorp is actively cooperating with the ODOJ on resolving the alleged claims.

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 as described below. Certain complaints included wrongful death claims associated with 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. Additional complaints associated with the 2022 McKinney Fire were filed and subsequently consolidated into the Bridges case, covering approximately 1,200 plaintiffs, including wrongful death claims. To date, settlements have been reached with substantially all the plaintiffs associated with the 2022 McKinney Fire, including all wrongful death claims. 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. No trials are scheduled for the remaining 2022 McKinney Fire plaintiffs.

On July 25, 2025, a complaint against PacifiCorp was filed, captioned California Department of Transportation v. PacifiCorp, ("Caltrans") in Siskiyou Superior Court California alleging negligence and seeking damages of less than $1 million. The Caltrans complaint was settled in March 2026, and was subsequently dismissed.

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, 2025.

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

Item 3.Defaults Upon Senior Securities

Not applicable.

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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


4.1			Twenty-Ninth Supplemental Indenture, dated as of July 23 , 2026, by and between AltaLink, L.P., AltaLink Management Ltd., and Computer share Advantage Trust of Canada , as trustee, relating to the C$350,000,000 in principal amount of the 5.111% Series 2026-1 Senior Secured Notes due 2056.

10.1			Fourth Amendment to the $3,500,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, 2026, 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 (redacted).

15.1			Awareness Letter of Independent Registered Public Accounting Firm.

31.1			Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2			Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1			Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2			Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

PACIFICORP


15.2			Awareness Letter of Independent Registered Public Accounting Firm.

31.3			Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4			Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.3			Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.4			Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP


4.2			Thirty-Seventh Supplemental Indenture, dated as of March 1, 2026, to the Mortgage and Deed of Trust dated as of January 9, 1989 between PacifiCorp and the Bank of New York Mellon Trust Company, N.A., as successor Trustee (incorporated by reference to Exhibit 4.1 to the PacifiCorp Current Report on Form 8-K dated March 25, 2026).

10.2			Letter of Credit Agreement, dated April 3, 2026, by and among PacifiCorp, PNC Bank, National Association, as administrative agent, the issuing banks party thereto from time to time, and PNC Capital Markets LLC, as lead arranger (incorporated by reference to Exhibit 10.1 to the PacifiCorp Current Report on Form 8-K dated April 6, 2026).

10.3			Amendment No. 1 to the Letter of Credit Agreement, dated May 18, 2026, by and among PacifiCorp, PNC Bank, National Association, as administrative agent, the issuing banks party thereto from time to time, and PNC Capital Markets LLC, as lead arranger.

10.4			Fourth Amendment to the $3,000,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, 2026, 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 (redacted).

95			Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act.

219


Exhibit No.			Description

MIDAMERICAN ENERGY


15.3			Awareness Letter of Independent Registered Public Accounting Firm.

31.5			Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.6			Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.5			Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.6			Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

MIDAMERICAN FUNDING


31.7			Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.8			Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.7			Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.8			Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN ENERGY AND MIDAMERICAN FUNDING


10.5			Fourth Amendment to the $1,500,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, 2026, 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 (redacted).

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


10.6			Fourth 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 (re dacted).

220


Exhibit No.			Description

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


4.3			Second Supplemental Indenture, dated as of March 9, 2026, by and between Sierra Pacific Power Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 6.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes, SPPC JSN Series 2026A, due 2056 (incorporated by reference to Exhibit 4.2 to the Sierra Pacific Power Company Current Report on Form 8-K dated March 11, 2026).

10.7			Fourth 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 (redacted).

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.

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 June 30, 2026, is formatted in iXBRL (Inline eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail.

104			Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


			BERKSHIRE HATHAWAY ENERGY COMPANY

Date: August 7, 2026			/s/ Terrell K. Crews II
			Terrell K. Crews II
			Senior Vice President and Chief Financial Officer
			(principal financial and accounting officer)

			PACIFICORP

Date: August 7, 2026			/s/ M. Ryan Weems
			M. Ryan Weems
			Senior Vice President, Chief Financial Officer and Treasurer
			(principal financial and accounting officer)

			MIDAMERICAN FUNDING, LLC
			MIDAMERICAN ENERGY COMPANY

Date: August 7, 2026			/s/ Blake M. Groen
			Blake M. Groen
			Vice President and Controller
			of MidAmerican Funding, LLC and
			Vice President and Chief Financial Officer
			of MidAmerican Energy Company
			(principal financial and accounting officer)

			NEVADA POWER COMPANY

Date: August 7, 2026			/s/ Michael J. Behrens
			Michael J. Behrens
			Vice President and Chief Financial Officer
			(principal financial and accounting officer)

			SIERRA PACIFIC POWER COMPANY

Date: August 7, 2026			/s/ Michael J. Behrens
			Michael J. Behrens
			Vice President and Chief Financial Officer
			(principal financial and accounting officer)

			EASTERN ENERGY GAS HOLDINGS, LLC

Date: August 7, 2026			/s/ Scott C. Miller
			Scott C. Miller
			Vice President, Chief Financial Officer and Treasurer
			(principal financial and accounting officer)

			EASTERN GAS TRANSMISSION AND STORAGE, INC.

Date: August 7, 2026			/s/ Scott C. Miller
			Scott C. Miller
			Vice President, Chief Financial Officer and Treasurer
			(principal financial and accounting officer)