UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2023

or

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

For the transition period from ______ to _______

Commission	Exact name of registrant as specified in its charter;	IRS Employer
File Number	State or other jurisdiction of incorporation or organization	Identification No.
001-14881	BERKSHIRE HATHAWAY ENERGY COMPANY	94-2213782
	(An Iowa Corporation)
	666 Grand Avenue
	Des Moines, Iowa 50309-2580
	515-242-4300
001-05152	PACIFICORP	93-0246090
	(An Oregon Corporation)
	825 N.E. Multnomah Street, Suite 1900
	Portland, Oregon 97232
	888-221-7070
333-90553	MIDAMERICAN FUNDING, LLC	47-0819200
	(An Iowa Limited Liability Company)
	666 Grand Avenue
	Des Moines, Iowa 50309-2580
	515-242-4300
333-15387	MIDAMERICAN ENERGY COMPANY	42-1425214
	(An Iowa Corporation)
	666 Grand Avenue
	Des Moines, Iowa 50309-2580
	515-242-4300
000-52378	NEVADA POWER COMPANY	88-0420104
	(A Nevada Corporation)
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	702-402-5000
000-00508	SIERRA PACIFIC POWER COMPANY	88-0044418
	(A Nevada Corporation)
	6100 Neil Road
	Reno, Nevada 89511
	775-834-4011
001-37591	EASTERN ENERGY GAS HOLDINGS, LLC	46-3639580
	(A Virginia Limited Liability Company)
	10700 Energy Way
	Glen Allen, Virginia 23060
	804-613-5100
333-266049	EASTERN GAS TRANSMISSION AND STORAGE, INC.	55-0629203
	(A Delaware Corporation)
	10700 Energy Way
	Glen Allen, Virginia 23060
	804-613-5100

Registrant	Former Address
EASTERN ENERGY GAS HOLDINGS, LLC	6603 West Broad Street
EASTERN GAS TRANSMISSION AND STORAGE, INC.	Richmond, Virginia 23230

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

Registrant	Securities registered pursuant to Section 12(g) of the Act:
BERKSHIRE HATHAWAY ENERGY COMPANY	None
PACIFICORP	None
MIDAMERICAN FUNDING, LLC	None
MIDAMERICAN ENERGY COMPANY	None
NEVADA POWER COMPANY	Common Stock, $1.00 stated value
SIERRA PACIFIC POWER COMPANY	Common Stock, $3.75 par value
EASTERN ENERGY GAS HOLDINGS, LLC	None
EASTERN GAS TRANSMISSION AND STORAGE, INC.	None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

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 if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

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 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 ☒ No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒

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. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive- based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

All shares of outstanding common stock of Berkshire Hathaway Energy Company are privately held by a limited group of investors. As of January 31, 2024, 75,627,913 shares of common stock, no par value, were outstanding.

All shares of outstanding common stock of PacifiCorp are indirectly owned by Berkshire Hathaway Energy Company. As of January 31, 2024, 357,060,915 shares of common stock, no par value, were outstanding.

All of the member's equity of MidAmerican Funding, LLC is held by its parent company, Berkshire Hathaway Energy Company, as of January 31, 2024.

All shares of outstanding common stock of MidAmerican Energy Company are owned by its parent company, MHC Inc., which is a direct, wholly owned subsidiary of MidAmerican Funding, LLC. As of January 31, 2024, 70,980,203 shares of common stock, no par value, were outstanding.

All shares of outstanding common stock of Nevada Power Company are owned by its parent company, NV Energy, Inc., which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of January 31, 2024, 1,000 shares of common stock, $1.00 stated value, were outstanding.

All shares of outstanding common stock of Sierra Pacific Power Company are owned by its parent company, NV Energy, Inc. As of January 31, 2024, 1,000 shares of common stock, $3.75 par value, were outstanding.

All of the member's equity of Eastern Energy Gas Holdings, LLC is held indirectly by its parent company, Berkshire Hathaway Energy Company, as of January 31, 2024.

All shares of outstanding common stock of Eastern Gas Transmission and Storage, Inc. are owned by its parent company, Eastern Energy Gas Holdings, LLC, which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of January 31, 2024, 60,101 shares of common stock, $10,000 par value, were outstanding.

Berkshire Hathaway Energy Company, 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. meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing portions of this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10‑K.

This combined Form 10-K 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.	Business	1
Item 1A.	Risk Factors	74
Item 1B.	Unresolved Staff Comments	89
Item 1C.	Cybersecurity	89
Item 2.	Properties	90
Item 3.	Legal Proceedings	91
Item 4.	Mine Safety Disclosures	101
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	102
Item 6.	[Reserved]	103
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	103
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	103
Item 8.	Financial Statements and Supplementary Data	104
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	486
Item 9A.	Controls and Procedures	486
Item 9B.	Other Information	486
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	487
Item 11.	Executive Compensation	488
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	496
Item 13.	Certain Relationships and Related Transactions, and Director Independence	497
Item 14.	Principal Accountant Fees and Services	498
PART IV
Item 15.	Exhibits and Financial Statement Schedules	499
Item 16.	Form 10-K Summary	499
Signatures		525

i

Definition of Abbreviations and Industry Terms

When used in Forward-Looking Statements, Part I - Items 1 through 4, Part II - Items 5 through 7A, and Part III - Items 10 through 14, the following terms have the definitions indicated.

Entity Definitions
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
Subsidiary Registrants	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 GT&S	BHE GT&S, LLC and its subsidiaries
Northern Natural Gas	Northern Natural Gas Company
Kern River	Kern River Gas Transmission Company
CGT	Carolina Gas Transmission, LLC
BHE Canada	BHE Canada Holdings Corporation and its subsidiaries
AltaLink	AltaLink, L.P.
BHE U.S. Transmission	BHE U.S. Transmission, LLC and its subsidiaries
HomeServices	HomeServices of America, Inc. and its subsidiaries
BHE Pipeline Group or Pipeline Companies	BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
BHE Transmission	BHE Canada Holdings Corporation and BHE U.S. Transmission, LLC
BHE Renewables	BHE Renewables, LLC and its subsidiaries
ETT	Electric Transmission Texas, LLC
Domestic Regulated Businesses	PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries, BHE GT&S, LLC and its subsidiaries, Northern Natural Gas Company and Kern River Gas Transmission Company
Regulated Businesses	PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries, BHE GT&S, LLC and its subsidiaries, Northern Natural Gas Company, Kern River Gas Transmission Company and AltaLink, L.P.
Utilities	PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries

ii

Northern Powergrid Distribution Companies	Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc
Topaz	Topaz Solar Farms LLC
Topaz Project	550-megawatt solar project in California
Agua Caliente	Agua Caliente Solar, LLC
Agua Caliente Project	290-megawatt solar project in Arizona
Bishop Hill II	Bishop Hill Energy II LLC
Bishop Hill Project	81-megawatt wind-powered generating facility in Illinois
Pinyon Pines I	Pinyon Pines Wind I, LLC
Pinyon Pines II	Pinyon Pines Wind II, LLC
Pinyon Pines Projects	168-megawatt and 132-megawatt wind-powered generating facilities in California
Jumbo Road	Jumbo Road Holdings, LLC
Jumbo Road Project	300-megawatt wind-powered generating facility in Texas
Solar Star Funding	Solar Star Funding, LLC
Solar Star Projects	A combined 586-megawatt solar project in California
Solar Star I	Solar Star California XIX, LLC
Solar Star II	Solar Star California XX, LLC
Cove Point	Cove Point LNG, LP
Iroquois	Iroquois Gas Transmission System, L.P.
DEI	Dominion Energy, Inc.
Liquefaction Facility	A natural gas export/liquefaction facility
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
AESO	Alberta Electric System Operator
AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income (Loss)
ARO	Asset Retirement Obligation
ASC	Accounting Standards Codification
AUC	Alberta Utilities Commission
BART	Best Available Retrofit Technology
Bcf	Billion cubic feet
BTER	Base Tariff Energy Rate
California ISO	California Independent System Operator Corporation
CCR	Coal Combustion Residuals
COVID-19	Coronavirus Disease 2019
CPUC	California Public Utilities Commission
CSAPR	Cross-State Air Pollution Rule
D.C. Circuit	U.S. Court of Appeals for the District of Columbia Circuit
DEAA	Deferred Energy Accounting Adjustment
DOE	U.S. Department of Energy
Dodd-Frank Reform Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
DOT	U.S. Department of Transportation
Dth	Decatherm
DSM	Demand-side Management

iii

EAC	Energy Adjustment Clause
EBA	Energy Balancing Account
ECAC	Energy Cost Adjustment Clause
ECAM	Energy Cost Adjustment Mechanism
EEIR	Energy Efficiency Implementation Rate
EEPR	Energy Efficiency Program Rate
EIM	Energy Imbalance Market
EPA	U.S. Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas
FERC	Federal Energy Regulatory Commission
FIP	Federal Implementation Plan
GAAP	Accounting principles generally accepted in the United States of America
GEMA	Gas and Electricity Markets Authority
GHG	Greenhouse Gases
GWh	Gigawatt Hour
ICC	Illinois Commerce Commission
IPUC	Idaho Public Utilities Commission
IRP	Integrated Resource Plan
IUB	Iowa Utilities Board
kV	Kilovolt
LNG	Liquefied Natural Gas
LDC	Local Distribution Company
MATS	Mercury and Air Toxics Standards
MISO	Midcontinent Independent System Operator, Inc.
MW	Megawatt
MWh	Megawatt Hour
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NOx	Nitrogen Oxides
NRC	Nuclear Regulatory Commission
OATT	Open Access Transmission Tariff
OCA	Iowa Office of Consumer Advocate
OCI	Other Comprehensive Income (Loss)
Ofgem	Office of Gas and Electric Markets
OPUC	Oregon Public Utility Commission
PCAM	Power Cost Adjustment Mechanism
PGA	Purchased Gas Adjustment Clause
PTAM	Post Test-year Adjustment Mechanism
PTC	Production Tax Credit
PUCN	Public Utilities Commission of Nevada
RCRA	Resource Conservation and Recovery Act
RAC	Renewable Adjustment Clause
REC	Renewable Energy Credit
RFP	Request for Proposals
RPS	Renewable Portfolio Standards
RRA	Renewable Energy Credit and Sulfur Dioxide Revenue Adjustment Mechanism
RTO	Regional Transmission Organization

iv

SCR	Selective Catalytic Reduction
SEC	U.S. Securities and Exchange Commission
SIP	State Implementation Plan
SO2	Sulfur Dioxide
TAM	Transition Adjustment Mechanism
UPSC	Utah Public Service Commission
VIE	Variable Interest Entity
WECC	Western Electricity Coordinating Council
WMP AAC	Wildfire Mitigation Plan Automatic Adjustment Clause
WPSC	Wyoming Public Service Commission
WUTC	Washington Utilities and Transportation Commission
ZEC	Zero Emission Credit

v

Forward-Looking Statements

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

•general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including income tax reform, initiatives regarding deregulation and restructuring of the utility industry and reliability and safety standards, affecting the respective Registrant's operations or related industries;

•changes in, and compliance with, environmental laws, regulations, decisions and policies, whether directed towards protection of environmental resources, present and future climate considerations or social justice concerns that could, among other items, increase operating and capital costs, reduce facility output, accelerate facility retirements or delay facility construction or acquisition;

•the outcome of regulatory rate reviews and other proceedings conducted by regulatory agencies or other governmental and legal bodies and the respective Registrant's ability to recover costs through rates in a timely manner;

•changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and private generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply or the respective Registrant's ability to obtain long-term contracts with customers and suppliers;

•performance, availability and ongoing operation of the respective Registrant's facilities, including facilities not operated by the Registrants, due to the impacts of market conditions, outages and associated repairs, transmission constraints, weather, including wind, solar and hydroelectric conditions, and operating conditions;

•the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the control of each respective Registrant or by a breakdown or failure of the Registrants' operating assets, including severe storms, floods, fires, extreme temperature events, wind events, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, costly litigation, wars, terrorism, pandemics, embargoes, and cyber security attacks, data security breaches, disruptions, or other malicious acts;

•the risks and uncertainties associated with wildfires that have occurred, are occurring or may occur in the respective Registrant's service territory; the damage caused by such wildfires; the extent of the respective Registrant's liability in connection with such wildfires (including the risk that the respective Registrant may be found liable for damages regardless of fault); investigations into such wildfires; the outcomes of any legal proceedings, demands or similar actions initiated against the respective Registrant; the risk that the respective Registrant is not able to recover losses from insurance or through rates; and the effect of such wildfires, investigations and legal proceedings on the respective Registrant's financial condition and reputation;

•the outcomes of legal or other actions and the effects of amounts to be paid to complainants as a result of settlements or final legal determinations associated with the 2020 Wildfires and the 2022 McKinney Fire (referred to together as "the Wildfires"), which could have a material adverse effect on PacifiCorp's financial condition and could limit PacifiCorp's ability to access capital on terms commensurate with historical transactions or at all and could impact PacifiCorp's liquidity, cash flows and capital expenditure plans;

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

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

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

vi

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

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

•changes in business strategy or development plans;

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

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

•risks relating to nuclear generation, including unique operational, closure and decommissioning risks;

•hydroelectric conditions and the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings;

•the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts;

•the impact of inflation on costs and the ability of the respective Registrants to recover such costs in regulated rates;

•fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar;

•increases in employee healthcare costs;

•the impact of investment performance, certain participant elections such as lump sum distributions and changes in interest rates, legislation, healthcare cost trends, mortality, morbidity on pension and other postretirement benefits expense and funding requirements;

•changes in the residential real estate brokerage, mortgage and franchising industries and regulations that could affect brokerage, mortgage and franchising transactions;

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

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

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

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

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

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

Further details of the potential risks and uncertainties affecting the Registrants are described in the Registrants' filings with the SEC, including Item 1A and other discussions contained in this Form 10-K. 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.

vii

PART I

Item 1.    Business

GENERAL

BHE is a holding company that owns a highly diversified portfolio of locally managed and operated businesses principally engaged in the energy industry and is a consolidated subsidiary of Berkshire Hathaway that, as of January 31, 2024, owned 92% of BHE's voting common stock. The balance of BHE's voting common stock is privately held by a limited group of investors.

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, owns four utility companies in the U.S. serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies in the U.S., one of which owns an LNG export, import and storage facility, an electric transmission business in Canada, interests in electric transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, one of the largest residential real estate brokerage firms and residential real estate brokerage franchise networks in the U.S.

BHE owns a highly diversified portfolio of primarily regulated businesses that generate, transmit, store, distribute and supply energy and serve customers and end-users across geographically diverse service territories, including 28 states located throughout the U.S. and in Great Britain and Canada.

•Approximately 80% of the Company's consolidated adjusted earnings on common shares during 2023 was generated from rate-regulated businesses.

•The Utilities serve 5.3 million electric and natural gas customers in 11 states in the U.S., Northern Powergrid serves 4.0 million end-users in northern England and AltaLink serves approximately 85% of Alberta, Canada's population.

•As of December 31, 2023, the Company owns approximately 36,000 MWs of generation capacity in operation and under construction:

◦Approximately 30,100 MWs of generation capacity is owned by its regulated electric utility businesses;

◦Approximately 5,900 MWs of generation capacity is owned by its nonregulated subsidiaries, the majority of which provides power to utilities under long-term contracts;

◦Owned generation capacity in operation and under construction consists of 42% wind and solar, 32% natural gas, 21% coal, 4% hydroelectric and geothermal and 1% nuclear and other; and,

◦Cumulative investments in (i) owned wind, solar and geothermal generation facilities of $34.1 billion and (ii) wind projects sponsored by third parties, commonly referred to as tax equity investments, of $5.8 billion.

•The Company owns approximately 36,400 miles of electric transmission lines, a 50% interest in ETT that has approximately 2,000 miles of electric transmission lines, approximately 176,800 miles of electric distribution lines and approximately 2,800 substations.

•The BHE Pipeline Group operates approximately 21,000 miles of pipeline with a design capacity of approximately 21.1 Bcf of natural gas per day, transported approximately 15% of the total natural gas consumed in the U.S. during 2023 and owns assets in 27 states. The BHE Pipeline Group also operates 22 natural gas storage facilities with a total working gas capacity of 515.6 Bcf and an LNG export, import and storage facility.

•HomeServices closed approximately $136.1 billion of home sales in 2023 and has brokerage, mortgage and franchise services in all 50 states. HomeServices' franchise business has approximately 300 franchisees primarily in the U.S.

1

Human Capital

The Registrants are committed to attracting, retaining and developing the highest quality of employees; maintaining a safe, diverse and inclusive work environment; offering competitive compensation and benefit programs; and providing employees with opportunities for growth and development.

Employees

As of December 31, 2023, the Company had approximately 23,700 employees, consisting of approximately 14,300 (60%) electric and natural gas operations employees, approximately 5,800 (24%) real estate services employees and approximately 3,600 (15%) corporate services employees. HomeServices has approximately 41,000 real estate agents who are independent contractors. As of December 31, 2023, approximately 8,900 employees were covered by union contracts. The majority of the union employees are employed by the Utilities and are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the United Utility Workers Association and the International Brotherhood of Boilermakers.

Safety and Security

Safety and security are integral to the Registrants' culture and will always be a part of the Registrants' top priorities. The Registrants' safety, cyber and physical security programs are built on personal ownership, compliance with standards, accountability for performance, and continuous improvement. The Registrants provide best-in-class training to ensure that all employees understand the risks and have thorough and specific knowledge to protect themselves, as well as the Registrants' assets, information and operations.

The Registrants use the recordable incident rate to measure employee safety. The recordable incident rate is defined as the number of work-related injuries per 100 full-time workers during a given year. The recordable incident rates for each of the Registrants for the year ended December 31, 2023 are included below:

Recordable Incident Rate:
PacifiCorp	0.48
MidAmerican Energy	0.90
Nevada Power	0.55
Sierra Pacific	0.57
Eastern Energy Gas	0.32
EGTS	0.39
BHE Overall	0.41

Compensation and Benefits

The Registrants' commitment to employees is further demonstrated through competitive compensation and benefits and by providing opportunities for personal growth and career development. In addition to market-based salary, the Registrants' compensation packages include incentive programs to recognize and reward outstanding performance. The Registrants' benefits programs are designed to meet the diverse needs of employees and their families and include among other benefits:

•A comprehensive and flexible benefits package that includes medical, dental and vision coverage; employee assistance programs; pre-tax flexible spending accounts; and adoption assistance;

•Income protection that includes options for short- and long-term disability coverage and life insurance;

•Retirement planning that includes a retirement savings plan 401(k) and a variety of employee and employer contribution and matching options;

•Family Medical Leave as well as paid time off, bereavement leave and holiday benefits; and

•Career development opportunities that provide access to a variety of learning programs and career development support, including tuition reimbursement or assistance.

BHE was incorporated under the laws of the state of Iowa in 1999 and its principal executive offices are located at 666 Grand Avenue, Des Moines, Iowa 50309-2580, its telephone number is (515) 242-4300 and its internet address is www.brkenergy.com.

2

PACIFICORP

General

PacifiCorp, an indirect wholly owned subsidiary of BHE, is a U.S. regulated electric utility company headquartered in Oregon that serves approximately 2.1 million retail electric customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp is principally engaged in the business of generating, transmitting, distributing and selling electricity. PacifiCorp's combined service territory covers approximately 141,500 square miles and includes diverse regional economies across six states. No single segment of the economy dominates the combined service territory, which helps mitigate PacifiCorp's exposure to economic fluctuations. In the eastern portion of the service territory, consisting of Utah, Wyoming and southeastern Idaho, the principal industries are manufacturing, mining or extraction of natural resources, agriculture, technology, recreation and government. In the western portion of the service territory, consisting of Oregon, southern Washington and northern California, the principal industries are agriculture, manufacturing, forest products, food processing, technology, government and primary metals. In addition to retail sales, PacifiCorp buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants to balance and optimize the economic benefits of electricity generation, retail customer loads and existing wholesale transactions. Certain PacifiCorp subsidiaries support its electric utility operations by providing coal mining services.

PacifiCorp's operations are conducted under numerous franchise agreements, certificates, permits and licenses obtained from federal, state and local authorities. The average term of the franchise agreements is approximately 22 years. Several of these franchise agreements allow the municipality the right to seek amendment to the franchise agreement at a specified time during the term. PacifiCorp generally has an exclusive right to serve electric customers within its service territories and, in turn, has an obligation to provide electric service to those customers. In return, the state utility commissions have established rates on a cost-of-service basis, which are designed to allow PacifiCorp an opportunity to recover its costs of providing services and to earn a reasonable return on its investments.

PacifiCorp was incorporated under the laws of the state of Oregon in 1989. Its principal executive offices are located at 825 N.E. Multnomah Street, Suite 1900 Portland, Oregon 97232, its telephone number is (888) 221-7070 and its internet address is www.pacificorp.com. PacifiCorp delivers electricity to customers in Utah, Wyoming and Idaho under the trade name Rocky Mountain Power and to customers in Oregon, Washington and California under the trade name Pacific Power.

All shares of PacifiCorp's common stock are indirectly owned by BHE. PacifiCorp also has shares of preferred stock outstanding that are subject to voting rights in certain limited circumstances.

Regulated Electric Operations

Customers

The GWhs and percentages of electricity sold to PacifiCorp's retail customers by jurisdiction for the years ended December 31 were as follows:

	2023			2022			2021
Utah	26,062	46	%	26,110	46	%	25,657	46	%
Oregon	13,949	25		13,701	24		13,510	24
Wyoming	8,579	15		8,666	15		8,557	15
Washington	3,850	7		4,181	7		4,199	8
Idaho	3,496	6		3,707	7		3,553	6
California	760	1		799	1		798	1
Total	56,696	100	%	57,164	100	%	56,274	100	%

3

Electricity sold to PacifiCorp's retail and wholesale customers by class of customer and the average number of retail customers for the years ended December 31 were as follows:

	2023			2022			2021
GWhs sold:
Residential	18,159	31	%	18,425	30	%	17,905	29	%
Commercial	20,491	34		19,570	32		18,839	31
Industrial	16,705	28		17,622	28		17,909	29
Other	1,341	2		1,547	2		1,621	3
Total retail	56,696	95		57,164	92		56,274	92
Wholesale	2,911	5		4,836	8		5,113	8
Total GWhs sold	59,607	100	%	62,000	100	%	61,387	100	%
Average number of retail customers (in thousands):
Residential	1,806	87	%	1,775	87	%	1,745	87	%
Commercial	227	11		225	11		222	11
Industrial	9	1		9	1		9	1
Other	27	1		28	1		27	1
Total	2,069	100	%	2,037	100	%	2,003	100	%

Variations in weather, economic conditions and various conservation, energy efficiency and private generation measures and programs can impact customer energy requirements. Wholesale sales are impacted by market prices for energy relative to the incremental cost to generate electricity.

The annual hourly peak customer demand, which represents the highest demand on a given day and at a given hour, occurs in the summer when air conditioning and irrigation systems are heavily used. Peak demand in the winter occurs due to heating requirements. During 2023, PacifiCorp's peak demand was 10,802 MWs in the summer and 8,998 MWs in the winter.

Generating Facilities and Fuel Supply

PacifiCorp has ownership interest in a diverse portfolio of generating facilities. The following table presents certain information regarding PacifiCorp's owned generating facilities as of December 31, 2023:

				Facility	Net Owned
			Installed /	Net Capacity	Capacity
Generating Facility	Location	Energy Source	Repowered(1)	(MWs)(2)	(MWs)(2)
COAL:
Hunter Nos. 1, 2 and 3	Castle Dale, UT	Coal	1978-1983	1,363	1,158
Huntington Nos. 1 and 2	Huntington, UT	Coal	1974-1977	909	909
Dave Johnston Nos. 1, 2, 3 and 4	Glenrock, WY	Coal	1959-1972	745	745
Jim Bridger Nos. 3 and 4(3)	Rock Springs, WY	Coal	1976-1979	1,049	700
Naughton Nos. 1 and 2	Kemmerer, WY	Coal	1963-1968	357	357
Wyodak No. 1	Gillette, WY	Coal	1978	332	266
Craig Nos. 1 and 2	Craig, CO	Coal	1979-1980	837	161
Colstrip Nos. 3 and 4	Colstrip, MT	Coal	1984-1986	1,480	148
Hayden Nos. 1 and 2	Hayden, CO	Coal	1965-1976	441	77
				7,513	4,521
NATURAL GAS:
Lake Side 2	Vineyard, UT	Natural gas/steam	2014	631	631
Lake Side	Vineyard, UT	Natural gas/steam	2007	546	546
Currant Creek	Mona, UT	Natural gas/steam	2005-2006	524	524
Chehalis	Chehalis, WA	Natural gas/steam	2003	477	477
Naughton No. 3(4)	Kemmerer, WY	Natural gas	1971	247	247
Gadsby Steam	Salt Lake City, UT	Natural gas	1951-1955	238	238
Hermiston	Hermiston, OR	Natural gas/steam	1996	461	231

4

				Facility	Net Owned
			Installed /	Net Capacity	Capacity
Generating Facility	Location	Energy Source	Repowered(1)	(MWs)(2)	(MWs)(2)
Gadsby Peakers	Salt Lake City, UT	Natural gas	2002	119	119
				3,243	3,013
WIND:
TB Flats	Medicine Bow, WY	Wind	2020-2021	500	500
Ekola Flats	Medicine Bow, WY	Wind	2020	250	250
Pryor Mountain	Bridger, MT	Wind	2020-2021	240	240
Marengo	Dayton, WA	Wind	2007-2008 / 2020	234	234
Cedar Springs II	Douglas, WY	Wind	2020	199	199
Glenrock	Glenrock, WY	Wind	2008-2009 / 2019	139	139
Seven Mile Hill	Medicine Bow, WY	Wind	2008 / 2019	119	119
Dunlap Ranch	Medicine Bow, WY	Wind	2010 / 2020	111	111
Leaning Juniper	Arlington, OR	Wind	2006 / 2019	100	100
Rolling Hills	Glenrock, WY	Wind	2009 / 2019	100	100
High Plains	McFadden, WY	Wind	2009 / 2019	99	99
Goodnoe Hills	Goldendale, WA	Wind	2008 / 2019	94	94
Foote Creek I	Arlington, WY	Wind	1999 / 2021	41	41
McFadden Ridge	McFadden, WY	Wind	2009 / 2019	28	28
Foote Creek III	Arlington, WY	Wind	2023	25	25
Foote Creek IV	Arlington, WY	Wind	2023	17	17
				2,296	2,296
HYDROELECTRIC:
Lewis River System	WA	Hydroelectric	1931-1958	578	578
North Umpqua River System	OR	Hydroelectric	1950-1956	204	204
Bear River System	ID, UT	Hydroelectric	1908-1984	105	105
Rogue River System	OR	Hydroelectric	1912-1957	52	52
Minor hydroelectric facilities	Various	Hydroelectric	1895-1986	32	32
				971	971
OTHER:
Blundell	Milford, UT	Geothermal	1984, 2007	32	32
				32	32
Total Available Generating Capacity				14,055	10,833
PROJECTS UNDER CONSTRUCTION:
Various projects				642	642
				14,697	11,475

(1)Repowered dates are associated with component replacements on existing wind-powered generating facilities commonly referred to by the U.S. Internal Revenue Service ("IRS") as repowering. IRS rules provide for re-establishment of the PTCs for an existing wind-powered generating facility upon the replacement of a significant portion of its components. If the degree of component replacement in such projects meets IRS guidelines, PTCs are re-established for 10 years beginning with the date the repowered facility is placed in‑service.

(2)Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates PacifiCorp's ownership of Facility Net Capacity.

(3)During 2023, Jim Bridger Units 1 and 2 operated under a consent decree as described in "Environmental Laws and Regulations" in Item 1 of this Form 10-K. PacifiCorp removed Jim Bridger Units 1 and 2 from coal-fueled service in December 2023 and will convert them to natural gas-fueled generation facilities in 2024.

(4)Naughton No. 3 was converted from a coal-fueled to a natural gas-fueled generating facility in 2020.

5

The following table shows the percentages of PacifiCorp's total energy supplied by energy source for the years ended December 31:

	2023		2022		2021
Coal	34	%	43	%	48	%
Natural gas	22		21		20
Wind(1)	10		11		10
Hydroelectric and other(1)	5		5		5
Total energy generated	71		80		83
Energy purchased - long-term contracts (renewable)(1)	16		15		15
Energy purchased - short-term contracts and other	12		5		2
Energy purchased - long term contracts (non-renewable)	1		—		—
	100	%	100	%	100	%

(1)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, (b) sold to third parties in the form of RECs or other environmental commodities, or (c) excluded from energy purchased.

PacifiCorp is required to have resources available to continuously meet its customer needs and reliably operate its electric system. The percentage of PacifiCorp's energy supplied by energy source varies from year to year and is subject to numerous operational, economic and environmental factors such as planned and unplanned outages, fuel commodity prices, fuel availability, fuel transportation costs, weather, legislative considerations, transmission constraints and wholesale market prices of electricity. PacifiCorp evaluates these factors continuously in order to facilitate economic dispatch of its generating facilities. When factors for one energy source are less favorable, PacifiCorp places more reliance on other energy sources. For example, PacifiCorp can generate more electricity using its low-cost wind-powered and hydroelectric generating facilities when factors associated with these facilities are favorable. In addition to meeting its customers' energy needs, PacifiCorp is required to maintain operating reserves on its system to mitigate the impacts of unplanned outages or other disruption in supply, and to meet intra-hour changes in load and resource balance. This operating reserve requirement is dispersed across PacifiCorp's generation portfolio on a least-cost basis based on the operating characteristics of the portfolio. Operating reserves may be held on hydroelectric, coal-fueled, natural gas-fueled or certain types of interruptible load. PacifiCorp manages certain risks relating to its supply of electricity and fuel requirements by entering into various contracts, which may be accounted for as derivatives and may include forwards, options, swaps and other agreements. Refer to "General Regulation" in Item 1 of this Form 10-K for a discussion of energy cost recovery by jurisdiction and to PacifiCorp's Item 7A in this Form 10-K for a discussion of commodity price risk and derivative contracts.

    Coal

PacifiCorp has interests in coal mines that support its coal-fueled generating facilities and jointly operates the Bridger surface coal mine. The Bridger underground mine ceased coal production in November 2021. These mines supplied 18%, 21% and 21% of PacifiCorp's total coal requirements during the years ended December 31, 2023, 2022 and 2021, respectively.

Most of PacifiCorp's coal reserves are held through agreements with the federal Bureau of Land Management and from certain states and private parties. The agreements generally have multi-year terms that may be renewed or extended and require payment of rents and royalties. In addition, federal and state regulations require that comprehensive environmental protection and reclamation standards be met during the course of mining operations and upon completion of mining activities.

Coal reserve estimates are subject to adjustment as a result of the development of additional engineering and geological data, new mining technology and changes in regulation and economic factors affecting the utilization of such reserves.

Recoverability by surface mining methods typically ranges from 90% to 95%. To meet applicable standards, PacifiCorp blends its coal with contracted coal and utilizes emissions reduction technologies for controlling SO2 and other emissions.

6

For fuel needs at PacifiCorp's coal-fueled generating facilities in excess of coal reserves available, PacifiCorp believes it will be able to purchase coal under both long- and short-term third-party contracts to supply the remaining coal requirements at its coal-fueled generating facilities over their currently expected remaining useful lives but at significantly higher prices. PacifiCorp has experienced higher costs to procure coal supply for its Utah coal-fueled generating facilities as a result of reduced suppliers, fires in third-party mines, coal supplier solvency and financing issues, labor shortages, transportation limitations, delays in federal leasing processes, and production delays due to unfavorable geologic conditions.

    Natural Gas

PacifiCorp uses natural gas as fuel for its generating facilities that use combined-cycle, simple-cycle and steam turbines. Oil and natural gas are also used for igniter fuel and standby purposes. These sources are presently in adequate supply and available to meet PacifiCorp's needs.

PacifiCorp enters into forward natural gas purchases at fixed or indexed market prices. PacifiCorp purchases natural gas in the spot market with both fixed and indexed market prices for physical delivery to fulfill any fuel requirements not already satisfied through forward purchases of natural gas and sells natural gas in the spot market for the disposition of any excess supply if the forecasted requirements of its natural gas-fueled generating facilities decrease. PacifiCorp also utilizes financial swap contracts to mitigate price risk associated with its forecasted fuel requirements.

Wind

PacifiCorp has pursued renewable resources as a viable, economical and environmentally prudent means of supplying electricity and complying with laws and regulations. Renewable resources have low to no emissions and require little or no fossil fuel. The generation from PacifiCorp's wind-powered generating fleet, comprised of newly constructed and recently repowered wind-powered generating facilities, qualifies for federal PTCs for 10 years beginning with the date the new or repowered facility is placed in‑service. In addition to the discussion contained herein regarding repowering activities, refer to "Regulatory Matters" in Item 1 of this Form 10-K.

    Hydroelectric and Other Renewable Resources

The amount of electricity PacifiCorp is able to generate from its hydroelectric generating facilities depends on a number of factors, including snowpack in the mountains upstream of its hydroelectric generating facilities, reservoir storage, precipitation in its watersheds, generating unit availability and restrictions imposed by oversight bodies due to competing water management objectives.

PacifiCorp operates the majority of its hydroelectric generating portfolio under long-term licenses. The FERC regulates 98% of the net capacity of this portfolio through 14 individual licenses, which have terms of 30 to 50 years. The licenses for these hydroelectric generating facilities expire at various dates through 2061. A portion of this portfolio is licensed under the Oregon Hydroelectric Act. For discussion of PacifiCorp's hydroelectric relicensing activities, including updated information regarding the Klamath River hydroelectric system, refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K.

    Wholesale Activities

PacifiCorp purchases and sells electricity in the wholesale markets as needed to balance its generation with its retail load obligations. PacifiCorp may also purchase electricity in the wholesale markets when it is more economical than generating electricity from its own facilities and may sell surplus electricity in the wholesale markets when it can do so economically. When prudent, PacifiCorp enters into financial swap contracts and forward electricity sales and purchases for physical delivery at fixed prices to reduce its exposure to electricity price volatility.

7

    Energy Imbalance Market

PacifiCorp and the California ISO implemented an EIM in November 2014, which reduces costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, more effectively integrates renewables and enhances reliability through improved situational awareness and responsiveness. The EIM expands the real-time component of the California ISO's market technology to optimize and balance electricity supply and demand every five minutes across the EIM footprint. The EIM is voluntary and available to all balancing authorities in the western U.S. EIM market participants submit bids to the California ISO market operator before each hour for each generating resource they choose to be dispatched by the market. Each bid is comprised of a dispatchable operating range, ramp rate and prices across the operating range. The California ISO market operator uses sophisticated technology to select the least-cost resources to meet demand and send simultaneous dispatch signals to every participating generator across the EIM footprint every five minutes. In addition to generation resource bids, the California ISO market operator also receives continuous real-time updates of the transmission grid network, meteorological and load forecast information that it uses to optimize dispatch instructions. Outside the EIM footprint, utilities in the western U.S. do not utilize comparable technology and are largely limited to transactions within the borders of their balancing authority area to balance supply and demand intra-hour using a combination of manual and automated dispatch. The EIM delivers customer benefits by leveraging automation and resource diversity to result in more efficient dispatch, more effective integration of renewables and improved situational awareness. Benefits are expected to increase further with renewable resource expansion and as more entities join the EIM, bringing incremental resource diversity. PacifiCorp is working with the California ISO to join the California ISO Extended Day-Ahead Market ("EDAM") in 2026. The EDAM is a voluntary day-ahead electricity market designed to deliver significant reliability, economic, and environmental benefits to balancing areas and utilities throughout the West.

Transmission and Distribution

PacifiCorp operates one balancing authority area in the western portion of its service territory ("PacifiCorp-West") and one balancing authority area in the eastern portion of its service territory ("PacifiCorp-East"). A balancing authority area is a geographic area with transmission systems that control generation to maintain schedules with other balancing authority areas and ensure reliable operations. In operating the balancing authority areas, PacifiCorp is responsible for continuously balancing electricity supply and demand by dispatching generating resources and interchange transactions so that generation internal to the balancing authority area, plus net imported power, matches customer loads. Deliveries of energy over PacifiCorp's transmission system are managed and scheduled in accordance with the FERC's requirements.

PacifiCorp's transmission system is part of the Western Interconnection, which includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico. PacifiCorp's transmission system, together with contractual rights on other transmission systems, enables PacifiCorp to integrate and access generation resources to meet its customer load requirements. PacifiCorp's transmission and distribution systems included approximately 17,100 miles of transmission lines in 10 states, 66,300 miles of distribution lines and 900 substations as of December 31, 2023.

PacifiCorp's transmission and distribution system is managed on a coordinated basis to obtain maximum load-carrying capability and efficiency. Portions of PacifiCorp's transmission and distribution systems are located:

•On property owned or used through agreements by PacifiCorp;

•Under or over streets, alleys, highways and other public places, the public domain and national forests and state and federal lands under franchises, easements or other rights that are generally subject to termination;

•Under or over private property as a result of easements obtained primarily from the title holder of record; or

•Under or over Native American reservations through agreements with the U.S. Secretary of Interior or Native American tribes.

It is possible that some of the easements and the property over which the easements were granted may have title defects or may be subject to mortgages or liens existing at the time the easements were acquired.

8

PacifiCorp's Energy Gateway Transmission Expansion Program represents plans to build over 2,000 miles of new high-voltage transmission lines, with an estimated cost of approximately $13 billion, primarily in Wyoming, Utah, Idaho and Oregon. The approximately $13 billion estimated cost includes: (a) the 135-mile, 345-kV transmission line between the Terminal substation near the Salt Lake City Airport and the Populus substation in Downey, Idaho, placed in-service in 2010; (b) the 100-mile, 345/500-kV transmission line between the Mona substation in central Utah and the Oquirrh substation in the Salt Lake Valley, placed in-service in 2013; (c) the 170-mile, 345-kV transmission line between the Sigurd substation in central Utah and the Red Butte substation in southwest Utah, placed in-service in 2015; (d) the 140-mile, 500-kV transmission line between the Aeolus substation near Medicine Bow, Wyoming and the Jim Bridger generating facility, placed in-service in 2020; (e) the 416-mile, 500-kV high-voltage transmission line between the Aeolus substation and the Clover substation near Mona, Utah, expected to be placed in-service in 2024; (f) the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation, expected to be placed in-service in 2024; (g) the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho (a joint project), expected to be placed in-service in 2026; (h) the 14-mile, 345-kV high-voltage transmission line between the Oquirrh substation and the Terminal substation, expected to be placed in-service in 2024; and (i) remaining segments that are expected to be placed in-service in future years, depending on load growth, economic analysis, IRP results, siting, permitting and construction schedules. The transmission line segments are intended to: (a) address customer load growth; (b) improve system reliability; (c) reduce transmission system constraints; (d) provide access to diverse generation resources, including renewable and zero carbon resources; and (e) improve the flow of electricity throughout PacifiCorp's six-state service area. Proposed transmission line segments are evaluated to ensure optimal benefits and timing before committing to move forward with permitting and construction. Through December 31, 2023, $4.8 billion had been spent and $2.3 billion, including AFUDC, had been placed in-service.

Wildfire Mitigation Plans

PacifiCorp has developed detailed wildfire mitigation plans for each of the six states in which it operates. Wildfire mitigation plans are filed annually with the OPUC, the CPUC and the UPSC. Although not required, a wildfire mitigation plan is provided annually to the WUTC. In 2024, wildfire mitigation plans will also be provided to the IPUC and the WPSC with a similar schedule of providing annual future updates. These plans include capital investment in asset hardening and meteorological systems, the implementation of risk modeling tools and PacifiCorp's ongoing elevated fire risk settings, inspections, vegetation management, public safety power shutoff ("PSPS") and wildfire encroachment programs and policies.

Asset Hardening

PacifiCorp has and continues to invest in rebuilding overhead transmission and distribution lines with covered conductor and in some cases has converted overhead distribution lines to underground. These system hardening efforts reduce the exposure of PacifiCorp's lines to interference from trees and other objects. Covered conductor helps mitigate the risk of fault-caused electrical arcs that could cause an ignition. Overall, mitigated overhead lines help reduce ignition risk and improve reliability during storms or periods of significant wildfire risk.

Approximately 6,100 miles, or 9%, of PacifiCorp's distribution lines are in fire high consequence areas ("FHCA"), covering approximately 8% of its service territory and approximately 5% of its customer base. Approximately 1,000 miles of transmission lines are in the FHCA. In 2023, the process for updating the risk modeling for the identification of the FHCA was initiated and is on track for finalization in early 2024. It is expected that as the wildfire mitigation program evolves, its targeted programs will cover more service territory.

As of December 31, 2023, all 1,000 miles of transmission lines in the FHCA were mitigated by system relay protection schemes. All 6,100 miles of distribution lines in the FHCA include some form of mitigation including:

•3,100 miles, or 51%, with bare conductor mitigated by system relay protection schemes;

•400 miles, or 6%, with new covered conductor; and

•2,600 miles, or 43%, underground.

The on-going asset hardening of the FHCA is a priority for PacifiCorp and a key part of the developed wildfire mitigation plans.

Refer to "Future Uses of Cash" in Item 7 of this Form 10-K for further discussion of PacifiCorp's wildfire mitigation related capital expenditures, including asset hardening.

9

Elevated Fire Risk Settings

Elevated fire risk settings are available across PacifiCorp's service territory, including the ongoing installation of new microprocessor relays to detect faults occurring on transmission and distribution lines in the FHCA and de-energize the line quickly limiting the arc-energy and potential for wildfire ignition. Field reclosers are being upgraded with similar fault detection capability in the FHCA.

Meteorology and Risk Modeling

PacifiCorp has installed over 450 weather stations that monitor weather conditions and model the impact to the electrical infrastructure. These weather stations combined with the around-the-clock weather forecasting team servicing PacifiCorp's service territory, provide PacifiCorp with the ability to forecast weather and fire risk impact data twice daily. PacifiCorp will continue to install additional weather stations to refine weather modeling in areas where geographic terrain conditions require a dense network of weather stations in order to provide the necessary granular data.

Asset Inspection Program

Within the FHCA PacifiCorp conducts an annual inspection of overhead facilities with an accelerated correction timeline for any conditions noted. A detailed inspection of facilities is conducted every five years, which is twice as often as areas outside the FHCA.

Vegetation Management

PacifiCorp's vegetation management program includes annual vegetation inspections and ground clearing of equipment poles in the FHCA along with three-year trimming cycles in place, including in Oregon and California where fire hazard risk is highest.

Public Safety Power Shutoff and Wildfire Encroachment Policy

A PSPS is used as a preventative measure during periods of extreme wildfire risk where the electrical network is de-energized proactively under certain conditions. In determining whether to initiate a PSPS, PacifiCorp works with local public safety authorities in consideration of data from meteorological systems and forecasting tools. PacifiCorp also has a wildfire encroachment policy under which it will de-energize its lines when a known wildfire is within a specified distance of its assets based on criteria such as system configuration, line structure material, weather conditions and wind. In August 2023, in response to potentially encroaching lightning-caused wildfires in the area at the time, PacifiCorp de‑energized transmission lines serving customers in Crescent City and Del Norte County, California, providing a temporary power solution to nearly all of the impacted customers.

Future Generation, Conservation and Energy Efficiency

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. The IRP process identifies the amount and timing of PacifiCorp's expected future resource needs, accounting for planning uncertainty, risks, reliability, state energy policies and other factors. The IRP is prepared following a public process, which provides an opportunity for stakeholders to participate in PacifiCorp's resource planning process. 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 recovery or prudency of resources ultimately selected.

In March 2023, PacifiCorp filed its 2023 IRP in Idaho, Oregon and Wyoming. The March 2023 filing was considered informational in Utah. PacifiCorp filed its 2023 IRP (Amended Final) report on May 31, 2023, following a 60-day extended comment period. In October 2023, the IPUC acknowledged the 2023 IRP. In November 2023 through February 2024, PacifiCorp responded to Wyoming, Utah and Oregon stakeholder reply comments as part of the 2023 IRP acknowledgement and related processes.

10

The 2023 IRP is off cycle with regard to Washington's four-year IRP cycle and has instead been filed in that state as the "Washington Two-Year Progress Report," aligned with the Clean Energy Transformation Act requirements. In October, the WUTC approved a multi-party settlement agreement that resolved challenges to the Clean Energy Implementation Plan ("CEIP").

PacifiCorp's petition to the WUTC to approve an alternative IRP filing schedule has been partially accepted and will extend the existing timeline of the 2025 IRP filing by three months to align with the filing schedules of the other five states within PacifiCorp's six-state territory. This is pertinent to maintaining a March 31, 2025 filing date for the 2025 IRP. Related 2025 IRP filing dates are also extended, however, the filing dates for Washington's CEIP are unchanged.

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 and state-specific compliance obligations. Depending upon the specific RFP, applicable laws and regulations may require PacifiCorp to file draft RFPs with the UPSC, the OPUC and the WUTC. Approval by the UPSC, the OPUC or the WUTC may be required depending on the nature of the RFPs.

PacifiCorp's most recent RFP, the 2022 All-Source ("2022AS") RFP, was issued to the market in April 2022. In September 2023, PacifiCorp suspended its 2022AS RFP. No final shortlist will be announced while the RFP is paused. As indicated in the 2022AS RFP, PacifiCorp reserves the right, without limitation or qualification and in its sole discretion, to reject any or all bids, and to terminate or suspend the RFP in whole or in part at any time.

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

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

•Ongoing rulemaking by the EPA regarding greenhouse gas emissions.

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

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

As of this filing, PacifiCorp has made no decision specific to the 2022AS RFP's reinstatement or termination. Next steps regarding the 2022 AS RFP will be further informed by the findings from the 2023 IRP updates scheduled for release in the first quarter of 2024.

Energy Efficiency Programs

PacifiCorp has provided its customers with a comprehensive set of DSM programs since the 1970s. The programs are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. PacifiCorp offers services to customers such as energy engineering audits and information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, PacifiCorp offers rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors, process equipment and systems, as well as incentives for energy project management, efficient building operations and efficient construction. Incentives are also paid to solicit participation in load management programs by residential, business and agricultural customers through programs such as PacifiCorp's residential and small commercial air conditioner load control program, battery control program and irrigation equipment load control programs. Although subject to prudence reviews, state regulations allow for recovery of costs incurred for the DSM programs through state-specific energy efficiency surcharges to retail customers or for recovery of costs through rates. During 2023, PacifiCorp spent $178 million on these DSM programs, resulting in an estimated 642,569 MWhs of first-year energy savings and an estimated 459 MWs of peak load management. In addition to these DSM programs, PacifiCorp has load curtailment contracts with a number of large industrial customers that deliver up to 372 MWs of load reduction when needed, depending on the customers' actual operations. Costs associated with the large industrial load curtailment program are captured in the respective customers' retail special contracts. The corresponding recovery of costs was approved by the respective state commissions or through PacifiCorp's general rate case process.

11

Human Capital

Employees

As of December 31, 2023, PacifiCorp had approximately 5,000 employees, of which approximately 2,800 were covered by union contracts, principally with the International Brotherhood of Electrical Workers, the Utility Workers Union of America and the International Brotherhood of Boilermakers. For more information regarding PacifiCorp's human capital disclosures, refer to Item 1. Business - General section of this Form 10-K.

MIDAMERICAN FUNDING AND MIDAMERICAN ENERGY

General

MidAmerican Funding and MHC

MidAmerican Funding, a wholly owned subsidiary of BHE, is a holding company headquartered in Iowa that owns all of the outstanding common stock of MHC Inc. ("MHC"), which is a holding company owning all of the common stock of MidAmerican Energy and Midwest Capital Group, Inc. ("Midwest Capital"). MidAmerican Funding and MidAmerican Energy are indirect consolidated subsidiaries of Berkshire Hathaway. MidAmerican Funding conducts no business other than activities related to its debt securities and the ownership of MHC. MHC conducts no business other than the ownership of its subsidiaries. MidAmerican Energy is a substantial portion of MidAmerican Funding's and MHC's assets, revenue and earnings.

MidAmerican Funding was formed as a limited liability company under the laws of the state of Iowa in 1999 and its principal executive offices are located at 666 Grand Avenue, Des Moines, Iowa 50309-2580 and its telephone number is (515) 242-4300.

MidAmerican Energy

MidAmerican Energy, an indirect wholly owned subsidiary of BHE, is a U.S. regulated electric and natural gas utility company headquartered in Iowa that serves 0.8 million retail electric customers in portions of Iowa, Illinois and South Dakota and 0.8 million retail and transportation natural gas customers in portions of Iowa, South Dakota, Illinois and Nebraska. MidAmerican Energy is principally engaged in the business of generating, transmitting, distributing and selling electricity and in distributing, selling and transporting natural gas. MidAmerican Energy's service territory covers approximately 11,000 square miles. MidAmerican Energy has a diverse customer base consisting of urban and rural residential customers and a variety of commercial and industrial customers. Principal industries served by MidAmerican Energy include electronic data storage; processing and sales of food products; manufacturing, processing and fabrication of primary metals, farm and other non-electrical machinery; cement and gypsum products; and government. In addition to retail sales and natural gas transportation, MidAmerican Energy sells electricity principally to markets operated by RTOs and natural gas to other utilities and market participants on a wholesale basis. MidAmerican Energy is a transmission-owning member of the MISO and participates in its capacity, energy and ancillary services markets.

MidAmerican Energy's regulated electric and natural gas operations are conducted under numerous franchise agreements, certificates, permits and licenses obtained from federal, state and local authorities. The franchise agreements, with various expiration dates, are typically for 20- to 25-year terms. Several of these franchise agreements give either party the right to seek amendment to the franchise agreement at one, two, three or four specified times during the term. MidAmerican Energy generally has an exclusive right to serve electric customers within its service territories and, in turn, has an obligation to provide electricity service to those customers. In return, the state utility commissions have established rates on a cost-of-service basis, which are designed to allow MidAmerican Energy an opportunity to recover its costs of providing services and to earn a reasonable return on its investment. In Illinois, MidAmerican Energy's regulated retail electric customers may choose their energy supplier.

12

MidAmerican Energy's operating revenue and operating income derived from the following business activities for the years ended December 31 were as follows (dollars in millions):

	2023				2022				2021
Operating revenue:
Regulated electric	$	2,673	79	%	$	2,988	74	%	$	2,529	71	%
Regulated gas	713		21		1,030		26		1,003		28
Other	7		—		7		—		15		1
Total operating revenue	$	3,393	100	%	$	4,025	100	%	$	3,547	100	%
Operating income:
Regulated electric	$	471	90	%	$	372	85	%	$	358	86	%
Regulated gas	50		10		66		15		58		14
Total operating income	$	521	100	%	$	438	100	%	$	416	100	%

MidAmerican Energy was incorporated under the laws of the state of Iowa in 1995 and its principal executive offices are located at 666 Grand Avenue, Des Moines, Iowa 50309-2580, its telephone number is (515) 242-4300 and its internet address is www.midamericanenergy.com.

Regulated Electric Operations

Customers

The GWhs and percentages of electricity sold to MidAmerican Energy's retail customers by jurisdiction for the years ended December 31 were as follows:

	2023			2022			2021
Iowa	27,554	93	%	27,024	92	%	25,909	92	%
Illinois	1,827	6		1,970	7		1,895	7
South Dakota	294	1		296	1		270	1
	29,675	100	%	29,290	100	%	28,074	100	%

13

Electricity sold to MidAmerican Energy's retail and wholesale customers by class of customer and the average number of retail customers for the years ended December 31 were as follows:

	2023			2022			2021
GWhs sold:
Residential	6,759	15	%	7,006	15	%	6,718	15	%
Commercial	3,992	9		4,017	9		3,841	9
Industrial	17,307	39		16,646	35		15,944	36
Other	1,617	3		1,621	3		1,571	4
Total retail	29,675	66		29,290	62		28,074	64
Wholesale	15,129	34		17,964	38		16,011	36
Total GWhs sold	44,804	100	%	47,254	100	%	44,085	100	%
Average number of retail customers (in thousands):
Residential	703	86	%	697	86	%	690	86	%
Commercial	101	12		99	12		98	12
Industrial	2	—		2	—		2	—
Other	14	2		15	2		14	2
Total	820	100	%	813	100	%	804	100	%

Variations in weather, economic conditions and various conservation and energy efficiency measures and programs can impact customer energy requirements. Wholesale sales are primarily impacted by market prices for energy.

There are seasonal variations in MidAmerican Energy's electricity sales that are principally related to weather and the related use of electricity for air conditioning. Additionally, electricity sales are priced higher in the summer months compared to the remaining months of the year. As a result, 40% to 50% of MidAmerican Energy's regulated electric retail revenue is reported in the months of June through September.

A degree of concentration of sales exists with certain large electric retail customers. Sales to the 10 largest customers, from a variety of industries, comprised 26%, 25% and 24% of total retail electric sales in 2023, 2022 and 2021, respectively. Sales to electronic data storage customers included in the 10 largest customers comprised 20%, 18% and 16% of total retail electric sales in 2023, 2022 and 2021, respectively.

The annual hourly peak demand on MidAmerican Energy's electric system usually occurs as a result of air conditioning use during the cooling season. Peak demand represents the highest demand on a given day and at a given hour. On August 23, 2023, retail customer usage of electricity caused a new record hourly peak demand of 5,851 MWs on MidAmerican Energy's electric distribution system, which is 465 MWs greater than the previous record hourly peak demand of 5,386 MWs set August 2, 2022.

Generating Facilities and Fuel Supply

MidAmerican Energy has ownership interest in a diverse portfolio of generating facilities. The following table presents certain information regarding MidAmerican Energy's owned generating facilities as of December 31, 2023:

				Facility	Net
			Year Installed /	Net Capacity	Owned Capacity
Generating Facility	Location	Energy Source	Repowered(1)	(MWs)(2)	(MWs)(2)
WIND:
Ida Grove	Ida Grove, IA	Wind	2016-2019	500	500
Orient	Greenfield, IA	Wind	2018-2019	500	500
Highland	Primghar, IA	Wind	2015	475	475
Rolling Hills	Massena, IA	Wind	2011 / 2022	443	443
Beaver Creek	Ogden, IA	Wind	2017-2018	340	340
North English	Montezuma, IA	Wind	2018-2019	340	340
Palo Alto	Palo Alto, IA	Wind	2019-2020	340	340
Arbor Hill	Greenfield, IA	Wind	2018-2020	316	316

14

				Facility	Net
			Year Installed /	Net Capacity	Owned Capacity
Generating Facility	Location	Energy Source	Repowered(1)	(MWs)(2)	(MWs)(2)
Pomeroy	Pomeroy, IA	Wind	2007-2011 / 2018-2019, 2021	286	286
Diamond Trail	Ladora, IA	Wind	2020	250	250
Lundgren	Otho, IA	Wind	2014	250	250
O'Brien	Primghar, IA	Wind	2016	250	250
Southern Hills	Orient, IA	Wind	2020-2021	250	250
Chickasaw	New Hampton, IA	Wind	2023	200	200
Century	Blairsburg, IA	Wind	2005-2008 / 2017-2018	200	200
Eclipse	Adair, IA	Wind	2012 / 2022	200	200
Plymouth	Remsen, IA	Wind	2021	200	200
Intrepid	Schaller, IA	Wind	2004-2005 / 2017	176	176
Adair	Adair, IA	Wind	2008 / 2019-2020	175	175
Prairie	Montezuma, IA	Wind	2017-2018	169	169
Carroll	Carroll, IA	Wind	2008 / 2019	150	150
Walnut	Walnut, IA	Wind	2008 / 2019	150	150
Vienna	Gladbrook, IA	Wind	2012-2013	150	150
Adams	Lennox, IA	Wind	2015	150	150
Wellsburg	Wellsburg, IA	Wind	2014	139	139
Laurel	Laurel, IA	Wind	2011 / 2022	120	120
Macksburg	Macksburg, IA	Wind	2014	119	119
Contrail	Braddyville, IA	Wind	2020	110	110
Morning Light	Adair, IA	Wind	2012 / 2022-2023	100	100
Victory	Westside, IA	Wind	2006 / 2017-2018	99	99
Ivester	Wellsburg, IA	Wind	2018	90	90
Pocahontas Prairie	Pomeroy, IA	Wind	2020 / 2021	80	80
Charles City	Charles City, IA	Wind	2008 / 2018	75	75
				7,392	7,392
COAL:
Louisa	Muscatine, IA	Coal	1983	746	656
Walter Scott, Jr. Unit No. 3	Council Bluffs, IA	Coal	1978	706	558
Walter Scott, Jr. Unit No. 4	Council Bluffs, IA	Coal	2007	806	481
Ottumwa	Ottumwa, IA	Coal	1981	724	376
George Neal Unit No. 3	Sergeant Bluff, IA	Coal	1975	510	367
George Neal Unit No. 4	Salix, IA	Coal	1979	647	263
				4,139	2,701
NATURAL GAS AND OTHER:
Greater Des Moines	Pleasant Hill, IA	Gas	2003-2004	510	510
Electrifarm	Waterloo, IA	Gas or Oil	1975-1978	190	190
Pleasant Hill	Pleasant Hill, IA	Gas or Oil	1990-1994	154	154
Sycamore	Johnston, IA	Gas or Oil	1974	145	145
River Hills	Des Moines, IA	Gas	1966-1967	115	115
Coralville	Coralville, IA	Gas	1970	64	64
Moline	Moline, IL	Gas	1970	61	61
27 portable power modules	Various	Oil	2000	54	54
Parr	Charles City, IA	Gas	1969	33	33
				1,326	1,326
NUCLEAR:
Quad Cities Unit Nos. 1 and 2	Cordova, IL	Uranium	1972	1,809	452
SOLAR:
Holliday Creek	Fort Dodge, IA	Solar	2022	100	100

15

				Facility	Net
			Year Installed /	Net Capacity	Owned Capacity
Generating Facility	Location	Energy Source	Repowered(1)	(MWs)(2)	(MWs)(2)
Arbor Hill	Adair, IA	Solar	2022	24	24
Franklin	Hampton, IA	Solar	2022	7	7
Neal	Salix, IA	Solar	2022	4	4
Waterloo	Waterloo, IA	Solar	2022	3	3
Hills	Hills, IA	Solar	2022	3	3
				141	141
HYDROELECTRIC:
Moline Unit Nos. 1-4	Moline, IL	Hydroelectric	1941	4	4
Total Available Generating Capacity				14,811	12,016

(1)Repowered dates are associated with component replacements on existing wind-powered generating facilities commonly referred to by the IRS as repowering. IRS rules provide for re-establishment of the PTCs for an existing wind-powered generating facility upon the replacement of a significant portion of its components. If the degree of component replacement in such projects meets IRS guidelines, PTCs are re-established for 10 years beginning with the date the repowered facility is placed in-service.

(2)Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates MidAmerican Energy's ownership of Facility Net Capacity.

The following table shows the percentages of MidAmerican Energy's total energy supplied by energy source for the years ended December 31:

	2023		2022		2021
Wind and other renewable(1)	55	%	58	%	52	%
Coal	22		21		27
Nuclear	8		8		9
Natural gas	5		3		3
Total energy generated	90		90		91
Energy purchased - short-term contracts and other	9		9		8
Energy purchased - long-term contracts (renewable)(1)	1		1		1
	100	%	100	%	100	%

(1)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, (b) sold to third parties in the form of RECs or other environmental commodities, or (c) excluded from energy purchased.

MidAmerican Energy is required to have accredited resources available for dispatch by MISO to continuously meet its customer's needs and reliably operate its electric system. The percentage of MidAmerican Energy's energy supplied by energy source varies from year to year and is subject to numerous operational and economic factors such as planned and unplanned outages, fuel commodity prices, fuel transportation costs, weather, environmental considerations, transmission constraints, and wholesale market prices of electricity. MidAmerican Energy evaluates these factors continuously in order to facilitate economic dispatch of its generating facilities by MISO. When factors for one energy source are less favorable, MidAmerican Energy places more reliance on other energy sources. For example, MidAmerican Energy can generate more electricity using its low cost wind-powered generating facilities when factors associated with these facilities are favorable. When factors associated with wind resources are less favorable, MidAmerican Energy must increase its reliance on more expensive generation or purchased electricity. Refer to "General Regulation" in Item 1 of this Form 10-K for a discussion of energy cost recovery by jurisdiction.

16

Wind

MidAmerican Energy owns more wind-powered generating capacity than any other U.S. rate-regulated electric utility and believes wind-powered generation offers a viable, economical and environmentally prudent means of supplying electricity and complying with laws and regulations. Pursuant to ratemaking principles approved by the IUB, facilities accounting for 89% of MidAmerican Energy's wind-powered generating capacity in-service at December 31, 2023, are authorized to earn a fixed rate of return on equity over their regulatory lives ranging from 10.75% to 12.2% on the depreciated cost of their original construction, which excludes the cost of later replacements, in any future Iowa rate proceeding. MidAmerican Energy's wind-powered generating facilities, including those facilities where a significant portion of the equipment was replaced, commonly referred to as repowered facilities, are eligible for federal renewable electricity PTCs for 10 years beginning with the date the facilities are placed in-service. PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold. PTCs for MidAmerican Energy's wind-powered generating facilities currently in-service began expiring in 2014, with final expiration in 2033. Since 2014, MidAmerican Energy has repowered, or plans to repower, 2,357 MWs of wind-powered generating facilities for which PTCs had expired by the end of 2022.

Of the 7,617 MWs (nameplate capacity) of wind-powered generating facilities in-service as of December 31, 2023, 7,416 MWs were generating PTCs, including 2,316 MWs of repowered facilities. PTCs earned by MidAmerican Energy's wind-powered generating facilities placed in-service prior to 2013, except for repowered facilities, were included in MidAmerican Energy's Iowa EAC, through which MidAmerican Energy is allowed to recover fluctuations in its electric retail energy costs. All of the eligibility of those facilities to earn PTCs had expired by the end of 2022. MidAmerican Energy earned PTCs totaling $681 million, $710 million and $574 million in 2023, 2022 and 2021, respectively, of which —%, 4% and 12%, respectively, were included in the Iowa EAC.

Coal

All of the coal-fueled generating facilities operated by MidAmerican Energy are fueled by low-sulfur, western coal from the Powder River Basin in northeast Wyoming. MidAmerican Energy's coal supply portfolio includes multiple suppliers and mines under short-term and multi-year agreements of varying terms and quantities through 2027. MidAmerican Energy believes supplies from these sources are presently adequate and available to meet MidAmerican Energy's needs. A substantial share of MidAmerican Energy's expected coal supply requirements for 2024 and 2025 are covered under fixed-price contracts. MidAmerican Energy regularly monitors the western coal market for opportunities to enhance its coal supply portfolio.

MidAmerican Energy has a multi-year long-haul coal transportation agreement with BNSF Railway Company ("BNSF"), an affiliate company, for the delivery of coal to all of the MidAmerican Energy-operated coal-fueled generating facilities other than the George Neal Energy Center. Under this agreement, BNSF delivers coal directly to MidAmerican Energy's Walter Scott, Jr. Energy Center and to an interchange point with Canadian Pacific Kansas City Railway Company for short-haul delivery to the Louisa Energy Center. MidAmerican Energy has a multi-year long-haul coal transportation agreement with Union Pacific Railroad Company for the delivery of coal to the George Neal Energy Center.

Nuclear

MidAmerican Energy is a 25% joint owner of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station"), a nuclear generating facility, which is currently licensed by the NRC for operation until December 14, 2032. Constellation Energy Generation, LLC ("Constellation Energy"), is the 75% joint owner and the operator of Quad Cities Station. Approximately one-third of the nuclear fuel assemblies in each reactor core at Quad Cities Station is replaced every 24 months. MidAmerican Energy has been advised by Constellation Energy that it expects to obtain the necessary uranium concentrates or conversion, enrichment or fabrication services to meet the nuclear fuel requirements of Quad Cities Station. In reaction to concerns about the profitability of Quad Cities Station and Constellation Energy's ability to continue its operation, in December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. Currently, Quad Cities is operating under agreements to provide Illinois load serving entities ZECs through June 1, 2027.

Natural Gas and Other

MidAmerican Energy uses natural gas and oil as fuel for intermediate and peak demand electric generation, igniter fuel, transmission support and standby purposes. These sources are presently in adequate supply and available to meet MidAmerican Energy's needs.

17

Regional Transmission Organizations

MidAmerican Energy sells and purchases electricity and ancillary services related to its generation and load in wholesale markets pursuant to the tariffs in those markets. MidAmerican Energy participates predominantly in the MISO energy and ancillary service markets, which provide MidAmerican Energy with wholesale opportunities over a large market area. MidAmerican Energy can enter into wholesale bilateral transactions in addition to market activity related to its assets. MidAmerican Energy is also authorized to participate in the Southwest Power Pool, Inc. and PJM Interconnection, L.L.C. markets and can contract with several other utilities in the region. MidAmerican Energy utilizes financial swaps and physical fixed-price electricity sales and purchases contracts to reduce its exposure to electricity price volatility.

MidAmerican Energy's decisions regarding additions to or reductions of its generation portfolio may be impacted by the MISO's minimum reserve margin requirement. The MISO requires each member to maintain a minimum seasonal reserve margin of its accredited generating capacity over its seasonal peak demand obligation based on the member's seasonal load forecast filed with the MISO each year. The MISO's reserve requirements for the 2023-2024 planning year were 7.4% for summer 2023, 14.9% for fall 2023, 25.5% for winter 2023-2024 and 24.5% for spring 2024. For the summer peak demand season, MidAmerican Energy's owned and contracted capacity accredited for the 2023-2024 MISO capacity auction was 5,984 MWs compared to a peak demand obligation of 5,332 MWs, or a reserve margin of 12.2%. Additionally, MidAmerican Energy had more than adequate reserve margin for the fall, winter and spring seasons when peak demands are typically lower. Some of the excess capacity may be sold through bilateral or MISO capacity auction transactions. The reserve requirements for the 2024-2025 planning year will be 9.0% for summer 2024, 14.2% for fall 2024, 27.4% for winter 2024-2025 and 26.7% for spring 2025. Accredited capacity represents the amount of generation available to meet the requirements of MidAmerican Energy's retail customers and consists of MidAmerican Energy-owned generation, interruptible retail customer load, certain customer private generation that MidAmerican Energy is contractually allowed to dispatch and the net amount of capacity purchases and sales, excluding sales into the MISO annual capacity auction. Accredited capacity may vary significantly from the nominal capacity ratings, particularly for wind or solar facilities whose output is dependent upon energy resource availability at any given time. Additionally, the actual amount of generating capacity available at any time may be less than the accredited capacity due to regulatory restrictions, transmission constraints, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling, modifications or other reasons.

Transmission and Distribution

MidAmerican Energy's transmission and distribution systems included 4,700 circuit miles of transmission lines in four states, 25,500 circuit miles of distribution lines and 340 substations as of December 31, 2023. Electricity from MidAmerican Energy's generating facilities and purchased electricity is delivered to wholesale markets and its retail customers via the transmission facilities of MidAmerican Energy and others. MidAmerican Energy participates in the MISO capacity, energy and ancillary services markets as a transmission-owning member and, accordingly, operates its transmission assets at the direction of the MISO. The MISO manages its energy and ancillary service markets using reliability-constrained economic dispatch of the region's generation. For both the day-ahead and real-time (every five minutes) markets, the MISO analyzes generation commitments to provide market liquidity and transparent pricing while maintaining transmission system reliability by minimizing congestion and maximizing efficient energy transmission. Additionally, through its FERC-approved OATT, the MISO performs the role of transmission service provider throughout the MISO footprint and administers the long-term planning function. The MISO costs of the participants are shared among the participants through a number of mechanisms in accordance with the MISO tariff.

Regulated Natural Gas Operations

MidAmerican Energy is engaged in the distribution of natural gas to customers in its service territory and the related procurement, transportation and storage of natural gas for the benefit of those customers. MidAmerican Energy purchases natural gas from various suppliers and contracts with interstate natural gas pipelines for transportation of the gas to MidAmerican Energy's service territory and for storage and balancing services. MidAmerican Energy sells natural gas and delivery services to end-use customers on its distribution system; sells natural gas to other utilities, municipalities and energy marketing companies; and transports natural gas through its distribution system for end-use customers who have independently secured their supply of natural gas. During 2023, 58% of the total natural gas delivered through MidAmerican Energy's distribution system was associated with transportation service.

Natural gas property consists primarily of natural gas mains and service lines, meters, and related distribution equipment, including feeder lines to communities served from natural gas pipelines owned by others. The natural gas distribution facilities of MidAmerican Energy included 24,900 miles of natural gas main and service lines as of December 31, 2023.

18

Customer Usage and Seasonality

The percentages of natural gas sold to MidAmerican Energy's retail customers by jurisdiction for the years ended December 31 were as follows:

	2023		2022		2021
Iowa	75	%	76	%	76	%
South Dakota	14		14		13
Illinois	10		9		10
Nebraska	1		1		1
	100	%	100	%	100	%

The percentages of natural gas sold to MidAmerican Energy's retail and wholesale customers by class of customer, total Dths of natural gas sold, total Dths of transportation service and the average number of retail customers for the years ended December 31 were as follows:

	2023		2022		2021
Residential	45	%	47	%	44	%
Commercial(1)	21		22		20
Industrial(1)	5		5		5
Total retail	71		74		69
Wholesale(2)	29		26		31
	100	%	100	%	100	%
Total Dths of natural gas sold (in thousands)	106,912		119,508		111,916
Total Dths of transportation service (in thousands)	106,422		102,827		112,631
Total average number of retail customers (in thousands)	796		789		781

(1)Commercial and industrial customers are classified primarily based on the nature of their business and natural gas usage. Commercial customers are non-residential customers that use natural gas principally for heating. Industrial customers are non-residential customers that use natural gas principally for their manufacturing processes.

(2)Wholesale sales are generally made to other utilities, municipalities and energy marketing companies for eventual resale to end-use customers.

There are seasonal variations in MidAmerican Energy's regulated natural gas business that are principally due to the use of natural gas for heating. Typically, 50-60% of MidAmerican Energy's regulated retail natural gas revenue is reported in the months of January, February, March and December.

On December 22, 2022, MidAmerican Energy recorded its all-time highest peak-day delivery through its distribution system of 1,325,160 Dths. This peak-day delivery consisted of 72% traditional retail sales service and 28% transportation service. MidAmerican Energy's 2023/2024 winter heating season preliminary peak-day delivery as of January 31, 2024, was 1,309,311 Dths, reached on January 15, 2024. This preliminary peak-day delivery consisted of 66% traditional retail sales service and 34% transportation service.

Natural Gas Supply and Capacity

MidAmerican Energy uses several strategies designed to maintain a reliable natural gas supply and reduce the impact of volatility in natural gas prices on its regulated retail natural gas customers. These strategies include the purchase of a geographically diverse supply portfolio from producers and third-party energy marketing companies, the use of interstate pipeline storage services and MidAmerican Energy's LNG peaking facilities, and the use of financial derivatives to fix the price on a portion of the anticipated natural gas requirements of MidAmerican Energy's customers. Refer to "General Regulation" in Item 1 of this Form 10-K for a discussion of the PGAs.

19

MidAmerican Energy contracts for firm natural gas pipeline capacity to transport natural gas from key production areas and liquid market centers to its service territory through direct interconnects to the pipeline systems of several interstate natural gas pipeline systems, including Northern Natural Gas, an affiliate company. MidAmerican Energy has multiple pipeline interconnections into several larger markets within its distribution system. Multiple pipeline interconnections create competition among pipeline suppliers for transportation capacity to serve those markets, thus reducing costs. In addition, multiple pipeline interconnections increase delivery reliability and give MidAmerican Energy the ability to optimize delivery of the lowest cost supply from the various production areas and liquid market centers into these markets. Benefits to MidAmerican Energy's distribution system customers are shared among all jurisdictions through a consolidated PGA.

At times, the natural gas pipeline capacity available through MidAmerican Energy's firm capacity portfolio may exceed the requirements of retail customers on MidAmerican Energy's distribution system. Firm capacity in excess of MidAmerican Energy's system needs can be released to other companies to achieve optimum use of the available capacity. Past IUB and South Dakota Public Utilities Commission ("SDPUC") rulings have allowed MidAmerican Energy to retain 30% of the revenue on the resold capacity, with the remaining 70% being returned to customers through the PGAs.

MidAmerican Energy utilizes interstate pipeline natural gas storage services to meet retail customer requirements, manage fluctuations in demand due to changes in weather and other usage factors and manage variation in seasonal natural gas pricing. MidAmerican Energy typically withdraws natural gas from storage during the heating season when customer demand is historically at its peak and injects natural gas into storage during off-peak months when customer demand is historically lower. MidAmerican Energy also utilizes its three LNG facilities to meet peak day demands during the winter heating season. Interstate pipeline storage services and MidAmerican Energy's LNG facilities reduce dependence on natural gas purchases during the volatile winter heating season and can deliver a significant portion of MidAmerican Energy's anticipated retail sales requirements on a peak winter day. For MidAmerican Energy's 2023/2024 winter heating season preliminary peak-day of January 15, 2024, supply sources used to meet deliveries to traditional retail sales service customers included 51% from purchases delivered on interstate pipelines, 37% from interstate pipeline storage services and 12% from MidAmerican Energy's LNG facilities.

MidAmerican Energy attempts to optimize the value of its regulated transportation capacity, natural gas supply and interstate pipeline storage services by engaging in wholesale transactions. IUB and SDPUC rulings have allowed MidAmerican Energy to retain 50% of the respective jurisdictional margins earned on certain wholesale sales of natural gas, with the remaining 50% being returned to customers through the PGAs.

MidAmerican Energy is not aware of any factors that would cause material difficulties in meeting its anticipated retail customer demand under normal operating conditions for the foreseeable future.

Energy Efficiency Programs

MidAmerican Energy has provided a comprehensive set of DSM programs to its Iowa electric and natural gas customers since 1990. The programs, collectively referred to as energy efficiency programs, are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. Current programs offer services to customers such as energy engineering audits and information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, MidAmerican Energy offers rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors, process equipment and systems, as well as incentives for efficient construction. Incentives are also paid to residential customers who participate in the air conditioner load control program and nonresidential customers who participate in the nonresidential load management program. In Iowa, legislation passed in 2018 provides that projected cumulative average annual costs for a natural gas energy efficiency plan cannot exceed 1.5% of expected Iowa natural gas retail revenue and, for an electric demand response plan and separately for an electric energy efficiency plan other than demand response, cannot exceed 2.0% of expected annual Iowa electric retail revenue. Although subject to prudence reviews, state regulations allow for contemporaneous recovery of costs incurred for energy efficiency programs through state-specific energy efficiency service charges paid by all retail electric and natural gas customers. In 2023, $43 million was expensed for MidAmerican Energy's energy efficiency programs, which resulted in estimated first-year energy savings of 119,000 MWhs of electricity and 113,000 Dths of natural gas and an estimated peak load reduction of 406 MWs of electricity and 1,641 Dths per day of natural gas.

20

Human Capital

Employees

All of MidAmerican Funding's employees are employed by MidAmerican Energy. As of December 31, 2023, MidAmerican Energy had approximately 3,500 employees, of which approximately 1,400 were covered by union contracts. MidAmerican Energy has three separate contracts with locals of the International Brotherhood of Electrical Workers and the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union. A contract with the International Brotherhood of Electrical Workers covering substantially all of the union employees expires April 30, 2027. For more information regarding MidAmerican Funding's and MidAmerican Energy's human capital disclosures, refer to Item 1. Business - General section of this Form 10-K.

NV ENERGY (NEVADA POWER AND SIERRA PACIFIC)

General

NV Energy, an indirect wholly owned subsidiary of BHE, is an energy holding company headquartered in Nevada whose principal subsidiaries are Nevada Power and Sierra Pacific. Nevada Power and Sierra Pacific are indirect consolidated subsidiaries of Berkshire Hathaway. Nevada Power is a U.S. regulated electric utility company serving 1.0 million retail customers primarily in the Las Vegas, North Las Vegas, Henderson and adjoining areas. Sierra Pacific is a U.S. regulated electric and natural gas utility company serving 0.4 million retail electric customers and 0.2 million retail and transportation natural gas customers in northern Nevada. The Nevada Utilities are principally engaged in the business of generating, transmitting, distributing and selling electricity and, in the case of Sierra Pacific, in distributing, selling and transporting natural gas. Nevada Power and Sierra Pacific have electric service territories covering approximately 4,500 square miles and 41,400 square miles, respectively. Sierra Pacific has a natural gas service territory covering approximately 900 square miles in Reno and Sparks. Principal industries served by the Nevada Utilities include gaming, recreation, warehousing, manufacturing and governmental services. Sierra Pacific also serves the mining industry. The Nevada Utilities buy and sell electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants to balance and optimize economic benefits of electricity generation, retail customer loads and wholesale transactions.

The Nevada Utilities' electric and natural gas operations are conducted under numerous nonexclusive franchise agreements, revocable permits and licenses obtained from federal, state and local authorities. The franchise agreements, with various expiration dates, are typically for 10- to 20-year terms. The Nevada Utilities operate under certificates of public convenience and necessity as regulated by the PUCN, and as such the Nevada Utilities have an obligation to provide electricity service to those customers within their service territory. In return, the PUCN has established rates on a cost-of-service basis, which are designed to allow the Nevada Utilities an opportunity to recover all prudently incurred costs of providing services and an opportunity to earn a reasonable return on their investment.

NV Energy's monthly net income is affected by the seasonal impact of weather on electricity and natural gas sales and seasonal retail electricity prices from the Nevada Utilities'. For 2023, 86% of NV Energy annual net income was recorded in the months of June through September.

Regulated electric utility operations is Nevada Power's only segment while regulated electric utility operations and regulated natural gas operations are the two segments of Sierra Pacific.

21

Sierra Pacific's operating revenue and operating income derived from the following business activities for the years ended December 31 were as follows (dollars in millions):

	2023				2022				2021
Operating revenue:
Electric	$	1,194	83	%	$	1,025	86	%	$	848	88	%
Gas	237		17		168		14		117		12
Total operating revenue	$	1,431	100	%	$	1,193	100	%	$	965	100	%
Operating income:
Electric	$	133	88	%	$	146	88	%	$	148	89	%
Gas	19		12		19		12		19		11
Total operating income	$	152	100	%	$	165	100	%	$	167	100	%

Nevada Power was incorporated under the laws of the state of Nevada in 1929 and its principal executive offices are located at 6226 West Sahara Avenue, Las Vegas, Nevada 89146, its telephone number is (702) 402-5000 and its internet address is www.nvenergy.com.

Sierra Pacific was incorporated under the laws of the state of Nevada in 1912 and its principal executive offices are located at 6100 Neil Road, Reno, Nevada 89511, its telephone number is (775) 834-4011 and its internet address is www.nvenergy.com.

22

Regulated Electric Operations

Customers

The Nevada Utilities' sell electricity to retail customers in a single state jurisdiction. Electricity sold to the Nevada Utilities' retail and wholesale customers by class of customer and the average number of retail customers for the years ended December 31 were as follows:

	2023			2022			2021
Nevada Power:
GWhs sold:
Residential	9,584	41	%	10,299	42	%	10,415	44	%
Commercial	4,807	20		4,904	21		4,838	21
Industrial	5,827	25		5,630	23		5,270	22
Other	179	1		191	1		198	1
Total fully bundled	20,397	87		21,024	87		20,721	88
Distribution only service	2,831	12		2,786	11		2,646	11
Total retail	23,228	99		23,810	98		23,367	99
Wholesale	230	1		586	2		356	1
Total GWhs sold	23,458	100	%	24,396	100	%	23,723	100	%
Average number of retail customers (in thousands):
Residential	899	89	%	886	89	%	871	88	%
Commercial	114	11		113	11		112	12
Industrial	2	—		2	—		2	—
Total	1,015	100	%	1,001	100	%	985	100	%
Sierra Pacific:
GWhs sold:
Residential	2,655	23	%	2,747	22	%	2,769	23	%
Commercial	2,998	25		3,124	26		3,056	26
Industrial	2,684	23		2,867	23		3,716	31
Other	11	—		13	—		15	—
Total fully bundled	8,348	71		8,751	71		9,556	80
Distribution only service	2,829	24		2,757	23		1,639	14
Total retail	11,177	95		11,508	94		11,195	94
Wholesale	621	5		741	6		656	6
Total GWhs sold	11,798	100	%	12,249	100	%	11,851	100	%
Average number of retail customers (in thousands):
Residential	326	87	%	322	87	%	316	87	%
Commercial	50	13		49	13		49	13
Total	376	100	%	371	100	%	365	100	%

Variations in weather, economic conditions, particularly for gaming, mining and wholesale customers and various conservation, energy efficiency and private generation measures and programs can impact customer energy requirements. Wholesale sales are impacted by market prices for energy relative to the incremental cost to generate power.

There are seasonal variations in the Nevada Utilities' electric business that are principally related to weather and the related use of electricity for air conditioning. Typically, 47-52% of Nevada Power's and 37-40% of Sierra Pacific's regulated electric revenue is reported in the months of June through September.

23

The annual hourly peak customer demand on the Nevada Utilities' electric systems occurs as a result of air conditioning use during the cooling season. Peak demand represents the highest demand on a given day and at a given hour. On July 21, 2023, customer usage of electricity caused an hourly peak demand of 6,311 MWs on Nevada Power's electric system, which is 11 MWs more than the record hourly peak demand of 6,300 MWs set July 9, 2021. On July 21, 2023, customer usage of electricity caused an hourly peak demand of 1,825 MWs on Sierra Pacific's electric system, which is 281 MWs less than the record hourly peak demand of 2,106 MWs set July 12, 2021.

Generating Facilities and Fuel Supply

The Nevada Utilities have ownership interest in a diverse portfolio of generating facilities. The following table presents certain information regarding the Nevada Utilities' owned generating facilities as of December 31, 2023:

				Facility	Net Owned
				Net Capacity	Capacity
Generating Facility	Location	Energy Source	Installed	(MWs)(1)	(MWs)(1)
Nevada Power:
NATURAL GAS:
Lenzie	Las Vegas, NV	Natural gas	2006	1,218	1,218
Clark	Las Vegas, NV	Natural gas	1973-2008	1,102	1,102
Harry Allen	Las Vegas, NV	Natural gas	1995-2011	628	628
Higgins	Primm, NV	Natural gas	2004	602	602
Silverhawk	Las Vegas, NV	Natural gas	2004	590	590
Las Vegas	Las Vegas, NV	Natural gas	1994-2003	272	272
Sun Peak	Las Vegas, NV	Natural gas/oil	1991	210	210
				4,622	4,622
RENEWABLES:
Nellis	Las Vegas, NV	Solar	2015	15	15
Goodsprings	Goodsprings, NV	Waste heat	2010	5	5
				20	20
Total Available Generating Capacity				4,642	4,642
Sierra Pacific:
NATURAL GAS:
Tracy	Sparks, NV	Natural gas	1974-2008	763	763
Ft. Churchill	Yerington, NV	Natural gas	1968-1971	196	196
Clark Mountain	Sparks, NV	Natural gas	1994	128	128
				1,087	1,087
COAL:
Valmy Unit Nos. 1 and 2	Valmy, NV	Coal	1981-1985	522	261
RENEWABLES:
Ft. Churchill	Yerington, NV	Solar	2015	20	20
Total Available Generating Capacity				1,629	1,368
Total NV Energy Available Generating Capacity				6,271	6,010
PROJECTS UNDER CONSTRUCTION:
Silverhawk peakers project	Las Vegas, NV	Natural Gas	Est. 2024	444	444
Dry Lake (2)	Dry Lake, NV	Solar	Est. 2024	150	150
				6,865	6,604

(1)Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates Nevada Power or Sierra Pacific's ownership of Facility Net Capacity.

24

(2)In addition to the 150-MW solar photovoltaic facility, Dry Lake has 100 MW of co-located battery energy storage that will be developed in Clark County, Nevada with commercial operation expected by 2024.

In December 2023, Nevada Power put into service its Reid Gardner battery energy storage system located in Moapa, Nevada, having total Facility Net Capacity and Net Owned Capacity of 220 MWs.

The following table shows the percentages of the Nevada Utilities' total energy supplied by energy source for the years ended December 31:

	2023		2022		2021
Nevada Power:
Total energy generated(1) - natural gas	65	%	60	%	64	%
Energy purchased - long-term contracts (renewable)(2)	24		23		19
Energy purchased - long-term contracts (non-renewable)	5		9		10
Energy purchased - short-term contracts and other	6		8		7
	100	%	100	%	100	%
Sierra Pacific:
Natural gas	44	%	41	%	43	%
Coal	8		11		11
Total energy generated(1)	52		52		54
Energy purchased - long-term contracts (renewable)(2)	32		28		17
Energy purchased - long-term contracts (non-renewable)	9		11		14
Energy purchased - short-term contracts and other	7		9		15
	100	%	100	%	100	%

(1)     Energy generated from renewable generating facilities is not meaningful.

(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, (b) sold to third parties in the form of RECs or other environmental commodities, or (c) excluded from energy purchased.

The Nevada Utilities are required to have resources available to continuously meet their customer needs and reliably operate their electric systems. The percentage of the Nevada Utilities' energy supplied by energy source varies from year-to-year and is subject to numerous operational and economic factors such as planned and unplanned outages; fuel commodity prices; fuel transportation costs; weather; environmental considerations; transmission constraints; and wholesale market prices of electricity. The Nevada Utilities evaluate these factors continuously in order to facilitate economic dispatch of their generating facilities. When factors for one energy source are less favorable, the Nevada Utilities place more reliance on other energy sources. As long as the Nevada Utilities' purchases are deemed prudent by the PUCN, through their annual prudency review, the Nevada Utilities are permitted to recover the cost of fuel and purchased power. The Nevada Utilities also have the ability to reset quarterly the BTERs, with PUCN approval, based on the last 12 months fuel costs and purchased power and to reset the quarterly DEAA.

The Nevada Utilities have adopted an approach to managing the energy supply function that has three primary elements. The first element is a set of management guidelines for procuring and optimizing the supply portfolio that is consistent with the requirements of a load serving entity with a full requirements obligation, and with the growth of private generation serving a small but growing group of customers with partial requirements. The second element is an energy risk management and control approach that ensures clear separation of roles between the day-to-day management of risks and compliance monitoring and control and ensures clear distinction between policy setting (or planning) and execution. Lastly, the Nevada Utilities pursue a process of ongoing regulatory involvement and acknowledgment of the resource portfolio management plans.

The Nevada Utilities have entered into multiple long-term power purchase contracts (three or more years) with suppliers that generate electricity utilizing renewable resources and natural gas. Nevada Power has entered into contracts with a total capacity of 2,937 MWs with contract termination dates ranging from 2024 to 2067. Included in these contracts are 2,852 MWs of capacity from renewable energy, of which 818 MWs of capacity are under development or construction and not currently available. Sierra Pacific has entered into contracts with a total capacity of 1,098 MWs with contract termination dates ranging from 2024 to 2053. Included in these contracts are 1,086 MWs of capacity from renewable energy, of which 140 MWs of capacity are owned and under development or construction and not currently available.

25

The Nevada Utilities manage certain risks relating to their supply of electricity and fuel requirements by entering into various contracts, which may be accounted for as derivatives, including forwards, futures, options, swaps and other agreements. Refer to NV Energy's "General Regulation" section in Item 1 of this Form 10-K for a discussion of energy cost recovery by jurisdiction and Nevada Power's Item 7A and Sierra Pacific's Item 7A in this Form 10-K for a discussion of commodity price risk and derivative contracts.

Natural Gas

The Nevada Utilities rely on indexed physical gas purchases for the majority of natural gas needed to operate their generating facilities. To secure natural gas supplies for the generating facilities, the Nevada Utilities execute purchases pursuant to a PUCN approved four-season laddering strategy. In 2023, natural gas supply net purchases averaged 299,343 and 154,897 Dths per day with the winter period contracts averaging 290,172 and 195,554 Dths per day and the summer period contracts averaging 305,813 and 126,209 Dths per day for Nevada Power and Sierra Pacific, respectively. The Nevada Utilities believe supplies from these sources are presently adequate and available to meet its needs.

The Nevada Utilities contract for firm natural gas pipeline capacity to transport natural gas from production areas to their service territory through direct interconnects to the pipeline systems of several interstate natural gas pipeline systems, including Nevada Power who contracts with Kern River, an affiliated company. Sierra Pacific utilizes natural gas storage contracted from interstate pipelines to meet retail customer requirements and to manage the daily changes in demand due to changes in weather and other usage factors. The stored natural gas is typically replaced during off-peak months when the demand for natural gas is historically lower than during the heating season.

Coal

Sierra Pacific relies on spot market solicitations for coal supplies and will regularly monitor the western coal market for opportunities to meet these needs. Sierra Pacific has a transportation services contract with Union Pacific Railroad Company to ship coal from various origins in central Utah, western Colorado and Wyoming that expires December 31, 2025. Sierra Pacific has a transportation services contract with Burlington Northern Sante Fe Railroad Company to ship coal from western Montana that expires December 31, 2024. The Valmy generating facility, Sierra Pacific's remaining facility requiring coal, has an approved retirement date of December 2025. Sierra Pacific has proposed in its Fifth Amendment to the 2021 Joint Integrated Resource Plan to convert the existing coal fueled plant to a cleaner natural gas fueled plant. Nevada Power has no coal requirements.

Energy Imbalance Market

The Nevada Utilities participate in the EIM operated by the California ISO, which reduces costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, more effectively integrates renewables and enhances reliability through improved situational awareness and responsiveness. The EIM expands the real-time component of the California ISO's market technology to optimize and balance electricity supply and demand every five minutes across the EIM footprint. The EIM is voluntary and available to all balancing authorities in the western U.S. EIM market participants submit bids to the California ISO market operator before each hour for each generating resource they choose to be dispatched by the market. Each bid is comprised of a dispatchable operating range, ramp rate and prices across the operating range. The California ISO market operator uses sophisticated technology to select the least-cost resources to meet demand and send simultaneous dispatch signals to every participating generator across the EIM footprint every five minutes. In addition to generation resource bids, the California ISO market operator also receives continuous real-time updates of the transmission grid network, meteorological and load forecast information that it uses to optimize dispatch instructions. Outside the EIM footprint, utilities in the western U.S. do not utilize comparable technology and are largely limited to transactions within the borders of their balancing authority area to balance supply and demand intra-hour using a combination of manual and automated dispatch. The EIM delivers customer benefits by leveraging automation and resource diversity to result in more efficient dispatch, more effective integration of renewables and improved situational awareness. Benefits are expected to increase further with renewable resource expansion and as more entities join the EIM bringing incremental diversity.

26

Transmission and Distribution

The Nevada Utilities' transmission system is part of the Western Interconnection, a regional grid in the U.S. The Western Interconnection includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico. The Nevada Utilities' transmission system, together with contractual rights on other transmission systems, enables the Nevada Utilities to integrate and access generation resources to meet their customer load requirements. Nevada Power's transmission and distribution systems included approximately 1,900 miles of transmission lines, 14,300 miles of distribution lines and 220 substations as of December 31, 2023. Sierra Pacific's transmission and distribution systems included approximately 4,200 miles of transmission lines, 9,600 miles of distribution lines and 210 substations as of December 31, 2023.

ON Line is a 231-mile, 500-kV transmission line connecting Nevada Power's and Sierra Pacific's service territories. ON Line provides the ability to jointly dispatch energy throughout Nevada and provide access to renewable energy resources in parts of northern and eastern Nevada, which enhances the Nevada Utilities' ability to manage and optimize their generating facilities. ON Line provides between 600 MWs northbound and 900 MWs southbound of transfer capability with interconnection between the Robinson Summit substation on the Sierra Pacific system and the Harry Allen substation on the Nevada Power system. ON Line was a joint project between the Nevada Utilities and Great Basin Transmission, LLC. The Nevada Utilities own a 25% interest in ON Line and have entered into a long-term transmission use agreement with Great Basin Transmission, LLC for its 75% interest in ON Line until 2054. The Nevada Utilities share of its 25% interest in ON Line and the long-term transmission use agreement is split 75% for Nevada Power and 25% for Sierra Pacific.

The PUCN has approved the Nevada Utilities' Greenlink Nevada transmission expansion program, with an estimated cost of approximately $3.1 billion, which builds a foundation for the Nevada Utilities to accommodate existing and future transmission network customers, increase transmission system reliability, create access to diversified renewable resources, facilitate development of existing designated solar energy zones, facilitate conventional generation retirement and achieve Nevada's carbon reduction and eventual net-zero objectives. The Greenlink program consists of a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation, near Yerington, Nevada to the Northwest substation, near Las Vegas, Nevada to the Harry Allen substation, near Las Vegas, Nevada; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation, near Yerington, Nevada to the Robinson Summit substation, near Ely, Nevada; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation, near Yerington, Nevada to the Mira Loma substations, near Yerington, Nevada; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation, near Yerington, Nevada to the Comstock Meadows substations, near Yerington, Nevada. The Greenlink program will be constructed in stages that are estimated to be placed in-service between May 2027 and December 2028. The Nevada Utilities will jointly own and operate the Greenlink transmission lines with Nevada Power having a 70% ownership share in Greenlink West and North and Sierra Pacific having a 30% ownership share. Sierra Pacific will have a 100% ownership share in the Greenlink Common Ties. Through December 31, 2023, $187 million had been spent.

Natural Disaster Protection Plan

The Nevada Utilities have developed detailed natural disaster protection plans for its service territory and areas in which it owns and operates assets. Natural disaster protection plans are filed annually with the PUCN on or before March 1 of every third year with annual updates to be filed on or before September 1 of the second and third years of the plan. These plans include capital investment in asset hardening and meteorological systems, the implementation of risk modeling tools and the Nevada Utilities' ongoing elevated fire risk settings, inspections, vegetation management, enhancement to situational awareness to include implementation of wildfire alert cameras and weather stations in extreme fire-risk areas and public safety outage management ("PSOM") programs and policies.

Asset Hardening

The Nevada Utilities have and continue to invest in rebuilding overhead transmission and distribution lines with covered conductor and fire mesh and in some cases have converted overhead distribution lines to underground. These system hardening efforts reduce the exposure of the Nevada Utilities' lines to interference from trees and other objects. Covered conductor helps mitigate the risk of fault-caused electrical arcs that could cause an ignition. Overall, mitigated overhead lines help reduce ignition risk and improve reliability during storms or periods of significant wildfire risk.

The Nevada Utilities compiled an assessment of heightened threat areas ("HTAs") for wildfires that are presented as different tiers to characterize wildfire risk and potential catastrophic wildfire risk. The different tiers that the Nevada Utilities use to categorize their HTAs are Tier 1, Tier1E - Elevated ("Tier 1E"), Tier 2 (high) and Tier 3 (extreme).

27

Approximately 2,730 miles, or 9%, of the Nevada Utilities' transmission and distribution lines are in Tier 1E, Tier 2 and Tier 3 HTAs, covering approximately 6% of its service territory and approximately 0.2% of its customer base.

As of December 31, 2023, the 2,730 miles of transmission and distribution lines in Tier 1E, Tier 2 and Tier 3 HTAs were as follows:

•1,964 miles, or 72%, with bare conductor miles, a portion of which in Tier 3 is fully mitigated by system relay fast trip protection schemes that are expanding into Tiers 2 and 1E with completion by the end of 2024;

•16 miles, or 1%, with new covered conductor miles; and

•750 miles, or 27%, with underground miles.

The on-going asset hardening of the HTAs is a priority for the Nevada Utilities and a key part of the developed wildfire mitigation plans.

Refer to "Future Uses of Cash" in Item 7 of this Form 10-K for further discussion of the Nevada Utilities' natural disaster protection plan related capital expenditures, including asset hardening.

Elevated Fire Risk Settings

Elevated fire risk settings are available across the HTAs in the Nevada Utilities' service territory. Upon declaration of wildfire season, the Nevada Utilities place all Tier 3 circuits and certain Tier 2 and Tier 1E circuits into fire season mode with no circuit reclosing which reduces the potential for sparking on multiple reclosing events when faults occur. Additionally, Fast Trip Fire Mode is an instantaneous lockout setting available at most HTA substations that is enabled when certain risk conditions are present to provide an enhanced level of protection to limit the potential for wildfire ignition.

Meteorology and Risk Modeling

The Nevada Utilities have installed 65 weather stations that monitor weather conditions and model the impact to the electrical infrastructure. These weather stations combined with the Nevada Utilities' dedicated full-time meteorologist provide the Nevada Utilities with the ability to forecast weather and fire risk impact data twice daily. The Nevada Utilities will continue to install additional weather stations to refine weather modeling in areas where geographic terrain conditions require a dense network of weather stations in order to provide the necessary granular data. The Nevada Utilities have also installed 11 fire cameras equipped with artificial intelligence that provide around-the-clock monitoring and alerts of new fire starts.

Asset Inspection Program

Within the identified HTAs, the Nevada Utilities conduct an annual inspection of overhead facilities with an accelerated correction timeline for any conditions noted. A detailed inspection of facilities located in HTAs is conducted every three to 10 years based on the identified risk level.

Vegetation Management

The Nevada Utilities' vegetation management program consists of prioritized patrols and inspections and vegetation clearing work including right-of-way clearing, tree trimming and ground clearing of equipment poles in all HTAs. The Nevada Utilities collaborate with state and federal agencies for enhanced ground clearing to create resilient corridors of cleared vegetation to deter fire spread.

Public Safety Outage Management

A PSOM is used as a preventative measure prior to extraordinary weather conditions that may pose threats to the public, customers, infrastructure or the environment where the electrical network is de-energized proactively under certain conditions. This program includes areas of wildfire risk in Tier 3, Tier 2 and Tier 1E where proactive de-energization zones are identified. In determining whether to initiate a PSOM, the Nevada Utilities evaluate conditions that may create an unacceptable level of risk of electric infrastructure being damaged and causing an ignition using data from meteorological systems and forecasting tools. During 2023, the Nevada Utilities continued to actively utilize the PSOM program to address extreme-risk weather conditions.

28

Future Generation, Conservation and Energy Efficiency

Energy Supply Planning

Within the energy supply planning process, there are four key components covering different time frames:

•IRPs are filed by the Nevada Utilities for approval by the PUCN every three years and the Nevada Utilities may, as necessary, file amendments to their IRPs. IRPs are prepared in compliance with Nevada laws and regulations and cover a 20-year period. Nevada law governing the IRP process was modified in 2017 and now requires joint filings by Nevada Power and Sierra Pacific. IRPs develop a comprehensive, integrated plan that considers customer energy requirements and propose the resources to meet those requirements in a manner that is consistent with prevailing market fundamentals. The ultimate goal of the IRPs is to balance the objectives of minimizing costs and reducing volatility while reliably meeting the electric needs of the Nevada Utilities' customers. Costs incurred to complete projects approved through the IRP process still remain subject to review for reasonableness by the PUCN.

•Energy Supply Plans ("ESP") are filed with the PUCN for approval and operate in conjunction with the PUCN-approved 20-year IRP. The ESP has a one- to three-year planning horizon and is an intermediate-term resource procurement and risk management plan that establishes the supply portfolio strategies within which intermediate-term resource requirements will be met with PUCN approval required for executing contracts of longer than three years.

•Distributed Resource Plans ("DRP") are filed with the PUCN for approval and operate in conjunction with the PUCN-approved 20-year IRP. The DRP establishes a formal process to aid in the cost-effective integration of distributed resources into the Nevada Utilities' distribution and transmission process and ultimately the NV Energy utilities' electricity grid.

•Action plans are filed with the PUCN for approval and operate in conjunction with the PUCN-approved 20-year IRP and PUCN-approved ESP. The action plan establishes tactical execution activities with a three-year focus.

In its 2021 Integrated Resource Plan Fourth Amendment filed November 30, 2022, NV Energy requested approval for a 20-megawatt Advanced Geothermal System power purchase agreement with Eavor, a 120-megawatt geothermal portfolio power purchase agreement with Ormat, and the development of a company-owned, 200-megawatt, 800 megawatt-hour grid-tied battery energy storage system in Sierra Pacific's territory at Valmy station. In June 2023, the PUCN granted in part and denied in part the fourth amendment as delineated in the order.

In compliance with SB 448, the Nevada Utilities filed their second and third amendments to the 2021 joint IRP in July and September 2022, respectively. The Nevada Utilities requested an approval to amend the Demand Side Plan for the action period for 2022-2024 in July's filing and requested in September an approval of a DRP amendment to implement the state's first Transportation Electrification Plan ("TEP") and approve proposed tariffs and schedules to implement the TEP. In November 2022, the Nevada Utilities filed an all-party settlement stipulation of the second amendment to the IRP, resolving all issues. In March 2023, the PUCN issued an order accepting the stipulation, granting in part and denying in part the Joint Application as modified by the Order and the Stipulation, accepting in part, deeming inadequate in part, and modifying the third amendment to the Joint IRP, and approving certain programs in the TEP, authorizing a lower program budget of $70 million and ordering specific caps on the program management and contingency budget amounts. The unapproved programs have been deferred for approval in future TEP filings. The PUCN also granted regulatory asset treatment of the approved program costs. In April 2023, interveners filed a petition for reconsideration of the PUCN's March 2023 order. In May 2023, the PUCN granted in part and denied in part the petition for reconsideration and affirmed the March 2023 order.

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

29

Energy Efficiency Programs

The Nevada Utilities have provided a comprehensive set of DSM programs which include energy efficiency, demand response, and conservation programs to their Nevada electric customers. The programs are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. Current programs offer services to customers such as energy audits and customer education and awareness efforts that provide information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, the Nevada Utilities have offered rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, electric water heating, weatherization, motors, process equipment and systems, as well as incentives for efficient construction. Incentives are also paid to residential customers who participate in the air conditioner load control program and nonresidential customers who participate in the smart thermostat and energy storage demand response program and nonresidential load management program. Energy efficiency program costs are recovered through annual rates set by the PUCN and adjusted based on the Nevada Utilities' annual filing to recover current program costs and any over or under collections from the prior filing, subject to prudence review. During 2023, Nevada Power spent $46 million on energy efficiency programs, resulting in an estimated 225,753 MWhs of electric energy savings and an estimated 156 MWs of electric peak load management. During 2023, Sierra Pacific spent $13 million on energy efficiency programs, resulting in an estimated 53,195 MWhs of electric energy savings and an estimated 25 MWs of electric peak load management.

Regulated Natural Gas Operations

Sierra Pacific is engaged in the distribution of natural gas to customers in its service territory and the related procurement, transportation and storage of natural gas for the benefit of those customers. Sierra Pacific purchases natural gas from various suppliers and contracts with interstate natural gas pipelines for transportation of the natural gas from the production areas to Sierra Pacific's service territory and for storage services to manage fluctuations in system demand and seasonal pricing. Sierra Pacific sells natural gas and delivery services to end-use customers on its distribution system; sells natural gas to other utilities, municipalities and energy marketing companies; and transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. During 2023, 6% of the total natural gas delivered through Sierra Pacific's distribution system was for transportation service.

Natural gas property consists primarily of natural gas mains and service lines, meters, and related distribution equipment, including feeder lines to communities served from natural gas pipelines owned by others. The natural gas distribution facilities of Sierra Pacific included 3,600 miles of natural gas mains and service lines as of December 31, 2023.

Customer Usage and Seasonality

The percentages of natural gas sold to Sierra Pacific's retail and wholesale customers by class of customer, total Dths of natural gas sold, total Dths of transportation service and the average number of retail customers for the years ended December 31 were as follows:

	2023		2022		2021
Residential	52	%	55	%	53	%
Commercial(1)	26		28		28
Industrial(1)	12		11		10
Total retail	90		94		91
Wholesale(2)	10		6		9
	100	%	100	%	100	%
Total Dths of natural gas sold (in thousands)	23,613		20,622		20,050
Total Dths of transportation service (in thousands)	1,453		1,576		1,850
Total average number of retail customers (in thousands)	183		180		177

(1)Commercial and industrial customers are classified primarily based on the nature of their business and natural gas usage. Commercial customers are non-residential customers with monthly gas usage less than 12,000 therms during five consecutive winter months. Industrial customers are non-residential customers that use natural gas in excess of 12,000 therms during one or more winter months.

(2)Wholesale sales are generally made to other utilities, municipalities and energy marketing companies for eventual resale to end-use customers.

30

There are seasonal variations in Sierra Pacific's regulated natural gas business that are principally due to the use of natural gas for heating. Typically, 47-56% of Sierra Pacific's regulated natural gas revenue is reported in the months of December through March.

On January 31, 2023, Sierra Pacific recorded its highest peak-day natural gas delivery of 160,974 Dths, which is 2,600 Dths less than the record peak-day delivery of 163,574 Dths set on December 9, 2013. This peak-day delivery consisted of 95% traditional retail sales service and 5% transportation service.

Fuel Supply and Capacity

The purchase of natural gas for Sierra Pacific's regulated natural gas operations is done in combination with the purchase of natural gas for Sierra Pacific's regulated electric operations. In response to energy supply challenges, Sierra Pacific has adopted an approach to managing the energy supply function that has three primary elements, as discussed earlier under Generating Facilities and Fuel Supply. Similar to Sierra Pacific's regulated electric operations, as long as Sierra Pacific's purchases of natural gas are deemed prudent by the PUCN, through its annual prudency review, Sierra Pacific is permitted to recover the cost of natural gas. Sierra Pacific also has the ability, with PUCN approval, to reset quarterly the BTERs, based on the last 12 months fuel costs, and to reset quarterly DEAA.

Human Capital

Employees

As of December 31, 2023, Nevada Power had approximately 1,500 employees, of which approximately 800 were covered by a union contract with the International Brotherhood of Electrical Workers.

As of December 31, 2023, Sierra Pacific had approximately 1,000 employees, of which approximately 500 were covered by a union contract with the International Brotherhood of Electrical Workers.

For more information regarding Nevada Power's and Sierra Pacific's human capital disclosures, refer to Item 1. Business - General section of this Form 10-K.

NORTHERN POWERGRID

Northern Powergrid, an indirect wholly owned subsidiary of BHE, is a holding company which owns two companies that distribute electricity in Great Britain, Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc. In addition to the Northern Powergrid Distribution Companies, Northern Powergrid also owns a meter asset rental business that leases meters to energy suppliers in the United Kingdom, an engineering contracting business that provides electrical infrastructure contracting services primarily to third parties, a hydrocarbon exploration and development business that is focused on developing integrated upstream gas projects in Europe and Australia ("CE Gas") and ownership interests in two solar generation facilities in Australia having a total net owned capacity of 260 MWs.

The Northern Powergrid Distribution Companies serve 4.0 million end-users and operate in the north-east of England from North Northumberland through Tyne and Wear, County Durham and Yorkshire to North Lincolnshire, an area covering 10,000 square miles. The principal function of the Northern Powergrid Distribution Companies is to build, maintain and operate the electricity distribution network through which the end-user receives a supply of electricity.

The Northern Powergrid Distribution Companies receive electricity from the national grid transmission system and from generators that are directly connected to the distribution network and distribute it to end-users' premises using their networks of transformers, switchgear and distribution lines and cables. Substantially all of the end-users in the Northern Powergrid Distribution Companies' distribution service areas are directly or indirectly connected to the Northern Powergrid Distribution Companies' networks and electricity can only be delivered to these end-users through their distribution systems, thus providing the Northern Powergrid Distribution Companies with distribution volumes that are relatively stable from year to year. The Northern Powergrid Distribution Companies charge fees for the use of their distribution systems to the suppliers of electricity.

31

The suppliers purchase electricity from generators, sell the electricity to end-user customers and use the Northern Powergrid Distribution Companies' distribution networks pursuant to an industry standard "Distribution Connection and Use of System Agreement." During 2023, E.ON and certain of its affiliates and British Gas Trading Limited represented 19% and 15%, respectively, of the total combined distribution revenue of the Northern Powergrid Distribution Companies. Variations in demand from end-users can affect the revenues that are received by the Northern Powergrid Distribution Companies in any year, but such variations have no effect on the total revenue that the Northern Powergrid Distribution Companies are allowed to recover in a price control period. Under- or over-recoveries against price-controlled revenues are carried forward into prices for future years.

The Northern Powergrid Distribution Companies' combined service territory features a diverse economy with no dominant sector. The mix of rural, agricultural, urban and industrial areas covers a broad customer base ranging from domestic usage through farming and retail to major industry including automotives, chemicals, mining, steelmaking and offshore marine construction. The industry within the area is concentrated around the principal centers of Newcastle, Middlesbrough, Sheffield and Leeds.

The price-controlled revenue of the Northern Powergrid Distribution Companies is set out in the special conditions of the licenses of those companies. The licenses are enforced by the regulator, GEMA, through Ofgem, and limit increases to allowed revenues (or may require decreases) based upon the rate of inflation, other specified factors and other regulatory action. The current electricity distribution price control became effective April 1, 2023 and will continue through March 31, 2028.

GWhs and percentages of electricity distributed to the Northern Powergrid Distribution Companies' end-users and the total number of end-users as of and for the years ended December 31 were as follows:

	2023			2022			2021
GWhs distributed:
Residential	11,638	38	%	11,880	37	%	13,334	40	%
Commercial	3,534	11		3,737	12		3,643	10
Industrial	15,655	50		16,239	50		16,424	49
Other	279	1		301	1		318	1
	31,106	100	%	32,157	100	%	33,719	100	%
Number of end-users (in thousands):	3,954			3,953			3,941

As of December 31, 2023, the combined electricity distribution network of the Northern Powergrid Distribution Companies included approximately 17,100 miles of overhead lines, 44,000 miles of underground cables and 790 major substations.

BHE PIPELINE GROUP (EASTERN ENERGY GAS AND EGTS)

The BHE Pipeline Group consists of BHE GT&S, Northern Natural Gas and Kern River, each an indirect wholly owned subsidiary of BHE. The BHE Pipeline Group operates approximately 21,000 miles of pipeline with a design capacity of approximately 21.1 Bcf of natural gas per day, transported approximately 15% of the total natural gas consumed in the U.S. during 2023 and owns assets in 27 states. The BHE Pipeline Group also operates 22 natural gas storage facilities with a total working gas capacity of 515.6 Bcf and an LNG export, import and storage facility.

The Pipeline Companies compete with other pipelines on the basis of cost, flexibility, reliability of service and overall customer service, with the customer's decision being made primarily on the basis of delivered price, which includes both the natural gas commodity cost and transportation costs. The Pipeline Companies also compete with midstream operators and gas marketers seeking to provide or arrange transportation, storage and other services to meet customer needs. Natural gas competes with alternative energy sources, including coal, nuclear energy, wind, geothermal, solar and fuel oil and the electricity generated from these alternative energy sources. The Pipeline Companies generate a substantial portion of their revenue from long-term firm contracts for transportation and storage services and are therefore insulated from competitive factors during the terms of the contracts. When these long-term contracts expire, the Pipeline Companies face competitive pressures from other natural gas pipeline facilities.

32

Subject to regulatory requirements, the Pipeline Companies attempt to recontract or remarket capacity at the maximum rates allowed under their tariffs, although at times the Pipeline Companies discount these rates to remain competitive. Historically, the Pipeline Companies have been able to provide competitively priced services because of access to a variety of relatively low cost supply basins, cost control measures and the relatively high level of firm entitlement that is sold on a seasonal and annual basis, which lowers the per unit cost of transportation. To date, the Pipeline Companies have avoided significant pipeline system bypasses.

BHE GT&S

BHE GT&S' operations, through its ownership of Eastern Energy Gas, includes three interstate natural gas pipeline systems, one of the nation's largest underground natural gas storage systems and one LNG export, import and storage facility. BHE GT&S' operations also include smaller LNG facilities and a gathering and processing company.

Eastern Energy Gas' principal subsidiaries are EGTS and CGT. EGTS' operations include natural gas transmission and storage pipelines 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. CGT's operations include an interstate natural gas pipeline system located in South Carolina and Georgia. Eastern Energy Gas also owns a 50% equity interest in Iroquois Gas Transmission System L.P. ("Iroquois"). Iroquois owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut.

Eastern Energy Gas' LNG operations involve the export, import and storage of LNG at the Cove Point LNG Facility that is owned by Cove Point, located in Maryland, as well as the transmission of regasified LNG to the interstate pipeline grid and mid-Atlantic markets and the liquefaction of natural gas for export as LNG. Cove Point's LNG Facility has an operational peak regasification daily send-out capacity of approximately 1.8 million Dth and an aggregate LNG storage capacity of approximately 14.6 billions of cubic feet equivalent ("Bcfe"). In addition, Cove Point has a small liquefier that has the potential to produce approximately 15,000 Dth/day. The Liquefaction Facility consists of one LNG train with a nameplate outlet capacity of 5.25 million tonnes per annum ("Mtpa"). Cove Point has authorization from the DOE to export up to 0.77 Bcfe/day (approximately 5.75 Mtpa) should the Liquefaction Facility perform better than expected. Cove Point's 36-inch diameter underground interstate natural gas pipelines are approximately 139 miles, with interconnections to Transcontinental Gas Pipeline, LLC in Fairfax County, Virginia, and with Columbia Gas Transmission, LLC and EGTS in Loudoun County, Virginia. Eastern Energy Gas operates, as the general partner, and prior to September 1, 2023, owned a 25% limited partner interest in the Cove Point LNG export, import and storage facility. On September 1, 2023, Eastern Energy Gas completed its acquisition of 50% of the limited partner interests in Cove Point from DEI, and accordingly, owns an aggregate of 75% of the limited partner interests and continues to own 100% of the general partner interest of Cove Point. BHE GT&S also operates and has ownership interests in three smaller LNG facilities in Alabama, Florida and Pennsylvania.

In total, Eastern Energy Gas operates approximately 5,400 miles of natural gas transmission, gathering and storage pipelines, of which approximately 5,200 miles are owned by Eastern Energy Gas, with a design capacity of 12.6 Bcf per day as well as approximately 100 miles of natural gas liquids pipelines operated by BHE GT&S. EGTS operates approximately 3,900 miles of natural gas transmission and storage pipelines with a design capacity of 9.9 Bcf per day. EGTS also operates 17 underground storage fields with a total working gas capacity of approximately 420 Bcf, of which approximately 307 Bcf relates to natural gas storage field capacity that EGTS owns. BHE GT&S' pipeline system is configured with approximately 360 active receipt and delivery points. In 2023, BHE GT&S delivered over 2.1 trillion cubic feet ("Tcf") of natural gas to its customers.

BHE GT&S' natural gas transmission and storage earnings primarily result from rates established by FERC. Revenues derived from BHE GT&S' pipeline operations are primarily from reservation charges for firm transmission and storage services as provided for in their FERC-approved tariffs. Reservation charges are required to be paid regardless of volumes transported or stored. The profitability of these businesses is dependent on their ability, through the rates they are permitted to charge, to recover costs and earn a reasonable return on their capital investments. As of December 31, 2023, 84% of BHE GT&S' transmission capacity is subscribed, including 79% under long-term contracts and 5% on a year-to-year basis, and 100% of EGTS' storage capacity is subscribed, including 97% under long-term contracts. As of December 31, 2023, the weighted average remaining contract term for Eastern Energy Gas' and EGTS' firm transmission contracts is seven years and five years, respectively, and EGTS' storage contracts is four years. Additionally, BHE GT&S receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain pipeline transmission and LNG storage and terminal services. Variability in BHE GT&S' earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, which are dependent on weather, changes in commodity prices and the economy.

33

BHE GT&S' operating revenue for the year ended December 31 was as follows (in millions):

	2023				2022
Transmission	$	881	39	%	$	849	35	%
LNG	796		36		790		33
Storage	329		15		316		13
Gas, liquids and other sales	233		10		447		19
Total operating revenue	$	2,239	100	%	$	2,402	100	%

Except for quantities of natural gas owned and managed for operational and system balancing purposes, BHE GT&S does not own the natural gas that is transported through its system.

During 2023, BHE GT&S had two customers that each accounted for greater than 15% of its operating revenue and its 10 largest customers accounted for 48% of its total operating revenue. BHE GT&S has agreements with terms through 2038 to retain the majority of its two largest customers' volumes. The loss of any of these significant customers, if not replaced, could have a material adverse effect on BHE GT&S.

Human Capital

As of December 31, 2023, Eastern Energy Gas had approximately 1,500 employees, consisting of approximately 1,200 natural gas operations employees and 300 corporate services employees. As of December 31, 2023, approximately 600 employees were covered by a union contract with the Utility Workers Union of America.

As of December 31, 2023, EGTS had approximately 1,300 employees, consisting of approximately 1,000 natural gas operations employees and 300 corporate services employees. As of December 31, 2023, approximately 600 employees were covered by a union contract with the Utility Workers Union of America.

For more information regarding Eastern Energy Gas' and EGTS' human capital disclosures, refer to Item 1. Business - General section of this Form 10-K.

Northern Natural Gas

Northern Natural Gas owns the largest interstate natural gas pipeline system in the U.S., as measured by pipeline miles, which reaches from west Texas to Michigan's Upper Peninsula. Northern Natural Gas primarily transports and stores natural gas for utilities, municipalities, gas marketing companies and industrial and commercial users. Northern Natural Gas' pipeline system consists of two commercial segments. Its traditional end-use and distribution market area in the northern part of its system, referred to as the Market Area, includes points in Iowa, Nebraska, Minnesota, Wisconsin, South Dakota, Michigan and Illinois. Its natural gas supply and delivery service area in the southern part of its system, referred to as the Field Area, includes points in Kansas, Texas, Oklahoma and New Mexico. The Market Area and Field Area are separated at a Demarcation Point ("Demarc"). Northern Natural Gas' pipeline system consists of 14,200 miles of natural gas pipelines, including 5,800 miles of mainline transmission pipelines and 8,400 miles of branch and lateral pipelines, with a Market Area design capacity of 6.3 Bcf per day, a Field Area delivery capacity of 1.7 Bcf per day to the Market Area and 1.5 Bcf per day to the West Texas area and 95.6 Bcf of working gas capacity in five storage facilities. Northern Natural Gas' pipeline system is configured with approximately 2,362 active receipt and delivery points which are integrated with the facilities of LDCs. Many of Northern Natural Gas' LDC customers are part of combined utilities that also use natural gas as a fuel source for electric generation. Northern Natural Gas delivered over 1.4 Tcf of natural gas to its customers in 2023.

34

Northern Natural Gas' transportation rates and most of its storage rates are cost-based. These rates are designed to provide Northern Natural Gas with an opportunity to recover its costs of providing services and earn a reasonable return on its investments. Substantially all of Northern Natural Gas' Market Area transportation revenue is generated from reservation charges, with the balance from usage charges. Most of Northern Natural Gas' transportation capacity in the Market Area is committed to customers under firm transportation contracts, where customers pay Northern Natural Gas a monthly reservation charge for the right to transport natural gas through Northern Natural Gas' system. Reservation charges are required to be paid regardless of volumes transported or stored. As of December 31, 2023, approximately 72% of Northern Natural Gas' customers' entitlement in the Market Area have terms beyond 2026 and approximately 49% beyond 2027. As of December 31, 2023, the weighted average remaining contract term for Northern Natural Gas' Market Area firm transportation contracts is six years. Northern Natural Gas' Field Area customers consist primarily of energy marketing companies, midstream companies and power generators that are connected to Northern Natural Gas' system in Texas and New Mexico that are contracted on a long-term basis with a weighted average remaining contract term of five years. Northern Natural Gas' storage services are provided through the operation of one underground natural gas storage field in Iowa and two underground natural gas storage facilities in Kansas. Additionally, Northern Natural Gas has two LNG storage peaking units, one in Iowa and one in Minnesota, that support its transportation service. The three underground natural gas storage facilities and two LNG storage peaking units have a total working gas capacity of over 95.6 Bcf and approximately 2.2 Bcf per day of peak delivery capability. The average remaining contract term for firm storage contracts is five years.

Northern Natural Gas' operating revenue for the years ended December 31 was as follows (in millions):

	2023				2022				2021
Transportation:
Market Area	$	815	65	%	$	688	62	%	$	658	61	%
Field Area	249		22		210		18		177		17
Total transportation	1,064		87		898		80		835		78
Storage	113		9		97		9		94		9
Total transportation and storage revenue	1,177		96		995		89		929		87
Gas, liquids and other sales	49		4		123		11		143		13
Total operating revenue	$	1,226	100	%	$	1,118	100	%	$	1,072	100	%

Except for quantities of natural gas owned and managed for operational and system balancing purposes, Northern Natural Gas does not own the natural gas that is transported through its system. The sale of natural gas for operational and system balancing purposes accounts for the majority of the remaining operating revenue.

During 2023, Northern Natural Gas had two customers that each accounted for greater than 10% of its transportation and storage revenue and its 10 largest customers accounted for 64% of its system-wide transportation and storage revenue. Northern Natural Gas has agreements with terms through 2027 and 2034 to retain the majority of its two largest customers' volumes. The loss of either of these significant customers, if not replaced, could have a material adverse effect on Northern Natural Gas.

Kern River

Kern River owns an interstate natural gas pipeline system that extends from supply areas in the Rocky Mountains to consuming markets in Utah, Nevada and California. Kern River operates 1,400 miles of mainline natural gas pipelines, with a year-round design capacity of 2,166,575 Dths, or 2.2 Bcf, per day. Additional seasonal design capacity (Bell-Curve) is contracted in all months except July, August and September. The mainline pipeline extends from the system's point of origination near Opal, Wyoming, through the Central Rocky Mountains to Daggett, California. The mainline section consists of 1,300 miles of 36-inch diameter pipeline and 100 miles of various laterals that connect to the mainline. Kern River primarily transports natural gas for utilities, municipalities, energy marketing companies, electric generating companies and other industrial and commercial users.

35

Kern River's rates are designed to provide Kern River with an opportunity to recover its costs of providing services and earn a reasonable return on its investments and are based on a levelized rate design that assumes recovery of 70% of the original investment during the initial long-term contracts ("Period One rates"). After expiration of the initial term, eligible customers have the option to elect service at rates ("Period Two rates") that are lower than Period One rates because they are designed to recover the remaining 30% of the original investment. To the extent that eligible customers do not contract for service at Period Two rates, the volumes are turned back to Kern River, and it resells capacity at market rates for varying terms. As of December 31, 2023, approximately 87% of Kern River's design capacity, including seasonal Bell-Curve, totaled 2,345,381 Dths per day and is contracted pursuant to long-term firm natural gas transportation service agreements, whereby Kern River receives natural gas on behalf of customers at designated receipt points and transports the natural gas on a firm basis to designated delivery points. In return for this service, each customer pays Kern River a fixed monthly reservation fee based on each customer's maximum daily quantity, which represents nearly 81% of total operating revenue, and a commodity charge based on the actual amount of natural gas transported pursuant to its long-term firm natural gas transportation service agreements and Kern River's tariff. These long-term firm natural gas transportation service agreements expire between February 2024 and December 2045 and have a weighted-average remaining contract term of over eight years. As of December 31, 2023, 74% of the year-round design capacity of 2,166,575 Dths under firm contract has primary delivery points in California, with the flexibility to access secondary delivery points in Nevada and Utah.

Except for quantities of natural gas owned for operational purposes, Kern River does not own the natural gas that is transported through its system. Kern River's transportation rates are cost-based.

During 2023, Kern River had two customers, including Nevada Power Company, an affiliated company, that each accounted for greater than 10% of its revenue. The loss of these significant customers, if not replaced, could have a material adverse effect on Kern River.

BHE TRANSMISSION

BHE Transmission consists of BHE Canada, an indirect wholly owned subsidiary of BHE, BHE U.S. Transmission, a wholly owned subsidiary of BHE, ownership interests in generating facilities and 300 MWs of long-term northbound transmission rights on the Montana Alberta Tie Line (commencing April 30, 2026). BHE Canada and BHE U.S. Transmission together own and operate the Montana Alberta Tie Line, which is a 214-mile, 230-kV transmission line that runs from Lethbridge, Alberta, Canada to Great Falls, Montana, U.S. and connects power grids in the two jurisdictions. BHE Canada also owns AlbertaEx, a cross-border operations center to optimize in real-time the value of BHE Canada and BHE U.S. Transmission's existing physical generation assets on the Montana Alberta Tie Line. Operations are set to commence in January 2025.

BHE Canada

BHE Canada primarily owns AltaLink, a regulated electric transmission utility company headquartered in Alberta, Canada serving approximately 85% of Alberta's population. AltaLink's high voltage transmission lines and related facilities transmit electricity from generating facilities to major load centers, cities and large industrial plants throughout its 87,000 square mile service territory, which covers a diverse geographic area including most major urban centers in central and southern Alberta. AltaLink's transmission facilities, consisting of approximately 8,300 miles of transmission lines and approximately 310 substations as of December 31, 2023, are an integral part of the Alberta Interconnected Electric System ("AIES").

The AIES is a network or grid of transmission facilities operating at high voltages ranging from 69 kV to 500 kV. The grid delivers electricity from generating units across Alberta, Canada through approximately 16,000 miles of transmission lines. The AIES is interconnected to British Columbia's transmission system that links Alberta with the North American western interconnected system, interconnection with Saskatchewan's transmission system and interconnection with Montana's transmission system.

AltaLink is a transmission facility owner within the electricity industry in Alberta and is permitted to charge a tariff rate for the use of its transmission facilities. Such tariff rates are established on a cost-of-service regulatory model, which is designed to allow AltaLink an opportunity to recover its costs of providing services and to earn a reasonable return on its investments. Transmission tariff rates are approved by the AUC and are collected from the AESO.

36

The electricity industry in Alberta consists of four principal segments. Generators sell wholesale power into the power pool operated by the AESO and through direct contractual arrangements. Alberta's transmission system or grid is composed of high voltage power lines and related facilities that transmit electricity from generating facilities to distribution networks and directly connected end-users. Distribution facility owners are regulated by the AUC and are responsible for arranging for, or providing, regulated rate and regulated default supply services to convey electricity from transmission systems and distribution-connected generators to end-use customers. Retailers can procure energy through the power pool, through direct contractual arrangements with energy suppliers or ownership of generation facilities and arrange for its distribution to end-use customers.

The AESO mandate is defined in the Electric Utilities Act (Alberta) and its regulations and requires the AESO to assess both current and future needs of Alberta's interconnected electrical system. In January 2022, the AESO released the 2022 Long-Term Transmission Plan. Updated every two years, the Long-Term Transmission Plan seeks to optimize the use of the existing transmission system and plan the development of new transmission to ensure a safe and reliable electricity system that enables a fair, efficient and openly competitive electricity market. The 2022 Long-Term Transmission Plan identifies C$1.3 billion in transmission projects over a 10-year period, which results in C$150 million to C$200 million per year on average over that 10-year period. This results in a cumulative transmission rate impact of C$2 per MWh for the first five to eight years, increasing to C$3 per MWh after 15 years. The Long-Term Transmission Plan identifies approximately C$900 million of projects in AltaLink's service territory with in-service dates before 2030. On November 15, 2023, the AESO issued a preliminary update on the 2024 Long-term Outlook. The AESO is re-evaluating scenarios to include decarbonization by 2050, as well as decarbonization by 2035. AltaLink and other stakeholders provided feedback to the AESO which was published on the AESO's website on December 8, 2023. The final 2024 Long-term Outlook is expected in the second quarter of 2024. The next Long-Term Transmission Plan is expected to be completed in the first quarter of 2025.

Wildfire Risk

Alberta may experience a heightened incidence of wildfires, or wildfire severity due to climate change and other factors. AltaLink cannot predict how the AUC will respond to such heightened incidence, or how the AUC might treat recovery of its investment or damages and whether or not it might impose fines. AltaLink has a robust set of procedures to address wildfire risk. AltaLink reviews and updates these procedures based on the best practices in other jurisdictions. AltaLink applies to the AUC for approval for funds to implement these procedures and mitigation investments. Additional requirements may be imposed by the regulator or legislators in response to heightened risk. AltaLink is monitoring all changes to its regulatory framework and will respond to any such changes as they arise. Electricity transmission facilities may also start wildfires as a result of causes such as equipment operation or failure, trees contacting transmission lines, or lightning strikes on transmission lines or equipment.

Wildfire Mitigation Plans

AltaLink has developed and implemented detailed wildfire mitigation plans for its service territory since 2019. AltaLink files and gets AUC approval for its wildfire mitigation plan as part of its GTA process. AltaLink has received approval for its wildfire mitigation plan in both the 2019-2021 and 2022-2023 GTA periods. These plans include improvements in situational awareness, meteorological systems, and risk modeling; investments in asset hardening and vegetation management; and AltaLink's ongoing elevated fire risk operating practices and policies, including inspections, recloser blocking procedures, and PSPS.

AltaLink filed an amendment to its 2024-2025 GTA with additional measures to proactively expand and accelerate its 2024-2025 Wildfire Mitigation Plan in response to the increase in wildfire risk to Albertans and AltaLink's critical infrastructure which delivers reliable electricity to customers. AltaLink proposes a catastrophic wildfire damages deferral account for damages in excess of commercial insurance. Despite its actions, AltaLink may be liable for firefighting costs, damages to personal property, structures, and natural resources, fines, and third-party claims including for personal injuries in connection with such fires. These costs could substantially exceed insurance coverage, if any, and such amounts may not be approved by the AUC for recovery, in whole or in part, through increased tariff revenues.

Asset Hardening and Vegetation Management

AltaLink has and continues to invest in specific asset improvements targeted to reduce the risk of wildfire ignition from AltaLink's operations. These hardening efforts reduce the likelihood of AltaLink's transmission lines to spark a wildfire at locations of high fire risk.

37

Approximately 15% of AltaLink's transmission lines are in High Risk Fire Areas ("HRFAs"). Of these HRFA lines, 27% are in urban areas and communities, 23% are in forested areas, with the remaining 50% located in agricultural, grassland or native prairie.

Situational Awareness, Meteorology, and Risk Modeling

AltaLink uses available integrated meteorology and camera systems available from the Alberta Government and has installed 13 of 17 planned incremental weather and camera stations in support of improvements to its situational awareness. This weather information, combined with expert third-party assessment, provides weather and fire risk forecasting daily for AltaLink's service territory. AltaLink has established a Daily Hazard Forecast Report provided to the organization and field crews as well as implemented an information portal in the control room. AltaLink initially completed its fire risk modeling and HRFA mapping in 2020 and is planning to complete an update of the modeling in 2024. AltaLink is developing further enhanced fire weather modeling tools in 2024. AltaLink has completed policy updates and training regarding field operations and contractor crew fire management and preventive practices.

Asset Inspection Program

AltaLink completes asset inspections for all its facilities on an annual basis. For lines located in HRFAs, inspection frequencies are twice per year to review structure and vegetation conditions.

Public Safety Power Shutoff

A PSPS is an operating protocol used as a preventative measure of last resort during periods of extreme wildfire risk where a transmission line or lines would be de-energized proactively under certain conditions to reduce the risk of wildfire ignition. In determining whether to initiate a PSPS, AltaLink works with local public safety authorities in consideration of data from its wildfire risk forecasting tools and meteorological systems. If the forecast exceeds thresholds, escalating action is taken proactively starting from the seven-day forecast outlook. AltaLink has and continues to conduct stakeholder engagement and exercises related to its PSPS process.

BHE U.S. Transmission

BHE U.S. Transmission is engaged in various joint ventures to develop, own and operate transmission assets and is pursuing additional investment opportunities in the U.S. Currently, BHE U.S. Transmission has two joint ventures with transmission assets that are operational, ETT, a 50% owned joint venture with subsidiaries of American Electric Power Company, Inc. ("AEP"), and Prairie Wind Transmission, LLC, a 25% owned joint venture with AEP and Evergy, Inc. ETT owns and operates electric transmission assets in the ERCOT and, as of December 31, 2023, had total assets of $3.8 billion. ETT's transmission system includes approximately 2,000 miles of transmission lines and 47 substations as of December 31, 2023. Prairie Wind Transmission, LLC, owns and operates a 108-mile, 345-kV transmission project in Kansas having total assets of $131 million as of December 31, 2023.

38

Generating Facilities

BHE Transmission has ownership interests in the following generating facilities as of December 31, 2023:

				Power		Facility	Net
				Purchase		Net	Owned
		Energy	Year	Agreement	Power	Capacity	Capacity
Generating Facility	Location	Source	Installed	Expiration	Purchaser	(MWs)(1)	(MWs)(1)
WIND:
Rattlesnake	Alberta	Wind	2022	2042/2032	Telus, RBC, Bullfrog, Shopify	130	130
Rim Rock	Montana	Wind	2012	2026	Morgan Stanley	189	189
Glacier 1	Montana	Wind	2008	N/A	N/A	107	107
Glacier 2	Montana	Wind	2009	N/A	N/A	103	103
						529	529
NATURAL GAS:
Nat-1	Alberta	Natural gas	2015	N/A	N/A	20	20
						20	20
Total Available Generating Capacity						549	549

(1)    Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates BHE Transmission' ownership of Facility Net Capacity.

BHE RENEWABLES

The subsidiaries comprising the BHE Renewables reportable segment own interests in several independent power projects in the U.S. The following table presents certain information concerning these independent power projects as of December 31, 2023:

				Power		Facility	Net
				Purchase		Net	Owned
		Energy	Year	Agreement	Power	Capacity	Capacity
Generating Facility	Location	Source	Installed	Expiration	Purchaser(1)	(MWs)(2)	(MWs)(2)
WIND:
Grande Prairie	Nebraska	Wind	2016	2036	OPPD	400	400
Jumbo Road	Texas	Wind	2015	2033	AE	300	300
Santa Rita	Texas	Wind	2018	2025-2038	KC, CODTX, MES	300	300
Mariah Del Norte	Texas	Wind	2016	N/A	N/A	230	230
Walnut Ridge	Illinois	Wind	2018	2028	USGSA	212	212
Flat Top	Texas	Wind	2019	2038	Shaw	200	200
Pinyon Pines I	California	Wind	2012	2035	SCE	168	168
Fluvanna II	Texas	Wind	2019	2034	Heinz	158	158
Pinyon Pines II	California	Wind	2012	2035	SCE	132	132
Bishop Hill II	Illinois	Wind	2012	2032	Ameren	81	81
Marshall	Kansas	Wind	2016	2036	MJMEC, KPP, KMEA & COIMO	72	72
Independence	Iowa	Wind	2021	2041	CIPCO	54	54
						2,307	2,307
SOLAR:
Topaz	California	Solar	2013-2014	2039	PG&E	550	550
Solar Star 1	California	Solar	2013-2015	2035	SCE	310	310

39

Solar Star 2	California	Solar	2013-2015	2035	SCE	276	276
Agua Caliente	Arizona	Solar	2012-2013	2039	PG&E	290	142
Alamo 6	Texas	Solar	2017	2042	CPS	110	110
Community Solar Gardens(5)	Minnesota	Solar	2016-2018	2041-2043	(4)	98	98
Pearl	Texas	Solar	2017	2042	CPS	50	50
						1,684	1,536
NATURAL GAS:
Cordova	Illinois	Natural Gas	2001	N/A	N/A	512	512
Power Resources	Texas	Natural Gas	1988	N/A	N/A	140	140
Saranac	New York	Natural Gas	1994	N/A	N/A	245	196
Yuma	Arizona	Natural Gas	1994	2024	SDG&E	50	50
						947	898
GEOTHERMAL:
Imperial Valley Projects	California	Geothermal	1982-2000	(3)	(3)	345	345
						345	345
HYDROELECTRIC:
Wailuku	Hawaii	Hydroelectric	1993	2028	HELCO	10	10
						10	10
Total Available Generating Capacity						5,293	5,096
PROJECTS UNDER CONSTRUCTION
Solar Star 3 & 4	California	Solar	Est. 2024			48	48
						5,341	5,144

(1)Omaha Public Power District ("OPPD"); Austin Energy ("AE"); Kimberly-Clark Corporation ("KC"); City of Denton, TX ("CODTX"); MidAmerican Energy Services, LLC ("MES"); U.S. General Services Administration ("USGSA"); Shaw Industries Group, Inc ("Shaw"); Southern California Edison ("SCE"); Kraft Heinz Food Company ("Heinz"); Ameren Illinois Company ("Ameren"); Missouri Joint Municipal Electric Commission ("MJMEC"); Kansas Power Pool ("KPP"); Kansas Municipal Energy Agency ("KMEA"); City of Independence, MO ("COIMO"); Central Iowa Power Cooperative ("CIPCO"); Pacific Gas and Electric Company ("PG&E"); CPS Energy ("CPS"); San Diego Gas & Electric Company ("SDG&E"); and Hawaii Electric Light Company, Inc. ("HELCO").

(2)Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates BHE Renewables' ownership of Facility Net Capacity.

(3)Approximately 12% of the Company's interests in the Imperial Valley Projects' Contract Capacity are currently sold to Southern California Edison Company under a long-term power purchase agreement expiring in 2026. Certain long-term power purchase agreement renewals for 252 MWs have been entered into with other parties at fixed prices that expire from 2028 to 2039, of which 202 MWs mature in 2039.

(4)The power purchasers are commercial, industrial and not-for-profit organizations.

(5)The community solar gardens project is consolidated in the table above for convenience as it consists of 98 distinct entities that each own an approximately 1-MW solar garden with independent but substantially similar terms and conditions.

40

BHE Renewables' operating revenue derived from the following business activities for the years ended December 31 were as follows (dollars in millions):

	2023				2022				2021
Solar	$	427	26	%	$	477	28	%	$	468	27	%
Wind	276		16		228		13		160		10
Geothermal	210		12		212		12		178		11
Hydro	4		—		5		—		32		2
Natural gas	105		6		71		4		143		9
Retail energy services	688		40		744		43		680		41
Total operating revenue	$	1,710	100	%	$	1,737	100	%	$	1,661	100	%

HOMESERVICES

HomeServices, a wholly owned subsidiary of BHE, is one of the largest residential real estate brokerage firms in the U.S. In addition to providing traditional residential real estate brokerage services, HomeServices offers other integrated real estate services, including mortgage originations and mortgage banking; title and closing services; property and casualty insurance; home warranties; relocation services; and other home-related services. HomeServices' real estate brokerage business is subject to seasonal fluctuations because more home sale transactions tend to close during the second and third quarters of the year. As a result, HomeServices' operating results and profitability are typically higher in the second and third quarters relative to the remainder of the year. HomeServices' owned brokerages currently operate in nearly 900 offices in 34 states and the District of Columbia with approximately 41,000 real estate agents under 50 brand names. The U.S. residential real estate brokerage business is subject to the general real estate market conditions, is highly competitive and consists of numerous local brokers and agents in each market seeking to represent sellers and buyers in residential real estate transactions.

HomeServices' franchise network currently includes approximately 300 franchisees and over 1,500 brokerage offices with approximately 48,000 real estate agents under two brand names, primarily in the U.S. In exchange for certain fees, HomeServices provides the right to use the Berkshire Hathaway HomeServices or Real Living brand names and other related service marks, as well as providing orientation programs, training and consultation services, advertising programs and other services.

GENERAL REGULATION

BHE's regulated subsidiaries and certain affiliates are subject to comprehensive governmental regulation, which significantly influences their operating environment, prices charged to customers, capital structure, costs and, ultimately, their ability to recover costs and earn a reasonable return on invested capital. In addition to the discussion contained herein regarding general regulation, refer to "Regulatory Matters" in Item 1 of this Form 10-K for further discussion regarding certain regulatory matters.

Domestic Regulated Public Utility Subsidiaries

The Utilities are subject to comprehensive regulation by various state, federal and local agencies. The more significant aspects of this regulatory framework are described below.

41

State Regulation

Historically, state regulatory commissions have established retail electric and natural gas rates on a cost-of-service basis, which are designed to allow a utility the opportunity to recover what each state regulatory commission deems to be the utility's reasonable costs of providing services, including the opportunity to earn a fair and reasonable return on its investments based on its cost of debt and equity. In addition to return on investment, a utility's cost of service generally reflects a representative level of prudent expenses, including cost of sales, operating expense, depreciation and amortization and income and other tax expense, reduced by wholesale electricity and other revenue. The allowed operating expenses are typically based on actual historical costs adjusted for known and measurable or forecasted changes. State regulatory commissions may adjust cost of service for various reasons, including pursuant to a review of: (a) the utility's revenue and expenses during a defined test period, (b) the utility's level of investment and (c) changes in income tax laws. State regulatory commissions typically have the authority to review and change rates on their own initiative; however, they may also initiate reviews at the request of a utility, utility customers or organizations representing groups of customers. In certain jurisdictions, the utility and such parties, however, may agree with one another not to request a review of or changes to rates for a specified period of time.

The retail electric rates of the Utilities are generally based on the cost of providing traditional bundled services, including generation, transmission and distribution services. The Utilities have established ECAMs and other cost recovery mechanisms in certain states, which help mitigate their exposure to changes in costs from those assumed in establishing base rates.

With certain limited exceptions, the Utilities have an exclusive right to serve retail customers within their service territories and, in turn, have an obligation to provide service to those customers. In some jurisdictions, certain classes of customers may choose to purchase all or a portion of their energy from alternative energy suppliers, and in some jurisdictions retail customers can generate all or a portion of their own energy. Under Oregon law, PacifiCorp has the exclusive right and obligation to provide electricity distribution services to all residential and nonresidential customers within its allocated service territory; however, nonresidential customers have the right to choose an alternative provider of energy supply. The impact of this right on PacifiCorp's consolidated financial results has not been material. In Washington, state law does not provide for exclusive service territory allocation. PacifiCorp's service territory in Washington is surrounded by other public utilities with whom PacifiCorp has from time to time entered into service area agreements under the jurisdiction of the WUTC. Under California law, PacifiCorp has the exclusive right and obligation to provide electricity distribution services to all residential and nonresidential customers within its allocated service territory; however, cities, counties and certain other public agencies have the right to choose to generate energy supply or elect an alternative provider of energy supply through the formation of a Community Choice Aggregator ("CCA"). To date, no CCA activity has occurred in PacifiCorp's California service territory. If a CCA is formed, PacifiCorp would continue to provide CCA customers transmission, distribution, metering and billing services and the CCA would provide generation supply. In addition, PacifiCorp would likely be able to collect costs from CCA customers for the generation-related costs that PacifiCorp incurred while they were customers of PacifiCorp. PacifiCorp would remain the electricity provider of last resort for these customers. In Illinois, state law has established a competitive environment so that all Illinois customers are free to choose their retail service supplier. For customers that choose an alternative retail energy supplier, MidAmerican Energy continues to have an ongoing obligation to deliver the supplier's energy to the retail customer. MidAmerican Energy bills the retail customer for such delivery services. MidAmerican Energy also has an obligation to serve customers at regulated cost-based rates and has a continuing obligation to serve customers who have not selected a competitive electricity provider. The impact of this right on MidAmerican Energy's financial results has not been material. In Nevada, Chapter 704B of the Nevada Revised Statutes allows retail electric customers with an average annual load of one MW or more to file a letter of intent and application with the PUCN to acquire electric energy and ancillary services from another energy supplier. The law requires customers wishing to choose a new supplier to receive the approval of the PUCN to meet public interest standards. In particular, departing customers must secure new energy resources that are not under contract to the Nevada Utilities, the departure must not burden the Nevada Utilities with increased costs or cause any remaining customers to pay increased costs and the departing customers must pay their portion of any deferred energy balances, all as determined by the PUCN. SB 547 revised Chapter 704B to establish limits on the amount of load eligible to take service under Chapter 704B and to set those limits as a part of the IRP filed by the Nevada Utilities. Also, the Utilities and the state regulatory commissions are individually evaluating how best to integrate private generation resources into their service and rate design, including considering such factors as maintaining high levels of customer safety and service reliability, minimizing adverse cost impacts and fairly allocating costs among all customers.

In Nevada, large natural gas customers using 12,000 therms per month with fuel switching capability are allowed to participate in the incentive natural gas rate tariff. Once a service agreement has been executed, a customer can compare natural gas prices under this tariff to alternative energy sources and choose its source of natural gas. In addition, natural gas customers using greater than 1,000 therms per day have the ability to secure their own natural gas supplies under the gas transportation tariff.

42

PacifiCorp

            Rate Filings

Under Utah law, the UPSC must issue a written order within 240 days of a public utility's application for a general rate change. Absent an order, the proposed rates go into effect as filed and are not subject to refund. The UPSC may allow interim rates to take effect within 45 days of an application, subject to refund or surcharge, if an adequate prima facie showing is established in hearing that the interim rate change is justified.

In Oregon, the OPUC has the authority to suspend proposed new rates for a period not to exceed more than six months, with an additional three-month extension, beyond the 30-day time period when the new rates would otherwise go into effect. Absent suspension or other action from the OPUC, new rates automatically go into effect 30 days from filing by the utility. Upon suspension by the OPUC, the OPUC is authorized to allow the collection of an interim rate, subject to refund, during the pendency of the OPUC's review of the rate request.

In Wyoming, the WPSC can allow interim rates to go into effect 30 days after the initial application but may require a bond to secure a refund for the amount. The WPSC may suspend the rates for final approval for a period not to exceed 10 months.

In Washington, the WUTC has the authority to suspend proposed new rates, subject to hearing, for a period not to exceed 10 months beyond the 30-day time period when the new rate would otherwise go into effect.

Under Idaho law, the IPUC can suspend a filing for an initial period not to exceed five months and an additional extension of 60 days with a showing of good cause.

In California, the CPUC has the authority to suspend proposed new rates, subject to hearing, for a period not to exceed 18 months. The CPUC may extend the suspension period on a case-by-case basis.

            Adjustment Mechanisms

In addition to recovery through base rates, PacifiCorp also achieves recovery of certain costs through various adjustment mechanisms as summarized below.

State Regulator	Base Rate Test Period	Adjustment Mechanism
UPSC	Forecasted or historical with known and measurable changes(1)	EBA under which 100% of the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates. Wheeling revenue is also included in the mechanism. Beginning in 2021, the mechanism includes a true-up of PTCs at 100%.
		Balancing account to provide for 100% recovery or refund of the difference between the level of REC revenues included in base rates and actual REC revenues after adjusting for a REC incentive authorized by the UPSC.
		Recovery mechanism for single capital investments that in total exceed 1% of existing rate base when a general rate case has occurred within the preceding 18 months.
		Effective January 1, 2021, Wildland Fire Mitigation Balancing Account to recover operating expenses and capital expenditures incurred to implement PacifiCorp's Utah Wildland Fire Protection Plan incremental to those included in base rates.
OPUC	Forecasted	PCAM under which 90% of the difference between forecasted net variable power costs and PTCs established under the annual TAM and actual net variable power costs and PTCs is deferred and reflected in future rates. The difference between the forecasted and actual net variable power costs and PTCs must fall outside of an established asymmetrical deadband, with a negative annual power cost variance deadband of $15 million; and a positive annual power cost variance deadband of $30 million and is subject to an earnings test of +/- 1% on PacifiCorp's allowed return on equity.
		Annual TAM based on forecasted net variable power costs and PTCs.
		RAC to recover the revenue requirement of new renewable resources and associated transmission costs that are not reflected in general rates.
		Balancing account for recovery of costs associated with the purchase of RECs necessary to meet Oregon's RPS requirements.

43

State Regulator	Base Rate Test Period	Adjustment Mechanism
		Effective January 1, 2021, Annual Wildfire Mitigation and Vegetation Management Cost Recovery Mechanism approved through 2024 to recover vegetation management and wildfire mitigation operations and maintenance costs and wildfire mitigation capital costs, incremental to those included in base rates. Recovery is subject to performance metrics and earnings tests. After 2024, the mechanism will be assessed to determine whether continued use is warranted.
		Effective May 10, 2023, the WMP AAC was approved to recover the capital and operations and maintenance costs associated with implementation and operation of PacifiCorp's Oregon Wildfire Mitigation Plan beginning with the 2022 plan.
WPSC	Forecasted or historical with known and measurable changes(1)	ECAM under which 80% of the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates. Within the mechanism, chemical costs and start-up fuel costs are also included at the 80% symmetrical sharing band and PTCs are included at 100% symmetrical sharing.
		REC and SO2 revenue adjustment mechanism to provide for recovery or refund of 100% of any difference between actual REC and SO2 revenues and the level in rates.
WUTC	Historical with known and measurable changes	PCAM under which the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates after applying a $4 million deadband for positive or negative net power cost variances. For net power cost variances between $4 million and $10 million, amounts to be recovered from customers are allocated 50/50 and amounts to be credited to customers are allocated 75/25 (customers/PacifiCorp). Positive or negative net power cost variances in excess of $10 million are allocated 90/10 (customers/PacifiCorp). Beginning in 2021, the mechanism includes a true-up of PTCs at 100%.
		Deferral mechanism of costs for up to 24 months of new base load generation resources and eligible renewable resources and related transmission that qualify under the state's emissions performance standard and are not reflected in base rates.
		REC revenue tracking mechanism to provide credit of 100% of REC revenues to customers.
		Decoupling mechanism under which the difference between actual annual revenues and authorized revenues per customer per specified rate schedules is deferred and reflected in future rates, subject to an earnings test. Under the earnings test, 50% of any proportional excess earnings over PacifiCorp's authorized return on equity is returned to customers in addition to any surcharge or surcredit related to the revenue variance. The earnings test is asymmetrical, and adjustments are not made when PacifiCorp earns at or below authorized returns on equity. To trigger a rate adjustment, the deferral balance must exceed plus or minus 2.5% of the authorized revenue at the end of each deferral period by rate class. Rate adjustments must not exceed a surcharge of 5% of the actual normalized revenue by class.
IPUC	Historical with known and measurable changes	ECAM under which 90% of the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates. Also provides for recovery or refund of 100% of the difference between the level of REC revenues included in base rates and actual REC revenues and differences in actual PTCs compared to the amount in base rates.
CPUC	Forecasted	PTAM for major capital additions that allows for rate adjustments outside of the context of a traditional general rate case for the revenue requirement associated with capital additions exceeding $50 million on a total-company basis. Filed as eligible capital additions are placed into service.
		ECAC that allows for an annual update to actual and forecasted net power costs.
		PTAM for attrition, a mechanism that allows for an annual adjustment to costs other than net power costs.
		Catastrophic Events Memorandum Account for catastrophic events, allows for deferral and cost recovery of reasonable costs incurred as the result of catastrophic events, which are events for which a state or federal agency has declared a state of emergency.
		Fire Risk Mitigation Memorandum Account to track costs related to wildfire mitigation activities incremental to what is in base rates and Wildfire Mitigation Plan Memorandum Account to track costs associated with the implementation of PacifiCorp's approved wildfire mitigation plan.

(1)PacifiCorp has relied on both historical test periods with known and measurable adjustments, as well as forecasted test periods.

44

MidAmerican Energy

            Rate Filings

Under Iowa law, a utility may implement temporary rates, without IUB review and subject to refund, on or after 10 days of filing a request for higher base rates. If the IUB has not issued a final order within 10 months after the filing date, the temporary rates become final. Under Illinois law, new base rates may become effective 45 days after the filing of a request with the ICC, or earlier with ICC approval. The ICC has authority to suspend the proposed new rates, subject to hearing, for a period not to exceed approximately 11 months after filing. South Dakota law authorizes the SDPUC to suspend new base rates for up to six months during the pendency of rate proceedings; however, a utility may implement all or a portion of the proposed new rates six months after the filing of a request for a rate increase subject to refund pending a final order in the proceeding.

Iowa law also permits rate-regulated utilities to seek ratemaking principles with the IUB prior to the construction of certain types of new generating facilities. Pursuant to this law, MidAmerican Energy has applied for and obtained IUB ratemaking principles orders for a 484-MW (MidAmerican Energy's share) coal-fueled generating facility, a 495-MW combined cycle natural gas-fueled generating facility and 6,841 MWs (nominal ratings) of wind-powered generating facilities as of December 31, 2023. These ratemaking principles established cost caps for the projects, below which such costs are deemed prudent by the IUB and authorized a fixed rate of return on equity for the respective generating facilities over the regulatory life of the facilities in any future Iowa rate proceeding. As of December 31, 2023, the generating facilities in-service totaled $7.5 billion, or 35%, of MidAmerican Energy's regulated property, plant and equipment, net and were subject to these ratemaking principles at a weighted average return on equity of 11.3% with a weighted average remaining life of 32 years.

Ratemaking principles for several wind-powered generation projects have established mechanisms in Iowa where electric rate base may be reduced. The current revenue sharing mechanism is in accordance with Wind PRIME ratemaking principles and reduces rate base for Iowa electric returns on equity exceeding an established benchmark. Sharing is triggered by MidAmerican Energy's actual equity return being above a threshold calculated annually. The threshold, not to exceed 11%, is the weighted average equity return of rate base with returns authorized via ratemaking principles proceedings and all other rate base. For all other rate base, the return is based on interest rates on 30-year A-rated utility bond yields plus 400 basis points, with a minimum return of 9.5%. MidAmerican Energy shares with customers 90% of the revenue in excess of the trigger. A second mechanism, the retail customer benefit mechanism, reduces electric rate base for the value of higher cost retail energy displaced by covered wind-powered production and applies to the wind-powered generating facilities constructed under the Wind X and Wind XII projects, and wind-powered generating facilities placed in service in 2023 and future projects yet to be constructed under the Wind PRIME project that was approved by the IUB in December 2023. Rate base reductions under these mechanisms are applied to coal and other generation facilities in specified orders. A third mechanism, the Iowa EAC rate mitigation mechanism, provides EAC rate stability to customers by allocating revenue sharing amounts as required to reduce retail electric energy cost recoveries to a targeted amount.

            Adjustment Mechanisms

Under its current Iowa, Illinois and South Dakota electric tariffs, MidAmerican Energy is allowed to recover fluctuations in electric energy costs for its retail electric sales through fuel, or energy, cost adjustment mechanisms. Additionally, MidAmerican Energy has transmission adjustment clauses to recover certain transmission charges related to retail customers in all jurisdictions. The transmission adjustment mechanisms recover costs billed by the MISO for regional transmission service. The Illinois adjustment mechanism additionally recovers MidAmerican Energy's entire transmission revenue requirement attributable to Illinois. The adjustment mechanisms reduce the regulatory lag for the recovery of energy and transmission costs related to retail electric customers in these jurisdictions and accomplish, with limited timing differences, a pass-through of the related costs to these customers. Recoveries through these adjustment mechanisms are reflected in operating revenue, and the related costs are reflected in cost of fuel and energy or operations and maintenance expense, as applicable.

Of the wind-powered generating facilities placed in-service as of December 31, 2023, 5,225 MWs (nominal ratings) have not been included in the determination of MidAmerican Energy's Iowa retail electric base rates. In accordance with related ratemaking principles, until such time as these generation assets are reflected in base rates and ceasing thereafter, MidAmerican Energy will continue to reduce its revenue from Iowa EAC recoveries by $12 million each calendar year.

MidAmerican Energy's cost of natural gas purchased for resale is collected for each jurisdiction through a uniform PGA, which is updated monthly to reflect changes in actual costs. Subject to prudence reviews, the PGA accomplishes a pass-through of MidAmerican Energy's cost of natural gas purchased for resale to its customers and, accordingly, has no direct effect on net income.

45

MidAmerican Energy's electric and natural gas energy efficiency program costs are collected through bill riders that are adjusted annually based on actual and expected costs in accordance with the energy efficiency plans filed with and approved by the respective state regulatory commission. As such, the energy efficiency program costs, which are reflected in operations and maintenance expense, and related recoveries, which are reflected in operating revenue, have no direct impact on net income.

MidAmerican Energy has income tax rider mechanisms in Iowa and Illinois that were established in response to significant changes to the Internal Revenue Code enacted in 2017, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to 21%. As a result of these changes, MidAmerican Energy re-measured its accumulated deferred income tax balances at the 21% rate and increased regulatory liabilities pursuant to the approved mechanisms. In December 2018, the IUB approved in final form a tax expense revision mechanism that reduces customer electric rates for the impact of the lower income tax rate on current operations, as calculated annually, and defers the amortization of excess accumulated deferred income taxes created by their re-measurement at the 21% income tax rate to a regulatory liability, the disposition of which will be determined in MidAmerican Energy's next rate case. In 2018, Iowa Senate File 2417 was signed into law, which, among other items, reduced the state of Iowa corporate tax rate in stages from 12% to its current 8.4%, and the impacts of such changes are included in the Iowa tax expense revision mechanism.

NV Energy (Nevada Power and Sierra Pacific)

            Rate Filings

Nevada enacted Assembly Bill 524 ("AB 524") on June 15, 2023. The legislation, among other things, allows an electric utility to file a general rate application more frequently than once every three years. Under AB 524, Nevada statutes require the Nevada Utilities to file electric general rate cases at least every three years with the PUCN and prohibit the Nevada Utilities from filing another general rate application until all pending general rate applications filed have been decided by the Commission unless, after application and hearing, the Commission determines that a substantial financial emergency would exist if the public utility or its affiliate is not permitted to file another general rate case sooner. Sierra Pacific may also file natural gas general rate cases with the PUCN. The Nevada Utilities are also subject to a two-part fuel and purchased power adjustment mechanism. The Nevada Utilities make quarterly filings to reset the BTERs, based on the last 12 months of fuel and purchased power costs. The difference between actual fuel and purchased power costs and the revenue collected in the BTERs is deferred into a balancing account. The DEAA rate clears amounts deferred into the balancing account. Nevada regulations allow an electric or natural gas utility that adjusts its BTERs on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest. During required annual DEAA proceedings, the prudence of fuel and purchased power costs is reviewed, and if any costs are disallowed on such grounds, the disallowances will be incorporated into the next quarterly BTERs change. Also, on an annual basis, the Nevada Utilities (a) seek a determination that energy efficiency program expenditures were reasonable, (b) request that the PUCN reset base and amortization EEPR, and (c) request that the PUCN reset base and amortization EEIR.

            EEPR and EEIR

EEPR was established to allow the Nevada Utilities to recover the costs of implementing energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by the Nevada Utilities and approved by the PUCN in the IRP proceedings. When the Nevada Utilities' regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, they are obligated to refund energy efficiency implementation revenue previously collected for that year.

            Net Metering

Nevada enacted Assembly Bill 405 ("AB 405") on June 15, 2017. The legislation, among other things, established net metering crediting rates for private generation customers with installed net metering systems less than 25 kilowatts. Under AB 405, private generation customers will be compensated for excess energy on a monthly basis at 95% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for the first 80 MWs of cumulative installed capacity of all net metering systems in Nevada, 88% of the rate for the next 80 MWs, 81% of the rate for the next 80 MWs and 75% of the rate for any additional private generation capacity. As of December 31, 2023, the cumulative installed and applied-for capacity of net metering systems under AB 405 in Nevada was 753 MWs.

46

            Natural Disaster Protection Plan ("NDPP")

SB 329, Natural Disaster Mitigation Measures, was signed into law on May 22, 2019. The legislation requires the Nevada Utilities to submit a NDPP to the PUCN. The PUCN adopted NDPP regulations on January 29, 2020, that require the Nevada Utilities to file their NDPP for approval on or before March 1 of every third year. The regulations also require annual updates to be filed on or before September 1 of the second and third years of the plan. The plan must include procedures, protocols and other certain information as it relates to the efforts of the Nevada Utilities to prevent or respond to a fire or other natural disaster. The expenditures incurred by the Nevada Utilities in developing and implementing the NDPP are required to be held in a regulatory asset account, with the Nevada Utilities filing an application for recovery on or before March 1 of each year. The PUCN reopened its investigation and rulemaking on SB 329 and the comment period for the reopened investigation ended in early February 2021. Final regulations are pending.

Federal Regulation

The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act, the Natural Gas Act ("NGA"), the Energy Policy Act of 2005 ("Energy Policy Act") and other federal statutes. The FERC regulates rates for wholesale sales of electricity; transmission of electricity, including pricing and regional planning for the expansion of transmission systems; electric system reliability; utility holding companies; accounting and records retention; securities issuances; construction and operation of hydroelectric facilities; and other matters. The FERC also has the enforcement authority to assess civil penalties of up to $1.5 million per day per violation of rules, regulations and orders issued under the Federal Power Act. The Utilities have implemented programs and procedures that facilitate and monitor compliance with the FERC's regulations described below. MidAmerican Energy is also subject to regulation by the NRC pursuant to the Atomic Energy Act of 1954, as amended ("Atomic Energy Act"), with respect to its ownership interest in the Quad Cities Station.

Wholesale Electricity and Capacity

The FERC regulates the Utilities' rates charged to wholesale customers for electricity and transmission capacity and related services. Much of the Utilities' wholesale electricity sales and purchases occur under market-based pricing allowed by the FERC and are therefore subject to market volatility. The Utilities are precluded from selling at market-based rates in the PacifiCorp-East, PacifiCorp-West, Nevada Utilities, Idaho Power Company and NorthWestern Energy balancing authority areas. Wholesale electricity sales in those specific balancing authority areas are permitted at cost-based rates. PacifiCorp and the Nevada Utilities have been granted the authority to bid into the California EIM at market-based rates.

The Utilities' authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the Utilities are required to submit triennial filings to the FERC that demonstrate a lack of market power over sales of wholesale electricity and electric generation capacity in their respective market areas. PacifiCorp, the Nevada Utilities and certain affiliates, representing the BHE Northwest Companies, file together for market power study purposes. The BHE Northwest Companies' most recent triennial filing was made in June 2022 and is under review by the FERC. MidAmerican Energy and certain affiliates file together for market power study purposes of the FERC-defined Northeast Region. The most recent triennial filing for the Northeast Region was made in June 2023, and it remains under review by the FERC. MidAmerican Energy and certain affiliates file together for market power study purposes of the FERC-defined Central Region. The most recent triennial filing for the Central Region was made in December 2023, and it remains pending under review. Under the FERC's market-based rules, the Utilities must also file with the FERC a notice of change in status when there is a change in the conditions that the FERC relied upon in granting market-based rate authority. MidAmerican Energy filed a notice of non-material change in status in July 2022, and the filing is currently under review by the FERC. In January 2024, MidAmerican Energy filed a change in status filing due to the addition of the Chickasaw wind farm generation, and the filing is currently under review by the FERC.

Transmission

PacifiCorp's and the Nevada Utilities' wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp's and the Nevada Utilities' OATTs. These services are offered on a non-discriminatory basis, which means that all potential customers are provided an equal opportunity to access the transmission system. PacifiCorp's and the Nevada Utilities' transmission business is managed and operated independently from its wholesale marketing business in accordance with the FERC's Standards of Conduct. PacifiCorp and the Nevada Utilities have made several required compliance filings in accordance with these rules.

47

In December 2011, PacifiCorp adopted a cost-based formula rate under its OATT for its transmission services. Cost-based formula rates are intended to be an effective means of recovering PacifiCorp's investments and associated costs of its transmission system without the need to file rate cases with the FERC, although the formula rate results are subject to discovery and challenges by the FERC and intervenors. A significant portion of these services are provided to PacifiCorp's energy supply management function.

MidAmerican Energy participates in the MISO as a transmission-owning member. Accordingly, the MISO is the transmission provider under its FERC-approved OATT. While the MISO is responsible for directing the operation of MidAmerican Energy's transmission system, MidAmerican Energy retains ownership of its transmission assets and, therefore, is subject to the FERC's reliability standards discussed below. MidAmerican Energy's transmission business is managed and operated independently from its wholesale marketing business in accordance with the FERC's Standards of Conduct.

MidAmerican Energy constructed and owns four Multi-Value Projects ("MVPs") located in Iowa and Illinois that added approximately 250 miles of 345-kV transmission line to MidAmerican Energy's transmission system since 2012. The MISO's OATT allows for broad cost allocation for MidAmerican Energy's MVPs, including similar MVPs of other MISO participants. Accordingly, a significant portion of the revenue requirement associated with MidAmerican Energy's MVP investments is shared with other MISO participants based on the MISO's cost allocation methodology, and a portion of the revenue requirement of the other participants' MVPs is allocated to MidAmerican Energy, which MidAmerican Energy recovers from customers via a rider mechanism. The transmission assets and financial results of MidAmerican Energy's MVPs are excluded from the determination of its base retail electric rates.

The FERC has established an extensive number of mandatory reliability standards developed by the NERC and the WECC, including planning and operations, critical infrastructure protection and regional standards. Compliance, enforcement and monitoring oversight of these standards is carried out by the FERC; the NERC; and the WECC for PacifiCorp, Nevada Power, and Sierra Pacific; and the Midwest Reliability Organization for MidAmerican Energy.

Hydroelectric

The FERC licenses and regulates the operation of hydroelectric systems, including license compliance and dam safety programs. Most of PacifiCorp's hydroelectric generating facilities are licensed by the FERC as major systems under the Federal Power Act, and certain of these systems are licensed under the Oregon Hydroelectric Act. Under the Federal Power Act, 16 of PacifiCorp's hydroelectric developments are classified as "high hazard potential," meaning it is probable in the event of a dam failure that loss of human life in the downstream population could occur. PacifiCorp uses the FERC's guidelines to develop public safety programs consisting of a dam safety program and emergency action plans.

For an update regarding PacifiCorp's Klamath River hydroelectric system, refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K.

Nuclear Regulatory Commission

    General

MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its license and 25% ownership interest in Quad Cities Station. Constellation Energy, the operator and 75% owner of Quad Cities Station, is under contract with MidAmerican Energy to secure and keep in effect all necessary NRC licenses and authorizations.

The NRC regulates the granting of permits and licenses for the construction and operation of nuclear generating stations and regularly inspects such stations for compliance with applicable laws, regulations and license terms. Current licenses for Quad Cities Station provide for operation until December 14, 2032. The NRC review and regulatory process covers, among other things, operations, maintenance, environmental and radiological aspects of such stations. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses.

Federal regulations provide that any nuclear operating facility may be required to cease operation if the NRC determines there are deficiencies in state, local or utility emergency preparedness plans relating to such facility, and the deficiencies are not corrected. Constellation Energy has advised MidAmerican Energy that an emergency preparedness plan for Quad Cities Station has been approved by the NRC. Constellation Energy has also advised MidAmerican Energy that state and local plans relating to Quad Cities Station have been approved by the Federal Emergency Management Agency.

48

The NRC also regulates the decommissioning of nuclear-powered generating facilities, including the planning and funding for the eventual decommissioning of the facilities. In accordance with these regulations, MidAmerican Energy submits a biennial report to the NRC providing reasonable assurance that funds will be available to pay its share of the costs of decommissioning Quad Cities Station. MidAmerican Energy has established a trust for the investment of funds collected for nuclear decommissioning of Quad Cities Station.

Under the Nuclear Waste Policy Act of 1982 ("NWPA"), the DOE is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Constellation Energy, as required by the NWPA, signed a contract with the DOE under which the DOE was to receive spent nuclear fuel and high-level radioactive waste for disposal beginning not later than January 1998. The DOE did not begin receiving spent nuclear fuel on the scheduled date and remains unable to receive such fuel and waste. The costs to be incurred by the DOE for disposal activities were previously being financed by fees charged to owners and generators of the waste. In accordance with a 2013 ruling by the D.C. Circuit, the DOE, in May 2014, provided notice that, effective May 16, 2014, the spent nuclear fuel disposal fee would be zero. In 2004, Constellation Energy, reached a settlement with the DOE concerning the DOE's failure to begin accepting spent nuclear fuel in 1998. As a result, Quad Cities Station has been billing the DOE, and the DOE is obligated to reimburse the station for all station costs incurred due to the DOE's delay. Constellation Energy has constructed an interim spent fuel storage installation ("ISFSI") at Quad Cities Station consisting of two pads to store spent nuclear fuel in dry casks in order to free space in the storage pool. The first dry cask was placed in-service in 2005. As of December 31, 2021, the first pad at the ISFSI is full, and the second pad is in operation. The first and second pads at the ISFSI are expected to facilitate storage of casks to support operations at Quad Cities Station through the end of its current operating licenses, which is 2032.    

Nuclear Insurance

MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in Quad Cities Station through a combination of insurance purchased by Constellation Energy, insurance purchased directly by MidAmerican Energy, and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988 ("Price-Anderson"), which was amended and extended by the Energy Policy Act. The general types of coverage maintained are: nuclear liability, property damage or loss and nuclear worker liability, as discussed below.

Constellation Energy purchases private market nuclear liability insurance for Quad Cities Station in the maximum available amount of $450 million, which includes coverage for MidAmerican Energy's ownership. In accordance with Price-Anderson, excess liability protection above that amount is provided by a mandatory industry-wide Secondary Financial Protection program under which the licensees of nuclear generating facilities could be assessed for liability incurred due to a serious nuclear incident at any commercial nuclear reactor in the U.S. Currently, MidAmerican Energy's aggregate maximum potential share of an assessment for Quad Cities Station is approximately $83 million per incident, payable in installments not to exceed $12 million annually.

The insurance for nuclear property damage losses covers property damage, stabilization and decontamination of the facility, disposal of the decontaminated material and premature decommissioning arising out of a covered loss. For Quad Cities Station, Constellation Energy purchases primary property insurance protection for the combined interests in Quad Cities Station, with coverage limits for nuclear damage losses up to $1.5 billion for nuclear perils and $500 million for non-nuclear perils. MidAmerican Energy also directly purchases extra expense coverage for its share of replacement power and other extra expenses in the event of a covered accidental outage at Quad Cities Station. The property and related coverages purchased directly by MidAmerican Energy and by Constellation Energy, which includes the interests of MidAmerican Energy, are underwritten by an industry mutual insurance company and contain provisions for retrospective premium assessments to be called upon based on the industry mutual board of directors' discretion for adverse loss experience. Currently, the maximum retrospective amounts that could be assessed against MidAmerican Energy from industry mutual policies for its obligations associated with Quad Cities Station total $10 million.

The master nuclear worker liability coverage, which is purchased by Constellation Energy for Quad Cities Station, is an industry-wide guaranteed-cost policy with an aggregate limit of $450 million for the nuclear industry as a whole, which is in effect to cover tort claims of workers in nuclear-related industries.

49

U.S. Mine Safety

PacifiCorp's surface mining operations are regulated by the Federal Mine Safety and Health Administration, which administers federal mine safety and health laws and regulations, and state regulatory agencies. The Federal Mine Safety and Health Administration has the statutory authority to institute a civil action for relief, including a temporary or permanent injunction, restraining order or other appropriate order against a mine operator who fails to pay penalties or fines for violations of federal mine safety standards. Information regarding PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Reform Act is included in Exhibit 95 to this Form 10-K.

Interstate Natural Gas Pipeline Subsidiaries

The Pipeline Companies are regulated by the FERC, pursuant to the NGA and the Natural Gas Policy Act of 1978. Under this authority, the FERC regulates, among other items, (a) rates, charges, terms and conditions of service, (b) the construction and operation of interstate pipelines, storage and related facilities, including the extension, expansion or abandonment of such facilities and (c) the construction and operation of LNG export/import facilities. The Pipeline Companies hold certificates of public convenience and necessity and LNG facility authorizations issued by the FERC, which authorize them to construct, operate and maintain their pipeline and related facilities and services.

In February 2022, the FERC updated its certificate policy that guides the authorization of natural gas projects and issued an interim policy providing guidance on how the FERC will review a natural gas project for its impact on climate change. The policies apply to pending and future natural gas projects. On March 24, 2022, the FERC revoked application of the policies and sought further comments.

FERC regulations and the Pipeline Companies' tariffs allow each of the Pipeline Companies to charge approved rates for the services set forth in their respective tariffs. Generally, these rates are a function of the cost of providing services to customers, including prudently incurred operations and maintenance expenses, taxes, depreciation and amortization and a reasonable return on invested capital. Tariff rates for each of the Pipeline Companies have been developed under a rate design methodology whereby substantially all fixed costs, including a return on invested capital and income taxes, are collected through reservation charges, which are paid by firm transportation and storage customers regardless of volumes shipped. Commodity charges, which are paid only with respect to volumes actually shipped, are designed to recover the remaining, primarily variable, costs. Kern River's reservation rates have historically been approved using a "levelized" cost-of-service methodology so that the rate remains constant over the levelization period. This levelized cost of service has been achieved by using a FERC-approved depreciation schedule in which depreciation increases as the cost of capital decreases on declining rate base. Each of the Pipeline Companies also hold authority to negotiate rates for their services, subject to requirements to offer cost-based rate alternatives, and to publish such negotiated rates. In addition, for services that are not subject to FERC rate jurisdiction pursuant to Section 3 of the Natural Gas Act, Cove Point charges rates that are established by contract.

The Pipeline Companies' rates are subject to change in future general rate proceedings. Rates for natural gas pipelines are changed by filings under either Section 5 or Section 4 of the Natural Gas Act. Section 5 proceedings are initiated by the FERC or the pipeline's customers for a potential reduction to rates that the FERC finds are no longer just and reasonable. In a Section 5 proceeding, the initiating party has the burden of demonstrating that the currently effective rates of the pipeline are no longer just and reasonable, and of demonstrating alternative just and reasonable rates. Any rate decrease as a result of a Section 5 proceeding is implemented prospectively upon the issuance of a final FERC order adopting the new just and reasonable rates. Section 4 rate proceedings are initiated by the natural gas pipeline, who must demonstrate that the new proposed rates are just and reasonable. The new rates as a result of a Section 4 proceeding are typically implemented six months after the Section 4 filing if higher than prior rates and are subject to refund upon issuance of a final order by the FERC.

The FERC-regulated natural gas companies may not grant undue preference to any customer. FERC regulations require that certain information be made public for market access, through standardized internet websites. These regulations also restrict each pipeline's marketing affiliates' access to certain non-public information that could affect price or availability of service.

50

Interstate natural gas pipelines are also subject to regulations administered by the Office of Pipeline Safety within the Pipeline and Hazardous Materials Safety Administration, an agency of the DOT. Federal pipeline safety regulations are issued pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended ("NGPSA"), which establishes safety requirements in the design, construction, operation and maintenance of interstate natural gas facilities, and requires an entity that owns or operates pipeline facilities to comply with such plans. Major amendments to the NGPSA include the Pipeline Safety Improvement Act of 2002 ("2002 Act"), the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 ("2006 Act"), the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 ("2011 Act") the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 ("2016 Act") and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020 ("2020 Act").

The 2002 Act established additional safety and pipeline integrity regulations for all natural gas pipelines in high-consequence areas. The 2002 Act imposed major new requirements in the areas of operator qualifications, risk analysis and integrity management. The 2002 Act mandated more frequent periodic inspection or testing of natural gas pipelines in high-consequence areas, which are locations where the potential consequences of a natural gas pipeline accident may be significant or may do considerable harm to persons or property. Pursuant to the 2002 Act, the DOT promulgated regulations that require natural gas pipeline operators to develop comprehensive integrity management programs, to identify applicable threats to natural gas pipeline segments that could impact high-consequence areas, to assess these segments and to provide ongoing mitigation and monitoring. The regulations require recurring inspections of high-consequence area segments every seven years after the initial baseline assessment.

The 2006 Act required pipeline operators to institute human factors management plans for personnel employed in pipeline control centers. DOT regulations published pursuant to the 2006 Act required development and implementation of written control room management procedures.

The 2011 Act was a response to natural gas pipeline incidents, most notably the San Bruno natural gas pipeline explosion that occurred in September 2010 in California. The 2011 Act increased the maximum allowable civil penalties for violations, directs operator assistance for Federal authorities conducting investigations and authorized the DOT to hire additional inspection and enforcement personnel. The 2011 Act also directed the DOT to study several topics, including the definition of high-consequence areas, the use of automatic shutoff valves in high-consequence areas, expansion of integrity management requirements beyond high-consequence areas and cast iron pipe replacement. The studies are complete, and a number of notices of proposed rulemaking have been issued. The Pipeline and Hazardous Materials Safety Administration ("PHMSA") issued the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements and Other Related Amendments final rule in October 2019. The primary change was the expansion of the pipeline integrity assessment requirements to cover moderate-consequence areas and reconfirming maximum allowable operating pressures. Pipeline operators were required to develop procedures to address assessment requirements by July 2021 and complete 50% of the required MAOP reconfirmation actions by 2028 and the remaining by 2035. The BHE Pipeline Group has updated procedures, identified pipeline segments subject to the rule and has planned projects to complete required assessments. PHMSA sent Part 2 of the rule to the Federal Register for publishing August 4, 2022, and it was published in the Federal Register August 24, 2022. The rule initially had an effective date of May 2023, but has been extended to February 2024. The third part of the rule, the gas gathering rule, has also been issued, but has minimal impact on the BHE Pipeline Group.

The 2016 Act required the Pipeline and Hazardous Materials Safety Administration to set federal minimum safety standards for underground natural gas storage facilities and authorized emergency order authority. In February 2020, the Pipeline and Hazardous Materials Safety Administration issued a final rule regarding underground natural gas storage facilities that incorporates by reference the American Petroleum Institute's Recommended Practice 1171, "Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs," clarifies certain aspects of the mandatory nature of the standard and defines regulatory completion dates for underground storage facility risk assessments. The BHE Pipeline Group has 20 total underground natural gas storage fields at EGTS and Northern Natural Gas that fall under this regulation and is complying with the final rule. The BHE Pipeline Group underground storage fields have had several audits under the Final Rule with no notices of probable violations issued. Kern River, Carolina Gas and Cove Point do not have underground natural gas storage facilities.

The 2020 Act required operations to review and update their inspection and maintenance plans to address how the plans contribute to eliminate hazardous leaks of natural gas, reduction of fugitive emissions and replacement or remediation of pipelines that are known to leak based on the material, design or past operating maintenance history. BHE Pipeline Group has completed the review and update of its inspection and maintenance plans. To assist in this effort, Kern River participated in a non-punitive pilot inspection with the Pipeline and Hazardous Materials Safety Administration.

51

The DOT and related state agencies routinely audit and inspect the pipeline facilities for compliance with their regulations. The Pipeline Companies conduct periodic internal audits of their facilities with more frequent reviews of those deemed higher risk. The Pipeline Companies also conduct preliminary audits in advance of agency audits. Compliance issues that arise during these audits or during the normal course of business are addressed on a timely basis. The Pipeline Companies believe their pipeline systems comply in all material respects with the NGPSA and with DOT regulations issued pursuant to the NGPSA.

Northern Powergrid Distribution Companies

The Northern Powergrid Distribution Companies, as holders of electricity distribution licenses, are subject to regulation by GEMA. GEMA regulates distribution network operators ("DNOs") within the terms of the Electricity Act 1989 and the terms of DNO licenses, which are revocable with 25 years notice. Under the Electricity Act 1989, GEMA has a duty to ensure that DNOs can finance their regulated activities and DNOs have a duty to maintain an investment grade credit rating. GEMA discharges certain of its duties through its staff within Ofgem. Each of fourteen licensed DNOs distributes electricity from the national grid transmission system and distribution-connected generators to end users within its respective distribution services area.

DNOs are subject to price controls, enforced by Ofgem, that limit the revenue that may be recovered and retained from their electricity distribution activities. The regulatory regime that has been applied to electricity distributors in Great Britain encourages companies to look for efficiency gains in order to improve profits. The distribution price control formula also adjusts the revenue received by DNOs to reflect a number of factors, including, but not limited to, the rate of inflation (as measured by the United Kingdom's Retail Prices Index) and the quality of service delivered by the licensee's distribution system. The current price control, Electricity Distribution 2 ("ED2"), has been set for a period of five years, starting April 1, 2023. The procedure and methodology adopted at a price control review are at the reasonable discretion of Ofgem. Ofgem's judgment of the future allowed revenue of licensees is likely to take into account, among other things:

•the actual operating and capital costs of each of the licensees;

•the operating and capital costs that each of the licensees would incur if it were as efficient as, in Ofgem's judgment, the more efficient licensees;

•the actual value of certain costs which are judged to be beyond the control of the licensees;

•the taxes that each licensee is expected to pay;

•the regulatory value ascribed to the expenditures that have been incurred in the past and the efficient expenditures that are to be incurred in the forthcoming regulatory period;

•the rate of return to be allowed on expenditures that make up the regulatory asset value;

•the financial ratios of each of the licensees and the license requirement for each licensee to maintain investment grade status;

•an allowance in respect of the repair of the pension deficits in the defined benefit pension schemes sponsored by each of the licensees; and

•any under- or over-recoveries of revenues, relative to allowed revenues, in the previous price control period.

A number of incentive schemes also operate within the current price control period to encourage DNOs to provide an appropriate quality of service to end users. This includes specified payments to be made for failures to meet prescribed standards of service. The aggregate of these guaranteed standards payments is uncapped but may be excused in certain prescribed circumstances that are generally beyond the control of the DNOs.

The current electricity distribution price control became effective April 1, 2023 and is due to terminate on March 31, 2028, and will be immediately replaced with a new price control. Although it has been the convention in Great Britain for regulators to conduct periodic regulatory reviews before making proposals for any changes to the price controls, a new price control can be implemented by GEMA without the consent of the DNOs. If a licensee disagrees with a change to its license, it can appeal the matter to the United Kingdom's CMA, as can certain other parties. Any appeals must be notified within 20 working days of the license modification by GEMA. If the CMA determines that the appellant has relevant standing, then the statute requires that the CMA complete its process within six months, or in some exceptional circumstances seven months. The Northern Powergrid Distribution Companies appealed Ofgem's proposals for the resetting of the formula that commenced April 1, 2023, the CMA remitted the matter back to Ofgem to determine and implement a remedy.

52

Ofgem completed the price control review that resulted in a new price control effective April 1, 2023. The license modifications that give effect to the price control were published by Ofgem on February 3, 2023 and were subject to appeal to the CMA, if an appeal is filed by March 3, 2023. Many aspects of the prior price control were maintained and the changes made generally follow the template that was set by the price controls implemented in April 2021 for transmission and gas distribution in Great Britain. Specific changes include new service standard incentives and mechanisms to adjust cost allowances in specific circumstances, particularly related to investment required to support decarbonization efforts, and partially updating the allowed return on equity within the period for changes in the interest rate on government bonds. Ofgem's final determinations also included an allowed cost of equity of 5.23% plus inflation (calculated using the United Kingdom's consumer prices index including owner occupiers' housing costs) and cost allowances representing a 20% real-term increase compared to the current regulatory period annual average. The base allowed revenue, excluding the effects of incentive schemes, pass-through costs and any deferred revenues from the prior price control, will decrease approximately 4.0% at Northern Powergrid (Northeast) plc and will increase approximately 2.5% at Northern Powergrid (Yorkshire) plc, respectively, in 2023-24 before the addition of inflation.

Ofgem also monitors DNO compliance with license conditions and enforces the remedies resulting from any breach of condition. License conditions include the prices and terms of service, financial strength of the DNO, the provision of information to Ofgem and the public, as well as maintaining transparency, non-discrimination and avoidance of cross-subsidy in the provision of such services. Ofgem also monitors and enforces certain duties of a DNO set out in the Electricity Act 1989, including the duty to develop and maintain an efficient, coordinated and economical system of electricity distribution. Under changes to the Electricity Act 1989 introduced by the Utilities Act 2000, GEMA is able to impose financial penalties on DNOs that contravene any of their license duties or certain of their duties under the Electricity Act 1989, as amended, or that are failing to achieve a satisfactory performance in relation to the individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the licensee's revenue.

AltaLink

AltaLink is regulated by the AUC, pursuant to the Electric Utilities Act (Alberta), the Public Utilities Act (Alberta), the Alberta Utilities Commission Act (Alberta) and the Hydro and Electric Energy Act (Alberta). The AUC is an independent, quasi-judicial agency established by the province of Alberta, Canada, which is responsible for, among other things, approving the tariffs of transmission facility owners, including AltaLink, and distribution utilities, acquisitions of such transmission facility owners or utilities, and construction and operation of new transmission projects in Alberta. The AUC also investigates and rules on regulated rate disputes and system access problems. The AUC regulates and oversees Alberta's electricity transmission sector with broad authority that may impact many of AltaLink's activities, including its tariffs, rates, construction, operations and financing.

The AUC has various core functions in regulating the Alberta electricity transmission sector, including the following:

•regulating and adjudicating issues related to the operation of electric utilities within Alberta;

•processing and approving general tariff applications relating to revenue requirements, capital expenditure prudency and rates of return including deemed capital structure for regulated utilities while ensuring that utility rates are just and reasonable, and approval of the transmission tariff rates of regulated transmission providers paid by the AESO, which is the independent transmission system operator in Alberta, Canada that controls the operation of AltaLink's transmission system;

•approving the need for new electricity transmission facilities and permits to build and licenses to operate electricity transmission facilities;

•reviewing operations and accounts from electric utilities and conducting on-site inspections to ensure compliance with industry regulation and standards;

•adjudicating enforcement issues including the imposition of administrative penalties that arise when market participants violate the rules of the AESO; and

•collecting, storing, analyzing, appraising and disseminating information to effectively fulfill its duties as an industry regulator.

In addition, AUC approval is required in connection with new energy and regulated utility initiatives in Alberta, amendments to existing approvals and financing proposals by designated utilities.

53

AltaLink's tariffs are regulated by the AUC under the provisions of the Electric Utilities Act (Alberta) in respect of rates and terms and conditions of service. The Electric Utilities Act (Alberta) and related regulations require the AUC to consider that it is in the public interest to provide consumers the benefit of unconstrained transmission access to competitive generation and the wholesale electricity market. In regulating transmission tariffs, the AUC must facilitate sufficient investment to ensure the timely upgrade, enhancement or expansion of transmission facilities, and foster a stable investment climate and a continued stream of capital investment for the transmission system.

Under the Electric Utilities Act (Alberta), AltaLink prepares and files applications with the AUC for approval of tariffs to be paid by the AESO for the use of its transmission facilities, and the terms and conditions governing the use of those facilities. The AUC reviews and approves such tariff applications based on a cost-of-service regulatory model under a forward test year basis. Under this model, the AUC provides AltaLink with a reasonable opportunity to (i) earn a fair return on equity; and (ii) recover its forecast costs, including operating expenses, depreciation, borrowing costs and taxes (including deemed income taxes) associated with its regulated transmission business. The AUC must approve tariffs that are just, reasonable and not unduly preferential, arbitrary or unjustly discriminatory. AltaLink's transmission tariffs are not dependent on the price or volume of electricity transported through its transmission system.

The AESO is an independent system operator in Alberta, Canada that oversees the Alberta Interconnected Electric System ("AIES") and wholesale electricity market. The AESO is responsible for directing the safe, reliable and economic operation of the AIES, including long-term transmission system planning. AltaLink and the other transmission facility owners receive substantially all of their transmission tariff revenues from the AESO. The AESO, in turn, charges wholesale tariffs, approved by the AUC, in a manner that promotes fair and open access to the AIES and facilitates a competitive market for the purchase and sale of electricity. The AESO monitors compliance with approved reliability standards, which are enforced by the Market Surveillance Administrator, which may impose penalties on transmission facility owners for non-compliance with the approved reliability standards.

The AESO determines the need and plans for the expansion and enhancement of the transmission system in Alberta in accordance with applicable law and reliability standards. The AESO's responsibilities include long-term transmission planning and management, including assessing the current and future transmission system capacity needs of market participants. When the AESO determines an expansion or enhancement of the transmission system is needed, with limited exceptions, it submits an application to the AUC for approval of the proposed expansion or enhancement. The AESO then determines which transmission provider should submit an application to the AUC for a permit and license to construct and operate the designated transmission facilities. Generally, the transmission provider operating in the geographic area where the transmission facilities expansion or enhancement is to be located is selected by the AESO to build, own and operate the transmission facilities. In addition, Alberta law provides that certain transmission projects may be subject to a competitive process open to qualified bidders.

Independent Power Projects

The Yuma, Cordova, Saranac, Power Resources, Topaz, Agua Caliente, Solar Star 1, Solar Star 2, Bishop Hill II, Jumbo Road, Marshall, Grande Prairie, Walnut Ridge, Pinyon Pines I, Pinyon Pines II, Santa Rita, Independence, Fluvanna II, Flat Top, Mariah del Norte, Alamo 6 and Pearl independent power projects are Exempt Wholesale Generators ("EWG") under the Energy Policy Act, while the Community Solar Gardens, Imperial Valley and Wailuku independent power projects are currently certified as Qualifying Facilities ("QF") under the Public Utility Regulatory Policies Act of 1978. Both EWGs and QFs generally are exempt from compliance with extensive federal and state regulations that control the financial structure of an electric generating plant and the prices and terms at which electricity may be sold by the facilities.

54

The Yuma, Cordova, Saranac, Imperial Valley, Topaz, Agua Caliente, Solar Star 1, Solar Star 2, Bishop Hill II, Marshall, Grande Prairie, Walnut Ridge, Independence, Pinyon Pines I and Pinyon Pines II independent power projects have obtained authority from the FERC to sell their power at market-based rates. This authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the respective independent power projects are required to submit triennial filings to the FERC that demonstrate a lack of market power over sales of wholesale electricity and electric generation capacity in their respective market areas. The Pinyon Pines I, Pinyon Pines II, Solar Star 1, Solar Star 2, Topaz and Yuma independent power projects and power marketers CalEnergy, LLC and BHER Market Operations, LLC file together for market power study purposes of the FERC-defined Southwest Region. The most recent triennial filing for the Southwest Region was made in June 2022 and is awaiting FERC action. The Cordova and Saranac independent power projects and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Northeast Region. The most recent triennial filing for the Northeast Region was made in June 2023 and is awaiting FERC action. The Bishop Hill II and Walnut Ridge independent power projects and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Central Region. The most recent triennial filing for the Central Region was made in December 2023 and is awaiting FERC action. The Marshall and Grande Prairie independent power projects and power marketer CalEnergy, LLC file together for market power study purposes in the FERC-defined Southwest Power Pool Region. The most recent triennial filing for the Southwest Power Pool Region was made in December 2021, was supplemented in July 2022 and an order accepting it was issued in January 2023. Power marketers CalEnergy LLC and BHER Market Operations, LLC also file for market power study purposes in the FERC-defined Northwest Region together with PacifiCorp, Nevada Power Company, Sierra Power Company and certain affiliates. The most recent triennial filing for the Northwest Region was made in June 2022, was supplemented in December 2022, and is awaiting FERC action.

The entire output of Jumbo Road, Santa Rita, Fluvanna II, Flat Top, Mariah del Norte, Alamo 6, Pearl and Power Resources is within the ERCOT and market-based authority is not required for such sales solely within ERCOT as the ERCOT market is not a FERC-jurisdictional market. Similarly, Wailuku sells its output solely to the Hawaii Electric Light Company within the Hawaii electric grid, which is not a FERC-jurisdictional market and therefore, Wailuku does not require market-based rate authority.

EWGs are permitted to sell capacity and electricity only in the wholesale markets, not to end users. Additionally, utilities are required to purchase electricity produced by QFs at a price that does not exceed the purchasing utility's "avoided cost" and to sell back-up power to the QFs on a non-discriminatory basis, unless they have successfully petitioned the FERC for an exemption from this purchase requirement. Avoided cost is defined generally as the price at which the utility could purchase or produce the same amount of power from sources other than the QF on a long-term basis. The Energy Policy Act eliminated the purchase requirement for utilities with respect to new contracts under certain conditions. New QF contracts are also subject to FERC rate filing requirements, unlike QF contracts entered into prior to the Energy Policy Act. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates other than the utility's avoided cost.

Residential Real Estate Brokerage Company

HomeServices and its operating subsidiaries are regulated by the U.S. Consumer Financial Protection Bureau which enforces the Truth In Lending Act ("TILA"), the Equal Credit Opportunity Act ("ECOA") and the Real Estate Settlement Procedures Act ("RESPA"); by the U.S. Federal Trade Commission with respect to certain franchising activities; by the U.S. Department of Housing and Urban Development, which enforces the Fair Housing Act ("FHA"); and by state agencies where its subsidiaries operate. TILA and ECOA regulate lending practices. FHA prohibits housing-related discrimination on the basis of race, color, national origin, religion, sex, familial status, and disability. RESPA regulates real estate settlement services including real estate closing practices, lender servicing and escrow account practices and business relationships among settlement service providers and third parties to the transaction.

55

REGULATORY MATTERS

In addition to the discussion contained herein regarding regulatory matters, refer to "General Regulation" in Item 1 of this Form 10-K for further information regarding the general regulatory framework.

PacifiCorp

Utah

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

In June 2023, PacifiCorp filed its annual wildland fire cost and compliance report with the UPSC, which reported on calendar year 2022 wildland fire mitigation activities. The report included a request to recover $7 million in deferred costs associated with implementing the wildland fire mitigation plan incremental to those included in base rates. PacifiCorp proposed to recover the amounts over one year. Intervening parties requested a hearing to review the rate request, which was held in October 2023. In November 2023, the UPSC issued an order denying the rate request without prejudice. PacifiCorp may continue to defer the 2022 wildland fire mitigation plan costs, and the UPSC may approve recovery of these costs, if PacifiCorp is able to provide substantial evidence that the claimed costs are not already recovered through base rates. PacifiCorp will request recovery as part of its upcoming general rate case expected to be filed in April 2024.

Oregon

In July 2021, in accordance with the OPUC's December 2020 general rate case order, PacifiCorp filed an application with the OPUC to initiate the review of PacifiCorp's estimated decommissioning and other closure costs per third-party studies associated with its coal-fueled generating facilities. The application requested an initial rate increase of $35 million, or 2.8%, to become effective January 1, 2022, to recover the incremental costs from those approved in the last general rate case. In November 2022, an independent evaluator was selected. Until the independent evaluator completes its work reviewing the third-party studies that contain the estimated decommissioning and other closure costs and the OPUC issues an order, there will be no change to rates related to this filing.

In July 2022, PacifiCorp filed an application requesting approval of an automatic adjustment clause with a balancing account to recover costs associated with implementing PacifiCorp's wildfire protection plan in Oregon. Per formal rulemaking at the OPUC, the wildfire protection plan was changed to be known as the wildfire mitigation plan, resulting in the requested automatic adjustment clause being referred to as the Wildfire Mitigation Plan Automatic Adjustment Clause ("WMP AAC"). In December 2022, a stipulation with certain parties was filed agreeing to the establishment of an automatic adjustment clause. In May 2023, the OPUC approved the stipulation, which resulted in an overall annual increase of $20 million, or 1.6%, effective May 24, 2023 for estimated 2022 incremental operation and maintenance costs in excess of those reflected in base rates as a result of the last general rate case. In June 2023, PacifiCorp filed its WMP AAC to recover remaining 2022 deferred operations and maintenance costs, projected incremental 2023 operations and maintenance costs and capital costs incremental to amounts previously included in general rate case filings. The filing requested a rate increase of $27 million over the existing amount approved in May 2023, to become effective November 5, 2023. When combined with the previously approved increase, the rate schedule would be set to recover $47 million. In October 2023, in response to discussions with the OPUC staff, PacifiCorp requested the effective date for the WMP AAC shift to December 13, 2023, to allow more time for the OPUC staff to review the filing, and in November 2023, PacifiCorp requested the effective date move to January 10, 2024, to allow PacifiCorp to participate in the public meeting when the matter is brought before the OPUC. In January 2024, PacifiCorp filed a supplemental filing reducing the requested rate increase to $25 million, or 1.4%, and in the public meeting the OPUC approved the rate increase with an effective date of January 10, 2024.

In April 2023, PacifiCorp filed its TAM requesting approval to update net power costs for 2024. The filing requested a rate increase of $164 million, or 9.5%, to become effective January 1, 2024. In July 2023, PacifiCorp updated its filing to reduce the requested rate increase to $131 million to reflect changes in PacifiCorp's forecast net power costs for 2024. In September 2023, a stipulation with certain intervening parties was filed settling substantially all issues in the 2024 TAM and in October 2023, the OPUC issued an order approving the stipulation, subject to final updates and excluding costs associated with the Washington Cap and Invest program. The final update, filed in November 2023, resulted in a rate increase of $150 million, or 8.7%, effective January 1, 2024.

56

In May 2023, PacifiCorp filed its 2022 PCAM requesting recovery of the difference between actual power costs and base power costs established in the 2022 TAM. The filing requested recovery of $131 million, which PacifiCorp proposed to recover over a two-year period with interest, resulting in a rate increase of $69 million, or 4.0%, effective January 1, 2024. In October 2023, a stipulation was filed providing for the requested amounts. In December 2023, the OPUC issued an order accepting the stipulation. As established in the stipulation, because the combined January 1, 2024 rate increase for residential customers from all January 1 rate changes was less than 15%, the rate effective date of the 2022 PCAM for residential customers remained January 1, 2024.

In February 2024, PacifiCorp filed a general rate case requesting a rate increase of $322 million, or 17.9%, to become effective January 1, 2025. The request includes new capital investments in transmission and wind-powered generating facilities, higher insurance premiums for third-party liability coverage and proposed funding for a catastrophic fire fund.

In February 2024, PacifiCorp filed its TAM requesting approval to update net power costs for 2025. The filing requests a rate decrease of $18 million, or 1.0%, subject to updates throughout the course of the proceeding, to become effective January 1, 2025.

Wyoming

In March 2023, PacifiCorp filed a general rate case requesting a rate increase of $140 million, or 21.6%, to become effective January 1, 2024. The requested rate increase includes recovery of increases in net power costs and new major capital investments in transmission and wind-powered generating facilities. In September 2023, PacifiCorp filed updated testimony that included updated net power costs and increased insurance premium costs associated with third-party liability coverage. As a result of the updates, the requested rate increase has been revised to $137 million, or 21.1%. In November 2023, the WPSC approved a rate increase of $54 million, or 8.3%, effective January 1, 2024. The approved rate increase reflects a reduction in the requested return on equity compared to what was sought by PacifiCorp, the exclusion of the increased insurance premium costs that will be addressed outside of the general rate case and a reduction in net power costs determined by the WPSC. The approved rate increase also excludes from the net power costs the costs associated with the Washington Cap and Invest program. In January 2024, PacifiCorp filed an application for rehearing requesting the WPSC consider three items, including the WPSC's net power costs adjustment, costs associated with the Washington Cap and Invest program and the opportunity to revise PacifiCorp's initial revenue requirement request for updates, corrections and revisions reflected in rebuttal testimony.

In April 2023, PacifiCorp filed its ECAM, REC and RRA to recover deferred net power costs from 2022. The combined filing requested a rate increase of $49 million, or 7.4%, which was effective on an interim basis July 1, 2023. In October 2023, PacifiCorp filed rebuttal testimony updating the ECAM calculation. As a result of the updates, the requested combined rate increase was revised to $42 million, or 6.3%. In December 2023, a stipulation and settlement agreement was filed, reflecting a combined rate increase of $40 million, or 6.0%. The WPSC approved the stipulation in December 2023, with an effective date of January 1, 2024.

Washington

In March 2023, PacifiCorp filed a general rate case requesting a two-year rate plan with a rate increase of $27 million, or 6.6%, to become effective March 1, 2024, and a second rate increase of $28 million, or 6.5%, to become effective March 1, 2025. The requested rate increase includes recovery of increases in net power costs and new major capital investments in transmission and wind-powered generating facilities. In October 2023, PacifiCorp filed updated testimony that included updated net power costs, increased insurance premium costs and removal of some capital projects. As a result of the updates, the requested rate increases have been revised to $19 million, or 4.6%, to become effective March 1, 2024, and $22 million, or 5.2%, to become effective March 1, 2025. In December 2023, a multi-party settlement stipulation was filed updating the requested rate increase to $14 million, or 3.4%, to become effective March 19, 2024, and $21 million, or 5.0%, to become effective March 1, 2025. A hearing on the settlement stipulation was held in January 2024 and a final decision from the WUTC is pending.

In June 2023, PacifiCorp filed its PCAM to recover deferred net power costs from 2022. The filing requested recovery of over $71 million, which PacifiCorp proposed to recover over a two-year period with interest, resulting in a rate increase of $37 million, or 9.5%, to become effective January 1, 2024. In November 2023, the WUTC suspended PacifiCorp's PCAM filing in response to an intervening party's petition for adjudication request. PacifiCorp's hedging practices will be evaluated in the adjudicative proceeding that is scheduled for hearing in June 2024.

57

Idaho

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

California

In May 2022, PacifiCorp filed a general rate case requesting an overall rate change of $28 million, or 25.7%, to become effective January 1, 2023. In November 2022, the CPUC granted the requested rate effective date and directed PacifiCorp to establish a memorandum account to track the change in rates beginning January 1, 2023 until the new rates become effective, upon the issuance of a decision in late 2023. PacifiCorp filed rebuttal testimony in February 2023 with a slight adjustment of an overall rate increase of $27 million, or 25.0%. Also in February 2023, the CPUC issued a ruling requesting additional information on PacifiCorp's wildfire and risk analyses and requested additional information regarding wildfire memorandum accounts. In March 2023, the CPUC split the general rate case into two tracks. The first track addresses the general rate case and the second track addresses the wildfire memorandum accounts. In October 2023, PacifiCorp filed updated testimony in the first track that removed the costs considered in the second track, as directed by the CPUC. The updated testimony clarified that the rate increase for the first track is $22 million, or 20.1%. In December 2023, the CPUC issued an order for the first track approving a rate increase of $19 million, or 17.5%, effective January 12, 2024. Additionally, the CPUC approved recovery of $19 million associated with the aforementioned memorandum account over three years. In the second track of the general rate case, PacifiCorp filed the independent audit of the wildfire memorandum accounts in January 2024, indicating no findings. A decision in the second track is expected by late 2024.

In September 2023, PacifiCorp filed its 2024 combined ECAC and GHG related costs application requesting an overall rate increase of $30 million, or 25.0%, effective March 1, 2024. Approximately $36 million of the increase is attributed to the ECAC rate, which is offset by $6 million decrease to the GHG rate. In January 2024, PacifiCorp filed a joint motion for approval of the GHG portion of the filing.

Deferral Accounting Treatment for Increased Costs Associated with Wildfires

In June 2023, PacifiCorp filed deferral applications with the UPSC, the OPUC, the WPSC, the WUTC and the IPUC to track the costs associated with third-party liability from litigation due to the 2020 Wildfires. The deferred accounting applications enable PacifiCorp to preserve its ability to seek recovery in the future in the event the outcome could potentially impact its financial stability. The applications state that PacifiCorp is not seeking recovery of these costs from customers at this time and does not expect to determine if it will seek recovery until the appeals process has concluded. In August 2023, PacifiCorp filed a motion to withdraw without prejudice with the UPSC, and in September 2023, PacifiCorp filed a notice of withdrawal without prejudice with the IPUC. These filings preserve the ability of PacifiCorp to file for deferred accounting treatment when the actual liability costs are more certain.

In June 2023, PacifiCorp filed an application with the CPUC for authority to establish a Wildfire Expense Memorandum Account to track the costs associated with third-party liability from litigation due to the 2020 Wildfires, increased insurance premium costs associated with third-party liability coverage and costs associated with potential liability for future catastrophic wildfires. The CPUC issued a proposed decision in February 2024 and PacifiCorp anticipates a final order by April 2024, approving the Wildfire Expense Memorandum Account to be able to track costs incurred on or after June 21, 2020.

In August 2023, PacifiCorp filed deferral applications with the UPSC, the OPUC, the WUTC and the IPUC for costs associated with increased insurance premium costs associated with third-party liability coverage. In December 2023, PacifiCorp filed a deferral application with the WPSC for the incremental insurance premium costs. The IPUC and the OPUC approved the request for authorization to defer the increased insurance premium costs in December 2023 and January 2024, respectively.

58

MidAmerican Energy

Iowa

In June 2023, MidAmerican Energy filed a request with the IUB for an increase in its Iowa retail natural gas rates, which would increase revenue by $39 million annually or increase retail customer's bills by an average of 6.1%. Interim rates of $31 million annually, or an average increase to customer's bills of 4.8%, were effective in June 2023. In January 2024, MidAmerican Energy filed a non-unanimous settlement with the OCA, which would allow for an increase in revenue of $30 million annually, or an average increase to customer's bills of 4.6%. On January 23, 2024, the IUB held a hearing regarding the non-unanimous settlement agreement. MidAmerican Energy expects the IUB to issue an order on the non-unanimous settlement in the first quarter of 2024 with final rates effective in the second quarter of 2024.

Wind PRIME

In January 2022, MidAmerican Energy filed an application with the IUB for advance ratemaking principles for Wind PRIME, which consists of up to 2,042 MWs of new wind generation and up to 50 MWs of solar generation. If all Wind PRIME generation is constructed, MidAmerican Energy will own over 9,300 MWs of wind generation and nearly 200 MWs of solar generation. Wind PRIME is projected to allow MidAmerican Energy to generate renewable energy greater than or equal to all of its Iowa retail customers' annual energy needs. MidAmerican Energy expects to be eligible for 100% PTCs under current tax law for the Wind PRIME projects. In December 2022, MidAmerican Energy, the OCA and the Iowa Business Energy Coalition filed a non-unanimous settlement with the IUB. On April 27, 2023, the IUB issued its final order regarding the application and found that MidAmerican Energy met the statutory requisites for a grant of advance ratemaking principles and granted the application, but rejected the settlement and proposed its own principles for the project. MidAmerican Energy reviewed the order and filed a motion for reconsideration or rehearing on May 17, 2023. On June 15, 2023, the IUB granted the motion for reconsideration and rehearing. In August 2023, MidAmerican Energy, the OCA and the Environmental Intervenors filed a revised non-unanimous settlement with the IUB that included a return on equity of 10.75%. The settlement would also benefit customers by providing a rate decrease through lower retail fuel costs and future rate increase mitigation through accelerated depreciation of generation assets. On December 14, 2023, the IUB issued its final order on rehearing, approving the revised non-unanimous settlement. MidAmerican Energy accepted the ratemaking principles on December 18, 2023, and plans to move forward with the construction of Wind PRIME.

59

Iowa Transmission Legislation

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

60

NV Energy (Nevada Power and Sierra Pacific)

Regulatory Rate Review

In June 2023, Nevada Power filed a regulatory rate review with the PUCN that requested an annual revenue increase of $93 million, or 3.3%. In addition, a filing was made to revise depreciation rates based on a study, the results of which are reflected in the proposed revenue requirement. In August, 2023, Nevada Power filed an updated certification filing that requested an annual revenue increase of $96 million, or 3.3%. Parties to the review filed testimony and evidence in August and September 2023. Hearings in the cost of capital, revenue requirement and rate design phases were held in October and November 2023. In December 2023, the PUCN issued an order approving an increase in base rates of $37 million, effective January 1, 2024, reflecting a reduction in Nevada Power's requested rate of return and updated depreciation and amortization rates for its electric operations. In January 2024, Nevada Power filed a petition for reconsideration and clarification of the order. In February of 2024, the PUCN issued a final order approving in part and denying in part the petition for reconsideration.

In February 2024, Sierra Pacific filed electric and gas regulatory rate reviews with the PUCN that requested annual revenue increases of $94.7 million, or 8.8% and $11.1 million, or 4.9%, respectively. Orders are expected by the third quarter of 2024 and, if approved, would be effective October 1, 2024.

Northern Powergrid Distribution Companies

Ofgem has completed the five-year RIIO-ED2 price control review that became effective April 1, 2023. The license modifications that gave effect to the price control were published by Ofgem in February 2023. In March 2023, Northern Powergrid sought permission from the Competition and Markets Authority ("CMA") to appeal against those license modifications. The appeal related to two specific areas:

•An error in the method that Ofgem used to allocate price control allowances into the different funding mechanisms resulting in underfunding; and

•Failure by Ofgem to award Northern Powergrid (Yorkshire) plc with a reward under its business plan incentive mechanism.

In September 2023, the CMA found that Ofgem's decision on the allocation of price control allowances was unlawful on the grounds of irrationality and remitted the matter back to Ofgem to redetermine. The CMA found that Ofgem's decision not to grant Northern Powergrid (Yorkshire) plc a reward under its business plan incentive mechanism was valid.

In February 2024, Ofgem published its redetermination on the allocation of Northern Powergrid's price control allowances, resulting in access to £97 million of additional funding for the period April 2023 to March 2028 in 2020/21 prices. This closes Northern Powergrid's appeal.

BHE Pipeline Group

BHE GT&S

In November 2023, CGT filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective January 1, 2024. CGT's current rates were established by a 2011 settlement. CGT proposed an annual cost-of-service of $167 million, and requested increases in various rates, including Zone 1 general system transportation rates by 84% and Zone 2 general system transportation rates by 23%. In December 2023, the FERC suspended the rate changes for five months following the proposed effective date, until June 1, 2024, subject to refund and the outcome of hearing procedures. This matter is pending.

BHE Transmission

AltaLink

2024-2025 General Tariff Application

In April 2023, AltaLink filed its 2024-2025 GTA with the AUC with total transmission tariffs of C$902 million and C$909 million for 2024 and 2025, respectively. The application also requested the approval to reinstate C$99 million cost of removal to rate base which was not previously approved, based on additional information filed.

61

In July 2023, AltaLink requested the AUC to suspend the schedule for its 2024-2025 GTA until August 31, 2023. AltaLink required the schedule delay to amend its application in response to the unprecedented wildfire events that AltaLink experienced in Alberta, Canada in May and June 2023. In August 2023, AltaLink filed an amendment to its 2024-2025 GTA. The amendment increased AltaLink's Wildfire Mitigation Plan capital expenditures from C$16 million to C$39 million in 2024 and from C$15 million to C$38 million for 2025. AltaLink's total amended transmission tariffs for 2024 and 2025 are C$904 million and C$912 million, respectively.

In December 2023, AltaLink advised the AUC that it reached a negotiated settlement with customer groups on the majority of its 2024-2025 GTA and filed the agreement with the AUC for approval. In February 2024, the AUC issued its decision with respect to AltaLink's 2024-2025 GTA, approving the negotiated settlement agreement as filed. Under the agreement, AltaLink will reduce its applied-for operating expenses by C$7 million and sustaining capital expenditures by C$39 million for the 2024-2025 test period. The agreement does not include AltaLink's proposed wildfire deferral account, certain components of the wildfire mitigation plan, and actual and forecast salvage expenditures from its 2019-2023 GTA and 2024-2025 GTA, respectively. AltaLink's total revised transmission tariffs adjusted for the negotiated settlement are C$900 million for 2024 and C$904 million for 2025. Information responses and AltaLink's rebuttal evidence on the negotiated settlement and the items excluded from the negotiated settlement were provided in February 2024. AltaLink will be adjusting its 2024 transmission tariff and the 8.50% return on equity included in its application filed on December 19, 2023, to the 9.28% return on equity approved by the AUC in the 2024 GCOC proceeding. An oral hearing to address the excluded matters is scheduled in March 2024.

Also, in December 2023, AltaLink filed an application with the AUC to recover all costs incurred as a result of the 2023 spring wildfire and storm events. The application includes capital expenditures of C$18.5 million and salvage expenditures of C$6 million.

In December 2023, the AUC approved 2024 interim refundable transmission tariffs for AltaLink, including monthly tariffs for PLP and KLP, of C$74 million per month effective January 1, 2024.

Generic Cost of Capital Proceeding

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

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

In October 2023, the AUC issued its decision on the Generic Cost of Capital for 2024 and beyond for Alberta's regulated electric and gas utilities, approving an equity ratio and formula to determine return on equity. The AUC set the deemed equity ratio of 37% and the notional return on equity of 9.00%, which is subject to formulaic adjustments utilizing 30-year Government of Canada bond yields and Canadian utility spreads. In November 2023, the AUC issued an order approving 9.28% as the final return on equity for 2024.

62

    BHE U.S. Transmission

A significant portion of ETT's revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base regulatory rate review scheduled for no later than February 1, 2025. In February 2023, the Public Utilities Commission of Texas ("PUCT") approved ETT's request to suspend a base regulatory rate review filing scheduled for February 2023. Results of a base regulatory rate review would be prospective except for any deemed disallowance by the PUCT of the transmission investment since the initial base regulatory rate review in 2007. In June 2018, the PUCT approved ETT's application to reduce its transmission revenue by $28 million to reflect the lower federal income tax rate due to the federal tax rate change from 35% to 21% in 2017, with the amortization of excess accumulated deferred federal income taxes expected to be addressed in the next base rate case.

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 laws and regulations are subject to interpretation that may ultimately be resolved by the courts.

The Company has cumulative investments in (i) owned wind, solar and geothermal generating facilities of $34.1 billion and (ii) wind tax equity investments of $5.8 billion and has ceased coal operations at 18 coal-fueled generation facilities. As a result, as of December 31 2023, the Company reduced its annual GHG emissions by more than 34% as compared to 2005 levels. The Company plans to continue investing in wind, solar and other low-carbon generation and storage in the future, including (i) $6.9 billion on the construction of renewable generating facilities and repowering certain existing wind-powered generating facilities through 2026 and (ii) $2.0 billion on the construction of electric battery and pumped hydro storage facilities through 2026, and to cease coal operations at an additional 15 coal-fueled generation facilities between 2025 and 2030 in a reliable and cost-effective manner, thereby achieving a 50% reduction in GHG emissions from 2005 levels in 2030. Refer to "Liquidity and Capital Resources" of each respective Registrant in Item 7 of this Form 10-K for discussion of each Registrant's renewable generation-related capital expenditures.

On August 16, 2022, the Inflation Reduction Act of 2022 (the "2022 Act") was signed into law. The 2022 Act contains numerous provisions, including expanded tax credits for clean energy incentives and a 15% corporate alternative minimum income tax on "adjusted financial statement income". The provisions of the 2022 Act become effective for tax years beginning after December 31, 2022. The Company currently does not expect a material impact on its consolidated financial statements. However, the Company expects future guidance from the Treasury Department and will continue to evaluate the impact of the 2022 Act as more guidance becomes available.

Air Quality Regulations

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

National Ambient Air Quality Standards

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

63

On June 4, 2018, the EPA published final ozone designations for much of the U.S. Relevant to the Registrants, these designations include classifying Yuma County, Arizona; Clark County, Nevada; and the Northern Wasatch Front, Southern Wasatch Front and Duchesne and Uintah counties in Utah as nonattainment-marginal with the 2015 ozone standard. These areas were required to meet the 2015 standard three years from the August 3, 2018, effective date. All other areas relevant to the Registrants were designated attainment/unclassifiable with this same action. However, on January 29, 2021, the D.C. Circuit vacated several provisions of the 2018 implementing rules for the 2015 ozone standards for contravening the Clean Air Act. The EPA and environmental groups finalized a consent decree in January 2022 that sets deadlines for the agency to approve or disapprove the "good neighbor" provisions of interstate ozone plans of dozens of states. Relevant to the Registrants, the EPA must, by April 30, 2022, propose to approve or disapprove the interstate ozone SIPs of Alabama, Iowa, Maryland, Michigan, Minnesota, New York, Ohio, Pennsylvania, Texas, West Virginia and Wisconsin. On February 22, 2022, the EPA published a series of proposed decisions to disapprove the SIPs for interstate ozone transport of 19 states. Relevant to the Registrants, these states include Alabama, Maryland, Michigan, Minnesota, New York, Ohio, West Virginia and Wisconsin. The EPA also proposed to approve Iowa's SIP after re-analyzing the state's data. In addition, the EPA must approve or disapprove the interstate plans of Arizona, California, Nevada and Wyoming. On April 15, 2022, the EPA issued its final rule approving Iowa's SIP as meeting the good neighbor provisions for the 2015 ozone standard. On May 24, 2022, the EPA disapproved the Utah and Wyoming interstate ozone SIPs. On January 30, 2023, the EPA entered into a stipulated extension to the deadline for action on the Wyoming SIP, setting a new deadline of December 15, 2023. The EPA explained that the extra time is needed to fully consider updated air quality information and public comments. The EPA published its proposed approval of Wyoming's SIP on August 14, 2023 and finalized the approval December 19, 2023. As a result Wyoming is not subject to the Good Neighbor Rule and litigation over Wyoming's SIP was terminated after the effective date of the rule on January 18, 2024. The EPA is also reevaluating SIPs for Tennessee and Arizona. On January 31, 2023, the EPA issued final disapproval of the 19 SIPs proposed in April 2022, setting the stage to include those states in the federal implementation plan described under the Cross-State Air Pollution Rule. Separately, on March 28, 2022, the EPA proposed determinations as to whether certain areas have achieved levels of ground-level ozone pollution that meet the 2008 and 2015 ozone NAAQS. Relevant to Registrants, the Southern Wasatch Front in Utah and Yuma, Arizona are proposed to have met the 2015 ozone standard; and the Cincinnati area of Ohio and Kentucky and the Northern Wasatch Front in Utah are proposed to have not met the 2015 ozone standard and to be reclassified as Moderate Non-Attainment, and have until August 3, 2024 to meet the standard. Until the EPA takes final action on the proposal and the affected states submit any required SIPs, the relevant Registrants cannot determine the impacts of the proposed rule.

On February 7, 2024, the EPA released final standards for fine particulate matter, PM2.5. The EPA strengthened the primary, health-based annual PM2.5 standard from 12 micrograms per cubic meter to 9 micrograms per cubic meter. The standards were last updated in 2012. Most PM2.5 particles form in the atmosphere as a result of chemical reactions of substances, such as sulfur dioxide and nitrogen oxides, that are emitted from power plants, industrial sources and automobiles. National ambient air quality standards are implemented through compliance plans submitted by states and tribes that are then approved by the EPA. The EPA stated that 119 counties in the 48 contiguous states do not meet the revised standard but predicted that that number would be reduced to 52 counties by 2032, the earliest year by which a compliance requirement is anticipated. 23 of these 52 counties are located in California. There are no immediate impacts on the relevant Registrants. Until additional rulemaking and litigation is exhausted, the relevant Registrants cannot determine the full impacts of the revised standard.

64

Cross-State Air Pollution Rule

The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate matter, from down-wind sources in the eastern U.S. to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate transport of SO2 and NOx emissions in 27 Eastern and Midwestern states. In March 2022, the EPA released its Good Neighbor Rule, which contains proposed revisions to the CSAPR framework and is intended to address ozone transport for the 2015 ozone NAAQS. In March 2023, the EPA released the final Good Neighbor Rule. The electric generation sector remains the key industry regulated by the rule and will be subject to emissions allowance trading beginning in summer 2023. The final rule shifted the maximum daily backstop rate for coal-fueled generating units, which drives the installation of new controls or curtailment, to take effect in 2030 instead of 2027. PacifiCorp's Hunter Units 1-3 and Huntington Units 1-2, which do not have SCR controls, are impacted by the rule. PacifiCorp's 2023 IRP selected the installation of SNCR on the Hunter and Huntington Units by 2026 as part of the preferred portfolio. The level of NOx allowances for the Utah units remains similar to 2021 levels, with significant reductions for the coal units beginning in 2026. The daily limit, which takes effect in 2030, will further restrict operation of coal-fueled units without SCR. NV Energy's fossil-fueled units are also covered by the final rule. North Valmy Units 1 and 2, which do not have SCR, will require additional controls or reduced operations during the ozone season if operated beyond 2025. Nevada's regional haze SIP has an enforceable retirement date for North Valmy Units 1 and 2 of December 31, 2028, and NV Energy's IRP identified a December 31, 2025, retirement date for the units and is seeking a request of approval from the PUCN to convert the existing coal-fueled generating facility at the North Valmy Generating Station to a cleaner natural gas-fueled generating facility. The EPA's updated modeling suggests that Arizona, Iowa and Kansas may be significantly contributing to nonattainment in downwind states. The EPA intends to undertake additional assessment of its modeling for these states and will determine if it is necessary to address obligations for these states in future actions. The EPA also deferred final action for Wyoming, pending further review of updated air quality and contribution modeling and analysis. Additional notice and comment rulemaking, such as a supplemental rule, would be required to rescind Iowa's approved SIP and incorporate additional states into the program. The states of Nevada, Utah and Wyoming challenged the EPA's denials and deferral, respectively, of their interstate ozone transport SIPs in the Ninth, Tenth and D.C. Circuit. PacifiCorp also filed petitions with the court opposing the EPA's action in Utah and Wyoming. At the time of filing, at least 11 other states have challenged the EPA's action to disapprove SIPs in seven different regional federal courts of appeal. Stays have been granted by six circuit courts for SIP disapprovals in 12 states. Relevant to Registrants, the states of Nevada, Texas and Utah were granted stays. The final Good Neighbor Rule was published June 5, 2023 and took effect August 4, 2023. The EPA issued several interim final rules stating that the federal rule will not take effect in states in which the SIP disapprovals have been deferred or stayed. In addition to litigation over SIP disapprovals, there are numerous appeals of the final Good Neighbor Rule pending in four different circuit courts, and at least four motions to stay the final rule have been filed in four different circuit courts. On September 25, 2023, the D.C. Circuit denied the motion to stay the Good Neighbor Rule filed by several state and industry parties. The denial means that states that do not have stays on their SIP disapprovals are subject to the Good Neighbor Rule. The states of Ohio, Indiana and West Virginia filed a request for stay of the Good Neighbor Rule with the U.S. Supreme Court on October 13, 2023. Several industry groups representing utilities as well as pipeline, paper, cement and other industries affected by the rule filed supportive requests for stay on the same day. The U.S. Supreme Court will hear oral arguments on the emergency stay requests February 21, 2024. Until additional rulemaking is completed and litigation is exhausted, the potential impacts to the relevant Registrants cannot be determined.

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

65

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

Regional Haze

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

In June 2019, the state of Utah incorporated a BART alternative into its SIP for regional haze planning period one. The BART alternative makes the shutdown of PacifiCorp's Carbon generating facility enforceable under the SIP and removes the requirement to install SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA approved the SIP revision with the BART alternative in October 2020. The EPA's actions also withdrew a prior FIP that required installation of SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. On January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. The EPA defended the SIP, and PacifiCorp and the state of Utah intervened in the litigation in support of the EPA. Oral arguments in HEAL Utah v. EPA were held March 21, 2023. On August 14, 2023, the Tenth Circuit denied the petition to vacate Utah's first planning period regional haze plan.

66

The state of Wyoming issued two regional haze SIPs requiring the installation of SO2, NOx and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the SO2 SIP in December 2012 and the EPA's approval was upheld on appeal by the Tenth Circuit in October 2014. The EPA's final action on the Wyoming SIP in 2014 approved the state's plan to have PacifiCorp install low-NOx burners at Naughton Units 1 and 2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units 1 through 4 between 2015 and 2022, and low-NOx burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility, requiring the installation of SCR controls by 2019. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming and several environmental groups also filed an appeal of the EPA's final action. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit in the appeal. The parties worked to mediate claims under the Wyoming regional haze requirements until the abatement on litigation was lifted in September 2022. On August 15, 2023, the Tenth Circuit ruled in favor of Wyoming and remanded the Wyodak portion of Wyoming's state plan to EPA for further review, with instructions to give appropriate deference to the state's determinations. For Naughton Units 1 and 2, the court determined the EPA properly approved Wyoming's Naughton determination and denied environmental groups' petition. Separately, on February 14, 2022, the First Judicial District Court for the State of Wyoming entered a consent decree reached between the state of Wyoming and PacifiCorp resolving claims of threatened violations of the Clean Air Act, the Wyoming Environmental Quality Act and the Wyoming Air Quality Standards and Regulations at the Jim Bridger facility. No penalties were imposed under the consent decree. Consistent with the terms and conditions of the consent decree, PacifiCorp must convert Jim Bridger Units 1 and 2 to natural gas and begin meeting emissions limits consistent with that conversion by January 1, 2024. The EPA and PacifiCorp executed an administrative order on consent June 9, 2022, covering compliance for Jim Bridger Units 1 and 2 under the regional haze rule. The federal order contains the same emission and operating limits as the Wyoming consent decree and adds federal approval of the compliance pathway outlined in the state consent decree, including revision of the SIP to include conversion of Jim Bridger Units 1 and 2 to natural gas. The order includes a one-year deadline to complete the SIP revision. On December 30, 2022, the Wyoming Air Quality Division submitted the state-approved revised regional haze SIP requiring natural gas conversion of Jim Bridger Units 1 and 2 to the EPA for approval. The plan revision replaces a previous requirement for selective catalytic reduction at the units. The Wyoming Air Quality Division also issued an air permit for the natural gas conversion of Jim Bridger Units 1 and 2 on December 28, 2022. PacifiCorp submitted a notice of compliance to the EPA on March 9, 2023, to certify completion of the Jim Bridger administrative compliance order requirements through compliance with the Wyoming consent decree and Wyoming's revised SIP submission. PacifiCorp remains subject to the compliance terms of the Wyoming consent decree as it works to convert Jim Bridger Units 1 and 2 to natural gas. The EPA is in on-going discussions with Wyoming to finalize a determination on the SIP revisions for Jim Bridger Units 1 and 2, with a decision anticipated by spring 2024.

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

67

Nevada, Utah and Wyoming each submitted regional haze SIPs for the regional haze second planning period to the EPA and received completeness determinations in August 2022. The EPA has not yet made determinations on these plans. It was required to make final determinations on the SIPs by August 2023. On August 25, 2022, the EPA promulgated a finding of failure to submit a SIP for the regional haze second planning period for 15 states, including Iowa. The finding establishes a two-year deadline for the agency to promulgate FIPs to address the requirements, unless prior to promulgating a FIP, the state submits, and the agency approves, a SIP meeting the requirements. The finding says the agency intends to continue to work with states in developing approvable SIP submittals in a timely manner. The Iowa Department of Natural Resources continues to work with the EPA on development of its SIP. Iowa issued a SIP in August 2023 that requires operational improvements to existing control equipment at MidAmerican Energy Company's Louisa Generation Station and Walter Scott Jr. Energy Center - Unit 3. Iowa submitted that plan to the EPA in fall 2023, where review is pending. In August 2023, the Nevada Utilities filed a Joint Application for approval of the Fifth Amendment to the 2021 Joint Integrated Resource Plan. The Fifth Amendment seeks, in part, to convert the existing coal-fueled North Valmy Generating Station to natural gas and to continue operation of Tracy units 4 and 5 to 2049. Based in this filing, the state of Nevada partially withdrew portions of the State Implementation plan for Regional Haze to re-evaluate emission control measures that may be necessary to achieve reasonable progress during the second implementation period of the Regional Haze Rule in Nevada. That review is ongoing at the time of filing.

The states of Utah and Wyoming filed deadline suits in the Utah and Wyoming federal district courts in October and November of 2023, asking the court to require EPA to perform its statutory duty to approve or disapprove the states' regional haze second planning period SIPs. PacifiCorp also filed a deadline suit in both courts. Three environmental groups filed similar deadline suits in the federal district court in Washington, D.C. for seven different states on June 15, 2023, The environmental groups amended their lawsuit on November 10, 2023, after Wyoming and PacifiCorp's suits were filed, to include Utah's and Wyoming's state plans. PacifiCorp has intervened in the D.C. district court case and asked that court to stay the Utah and Wyoming cases in that court while they proceed in the relevant state courts. The EPA is consulting with all groups on appropriate deadlines for agency action on specific state SIPs as the cases move forward in separate courts. As parties in the deadline suits the states and PacifiCorp will be included in settlement discussions and court oversight of the EPA's review of the Utah and Wyoming SIPs. Until the cases are settled and additional rulemaking is completed by the EPA, any potential impacts to the relevant Registrants cannot be determined.

Climate Change

In December 2015, an international agreement was negotiated by 195 nations to create a universal framework for coordinated action on climate change in what is referred to as the Paris Agreement. The Paris Agreement reaffirms the goal of limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius and reaching a global peak of GHG emissions as soon as possible to achieve climate neutrality by mid-century; establishes commitments by all parties to make nationally determined contributions and pursue domestic measures aimed at achieving the commitments; commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the U.S. agreed to reduce GHG emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global GHG emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016; however, the U.S. completed its withdrawal from the Paris Agreement on November 4, 2020. President Biden accepted the terms of the climate agreement on January 20, 2021, and the U.S. completed its reentry February 19, 2021. New commitments to the Paris Agreement were announced in April 2021, with the U.S. pledging to cut its overall GHG emissions 50% to 52% from 2005 levels by 2030 and to reach 100% carbon pollution-free electricity by 2035. Increasingly, states are adopting legislation and regulations to reduce GHG emissions, and local governments and consumers are seeking increasing amounts of clean and renewable energy.

68

Federal Greenhouse Gas Standards

Performance Standards for New and Existing Generating Facilities

In June 2014, the EPA released proposed regulations to address GHG emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on the "best system of emission reduction." In August 2015, the final Clean Power Plan was released, which established the best system of emission reduction as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The Clean Power Plan was stayed by the U.S. Supreme Court in February 2016 while litigation proceeded. On June 19, 2019, the EPA repealed the Clean Power Plan and issued the Affordable Clean Energy rule. In the Affordable Clean Energy rule, the EPA determined that the best system of emission reduction for existing coal-fueled generating facilities is limited to actions that can be taken at a point source facility, specifically heat rate improvements and identified a set of candidate technologies and measures that could improve heat rates. Measures taken to meet the standards of performance must be achieved at the source itself. The Affordable Clean Energy rule was challenged by environmental and health groups in the D.C. Circuit. On January 19, 2021, the D.C. Circuit vacated and remanded the Affordable Clean Energy rule to the EPA, finding that the rule "rested critically on a mistaken reading of the Clean Air Act" that limited the best system of emission reduction to actions taken at a facility. In October 2021, the U.S. Supreme Court agreed to hear an appeal of that decision. Arguments in the case were held February 28, 2022, and on June 30, 2022, the U.S. Supreme Court issued its decision regarding the scope of the EPA's authority to regulate greenhouse gas emissions under the Clean Air Act. The U.S. Supreme Court held that the "generation shifting" approach in the Clean Power Plan exceeded the powers granted to the EPA by Congress, although the court did not address whether the EPA may only adopt measures applied at the individual source as it did in the Affordable Clean Energy rule. A key area where the EPA went astray was using the Clean Power Plan to give states the option to promulgate regulations that would encourage "generation shifting," or moving away from higher-polluting power sources like coal to lower-polluting sources like natural gas or renewables. The U.S. Supreme Court found that type of regulation, which would impact larger economic forces beyond the fence lines of individual generating facilities, is not permitted under Section 111(d) of the Clean Air Act. The U.S. Supreme Court reversed the D.C. Circuit's vacatur of the Affordable Clean Energy rule and remanded the case for further proceedings. In May 2023, the EPA proposed rules addressing greenhouse gas emissions from new and reconstructed natural gas-fueled combustion turbines (Clean Air Act Section 111(b) rule) and existing coal- and gas- or oil-fueled steam units and natural gas-fueled combustion turbines (Clean Air Act Section 111(d) rule). The proposed requirements for existing units would take effect January 1, 2030, through state implementation plans. Requirements for new combustion turbines are subcategorized based on capacity factor, where low-load units would be required to meet an emissions limit, intermediate-load units would be required to use a blend of low-emitting hydrogen and natural gas and base-load units would be required to utilize carbon capture and sequestration technology or a high-percentage blend of low-emitting hydrogen. Requirements for existing gas- and oil-fueled steam units are also subcategorized based on capacity factor, where low-load units would be subject to routine maintenance to demonstrate no increase in emissions, intermediate-load units would be subject to an emission limit of 1,500 pounds of CO2 / MWh-gross and base-load units would be subject to an emission limit of 1,300 pounds of CO2 / MWh-gross. Control equipment requirements for existing combustion turbines only apply to large, high load turbines that are greater than 300MW in capacity and operate at a greater than 50% capacity factor. These units would be required to begin utilizing carbon capture and sequestration with a 90% capture rate by 2035 or use a blend of low-emitting hydrogen starting in 2032. Requirements for existing coal-fueled units are subcategorized based on retirement date. Units with earlier retirement dates would be subject to less stringent requirements while units that commit to later retirement dates would be subject to annual capacity factor limits or natural gas co-firing requirements. Units that will continue operating after December 31, 2039, would be required to utilize carbon capture and sequestration with a 90% carbon capture rate. Clean Air Act Section 111 establishes a cooperative approach between the EPA and the states. The EPA establishes nationwide standards based on the best system of emissions reductions it identifies for a source category. States are then expected to develop plans to implement those standards at affected units. States may adopt the EPA's standards or develop state-specific standards that achieve the same air quality results. The EPA accepted comments on the proposal through August 8, 2023. In November 2023, the EPA issued a supplement to the proposed rule, seeking comment on impacts to small businesses and whether to include options to address potential reliability issues. The EPA accepted comment on the supplemental proposal through December 20, 2023. The EPA has indicated it intends to finalize the rules by April 2024. The relevant Registrants operate facilities that may be affected by these proposals. Until the EPA takes final action on the proposals, the states submit any required SIPs and litigation is exhausted, the relevant Registrants cannot determine the impacts of the proposed rule.

69

New Source Performance Standards for Methane Emissions

In August 2020, the EPA finalized regulations to rescind standards for methane emissions from the oil and gas sector. The changes eliminate requirements to regulate methane emissions from the production, processing, transmission and storage of oil and gas. The rule was immediately challenged by environmental and tribal groups, as well as numerous states. In January 2021, the D.C. Circuit lifted an administrative stay and allowed the rule to take effect, finding that groups challenging the rule had not met the standard for a long-term stay. On June 30, 2021, President Biden signed into law a joint resolution of Congress, adopted under the Congressional Review Act, disapproving the August 2020 rule. The resolution reinstated the 2012 volatile organic compounds standards and the 2016 volatile organic compounds and methane standards for the oil and natural gas transmission and storage segments, as well as the methane standards for the production and processing segments of the oil and gas sector. On November 2, 2021, the EPA proposed rules that would reduce methane emissions from both new and existing sources in the oil and natural gas industry. The proposals would expand and strengthen emission reduction requirements for new, modified and reconstructed oil and natural gas sources and would require states to reduce methane emissions from existing sources nationwide. The EPA took comment on the proposed rules through January 31, 2022. The EPA issued a supplemental proposal in November 2022 to further strengthen emission reduction requirements. The EPA issued the final rule in December 2023, establishing emissions standards and leak detection and repair requirements for a number of components across the natural gas system. Kern River is not affected by the rule. Northern Natural Gas and BHE GT&S are affected by the rule and anticipate replacing some pneumatic controls and seals at centrifugal and reciprocating compressors. Additional leak detection and repair surveys and reports are also anticipated. In January 2024, the EPA proposed the methane fee rule, which is required under the Inflation Reduction Act. The fee, called a waste emissions charge, will be assessed on natural gas facilities that are subject to Greenhouse Gas Reporting Program Subpart W reporting. For transmission and storage operations, any facility that reports methane emissions over the congressionally-determined "0.11% of the methane sent to sale from or through such facility" will pay a fee to the federal government. The fee can be reduced by the netting of emissions, or altogether eliminated by certain statutory exemptions. The amount of the fee is scaled, beginning at $900 per metric ton of methane over the 0.11% threshold beginning in 2025 and increasing to $1500 per metric ton of methane over the 0.11% threshold in 2027. The relevant Registrants do not expect significant impacts from the proposed fee rule due to the combination of the excess emissions threshold, netting allowance and compliance with the methane emissions standards rule. The EPA is accepting comments on the proposed fee rule through March 11, 2024. Until the EPA takes final action on the proposal, the full impacts of the rule cannot be determined.

Water Quality Standards

The Clean Water Act establishes the framework for maintaining and improving water quality in the U.S. through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. After significant litigation, the EPA released a proposed rule under §316(b) of the Clean Water Act to regulate cooling water intakes at existing facilities. The final rule was released in May 2014 and became effective in October 2014. Under the final rule, existing facilities that withdraw at least 25% of their water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day are required to reduce fish impingement (i.e., when fish and other aquatic organisms are trapped against screens when water is drawn into a facility's cooling system) by choosing one of seven options. Facilities that withdraw at least 125 million gallons of water per day from waters of the U.S. must also conduct studies to help their permitting authority determine what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms (i.e., when organisms are drawn into the facility). PacifiCorp's Dave Johnston generating facility and all of MidAmerican Energy's coal-fueled generating facilities, except Louisa, Ottumwa and Walter Scott, Jr. Unit 4, which have water cooling towers, withdraw more than 125 million gallons per day of water from waters of the U.S. for once-through cooling applications. PacifiCorp's Jim Bridger, Naughton, Gadsby, Hunter and Huntington generating facilities currently utilize closed cycle cooling towers but are designed to withdraw more than two million gallons of water per day. If PacifiCorp's or MidAmerican Energy's existing intake structures require modification, the costs are not anticipated to be significant to the consolidated financial statements. Nevada Power and Sierra Pacific are not impacted by the §316(b) final rule since they do not utilize once-through cooling water intake or discharge structures at any of their generating facilities.

70

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

In March 2023, the latest changes to the definition of "waters of the U.S.," a rule that determines which waters are regulated under the federal Clean Water Act, took effect. Under this rule, tributaries, many wetlands, intrastate lakes, intrastate ponds, intrastate streams and some impoundments must meet either test from the 2006 Rapanos plurality decision to be considered a water of the U.S. That is, a water must be relatively permanent and have a continuous surface connection to an included waterbody (the "relatively permanent" test) or it must significantly affect the biological, physical or chemical integrity of a traditional navigable water, territorial seas or interstate waters (the "significant nexus" test). The rule was challenged in multiple courts. On May 23, 2023, the U.S. Supreme Court issued a decision in Sackett v. EPA, a case that challenged the Clean Water Act's applicability to certain wetlands. In its decision, the U.S. Supreme Court significantly narrowed protections for wetlands and intermittent streams under the federal Clean Water Act. The U.S. Supreme Court unanimously rejected the significant nexus test as unworkable. A divided U.S. Supreme Court determined that jurisdiction applies to waters that are adjacent to traditional interstate navigable waters and that have a continuous surface connection with that traditional interstate navigable waters. In light of the Sackett decision, the EPA secured stays of litigation over its definitional rule in two of three pending challenges in order to conduct rulemaking to conform to the U.S. Supreme Court's decision. On September 8, 2023, the EPA issued a new rule conforming to the U.S. Supreme Court's decision.

Coal Ash Disposal

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

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

71

Multiple parties filed challenges over various aspects of the final rule in the D.C. Circuit, resulting in settlement of some of the issues and subsequent regulatory action by the EPA. The EPA finalized the first phase of the CCR rule amendments in July 2018 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater performance standards for certain constituents, the EPA extended the deadline by which facilities must initiate closure of unlined ash ponds exceeding a groundwater protection standard and impoundments that do not meet the rule's aquifer location restrictions to October 31, 2020. Following submittal of competing motions from environmental groups and the EPA to stay or remand this deadline extension, on March 13, 2019, the D.C. Circuit granted the EPA's request to remand the rule and left the October 31, 2020 deadline in place while the agency undertakes a new rulemaking establishing a new deadline for initiating closure. On August 14, 2019, the EPA released its "Phase 2" proposal, which contains targeted amendments to the CCR rule in response to court remands and EPA settlement agreements, as well as issues raised in a rulemaking petition. The Phase 2 rule has not been finalized. In February 2020, the EPA proposed a federal CCR permit program as required by the WIIN Act of 2016. The federal permit rule has not been finalized. In October 2020, the EPA released an advanced notice of proposed rulemaking on legacy CCR surface impoundments, seeking comment on and information related to issues relevant to development of regulations for legacy impoundments. On May 18, 2023, the EPA proposed the legacy surface impoundments rule and accepted comment on the proposal through July 17, 2023. The proposal encompasses legacy surface impoundments, which are inactive surface impoundments at inactive facilities; and CCR management units ("CCRMU"), which include CCR surface impoundments and landfills that closed prior to October 19, 2015, inactive CCR landfills, and other areas where CCR has been or is managed directly on the land. CCRMUs include all units meeting that definition at active CCR facilities, as well as those at inactive facilities with one or more legacy surface impoundment. EPA proposes the impose substantially the same regulatory obligations for both legacy surface impoundments and CCRMUs as are applicable to currently regulated units, including groundwater monitoring and corrective action. All legacy surface impoundments and CCRMUs would be required to initiate closure, including reclosure, within one year after the rule is finalized. The EPA has indicated it intends to finalize the legacy surface impoundment rule by spring 2024.

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

The EPA published a Notice of Data Availability on November 14, 2023, in support of its proposed legacy impoundments rule. The notice sought information on two specific pieces of information: (1) an updated list of legacy impoundments and CCRMUs, based on information received during the comment period for the proposed rule; and (2) a risk assessment for legacy impoundments and CCRMUs. The EPA included lists of potential legacy surface impoundments and CCRMUs in the rulemaking docket and those lists included several Berkshire Hathaway Energy facilities. Berkshire Hathaway Energy identified a number of errors and inaccuracies in those lists in comments submitted December 11, 2023.

In August 2020, the EPA finalized its Holistic Approach to Closure: Part A rule ("Part A rule"). This proposal addressed the D.C. Circuit's revocation of the provisions that allow unlined impoundments to continue receiving ash. The Part A rule established a new deadline of April 11, 2021, by which all unlined surface impoundments must initiate closure. The Part A rule also identifies two extensions to that date: (1) a site-specific extension to develop alternate disposal capacity and initiate closure by October 15, 2023; and (2) a site-specific extension for facilities that agree to shut down the coal-fueled unit and complete ash pond closure activities by October 17, 2028. PacifiCorp developed a demonstration for the development of alternative capacity for the Jim Bridger facility's FGD Pond 2 and a demonstration for closure of the Naughton generating facility and ash pond and submitted them to the EPA in November 2020. On January 11, 2022, the EPA deemed these submittals complete but has not taken additional action on them. No other Registrants used the provisions of the Part A rule. On October 12, 2023, Jim Bridger FGD Pond 2 ceased receiving waste and the newly constructed FGD Pond 3 came into service. The EPA was notified on October 12, 2023, of PacifiCorp's withdrawal of its pending Part A alternative storage capacity demonstration request.

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

72

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

Other

Other laws, regulations and agencies to which the relevant Registrants are subject include, but are not limited to:

•The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental remediation costs. Certain Registrants have been identified as potentially responsible parties in connection with certain disposal sites. The relevant Registrants have completed several cleanup actions and are participating in ongoing investigations and remedial actions. Costs associated with these actions are not expected to be material and are expected to be found prudent and included in rates.

•The Nuclear Waste Policy Act of 1982, under which the DOE is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Refer to Note 14 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 11 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K for additional information regarding MidAmerican Energy's nuclear decommissioning obligations.

•The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of PacifiCorp's mining activities.

•The FERC evaluates hydroelectric systems to ensure environmental impacts are minimized, including the issuance of environmental impact statements for licensed projects both initially and upon relicensing. The FERC monitors the hydroelectric facilities for compliance with the license terms and conditions, which include environmental provisions. Refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for information regarding PacifiCorp's Klamath River hydroelectric system.

The Registrants expect they will be allowed to recover their respective prudently incurred costs to comply with the environmental laws and regulations discussed above. The Registrants' planning efforts take into consideration the complexity of balancing factors such as: (a) pending environmental regulations and requirements to reduce emissions, address waste disposal, ensure water quality and protect wildlife; (b) avoidance of excessive reliance on any one generation technology; (c) costs and trade-offs of various resource options including energy efficiency, demand response programs and renewable generation; (d) state-specific energy policies, resource preferences and economic development efforts; (e) additional transmission investment to reduce power costs and increase efficiency and reliability of the integrated transmission system; and (f) keeping rates affordable. Due to the number of generating units impacted by environmental regulations, deferring installation of compliance-related projects is often not feasible or cost effective and places the Registrants at risk of not having access to necessary capital, material, and labor while attempting to perform major equipment installations in a compressed timeframe concurrent with other utilities across the country. Therefore, the Registrants have established installation schedules with permitting agencies that coordinate compliance timeframes with construction and tie-in of major environmental compliance projects as units are scheduled off-line for planned maintenance outages; these coordinated efforts help reduce costs associated with replacement power and maintain system reliability.

73

Item 1A.    Risk Factors

Each Registrant is subject to numerous risks and uncertainties, including, but not limited to, those described below. Careful consideration of these risks, together with all of the other information included in this Form 10-K and the other public information filed by the relevant Registrant, should be made before making an investment decision. Additional risks and uncertainties not presently known or which each Registrant currently deems immaterial may also impair its business operations. Unless stated otherwise, the risks described below generally relate to each Registrant.

Liquidity, Capital Requirements and Corporate Structure Risks

BHE is a holding company and depends on distributions from subsidiaries, including joint ventures, to meet its obligations.

BHE is a holding company with no material assets other than the ownership interests in its subsidiaries and joint ventures, collectively referred to as its subsidiaries. Accordingly, cash flows and the ability to meet BHE's obligations are largely dependent upon the earnings of its subsidiaries and the payment of such earnings to BHE in the form of dividends or other distributions. As a result of material wildfire litigation at PacifiCorp, no dividends will be paid to BHE by PacifiCorp over the next several years, which could impact BHE's ability to fund its operations, make interest payments, fund debt maturities and increase BHE's reliance on debt.

BHE's subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay amounts due pursuant to BHE's senior debt, junior subordinated debt or its other obligations, or to make funds available, whether by dividends or other payments, for the payment of amounts due pursuant to BHE's senior debt, junior subordinated debt or its other obligations, and do not guarantee the payment of any of its obligations. Distributions from subsidiaries may also be limited by:

•PacifiCorp's liquidity concerns resulting from wildfire litigation (described below);

•their respective earnings, capital requirements, and required debt and preferred stock payments;

•the satisfaction of certain terms contained in financing, ring-fencing or organizational documents; and

•regulatory restrictions that limit the ability of BHE's regulated utility subsidiaries to distribute profits.

BHE is substantially leveraged, the terms of its existing senior and junior subordinated debt do not restrict the incurrence of additional debt by BHE or its subsidiaries, and BHE's senior debt is structurally subordinated to the debt of its subsidiaries, and each of such factors could adversely affect BHE's consolidated financial results.

A significant portion of BHE's capital structure is comprised of debt, and BHE expects to incur additional debt in the future to fund items such as, among others, acquisitions, capital investments and the development and construction of new or expanded facilities. As of December 31, 2023, BHE had the following outstanding obligations:

•senior unsecured debt of $13.1 billion;

•junior subordinated debentures of $100 million;

•guarantees and letters of credit in respect of subsidiaries, equity method investments and other related parties aggregating $2.6 billion; and

BHE's consolidated subsidiaries also have significant amounts of outstanding debt, which totaled $41.2 billion as of December 31, 2023. These amounts exclude (a) trade debt, (b) preferred stock obligations, (c) letters of credit in respect of subsidiary debt, and (d) BHE's share of the outstanding debt of its own or its subsidiaries' equity method investments.

Given BHE's substantial leverage, it may not have sufficient cash to service its debt, which could limit its ability to finance future acquisitions, develop and construct additional projects, or operate successfully under difficult conditions, including those brought on by adverse national and global economies, unfavorable financial markets or growth conditions where its capital needs may exceed its ability to fund them. BHE's leverage could also impair its credit quality or the credit quality of its subsidiaries, making it more difficult to finance operations or issue future debt on favorable terms, and could result in a downgrade in debt ratings by credit rating agencies.

The terms of BHE's and its subsidiaries' debt do not limit BHE's ability or the ability of its subsidiaries to incur additional debt or issue preferred stock. Accordingly, BHE or its subsidiaries could enter into acquisitions, new financings, refinancings, recapitalizations, leases or other highly leveraged transactions that could significantly increase BHE's or its subsidiaries' total

74

amount of outstanding debt. The interest payments needed to service this increased level of debt could adversely affect BHE's or its subsidiaries' financial results. Many of BHE's subsidiaries' debt agreements contain covenants, or may in the future contain covenants, that restrict or limit, among other things, such subsidiaries' ability to create liens, sell assets, make certain distributions, incur additional debt or miss contractual deadlines or requirements, and BHE's ability to comply with these covenants may be affected by events beyond its control. Further, if an event of default accelerates a repayment obligation and such acceleration results in an event of default under some or all of BHE's other debt, BHE may not have sufficient funds to repay all of the accelerated debt simultaneously, and the other risks described under "Corporate and Financial Structure Risks" may be magnified as well.

Because BHE is a holding company, the claims of its senior debt holders are structurally subordinated with respect to the assets and earnings of its subsidiaries. Therefore, the rights of its creditors to participate in the assets of any subsidiary in the event of a liquidation or reorganization are subject to the prior claims of the subsidiary's creditors and preferred shareholders, if any. In the event of default due to the bankruptcy, insolvency, or reorganization of a significant subsidiary, all of BHE's debt will become immediately due. In addition, pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties in the state of Nevada, AltaLink's transmission properties, the equity interest of MidAmerican Funding's subsidiary and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of solar and wind generation projects, are directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of BHE's debt.

A downgrade in BHE's credit ratings or the credit ratings of its subsidiaries, including the Subsidiary Registrants, could negatively affect BHE's or its subsidiaries' access to capital, increase the cost of borrowing or raise energy transaction credit support requirements and PacifiCorp's credit rating has been downgraded as a result of wildfire litigation related risks.

BHE's senior unsecured debt and its subsidiaries' long-term debt, including the Subsidiary Registrants, are rated by various rating agencies. BHE cannot give assurance that its senior unsecured debt rating or any of its subsidiaries' long-term debt ratings will not be reduced in the future. Although none of the Registrants' outstanding debt has rating-downgrade triggers that would accelerate a repayment obligation, a credit rating downgrade would increase any such Registrant's borrowing costs and commitment fees on its revolving credit agreements and other financing arrangements, perhaps significantly. In addition, such Registrant would likely be required to pay a higher interest rate in future financings, the potential pool of investors would likely decrease and depending on the rating, require some investors to sell the Registrants' bonds. Further, access to the commercial paper market could be significantly limited, resulting in higher interest costs.

Similarly, any downgrade, change in rating methodology impacting subsidiaries credit rating, placement on negative outlook or credit watch or other event negatively affecting the credit ratings of BHE's subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could cause BHE to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing its and its subsidiaries' liquidity and borrowing capacity; however BHE is not obligated to provide liquidity to its subsidiaries.

Most of the Registrants' large wholesale customers, suppliers and counterparties require such Registrant to have sufficient creditworthiness in order to enter into transactions, particularly in the wholesale energy markets. If the credit ratings of a Registrant were to decline, especially below investment grade, the relevant Registrant's financing costs and borrowings would likely increase because certain counterparties may require collateral in the form of cash, a letter of credit or some other form of security for existing transactions and as a condition to entering into future transactions with such Registrant. Amounts could be material and could adversely affect such Registrant's liquidity and cash flows.

Refer to "PacifiCorp Wildfire Litigation Risks" section below for additional information regarding PacifiCorp.

Disruptions in the financial markets could affect each Registrant's ability to obtain debt financing or to draw upon or renew existing credit facilities and have other adverse effects on each Registrant.

Disruptions in the financial markets could affect each Registrant's ability to obtain debt financing or to draw upon or renew existing credit facilities and have other adverse effects on each Registrant. Significant dislocations and liquidity disruptions in the U.S., Great Britain, Canada and global credit markets, such as those that occurred in 2008, 2009 and 2020, may materially impact liquidity in the bank and debt capital markets, making financing terms less attractive for borrowers that are able to find financing and, in other cases, may cause certain types of debt financing, or any financing, to be unavailable. Additionally, economic uncertainty in the U.S. or globally may adversely affect the U.S. credit markets and could negatively impact each Registrant's ability to access funds on favorable terms or at all. If a Registrant is unable to access the bank and debt markets to

75

meet liquidity and capital expenditure needs, it may adversely affect the timing and amount of its capital expenditures, acquisition financing and its financial results.

Poor performance of plan and fund investments and other factors impacting the pension and other postretirement benefit plans and nuclear decommissioning and mine reclamation trust funds could unfavorably impact each Registrant's cash flows, liquidity and financial results.

Costs of providing each Registrant's defined benefit pension and other postretirement benefit plans and costs associated with the joint trustee plan to which PacifiCorp contributes depend upon a number of factors, including the rates of return on plan assets, the level and nature of benefits provided, discount rates, mortality assumptions, the interest rates used to measure required minimum funding levels, the funded status of the plans, changes in benefit design, tax deductibility and funding limits, changes in laws and government regulation and each Registrant's required or voluntary contributions made to the plans. Furthermore, the timing of recognition of unrecognized gains and losses associated with the Registrants' defined benefit pension plans is subject to volatility due to events that may give rise to settlement accounting. Settlement events resulting from lump sum distributions offered by certain of the Registrants' defined benefit pension plans are influenced by the interest rates used to discount a participant's lump sum distribution. When the applicable interest rates are low, lump sum distributions in a given year tend to increase resulting in a higher likelihood of triggering settlement accounting.

If the Registrant's pension or other postretirement benefit plans are in underfunded positions, the respective Registrant may be required to make cash contributions to fund such underfunded plans in the future. Additionally, each Registrant's plans have investments in domestic and foreign equity and debt securities and other investments that are subject to the risk of loss. Losses from investments could add to the volatility, size and timing of future contributions.

Furthermore, the funded status of the UMWA 1974 Pension Plan multiemployer plan to which PacifiCorp's subsidiary previously contributed is considered critical and declining. PacifiCorp's subsidiary involuntarily withdrew from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceased performing work for the subsidiary. PacifiCorp has recorded its best estimate of the withdrawal obligation.

In addition, MidAmerican Energy is required to fund over time the projected costs of decommissioning Quad Cities Station, a nuclear generating facility, and Bridger Coal Company, a joint venture of PacifiCorp's subsidiary, Pacific Minerals, Inc., is required to fund projected mine reclamation costs. The funds that MidAmerican Energy has invested in a nuclear decommissioning trust and a subsidiary of PacifiCorp has invested in a mine reclamation trust are invested in debt and equity securities and poor performance of these investments will reduce the amount of funds available for their intended purpose, which could require MidAmerican Energy or PacifiCorp's subsidiary to make additional cash contributions. As contributions to the trust are being made over the operating life of the respective facility, reductions in the expected operating life of the facility could also require MidAmerican Energy and PacifiCorp's subsidiary to make additional contributions to the related trust. Such cash funding obligations, which are also impacted by the other factors described above, could have a material impact on MidAmerican Energy's or PacifiCorp's liquidity by reducing their available cash. Additionally, PacifiCorp's mine reclamation obligation for Bridger Coal Company is secured by a surety bond. Refer to "PacifiCorp Wildfire Litigation and Insurance Risks" above for additional information regarding the impact of wildfire litigation risks on PacifiCorp's liquidity and ability to obtain security.

BHE's majority shareholder, Berkshire Hathaway, could exercise control over BHE in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors and BHE could exercise control over the Subsidiary Registrants in a manner that would benefit BHE to the detriment of the Subsidiary Registrants' creditors and PacifiCorp's preferred stockholders.

Berkshire Hathaway is majority owner of BHE and has control over all decisions requiring shareholder approval. In circumstances involving a conflict of interest between Berkshire Hathaway and BHE's creditors, Berkshire Hathaway could exercise its control in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors.

BHE indirectly owns all of the common stock of PacifiCorp, Nevada Power, Sierra Pacific and EGTS and the membership interest in Eastern Energy Gas. BHE is also the sole member of MidAmerican Funding and, accordingly, indirectly owns all of MidAmerican Energy's common stock. As a result, BHE has control over all decisions requiring shareholder approval, including the election of directors. In circumstances involving a conflict of interest between BHE and the creditors of the Subsidiary Registrants, BHE could exercise its control in a manner that would benefit BHE to the detriment of the Subsidiary Registrants' creditors.

76

PacifiCorp Wildfire Risks

PacifiCorp's litigation risk associated with the Wildfires is inherently uncertain and the ultimate outcomes of the associated claims could materially and adversely affect PacifiCorp's financial condition and results of operations and its ability to obtain financing, to fund its operations, capital investments and settlements arising from the Wildfires, and to obtain and fund third-party liability insurance coverage.

Litigation

In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damages, personal injuries and loss of life and widespread power outages in Oregon and Northern California (the "2020 Wildfires"). Additionally, a major wildfire began in PacifiCorp's service territory in July 2022 causing private and public property damage, personal injuries, loss of life and power outages in Northern California (the "2022 McKinney Fire"). Together, the 2020 Wildfires and the 2022 McKinney Fire are referred to as "the Wildfires."

A significant number of complaints and demands alleging similar claims related to the 2020 Wildfires have been filed in Oregon and California, including a class action complaint. Additionally, multiple complaints associated with the 2022 McKinney Wildfire have been filed in California. Refer to Item 3. Legal Proceedings, BHE's Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K and PacifiCorp's Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information on the Wildfires. PacifiCorp may be subject to additional complaints and demands (collectively "actions") associated with the Wildfires. Further, the amounts specified in the original filed actions do not limit the amount of damages that ultimately may be awarded in a court proceeding, and therefore PacifiCorp's liability for damages could be substantially greater than the original amounts specified and its estimated losses. For example, plaintiffs frequently are permitted to amend their complaints, such as to seek punitive and additional noneconomic damages.

As described in BHE's Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K and PacifiCorp's Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K, the jury in an initial June 2023 trial related to the 2020 Wildfires (captioned Jeanyne James et al. v. PacifiCorp et al, in Multnomah County Circuit Court, Oregon, and referred to as "James") issued a verdict finding PacifiCorp liable to the 17 individual plaintiffs and making certain findings as to the class with respect to four wildfires. While PacifiCorp disagrees with and has appealed the court's granting of class certification (among other matters), the potential class size, if class certification is not overturned on appeal, could be significant and the liability for damages may be substantially higher than current estimated losses. Additional trials related to the Wildfires, including damages-only reserves for James, are expected and could also result in an increase in current estimated losses. Damages with respect to certain plaintiffs may be significantly higher or lower than with respect to other plaintiffs. PacifiCorp intends to appeal adverse decisions, starting with the James decisions, such that it is possible that a final determination of its liability and damages could take several years. While certain settlements have occurred, PacifiCorp cannot be certain that additional settlements can be achieved on terms it finds reasonable, if at all.

Liquidity

As a result of the litigation risk and estimated losses recorded to date associated with the Wildfires, PacifiCorp's liquidity has been materially impacted and its credit ratings have been downgraded. PacifiCorp could experience further declines in its credit ratings, changes to its ratings methodology, placed on credit watch or outlook negative if additional unfavorable litigation or similar outcomes occur as a result of the Wildfires.

These changes in PacifiCorp's credit ratings have and are expected to continue to have a material impact on PacifiCorp's liquidity and may result in, among other things, PacifiCorp being unable to maintain sufficient levels of cash or to obtain necessary short- and long-term financing to fund its operations and financial obligations, capital investments and potential future settlements associated with the Wildfires. PacifiCorp may be unable to access debt capital markets for an extended period of time in the event of unfavorable jury verdicts, additional declines in PacifiCorp's credit ratings and potential uncertainty around PacifiCorp's ultimate exposure associated with the James class action and future catastrophic wildfires that may occur despite PacifiCorp's wildfire mitigation efforts. PacifiCorp may also be subject to borrowing limitations due to long-term debt covenants and increasing leverage ratios. Furthermore, investors in PacifiCorp's First Mortgage Bonds may be unable to hold existing bonds or to invest in new bonds, and perceived risks associated with the Wildfires may limit PacifiCorp's ability to attract investors. At a minimum, the cost of any short- or long-term financing is expected to be higher as a result of the wildfire litigation risks and decline in PacifiCorp's credit ratings.

In addition to the above-described financing constraints, PacifiCorp may be required to provide additional collateral, letters of credit, adequate assurance, or other forms of security to achieve otherwise routine transactions and at a higher cost than has

77

been experienced in the past. Collateral may be required to be posted in association with commodity contracts with credit-risk-related contingent features or material adverse change clauses.

Refer to Item 7 "Liquidity and Capital Resources" for further information regarding the liquidity impacts arising from the Wildfires.

Insurance

PacifiCorp has experienced material increases in the cost of third-party liability insurance as a result of worsening damage claims in the utility industry associated with catastrophic wildfires in the geographic regions in which PacifiCorp operates. Such costs may continue to increase materially to the point of being prohibitively expensive, and it is possible that PacifiCorp may be unable to obtain third-party liability insurance. Increases in the cost of insurance may be challenged when PacifiCorp seeks cost recovery and such amounts may not be recoverable in customer rates. To the extent third-party liability insurance costs continue to increase, becomes cost prohibitive or is unavailable and such increased costs are not recoverable in customer rates, PacifiCorp's financial condition and results of operations could be materially adversely affected and its liquidity position further negatively impacted.

Regulatory, Legislative and Legal Risks

Each Registrant may be subject to extensive federal, state, local and foreign legislation and regulation, including numerous environmental, health, safety, reliability, data privacy and other laws and regulations that may affect its operations and costs. These laws and regulations are complex, dynamic and subject to new interpretations or change. In addition, new laws and regulations, including, but not limited to, initiatives regarding deregulation and restructuring of the utility industry, are continually being proposed and enacted that may impose new or revised requirements or standards on each Registrant.

Each Registrant is required to comply with numerous federal, state, local or foreign laws and regulations as described in "General Regulation" and "Environmental Laws and Regulations" in Item 1 of this Form 10-K that have broad application to each Registrant and limits the respective Registrant's ability to independently make and implement management decisions regarding, among other items, acquiring businesses; constructing, acquiring, disposing or retiring operating assets; operating and maintaining generating facilities and transmission and distribution system assets; complying with pipeline safety and integrity and environmental requirements; setting rates charged to customers; establishing capital structures and issuing debt or equity securities; managing and reporting transactions between subsidiaries and affiliates; and paying dividends or similar distributions. These laws and regulations, which are followed in developing the Registrants' safety and compliance programs and procedures, are implemented and enforced by federal, state and local regulatory agencies, such as the Occupational Safety and Health Administration, the FERC, the EPA, the DOT, the NRC, the Federal Mine Safety and Health Administration and various state regulatory commissions in the U.S., and by foreign regulatory agencies, such as GEMA, which discharges certain of its powers through its staff within Ofgem, in Great Britain and the AUC in Alberta, Canada.

Compliance with applicable laws and regulations generally requires each Registrant to obtain and comply with a wide variety of licenses, permits, inspections, audits and other approvals. Further, compliance with laws and regulations can require significant capital and operating expenditures, including expenditures for new equipment, inspection, cleanup costs, removal and remediation costs and damages arising out of contaminated properties. Compliance activities pursuant to existing or new laws and regulations could be prohibitively expensive or otherwise uneconomical. As a result, each Registrant could be required to shut down some facilities or materially alter its operations. Further, each Registrant may not be able to obtain or maintain all required environmental or other regulatory approvals and permits for its operating assets or development projects. Delays in, or active opposition by third parties to, obtaining any required environmental or regulatory authorizations or failure to comply with the terms and conditions of the authorizations may increase costs or prevent or delay each Registrant from operating its facilities, developing or favorably locating new facilities or expanding existing facilities. If any Registrant fails to comply with any environmental or other regulatory requirements, such Registrant may be subject to penalties and fines or other sanctions, including changes to the way its electricity generating facilities are operated that may adversely impact generation or how the Pipeline Companies are permitted to operate their systems that may adversely impact throughput. The costs of complying with laws and regulations could adversely affect each Registrant's financial results. Not being able to operate existing facilities or develop new generating facilities to meet customer electricity needs could require such Registrant to increase its purchases of electricity on the wholesale market, which could increase market and price risks and adversely affect such Registrant's financial results.

Existing laws and regulations, while comprehensive, are subject to changes and revisions from ongoing policy initiatives by legislators and regulators and to interpretations that may ultimately be resolved by the courts. For example, changes in laws and regulations could result in, but are not limited to, increased competition and decreased revenue within each Registrant's service

78

territories; new environmental or climate-related requirements, including the implementation of or changes to the Affordable Clean Energy rule, RPS and GHG emissions reduction goals; the issuance of new or stricter air quality standards; the implementation of energy efficiency mandates; the issuance of regulations governing the management and disposal of coal combustion byproducts; changes in forecasting requirements; changes to each Registrant's service territories as a result of condemnation or takeover by municipalities or other governmental entities, particularly where it lacks the exclusive right to serve its customers; the inability of each Registrant to recover its costs on a timely basis, if at all; new pipeline safety requirements; or a negative impact on each Registrant's current cost recovery arrangements. In addition to changes in existing legislation and regulation, new laws and regulations are likely to be enacted from time to time that impose additional or new requirements or standards on each Registrant. For example, in April 2022, the EPA proposed the "Cross-State Ozone Transport Rule", which contains requirements intended to address ozone transport between states through federally required nitrogen oxide reductions from fossil-fuel generating facilities. The rule included Wyoming, Utah and Nevada for the first time. If finalized as proposed, the rule will have impacts on PacifiCorp's coal-fueled generating facilities in both Utah and Wyoming that do not have an SCR as early as 2026 and threatens early coal-fueled unit retirements and reliability impacts. PacifiCorp has engaged with state and federal agencies to make adjustments to the rule and mitigate potential reliability impacts. Adverse rulings in GHG-related cases could result in increased or changed regulations and could increase costs for GHG emitters, including the Registrants' generating facilities. The GHG rules, changes to those rules, and the Registrants' compliance requirements are subject to potential outcomes from proceedings and litigation challenging the rules.

New federal, regional, state and international accords, legislation, regulation, or judicial proceedings limiting GHG emissions could have a material adverse impact on the Registrants, the U.S. and the global economy. Companies and industries with higher GHG emissions, such as utilities with significant coal-fueled generating facilities, will be subject to more direct impacts and greater financial and regulatory risks. The impact is dependent on numerous factors, none of which can be meaningfully quantified at this time. These factors include, but are not limited to, the magnitude and timing of GHG emissions reduction requirements; the design of the requirements; the cost, availability and effectiveness of emissions control technology; the price, distribution method and availability of offsets and allowances used for compliance; government-imposed compliance costs; and the existence and nature of incremental cost recovery mechanisms. Examples of how new requirements may impact the Registrants include:

•Additional costs may be incurred to purchase required emissions allowances under any market-based cap-and-trade system in excess of allocations that are received at no cost. These purchases would be necessary until new technologies could be developed and deployed to reduce emissions or lower carbon generation is available;

•Acquiring and renewing construction and operating permits for new and existing generating facilities may be costly and difficult;

•Additional costs may be incurred to purchase and deploy new generating technologies;

•Costs may be incurred to retire existing coal-fueled generating facilities before the end of their otherwise useful lives or to convert them to burn fuels, such as natural gas or biomass, that result in lower emissions;

•Operating costs may be higher and generating unit outputs may be lower;

•Higher interest and financing costs and reduced access to capital markets may result to the extent that financial markets view climate change and GHG emissions as a greater business risk; and

•The relevant Registrant's natural gas pipeline operations and capacity sales, electric transmission and retail sales may be impacted in response to changes in customer demand and requirements to reduce GHG emissions.

The impact of events or conditions caused by climate change, whether from natural processes or human activities, are uncertain and could vary widely, from highly localized to worldwide, and the extent to which a utility's operations may be affected is uncertain. Climate change may cause physical and financial risks through, among other things, sea level rise, changes in precipitation and extreme weather events. Consumer demand for energy may increase or decrease, based on overall changes in weather and as customers promote lower energy consumption through the continued use of energy efficiency programs or other means. Availability of resources to generate electricity, such as water for hydroelectric production and cooling purposes, may also be impacted by climate change and could influence the Registrants' existing and future electricity generating portfolio. These issues may have a direct impact on the costs of electricity production and increase the price customers pay or their demand for electricity.

Implementing actions required under, and otherwise complying with, new federal and state laws and regulations and changes in existing ones are among the most challenging aspects of managing utility operations. The Registrants cannot accurately predict the type or scope of future laws and regulations that may be enacted, changes in existing ones or new interpretations by agency orders or court decisions, nor can each Registrant determine their impact on it at this time; however, any one of these could

79

adversely affect each Registrant's financial results through higher capital expenditures and operating costs, early closure of generating facilities or lower tax benefits or restrict or otherwise cause an adverse change in how each Registrant operates its business. To the extent that each Registrant is not allowed by its regulators to recover or cannot otherwise recover the costs to comply with new laws and regulations or changes in existing ones, the costs of complying with such additional requirements could have a material adverse effect on the relevant Registrant's financial results. Additionally, even if such costs are recoverable in rates, if they are substantial and result in rates increasing to levels that substantially reduce customer demand, this could have a material adverse effect on the relevant Registrant's financial results.

Recovery of costs and certain activities by each Registrant is subject to regulatory review and approval, and the inability to recover costs or undertake certain activities may adversely affect each Registrant's financial results.

State Regulatory Rate Review Proceedings

The Utilities establish rates for their regulated retail services through state regulatory proceedings. These proceedings typically involve multiple parties, including government bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but generally have the common objective of limiting rate increases or requesting rate decreases while also requiring the Utilities to ensure system reliability. Decisions are subject to judicial appeal, potentially leading to further uncertainty associated with the approval proceedings.

States set retail rates for consumers within their jurisdiction based in part upon the state regulatory commission's acceptance of an allocated share of total utility costs. When states adopt different methods to calculate interjurisdictional cost allocations, some costs may not be incorporated into rates of any state or other jurisdiction. Ratemaking is also generally done on the basis of estimates of normalized costs, so if a given year's realized costs are higher than normalized costs, rates may not be sufficient to cover those costs. In some cases, actual costs are lower than the normalized or estimated costs recovered through rates and from time-to-time may result in a state regulator requiring refunds to customers. Each state regulatory commission generally sets rates based on a test year established in accordance with that commission's policies. The test year data adopted by each state regulatory commission may create a lag between the incurrence of a cost and its recovery in rates. Each state regulatory commission also decides the allowed levels of expense, investment and capital structure that it deems are prudently incurred in providing the service and may disallow recovery in rates for any costs that it believes do not meet such standard. Additionally, each state regulatory commission establishes the allowed rate of return the Utilities will be given an opportunity to earn on their sources of capital. While rate regulation is premised on providing a fair opportunity to earn a reasonable rate of return on invested capital, the state regulatory commissions do not guarantee that each Registrant will be able to realize the allowed rate of return or recover all of its costs even if it believes such costs to be prudently incurred.

Some state regulatory commissions have authorized recovery of certain costs above the level assumed in establishing base rates through adjustment mechanisms, which may be subject to customer sharing. Any significant increase in fuel costs for electricity generation or purchased electricity costs could have a negative impact on the Utilities, despite efforts to minimize this impact through the use of hedging contracts and adjustment mechanisms or through future general regulatory rate reviews. Further, interjurisdictional cost allocation constraints could limit PacifiCorp's ability to recover such costs despite the adjustment mechanisms. Any of these consequences could adversely affect each Registrant's financial results.

FERC and Other Jurisdictions

The FERC authorizes cost-based rates associated with transmission services provided by the Utilities' transmission facilities. Under the Federal Power Act, the Utilities, or MISO as it relates to MidAmerican Energy, may voluntarily file, or may be obligated to file, for changes, including general rate changes, to their system-wide transmission service rates. General rate changes implemented may be subject to refund. The FERC also has responsibility for approving both cost- and market-based rates under which the Utilities sell electricity in the wholesale market, has jurisdiction over most of PacifiCorp's hydroelectric generating facilities and has broad jurisdiction over energy markets. The FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or could revoke or restrict the ability of the Utilities to sell electricity at market-based rates, which could adversely affect each Registrant's financial results. The FERC also maintains rules concerning standards of conduct, affiliate restrictions, interlocking directorates and cross-subsidization. As a transmission owning member of MISO, MidAmerican Energy is also subject to MISO-directed modifications of market rules, which are subject to FERC approval and operational procedures. As participants in EIM, PacifiCorp, Nevada Power and Sierra Pacific are also subject to applicable California ISO rules, which are subject to FERC approval and operational procedures. The FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act and the FERC's rules and orders.

80

The NERC has standards in place to ensure the reliability of the electric generation system and transmission grid. The Utilities are subject to the NERC's regulations and periodic audits to ensure compliance with those regulations. The NERC may carry out enforcement actions for non-compliance and administer significant financial penalties, subject to the FERC's review.

The FERC has jurisdiction over, among other things, the construction, abandonment, modification and operation of natural gas pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including all rates, charges and terms and conditions of service. The FERC also has market transparency authority and has adopted additional reporting and internet posting requirements for natural gas pipelines and buyers and sellers of natural gas.

Rates for the interstate natural gas transmission and storage operations at the Pipeline Companies, which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for charges, are authorized by the FERC. In accordance with the FERC's ratemaking principles, the Pipeline Companies' current maximum tariff rates are designed to recover prudently incurred costs included in their pipeline systems' regulatory cost of service that are associated with the construction, operation and maintenance of their pipeline systems and to afford the Pipeline Companies an opportunity to earn a reasonable rate of return. Nevertheless, the rates the FERC authorizes the Pipeline Companies to charge their customers may not be sufficient to recover the costs incurred to provide services in any given period. Moreover, from time to time, the FERC may change, alter or refine its policies or methodologies for establishing pipeline rates and terms and conditions of service. In addition, the FERC has the authority under Section 5 of the Natural Gas Act of 1938 ("NGA") to investigate whether a pipeline may be earning more than its allowed rate of return and, when appropriate, to institute proceedings against such pipeline to prospectively reduce rates. Any such proceedings, if instituted, could result in significantly adverse rate decreases.

Under FERC policy, interstate pipelines and their customers may execute contracts at negotiated rates, which may be above or below the maximum tariff rate for that service or the pipeline may agree to provide a discounted rate, which would be a rate between the maximum and minimum tariff rates. In a rate proceeding, rates in these contracts are generally not subject to adjustment. It is possible that the cost to perform services under negotiated or discounted rate contracts will exceed the cost used in the determination of the negotiated or discounted rates, which could result either in losses or lower rates of return for providing such services. Under certain circumstances, FERC policy allows interstate natural gas pipelines to design new maximum tariff rates to recover such costs in regulatory rate reviews. However, with respect to discounts granted to affiliates, the interstate natural gas pipeline must demonstrate that the discounted rate was necessary in order to meet competition.

The Northern Powergrid Distribution Companies, as DNOs and holders of electricity distribution licenses, are subject to regulation by GEMA. Most of the revenue of a DNO is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not directly constrain profits from year-to-year but is a control on revenue that operates independent of a significant portion of the DNO's actual costs. A resetting of the formula does not require the consent of the DNO, but if a licensee disagrees with a change to its license, it can appeal the matter to the United Kingdom's CMA. GEMA is able to impose financial penalties on DNOs that contravene any of their electricity distribution license duties or certain of their duties under British law or fail to achieve satisfactory performance of individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the DNO's revenue. During the term of any price control, additional costs have a direct impact on the financial results of the Northern Powergrid Distribution Companies.

The AUC is an independent, quasi-judicial agency established by the province of Alberta, Canada, which is responsible for, among other things, approving the tariffs of transmission facility owners, including AltaLink, and distribution utilities, acquisitions of such transmission facility owners or utilities, and construction and operation of new transmission projects in Alberta. The AUC also investigates and rules on regulated rate disputes and system access problems.

The AUC regulates and oversees Alberta's electricity transmission sector with broad authority that may impact many of AltaLink's activities, including its tariffs, rates, construction, operations and financing. In addition, AUC approval is required in connection with new energy and regulated utility initiatives in Alberta, amendments to existing approvals and financing proposals by designated utilities.

Each Registrant is involved in a variety of legal proceedings, the outcomes of which are uncertain and could adversely affect its financial results.

Each Registrant is, and in the future may become, a party to a variety of legal proceedings. Litigation is subject to many uncertainties, and the Registrants cannot predict the outcome of individual matters with certainty. It is possible that the final resolution of some of the matters in which each Registrant is involved could result in additional material payments substantially in excess of established liabilities or in terms that could require each Registrant to change business practices and procedures or divest ownership of assets. Further, litigation could result in the imposition of operational or financial penalties or injunctions and adverse regulatory consequences, any of which could limit each Registrant's ability to take certain desired actions or the

81

denial of needed permits, licenses or regulatory authority to conduct its business, including the siting, operation or permitting of facilities. Unfavorable judgments could also require posting of surety bonds as security until the amounts awarded to plaintiffs are paid or the judgment is overturned in the appeals process. To the extent the Registrant or affected subsidiary is unable to post such a bond, other forms of security may be required such as cash or letters of credit that could reduce borrowing capacity under credit facility agreements. Any of these outcomes could have a material adverse effect on such Registrant's or BHE's financial results. Refer to "PacifiCorp Wildfire Litigation and Insurance Risks" above for additional information regarding PacifiCorp's wildfire litigation risks.

Operational and Development Risks

The Registrants are subject to operating uncertainties and events beyond each respective Registrant's control that impact the costs to operate, maintain, repair and replace utility and interstate natural gas pipeline systems and the ability to self-insure many risks, which could adversely affect each respective Registrant's financial results.

The operation of complex utility systems or interstate natural gas pipeline and storage systems that are spread over large geographic areas involves many operating uncertainties and events beyond each respective Registrant's control. These potential events include the breakdown or failure of the Registrants' thermal, nuclear, hydroelectric, solar, wind and other electricity generating facilities and related equipment, compressors, pipelines, transmission and distribution lines and associated electric operations equipment or other equipment or processes, which could lead to catastrophic events; unscheduled outages; coal supply challenges occurring as a result of the transition away from coal-fueled resources; strikes, lockouts, other labor-related actions or shortages of qualified labor, including with respect to the Registrants' suppliers and vendors; transmission and distribution system constraints; failure to obtain, renew or maintain rights-of-way, easements and leases on U.S. federal, Native American, First Nations or tribal lands; terrorist activities or military or other actions, including physical or cyber attacks; fuel shortages or interruptions; unavailability of critical equipment, materials and supplies; low water flows and other weather-related impacts; performance below expected levels of output, capacity or efficiency; operator error; third-party excavation errors; unexpected degradation of transmission lines, pipeline systems or storage reservoirs; design, construction or manufacturing defects; and catastrophic events such as severe storms, floods, fires, extreme temperature events, wind events, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, costly litigation, wars, terrorism, pandemics and embargoes. A catastrophic event might result in injury or loss of life, extensive property damage, environmental or natural resource damages or excessive economic loss. For example, in the event of an uncontrolled release of water at one of PacifiCorp's high hazard potential hydroelectric dams, it is probable that loss of human life, disruption of lifeline facilities and property damage could occur in the downstream population and civil or other penalties could be imposed by the FERC. The extent of that liability would be determined by the applicable state law where any such damage occurred. Any of these events or other operational events could significantly reduce or eliminate the relevant Registrant's revenue or significantly increase its expenses, thereby reducing the availability of distributions to BHE. For example, if the relevant Registrant cannot operate its electricity or natural gas facilities at full capacity due to damage caused by a catastrophic event or due to supply constraints, its revenue could decrease and its expenses could increase due to the need to obtain energy from more expensive sources.

The Registrants self-insure many risks, and current and future insurance coverage may not be sufficient to replace lost revenue or cover repair and replacement costs or other damages. Further, third-party liability insurance coverage may be costly or unavailable as a result of increasing risks associated with catastrophic wildfires as discussed below. The scope, cost and availability of each Registrant's insurance coverage may change, including the portion that is self-insured.

Any reduction of each Registrant's revenue or increase in its expenses resulting from the risks described above, could adversely affect the relevant Registrant's financial results. Refer also to "PacifiCorp Wildfire Litigation and Insurance Risks" above for additional information regarding PacifiCorp's wildfire insurance risks.

The Registrants are subject to increasing risks from catastrophic wildfires and may be unable to obtain enough third-party liability insurance coverage at a reasonable cost or at all and insurance coverage on existing wildfire claims could be insufficient to cover all losses, all of which could materially affect the Registrants financial results and liquidity.

The risk of catastrophic and severe wildfires has increased in the western U.S. giving rise to the potential for large damage claims against utilities for fire-related losses. Catastrophic and severe wildfires can occur in PacifiCorp, Nevada Power and Sierra Pacific's ("Western Domestic Utilities") service territories even when the Western Domestic Utilities effectively implement their wildfire mitigation plans and prudently manage their systems.

82

In California, for example, where PacifiCorp operates, "inverse condemnation" currently exposes utilities to potential liability for property damages where the utility's electrical equipment was a substantial cause of the wildfire. California courts have held that utilities can be held liable under inverse condemnation without being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover attorney's fees. As a result of inverse condemnation being applied to utilities and wildfire damages, recent losses recorded by insurance companies, and the risk of an increase in the frequency, duration and size of wildfires, insurance for wildfire liabilities may not be available or may be available only at rates that are prohibitively expensive. In addition, even if insurance for wildfire liabilities is available, it may not be available in amounts necessary to cover potential losses. Uninsured losses and increases in the cost of insurance may be challenged when PacifiCorp seeks cost recovery and may not be recoverable in customer rates.

The Western Domestic Utilities monitor weather conditions with specific thresholds for designated high fire consequence areas to help ensure the safe and reliable operation of their systems during periods of elevated wildfire ignition risk. Should weather conditions become extreme, the Western Domestic Utilities may de-energize certain sections of their transmission and distribution facilities as a last resort to minimize risk to the public. These "public safety power shutoffs" could be subject to increased scrutiny by regulators and policy makers. And, although "public safety power shutoffs" are intended to minimize risk of wildfire ignition, de-energization may cause other damages for which the Western Domestic Utilities could be held liable.

Refer also to "PacifiCorp Wildfire Litigation and Insurance Risks" above for additional information regarding PacifiCorp's wildfire insurance risks.

Each Registrant is actively pursuing, developing and constructing new or expanded facilities, the completion and expected costs of which are subject to significant risk, and each Registrant has significant funding needs related to its planned capital expenditures.

Each Registrant actively pursues, develops and constructs new or expanded facilities. Each Registrant expects to incur significant annual capital expenditures over the next several years. Such expenditures may include construction and other costs for new electricity generating facilities, electric transmission or distribution projects, environmental control and compliance systems, natural gas storage facilities, new or expanded pipeline and local distribution systems, and continued maintenance and upgrades of existing assets.

Development and construction of major facilities are subject to substantial risks, including fluctuations in the price and availability of commodities, manufactured goods, equipment, and the imposition of tariffs thereon when sourced by foreign providers, labor, siting and permitting and changes in environmental and operational compliance matters, load forecasts and other items over a multi-year construction period, as well as counterparty risk and the economic viability of the Registrants' suppliers, customers and contractors. Certain of the Registrants' construction projects are substantially dependent upon a single supplier or contractor and replacement of such supplier or contractor may be difficult and cannot be assured. These risks may result in the inability to timely complete a project or higher than expected costs to complete an asset and place it in-service and, in extreme cases, the loss of the power purchase agreements or other long-term off-take contracts underlying such projects. Such costs may not be recoverable in the regulated rates or market or contract prices each Registrant is able to charge its customers. Delays in construction of renewable projects may result in delayed in-service dates which may result in the loss of anticipated revenue or income tax benefits. It is also possible that additional generation needs may be obtained through power purchase agreements, which could increase long-term purchase obligations and force reliance on the operating performance of a third party. The inability to successfully and timely complete a project, avoid unexpected costs or recover any such costs could adversely affect such Registrant's financial results.

Furthermore, each Registrant depends upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. If BHE does not provide needed funding to its subsidiaries and the subsidiaries are unable to obtain funding from external sources, they may need to postpone or cancel planned capital expenditures. Refer to "PacifiCorp Wildfire Litigation and Insurance Risks" above for additional information regarding the impact of wildfire litigation risks on PacifiCorp's capital expenditures.

A significant sustained decrease in demand for electricity or natural gas in the markets served by each Registrant would decrease its operating revenue, could impact its planned capital expenditures and could adversely affect its financial results.

A significant sustained decrease in demand for electricity or natural gas in the markets served by each Registrant would decrease its operating revenue, could impact its planned capital expenditures and could adversely affect its financial results. Factors that could lead to a decrease in market demand include, among others:

83

•a depression, recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on electricity or natural gas;

•an increase in the market price of electricity or natural gas or a decrease in the price of other competing forms of energy;

•shifts in competitively priced natural gas supply sources away from the sources connected to the Pipeline Companies' systems, including shale gas sources;

•efforts by customers, legislators and regulators to reduce the consumption of electricity generated or distributed by each Registrant through various existing laws and regulations, as well as, deregulation, conservation, energy efficiency and private generation measures and programs;

•laws or policy pronouncements mandating or encouraging renewable energy sources, which may decrease the demand for electricity and natural gas or change the market prices of these commodities;

•higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or other fuel sources for electricity generation or that limit the use of natural gas or the generation of electricity from fossil fuels;

•a shift to more energy-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, legislation mandating higher fuel economy or lower emissions, price differentials, incentives or otherwise;

•a reduction in the state or federal subsidies or tax incentives that are provided to agricultural, industrial or other customers, or a significant sustained change in prices for commodities such as ethanol or corn for ethanol manufacturers; and

•sustained mild weather that reduces heating or cooling needs.

Each Registrant's operating results may fluctuate on a seasonal and quarterly basis and may be adversely affected by weather.

In most parts of the U.S. and other markets in which each Registrant operates, demand for electricity peaks during the summer months when irrigation and cooling needs are higher. Market prices for electricity also generally peak at that time. In other areas, including the western portion of PacifiCorp's service territory, demand for electricity peaks during the winter when heating needs are higher. In addition, demand for natural gas and other fuels generally peaks during the winter. This is especially true in MidAmerican Energy's and Sierra Pacific's retail natural gas businesses. Further, extreme weather conditions, such as heat waves, winter storms or floods could cause these seasonal fluctuations to be more pronounced. Periods of low rainfall or snowpack may negatively impact electricity generation at PacifiCorp's hydroelectric generating facilities, which may result in greater purchases of electricity from the wholesale market or from other sources at market prices. Additionally, PacifiCorp and MidAmerican Energy have added substantial wind-powered generating capacity, and BHE's unregulated subsidiaries are adding solar-powered and wind-powered generating capacity, each of which is also a climate-dependent resource.

As a result, the overall financial results of each Registrant may fluctuate substantially on a seasonal and quarterly basis. Each Registrant has historically provided less service, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect each Registrant's financial results through lower revenue or margins. Conversely, unusually extreme weather conditions could increase each Registrant's costs to provide services and could adversely affect its financial results. The extent of fluctuation in each Registrant's financial results may change depending on a number of factors related to its regulatory environment and contractual agreements, including its ability to recover energy costs, the existence of revenue sharing provisions as it relates to MidAmerican Energy, Nevada Power and Sierra Pacific, and terms of its wholesale sale contracts.

Each Registrant is subject to market risk associated with the wholesale energy markets, which could adversely affect its financial results.

In general, each Registrant's primary market risk is adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas, coal and fuel oil, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. The market price of wholesale electricity may be influenced by several factors, such as the adequacy or type of generating capacity, scheduled and unscheduled outages of generating facilities, prices and availability of fuel sources for generation, disruptions or constraints to transmission and distribution facilities, weather conditions, demand for electricity, economic growth and changes in technology. Volumetric changes are caused by fluctuations in generation or changes in

84

customer needs that can be due to the weather, electricity and fuel prices, the economy, regulations and governmental policies or customer behavior. For example, the Utilities purchase electricity and fuel in the open market as part of their normal operating businesses. If market prices rise, especially in a time when larger than expected volumes must be purchased at market prices, the Utilities may incur significantly greater expenses than anticipated. Likewise, if electricity market prices decline in a period when the Utilities are a net seller of electricity in the wholesale market, the Utilities could earn less revenue. Although the Utilities have ECAMs, the risks associated with changes in market prices may not be fully mitigated due to customer sharing bands as it relates to PacifiCorp and other factors, including potential interjurisdictional allocation constraints and extended recovery periods that negatively impact cash flows.

Certain of BHE's subsidiaries are subject to the risk that customers will not renew their contracts or that BHE's subsidiaries will be unable to obtain new customers for expanded capacity, each of which could adversely affect its financial results.

If BHE's subsidiaries are unable to renew, remarket, or find replacements for their customer agreements on favorable terms, BHE's subsidiaries' sales volumes and operating revenue would be exposed to reduction and increased volatility. For example, without the benefit of long-term transportation agreements, BHE cannot assure that the Pipeline Companies will be able to transport natural gas at efficient capacity levels. Substantially all of the Pipeline Companies' revenue is generated under transportation, storage and LNG contracts that periodically must be renegotiated and extended or replaced, and the Pipeline Companies are dependent upon relatively few customers for a substantial portion of their revenue. Similarly, without long-term power purchase agreements, BHE cannot assure that its unregulated power generators will be able to operate profitably. Failure to maintain existing long-term agreements or secure new long-term agreements, or being required to discount rates significantly upon renewal or replacement, could adversely affect BHE's consolidated financial results. The replacement of any existing long-term agreements depends on market conditions and other factors that may be beyond BHE's subsidiaries' control.

Each Registrant is subject to counterparty risk, which could adversely affect its financial results.

Each Registrant is subject to counterparty credit risk related to contractual payment obligations with wholesale suppliers and customers. Adverse economic conditions or other events affecting counterparties with whom each Registrant conducts business could impair the ability of these counterparties to meet their payment obligations. Each Registrant depends on these counterparties to remit payments on a timely basis. Each Registrant monitors the creditworthiness of its wholesale suppliers and customers in an attempt to reduce the impact of any potential counterparty default. If strategies used to minimize these risk exposures are ineffective or if a Registrant's wholesale suppliers' or customers' financial condition deteriorates or they otherwise become unable to pay, it could have a significant adverse impact on the Registrant's liquidity and its financial results.

Each Registrant is subject to counterparty performance risk related to performance of contractual obligations by wholesale suppliers, customers and contractors. Each Registrant relies on wholesale suppliers to deliver commodities, primarily natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide these commodities pursuant to existing contracts could disrupt the delivery of electricity and require the Utilities to incur additional expenses to meet customer needs. In addition, when these contracts terminate, the Utilities may be unable to purchase the commodities on terms equivalent to the terms of current contracts.

Each Registrant relies on wholesale customers to take delivery of the energy they have committed to purchase. Failure of customers to take delivery may require the relevant Registrant to find other customers to take the energy at lower prices than the original customers committed to pay. If each Registrant's wholesale customers are unable to fulfill their obligations, there may be a significant adverse impact on its financial results.

The Northern Powergrid Distribution Companies' customers are concentrated in a small number of electricity supply businesses with E.ON and British Gas Trading Limited accounting for approximately 19% and 15%, respectively, of distribution revenue in 2023. AltaLink's primary source of operating revenue is the AESO. Generally, a single customer purchases the energy from BHE's independent power projects in the U.S. pursuant to long-term power purchase agreements. For example, certain of BHE Renewables' solar and wind independent power projects sell all of their electrical production to either PG&E or SCE, respectively. Any material payment or other performance failure by the counterparties in these arrangements could have a significant adverse impact on BHE's consolidated financial results.

Inflation and changes in commodity prices and transportation fuel costs may adversely affect each Registrant's financial results.

Inflation and increases in commodity prices and transportation fuel costs may affect each Registrant by increasing both operating and capital costs. As a result of existing rate agreements, contractual arrangements or competitive price pressures,

85

each Registrant may not be able to pass the inflated costs on to its customers. If a Registrant is unable to manage cost increases or pass them on to its customers, its financial results could be adversely affected.

Physical or cyber attacks, both threatened and actual, could impact each Registrant's operations and could adversely affect its financial results.

Each Registrant relies on technology in virtually all aspects of its business. Like any business, the Registrants' technology systems are a target for computer viruses, malicious codes, unauthorized access, phishing efforts, denial-of-service attacks and other cyber attacks and each Registrant expects to be subject to attempted attacks in the future and will continue to adapt defensive capabilities as such attacks become more sophisticated and frequent. A significant disruption or failure of its technology systems by cyber or physical attack could result in service interruptions, safety failures, security events, regulatory compliance failures, an inability to protect information and assets against unauthorized users, and other operational difficulties. Attacks perpetrated against each Registrant's systems could result in loss of assets and critical information and expose it to remediation costs and reputational damage.

Although the Registrants have taken steps intended to mitigate these risks, a significant disruption or cyber intrusion at one or more of each Registrant's operations could adversely affect the impacted Registrant's financial results. Cyber attacks could further adversely affect each Registrant's ability to operate facilities, information technology and business systems, or compromise sensitive customer and employee information. In addition, physical or cyber attacks against key suppliers or service providers could have a similar effect on each Registrant. Additionally, if each Registrant is unable to acquire, develop, implement, adopt or protect rights around new technology, it may suffer a competitive disadvantage.

Much of BHE's growth has been achieved through acquisitions, and any such acquisition may not be successful.

Much of BHE's growth has been achieved through acquisitions. Future acquisitions may range from buying individual assets to the purchase of entire businesses. BHE will continue to investigate and pursue opportunities for future acquisitions that it believes, but cannot assure, may increase value and expand or complement existing businesses. BHE may participate in bidding or other negotiations at any time for such acquisition opportunities which may or may not be successful.

An acquisition could cause an interruption of, or a loss of momentum in, the activities of one or more of BHE's subsidiaries. In addition, the final orders of regulatory authorities approving acquisitions may be subject to appeal by third parties. The diversion of BHE management's attention and any delays or difficulties encountered in connection with the approval and integration of the acquired operations could adversely affect BHE's combined businesses and financial results and could impair its ability to realize the anticipated benefits of the acquisition.

BHE cannot assure that future acquisitions, if any, or any integration efforts will be successful, or that BHE's ability to repay its obligations will not be adversely affected by any future acquisitions.

Certain Registrants are subject to the unique risks associated with nuclear generation.

The ownership and operation of nuclear generating facilities, such as MidAmerican Energy's 25% ownership interest in Quad Cities Station, involves certain risks. These risks include, among other items, mechanical or structural problems, inadequacy or lapses in maintenance protocols, the impairment of reactor operation and safety systems due to human error, the costs of storage, handling and disposal of nuclear materials, compliance with and changes in regulation of nuclear generating facilities, limitations on the amounts and types of insurance coverage commercially available, and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. Additionally, Constellation Energy, the 75% owner and operator of the facility, may respond to the occurrence of any of these or other risks in a manner that negatively impacts MidAmerican Energy, including closure of Quad Cities Station prior to the expiration of its operating license. The prolonged unavailability, or early closure, of Quad Cities Station due to operational or economic factors could have a materially adverse effect on the relevant Registrant's financial results, particularly when the cost to produce power at the generating facility is significantly less than market wholesale prices. The following are among the more significant of these risks:

86

•Operational Risk - Operations at any nuclear generating facility could degrade to the point where the generating facility would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the generating facility to operation could require significant time and expenses, resulting in both lost revenue and increased fuel and purchased electricity costs to meet supply commitments. Rather than incurring substantial costs to restart the generating facility, the generating facility could be shut down. Furthermore, a shut-down or failure at any other nuclear generating facility could cause regulators to require a shut-down or reduced availability at Quad Cities Station.

In addition, issues relating to the disposal of nuclear waste material, including the availability, unavailability and expenses of a permanent repository for spent nuclear fuel could adversely impact operations as well as the cost and ability to decommission nuclear generating facilities, including Quad Cities Station, in the future.

•Regulatory Risk - The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with applicable Atomic Energy Act regulations or the terms of the licenses of nuclear facilities. Unless extended, the NRC operating licenses for Quad Cities Station will expire in 2032. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.

•Nuclear Accident and Catastrophic Risks - Accidents and other unforeseen catastrophic events have occurred at nuclear facilities other than Quad Cities Station, both in the U.S. and elsewhere, such as at the Fukushima Daiichi nuclear generating facility in Japan as a result of the earthquake and tsunami in March 2011. The consequences of an accident or catastrophic event can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident or catastrophic event could exceed the relevant Registrant's resources, including insurance coverage.

Potential terrorist activities and the impact of military or other actions, including sanctions, export controls and similar measures, could adversely affect each Registrant's financial results.

The ongoing threat of terrorism and the impact of military or other actions by nations or politically, ethnically or religiously motivated organizations regionally or globally may create increased political, economic, social and financial market instability, which could subject each Registrant's operations to increased risks. Additionally, the U.S. government has issued warnings that energy assets, specifically pipeline, nuclear generation, transmission and other electric utility infrastructure, are potential targets for terrorist attacks. Further, the potential or actual outbreak of war or other hostilities and the resulting economic sanctions on aggressor nations, as well as the existing and potential further responses from such aggressors or other countries to such sanctions and military actions, could adversely affect global and regional economies and financial markets. For instance, a ban on imports of oil, liquefied natural gas and coal to the U.S. could contribute to increases in prices for such commodities in the U.S. and elsewhere which could adversely affect each Registrant's business. Further, each Registrant's business must be conducted in compliance with applicable economic and trade sanctions laws and regulations, including those administered and enforced by the U.S. Department of Treasury's Office of Foreign Assets Control, the U.S. Department of State, the U.S. Department of Commerce, the United Nations Security Council and other relevant governmental authorities in the U.S., Canada, the United Kingdom and European Union, which include sanctions that could potentially restrict or prohibit each Registrant's relationships with certain suppliers and customers. Political, economic, social or financial market instability or damage to or interference with the operating assets of the Registrants, customers or suppliers, or continued increases in the price of natural gas and other petroleum commodities may result in business interruptions, lost revenue, higher costs, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to electricity and natural gas, and increased security, repair or other costs, any of which may materially adversely affect each Registrant in ways that cannot be predicted at this time. Any of these risks could materially affect BHE's consolidated financial results. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect each Registrant's ability to raise capital.

Each Registrant's business could be adversely affected by epidemics, pandemics or other outbreaks.

Each Registrant's business could be adversely affected by epidemics, pandemics or other outbreaks generally and more specifically in the markets in which we operate, including, without limitation, if each Registrant's utility customers experience decreases in demand for their products and services or otherwise reduce their consumption of electricity or natural gas that the respective Registrant supplies, or if such Registrant experiences material payment defaults by its customers. In addition, each Registrant's results and financial condition may be adversely affected by federal, state or local and foreign legislation related to such epidemics, pandemics or other outbreaks (or other similar laws, regulations, policies, orders or other governmental or regulatory actions) that would impose a moratorium on terminating electric or natural gas utility services, including related

87

assessment of late fees, due to non-payment or other circumstances. Additionally, HomeServices' real estate businesses could experience a decline (which could be significant) in real estate transactions if potential customers elect to defer purchases in reaction to any epidemic, pandemic or other outbreak or due to general economic uncertainty such as high unemployment levels, in some or all of the real estate markets in which HomeServices operates. The government and regulators could impose other requirements on each Registrant's business that could have an adverse impact on such Registrant's financial results.

Further, epidemics, pandemics or other outbreaks could disrupt supply chains (including supply chains for energy generation, steel or transmission wire) relating to the markets each Registrant serves, which could adversely impact such Registrant's ability to generate or supply power. In addition, such disruptions to the supply chain could delay certain construction and other capital expenditure projects, including construction and repowering of the Registrants' renewable generation projects. Such disruptions could adversely affect the impacted Registrant's future financial results.

Such declines in demand, any inability to generate or supply power or delays in capital projects could also significantly reduce cash flows at BHE's subsidiaries, thereby reducing the availability of distributions to BHE, which could adversely affect its financial results.

Cyclical fluctuations and competition in the residential real estate brokerage and mortgage businesses could adversely affect HomeServices.

The residential real estate brokerage and mortgage industries tend to experience cycles of greater and lesser activity and profitability and are typically affected by changes in economic conditions, which are beyond HomeServices' control. Any of the following, among others, are examples of items that could have a material adverse effect on HomeServices' businesses by causing a general decline in the number of home sales, sale prices or the number of home financings which, in turn, would adversely affect its financial results:

•rising interest rates or unemployment rates, including a sustained high unemployment rate in the U.S.;

•periods of economic slowdown or recession in the markets served or the adverse effects on market actions as a result of epidemics, pandemics or other outbreaks;

•decreasing home affordability;

•lack of available mortgage credit for potential homebuyers, such as the reduced availability of credit, which may continue into future periods;

•inadequate home inventory levels;

•sources of new competition; and

•changes in applicable tax law.

BHE owns investments in foreign countries that are exposed to risks related to fluctuations in foreign currency exchange rates and increased economic, regulatory and political risks.

BHE's business operations and investments outside the U.S. increase its risk related to fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar. BHE's principal reporting currency is the U.S. dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from its foreign operations changes with the fluctuations of the currency in which they transact. BHE may selectively reduce some foreign currency exchange rate risk by, among other things, requiring contracted amounts be settled in, or indexed to, U.S. dollars or a currency freely convertible into U.S. dollars, or hedging through foreign currency derivatives. These efforts, however, may not be effective and could negatively affect BHE's consolidated financial results.

In addition to any disruption in the global financial markets, the economic, regulatory and political conditions in some of the countries where BHE has operations or is pursuing investment opportunities may present increased risks related to, among others, inflation, foreign currency exchange rate fluctuations, currency repatriation restrictions, nationalization, renegotiation, privatization, availability of financing on suitable terms, customer creditworthiness, construction delays, business interruption, political instability, civil unrest, guerilla activity, terrorism, pandemics (including potentially in relation to COVID-19 variants), expropriation, trade sanctions, contract nullification and changes in law, regulations or tax policy. BHE may not choose to or be capable of either fully insuring against or effectively hedging these risks.

88

Item 1B.    Unresolved Staff Comments

Not applicable.

Item 1C.    Cybersecurity

CYBER RISK MANAGEMENT AND STRATEGY

BHE and its Subsidiary Registrants recognize that maintaining processes for identifying, assessing and managing cybersecurity threats is important in dealing with their significant business risks. As such, BHE has implemented a framework for cybersecurity and cyber-related information management across its businesses. BHE's Chief Security Office ("CSO") drives collective focus and central coordination of BHE's cyber and physical security programs. The CSO identifies the strategic framework that promotes standardization of business security policies and practices and provides direction in managing security risks. Although the CSO provides oversight, the businesses retain accountability for executing company security objectives, policies and practices within their areas of responsibility.

BHE manages cybersecurity threats through its proactive risk management program and cybersecurity awareness program. BHE's businesses are certified against the ISO 27001 standard. The standard is authored by the International Organization for Standardization ("ISO") of Geneva, Switzerland. To achieve the certification, each business must sustain an information security management system that includes a risk-based framework to identify and manage information security risks through a continuous improvement cycle. The risks and controls identified in the system must be approved by top management and confirmed through annual internal and external ISO audits prior to certification.

In addition, BHE's compliance requirements include the North American Electric Reliability Corporation Critical Infrastructure Protection Standards, the Transportation Security Administration Pipeline Security Directives and the United Kingdom Center for the Protection of National Infrastructure Standards as applicable to each of the companies. These requirements are audited and assessed as mandated by applicable government agencies.

Each Registrant relies on technology in virtually all aspects of its business. Like any business, the Registrants' technology systems are a target for cyber attacks. Each Registrant expects to be subject to attempted attacks in the future and will continue to adapt defensive capabilities as such attacks become more sophisticated and frequent. A significant disruption or failure of its technology systems by cyber or physical attack could result in service interruptions, safety failures, security events, regulatory compliance failures, an inability to protect information and assets against unauthorized users, and other operational difficulties. Attacks perpetrated against each Registrant's systems could result in loss of assets and critical information and expose it to remediation costs and reputational damage.

In certain circumstances, BHE relies on third-party service providers for a variety of products and services to run its information systems. This dependence exposes BHE, along with others who use these service providers, to the impact of a cyber attack on its service providers. Cyber attacks at a third-party service provider could have a significant financial, operational, or reputational impact. BHE continuously monitors the risks associated with its service providers.

GOVERNANCE

BHE's Board of Directors has responsibility for oversight of BHE's cybersecurity risk management program.

BHE's CSO is responsible for cyber and physical security across BHE and its Subsidiary Registrants. The CSO reports directly to the Chief Executive Officer of BHE. The CSO is responsible for identifying, assessing and managing cyber risk for BHE and its Subsidiary Registrants. Management has evaluated the expertise of the CSO and determined that it possesses the knowledge and expertise necessary to oversee BHE's cybersecurity risk management processes.

The CSO provides, at least annually, updates to the Chief Executive Officer and BHE's Board of Directors on:

•Updates on strategic cyber and physical security initiatives

•Current threat and risk landscape impacting the organization

•Security compliance with regulatory requirements

•Compliance with ISO 27001 framework

•Number and impact of incidents reported through the BHE cybersecurity incident reporting process

89

A BHE Cybersecurity Reporting Framework has been adopted so that BHE has a repeatable and timely process to identify, assess and manage any security incidents for materiality reporting. Each BHE business is required to report significant cybersecurity events to BHE. BHE's senior management reviews incident reports to determine whether a cyber incident report should be filed with the SEC.

Item 2.    Properties

Each Registrant's energy properties consist of the physical assets necessary to support its electricity and natural gas businesses. Properties of the relevant Registrant's electricity businesses include electric generation, transmission and distribution facilities, as well as coal mining assets that support certain of PacifiCorp's electric generating facilities. Properties of the relevant Registrant's natural gas businesses include natural gas distribution facilities, interstate pipelines, storage facilities, LNG facilities, compressor stations and meter stations. The transmission and distribution assets are primarily within each Registrant's service territories. In addition to these physical assets, the Registrants have rights-of-way, mineral rights and water rights that enable each Registrant to utilize its facilities. It is the opinion of each Registrant's management that the principal depreciable properties owned by it are in good operating condition and are well maintained. Pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties in the state of Nevada, AltaLink's transmission properties and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of generation projects are pledged or encumbered to support or otherwise provide the security for the related subsidiary debt. For additional information regarding each Registrant's energy properties, refer to Item 1 of this Form 10-K and Notes 4, 5 and 22 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of Nevada Power in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of Sierra Pacific in Item 8 of this Form 10-K and Notes 4 and 5 of the Notes to Consolidated Financial Statements of Eastern Energy Gas in Item 8 of this Form 10-K.

The following table summarizes Berkshire Hathaway Energy's operating electric generating facilities as of December 31, 2023:

			Facility Net	Net Owned
Energy			Capacity	Capacity
Source	Entity	Location by Significance	(MWs)	(MWs)
Wind	PacifiCorp, MidAmerican Energy, BHE Canada, BHE Montana and BHE Renewables	Iowa, Wyoming, Texas, Montana, Nebraska, Washington, California, Illinois, Canada, Oregon and Kansas	12,524	12,524
Natural gas	PacifiCorp, MidAmerican Energy, NV Energy, BHE Canada and BHE Renewables	Nevada, Utah, Iowa, Illinois, Washington, Wyoming, Oregon, Texas, New York, Arizona and Canada	11,250	10,971
Coal	PacifiCorp, MidAmerican Energy and NV Energy	Iowa, Wyoming, Utah, Nevada, Colorado and Montana	12,174	7,483
Solar	MidAmerican Energy, NV Energy, Northern Powergrid and BHE Renewables	California, Australia, Texas, Arizona, Iowa, Minnesota and Nevada	2,120	1,972
Hydroelectric	PacifiCorp, MidAmerican Energy and BHE Renewables	Washington, Oregon, Idaho, Utah, Hawaii, Montana, Illinois, California and Wyoming	985	985
Nuclear	MidAmerican Energy	Illinois	1,809	452
Geothermal	PacifiCorp and BHE Renewables	California and Utah	377	377
		Total	41,239	34,764

Additionally, as of December 31, 2023, the Company has electric generating facilities that are under construction in Nevada, Wyoming and California having total Facility Net Capacity and Net Owned Capacity of 1,284 MWs.

90

As of December 31, 2023, the Company also has battery energy storage systems in Nevada having total Facility Net Capacity and Net Owned Capacity in operation of 220 MW and under construction of 100 MW.

The right to construct and operate each Registrant's electric transmission and distribution facilities and interstate natural gas pipelines across certain property was obtained in most circumstances through negotiations and, where necessary, through prescription, eminent domain or similar rights. PacifiCorp, MidAmerican Energy, Nevada Power, Sierra Pacific, BHE GT&S, Northern Natural Gas and Kern River in the U.S.; Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc in Great Britain; and AltaLink in Alberta, Canada continue to have the power of eminent domain or similar rights in each of the jurisdictions in which they operate their respective facilities, but the U.S. and Canadian utilities do not have the power of eminent domain with respect to governmental, Native American or Canadian First Nations' tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities in the Moapa Indian Reservation are located within a utility corridor that is reserved to the U.S. Department of Interior, Bureau of Land Management.

With respect to real property, each of the electric transmission and distribution facilities and interstate natural gas pipelines fall into two basic categories: (1) parcels that are owned in fee, such as certain of the electric generating facilities, electric substations, natural gas compressor stations, natural gas meter stations and office sites; and (2) parcels where the interest derives from leases, easements (including prescriptive easements), rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the electric transmission and distribution facilities and interstate natural gas pipelines. Each Registrant believes it has satisfactory title or interest to all of the real property making up their respective facilities in all material respects.

Item 3.    Legal Proceedings

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP

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

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

As described below, a significant number of complaints and demands alleging similar claims have been filed in Oregon and California related to the 2020 Wildfires. Amounts sought in the complaints and demands filed in Oregon and in certain demands made in California total approximately $8 billion, excluding any doubling or trebling of damages included in the complaints and those settled. Generally, the complaints filed in California do not specify damages sought and are excluded from this amount. The complaints and demands filed in Oregon generally seek doubling of economic damages under Oregon law, which provides for such doubling in the event the wildfire is determined to have occurred as a result of recklessness, gross negligence, willfulness or malice. Additionally, those complaints and demands filed in Oregon that involve damages associated with forestry, trees or shrubbery generally seek trebling of damages claimed under Oregon law, which provides for such trebling in the event the damages are determined to have occurred by willful and intentional acts and without consent. Amounts sought for any doubling or trebling of damages are excluded from the amounts described below.

Multiple complaints have also been filed in California for the 2022 McKinney Fire for which the damages sought have not been specified.

Investigations into the causes and origins of the Wildfires are ongoing. For more information regarding certain legal proceedings affecting Berkshire Hathaway Energy, refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part II, Item 8 of this Form 10-K, and PacifiCorp, refer to Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Part II, Item 8 of this Form 10-K.

91

2020 Slater Fire California and Oregon Complaints and Demands

As described below, a significant number of complaints on behalf of plaintiffs associated with the Northern California and Southern Oregon Slater Fire ("Slater Fire") have been filed in Oregon and California. The complaints generally allege: (i) inverse condemnation; (ii) negligence; (iii) trespass; (iv) nuisance; and (v) violation of certain sections of the California Public Utilities Code and the California Health & Safety Code and request a jury trial and seek various damages, generally including: (i) economic damages; (ii) noneconomic damages; (iii) doubling of economic damages; (iv) punitive damages; (v) pre- and post-judgment interest; and (vi) attorneys' fees and other costs. Certain complaints include wrongful death claims as described below.

Hitchcock et al. v. PacifiCorp and Consolidated Slater Fire Cases

On December 16, 2020, a complaint against PacifiCorp was filed, captioned Hitchcock et al. v. PacifiCorp, Case No. 34-2020-00290833 ("Hitchcock") in California Superior Court, Sacramento County, California by approximately 69 plaintiffs. The Hitchcock case makes similar allegations as those described above for the Slater Fire, includes a wrongful death claim for one of the two Slater Fire decedents and does not specify the amount of damages sought.

The following complaints also filed in California Superior Court, Sacramento County, California have been consolidated into the Hitchcock case: Hillman complaint filed January 29, 2021, approximately 234 plaintiffs; Franklin complaint filed February 17, 2022, approximately 43 plaintiffs; Ormsby complaint filed April 18, 2022, approximately four plaintiffs; Hodges complaint filed August 23, 2022, approximately 26 plaintiffs; Nixon complaint filed August 31, 2022, approximately two plaintiffs; Bleeg complaint filed September 1, 2022, approximately 17 plaintiffs; Sanchez complaint filed September 7, 2022, approximately 10 plaintiffs; Lemon complaint filed September 2, 2022, approximately 186 plaintiffs; and Duval complaint filed September 29, 2022, approximately 24 plaintiffs.

The complaints make similar allegations as those described above for the Slater Fire and do not specify the amount of damages sought.

In 2023, PacifiCorp settled certain claims in the consolidated Hitchcock case for $8 million representing three individual plaintiffs and one commercial timber plaintiff. In January and February 2024, PacifiCorp reached additional settlements totaling $48 million representing 153 plaintiffs. As a result of the settlements, the Hitchcock case set for trial starting March 4, 2024 through March 29, 2024 was cancelled.

Other Slater Fire Cases

On August 17, 2023, a complaint against PacifiCorp was filed captioned Fernandez et. al v. PacifiCorp, Case No. 23CV007154 in California Superior Court, Sacramento County, California by approximately 51 plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and does not specify the amount of damages sought.

On September 8, 2023, a subrogation complaint against PacifiCorp was filed captioned Travelers Commercial Insurance Company et al. v. PacifiCorp, Case No. 23CV008226 in California Superior Court, Sacramento County, California by 4 plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and does not specify the amount of damages sought.

On September 7, 2023, a complaint against PacifiCorp was filed captioned Thomason et. al v. PacifiCorp, Case No. 23CV008033 in California Superior Court, Sacramento County, California, by approximately 4 plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and does not specify the amount of damages sought.

On September 28, 2023, a complaint against PacifiCorp was filed captioned Bledsoe et. al v. PacifiCorp, Case No. 23CV009242 in California Superior Court, Sacramento County, California, by three plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and does not specify the amount of damages sought.

On August 10, 2022, a complaint against PacifiCorp was filed captioned Siskiyou County v. PacifiCorp, Case No. 34-2022-00324977 by one plaintiff in California Superior Court, Sacramento County. The complaint makes similar allegations as those described above for the Slater Fire and does not specify the amount of damages sought. In April 2023, PacifiCorp received a mediation demand from Siskiyou County for approximately $6 million in damages. A jury trial is scheduled for December 2, 2024.

92

On July 12, 2023, a complaint against PacifiCorp was filed captioned Susan Irene Terran et. al v. PacifiCorp, Case No. 23CV27759 in Multnomah County Circuit Court in Oregon, by approximately six plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and seeks various damages, including economic damages of approximately $10 million based on $1 million for each of the five individual plaintiffs and $5 million for the one non-individual plaintiff. The complaint seeks noneconomic damages to be determined at trial.

Black et al. v. PacifiCorp and Consolidated Slater Fire Cases

On March 10, 2022, a complaint against PacifiCorp was filed, captioned Susan Black et al. v. PacifiCorp, Case No. 22CV08622 ("Black") in Oregon Circuit Court in Multnomah County, Oregon, by approximately 28 plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and seeks various damages, including economic damages of approximately $44 million based on $1 million for each of the 24 individual plaintiffs and $5 million for each of the four non-individual plaintiffs. The individual plaintiffs also seek unspecified noneconomic damages. A jury trial is scheduled for September 23, 2024, through November 1, 2024.

The following complaints filed in Oregon Circuit Court in Multnomah County have been consolidated into the Black case: Denny complaint filed August 31, 2022, approximately seven plaintiffs and Sparks amended complaint filed September 7, 2022, approximately five plaintiffs. The complaints make similar allegations as those described above for the Slater Fire and each seek various damages, including economic damages of approximately $16 million based on $1 million for each of the 11 individual plaintiffs and $5 million for the one non-individual plaintiff across both the Denny and Sparks complaints. The individual plaintiffs also seek unspecified noneconomic damages.

United States – Loss and Damages to Federal Lands – Slater Fire

PacifiCorp received a notice of indebtedness from the U.S. Department of Agriculture Forest Service ("USFS") indicating that PacifiCorp owes the U.S. $356 million for fire suppression costs, natural resource damages and burned area emergency response costs incurred by the USFS associated with the Slater fire in California. The notice further indicates that the alleged amounts owed may not include all environmental damages to which the USFS may be entitled and which the U.S. may seek to recover if further action is taken to resolve the debt. Additional charges for interest, penalties and administrative costs may also be sought associated with amounts considered overdue. In January 2024, PacifiCorp received correspondence from the U.S. Department of Justice ("USDOJ") indicating its intent to litigate the matter due to PacifiCorp not having paid the $356 million. PacifiCorp is actively cooperating with the USDOJ on resolving these alleged claims, including through the pursuit of alternative dispute resolution.

2020 Oregon Wildfires, Excluding Slater Fire

As described below, a significant number of complaints on behalf of plaintiffs associated with the 2020 Wildfires have been filed in Oregon in addition to those described above for the Slater Fire. The plaintiffs generally allege: (i) negligence due in part to alleged failure to comply with certain Oregon statutes and administrative rules, including those issued by the OPUC; (ii) gross negligence alleged in the form of willful, wanton and reckless disregard of known risks to the public; (iii) trespass; (iv) nuisance; (v) inverse condemnation; (vi) prejudgment interest; and (vii) reasonable attorney fees, investigation costs and expert witness fees. The complaints generally assert claims for: (i) noneconomic damages, including mental suffering, emotional distress, inconvenience and interference with normal and usual activities; (ii) damages for real and personal property and other economic losses; (iii) double the amount of property and economic damages; (iv) treble damages for specific costs associated with loss of forestry, trees and shrubbery; and (v) double the damages for the costs of litigation and reforestation. Certain complaints include wrongful death claims as described below. The plaintiffs generally demand a trial by jury and reserve their right to further amend their complaints to allege claims for punitive damages.

93

Jeanyne James et al. v. PacifiCorp and Consolidated Cases

On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885, in Multnomah County Circuit Court, Oregon ("James"). The complaint was filed by Oregon residents and businesses who sought to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. On November 3, 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Echo Mountain Complex, South Obenchain, 242 and Santiam Canyon fires, as well as to add claims for noneconomic damages. The amended complaint alleged that PacifiCorp's assets contributed to the Oregon wildfires occurring on or after September 7, 2020, and that PacifiCorp acted with gross negligence, among other things. The amended complaint 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.

On April 24, 2023, the jury trial for James with respect to the 17 named plaintiffs began in Multnomah County Circuit Court. In June 2023, the jury issued its verdict finding PacifiCorp liable to the 17 named plaintiffs and to the class with respect to the four wildfires. The jury found PacifiCorp's conduct grossly negligent, reckless and willful as to each plaintiff and the entire class. The jury awarded the 17 named plaintiffs $90 million of damages, including $4 million of economic damages, $68 million of noneconomic damages and $18 million of punitive damages based on a 0.25 multiplier of the economic and noneconomic damages.

In September 2023, the Multnomah County Circuit Court ordered trial dates for two consolidated jury trials including approximately 10 class members each and a third trial for certain commercial timber plaintiffs wherein plaintiffs in each of the three damages phase trials will present evidence regarding their damages. The first of these trials addressing nine individual plaintiffs was held in January 2024 while the remaining trials are scheduled at various dates through April 2024.

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

In January 2024, the jury for the first James damages phase trial awarded nine plaintiffs $62 million of damages, including $6 million of economic damages and $56 million of noneconomic damages. After the jury verdict, the Multnomah County Circuit Court doubled the economic damages to $12 million and added $16 million of punitive damages using the 0.25 multiplier determined by the jury for the June 2023 James verdict. PacifiCorp will request that the Multnomah County Circuit Court judge offset the damage awards by deducting insurance proceeds received by any of the nine plaintiffs. PacifiCorp intends to appeal the jury's damage awards associated with the January 2024 jury verdict once judgement is entered.

The following cases have been consolidated into the James case:

Amended Salter filed August 20, 2021, in Multnomah County Circuit Court, Oregon by approximately 97 individuals. The complaint seeks damages similar to those described above, including economic damages not to exceed $150 million and noneconomic damages not to exceed $500 million.

Amended Allen filed September 2, 2021, in Multnomah County Circuit Court, Oregon by approximately five individuals. The Allen case seeks damages similar to those described above, including $8 million in economic and $24 million in noneconomic damages related to the Beachie Creek fire.

94

Dietrich filed August 26, 2022, in Multnomah County Circuit Court, Oregon. The complaint, as amended on September 6, 2022, was filed by six Oregon residents individually and on behalf of a class defined to include residents of, business owners in, real or personal property owners in and any other individuals physically present in specified Oregon counties as of September 7, 2020 who experienced any harm, damage or loss as a result of the Santiam Canyon, Echo Mountain Complex, 242 or South Obenchain fires. The amended complaint seeks $400 million in economic damages and $500 million in noneconomic damages. The Dietrich case is currently stayed due to plaintiffs' motion to consolidate the case into James.

Cady filed April 26,2022, in Multnomah County Circuit Court, Oregon. The Cady case was filed by 21 individuals seeking approximately $105 million in economic damages based on $5 million per each of the 21 individual plaintiffs in connection with the Echo Mountain Complex fire. The individual plaintiffs also seek noneconomic damages to be determined at trial. A jury trial is scheduled for May 6, 2024, through June 7, 2024.

Logan filed September 2, 2022, in Multnomah County Circuit Court, Oregon. The Logan case was filed by five individuals seeking approximately $35 million in economic damages based on $5 million for each of the four individual plaintiffs and $15 million for the one non-individual plaintiff. A jury trial is scheduled for May 6, 2024, through June 7, 2024.

Bell filed September 7, 2022, in Multnomah County Circuit Court, Oregon by 59 plaintiffs seeking $35 million in damages, including economic and noneconomic damages.

Freres Timber filed September 1, 2022, in Multnomah County Circuit Court, Oregon. The complaint, as amended on October 18, 2023, was filed by three commercial plaintiffs seeking approximately $7 million in economic damages and $2 million of punitive damages. A jury trial is scheduled for April 22, 2024, through April 30, 2024.

CW Specialty Lumber, Inc. filed December 6, 2022, in Multnomah County Circuit Court, Oregon. The complaint, as amended on October 17, 2023, was filed by two commercial timber plaintiffs each seeking approximately $10 million in economic damages and $3 million in punitive damages. A jury trial is scheduled for April 22, 2024, through April 30, 2024.

In October 2022, the Multnomah County Circuit Court consolidated 21st Century Centennial Insurance Company, et al. v. PacifiCorp, Case No. 22CV26326 ("21st Century") and Allstate Vehicle and Property Insurance Company, et al. v. PacifiCorp, Case No. 22CV29976 ("Allstate") into James (described above). The 21st Century and Allstate complaints were each filed in Multnomah County Circuit Court, Oregon by subrogated insurance carriers resulting from the September 2020 Santiam Canyon, Echo Mountain Complex, 242 and South Obenchain fires. The 21st Century case was filed in August 2022 by 177 insurance carriers seeking not less than $20 million in monetary damages. The Allstate case was filed in September 2022 by 11 insurance carriers seeking not less than $40 million in monetary damages. In April 2023, PacifiCorp and the subrogated insurance carriers entered into a settlement agreement. In September 2023, PacifiCorp paid $55 million in settlements associated with the subrogation claims. As a result of the settlement, the 21st Century and Allstate cases have been dismissed.

Roseburg Resources Co et al. v. PacifiCorp and Consolidated Cases (Archie Creek Fire)

On March 17, 2022, a complaint against PacifiCorp was filed, captioned Roseburg Resources Co et al. v. PacifiCorp, Case No. 22CV09346 ("Roseburg") in Douglas County Circuit Court, Oregon. The complaint was filed by nine businesses and public pension plans that own or operate timberlands or possess property in Douglas County who allege damages, losses and injuries associated with their timberlands as a result of the French Creek, Archie Creek, Susan Creek and Smith Springs Road fires in Douglas County in September 2020. The complaint was amended in September 2023 and seeks economic damages of $195 million; attorney's fees, experts fees and other costs of $105 million; and pre-judgment interest of $43 million.

95

The following complaints were filed in Douglas County Circuit Court, Oregon with substantially similar allegations as those of Roseburg with the exception that certain of the complaints do not allege inverse condemnation. On February 9, 2023, in an oral ruling, the Douglas County Circuit Court ordered these seventeen cases consolidated for trial as to certain specified issues, along with the above-mentioned Roseburg case; the precise scope of the trial will be determined in a later order. Collectively, these eighteen cases seek economic damages of $531 million and noneconomic damages of $102 million, inclusive of the $195 million of economic damages in the Roseburg case. Moore filed November 1, 2022, approximately 8 plaintiffs; Blodgett filed November 1, 2022, approximately 11 plaintiffs; Ellis filed November 1, 2022, approximately 10 plaintiffs; Tague filed December 5, 2022, approximately 28 plaintiffs; Long filed December 5, 2022, approximately 33 plaintiffs; Moyers filed December 5, 2022, approximately 41 plaintiffs; Meyer filed January 6, 2023, approximately 11 plaintiffs; Foster filed January 17, 2023, approximately 44 plaintiffs; Hall filed January 17, 2023, approximately 39 plaintiffs; Jones filed January 17, 2023, approximately 47 plaintiffs; Price filed January 17, 2023, approximately 39 plaintiffs; Minott filed January 17, 2023, approximately 33 plaintiffs; Webb filed January 17, 2023, approximately 30 plaintiffs; Keith filed January 17, 2023, approximately 40 plaintiffs; Kidd filed January 24, 2023, approximately 12 plaintiffs; Parker filed January 24, 2023, approximately 16 plaintiffs; and Diaz filed January 24, 2023, approximately 14 plaintiffs.

On February 14, 2023, the Douglas County Circuit Court ordered that all plaintiffs' claims for inverse condemnation be dismissed.

In December 2023, PacifiCorp entered into settlement agreements with 463 claimants and 10 companies with commercial timber interests associated with the Archie Creek Fire generally associated with the consolidated Roseburg cases and paid $299 million to the 463 claimants and $250 million to the 10 companies with commercial timber interests. These settlements resolve substantially all claims filed by individual plaintiffs and all claims filed by commercial timber plaintiffs associated with the consolidated Roseburg cases and claims filed by certain of the plaintiffs associated with the Beamer case described below, but do not address related damages claimed by the U.S. or Oregon Departments of Justice also described below. As a result of the settlement, only the Lee, Beamer and insurance subrogation cases remain active; the Roseburg consolidated cases have been dismissed.

On September 1, 2022, a complaint against PacifiCorp associated with the Archie Creek Fire was filed captioned Leonard Mitchell Lee et. al v. PacifiCorp, Case No. 22CV29685 in Oregon Circuit Court in Multnomah County, Oregon by approximately five plaintiffs, seeking approximately $63 million in economic damages and $63 million in noneconomic damages and makes allegations similar to those described above.

On September 2, 2022, a complaint against PacifiCorp associated with the Archie Creek Fire was filed captioned Beamer et. al v. PacifiCorp, Case No. 22CV29851 in Oregon Circuit Court in Douglas County, Oregon by approximately 36 plaintiffs, seeking more than $190 million in economic damages based on $5 million for each of the 35 individual plaintiffs and $15 million for the one non-individual plaintiff and makes allegations similar to those described above. The individual plaintiffs also seek noneconomic damages to be determined at trial. As a result of the December 2023 settlement described above, claims associated with approximately 27 plaintiffs in the Beamer case were resolved.

A group of subrogation insurers that filed complaints against PacifiCorp associated with the Archie Creek Fire agreed to a mediator's proposal under which PacifiCorp will pay 51.75% of the total claims paid and to be paid by the carriers related to the Archie Creek Fire. In October 2022, PacifiCorp paid $24 million to the subrogation insurers. During 2023 and January 2024, PacifiCorp paid additional amounts to the subrogation insurers and ultimately expects to pay a total of $28 million to the subrogation insurers. While some of the subrogation complaints have been fully dismissed, the following remain active:

The Lexington complaint was filed against PacifiCorp by two insurers in Oregon Circuit Court in Douglas County, Oregon seeking $14 million in damages for negligence associated with the Archie Creek Fire and, as amended on February 3, 2022, make allegations similar to those described above. The Lexington case was partially dismissed following settlement, but general judgment of dismissal has not yet been entered because certain plaintiffs remain active.

The Certain Underwriters complaint was filed against PacifiCorp by four insurers in Oregon Circuit Court in Douglas County, Oregon on April 28, 2022 by multiple insurers seeking $14 million in damages for negligence associated with the Archie Creek Fire. The Certain Underwriters case remains pending because general judgment of dismissal has not yet been entered because certain plaintiffs remain active.

The Ace American Insurance Co. complaint was filed against PacifiCorp in Oregon Circuit Court in Douglas County, Oregon on August 25, 2022, by 15 insurers seeking approximately $24 million for negligence. The Ace American

96

Insurance case was partially dismissed following settlement, but general judgment of dismissal has not yet been entered because certain plaintiffs remain active.

Ashley Andersen et al. v. PacifiCorp and Consolidated Cases

On November 16, 2021, a complaint against PacifiCorp was filed in Multnomah County Circuit Court, Oregon, captioned Ashley Andersen et al. v. PacifiCorp, Case No. 21CV36567 ("Andersen"). The Andersen case was filed by approximately 50 Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The Andersen case as amended on December 6, 2022 makes allegations similar to those described above and seeks economic damages of approximately $83 million and noneconomic damages of approximately $83 million. Multiple complaints have been consolidated into Andersen as described below.

The following complaints also filed in Multnomah County Circuit Court, Oregon, have been consolidated into the Andersen case each with allegations and damages similar to those described above for the Andersen case and each seek economic damages of approximately $83 million and noneconomic damages of approximately $83 million unless otherwise noted: Klinger filed September 1, 2022, approximately 49 plaintiffs; Bowen filed September 1, 2022, approximately 47 plaintiffs; Weathers filed September 1, 2022, approximately 46 plaintiffs; Barnholdt filed September 6, 2022, approximately 26 plaintiffs; Pratt filed September 7, 2022, approximately 16 plaintiffs; Thompson filed September 7, 2022, approximately 49 plaintiffs; Cohn filed September 7, 2022, approximately 6 plaintiffs, $5 million for a wrongful death claim, $15 million in economic damages and $15 million in noneconomic damages; Sparks filed December 17, 2021 and amended on September 7, 2022, approximately 49 plaintiffs, various damages of approximately $125 million; Russie filed May 13, 2022, approximately 45 plaintiffs, various damages of approximately $125 million.

The Andersen case is set for trial starting August 19, 2024, through September 13, 2024.

Judith O'Keefe v. PacifiCorp and Consolidated Cases

On April 23, 2021, a complaint against PacifiCorp was filed, captioned Judith O'Keefe v. PacifiCorp, Case No. 21CV15857 ("O'Keefe") in Multnomah County Circuit Court, Oregon associated with the Beachie Creek Fire. The complaint, as amended on January 31, 2024, was filed by one individual plaintiff seeking damages similar to those described above, including approximately $1 million in economic damages and $1 million in noneconomic damages. A jury trial is scheduled for November 4, 2024, through November 29, 2024.

The following cases also associated with the Beachie Creek Fire have been consolidated into the O'Keefe case: Macy-Wyngarden filed September 1, 2022, in Multnomah County Circuit Court, Oregon, by approximately 12 plaintiffs seeking economic damages of approximately $83 million and noneconomic damages of approximately $83 million; Bogle filed September 1, 2022, in Multnomah County Circuit Court, Oregon, by approximately 39 plaintiffs seeking economic damages of approximately $83 million and noneconomic damages of approximately $83 million; Dodge filed September 8, 2022, in Multnomah County Circuit Court, Oregon, by two plaintiffs seeking $3 million in economic damages and $3 million in noneconomic damages.

Other Cases

On October 7, 2021, a complaint against PacifiCorp was filed captioned Estate of Cathy Lynn Cook et. al v. PacifiCorp, Case No. 21CV35076 ("Cook") in Oregon Circuit Court in Multnomah County, Oregon, approximately two plaintiffs, seeking a minor amount of economic damages and approximately $40 million in noneconomic damages associated with the Beachie Creek Fire, makes allegations similar to those described above and includes wrongful death claims. On February 5, 2024, the complaint was amended to add a request for $200 million in punitive damages. The Cook case is set for trial starting July 5, 2024, through July 19, 2024.

On October 7, 2021, a complaint against PacifiCorp was filed captioned Angela Mosso et. al v. PacifiCorp, Case No. 21CV35069 in Oregon Circuit Court in Multnomah County, Oregon, approximately four plaintiffs, seeking approximately $10 million in economic damages and $90 million in noneconomic damages associated with the Beachie Creek Fire, makes allegations similar to those described above and includes wrongful death claims. On February 5, 2024, the complaint was amended to add a request for $400 million in punitive damages. The Mosso case is set for trial starting August 5, 2024, through August 16, 2024.

97

On June 9, 2023, a complaint against PacifiCorp was filed captioned Annamarie Miller et. al v. PacifiCorp, Case No. 23CV23104 in Oregon Circuit Court in Multnomah County, Oregon, approximately 10 plaintiffs, seeking approximately $42 million in economic damages and $42 million in noneconomic damages associated with the Echo Mountain Fire and makes allegations similar to those described above.

On November 7, 2023, a complaint against PacifiCorp was filed captioned Cooper Mountain Winery LLC v. PacifiCorp, Case No. 23CV47202 in Oregon Circuit Court in Washington County, Oregon, seeking approximately $750,000 in economic damages associated with multiple fires and makes allegations similar to those described above.

On January 18, 2024, a complaint against PacifiCorp was filed captioned Sokol Blosser, Ltd. et. al v. PacifiCorp, Case No. 24CV03044 in Oregon Circuit Court in Multnomah County, Oregon, approximately nine plaintiffs, seeking approximately $20 million in economic damages associated with multiple fires and makes allegations similar to those described above.

On July 14, 2023, a complaint against PacifiCorp was filed captioned Elk Cove Vineyards, Inc. v. PacifiCorp, Case No. 23CV28258 in Oregon Circuit Court in Yamhill County, Oregon, one plaintiff, seeking approximately $3 million in economic damages associated with multiple fires and makes allegations similar to those described above.

On July 14, 2023, a complaint against PacifiCorp was filed captioned Retraite, LLC, et. al v. PacifiCorp, Case No. 23CV28213 in Oregon Circuit Court in Polk County, Oregon, approximately four plaintiffs, seeking approximately $4 million in economic damages associated with multiple fires and makes allegations similar to those described above.

On July 14, 2023, a complaint against PacifiCorp was filed captioned Brigadoon Vineyards, LLC v. PacifiCorp, Case No. 23CV28149 in Oregon Circuit Court in Lane County, Oregon seeking approximately $100,000 in economic damages associated with multiple fires and makes allegations similar to those described above.

On July 24, 2023, a complaint against PacifiCorp was filed captioned Willamette Valley Vineyards Inc v. PacifiCorp, Case No. 23CV29519 in Oregon Circuit Court in Marion County, Oregon seeking approximately $3 million in economic damages associated with multiple fires and makes allegations similar to those described above.

On September 1, 2022, a complaint against PacifiCorp was filed captioned Stroh Coastal Holdings LLC, v. PacifiCorp, Case No. 22CV29695 in Oregon Circuit Court in Multnomah County, Oregon, one plaintiff, seeking $1 million in economic damages associated with the Pike Road Fire and makes allegations similar to those described above.

In January 2024, PacifiCorp settled various claims for $3 million with approximately 14 plaintiffs associated with various 2020 Wildfire complaints in Oregon.

United States and State of Oregon – Loss and Damages to Federal and State Lands – Oregon Fires

PacifiCorp received correspondence from the USDOJ, representing the U.S. Department of the Interior, Bureau of Land Management, Bureau of Indian Affairs, Department of Agriculture and Forest Service, regarding the potential recovery of certain costs and damages alleged to have occurred to federal lands from the September 2020 Archie Creek and Susan Creek fires. The USDOJ estimates for mediation purposes only the costs and damages relating to reforestation, damaged timber and improvements, coordination with hydropower license, suppression costs and other assessment, cleanup and rehabilitation costs and damages at approximately $625 million. The amounts alleged for natural resource damage from these fires do not include intangible environmental and natural resource damages that the U.S. could potentially seek to recover if this matter was fully litigated, nor do they include multipliers which the agencies are allegedly entitled to collect under pertinent federal regulations, under which, for example, minimum damages for trespass to timber managed by the U.S. Department of Interior are twice the fair market value of the resource at the time of the trespass, or three times if the violation was willful.

PacifiCorp also received correspondence from the Oregon Department of Justice ("ODOJ"), representing the State of Oregon, regarding the potential recovery of losses and damages to state lands from the Archie Creek and Susan Creek fires. The ODOJ estimates for mediation purposes only losses and damages relating to the sheltering of, and assistance to, affected Oregonians, fire control and extinguishment costs, 39 acres of Oregon forestland, losses and damages at the Rock Creek Fish Hatchery, road and highway damages, and other costs, at approximately $109 million.

On October 12, 2023 and December 21, 2023, the Oregon Department of Forestry sent demand notices for fire suppression costs totaling $2 million for three separate ignition points associated with the 2020 Wildfires.

98

PacifiCorp is actively cooperating with both the USDOJ and ODOJ on resolving these alleged claims, including through the pursuit of alternative dispute resolution.

2022 McKinney Fire

Numerous complaints associated with the 2022 McKinney Fire have been filed in California Superior Court, Sacramento County, California on behalf of over 300 plaintiffs, including multiple insurers, as described below. The complaints generally allege: (i) inverse condemnation; (ii) negligence; (iii) trespass; (iv) nuisance; and (v) violation of certain sections of the California Public Utilities Code and the California Health & Safety Code, as well as, in limited cases, wrongful death claims. 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, Case No. 34-2022-00325257, in California Superior Court, Sacramento County, California ("Bridges") by approximately five plaintiffs. The following complaints were filed and subsequently consolidated into Bridges: Cogan filed August 23, 2022, approximately 12 plaintiffs, including a wrongful death claim; Shoopman filed August 26, 2022, approximately 61 plaintiffs, including a wrongful death claim; Lowe filed September 28, 2022, approximately two plaintiffs; Fraser filed November 9, 2022, approximately 180 plaintiffs; Muelrath filed January 18, 2023, approximately two plaintiffs; California Fair Plan Association, filed March 3, 2023, approximately 18 subrogation insurers; Corrales, filed April 6, 2023, approximately 30 plaintiffs; Murieen, filed April 20, 2023, approximately seven plaintiffs; Hickey, filed May 9, 2023, approximately five plaintiffs; and Volckhausen, filed May 9, 2023, one plaintiff; Huber, filed August 21, 2023, approximately three plaintiffs, including a wrongful death claim; CSAA filed December 21, 2023, one subrogation insurer.

In November 2023, PacifiCorp settled the Muelrath claims and the trial date was vacated.

On December 21, 2022, a complaint against PacifiCorp was filed, captioned Siskiyou County v. PacifiCorp, Case No. 2:22‑cv‑02278‑DMC, in the U.S. District Court for the Eastern District of California ("Siskiyou County") on behalf of a single plaintiff. A jury trial is scheduled for September 22, 2025.

On January 8, 2024, a complaint against PacifiCorp was filed, captioned Insurance Company of Hannover v. PacifiCorp, Case No. 24CV000183, in Sacramento Superior Court, California, by one subrogation plaintiff.

BERKSHIRE HATHAWAY ENERGY

HomeServices, a subsidiary of Berkshire Hathaway Energy, is currently defending against eleven antitrust cases, all in federal district courts. In each case, plaintiffs claim HomeServices (or, in one instance, Berkshire Hathaway) and certain of its subsidiaries conspired with co-defendants to artificially inflate real estate commissions by following and enforcing multiple listing service ("MLS") rules that require listing agents to offer a commission split to cooperating agents in order for the property to appear on the MLS ("Cooperative Compensation Rule"). None of the complaints specify damages sought. However, two cases allege Texas state law deceptive trade practices claims, for which plaintiffs have provided written notice of the damages sought totaling approximately $9 billion by separate notice as required by Texas law. The cases are captioned as follows.

In April 2019, the Burnett (formerly Sitzer) et al. v. HomeServices of America, Inc. et al., Case No. 19CV332, complaint was filed in the U.S. District Court for the Western District of Missouri (the "Burnett case"). This lawsuit, which was certified as a class in April 2022, was originally brought on behalf of named plaintiffs Joshua Sitzer and Amy Winger against the National Association of Realtors ("NAR"), Anywhere Real Estate (formerly Realogy Holdings Corp.), HomeServices of America, Inc., RE/MAX, LLC, and Keller Williams Realty, Inc. HSF Affiliates, LLC and BHH Affiliates, LLC, each a subsidiary of HomeServices, were subsequently added as defendants. Rhonda Burnett became a lead class plaintiff in June 2021. The jury trial commenced on October 16, 2023, and the jury returned a verdict for the plaintiffs on October 31, 2023, finding that the named defendants participated in a conspiracy to follow and enforce the Cooperative Compensation Rule, which 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 (formerly Realogy Holdings Corp.) and RE/MAX, LLC reached settlement agreements with the plaintiffs, which have not yet been approved by the court. Final judgment has not yet been entered by the U.S. District Court for the Western District of Missouri. HomeServices intends to vigorously appeal on multiple grounds the jury's findings and damage award in the Burnett case, including whether the case can proceed as a class action. The appeals process and further actions could take several years.

99

In March 2019, the Christopher Moehrl v. National Association of Realtors, et al. & Sawbill Strategic, Inc. v. HomeServices of America, Inc. et al., Case Nos. 19CV01610 and 19CV2544 (together "Moehrl") complaint was filed in the U.S. District Court for the Northern District of Illinois. This certified class action lawsuit was brought on behalf of named plaintiff Christopher Moehrl against the NAR, Anywhere Real Estate (formerly Realogy Holdings Corp.), HomeServices of America, Inc., HSF Affiliates, LLC, BHH Affiliates, LLC, Long & Foster Companies, Inc. (also a HomeServices subsidiary), RE/MAX, LLC and Keller Williams Realty, Inc.

In December 2020, the Nosalek (formerly Bauman) v. HomeServices of America, Inc. et al., Case No. 20CV1244, complaint was filed in the U.S. District Court for the District of Massachusetts. This putative class action lawsuit was originally filed on behalf of named plaintiffs Gary Bauman, Mary Jane Bauman, and Jennifer Nosalek against the MLS Property Information Network, Inc. (MassPIN), Anywhere Real Estate (formerly Realogy Holdings Corp.), HomeServices of America, Inc., BHH Affiliates, LLC, HSF Affiliates, LLC, RE/MAX, LLC, Keller Williams Realty, Inc. and additional named defendants. In October 2021, the Baumans voluntarily dismissed themselves from the case, removing them as class representatives.

In January 2021, the Batton (formerly Leeder) v. HomeServices of America, Inc. et al., Case No. 21CV00430, complaint was filed in the U.S. District Court for the Northern District of Illinois. This putative class action lawsuit was originally brought on behalf of former named plaintiff Judah Leeder against the NAR, HomeServices of America, Inc. HSF Affiliates, LLC, BHH Affiliates, LLC, Long & Foster Companies, Inc. (also a HomeServices subsidiary), Anywhere Real Estate (formerly Realogy Holdings Corp.), RE/MAX, LLC and Keller Williams Realty, Inc. Mya Batton replaced Leeder as class representative in July 2022. This case has been brought on behalf of a putative class of real estate buyers; all other referenced cases have been brought on behalf of real estate sellers. On February 20, 2024, the court entered an order dismissing HomeServices of America, Inc., HSF Affiliates, LLC, BHH Affiliates, LLC and Long & Foster Companies, Inc. from the case without prejudice.

In November 2023, the QJ v. HomeServices of America, Inc. et al., Case No. 23CV01013, complaint was filed in the U.S. District Court for the Eastern District of Texas. This putative class action lawsuit was brought on behalf of named plaintiff QJ Team, LLC against the Texas Association of Realtors, Inc., HomeServices of America, Inc., ABA Management, L.L.C. (a HomeServices subsidiary), Ebby Halliday Real Estate, LLC (a HomeServices subsidiary), Keller Williams Realty, Inc. and additional named defendants.

In December 2023, the Martin v. HomeServices of America, Inc. et al., Case No. 23CV01104, complaint was filed in the U.S. District Court for the Eastern District of Texas. This putative class action lawsuit was brought on behalf of named plaintiff Julie Martin against the Texas Association of Realtors, Inc., HomeServices of America, Inc., ABA Management, L.L.C., Ebby Halliday Real Estate, LLC, Keller Williams Realty, Inc. and additional named defendants.

In December 2023, the Umpa v. HomeServices of America, Inc. et al., Case No. 23CV00945, complaint was filed in the U.S. District Court for the Western District of Missouri. This putative class action lawsuit was brought on behalf of named plaintiff Daniel Umpa against the NAR, HomeServices of America, Inc., BHH Affiliates, LLC, HSF Affiliates, LLC, Long & Foster Companies, Inc., Keller Williams Realty, Inc. and additional named defendants.

In January 2024, the Masiello v. Roy H. Long Realty, Inc. d/b/a Long Realty et al., Case No. 24CV00045, complaint was filed in the U.S. District Court for the District of Arizona. This putative class action lawsuit was brought on behalf of named plaintiff Joseph Masiello against the Arizona Association of Realtors, Roy H. Long Realty, Inc. d/b/a Long Realty (a HomeServices of America, Inc. subsidiary) and additional named defendants.

In January 2024, the Fierro v. BHH Affiliates, LLC, et al., Case No. 24CV00449, complaint was filed in the U.S. District Court for the Central District of California. This putative class action lawsuit was brought on behalf of named plaintiffs Gael Fierro and Patrick Thurber against the NAR, Berkshire Hathaway Inc., BHH Affiliates, LLC and additional named defendants.

In January 2024, the Whaley v. Berkshire Hathaway HomeServices Nevada Properties et al., Case No. 24CV00105, amended complaint was filed in the U.S. District Court for the District of Nevada. This putative class action lawsuit was brought on behalf of named plaintiff Nathaniel Whaley against the NAR, Berkshire Hathaway HomeServices Nevada Properties (a HomeServices of America, Inc. subsidiary) and additional named defendants.

In February 2024, the Jensen v. HomeServices of America, Inc., et al., Case No. 24CV00109, complaint was filed in the U.S. District Court for the District of Utah. The putative class action lawsuit was brought on behalf of named plaintiff Dalton Jensen against the NAR, Anywhere Real Estate, Inc., HomeServices of America, Inc., HSF Affiliates, LLC, BHH Affiliates, LLC and additional named defendants.

100

In February 2024, the Boykin v. BHH Affiliates, LLC, et al., Case No. 24CV00340, compliant was filed in the U.S. District Court for the District of Nevada. This putative class action lawsuit was brought on behalf of named plaintiff Angela Boykin against the NAR, BHH Affiliates, LLC and additional named defendants.

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 Reform Act is included in Exhibit 95 to this Form 10-K.

101

PART II

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

BERKSHIRE HATHAWAY ENERGY

BHE's common stock is beneficially owned by Berkshire Hathaway and family members and related or affiliated entities of the late Mr. Walter Scott, Jr., a former member of BHE's Board of Directors, and has not been registered with the SEC pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly held or traded. BHE has not declared or paid any cash dividends to its common shareholders since Berkshire Hathaway acquired an equity ownership interest in BHE in March 2000 and does not presently anticipate that it will declare any dividends on its common stock in the foreseeable future.

PACIFICORP

All common stock of PacifiCorp is held by its parent company, PPW Holdings LLC, which is a direct, wholly owned subsidiary of BHE. PacifiCorp declared and paid dividends to PPW Holdings LLC of $300 million in 2023, $100 million in 2022 and $150 million in 2021.

MIDAMERICAN FUNDING AND MIDAMERICAN ENERGY

All common stock of MidAmerican Energy is held by its parent company, MHC, which is a direct, wholly owned subsidiary of MidAmerican Funding. MidAmerican Funding is an Iowa limited liability company whose membership interest is held solely by BHE. MidAmerican Funding declared and paid cash distributions to BHE of $425 million in 2024, $1,025 million in 2023, $69 million in 2022 and $— million in 2021. MidAmerican Energy declared and paid cash dividends to MHC totaling $425 million in 2024, $1,025 million in 2023, $275 million in 2022 and $— million in 2021.

NEVADA POWER

All common stock of Nevada Power is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE. Nevada Power declared and paid dividends to NV Energy of $50 million in 2023, $— million in 2022 and $213 million in 2021.

SIERRA PACIFIC

All common stock of Sierra Pacific is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE. Sierra Pacific declared and paid dividends to NV Energy of $150 million in 2024, $100 million in 2023, $70 million in 2022 and $— million in 2021.

EASTERN ENERGY GAS

Eastern Energy Gas is a Virginia limited liability corporation whose membership interest is held solely by its parent company, BHE GT&S, which is an indirect, wholly owned subsidiary of BHE. Eastern Energy Gas declared and paid dividends to BHE GT&S of $332 million in 2023, $— million in 2022 and $— million in 2021.

EGTS

All common stock of EGTS is held by its parent company, Eastern Energy Gas, which is an indirect, wholly owned subsidiary of BHE. EGTS declared and paid dividends to Eastern Energy Gas of $158 million in 2023, $215 million million in 2022 and $18 million in 2021.

102

Item 6.    [Reserved]

Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

Berkshire Hathaway Energy Company and its subsidiaries	106
PacifiCorp and its subsidiaries	201
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company	265
Nevada Power Company and its subsidiaries	334
Sierra Pacific Power Company and its subsidiaries	373
Eastern Energy Gas Holdings, LLC and its subsidiaries	413
Eastern Gas Transmission and Storage, Inc. and its subsidiaries	452

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

Berkshire Hathaway Energy Company and its subsidiaries	123
PacifiCorp and its subsidiaries	215
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company	278
Nevada Power Company and its subsidiaries	344
Sierra Pacific Power Company and its subsidiaries	383
Eastern Energy Gas Holdings, LLC and its subsidiaries	419
Eastern Gas Transmission and Storage, Inc. and its subsidiaries	457

103

Item 8.    Financial Statements and Supplementary Data

Berkshire Hathaway Energy Company and its subsidiaries
Report of Independent Registered Public Accounting Firm	129
Consolidated Balance Sheets	132
Consolidated Statements of Operations	134
Consolidated Statements of Comprehensive Income	135
Consolidated Statements of Changes in Equity	136
Consolidated Statements of Cash Flows	137
Notes to Consolidated Financial Statements	138
PacifiCorp and its subsidiaries
Report of Independent Registered Public Accounting Firm	219
Consolidated Balance Sheets	222
Consolidated Statements of Operations	224
Consolidated Statements of Comprehensive Income	225
Consolidated Statements of Changes in Shareholders' Equity	226
Consolidated Statements of Cash Flows	227
Notes to Consolidated Financial Statements	228
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm	281
Balance Sheets	283
Statements of Operations	285
Statements of Changes in Shareholder's Equity	286
Statements of Cash Flows	287
Notes to Financial Statements	288
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm	318
Consolidated Balance Sheets	320
Consolidated Statements of Operations	322
Consolidated Statements of Changes in Member's Equity	323
Consolidated Statements of Cash Flows	324
Notes to Consolidated Financial Statements	325
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm	347
Consolidated Balance Sheets	349
Consolidated Statements of Operations	350
Consolidated Statements of Changes in Shareholder's Equity	351
Consolidated Statements of Cash Flows	352
Notes to Consolidated Financial Statements	353
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm	386
Consolidated Balance Sheets	388
Consolidated Statements of Operations	389
Consolidated Statements of Changes in Shareholder's Equity	390
Consolidated Statements of Cash Flows	391
Notes to Consolidated Financial Statements	392
Eastern Energy Gas Holdings, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm	422
Consolidated Balance Sheets	424
Consolidated Statements of Operations	426
Consolidated Statements of Comprehensive Income	427
Consolidated Statements of Changes in Equity	428
Consolidated Statements of Cash Flows	429
Notes to Consolidated Financial Statements	430
Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Report of Independent Registered Public Accounting Firm	460
Consolidated Balance Sheets	462
Consolidated Statements of Operations	464
Consolidated Statements of Comprehensive Income	465
Consolidated Statements of Changes in Shareholder's Equity	466
Consolidated Statements of Cash Flows	467
Notes to Consolidated Financial Statements	468

104

Berkshire Hathaway Energy Company and its subsidiaries

Consolidated Financial Section

105

Item 7.    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 Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. The Company's actual results in the future could differ significantly from the historical results.

The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other corporate entities, corporate functions and intersegment eliminations. Effective January 1, 2023, the Company's unregulated retail energy services business was transferred to a subsidiary of BHE Renewables. Prior period amounts, which were previously reported in BHE and Other, have been reclassified to reflect this activity in BHE Renewables.

Results of Operations

Overview

Operating revenue and earnings on common shares for the Company's reportable segments for the years ended December 31 are summarized as follows (in millions):

	2023		2022		Change				2022		2021		Change
Operating revenue:
PacifiCorp	$	5,936	$	5,679	$	257	5	%	$	5,679	$	5,296	$	383	7	%
MidAmerican Funding	3,393		4,025		(632)		(16)		4,025		3,547		478		13
NV Energy	4,523		3,824		699		18		3,824		3,107		717		23
Northern Powergrid	1,303		1,365		(62)		(5)		1,365		1,188		177		15
BHE Pipeline Group	3,774		3,844		(70)		(2)		3,844		3,544		300		8
BHE Transmission	799		732		67		9		732		731		1		—
BHE Renewables	1,710		1,737		(27)		(2)		1,737		1,661		76		5
HomeServices	4,322		5,268		(946)		(18)		5,268		6,215		(947)		(15)
BHE and Other	(158)		(137)		(21)		15		(137)		(139)		2		(1)
Total operating revenue	$	25,602	$	26,337	$	(735)	(3)	%	$	26,337	$	25,150	$	1,187	5	%
Earnings on common shares:
PacifiCorp	$	(468)	$	921	$	(1,389)	(151)	%	$	921	$	889	$	32	4	%
MidAmerican Funding	980		947		33		3		947		883		64		7
NV Energy	394		427		(33)		(8)		427		439		(12)		(3)
Northern Powergrid	165		385		(220)		(57)		385		247		138		56
BHE Pipeline Group	1,079		1,040		39		4		1,040		807		233		29
BHE Transmission	246		247		(1)		—		247		247		—		—
BHE Renewables(1)	518		643		(125)		(19)		643		459		184		40
HomeServices	13		100		(87)		(87)		100		387		(287)		(74)
BHE and Other	59		(2,035)		2,094		*		(2,035)		1,311		(3,346)		*
Total earnings on common shares	$	2,986	$	2,675	$	311	12	%	$	2,675	$	5,669	$	(2,994)	(53)	%

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

*    Not meaningful.

106

Earnings on common shares increased $311 million for 2023 compared to 2022. Included in these results was a pre-tax gain in 2023 of $639 million ($505 million after-tax) compared to a pre-tax loss in 2022 of $1,950 million ($1,540 million after-tax) related to the Company's investment in BYD Company Limited ("BYD"). Excluding the impact of this item, adjusted earnings on common shares in 2023 was $2,481 million, a decrease of $1,734 million, or 41%, compared to adjusted earnings on common shares in 2022 of $4,215 million.

The increase in earnings on common shares for 2023 compared to 2022 was primarily due to:

•The Utilities' earnings decreased $1,389 million largely due to an increase in wildfire loss accruals, net of expected insurance recoveries, of $1,613 million, higher operations and maintenance expense, increased interest expense and lower electric utility margin. These items were offset by lower depreciation and amortization expense, higher allowances for equity and borrowed funds used during construction, increased interest and dividend income and favorable changes in the cash surrender value of corporate-owned life insurance policies. Electric retail customer volumes decreased 0.8% for 2023 compared to 2022, primarily due to the unfavorable impact of weather, partially offset by higher customer usage and an increase in the average number of customers;

•Northern Powergrid's earnings decreased $220 million, primarily due to the write-off of gas exploration costs of $92 million, unfavorable operating performance at CE Gas, higher deferred income tax expense, including amounts related to the enactment of a new Energy Profits Levy income tax at the CE Gas business, and increased non-service benefit plan costs. Units distributed declined 3.3% due to the unfavorable impact of weather and lower customer usage;

•BHE Pipeline Group's earnings increased $39 million, primarily due to the impact of a general rate case at Northern Natural Gas and higher earnings from Cove Point, primarily due to the acquisition of DEI's 50% limited partner interests in Cove Point on September 1, 2023, partially offset by higher operations and maintenance expense;

•BHE Renewables' earnings decreased $125 million, primarily due to lower earnings from wind tax equity investments, mainly due to lower PTCs, lower earnings from the retail energy service business, largely due to unfavorable changes in unrealized positions on derivative contracts, and lower operating revenue from owned renewable energy projects, partially offset by favorable derivative contract valuations and gains on the extinguishment of debt at owned wind projects;

•HomeServices' earnings decreased $87 million, primarily due to lower earnings from brokerage, settlement and mortgage services, reflecting the impact of rising interest rates and a corresponding decline in home sales; and

•BHE and Other's earnings increased $2,094 million, primarily due to the $2,045 million favorable comparative change in fair value related to the Company's investment in BYD.

Earnings on common shares decreased $2,994 million for 2022 compared to 2021. Included in these results was a pre-tax loss in 2022 of $1,950 million ($1,540 million after-tax) compared to a pre-tax gain in 2021 of $1,796 million ($1,777 million after-tax) related to the Company's investment in BYD. Excluding the impact of this item, adjusted earnings on common shares in 2022 was $4,215 million, an increase of $323 million, or 8%, compared to adjusted earnings on common shares in 2021 of $3,892 million.

The decrease in earnings on common shares for 2022 compared to 2021 was primarily due to:

•The Utilities' earnings increased $84 million reflecting higher electric utility margin and higher PTCs recognized of $157 million, partially offset by higher operations and maintenance expense and higher depreciation and amortization expense. Electric retail customer volumes increased 2.4% for 2022 compared to 2021, primarily due to higher customer usage, an increase in the average number of customers and the favorable impact of weather;

•Northern Powergrid's earnings increased $138 million, primarily due to a deferred income tax charge of $109 million related to a June 2021 enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023 and favorable earnings from new gas and solar projects, partially offset by $41 million from the stronger U.S. dollar;

•BHE Pipeline Group's earnings increased $233 million due to higher earnings at BHE GT&S from the impacts of the EGTS general rate case, favorable income tax adjustments, lower operations and maintenance expense and higher margin from non-regulated activities;

•BHE Renewables' earnings increased $184 million, primarily due to higher operating revenue from owned renewable energy projects and higher earnings from wind tax equity investments, mainly due to the unfavorable impacts from the February 2021 polar vortex weather event;

107

•HomeServices' earnings decreased $287 million, reflecting lower earnings from brokerage and settlement services largely attributable to a decrease in closed units at existing companies and lower earnings from mortgage services mainly from a decrease in funded volumes; and

•BHE and Other's earnings decreased $3,346 million, primarily due to the $3,317 million unfavorable comparative change in fair value related to the Company's investment in BYD.

Reportable Segment Results

PacifiCorp

Operating revenue increased $257 million for 2023 compared to 2022, primarily due to higher retail revenues of $350 million, partially offset by lower wholesale and other revenue of $93 million. Retail revenue increased primarily due to price impacts of $389 million from higher average rates, largely due to tariff changes and sales mix, partially offset by $39 million from lower retail volumes. Retail customer volumes decreased 0.8%, primarily due to the unfavorable impact of weather and lower customer usage, partially offset by an increase in the average number of customers. Wholesale and other revenue decreased mainly due to lower wholesale volumes, partially offset by higher average wholesale prices.

Earnings decreased $1,389 million for 2023 compared to 2022, primarily due to an increase in wildfire loss accruals, net of expected insurance recoveries, of $1,613 million, higher operations and maintenance expense of $304 million, increased interest expense of $115 million due to debt issuances in December 2022 and May 2023, unfavorable property and other taxes of $20 million and lower utility margin of $10 million. These items were partially offset by higher allowances for equity and borrowed funds used during construction of $112 million, increased interest and dividend income of $54 million, a favorable income tax benefit from valuation changes on state net operating loss carryforwards of $31 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $10 million. Operations and maintenance expense increased due to increased wildfire mitigation and vegetation management costs, higher insurance premiums, increased general and plant maintenance costs and higher legal expenses. Utility margin decreased primarily due to higher purchased power costs and lower wholesale and retail volumes, partially offset by higher retail rates, favorable deferred net power costs, lower thermal generation costs and higher average wholesale prices.

Operating revenue increased $383 million for 2022 compared to 2021, primarily due to higher retail revenue of $263 million, and higher wholesale and other revenue of $120 million, largely from higher average wholesale prices. Retail revenue increased primarily due to price impacts of $166 million from higher average rates largely due to sales mix and tariff changes and $97 million from higher retail volumes. Retail customer volumes increased 1.6%, primarily due to the favorable impact of weather and an increase in the average number of customers, partially offset by lower customer usage.

Earnings increased $32 million for 2022 compared to 2021, primarily due to higher utility margin of $235 million and higher allowances for equity and borrowed funds used during construction of $28 million, partially offset by higher operations and maintenance expense of $196 million, higher depreciation and amortization expense of $32 million, mainly from additional assets placed in-service, unfavorable changes in the cash surrender value of corporate-owned life insurance policies and an unfavorable income tax benefit. Utility margin increased primarily due to favorable deferred net power costs, higher retail rates and volumes and higher average wholesale prices, partially offset by higher purchased power and thermal generation costs. Operations and maintenance expense increased mainly due to an increase in wildfire loss accruals, net of expected insurance recoveries of $64 million and higher general and plant maintenance costs. The unfavorable income tax benefit was largely due to state income tax impacts, partially offset by higher PTCs recognized of $21 million.

MidAmerican Funding

Operating revenue decreased $632 million for 2023 compared to 2022, primarily due to lower natural gas operating revenue of $317 million and lower electric operating revenue of $315 million. Natural gas operating revenue decreased due to a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $311 million (fully offset in cost of sales) and the unfavorable impact of weather of $19 million, partially offset by higher average rates of $11 million. Electric operating revenue decreased due to lower wholesale and other revenue of $299 million and lower retail revenue of $16 million. Electric wholesale and other revenue decreased mainly due to lower average wholesale prices of $203 million and lower wholesale volumes of $94 million. Electric retail revenue decreased primarily due to lower recoveries through adjustment clauses of $29 million (fully offset in expense, primarily cost of sales), partially offset by $7 million from higher retail volumes and price impacts of $6 million from changes in sales mix. Electric retail customer volumes increased 1.3%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather.

108

Earnings increased $33 million for 2023 compared to 2022, primarily due to lower depreciation and amortization expense of $260 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $39 million, partially offset by lower electric utility margin of $137 million, an unfavorable income tax benefit from the effects of ratemaking of $40 million and lower PTCs recognized of $29 million, increased interest expense of $29 million due to a September 2023 debt issuance and higher operations and maintenance expense of $23 million. Depreciation and amortization expense decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Electric utility margin decreased primarily due to lower wholesale and retail revenues, partially offset by lower purchased power and thermal generation costs. Operations and maintenance expense increased mainly due to higher administrative and other costs, increased general and plant maintenance costs and higher property insurance costs.

Operating revenue increased $478 million for 2022 compared to 2021, primarily due to higher electric operating revenue of $459 million and higher natural gas operating revenue of $27 million. Electric operating revenue increased due to higher wholesale and other revenue of $261 million and higher retail revenue of $198 million. Electric wholesale and other revenue increased mainly due to higher average wholesale prices of $229 million and higher wholesale volumes of $36 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $134 million (fully offset in expense, primarily cost of sales) and higher customer volumes of $62 million. Electric retail customer volumes increased 4.3%, primarily due to higher customer usage and the favorable impact of weather. Natural gas operating revenue increased due to higher customer usage of $9 million, the favorable impact of weather of $9 million and the impacts of tax reform of $5 million.

Earnings increased $64 million for 2022 compared to 2021, primarily due to higher electric utility margin of $319 million, a favorable income tax benefit and higher natural gas utility margin of $25 million, partially offset by higher depreciation and amortization expense of $254 million, higher operations and maintenance expense of $53 million, unfavorable changes in the cash surrender value of corporate-owned life insurance policies and higher non-service benefit plan costs of $17 million. Electric utility margin increased primarily due to higher wholesale and retail revenues, partially offset by higher purchased power and thermal generation costs. The favorable income tax benefit was mainly due to higher PTCs recognized of $136 million, partially offset by state income tax impacts. Depreciation and amortization expense increased primarily from the impacts of certain regulatory mechanisms and additional assets placed in-service. Operations and maintenance expense increased due to higher general and plant maintenance costs.

NV Energy

Operating revenue increased $699 million for 2023 compared to 2022, primarily due to higher electric operating revenue of $626 million and higher natural gas operating revenue of $69 million largely from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric operating revenue increased primarily due to higher fully bundled energy rates (fully offset in cost of sales) of $649 million and increased base tariff general rates of $39 million at Sierra Pacific, partially offset by lower customer volumes of $44 million and lower regulatory-related revenue deferrals of $34 million. Electric retail customer volumes decreased 2.6%, primarily due to the unfavorable impact of weather and lower customer usage, partially offset by an increase in the average number of customers.

Earnings decreased $33 million for 2023 compared to 2022, primarily due to higher depreciation and amortization expense of $49 million largely due to additional assets placed in-service, increased interest expense of $38 million due to higher outstanding long-term debt balances and higher average interest rates, higher operations and maintenance expense of $28 million and lower electric utility margin of $23 million, partially offset by higher allowances for equity and borrowed funds of $38 million, increased interest and dividend income of $30 million, mainly from carrying charges on higher deferred energy balances, and favorable changes in the cash surrender value of corporate-owned life insurance policies of $12 million. Operations and maintenance expense increased primarily due to higher general and plant maintenance costs and higher customer service operations costs, partially offset by lower earnings sharing accruals at Nevada Power. Electric utility margin decreased primarily due to lower retail customer volumes and lower regulatory-related revenue deferrals, partially offset by higher base tariff general rates at Sierra Pacific.

Operating revenue increased $717 million for 2022 compared to 2021, primarily due to higher electric operating revenue of $668 million and higher natural gas operating revenue of $51 million from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric operating revenue increased primarily due to higher fully-bundled energy rates (fully offset in cost of sales) of $636 million, higher regulatory-related revenue deferrals of $15 million and higher customer volumes of $6 million. Electric retail customer volumes increased 2.2%, primarily due to an increase in the average number of customers, partially offset by the unfavorable impact of weather.

109

Earnings decreased $12 million for 2022 compared to 2021, primarily due to higher operations and maintenance expense of $24 million, higher depreciation and amortization expense of $17 million, higher interest expense of $15 million, unfavorable changes in the cash surrender value of corporate-owned life insurance policies and higher non-service benefit plan costs of $11 million, partially offset by higher interest and dividend income of $36 million from carrying charges on regulatory balances and higher electric utility margin of $32 million. Operations and maintenance expense increased mainly due to higher general and plant maintenance costs and an unfavorable change in earnings sharing at the Nevada Utilities. Depreciation and amortization expense increased mainly from additional assets placed in-service. Electric utility margin increased mainly due to higher regulatory-related revenue deferrals of $15 million and higher electric retail customer volumes.

Northern Powergrid

Operating revenue decreased $62 million for 2023 compared to 2022, primarily due to lower revenue at CE Gas of $48 million and lower distribution revenue of $48 million, partially offset by higher non-regulated contracting revenue of $18 million and $11 million from the weaker U.S. dollar. CE Gas revenue decreased due to lower gas production volumes and prices from a gas project that commenced commercial operations in March 2022, partially offset by a solar project that commenced commercial operations in July 2022. Distribution revenue decreased primarily due to lower recoveries of Supplier of Last Resort payments of $47 million (largely offset in cost of sales) and a 3.3% decline in units distributed of $9 million, largely due to the unfavorable impact of weather and lower customer usage, partially offset by higher tariff rates of $10 million.

Earnings decreased $220 million for 2023 compared to 2022, primarily due to the write-off of gas exploration costs of $92 million, unfavorable operating performance at CE Gas of $61 million, higher deferred income tax expense, including amounts related to the enactment of a new Energy Profits Levy income tax at the CE Gas business, increased non-service benefit plan costs of $35 million and higher distribution-related operating and depreciation expenses of $18 million, partially offset by lower interest expense of $14 million. The unfavorable operating performance at CE Gas was largely due to lower gas production volumes and prices from a gas project that commenced commercial operations in March 2022, partially offset by a solar project that commenced commercial operations in July 2022.

Operating revenue increased $177 million for 2022 compared to 2021, primarily due to higher distribution revenue of $167 million and higher revenue at CE Gas of $158 million, due to a gas project that commenced commercial operation in March 2022 and a solar project that commenced commercial operation in July 2022, partially offset by $155 million from the stronger U.S. dollar. Distribution revenue increased primarily due to the recovery of Supplier of Last Resort payments of $135 million (largely offset in cost of sales) and higher tariff rates of $78 million, partially offset by a 4.6% decline in units distributed of $36 million.

Earnings increased $138 million for 2022 compared to 2021, primarily due to a deferred income tax charge of $109 million related to a June 2021 enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, higher distribution tariff rates and improved earnings of $47 million from the new gas and solar projects, partially offset by $41 million from the stronger U.S. dollar, lower units distributed and higher distribution-related operating and depreciation expenses of $25 million.

BHE Pipeline Group

Operating revenue decreased $70 million for 2023 compared to 2022, primarily due to lower operating revenue of $164 million at BHE GT&S and $29 million at Kern River, largely due to a decline in transportation revenue from lower rates and volumes, partially offset by higher operating revenue of $107 million at Northern Natural Gas. The decrease in operating revenue at BHE GT&S was primarily due to lower non-regulated revenue of $229 million (largely offset in cost of sales) from lower volumes and unfavorable commodity prices and lower volumes at EGTS primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $22 million, partially offset by an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $49 million, an increase in variable revenue related to natural gas storage park and loan activity of $17 million at EGTS and higher gas sales of $15 million at EGTS from operational and system balancing activities. The increase in operating revenue at Northern Natural Gas was largely due to the impacts of a general rate case of $117 million and higher transportation revenue of $57 million from higher rates, partially offset by lower gas sales of $74 million (largely offset in cost of sales) from system balancing activities.

110

Earnings increased $39 million for 2023 compared to 2022, primarily due to higher earnings of $74 million at Northern Natural Gas, partially offset by lower earnings of $25 million at Kern River, largely due to lower transportation revenue, and lower earnings of $19 million at BHE GT&S. The increase at Northern Natural Gas was primarily due to the impacts of the general rate case of $79 million and higher transportation revenue, partially offset by higher operations and maintenance expense of $34 million, an increase in depreciation and amortization expense of $16 million and unfavorable margin on gas sales from system balancing activities of $16 million. The decrease at BHE GT&S was primarily due to increased cost of gas of $72 million from system balancing activities at EGTS and the unfavorable revaluation of volumes retained at EGTS due to lower natural gas prices and higher operations and maintenance expense of $52 million, partially offset by higher earnings from Cove Point of $42 million, primarily due to the acquisition of DEI's 50% limited partner interests in Cove Point on September 1, 2023, and a $40 million earnings impact from the rate case settlement at EGTS in 2022. Operations and maintenance expense increased at BHE GT&S mainly due to higher compensation costs and higher technology and related charges.

Operating revenue increased $300 million for 2022 compared to 2021, primarily due to higher operating revenue of $242 million at BHE GT&S and $47 million at Northern Natural Gas. The increase in operating revenue at BHE GT&S was primarily due to higher non-regulated revenue of $109 million (largely offset in cost of sales) from favorable commodity prices, an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $101 million and higher LNG revenue of $56 million at Cove Point, largely from favorable variable revenue, partially offset by lower gas sales of $49 million at EGTS from system balancing activities. The increase in operating revenue at Northern Natural Gas was mainly due to higher transportation revenue of $63 million offset by lower gas sales of $14 million from system balancing activities. The variances in transportation revenue and gas sales included favorable impacts recognized of $49 million and $77 million, respectively, from the February 2021 polar vortex weather event. Excluding this item, transportation revenue increased $112 million due to higher volumes and rates and gas sales increased $63 million (largely offset in cost of sales).

Earnings increased $233 million for 2022 compared to 2021, primarily due to higher earnings of $232 million at BHE GT&S. Earnings at BHE GT&S increased mainly due to the impacts of the EGTS general rate case of $124 million, favorable income tax adjustments, lower operations and maintenance costs and a decrease in property and other tax expense of $30 million, higher margin of $26 million from non-regulated activities and increased earnings at Cove Point of $16 million.

BHE Transmission

Operating revenue increased $67 million for 2023 compared to 2022, primarily due to $69 million of incremental revenue from non-regulated wind-powered generating facilities acquired in November 2022 and higher other non-regulated revenue at BHE Canada, partially offset by $26 million from the stronger U.S. dollar.

Earnings decreased $1 million for 2023 compared to 2022, primarily due to $7 million from the stronger U.S. dollar, partially offset by the higher non-regulated revenue at BHE Canada.

Operating revenue increased $1 million for 2022 compared to 2021, primarily due to higher non-regulated revenue from wind-powered generating facilities, partially offset by $27 million from the stronger U.S. dollar.

Earnings for 2022 were equal to 2021, primarily due to improved equity earnings from ETT offset by $7 million from the stronger U.S. dollar.

BHE Renewables

Operating revenue decreased $27 million for 2023 compared to 2022, primarily due to lower solar and wind revenues of $78 million, largely from lower generation, and lower natural gas and electric retail energy services revenue of $56 million, partially offset by favorable changes in the valuations of certain derivative contracts of $76 million and higher natural gas revenue of $34 million from favorable generation and pricing. Retail energy services revenue decreased mainly due to unfavorable natural gas pricing, partially offset by an increase in natural gas volumes.

111

Earnings decreased $125 million for 2023 compared to 2022, primarily due to lower earnings from wind tax equity investments of $89 million, primarily due to lower PTCs and higher realized hedge losses, lower earnings of $70 million from the retail services business, largely due to unfavorable changes in unrealized positions on derivative contracts, lower solar earnings of $40 million from lower generation and lower geothermal and natural gas earnings of $7 million, partially offset by higher earnings at owned wind projects of $88 million. Geothermal and natural gas earnings were lower due to higher geothermal operating and maintenance costs related to storms and outages as well as higher geothermal development costs, partially offset by favorable pricing and generation at the natural gas generating facilities. Earnings from owned wind projects were higher primarily due to favorable derivative contract valuations and from gains on the extinguishment of debt, partially offset by a decrease in operating revenue from lower generation.

Operating revenue increased $76 million for 2022 compared to 2021, primarily due to higher wind, geothermal, and solar revenues of $140 million from higher generation and pricing, and higher natural gas and electric retail energy services revenue of $64 million due to favorable electric volumes and natural gas pricing, including changes in unrealized positions on derivative contracts, offset by lower electric pricing and natural gas volumes. These items were partially offset by lower natural gas revenues of $72 million from lower generation and pricing, lower hydro revenues of $28 million due to the transfer of the Casecnan generating facility to the Philippine government in December 2021 and $27 million from unfavorable changes in the valuation of certain derivative contracts.

Earnings increased $184 million for 2022 compared to 2021, primarily due to higher wind earnings of $214 million, higher geothermal earnings of $16 million and higher solar earnings of $14 million, partially offset by lower natural gas earnings of $44 million and lower hydro earnings of $18 million due to the Casecnan generating facility transfer. Wind earnings increased due to higher earnings from tax equity investments of $153 million, largely as a result of the unfavorable impacts recognized in 2021 from the February 2021 polar vortex weather event and higher production tax credits, and higher earnings from owned projects of $61 million.

HomeServices

Operating revenue decreased $946 million for 2023 compared to 2022, primarily due to lower brokerage and settlement services revenue of $873 million and lower mortgage revenue of $68 million. The decrease in brokerage and settlement services revenue resulted from a 19% decrease in closed transaction volume due to rising interest rates and a corresponding decline in home sales. The lower mortgage revenue was due to a 28% decrease in funded volume, primarily due to rising interest rates.

Earnings decreased $87 million for 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services of $78 million and mortgage services of $10 million. Earnings declined due to declines in closed brokerage transaction volume and mortgage funded volume, partially offset by favorable operating expenses primarily due to lower compensation costs.

Operating revenue decreased $947 million for 2022 compared to 2021, primarily due to lower brokerage and settlement services revenue of $637 million and lower mortgage revenue of $305 million. The decrease in brokerage and settlement services revenue resulted from an 11% decrease in closed transaction volume driven by 23% fewer closed units at existing companies resulting from rising interest rates and a corresponding slowdown in home sales offset by acquisitions and a 7% increase in average sales price. The lower mortgage revenue was due to a 40% decrease in funded volume, primarily due to a decline in refinance activity resulting from rising interest rates.

Earnings decreased $287 million for 2022 compared to 2021, primarily due to lower earnings from brokerage and settlement services of $142 million and mortgage services of $126 million, largely from declines in closed brokerage transaction volume and mortgage funded volume. Earnings at brokerage and settlement services declined due to the decrease in closed units at existing companies, partially offset by favorable operating expense variances.

BHE and Other

Earnings increased $2,094 million for 2023 compared to 2022, primarily due to the Company's investment in BYD including the $2,045 million favorable comparative change in fair value, favorable changes in the cash surrender value of corporate-owned life insurance policies of $45 million and $12 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway. These items were partially offset by unfavorable consolidated income tax adjustments, largely state related, totaling $48 million and higher BHE corporate interest expense of $52 million from an April 2022 debt issuance.

112

Earnings decreased $3,346 million for 2022 compared to 2021, primarily due to the Company's investment in BYD, including the $3,317 million unfavorable comparative change in fair value, lower consolidated state income tax benefits, higher BHE corporate interest expense from an April 2022 debt issuance and unfavorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by $75 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway and lower corporate costs.

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 this Form 10-K for further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of December 31, 2023, the Company's total net liquidity was as follows (in millions):

															BHE Pipeline
					MidAmerican		NV		Northern		BHE				Group and
	BHE		PacifiCorp		Funding		Energy		Powergrid		Canada		HomeServices		Other		Total
Cash and cash equivalents	$	166	$	138	$	637	$	58	$	44	$	66	$	280	$	176	$	1,565
Credit facilities(1)	3,500		2,000		1,509		1,000		346		850		1,500		—		10,705
Less:
Short-term debt	(1,935)		(1,604)		—		—		(92)		(97)		(420)		—		(4,148)
Tax-exempt bond support and letters of credit	—		(249)		(306)		—		—		(1)		—		—		(556)
Net credit facilities	1,565		147		1,203		1,000		254		752		1,080		—		6,001
Total net liquidity(2)	$	1,731	$	285	$	1,840	$	1,058	$	298	$	818	$	1,360	$	176	$	7,566
Credit facilities:
Maturity dates	2026		2026		2024, 2026		2026		2026		2024, 2026, 2027, 2028		2024

(1)    Includes $92 million drawn on capital expenditure and other uncommitted credit facilities at Northern Powergrid.

(2)    Excludes $900 million of available liquidity under a delayed draw term loan at PacifiCorp and $700 million from a credit facility at HomeServices that is unavailable due to borrowing restrictions pursuant to the credit agreement.

Refer to Note 9 of the Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the Company's credit facilities, letters of credit, equity commitments and other related items.

Operating Activities

Net cash flows from operating activities for the years ended December 31, 2023 and 2022 were $7.1 billion and $9.4 billion, respectively. The decrease was primarily due to unfavorable operating results, the timing of payments related to fuel and energy costs, a decrease in income tax receipts and changes in working capital.

Net cash flows from operating activities for the years ended December 31, 2022 and 2021 were $9.4 billion and $8.7 billion, respectively. The increase was primarily due to an increase in income tax receipts and improved operating results, partially offset by changes in regulatory assets and working capital.

113

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 years ended December 31, 2023 and 2022 were $(5.9) billion and $(7.8) billion, respectively. The change was primarily due to higher proceeds from sales and maturities, net of purchases, of U.S. Treasury Bills totaling $3.0 billion, higher proceeds from sales, net of purchases, of marketable securities of $316 million and lower cash paid for acquisitions, partially offset by higher capital expenditures of $1.6 billion. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Net cash flows from investing activities for the years ended December 31, 2022 and 2021 were $(7.8) billion and $(5.8) billion, respectively. The change was primarily due to the July 2021 receipt of $1.3 billion due to the termination of the second Purchase and Sale Agreement with Dominion Energy Questar Corporation, higher capital expenditures of $894 million and higher cash paid for acquisitions, partially offset by lower funding of tax equity investments. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the year ended December 31, 2023 were $(1.3) billion. Sources of cash totaled $7.1 billion and consisted of proceeds from subsidiary debt issuances of $4.1 billion and net proceeds from short-term debt totaling $3.0 billion. Uses of cash totaled $8.4 billion and consisted mainly of $3.3 billion for the purchase of Cove Point noncontrolling interest, repayments of subsidiary debt totaling $2.8 billion, repayments of BHE senior debt of $900 million, preferred stock redemptions totaling $850 million and distributions to noncontrolling interests of $395 million.

Net cash flows from financing activities for the year ended December 31, 2022 were $(1.0) billion. Sources of cash totaled $3.9 billion and consisted of proceeds from subsidiary debt issuances of $2.9 billion and proceeds from BHE senior debt issuances of $986 million. Uses of cash totaled $4.9 billion and consisted mainly of repayments of subsidiary debt totaling $1.5 billion, purchases of common stock of $870 million, net repayments of short-term debt totaling $867 million, preferred stock redemptions totaling $800 million and distributions to noncontrolling interests of $524 million.

Net cash flows from financing activities for the year ended December 31, 2021 were $(3.1) billion. Sources of cash totaled $2.4 billion and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $5.5 billion and consisted mainly of preferred stock redemptions totaling $2.1 billion, repayments of subsidiary debt totaling $2.0 billion, distributions to noncontrolling interests of $488 million, repayments of BHE senior debt totaling $450 million and net repayments of short-term debt totaling $276 million.

Recent Financing Transactions

In January and February 2024, the Company issued $5.1 billion of term debt with a weighted average interest rate of 5.4% and maturity dates ranging from 2029 to 2055 and repaid short term borrowings of approximately $2.8 billion.

Debt Repurchases

The Company may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Preferred Stock Redemptions

For the years ended December 31, 2023, 2022 and 2021, BHE redeemed at par 849,982, 800,006 and 2,100,012 shares of its 4.00% Perpetual Preferred Stock from certain subsidiaries of Berkshire Hathaway Inc. for $850 million, $800 million and $2.1 billion.

114

Common Stock Transactions

For the year ended December 31, 2022, BHE purchased 740,961 shares of its common stock held by Mr. Gregory E. Abel, BHE's Chair, for $870 million. The purchase was pursuant to the terms of BHE's Shareholders Agreement.

There were no common stock repurchases for the years ended December 31, 2023 and 2021.

Future Uses of Cash

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

Capital Expenditures

The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' 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. Expenditures for certain assets may ultimately include acquisitions of existing assets.

The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, by reportable segment for the years ended December 31 are as follows (in millions):

	Historical						Forecast
	2021		2022		2023		2024		2025		2026
PacifiCorp	$	1,513	$	2,166	$	3,226	$	3,577	$	3,545	$	3,492
MidAmerican Funding	1,912		1,869		1,833		1,880		2,761		2,792
NV Energy	749		1,113		1,797		1,840		2,200		2,945
Northern Powergrid	742		768		557		872		978		997
BHE Pipeline Group	1,128		1,157		1,294		1,177		1,241		1,038
BHE Transmission	279		200		206		330		441		447
BHE Renewables	227		140		177		638		197		193
HomeServices	42		48		41		40		43		41
BHE and Other(1)	19		44		17		24		12		20
Total	$	6,611	$	7,505	$	9,148	$	10,378	$	11,418	$	11,965

(1)BHE and Other includes intersegment eliminations.

115

	Historical						Forecast
	2021		2022		2023		2024		2025		2026
Electric transmission	$	799	$	1,693	$	1,802	$	2,121	$	2,445	$	2,804
Electric distribution	1,620		1,650		2,047		2,293		2,528		2,243
Wind generation	1,339		774		1,538		1,317		1,909		1,798
Natural gas transmission and storage	1,068		945		997		924		1,014		952
Electric battery and pumped hydro storage	23		16		371		350		572		1,103
Solar generation	157		422		271		224		584		1,067
Wildfire mitigation	83		188		352		409		364		368
Other	1,522		1,817		1,770		2,740		2,002		1,630
Total	$	6,611	$	7,505	$	9,148	$	10,378	$	11,418	$	11,965

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

•Electric transmission includes both growth and operating expenditures. Growth expenditures include spending for the following:

◦PacifiCorp's transmission investment primarily reflects planned costs for the following major transmission segments: the 416-mile, 500-kV high-voltage transmission line between the Aeolus substation near Medicine Bow, Wyoming and the Clover substation near Mona, Utah; the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation; the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho; the 14-mile, 345-kV high-voltage transmission line between the Oquirrh substation in the Salt Lake Valley and the Terminal substation near the Salt Lake City Airport; and the 200-mile, 500-kV high-voltage transmission line between the Anticline substation near Point of Rocks, Wyoming and the Populus substation in Downey, Idaho. Planned spending for major transmission segments that are expected to be placed in-service in 2024 through 2031 totals $694 million in 2024, $325 million in 2025 and $504 million in 2026.

◦Nevada Utilities' Greenlink Nevada transmission expansion program. The Nevada Utilities have received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation, near Yerington, Nevada to the Northwest substation, near Las Vegas, Nevada to the Harry Allen substation, near Las Vegas, Nevada; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation, near Yerington, Nevada to the Robinson Summit substation, near Ely, Nevada; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation, near Yerington, Nevada to the Mira Loma substations, near Yerington, Nevada; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation, near Yerington, Nevada to the Robinson Summit substation, near Ely, Nevada. Planned spending for the expansion program estimated to be placed in-service in 2027 through 2028 totals $281 million in 2024, $584 million in 2025 and $713 million in 2026.

◦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.

•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 needed 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.

•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 $608 million for 2023, $72 million for 2022 and $540 million for 2021. MidAmerican Energy placed in-service 200 MWs during 2023 and 294 MWs during 2021. Planned spending for the construction of additional wind-powered generating facilities totals $515 million in 2024, $1,196 million in 2025 and $998 million in 2026.

116

◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $47 million for 2023, $500 million for 2022 and $354 million for 2021. Planned spending for repowering totals $228 million in 2024, $382 million in 2025 and $601 million in 2026. MidAmerican Energy expects its repowered facilities to meet IRS guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service.

◦Construction of new wind-powered generating facilities and construction at existing wind-powered generating facility sites acquired from third parties at PacifiCorp totaling $735 million for 2023, $23 million for 2022 and $118 million for 2021. PacifiCorp placed in-service 42 MWs at the Foote Creek III and Foote Creek IV wind-powered generating facilities in 2023 and 516 MWs of new wind-powered generating facilities in 2021. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $478 million in 2024, $238 million in 2025 and $95 million in 2026 and is primarily for the Rock River I, Rock Creek I and Rock Creek II wind-powered generating facilities totaling approximately 640 MWs that are expected to be placed in-service in 2024 through 2025.

◦Construction of wind-powered generating facilities at BHE Renewables totaling $155 million for 2021. In May 2021, BHE Renewables completed the asset acquisition of a 54-MW wind-powered generating facility located in Iowa. In December 2021, BHE Renewables completed asset acquisitions of 158-MW and 200-MW wind-powered generating facilities located in Texas.

◦Repowering of wind-powered generating facilities at BHE Renewables totaling $39 million for 2023 and $45 million in 2022. BHE Renewables repowered facilities were placed in-service in the fourth quarter of 2023 and meet IRS guidelines for the re-establishment of PTCs for 10 years.

•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.

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

◦Construction at the Nevada Utilities of a 100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that will be developed in Clark County, Nevada, with commercial operation expected by early 2024, a 220-MW grid-tied battery energy storage system that was developed on the site of the retired Reid Gardner generating station in Clark County, Nevada with commercial operation being reached in December of 2023, a planned 400-MW battery energy storage system co-located with a 400MW solar photovoltaic facility that would be developed in Churchill County, Nevada with ownership share between Nevada Power and Sierra Pacific to be approved by the PUCN, with commercial operation expected by early 2026 and other planned electric battery storage systems.

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

◦Construction and operation of solar-powered generating facilities at MidAmerican Energy primarily consisting of 141 MWs of small- and utility-scale solar generation, all of which were placed in-service in 2022, with total spend of $13 million in 2023, $119 million in 2022 and $132 million in 2021. Planned spending for the construction and operation of additional solar-powered generating facilities totals $14 million in 2024, $82 million in 2025 and $30 million in 2026.

◦Construction of solar-powered generating facility at the Nevada Utilities includes expenditures for a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada, with commercial operation expected by early 2024. Also included is a planned 400-MW of co-located battery storage that would be developed in Churchill County, Nevada with ownership share between Nevada Power and Sierra Pacific to be approved by the PUCN, with commercial operation expected by early 2027 and other planned solar generating facilities.

◦Construction of solar-powered generating facilities at BHE Renewables' includes expenditures for a 48-MW solar photovoltaic facility with an additional 52 MWs of capacity of co-located battery storage in Kern County, California, with commercial operation expected in the fourth quarter of 2024, with total spend of $60 million for 2023 and $22 million for 2022. Planned spending totals $139 million in 2024.

117

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

◦Expenditures at PacifiCorp totaling $325 million in 2023, $159 million in 2022 and $64 million in 2021. Planned spending totals $374 million in 2024, $324 million in 2025 and $319 million in 2026 and is comprised of reducing wildfire risk in the FHCA by conversion of overhead systems to underground, replacing overhead bare wire conductor with covered conductors and deployment of advanced protection devices for faster fault detection. The efforts will also include an expansion of the weather station network and predictive tools for situational awareness across the entire service territory.

◦Expenditures at the Nevada Utilities totaling $20 million in 2023, $20 million in 2022 and $5 million in 2021. Planned spending totals $25 million in 2024, $31 million in 2025 and $36 million in 2026 is comprised of reducing wildfire risk in Tier 3 HTAs by rebuilding distribution lines with covered conductor, converting overhead distribution lines to underground and copper wire and pole replacement projects.

•Other capital expenditures 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 CCR.

Off-Balance Sheet Arrangements

The Company has certain investments that are accounted for under the equity method in accordance with GAAP. Accordingly, an amount is recorded on the Company's Consolidated Balance Sheets as an equity investment and is increased or decreased for the Company's pro-rata share of earnings or losses, respectively, less any dividends from such investments. Certain equity investments are presented on the Consolidated Balance Sheets net of investment tax credits.

As of December 31, 2023, the Company's investments that are accounted for under the equity method had short- and long-term debt of $2.8 billion, unused revolving credit facilities of $127 million and letters of credit outstanding of $88 million. As of December 31, 2023, the Company's pro-rata share of such short- and long-term debt was $1.4 billion, unused revolving credit facilities was $64 million and outstanding letters of credit was $43 million. The entire amount of the Company's pro-rata share of the outstanding short- and long-term debt and unused revolving credit facilities is non-recourse to the Company. The entire amount of the Company's pro-rata share of the outstanding letters of credit is recourse to the Company. Although the Company is generally not required to support debt service obligations of its equity investees, default with respect to this non-recourse short- and long-term debt could result in a loss of invested equity.

Material Cash Requirements

The Company has cash requirements that may affect its consolidated financial condition that arise primarily from long- and short-term debt (refer to Note 9, 10 and 11), operating and financing leases (refer to Note 6), firm commitments (refer to Note 16), letters of credit (refer to Note 9), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7), uncertain tax positions (refer to Note 12) and AROs (refer to Note 14). Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

The Company has cash requirements relating to interest payments of $39.6 billion on long-term debt, including $2.3 billion due in 2024.

Regulatory Matters

The Company is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding the Company's general regulatory framework and current regulatory matters.

118

Quad Cities Generating Station Operating Status

Constellation Energy Generation, LLC ("Constellation Energy"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, receives financial support for continued operation of Quad Cities Station from the zero emission standard enacted by the Illinois legislature in December 2016. The zero emission standard requires the Illinois Power Agency to purchase ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs provide Constellation Energy additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy does not receive additional revenue from the subsidy.

The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a state government-provided financial support program like the Illinois zero emission standard, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fueled resources.

On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expanded the breadth and scope of the PJM's MOPR, which became effective as of the PJM's capacity auction for the 2022-2023 planning year. While the FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC denied rehearing of that order on April 16, 2020. A number of parties, including Constellation Energy, have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Seventh Circuit. MidAmerican Energy cannot predict the outcome of this proceeding.

While this litigation is pending, the MOPR applied to Quad Cities Station in the capacity auction for the 2022-2023 planning year in May 2021, which prevented Quad Cities Station from clearing in that capacity auction.

At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. The PJM filed related tariff revisions with the FERC on July 30, 2021, and, on September 29, 2021, the PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR applied in the capacity auction for the 2023-2024 delivery year but did not restrict the offers of Quad Cities Station, which cleared in the capacity auction. Requests for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms were filed in October 2021 and denied by operation of law on November 4, 2021. Several parties have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Third Circuit.

Assuming the continued effectiveness of the Illinois zero emission standard, Constellation Energy no longer considers Quad Cities Station to be at heightened risk for early retirement. However, to the extent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement. The FERC provided no new mechanism for accommodating state-supported resources like Quad Cities Station other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. Depending on the outcome of the proceedings related to the PJM MOPR, the continued effectiveness of the Illinois zero emission standard may be undermined unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism, under which Quad Cities Station would be removed from the PJM's capacity auction.

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 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, local and international agencies. The Company 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 the Company 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 Item 1 of this Form 10-K for further discussion regarding environmental laws and regulations.

119

Collateral and Contingent Features

Debt of BHE and debt and preferred securities of certain of its subsidiaries are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of the rated company's ability to, in general, meet the obligations of its issued debt or preferred 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.

BHE and its subsidiaries have 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. The Company's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order 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.

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," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2023, the applicable entities' credit ratings from the recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2023, the Company would have been required to post $446 million of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.

Inflation

Historically, overall inflation and changing prices in the economies where BHE's subsidiaries operate have not had a significant impact on the Company's consolidated financial results. In the U.S. and Canada, the Regulated Businesses operate under cost-of-service based rate-setting structures administered by various state and provincial commissions and the FERC. Under these rate-setting structures, the Regulated Businesses are allowed to include prudent costs in their rates, including the impact of inflation. The price control formula used by the Northern Powergrid Distribution Companies incorporates the rate of inflation in determining rates charged to customers. BHE's subsidiaries attempt to minimize the potential impact of inflation on their operations through the use of fuel, energy and other cost adjustment clauses and bill riders, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

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. The following critical accounting estimates are impacted significantly by the Company's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with the Company's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

120

Accounting for the Effects of Certain Types of Regulation

The Regulated Businesses prepare their financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Regulated Businesses defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.

The Company continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit the Regulated Businesses' ability to recover their costs. The Company believes its application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at the federal, state and provincial levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as AOCI. Total regulatory assets were $5.6 billion and total regulatory liabilities were $6.8 billion as of December 31, 2023. Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Regulated Businesses' regulatory assets and liabilities.

Impairment of Goodwill and Long-Lived Assets

The Company's Consolidated Balance Sheet as of December 31, 2023 includes goodwill of acquired businesses of $11.5 billion. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31, 2023. Additionally, no indicators of impairment were identified as of December 31, 2023. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The Company uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings or rate base; and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating future cash flows, the Company incorporates current market information, as well as historical factors.

The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As a majority of all property, plant and equipment is used in regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets.

The estimate of cash flows arising from the future use of an asset, for the purposes of impairment analysis, requires the exercise of judgment. Circumstances that could significantly alter the calculation of fair value or the recoverable amount of an asset may include significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset, the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect the Company's results of operations.

Pension and Other Postretirement Benefits

Certain of the Company's subsidiaries sponsor defined benefit pension and other postretirement benefit plans that cover the majority of employees. The Company recognizes the funded status of the defined benefit pension and other postretirement benefit plans on the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2023, the Company recognized a net asset totaling $302 million for the funded status of the defined benefit pension and other postretirement benefit plans. As of December 31, 2023, amounts not yet recognized as a component of net periodic benefit cost that were included in net regulatory assets totaled $282 million and in AOCI totaled $570 million.

121

The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including, but not limited to, discount rates, expected long-term rate of return on plan assets and healthcare cost trend rates. These key assumptions are reviewed annually and modified as appropriate. The Company believes that the key assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about the defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2023.

The Company chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.

In establishing its assumption as to the expected long-term rate of return on plan assets, the Company utilizes the expected asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. The Company regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.

The Company chooses a healthcare cost trend rate that reflects the near and long-term expectations of increases in medical costs and corresponds to the expected benefit payment periods. The healthcare cost trend rate is assumed to gradually decline to 5.00% by 2028, at which point the rate of increase is assumed to remain constant.

The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and funded status. If changes were to occur for the following key assumptions, the approximate effect on the Consolidated Financial Statements would be as follows (dollars in millions):

	Domestic Plans
					Other Postretirement				United Kingdom
	Pension Plans				Benefit Plans				Pension Plan
	+0.5%		-0.5%		+0.5%		-0.5%		+0.5%		-0.5%
Effect on December 31, 2023
Benefit Obligations:
Discount rate	$	(78)	$	85	$	(21)	$	22	$	(75)	$	83
Effect on 2023 Periodic Cost:
Discount rate	$	7	$	—	$	—	$	(1)	$	(6)	$	6
Expected rate of return on plan assets	(10)		10		(3)		3		(4)		4

A variety of factors affect the funded status of the plans, including discount rates, asset returns, mortality assumptions, plan changes and the Company's funding policy for each plan.

122

Income Taxes

In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory commissions. The Company's income tax returns are subject to continuous examinations by federal, state, local and foreign income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations is not expected to have a material impact on the Company's consolidated financial results. Refer to Note 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's income taxes.

It is probable the Company's regulated businesses will pass income tax benefit and expense related to the 2017 federal tax rate change from 35% to 21%, certain property-related basis differences and other various differences on to their customers. As of December 31, 2023, these amounts were recognized as a net regulatory liability of $2.3 billion and will be included in regulated rates when the temporary differences reverse.

The Company has not established deferred income taxes on its undistributed foreign earnings that have been determined by management to be reinvested indefinitely; however, the Company periodically evaluates its capital requirements. If circumstances change in the future and a portion of the Company's undistributed foreign earnings were repatriated, the dividends may be subject to taxation in the U.S. but the tax is not expected to be material.

Loss Contingencies

As a result of certain conditions, situations or circumstances involving uncertainty as to possible loss, including (i) several wildfires that have occurred in the Company's service territory and surrounding areas in the western U.S. and Canada and (ii) antitrust cases at HomeServices, the Company is required to evaluate its exposure to potential loss contingencies arising from claims associated with these items. In determining this exposure, the Company is required to assess whether the likelihood of loss for each of these items is remote, reasonably possible or probable, which involves complex judgments based on several variables including available information regarding the outcome of the appeals process, cause and origin of the wildfires, investigations, discovery associated with lawsuits and negotiations with various parties. If deemed reasonably possible, the Company is required to estimate the potential loss or range of potential loss and disclose any material amounts. If deemed probable, the Company is required to accrue a loss if reasonably estimable based on the bottom end of the range if no amount within the range of estimated loss is any better than another amount. Many assumptions and variables are involved in determining the estimates relative to wildfires, including identifying the various categories of potential loss such as fire suppression costs, real and personal property damages, natural resource damages for certain areas and noneconomic damages such as personal injury damages and loss of life damages. Within the categories of potential loss, further assumptions are made regarding items such as the types of structures damaged, estimated replacement values associated with those structures, value of personal property, the types of natural resource damage such as timber, the value of that timber, the nature of noneconomic damages such as those arising from personal injuries, other damages the Company may be responsible for if found negligent such as punitive damages, and the amount of any penalties or fines that may be imposed by governmental entities. Refer to Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's loss contingencies associated with wildfires and the antitrust cases at HomeServices.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

The Company's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. The Company's significant market risks are primarily associated with commodity prices, interest rates, equity prices, foreign currency exchange rates and the extension of credit to counterparties with which the Company transacts. The following discussion addresses the significant market risks associated with the Company's business activities. Each of the Company's businesses has established guidelines for credit risk management.

123

Commodity Price Risk

The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through BHE's ownership of the Utilities as they have an obligation to serve retail customer load in their regulated service territories. The Company also provides nonregulated retail electricity and natural gas services in competitive markets. The Utilities' 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, wholesale electricity that is purchased and sold and natural gas supply for retail customers. 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 Company does not engage in a material amount of proprietary trading activities. To manage a portion of its commodity price risk, the Company 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. The Company does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. The Company's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates, which is subject to regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.

The table that follows summarizes the Company's price risk on commodity contracts accounted for as derivatives, excluding collateral netting of $23 million and $(88) million, respectively, as of December 31, 2023 and 2022, and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices with the contracted or expected volumes. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).

	Fair Value -		Estimated Fair Value after
	Net Asset		Hypothetical Change in Price
	(Liability)		10% increase		10% decrease
As of December 31, 2023:
Not designated as hedging contracts	$	(121)	$	(14)	$	(228)
Designated as hedging contracts	11		19		3
Total commodity derivative contracts	$	(110)	$	5	$	(225)
As of December 31, 2022:
Not designated as hedging contracts	$	335	$	520	$	150
Designated as hedging contracts	12		40		(16)
Total commodity derivative contracts	$	347	$	560	$	134

The settled cost of certain of the Company's commodity derivative contracts not designated as hedging contracts is included in regulated rates and, therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose the Company to earnings volatility. Consolidated financial results would be negatively impacted if the costs of wholesale electricity, wholesale natural gas or fuel are higher than what is included in regulated rates, including the impacts of adjustment mechanisms. As of December 31, 2023 and 2022, a net regulatory asset of $166 million and a net regulatory liability of $231 million, respectively, was recorded related to the net derivative liability of $121 million and net derivative asset of $335 million, respectively. For the Company's commodity derivative contracts designated as hedging contracts, net unrealized gains and losses associated with interim price movements on commodity derivative contracts, to the extent the hedge is considered effective, generally do not expose the Company to earnings volatility.

124

Interest Rate Risk

The Company is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt, future debt issuances and mortgage commitments. The Company 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. As a result of the fixed interest rates, the Company's fixed-rate long-term debt does not expose the Company to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of the Company's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 9, 10, 11, and 15 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of the Company's short and long-term debt.

As of December 31, 2023 and 2022, the Company had short- and long-term variable-rate obligations totaling $5.0 billion and $3.2 billion, respectively, that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on the Company's consolidated annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2023 and 2022.

The Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, forward sale commitments or mortgage interest rate lock commitments, to mitigate the Company's exposure to interest rate risk. Changes in fair value of agreements designated as cash flow hedges are reported in AOCI to the extent the hedge is effective until the forecasted transaction occurs. Changes in fair value of agreements not designated as hedging contracts are recognized in earnings. As of December 31, 2023 and 2022, the Company had variable-to-fixed interest rate swaps with notional amounts of $426 million and $481 million, respectively, £163 million and £178 million, respectively, and A$161 million and A$167 million, respectively, to protect the Company against an increase in interest rates. Additionally, as of December 31, 2023 and 2022, the Company had mortgage commitments, net, with notional amounts of $406 million and $438 million, respectively, to protect the Company against an increase in interest rates. The fair value of the Company's interest rate derivative contracts was a net derivative asset of $78 million and $108 million as of December 31, 2023 and 2022, respectively. A hypothetical 10 basis point increase and a 10 basis point decrease in interest rates would not have a material impact on the Company.

The Company holds foreign currency swaps with the purpose of hedging the foreign currency exchange rate associated with Euro denominated debt. As of December 31, 2023 and 2022, the Company had €250 million in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would not have resulted in a material decrease in fair value of the Company's foreign currency swaps.

Equity Price Risk

Market prices for equity securities are subject to fluctuation and consequently the amount realized in the subsequent sale of an investment may significantly differ from the reported market value. Fluctuation in the market price of a security may result from perceived changes in the underlying economic characteristics of the investee, the relative price of alternative investments and general market conditions.

125

As of December 31, 2023 and 2022, the Company's investment in BYD Company Limited common stock represented approximately 76% and 86%, respectively, of the total fair value of the Company's equity securities. The majority of the Company's remaining equity securities are held in a trust related to the decommissioning of nuclear generation assets and the realized and unrealized gains and losses are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates. The following table summarizes the Company's investment in BYD Company Limited as of December 31, 2023 and 2022 and the effects of a hypothetical 30% increase and a 30% decrease in market price as of those dates. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).

				Estimated		Hypothetical
			Hypothetical	Fair Value after		Percentage Increase
	Fair		Price	Hypothetical		(Decrease) in BHE
	Value		Change	Change in Prices		Shareholders' Equity
As of December 31, 2023	$	2,218	30% increase	$	2,883	1	%
			30% decrease	1,553		(1)
As of December 31, 2022	$	3,763	30% increase	$	4,892	1	%
			30% decrease	2,634		(1)

Foreign Currency Exchange Rate Risk

BHE's business operations and investments outside of the U.S. increase its risk related to fluctuations in foreign currency exchange rates primarily in relation to the British pound and the Canadian dollar. BHE's reporting currency is the U.S. dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from BHE's foreign operations changes with the fluctuations of the currency in which they transact.

Northern Powergrid's functional currency is the British pound. As of December 31, 2023, a 10% devaluation in the British pound to the U.S. dollar would result in the Company's Consolidated Balance Sheet being negatively impacted by a $840 million cumulative translation adjustment in AOCI. A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for Northern Powergrid of $16 million in 2023.

BHE Canada's functional currency is the Canadian dollar. As of December 31, 2023, a 10% devaluation in the Canadian dollar to the U.S. dollar would result in the Company's Consolidated Balance Sheet being negatively impacted by a $453 million cumulative translation adjustment in AOCI. A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for BHE Canada of $18 million in 2023.

Credit Risk

Domestic Regulated Operations

The Utilities are 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 the Utilities' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, the Utilities analyze the financial condition of each significant wholesale counterparty, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, the Utilities enter 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, the Utilities exercise rights under these arrangements, including calling on the counterparty's credit support arrangement.

As of December 31, 2023, PacifiCorp's aggregate credit exposure with wholesale energy supply and marketing counterparties included counterparties having non-investment grade, internally rated credit ratings. Substantially all of these non-investment grade, internally rated counterparties are associated with long-duration solar and wind power purchase agreements, some of which are from facilities that have not yet achieved commercial operation and for which PacifiCorp has no obligation should the facilities not achieve commercial operation.

126

Substantially all of MidAmerican Energy's electric wholesale sales revenue results from participation in RTOs, including the MISO and the PJM. MidAmerican Energy's share of historical losses from defaults by other RTO market participants has not been material. Additionally, as of December 31, 2023, MidAmerican Energy's aggregate direct credit exposure from electric wholesale marketing counterparties was not material.

As of December 31, 2023, NV Energy's aggregate credit exposure from energy related transactions, based on settlement and mark-to-market exposures, net of collateral, was not material.

BHE GT&S primary customers include electric and natural gas distribution utilities and LNG export, import and storage customers. Northern Natural Gas' primary customers include utilities in the upper Midwest. Kern River's primary customers are electric and natural gas distribution utilities, major oil and natural gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies and financial institutions. As a general policy, collateral is not required for receivables from creditworthy customers. Customers' financial condition and creditworthiness, as defined by the tariff, are regularly evaluated and historical losses have been minimal. In order to provide protection against credit risk, and as permitted by the separate terms of each of BHE GT&S, Northern Natural Gas' and Kern River's tariffs, the companies have required customers that lack creditworthiness to provide cash deposits, letters of credit or other security until they meet the creditworthiness requirements of the respective tariff.

Northern Powergrid

The Northern Powergrid Distribution Companies charge fees for the use of their distribution systems to supply companies. The supply companies purchase electricity from generators and traders, sell the electricity to end-use customers and use the Northern Powergrid Distribution Companies' distribution networks pursuant to the multilateral "Distribution Connection and Use of System Agreement." The Northern Powergrid Distribution Companies' customers are concentrated in a small number of electricity supply businesses. During 2023, E.ON and certain of its affiliates and British Gas Trading Limited represented approximately 19% and 15%, respectively, of the total combined distribution revenue of the Northern Powergrid Distribution Companies. The industry operates in accordance with a framework which sets credit limits for each supply business based on its credit rating or payment history and requires them to provide credit cover if their value at risk (measured as being equivalent to 45 days usage) exceeds the credit limit. Acceptable credit typically is provided in the form of a parent company guarantee, letter of credit or an escrow account. Ofgem has indicated that, provided the Northern Powergrid Distribution Companies have implemented credit control, billing and collection in line with best practice guidelines and can demonstrate compliance with the guidelines or are able to satisfactorily explain departure from the guidelines, any bad debt losses arising from supplier default will be recovered through an increase in future allowed income. Losses incurred to date have not been material.

BHE Canada

AltaLink's primary source of operating revenue is the AESO, an entity rated AA- by Standard and Poor's. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligations would significantly impair AltaLink's ability to meet its existing and future obligations. Total operating revenue for AltaLink was $666 million for the year ended December 31, 2023.

BHE Renewables

BHE Renewables owns independent power projects that generally have separate project financing agreements. Operating revenue for these projects is derived primarily from long-term power purchase agreements with single customers, primarily utilities, which expire between 2024 and 2043. Because of the dependence generally from a single customer at each project, any material failure of the customer to fulfill its obligations would significantly impair that project's ability to meet its existing and future obligations. Total operating revenue for BHE Renewables' independent power projects was $1,022 million for the year ended December 31, 2023.

127

Item 8.    Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm	129
Consolidated Balance Sheets	132
Consolidated Statements of Operations	134
Consolidated Statements of Comprehensive Income	135
Consolidated Statements of Changes in Equity	136
Consolidated Statements of Cash Flows	137
Notes to Consolidated Financial Statements	138

128

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and the shareholders of

Berkshire Hathaway Energy Company

Des Moines, Iowa

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2023, the related notes and the schedule listed in the Index at Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Regulatory Matters — Effects of Rate Regulation on the Financial Statements — Refer to Note 7 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by the Federal Energy Regulatory Commission as well as certain other regulatory commissions (collectively, the "Commissions"), which have jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where the Company operates. Management has determined its regulated operations meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation has a pervasive effect on the financial statements.

129

Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow the Company an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an effect on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit the Company's ability to recover its costs.

We identified the effects of rate regulation on the financial statements as a critical audit matter due to the significant judgments made by management to support its assertions about certain affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and (3) refunds to customers. Given that management's accounting judgments are based on assumptions about the outcome of decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of decisions by the Commissions included the following, among others:

•We evaluated the Company's disclosures related to the effects of rate regulation, by testing certain recorded balances and evaluating regulatory developments.

•We read relevant regulatory orders issued by the Commissions, regulatory statutes, filings made by the Company and intervenors, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.

•For certain regulatory matters, we inspected the Company's filings with the Commissions and the filings with the Commissions by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances.

Wildfires — Contingencies — Refer to Note 16 to the financial statements

Critical Audit Matter Description

As a result of several wildfires that have occurred in the Company's service territory and surrounding areas in Oregon and California, the Company is required to evaluate its exposure to potential loss contingencies arising from claims associated with the 2020 Wildfires and the 2022 McKinney Fire (the "Wildfires"). In determining this exposure, the Company is required to determine whether the likelihood of loss for each of the Wildfires is remote, reasonably possible or probable, which involves complex judgments based on several variables including available information regarding the cause and origin of the Wildfires, investigations, discovery associated with lawsuits and negotiations with claimants.

A provision for a loss contingency is recorded when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. If deemed reasonably possible, the Company is required to estimate the potential loss or range of potential loss and disclose any material amounts.

Management has recorded estimated liabilities and receivables, which represent its best estimate of probable losses and expected insurance recoveries associated with the Wildfires.

We identified wildfire-related contingencies and the related disclosures as a critical audit matter because of the significant judgments made by management to determine the probability of loss and estimate the probable losses and insurance recoveries. Auditing the reasonableness of management's judgments, estimates and disclosures related to wildfire-related loss contingencies required the application of a high degree of judgment and extensive effort.

130

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management's judgments regarding the probability of loss, estimated losses and insurance recoveries, and related disclosures for wildfire-related contingencies included the following, among others:

•We evaluated management's judgments related to whether a loss was probable or reasonably possible for the Wildfires by inquiring of management and the Company's external and internal legal counsel regarding the likelihood and amounts of probable and reasonably possible losses. We also evaluated the potential impact of information gained through the Company and third parties' investigations into the cause of the fires, information from claimants, the advice of legal counsel, and reading external information for any evidence that might contradict management's assertions.

•We evaluated the estimation methodology for determining the amount of probable and reasonably possible losses through inquiries with management and external and internal legal counsel and we tested the significant assumptions, including certain settlements, used in the estimates of probable and reasonably possible losses.

•We read legal letters from the Company's external and internal legal counsel regarding known information and evaluated whether the information therein was consistent with the information obtained in our procedures.

•We evaluated management's judgments related to whether certain insurance recoveries were probable of collection by inquiring of management and the Company's external and internal legal counsel regarding the amounts of insurance recoveries recorded or disclosed. With the assistance of our insurance specialists, we tested certain significant assumptions used in the determination of collectability, including obtaining and reading relevant insurance policies to determine whether the types of insurance claims are included or excluded from coverage. We compared a sample of subsequent insurance recoveries collected to recorded amounts.

•We evaluated whether the Company's disclosures were appropriate and consistent with the information obtained in our procedures.

/s/    Deloitte & Touche LLP

Des Moines, Iowa

February 23, 2024

We have served as the Company's auditor since 1991.

131

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in millions)

	As of December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	1,565	$	1,591
Investments and restricted cash and cash equivalents	1,253		2,141
Trade receivables, net	2,667		2,876
Inventories	1,509		1,256
Mortgage loans held for sale	451		474
Regulatory assets	1,398		1,319
Other current assets	1,355		1,345
Total current assets	10,198		11,002
Property, plant and equipment, net	99,248		93,043
Goodwill	11,547		11,489
Regulatory assets	4,167		3,743
Investments and restricted cash and cash equivalents and investments	9,510		11,273
Other assets	3,170		3,290
Total assets	$	137,840	$	133,840

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

132

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (continued)

(Amounts in millions)

	As of December 31,
	2023		2022
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	3,175	$	2,679
Accrued interest	625		558
Accrued property, income and other taxes	828		746
Accrued employee expenses	354		333
Short-term debt	4,148		1,119
Current portion of long-term debt	2,740		3,201
Other current liabilities	1,551		1,677
Total current liabilities	13,421		10,313
BHE senior debt	13,101		13,096
BHE junior subordinated debentures	100		100
Subsidiary debt	36,231		35,238
Regulatory liabilities	6,644		7,070
Deferred income taxes	12,437		12,678
Other long-term liabilities	6,166		4,706
Total liabilities	88,100		83,201
Commitments and contingencies (Note 16)
Equity:
BHE shareholders' equity:
Preferred stock - 100 shares authorized, $0.01 par value, 0 and 1 shares issued and outstanding	—		850
Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding	—		—
Additional paid-in capital	5,573		6,298
Retained earnings	44,765		41,833
Accumulated other comprehensive loss, net	(1,904)		(2,149)
Total BHE shareholders' equity	48,434		46,832
Noncontrolling interests	1,306		3,807
Total equity	49,740		50,639
Total liabilities and equity	$	137,840	$	133,840

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

133

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in millions)

	Years Ended December 31,
	2023		2022		2021
Operating revenue:
Energy	$	21,280	$	21,069	$	18,935
Real estate	4,322		5,268		6,215
Total operating revenue	25,602		26,337		25,150
Operating expenses:
Energy:
Cost of sales	7,057		6,757		5,504
Operations and maintenance	4,779		4,153		3,991
Wildfire losses, net of recoveries (Note 16)	1,677		64		—
Depreciation and amortization	4,170		4,230		3,829
Property and other taxes	823		775		789
Real estate	4,316		5,117		5,710
Total operating expenses	22,822		21,096		19,823
Operating income	2,780		5,241		5,327
Other income (expense):
Interest expense	(2,415)		(2,216)		(2,118)
Capitalized interest	132		76		64
Allowance for equity funds	267		167		126
Interest and dividend income	412		154		89
Gains (losses) on marketable securities, net	669		(2,002)		1,823
Other, net	116		(7)		(17)
Total other income (expense)	(819)		(3,828)		(33)
Income before income tax expense (benefit) and equity income (loss)	1,961		1,413		5,294
Income tax expense (benefit)	(1,699)		(1,916)		(1,132)
Equity income (loss)	(288)		(185)		(237)
Net income	3,372		3,144		6,189
Net income attributable to noncontrolling interests	352		423		399
Net income attributable to BHE shareholders	3,020		2,721		5,790
Preferred dividends	34		46		121
Earnings on common shares	$	2,986	$	2,675	$	5,669

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

134

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Amounts in millions)

	Years Ended December 31,
	2023		2022		2021
Net income	$	3,372	$	3,144	$	6,189
Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $(13), $(23) and $55	(36)		(72)		174
Foreign currency translation adjustment	346		(810)		(24)
Unrealized (losses) gains on cash flow hedges, net of tax of $(13), $20 and $10	(64)		76		67
Total other comprehensive income (loss), net of tax	246		(806)		217
Comprehensive income	3,618		2,338		6,406
Comprehensive income attributable to noncontrolling interests	352		426		404
Comprehensive income attributable to BHE shareholders	$	3,266	$	1,912	$	6,002

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

135

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Amounts in millions)

	BHE Shareholders' Equity
							Long-term				Accumulated
					Additional		Income				Other
	Preferred		Common		Paid-in		Tax		Retained		Comprehensive		Noncontrolling		Total
	Stock		Stock		Capital		Receivable		Earnings		Loss, Net		Interests		Equity
Balance, December 31, 2020	$	3,750	$	—	$	6,377	$	(658)	$	35,093	$	(1,552)	$	3,967	$	46,977
Net income	—		—		—		—		5,790		—		397		6,187
Other comprehensive income	—		—		—		—		—		212		5		217
Long-term income tax    receivable adjustments	—		—		—		(86)		(8)		—		—		(94)
Preferred stock redemptions	(2,100)		—		—		—		—		—		—		(2,100)
Preferred stock dividend	—		—		—		—		(121)		—		—		(121)
Distributions			—		—		—		—		—		(478)		(478)
Contributions	—		—		—		—		—		—		9		9
Other equity transactions	—		—		(3)		—		—		—		(5)		(8)
Balance, December 31, 2021	1,650		—		6,374		(744)		40,754		(1,340)		3,895		50,589
Net income	—		—		—		—		2,721		—		421		3,142
Other comprehensive (loss) income	—		—		—		—		—		(809)		3		(806)
Long-term income tax    receivable adjustments	—		—		—		744		(791)		—		—		(47)
Preferred stock redemptions	(800)		—		—		—		—		—		—		(800)
Preferred stock dividend	—		—		—		—		(46)		—		—		(46)
Common stock purchases	—		—		(77)		—		(793)		—		—		(870)
Distributions			—		—		—		—		—		(522)		(522)
Contributions	—		—		—		—		—		—		5		5
Other equity transactions	—		—		1		—		(12)		—		5		(6)
Balance, December 31, 2022	850		—		6,298		—		41,833		(2,149)		3,807		50,639
Net income	—		—		—		—		3,020		—		352		3,372
Other comprehensive income	—		—		—		—		—		246		—		246
Long-term income tax    receivable adjustments	—		—		—		—		(54)		—		—		(54)
Preferred stock redemptions	(850)		—		—		—		—		—		—		(850)
Preferred stock dividend	—		—		—		—		(34)		—		—		(34)
Distributions			—		—		—		—		—		(394)		(394)
Contributions	—		—		—		—		—		—		4		4
Purchase of Cove Point noncontrolling interest	—		—		(725)		—		—		(1)		(2,454)		(3,180)
Other equity transactions	—		—		—		—		—		—		(9)		(9)
Balance, December 31, 2023	$	—	$	—	$	5,573	$	—	$	44,765	$	(1,904)	$	1,306	$	49,740

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

136

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in millions)

	Years Ended December 31,
	2023		2022		2021
Cash flows from operating activities:
Net income	$	3,372	$	3,144	$	6,189
Adjustments to reconcile net income to net cash flows from operating activities:
(Gains) losses on marketable securities, net	(669)		2,002		(1,823)
Depreciation and amortization	4,220		4,286		3,881
Allowance for equity funds	(267)		(167)		(126)
Equity (income) loss, net of distributions	415		319		380
Net power cost deferrals	(629)		(1,290)		(520)
Amortization of net power cost deferrals	354		357		107
Other changes in regulatory assets and liabilities	(260)		(146)		(255)
Deferred income taxes and investment tax credits, net	(257)		(467)		646
Other, net	(46)		59		(57)
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(134)		150		553
Derivative collateral, net	(226)		121		82
Pension and other postretirement benefit plans	(10)		(27)		(39)
Accrued property, income and other taxes, net	(58)		397		(489)
Accounts payable and other liabilities	280		579		163
Wildfires insurance receivable	(253)		(130)		—
Wildfires liability	1,300		172		—
Net cash flows from operating activities	7,132		9,359		8,692
Cash flows from investing activities:
Capital expenditures	(9,148)		(7,505)		(6,611)
Acquisitions, net of cash acquired	—		(314)		(122)
Purchases of marketable securities	(314)		(574)		(297)
Proceeds from sales of marketable securities	2,520		2,464		273
Purchases of U.S. Treasury Bills	(4,282)		(1,918)		—
Proceeds from sales of U.S. Treasury Bills	1,809		—		—
Proceeds from maturities of U.S. Treasury Bills	3,507		—		—
Proceeds from other investments	4		6		1,300
Equity method investments	(12)		119		(212)
Other, net	17		(28)		(94)
Net cash flows from investing activities	(5,899)		(7,750)		(5,763)
Cash flows from financing activities:
Preferred stock redemptions	(850)		(800)		(2,100)
Preferred dividends	(38)		(50)		(132)
Common stock purchases	—		(870)		—
Proceeds from BHE senior debt	—		986		—
Repayments of BHE senior debt	(900)		—		(450)
Proceeds from subsidiary debt	4,084		2,887		2,409
Repayments of subsidiary debt	(2,821)		(1,494)		(2,024)
Net proceeds from (repayments of) short-term debt	3,024		(867)		(276)
Purchase of Cove Point noncontrolling interest	(3,300)		—		—
Distributions to noncontrolling interests	(395)		(524)		(488)
Other, net	(54)		(274)		(70)
Net cash flows from financing activities	(1,250)		(1,006)		(3,131)
Effect of exchange rate changes	11		(30)		1
Net change in cash and cash equivalents and restricted cash and cash equivalents	(6)		573		(201)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	1,817		1,244		1,445
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	1,811	$	1,817	$	1,244

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

137

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)    Organization and Operations

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

The Company's operations are organized as eight business segments: PacifiCorp and its subsidiaries ("PacifiCorp"), MidAmerican Funding, LLC and its subsidiaries ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. and its subsidiaries ("NV Energy") (which primarily consists of Nevada Power Company and its subsidiaries ("Nevada Power") and Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific")), Northern Powergrid Holdings Company and its subsidiaries ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group, LLC and its subsidiaries (which primarily consists of BHE GT&S, LLC and its subsidiaries ("BHE GT&S"), Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation and its subsidiaries ("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, LLC and its subsidiaries), BHE Renewables, LLC and its subsidiaries ("BHE Renewables") and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through these locally managed and operated businesses, owns four utility companies in the U.S. serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies 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, the largest residential real estate brokerage firm in the U.S. and one of the largest residential real estate brokerage franchise networks in the U.S.

(2)    Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

The Consolidated Financial Statements include the accounts of BHE and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. The Consolidated Statements of Operations include the revenue and expenses of any acquired entities from the date of acquisition. The Company consolidates variable interest entities ("VIE") in which it possesses both (i) the power to direct the activities that most significantly impact the entity's economic performance and (ii) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE. Intercompany accounts and transactions have been eliminated.

Use of Estimates in Preparation of Financial Statements

The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; impairment of goodwill; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for loss contingencies and applicable insurance recoveries, including those related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") and a wildfire that began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California in July 2022 (the "2022 McKinney Fire"), referred to together as "the Wildfires" as discussed in Note 16. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.

138

Accounting for the Effects of Certain Types of Regulation

PacifiCorp, MidAmerican Energy, Nevada Power, Sierra Pacific, BHE GT&S, Northern Natural Gas, Kern River and AltaLink (the "Regulated Businesses") prepare their financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Regulated Businesses defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").

Fair Value Measurements

As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Alternative valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered when determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.

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 of December 31, 2023 and 2022, 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 December 31,
	2023		2022
Cash and cash equivalents	$	1,565	$	1,591
Investments and restricted cash and cash equivalents	224		173
Investments and restricted cash and cash equivalents and investments	22		53
Total cash and cash equivalents and restricted cash and cash equivalents	$	1,811	$	1,817

Investments

Fixed Maturity Securities

The Company's management determines the appropriate classification of investments in fixed maturity securities at the acquisition date and reevaluates the classification at each balance sheet date. Investments and restricted cash and cash equivalents and investments that management does not intend to use or is restricted from using in current operations are presented as noncurrent on the Consolidated Balance Sheets.

Available-for-sale investments are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. Realized and unrealized gains and losses on fixed maturity securities in a trust related to the decommissioning of nuclear generation assets are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates. Trading investments are carried at fair value with changes in fair value recognized in earnings. Held-to-maturity investments are carried at amortized cost, reflecting the ability and intent to hold the securities to maturity. The difference between the original cost and maturity value of a fixed maturity security is amortized to earnings using the interest method.

139

Investment gains and losses arise when investments are sold (as determined on a specific identification basis) or are other-than-temporarily impaired with respect to securities classified as available-for-sale. If the value of a fixed maturity investment declines to below amortized cost and the decline is deemed other than temporary, the amortized cost of the investment is reduced to fair value, with a corresponding charge to earnings. Any resulting impairment loss is recognized in earnings if the Company intends to sell, or expects to be required to sell, the debt security before its amortized cost is recovered. If the Company does not expect to ultimately recover the amortized cost basis even if it does not intend to sell the security, the credit loss component is recognized in earnings and any difference between fair value and the amortized cost basis, net of the credit loss, is reflected in other comprehensive income (loss) ("OCI"). For regulated fixed maturity investments, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in regulated rates is probable.

Equity Securities

Investments in equity securities are carried at fair value with changes in fair value recognized in earnings as a component of gains (losses) on marketable securities, net. All changes in fair value of equity securities in a trust related to the decommissioning of nuclear generation assets are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates.

Equity Method Investments

The Company utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when the investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate that the ability to exercise significant influence is restricted. In applying the equity method, the Company records the investment at cost and subsequently increases or decreases the carrying value of the investment by the Company's share of the net earnings or losses and OCI of the investee. The Company records dividends or other equity distributions as reductions in the carrying value of the investment. Certain equity investments are presented on the Consolidated Balance Sheets net of related investment tax credits.

Allowance for Credit Losses

Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on the Company's assessment of the collectability of amounts owed to the Company by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, the Company primarily utilizes credit loss history. However, the Company may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. The change in the balance of the allowance for credit losses, which is included in trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31 (in millions):

	2023		2022		2021
Beginning balance	$	106	$	108	$	77
Charged to operating costs and expenses, net	68		43		81
Write-offs, net	(72)		(45)		(50)
Ending balance	$	102	$	106	$	108

Derivatives

The Company employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price, interest rate, and foreign currency exchange rate risk. 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. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets on the Consolidated Balance Sheets.

140

Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or cost of sales on the Consolidated Statements of Operations.

For the Company's derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For the Company's derivatives not designated as hedging contracts and for which changes in fair value are not recorded as regulatory assets and liabilities, unrealized gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for sales contracts; cost of sales and operating expense for purchase contracts and electricity, natural gas and fuel swap contracts; and other, net for interest rate swap derivatives.

For the Company's derivatives designated as hedging contracts, the Company formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. The Company formally documents hedging activity by transaction type and risk management strategy.

Changes in the estimated fair value of a derivative contract designated and qualified as a cash flow hedge, to the extent effective, are included on the Consolidated Statements of Changes in Equity as AOCI, net of tax, until the contract settles and the hedged item is recognized in earnings. The Company discontinues hedge accounting prospectively when it has determined that a derivative contract no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative contract no longer qualifies as an effective hedge, future changes in the estimated fair value of the derivative contract are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the contract settles and the hedged item is recognized in earnings, unless it becomes probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in earnings.

Inventories

Inventories consist mainly of fuel, which includes coal stocks, stored gas and fuel oil, totaling $250 million and $248 million as of December 31, 2023 and 2022, respectively, and materials and supplies totaling $1,259 million and $1,008 million as of December 31, 2023 and 2022, respectively. The cost of materials and supplies, coal stocks and fuel oil is determined primarily using the average cost method. The cost of stored gas is determined using either the last-in-first-out ("LIFO") method or the lower of average cost or market. With respect to inventories carried at LIFO cost, the replacement cost would be $4 million and $22 million higher as of December 31, 2023 and 2022, respectively.

Property, Plant and Equipment, Net

General

Additions to property, plant and equipment are recorded at cost. The Company capitalizes all construction-related materials, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include capitalized interest, including debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable to the Regulated Businesses. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. Additionally, MidAmerican Energy has regulatory arrangements in Iowa in which the carrying cost of certain utility plant has been reduced for amounts associated with electric returns on equity exceeding specified thresholds.

Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by the Company's various regulatory authorities. Depreciation studies are completed by the Regulated Businesses to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.

141

Generally when the Company retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.

Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, is capitalized by the Regulated Businesses as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC") and the Alberta Utilities Commission ("AUC"). After construction is completed, the Company is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.

Asset Retirement Obligations ("ARO")

The Company recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. The Company's AROs are primarily related to the decommissioning of nuclear generating facilities and obligations associated with its other generating facilities and offshore natural gas pipelines. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. For the Regulated Businesses, the difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.

Impairment

The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As a majority of all property, plant and equipment is used in regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets.

Leases

The Company has non-cancelable operating leases primarily for office space, office equipment, generating facilities, land and rail cars and finance leases consisting primarily of transmission assets, generating facilities and vehicles. These leases generally require the Company to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. The Company does not include options in its lease calculations unless there is a triggering event indicating the Company is reasonably certain to exercise the option. The Company's accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with Accounting Standards Codification ("ASC") 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.

The Company's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.

The Company's operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly.

142

Goodwill

Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired in business combinations. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31, 2023. When evaluating goodwill for impairment, the Company estimates the fair value of its reporting units. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the excess is charged to earnings as an impairment loss. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The determination of fair value incorporates significant unobservable inputs. During 2023, 2022 and 2021, the Company did not record any material goodwill impairments.

The Company records goodwill adjustments for changes to the purchase price allocation prior to the end of the measurement period, which is not to exceed one year from the acquisition date.

Revenue Recognition

    Customer Revenue

The Company uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The Company records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations. In the event one of the parties to a contract has performed before the other, the Company would recognize a contract asset or contract liability depending on the relationship between the Company's performance and the customer's payment.

        Energy Products and Services

A majority of the Company's energy revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. The Company's energy revenue that is nonregulated primarily relates to the Company's renewable energy business.

Revenue recognized is equal to what the Company has the right to invoice as it generally corresponds directly with the value to the customer of the Company's performance to date and includes billed and unbilled amounts. As of December 31, 2023 and 2022, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $787 million and $828 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.

        Real Estate Services

The Company's HomeServices reportable segment consists of separate brokerage, mortgage and franchise businesses. Rates charged for brokerage, mortgage and franchise real estate services are established through contractual arrangements that establish the transaction price and the allocation of the price amongst the separate performance obligations.

The full-service residential real estate brokerage business has performance obligations to deliver integrated real estate services including brokerage services, title and closing services, property and casualty insurance, home warranties, relocation services, and other home-related services to customers. All performance obligations related to the full-service residential real estate brokerage business are satisfied in less than one year at the point in time when a real estate transaction is closed or when services are provided. Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when a real estate transaction is closed. Title and escrow closing fee revenue from real estate transactions and related amounts due to the title insurer are recognized at closing. Payments for amounts billed are generally due from the customer at closing.

143

The franchise business operates a network that has performance obligations to provide the right to use certain brand names and other related service marks as well as to provide orientation programs, training and consultation services, advertising programs and other services to its franchisees. The performance obligations related to the franchise business are satisfied over time or when the services are provided. Franchise royalty fees are sales-based variable consideration and are based on a percentage of commissions earned by franchisees on real estate sales, which are recognized when the sale closes. Meetings and training revenue, referral fees, late fees, service fees and franchise termination fees are earned when services have been completed. Payments for amounts billed are generally due from the franchisee within 30 days of billing.

    Other Revenue

        Energy Products and Services

Other revenue consists primarily of revenue related to power purchase agreements not considered Customer Revenue as they are recognized in accordance with ASC 815, "Derivatives and Hedging" and ASC 842, "Leases" and certain non-tariff-based revenue approved by the regulator that is not considered Customer Revenue within ASC 606, "Revenue from Contracts with Customers."

        Real Estate Service

Mortgage and other revenue consists primarily of revenue related to the mortgage business. Mortgage fee revenue consists of amounts earned related to application and underwriting fees and fees on canceled loans. Fees associated with the origination of mortgage loans are recognized as earned. These amounts are not considered Customer Revenue as they are recognized in accordance with ASC 815, "Derivatives and Hedging," ASC 825, "Financial Instruments" and ASC 860, "Transfers and Servicing."

Unamortized Debt Premiums, Discounts and Debt Issuance Costs

Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.

Foreign Currency

The accounts of foreign-based subsidiaries are measured in most instances using the local currency of the subsidiary as the functional currency. Revenue and expenses of these businesses are translated into U.S. dollars at the average exchange rate for the period. Assets and liabilities are translated at the exchange rate as of the end of the reporting period. Gains or losses from translating the financial statements of foreign-based operations are included in equity as a component of AOCI. Gains or losses arising from transactions denominated in a currency other than the functional currency of the entity that is party to the transaction are included in earnings.

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.

Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities associated with income tax benefits and expense for certain property-related basis differences and other various differences that the Company's regulated businesses deems probable to be passed on to their customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.

144

Investment tax credits are deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions. The Company has not established deferred income taxes on its undistributed foreign earnings that have been determined by management to be reinvested indefinitely.

The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. The Company's unrecognized tax benefits are primarily included in accrued property, income and other taxes and other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.

New Accounting Pronouncements

In March 2023, the FASB issued ASU No. 2023-02, amending FASB ASC Topic 323-740, "Investments—Equity Method and Joint Ventures—Income Taxes" which set forth the conditions needed to apply the proportional amortization method. The amendments in this update permit reporting entities to elect to account for their tax equity investments, regardless of the tax credit program from which the income tax credits are received, using the proportional amortization method if certain conditions are met. This guidance is effective for interim and annual reporting periods beginning after December 15, 2023, with early adoption permitted, and is required to be adopted either using a modified retrospective approach by means of a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption or a retrospective approach by means of a cumulative-effect adjustment to retained earnings as of the beginning of the earliest fiscal year presented. The Company has elected not to adopt this guidance and therefore this ASU will have no effect on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

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

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

145

(3)    Business Acquisitions

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

Other

In 2022, the Company completed various acquisitions totaling $314 million, net of cash acquired. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which related to residential real estate brokerage businesses, 300 MWs of long-term transmission rights and 399 MWs of wind-powered generating facilities. As a result of the various acquisitions, the Company acquired assets of $363 million, assumed liabilities of $65 million and recognized goodwill of $16 million.

In 2021, the Company completed various acquisitions totaling $122 million, net of cash acquired. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which related to residential real estate brokerage businesses. As a result of the various acquisitions, the Company acquired assets of $54 million, assumed liabilities of $61 million and recognized goodwill of $129 million.

146

(4)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following as of December 31 (in millions):

	Depreciable Life	2023		2022
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	96,195	$	92,759
Interstate natural gas pipeline assets	3-80 years	19,226		18,328
		115,421		111,087
Accumulated depreciation and amortization		(36,365)		(34,599)
Regulated assets, net		79,056		76,488
Nonregulated assets:
Independent power plants	2-50 years	8,484		8,545
Cove Point LNG facility	40 years	3,423		3,412
Other assets	2-30 years	2,874		2,693
		14,781		14,650
Accumulated depreciation and amortization		(3,856)		(3,452)
Nonregulated assets, net		10,925		11,198
		89,981		87,686
Construction work-in-progress		9,267		5,357
Property, plant and equipment, net		$	99,248	$	93,043

Construction work-in-progress includes $8.6 billion and $4.9 billion as of December 31, 2023 and 2022, respectively, related to the construction of regulated assets.

(5)    Jointly Owned Utility Facilities

Under joint facility ownership agreements, the Domestic Regulated Businesses, as tenants in common, have undivided interests in jointly owned generation, transmission, distribution and pipeline common facilities. The Company accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include the Company's share of the expenses of these facilities.

147

The amounts shown in the table below represent the Company's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2023 (dollars in millions):

					Accumulated		Construction
	Company		Facility In		Depreciation and		Work-in-
	Share		Service		Amortization		Progress
PacifiCorp:
Jim Bridger Nos. 1-4	67	%	$	1,596	$	996	$	26
Hunter No. 1	94		510		237		4
Hunter No. 2	60		316		151		2
Wyodak	80		491		285		—
Colstrip Nos. 3 and 4	10		262		199		—
Hermiston	50		191		111		3
Craig Nos. 1 and 2	19		372		341		—
Hayden No. 1	25		77		55		—
Hayden No. 2	13		45		32		—
Transmission and distribution facilities	Various		900		283		192
Total PacifiCorp			4,760		2,690		227
MidAmerican Energy:
Louisa No. 1	88	%	983		531		5
Quad Cities Nos. 1 and 2(1)	25		737		496		11
Walter Scott, Jr. No. 3	79		1,017		888		14
Walter Scott, Jr. No. 4(2)	60		170		123		8
George Neal No. 4	41		330		191		6
Ottumwa No. 1(2)	52		433		299		8
George Neal No. 3	72		557		375		20
Transmission facilities	Various		274		100		3
Total MidAmerican Energy			4,501		3,003		75
NV Energy:
Navajo	11	%	—		2		—
Valmy	50		405		351		4
On Line Transmissi