Dominion Energy (NYSE: D) shifts to regulated utilities with $65B plan

Rhea-AI Filing Summary

Dominion Energy outlines a regulated-utility focused strategy built around a roughly $65 billion capital plan for 2026–2030, emphasizing offshore wind, solar, batteries, grid modernization and new gas-fired reliability projects. The company has exited most gas distribution outside South Carolina through multi‑billion‑dollar sales to Enbridge and sold its remaining 50% Cove Point interest to BHE.

Virginia Power’s 2.6 GW CVOW offshore wind project is now estimated at about $11.5 billion, with major onshore and offshore construction milestones achieved and a 50% interest sold to Stonepeak for $2.6 billion. Dominion expects about 95% of earnings to come from state‑regulated utilities and continues to invest heavily in nuclear license extensions and decommissioning trusts, where current trust balances exceed most recent site‑specific cost estimates.

Insights

Utility sector equity analyst

Dominion doubles down on regulated utilities with heavy capex and offshore wind risk.

Dominion Energy is reshaping its portfolio toward regulated electric and long-term contracted assets. Large gas distribution divestitures to Enbridge and the Cove Point sale to BHE simplify the business and concentrate earnings in Virginia, North Carolina and South Carolina utility operations.

The strategic centerpiece is Virginia Power’s 2.6 GW CVOW offshore wind project, with an estimated cost of $11.5 billion and complex exposure to tariffs, BOEM permitting, PJM network upgrades and construction contingencies. A 50% sale to Stonepeak for $2.6 billion shares risk but adds intricate capital‑funding bands and cost‑sharing thresholds.

Through 2030, the plan calls for about $65 billion of spending across offshore wind, solar, storage, gas generation, nuclear life extensions, transmission and undergrounding. Actual financial impact will depend on future regulatory approvals, allowed returns, execution on mega‑projects like CVOW, and how data‑center driven load growth materializes in the PJM DOM Zone.

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number	Exact name of registrants as specified in their charters	I.R.S. Employer Identification Number
001-08489	DOMINION ENERGY, INC.	54-1229715
000-55337	Virginia ELECTRIC AND POWER COMPANY	54-0418825
	Virginia (State or other jurisdiction of incorporation or organization)
	600 EAST CANAL STREET RICHMOND, Virginia (Address of principal executive offices)	23219 (Zip Code)
	(804) 819-2284 (Registrants’ telephone number)

Securities registered pursuant to Section 12(b) of the Act:

Registrant	Trading Symbol	Title of Each Class	Name of Each Exchange on Which Registered
DOMINION ENERGY, INC.	D	Common Stock, no par value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

VIRGINIA ELECTRIC AND POWER COMPANY

Common Stock, no par value

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

Dominion Energy, Inc. Yes ☒ No ☐ Virginia Electric and Power Company Yes ☒ No ☐

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

Dominion Energy, Inc. Yes ☐ No ☒ Virginia Electric and Power Company Yes ☐ No ☒

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.

Dominion Energy, Inc. Yes ☒ No ☐ Virginia Electric and Power Company Yes ☒ No ☐

Indicate by check mark whether the registrant has 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 registrant was required to submit such files).

Dominion Energy, Inc. Yes ☒ No ☐ Virginia Electric and Power Company Yes ☒ No ☐

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

Dominion Energy, Inc.

Large accelerated filer	☒	Accelerated filer	☐	Emerging growth company	☐
Non-accelerated filer	☐	Smaller reporting company	☐

Virginia Electric and Power Company

Large accelerated filer	☐	Accelerated filer	☐	Emerging growth company		☐
Non-accelerated filer	☒	Smaller reporting company	☐

If an emerging growth company, indicate by check mark if the registrant has 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.

Dominion Energy, Inc. ☒ Virginia Electric and Power Company ☐

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 registrant is a shell company (as defined by Rule 12b-2 of the Act).

Dominion Energy, Inc. Yes ☐ No ☒ Virginia Electric and Power Company Yes ☐ No ☒

The aggregate market value of Dominion Energy, Inc. common stock held by non-affiliates of Dominion Energy, Inc. was approximately $48.2 billion based on the closing price of Dominion Energy, Inc.’s common stock as reported on the New York Stock Exchange as of the last day of Dominion Energy, Inc.’s most recently completed second fiscal quarter. Dominion Energy, Inc. is the sole holder of Virginia Electric and Power Company common stock. At February 16, 2026, Dominion Energy, Inc. had 878,785,631 shares of common stock outstanding and Virginia Electric and Power Company had 373,881 shares of common stock outstanding.

DOCUMENT INCORPORATED BY REFERENCE

Portions of Dominion Energy, Inc.’s 2026 Proxy Statement are incorporated by reference in Part III.

This combined Form 10-K represents separate filings by Dominion Energy, Inc. and Virginia Electric and Power Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Virginia Electric and Power Company makes no representations as to the information relating to Dominion Energy, Inc.’s other operations.

VIRGINIA ELECTRIC AND POWER COMPANY MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I(1)(a) AND (b) OF FORM 10-K AND IS FILING THIS FORM 10-K UNDER THE REDUCED DISCLOSURE FORMAT.

Dominion Energy, Inc. and Virginia Electric and Power Company

Item Number			Page Number
	Glossary of Terms		3
Part I
1.	Business		8
1A.	Risk Factors		25
1B.	Unresolved Staff Comments		34
1C.	Cybersecurity		35
2.	Properties		36
3.	Legal Proceedings		41
4.	Mine Safety Disclosures		41
	Information about our Executive Officers		41
Part II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		42
6.	[Reserved]		42
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		43
7A.	Quantitative and Qualitative Disclosures About Market Risk		63
8.	Financial Statements and Supplementary Data		65
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		158
9A.	Controls and Procedures		158
9B.	Other Information		160
9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections		160
Part III
10.	Directors, Executive Officers and Corporate Governance		161
11.	Executive Compensation		161
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		161
13.	Certain Relationships and Related Transactions, and Director Independence		161
14.	Principal Accountant Fees and Services		161
Part IV
15.	Exhibits and Financial Statement Schedules		162
16.	Form 10-K Summary		167

2

Glossary of Terms

The following abbreviations or acronyms used in this Form 10-K are defined below:

Abbreviation or Acronym		Definition
2017 Tax Reform Act		An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (previously known as The Tax Cuts and Jobs Act) enacted on December 22, 2017
2021 Triennial Review		Virginia Commission review of Virginia Power’s earned return on base rate generation and distribution services for the four successive 12-month test periods beginning January 1, 2017 and ending December 31, 2020
2023 Biennial Review		Virginia Commission review of Virginia Power’s earned return on base rate generation and distribution services for the two successive 12-month test periods beginning January 1, 2021 and ending December 31, 2022 and prospective rate base setting for the succeeding annual periods beginning January 1, 2024 and ending December 31, 2025
2024 Series A JSNs		Dominion Energy’s 2024 Series A Enhanced Junior Subordinated Notes due 2055
2024 Series B JSNs		Dominion Energy’s 2024 Series B Enhanced Junior Subordinated Notes due 2054
2024 Series C JSNs		Dominion Energy’s 2024 Series C Enhanced Junior Subordinated Notes due 2055
2025 Biennial Review		Virginia Commission review of Virginia Power’s earned return on base rate generation and distribution services for the two successive 12-month test periods beginning January 1, 2023 and ending December 31, 2024 and prospective rate base setting for the succeeding annual periods beginning January 1, 2026 and ending December 31, 2027
2025 Series A JSNs		Dominion Energy’s 2025 Series A Junior Subordinated Notes due 2056
2025 Series B JSNs		Dominion Energy’s 2025 Series B Junior Subordinated Notes due 2056
2026 Proxy Statement		Dominion Energy 2026 Proxy Statement, File No. 001-08489
2027 Biennial Review		Future Virginia Commission review of Virginia Power’s earned return on base rate generation and distribution services for the two successive 12-month test periods beginning January 1, 2025 and ending December 31, 2026 and prospective rate base setting for the succeeding annual periods beginning January 1, 2028 and ending December 31, 2029
ABO		Accumulated benefit obligation
AEP		The legal entity American Electric Power Company, Inc., one or more of its consolidated subsidiaries, or the entirety of American Electric Power Company, Inc. and its consolidated subsidiaries
AES		The legal entity The AES Corporation, one or more of its consolidated subsidiaries, or the entirety of The AES Corporation and its consolidated subsidiaries
AFUDC		Allowance for funds used during construction
Align RNG		Align RNG, LLC, a joint venture between Dominion Energy and Smithfield Foods, Inc.
Altavista		Altavista biomass power station
AOCI		Accumulated other comprehensive income (loss)
ARO		Asset retirement obligation
Atlantic Coast Pipeline		Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion Energy and Duke Energy
Atlantic Coast Pipeline Project		A previously proposed approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina which would have been owned by Dominion Energy and Duke Energy
bcf		Billion cubic feet
Bear Garden		A 622 MW combined-cycle, natural gas-fired power station in Buckingham County, Virginia
Bedford		A 70 MW solar generation facility in Chesapeake, Virginia
BHE		The legal entity, Berkshire Hathaway Energy Company, one or more of its consolidated subsidiaries (including Eastern Energy Gas Holdings, LLC, Northeast Midstream Partners, LP and Cove Point effective November 2020), or the entirety of Berkshire Hathaway Energy Company and its consolidated subsidiaries
Birdseye		Birdseye Renewable Energy, LLC
BLS Industry Average OSHA Recordable Rate		An average of the OSHA Recordable Rate published by the Bureau of Labor Statistics for electric power generation, transmission and distribution (NAICS code 2211) and natural gas distribution (NAICS code 2212)
BOEM		U.S. Department of Interior’s Bureau of Ocean Energy Management
Brunswick County		A 1,376 MW combined-cycle, natural gas-fired power station in Brunswick County, Virginia
CAA		Clean Air Act
CAISO		California ISO
Canadys Station		A proposed 2.2 GW advanced class combined cycle natural gas-fired power station in Colleton County, South Carolina, to be jointly owned by DESC and Santee Cooper
CAO		Chief Accounting Officer
CCR		Coal combustion residual
CCRO		Customer credit reinvestment offset
CEA		Commodity Exchange Act
CEO		Chief Executive Officer
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund

3

Abbreviation or Acronym		Definition
CFIUS		The Committee on Foreign Investment in the U.S.
CFO		Chief Financial Officer
CH4		Methane
Chesterfield Energy Reliability Center		A proposed 944 MW simple-cycle, natural gas-fired power station in Chesterfield County, Virginia
CNG		Consolidated Natural Gas Company
CO2		Carbon dioxide
CODM		Chief Operating Decision Maker
Community Energy Act		House Bill 2346, known as the Community Energy Act, which was signed into law in the Commonwealth of Virginia in May 2025
Companies		Dominion Energy and Virginia Power, collectively
Contracted Energy		Contracted Energy operating segment
Cooling degree days		Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, or 75 degrees Fahrenheit in DESC’s service territory, calculated as the difference between 65 or 75 degrees, as applicable, and the average temperature for that day
Cove Point		Cove Point LNG, LP (formerly known as Dominion Energy Cove Point LNG, LP)
CPCN		Certificate of Public Convenience and Necessity
CVOW Commercial Project		A proposed 2.6 GW wind generation facility 27 miles off the coast of Virginia Beach, Virginia in federal waters adjacent to the CVOW Pilot Project and associated interconnection facilities in and around Virginia Beach, Virginia
CVOW Pilot Project		A 12 MW wind generation facility 27 miles off the coast of Virginia Beach, Virginia in federal waters
CWA		Clean Water Act
DECP Holdings		The legal entity DECP Holdings, Inc., which held Dominion Energy’s noncontrolling interest in Cove Point (through September 2023)
DES		Dominion Energy Services, Inc.
DESC		The legal entity, Dominion Energy South Carolina, Inc., one or more of its consolidated entities or operating segment, or the entirety of Dominion Energy South Carolina, Inc. and its consolidated entities
Dodd-Frank Act		The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
DOE		U.S. Department of Energy
Dominion Energy		The legal entity, Dominion Energy, Inc., one or more of its consolidated subsidiaries (other than Virginia Power) or operating segments, or the entirety of Dominion Energy, Inc. and its consolidated subsidiaries
Dominion Energy Direct®		A dividend reinvestment and open enrollment direct stock purchase plan
Dominion Energy South Carolina		Dominion Energy South Carolina operating segment
Dominion Energy Virginia		Dominion Energy Virginia operating segment
Dominion Privatization		Dominion Utility Privatization, LLC, a joint venture between Dominion Energy and Patriot
DSM		Demand-side management
DSM Riders		Rate adjustment clauses, designated Riders C1A, C2A, C3A and C4A, associated with the recovery of costs related to certain Virginia DSM programs in approved DSM cases
Dth		Dekatherm
Duke Energy		The legal entity, Duke Energy Corporation, one or more of its consolidated subsidiaries, or the entirety of Duke Energy Corporation and its consolidated subsidiaries
Eagle Solar		Eagle Solar, LLC, a wholly-owned subsidiary of Dominion Generation, Inc.
East Ohio		The East Ohio Gas Company (a subsidiary of Enbridge effective March 2024)
East Ohio Transaction		The sale by Dominion Energy to Enbridge of all issued and outstanding capital stock in Dominion Energy Questar Corporation and its consolidated subsidiaries, which following a reorganization included East Ohio and Dominion Energy Gas Distribution, LLC, pursuant to a purchase and sale agreement entered into on September 5, 2023, which was completed on March 6, 2024
Enbridge		The legal entity, Enbridge Inc., one or more of its consolidated subsidiaries (including Enbridge Elephant Holdings, LLC, Enbridge Parrot Holdings, LLC and Enbridge Quail Holdings, LLC), or the entirety of Enbridge Inc. and its consolidated subsidiaries
EPA		U.S. Environmental Protection Agency
EPACT		Energy Policy Act of 2005
EPS		Earnings per common share
ERISA		Employee Retirement Income Security Act of 1974
ESA		Endangered Species Act
Excess Tax Benefits		Benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation
FASB		Financial Accounting Standards Board
FCC		Federal Communications Commission
FERC		Federal Energy Regulatory Commission

4

Abbreviation or Acronym		Definition
FirstEnergy		The legal entity FirstEnergy Corp., one or more of its consolidated subsidiaries, or the entirety of FirstEnergy Corp. and its consolidated subsidiaries
Fitch		Fitch Ratings Ltd.
FTRs		Financial transmission rights
GAAP		U.S. generally accepted accounting principles
GENCO		South Carolina Generating Company, Inc.
GHG		Greenhouse gas
Green Mountain		Green Mountain Power Corporation
Greensville County		A 1,605 MW combined-cycle, natural gas-fired power station in Greensville County, Virginia
GTSA		Virginia Grid Transformation and Security Act of 2018
GW		Gigawatt
Heating degree days		Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, or 60 degrees Fahrenheit in DESC’s service territory, calculated as the difference between 65 or 60 degrees, as applicable, and the average temperature for that day
Hopewell		Polyester biomass power station
Idaho Commission		Idaho Public Utilities Commission
IRA		An Act to Provide for Reconciliation Pursuant to Title II of Senate Concurrent Resolution 14 of the 117th Congress (also known as the Inflation Reduction Act of 2022) enacted on August 16, 2022
IRS		Internal Revenue Service
ISO		Independent system operator
ISO-NE		ISO New England
Jones Act		The Coastwise Merchandise Statute (commonly known as the Jones Act) 46 U.S.C. §55102 regulating U.S. maritime commerce
kV		Kilovolt
LNG		Liquefied natural gas
LTIP		Long-term incentive program
Massachusetts Municipal		Massachusetts Municipal Wholesale Electric Company
mcfe		Thousand cubic feet equivalent
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
MGD		Million gallons per day
Millstone		Millstone nuclear power station
Millstone 2019 power purchase agreements		Power purchase agreements with Eversource Energy and The United Illuminating Company for Millstone to provide nine million MWh per year of electricity for ten years
MMBtu		Metric Million British thermal unit
Moody’s		Moody’s Investors Service
MW		Megawatt
MWh		Megawatt hour
N2O		Nitrous oxide
Natural Gas Rate Stabilization Act		Legislation effective February 2005 designed to improve and maintain natural gas service infrastructure to meet the needs of customers in South Carolina
NAV		Net asset value
NEIL		Nuclear Electric Insurance Limited
NERC		North American Electric Reliability Corporation
NND Project		V.C. Summer Units 2 and 3 nuclear development project under which DESC and Santee Cooper undertook to construct two Westinghouse AP1000 Advanced Passive Safety nuclear units in Jenkinsville, South Carolina
North Anna		North Anna nuclear power station
North Carolina Commission		North Carolina Utilities Commission
NOX		Nitrogen oxide
NRC		U.S. Nuclear Regulatory Commission
NYSE		New York Stock Exchange
OBBBA		An Act to Provide for Reconciliation Pursuant to Title II of House Concurrent Resolution 14 of the 119th Congress (also known as the One Big Beautiful Bill Act) enacted on July 4, 2025
October 2014 hybrids		Dominion Energy’s 2014 Series A Enhanced Junior Subordinated Notes due 2054
ODEC		Old Dominion Electric Cooperative
Ohio Commission		Public Utilities Commission of Ohio
Order 1000		Order issued by FERC adopting requirements for electric transmission planning, cost allocation and development

5

Abbreviation or Acronym		Definition
OSHA Recordable Rate		Number of recordable cases, as defined by the Occupational Safety and Health Administration, a division of the U.S. Department of Labor, for every 100 employees over the course of a year
OSWP		OSW Project LLC, a limited liability company owned by Virginia Power and Stonepeak
ozone season		The period May 1 through September 30, as determined on a federal level
Patriot		Patriot Utility Privatizations, LLC, a joint venture between Foundation Infrastructure Partners, LLC and John Hancock Life Insurance Company (U.S.A.) and affiliates
PFAS		Per- and polyfluorinated substances, a group of widely used chemicals that break down very slowly over time in the environment
PHMSA		Pipeline and Hazardous Materials Safety Administration
PJM		PJM Interconnection, LLC
PSD		Prevention of significant deterioration
PSNC		Public Service Company of North Carolina, Incorporated (a subsidiary of Enbridge effective September 2024)
PSNC Transaction		The sale by Dominion Energy to Enbridge of all of its membership interests in Fall North Carolina Holdco LLC and its consolidated subsidiaries, which following a reorganization included PSNC, pursuant to a purchase and sale agreement entered into on September 5, 2023, which was completed on September 30, 2024
Pumpkinseed		A 60 MW solar generation facility in Emporia, Virginia
Questar Gas		Questar Gas Company (a subsidiary of Enbridge effective May 2024)
Questar Gas Transaction		The sale by Dominion Energy to Enbridge of all of its membership interests in Fall West Holdco LLC and its consolidated subsidiaries, which following a reorganization included Questar Gas, Wexpro, Wexpro II Company, Wexpro Development Company, Dominion Energy Wexpro Services Company, Questar InfoComm Inc. and Dominion Gas Projects Company, LLC, pursuant to a purchase and sale agreement entered into on September 5, 2023, which was completed on May 31, 2024
Regulation Act		Legislation effective July 1, 2007, that amended the Virginia Electric Utility Restructuring Act and fuel factor statute, which legislation is also known as the Virginia Electric Utility Regulation Act, as amended in 2015, 2018 and 2023
RGGI		Regional Greenhouse Gas Initiative
Rider CCR		A rate adjustment clause associated with the recovery of costs related to the removal of CCR at certain power stations
Rider CE		A rate adjustment clause associated with the recovery of costs related to certain renewable generation, energy storage and related transmission facilities in Virginia, certain small-scale distributed generation projects and related transmission facilities and, beginning May 2024, power purchase agreements for the energy, capacity, ancillary services and renewable energy credits owned by third parties
Rider DIST		A rate adjustment clause associated with the recovery of costs related to electric distribution grid transformation projects that the Virginia Commission has approved as authorized by the GTSA and costs of new underground distribution facilities
Rider GEN		A rate adjustment clause associated with the recovery of costs related to Altavista, Hopewell, Southampton, Brunswick County, Greensville County, certain solar facilities and the Virginia LNG Storage Facility
Rider OSW		A rate adjustment clause associated with costs incurred to construct, own and operate the CVOW Commercial Project
Rider RPS		A rate adjustment clause associated with the recovery of costs related to the mandatory renewable portfolio standard program established by the VCEA
Rider SNA		A rate adjustment clause associated with costs relating to the preparation of the applications for subsequent license renewal to the NRC to extend the operating licenses of Surry and North Anna and related projects
Rider T1		A rate adjustment clause to recover the difference between revenues produced from transmission rates included in base rates, and the new total revenue requirement developed annually for the rate years effective September 1
Rider U		A rate adjustment clause associated with the recovery of costs of new underground distribution facilities
ROE		Return on equity
ROIC		Return on invested capital
RTEP		Regional transmission expansion plan
RTO		Regional transmission organization
SAIDI		System Average Interruption Duration Index, metric used to measure electric service reliability
Santee Cooper		South Carolina Public Service Authority
SCANA		The legal entity, SCANA Corporation, one or more of its consolidated subsidiaries, or the entirety of SCANA Corporation and its consolidated subsidiaries
SCANA Combination		Dominion Energy’s acquisition of SCANA completed on January 1, 2019 pursuant to the terms of the agreement and plan of merger entered on January 2, 2018 between Dominion Energy and SCANA

6

Abbreviation or Acronym		Definition
SCANA Merger Approval Order		Final order issued by the South Carolina Commission on December 21, 2018 setting forth its approval of the SCANA Combination
SCDOR		South Carolina Department of Revenue
SCESA		South Carolina Energy Security Act
Scope 1 emissions		Emissions that are produced directly by an entity’s own operations
Scope 2 emissions		Emissions from electricity a company consumes but does not generate from its own facilities
Scope 3 emissions		Emissions generated downstream of company operations by customers and upstream by suppliers
SEC		U.S. Securities and Exchange Commission
Section 232		Section 232 of the Trade Expansion Act of 1962
SEEM		Southeast Energy Exchange Market
SERC		Southeast Electric Reliability Council
Series B Preferred Stock		Dominion Energy’s 4.65% Series B Fixed-Rate Cumulative Redeemable Perpetual Preferred Stock, without par value, with a liquidation preference of $1,000 per share
Series C Preferred Stock		Dominion Energy’s 4.35% Series C Fixed-Rate Cumulative Redeemable Perpetual Preferred Stock, without par value, with a liquidation preference of $1,000 per share
SF6		Sulfur hexafluoride
SO2		Sulfur dioxide
South Carolina Commission		Public Service Commission of South Carolina
Southampton		Southampton biomass power station
Southern		The legal entity, The Southern Company, one or more of its consolidated subsidiaries, or the entirety of The Southern Company and its consolidated subsidiaries
Spruce Power		The legal entity, Spruce Power Holding Corporation, one or more of its consolidated subsidiaries, or the entirety of Spruce Power Holding Corporation and its consolidated subsidiaries
Standard & Poor’s		Standard & Poor’s Ratings Services, a division of S&P Global Inc.
Stonepeak		The legal entity Stonepeak Partners, LLC, one or more of its affiliated investment vehicles (including Dunedin Member LLC) or the entirety of Stonepeak Partners, LLC and its affiliated investment vehicles
Summer		V.C. Summer nuclear power station
Surry		Surry nuclear power station
Toshiba		Toshiba Corporation, parent company of Westinghouse
Toshiba settlement		Settlement Agreement dated as of July 27, 2017, by and among Toshiba, DESC and Santee Cooper
TSR		Total shareholder return
Utah Commission		Utah Public Service Commission
Valley Link		Valley Link Transmission Company, LLC, a limited liability company owned by Dominion Energy, AEP and FirstEnergy, one or more of its consolidated subsidiaries or the entirety of Valley Link Transmission Company, LLC and its consolidated subsidiaries
VCEA		Virginia Clean Economy Act of March 2020
VEBA		Voluntary Employees’ Beneficiary Association
VIE		Variable interest entity
Virginia City Hybrid Energy Center		A 610 MW baseload carbon-capture compatible, clean coal powered electric generation facility in Wise County, Virginia
Virginia Commission		Virginia State Corporation Commission
Virginia Facilities		Proposed electric interconnection and transmission facilities in and around Virginia Beach, Virginia, comprising transmission facilities required to interconnect the CVOW Commercial Project reliably with the existing transmission system; including 3 miles of 230 kV offshore export circuits, 4 miles of underground 230 kV onshore export circuits, a new Harpers switching station, 14 miles of three new overhead 230 kV transmission circuits between a new Harpers switching station and the Fentress substation, rebuild eight miles of two existing 230 kV overhead lines and an expansion of the Fentress substation
Virginia LNG Storage Facility		A proposed LNG storage facility in Brunswick and Greensville Counties, Virginia
Virginia Power		The legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segment, or the entirety of Virginia Electric and Power Company and its consolidated subsidiaries
VOC		Volatile organic compounds
VPFS		Virginia Power Fuel Securitization, LLC
VPP		Virtual power plant
Warren County		A 1,349 MW combined-cycle, natural gas-fired power station in Warren County, Virginia
Westinghouse		Westinghouse Electric Company LLC
Wexpro		The legal entity, Wexpro Company, one or more of its consolidated subsidiaries, or the entirety of Wexpro Company and its consolidated subsidiaries (a subsidiary of Enbridge effective May 2024)
Wyoming Commission		Wyoming Public Service Commission

7

Part I

Item 1. Business

General

Dominion Energy, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, provides service to approximately 4.1 million primarily electric utility customers in Virginia, North Carolina and South Carolina. At December 31, 2025, Dominion Energy’s portfolio of assets includes approximately 30.7 GW of electric generating capacity, 10,800 miles of electric transmission lines and 80,400 miles of electric distribution lines. Dominion Energy is one of the nation’s leading developers and operators of regulated offshore wind and solar power and the largest producer of carbon-free electricity in New England. Dominion Energy’s mission is to provide the reliable, affordable and increasingly clean energy that powers its customers every day.

In connection with the comprehensive business review concluded in March 2024, Dominion Energy entered into agreements in September 2023 to sell all of its regulated gas distribution operations, except for DESC’s, to Enbridge. In addition, Dominion Energy completed the sale in September 2023 of its remaining 50% noncontrolling partnership interest in Cove Point to BHE under an agreement entered into in July 2023. Dominion Energy continues to focus on expanding and improving its regulated electric utilities and long-term contracted businesses while transitioning to a cleaner energy future. Its approximately $65 billion capital expenditure plan for 2026 through 2030 advances its “all-of-the-above” strategy through investments in zero-carbon and renewable generation, grid transformation, generation reliability and transmission and distribution resiliency to meet projected demand growth. Renewable generation facilities are expected to include significant investments in utility-scale solar and the CVOW Commercial Project. In addition, Dominion Energy has received license extensions for its regulated nuclear power stations in Virginia and South Carolina and intends to apply for license extensions for Millstone.

Dominion Energy currently expects approximately 95% of earnings to come from state-regulated utility operations in Virginia, North Carolina and South Carolina. Dominion Energy’s nonregulated operations consist primarily of long-term contracted electric generation operations. Dominion Energy’s operations are conducted through various subsidiaries, including DESC and Virginia Power. DESC is an SEC registrant; however, its Form 10-K is filed separately and is not combined herein.

Virginia Power, headquartered in Richmond, Virginia and incorporated in Virginia in 1909 as a Virginia public service corporation, is a wholly-owned subsidiary of Dominion Energy and a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and North Carolina. In Virginia, Virginia Power conducts business under the name “Dominion Energy Virginia” and primarily serves retail customers. In North Carolina, it conducts business under the name “Dominion Energy North Carolina” and serves retail customers located in the northeastern region of the state, excluding certain municipalities. In addition, Virginia Power sells and transmits electricity at wholesale prices to rural electric cooperatives, municipalities and into wholesale electricity markets. All of Virginia Power’s stock is owned by Dominion Energy.

Amounts and information disclosed for Dominion Energy are inclusive of Virginia Power, where applicable.

Where You Can Find More Information About the Companies

The Companies file their annual, quarterly and current reports, proxy statements and other information with the SEC. Their SEC filings are available to the public over the Internet at the SEC’s website at https://www.sec.gov.

The Companies make their SEC filings, including the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports, available, free of charge, through Dominion Energy’s website, https://www.dominionenergy.com, as soon as reasonably practicable after filing or furnishing the material to the SEC. The Companies also make available on the “Investors” page of Dominion Energy’s website additional information which may be important to investors, such as investor presentations, earnings release kits and other materials and presentations. Information contained on Dominion Energy’s website, including, but not limited to reports mentioned in Environmental Strategy, is not incorporated by reference in this report.

Acquisitions and Dispositions

The following acquisitions and divestitures within the last three years are considered significant to the Companies.

Gas Distribution Operations

Sales to Enbridge

In March 2024, Dominion Energy completed the East Ohio Transaction with Enbridge for $4.3 billion in cash consideration and the assumption by Enbridge of approximately $2.3 billion of related long-term debt.

In May 2024, Dominion Energy completed the Questar Gas Transaction with Enbridge for $3.0 billion in cash consideration and the assumption by Enbridge of approximately $1.3 billion of related long-term debt.

In September 2024, Dominion Energy completed the PSNC Transaction with Enbridge for $2.0 billion in cash consideration and the assumption by Enbridge of approximately $1.3 billion of related long-term debt.

See Note 3 to the Consolidated Financial Statements for additional information.

Electric Generation Facilities

Sale of Noncontrolling Interest in CVOW Commercial Project

In October 2024, Virginia Power completed the sale of a 50% noncontrolling interest in the CVOW Commercial Project to Stonepeak through the formation of OSWP. At closing, Virginia Power received $2.6 billion, representing 50% of the CVOW Commercial Project construction costs incurred through closing, less an initial withholding of $145 million.

See Note 10 to the Consolidated Financial Statements for additional information.

Acquisition of Nonregulated Solar Projects

In 2023, Dominion Energy entered into an agreement to acquire a nonregulated solar project in Virginia and completed the acquisition in 2024. The project was completed at a total cost of approximately $195 million, including initial acquisition cost, and generates approximately 83 MW.

8

See Note 10 to the Consolidated Financial Statements for additional information.

Acquisition of Offshore Wind Project

In October 2024, Virginia Power completed the acquisition of an approximately 40,000-acre area lease 27 miles off the coast of North Carolina in federal waters and associated project assets in the early stages of development for approximately $160 million.

See Note 10 to the Consolidated Financial Statements for additional information.

Equity Method Investment

Sale of Interest in Cove Point

In September 2023, Dominion Energy completed the sale of its 50% noncontrolling limited partnership interest in Cove Point to BHE for approximately $3.3 billion in cash proceeds.

See Note 9 to the Consolidated Financial Statements for additional information.

Human Capital

One of Dominion Energy’s greatest strengths is its employees, and their unique skills, knowledge, expertise and backgrounds allow Dominion Energy to fulfill its mission to provide the reliable, affordable and increasingly clean energy that powers its customers every day. At December 31, 2025, Dominion Energy had approximately 15,200 full-time employees, of which approximately 3,400 are subject to collective bargaining agreements, including approximately 6,700 full-time employees at Virginia Power, of which approximately 2,700 are subject to collective bargaining agreements.

Safety is the highest priority of Dominion Energy’s five core values with the fundamental goal to send every employee home safe and sound every day. In 2025, Dominion Energy experienced an OSHA Recordable Rate of 0.26 compared to 0.42 in 2024 and 0.45 in 2023. These rates reflect Dominion Energy’s dedication to safety when compared to a BLS Industry Average OSHA Recordable Rate of 1.9 in 2024 and 2.0 in 2023. As evidence of Dominion Energy’s commitment to safety, annual incentive plans for all employees, except as restricted by any collective bargaining agreements, include a safety performance measure.

Dominion Energy works to recruit, retain and develop the careers of talented individuals regardless of background who reflect its core values; safety, ethics, excellence, embrace change and one Dominion Energy. These core values support Dominion Energy’s employees in their efforts to optimize performance, collaborate within teams and across the organization and create a respectful, welcoming work environment. As an example, Dominion Energy sponsors ten employee resource groups enabling employees to work together to create community and promote excellent performance. Further, Dominion Energy is an equal opportunity employer committed to non-discrimination in all operations. As part of this, Dominion Energy periodically reviews its workforce representation to ensure it is casting a wide net for the best and brightest talent. In 2025, 2024 and 2023, the percentage of Dominion Energy’s workforce that was diverse was 39.1%, 38.7% and 37.7%, respectively. In 2025, 2024 and 2023, the percentage of new hires that were diverse was 43.9%, 45.3% and 49.0%, respectively. For the purposes of measuring and reporting on diversity as required by federal law, Dominion Energy follows federal EEO-1 guidelines and includes employees who self-identify their gender as female and/or their race/ethnicity as American Indian or Alaskan Native, Asian, Black or African American, Hispanic or Latino, Native Hawaiian or Other Pacific Islander or Two or More Races.

Dominion Energy attracts and retains its employees by offering competitive compensation and benefits packages, including healthcare, retirement, paid time off, parental leave and other benefits. Dominion Energy also offers continuous learning opportunities including tuition assistance programs, professional development resources and leadership development programs. Additionally, Dominion Energy creates opportunities for its employees to engage its leaders and with each other through respectful two-way conversations that help employees and leaders learn from one another, share insights and opinions and broaden the workforce’s perspectives regarding what matters to customers. Dominion Energy prioritizes employee engagement and routinely seeks feedback through surveys, focus groups and other means. Such feedback informs management decisions, enhances support for employees and improves customer service. These resources and programs are designed not only to engage and retain talented employees but also to allow Dominion Energy to meet the needs of its customers in an ever-changing industry with a skilled workforce.

OPERATING SEGMENTS

Dominion Energy manages its daily operations through three primary operating segments: Dominion Energy Virginia, Dominion Energy South Carolina and Contracted Energy. See Note 26 to the Consolidated Financial Statements for a summary description of operations within each of the three primary operating segments. Dominion Energy also reports a Corporate and Other segment, which includes its corporate, service companies and other functions (including unallocated debt) as well as Dominion Energy’s noncontrolling interest in Dominion Privatization. Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the operating segments’ performance or in allocating resources. In addition, Corporate and Other includes the net impact of discontinued operations consisting primarily of the operations included in the East Ohio, PSNC and Questar Gas Transactions and Dominion Energy’s equity investment in Atlantic Coast Pipeline as discussed in Notes 3 and 9 to the Consolidated Financial Statements.

Virginia Power manages its daily operations through its primary operating segment: Dominion Energy Virginia. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources.

DOMINION ENERGY VIRGINIA

Dominion Energy Virginia is composed of Virginia Power’s regulated electric transmission, distribution and generation (regulated electric utility and its related energy supply) operations, which serve approximately 2.8 million residential, commercial, high load (including certain data centers), industrial and governmental customers in Virginia and North Carolina.

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Dominion Energy Virginia’s capital plan for 2026 through 2030 includes spending approximately $55 billion, net of reimbursements from Stonepeak, to construct new generation capacity, including the CVOW Commercial Project and dispatchable generation facilities, to continue developments to meet its renewable generation targets and growing electricity demand within its service territory in order to maintain reliability and regulatory compliance and to upgrade or add new transmission lines, distribution lines, substations and other facilities, as well as maintain existing generation capacity. The proposed infrastructure projects and investment commitments are intended to address both continued customer growth and increases in electricity consumption which are primarily driven by new and larger data center customers. See Properties and Environmental Strategy for additional information on this and other utility projects.

Data centers have been a source of significant increase in demand which is expected to continue over the next decade. The concentration of data centers primarily in Loudoun County, Virginia represents a unique challenge and requires significant investments in electric transmission and generation facilities to meet the growing demand. PJM has projected a 5.4% average peak annual load growth over the next ten years for the PJM DOM Zone, which includes Dominion Energy Virginia’s service territory. Data centers represent 28% and 26% of Virginia Power’s electricity sales for the years ended December 31, 2025 and 2024, respectively. Virginia Power has implemented requirements over the years intended to ensure that its project queue is firm, such as requiring deposits for expensive long lead-time equipment along with reimbursement clauses for canceled projects.  In addition, Virginia Power will, in accordance with the terms of the 2025 Biennial Review order, begin in January 2027 to require a 14-year contract, collateral over that period and demand minimums for distribution, transmission and generation revenues for high load customers at connection. All of these contract provisions are designed to minimize both cross-rate class subsidies and stranded costs.

Virginia Power also plans to continue making progress on its ten-year plan through 2028 to transform its electric grid into a smarter, stronger and greener grid. This plan addresses the structural limitations of Virginia Power’s distribution grid in a systematic manner in order to recognize and accommodate fundamental changes and requirements in the energy industry. The objective is to address both customer and system needs by (i) achieving even higher levels of reliability and resiliency against natural and man-made threats, (ii) leveraging technology to enhance the customer experience and improve the operation of the system and (iii) safely and effectively integrating new utility-scale renewable generation and storage as well as customer–level distributed energy resources such as rooftop solar and battery storage. The Virginia Commission has approved portions of this plan through 2026.

Revenue provided by electric distribution and generation operations is based primarily on rates established by the Virginia and North Carolina Commissions. Approximately 80% of revenue comes from serving Virginia jurisdictional customers. Base rates for the Virginia jurisdiction are set using a modified cost-of-service rate model, and are generally designed to allow an opportunity to recover the cost of providing utility service and earn a reasonable return on investments used to provide that service. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures. Electric operations continue to focus on improving service and experience levels while striving to reduce costs and link investments to operational results. SAIDI performance results, excluding major events, were 133 minutes for the three-year average ending 2025, up from the previous three-year average of 130 minutes. This increase is primarily due to increased storm activity.

Earnings may also reflect variations in the timing or nature of expenses as compared to those contemplated in current rates, such as labor and benefit costs, capacity expenses, the timing, duration and costs of scheduled and unscheduled outages as well as certain customers’ ability to choose a generation service provider. The cost of fuel and purchased power is generally collected through fuel cost-recovery mechanisms established by regulators and does not materially impact net income. The cost of new generation facilities is generally recovered through riders in Virginia. Variability in earnings from riders reflects changes in the authorized ROE and the carrying amount of these facilities, which are largely driven by the timing and amount of capital investments, as well as depreciation. See Note 13 to the Consolidated Financial Statements for additional information.

Revenue provided by Virginia Power’s electric transmission operations is based primarily on rates approved by FERC. The profitability of this business is dependent on its ability, through the rates it is permitted to charge, to recover costs and earn a reasonable ROIC. Variability in earnings primarily results from changes in rates and the timing of property additions, retirements and depreciation.

Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into PJM. Consistent with the increased authority given to NERC by EPACT, Virginia Power is committed to meeting NERC standards, modernizing its infrastructure and maintaining superior system reliability with respect to its electric transmission operations.

Competition

There is no competition for electric distribution service within Virginia Power’s service territory in Virginia and North Carolina and no such competition is currently permitted. Historically, since its electric transmission facilities are integrated into PJM and electric transmission services are administered by PJM, there was no competition in relation to transmission service provided to customers within the PJM region. However, competition from non-incumbent PJM transmission owners for development, construction and ownership of certain transmission facilities in Virginia Power’s service territory is permitted pursuant to Order 1000, subject to state and local siting and permitting approvals. This has resulted in additional competition to build and own transmission infrastructure in Virginia Power’s service area and allows Dominion Energy to seek opportunities to build and own facilities in other service territories, for example, through Valley Link. Additionally, there is some competition for Virginia Power’s generation operations for Virginia jurisdictional electric utility customers that meet certain size requirements or that currently are purchasing energy from competitive suppliers deemed to be 100% renewable by the Virginia Commission. See Electric under State Regulations in Regulation for additional information. Currently, North Carolina does not offer retail choice to electric customers.

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Virginia Power’s non-jurisdictional solar operations are not currently subject to significant competition as the output from these facilities is primarily sold under long-term power purchase agreements with terms generally ranging from 16 to 25 years. However, in the future, such operations may compete with other power generation facilities to serve certain large-scale customers after the power purchase agreements expire.

Regulation

Virginia Power’s electric distribution and generation operations, including the rates it may charge to jurisdictional customers, as well as wholesale electric transmission rates, tariffs and terms of service, are subject to regulation by the Virginia and North Carolina Commissions as well as FERC, NRC, EPA, DOE, U.S. Army Corps of Engineers, BOEM and other federal, state and local authorities. See State Regulations and Federal Regulations in Regulation, Future Issues and Other Matters in Item 7. MD&A and Notes 13 and 23 to the Consolidated Financial Statements for additional information.

Properties

For a description of existing facilities see Item 2. Properties.

CVOW Commercial Project

In September 2019, Virginia Power filed applications with PJM for the CVOW Commercial Project and for certain approvals and rider recovery from the Virginia Commission in November 2021. The Virginia Commission provided such approvals in August 2022, as revised for certain provisions related to rider recovery in December 2022. The majority of turbines comprising the 2.6 GW project are expected to be placed in service by the end of 2026 with the remainder in early 2027. The estimated total project cost is approximately $11.5 billion (excluding financing costs) which reflects a temporary suspension of work order and an estimated impact of certain tariffs which became effective during 2025 as well as the previously included revised estimate of network upgrade costs assigned by PJM to the CVOW Commercial Project. The Companies’ projected impact of tariffs on expected total project cost is subject to change due to the inherent uncertainty associated with which tariffs, if any, may be in effect and the associated requirements and rates of such tariffs. Virginia Power’s estimate for the project’s projected levelized cost of energy, including renewable energy credits, is approximately $84/MWh, compared to the initial filing submission of $80-90/MWh.

The expected total project cost reflects an increase of $0.2 billion, relative to Virginia Power’s October 2025 Rider OSW filing, associated with projected installation timeline changes arising from the temporary suspension of work from the BOEM Director’s Order issued in December 2025 until a preliminary injunction was granted by the U.S District Court for the Eastern District of Virginia in January 2026, which allowed work to resume. The estimated total project costs also include $0.6 billion of tariffs on equipment expected to be delivered from March 2025 through March 2026 that originates from Mexico, Canada, a European Union member or other applicable countries and on equipment expected to be delivered from March 2025 through early 2027 that contains steel. Such amount is inclusive of approximately $0.2 billion associated with tariffs on equipment expected to be delivered from March 2025 through March 2026 that originates from Mexico, Canada, a European Union member or other applicable countries that were the subject of a U.S. Supreme Court’s ruling on February 20, 2026. The actual tariffs to be incurred are dependent upon the tariff requirements and rates, if any, at the time of delivery of the specific component.

As previously considered in Virginia Power’s February 2025 construction update filing, the expected total project cost reflects projections for onshore electrical interconnection costs and network upgrade costs assigned to the project by PJM, specifically incorporating consideration of PJM’s December 2024 publication of potential transmission network upgrades required for certain generation projects and related cost allocations, including those attributable to the CVOW Commercial Project. Relative to Virginia Power’s November 2024 Rider OSW filing, the estimated total project cost reflects an approximately $0.6 billion increase for such onshore and network upgrade costs and an approximately $0.3 billion increase for increased contingency for remaining construction activities, completion of the removal of unexploded ordnance, undersea cable protection system design enhancements, commodity prices for transportation fuel, updates for sea fastener fabrication and installation and other construction and equipment supplier costs.

Virginia Power has entered into fixed price contracts for the major offshore construction and equipment components. These contracts include services denominated in currencies other than the U.S. dollar for approximately €2.6 billion and 5.1 billion kr., which have been included within the cost estimate above. In addition, certain of the fixed price contracts, approximately €0.7 billion, contain commodity indexing provisions linked to steel. In May 2022, Virginia Power entered into forward purchase agreements with a notional amount of approximately €3.2 billion to hedge its foreign currency rate risk exposure from certain fixed price contracts for the major offshore construction and equipment components of the CVOW Commercial Project. In January 2026, the interconnection agreement between PJM and Virginia Power for the CVOW Commercial Project was filed with FERC.

The estimated total project cost above reflects the Companies’ best estimate of the remaining construction costs, including contingency of approximately 7% on such remaining amounts. Such estimate could potentially change for items, certain of which are beyond the Companies’ control, including but not limited to actual network upgrade costs allocated by PJM, fuel for transportation and installation, the impact of applicable tariffs including any potential impact of Section 232 investigations and litigation ruled on by the U.S. Supreme Court on February 20, 2026, costs to maintain necessary permits, approvals and authorizations, any additional suspension of work orders, ability of key suppliers and contractors to timely satisfy their obligations under existing contracts, marine wildlife and/or any severe weather events.

Virginia Power commenced major onshore construction activities for the CVOW Commercial Project in November 2023 following the receipt of a record of decision from BOEM in October 2023 for construction. Onshore construction activities to support first power delivery were completed in December 2025 with remaining project activities to support commercial operations anticipated to be completed by mid-2026. Virginia Power commenced major offshore construction activities in May 2024 following the receipt of final approval from BOEM authorizing offshore construction and necessary permits from the U.S. Army Corps of Engineers for offshore construction in January 2024.

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Virginia Power completed the installation of all monopiles in October 2025. Transition pieces began to be installed on monopiles near the end of 2024 with 126 transition pieces installed through February 2026 and the remaining 50 expected to be installed in early 2026. The first of three offshore substations was installed in March 2025, with the second installed in November 2025 and the third installed in February 2026. Deepwater cables commenced being laid in late 2024 with the last of nine completed in July 2025. Of the 176 segments of interarray cable, expected to total 260 miles, 59 have been installed through February 2026 with the remaining expected to be laid throughout 2026. Installation commenced on turbines in December 2025 prior to being delayed by the temporary suspension of work order, with one of 176 completed through February 2026.

In August 2022, the Virginia Commission approved the application for certification of the Virginia Facilities component of the CVOW Commercial Project, the revenue requirement for the initial rate year of Rider OSW, subject to certain performance measures, and noted that no further action was required with respect to Virginia Power’s foreign currency risk mitigation plan. In December 2022, the Virginia Commission approved the settlement agreement filed in October 2022 by Virginia Power, Office of the Attorney General of Virginia and other parties and reinstated its August 2022 order granting approval of Rider OSW. The settlement agreement provides for a voluntary cost sharing mechanism resulting from unforeseen construction cost increases; specifically, that Virginia Power will be eligible to recover 50% of such incremental costs which fall between $10.3 billion and $11.3 billion with no recovery of such incremental costs which fall between $11.3 billion and $13.7 billion. There is no voluntary cost sharing mechanism for any total construction costs in excess of $13.7 billion, the recovery of which would be determined in a future Virginia Commission proceeding. The settlement agreement also provides for customers to receive the maximum benefits available under the IRA including that to the extent the IRA reduces the total construction costs, such reductions will also be applied to the cost sharing bands discussed above. In addition, the settlement agreement includes enhanced performance reporting provisions, in lieu of a performance guarantee, for the operation of the CVOW Commercial Project. To the extent the annual net capacity factor is below 42%, as determined on a three-year rolling average, Virginia Power is required to provide detailed explanation of the factors contributing to any shortfall to the Virginia Commission which could determine in a future proceeding a remedy for incremental costs incurred associated with any deemed unreasonable or imprudent actions of Virginia Power. See Note 13 to the Consolidated Financial Statements for additional information on Rider OSW.

In January 2023, following receipt of approval from the Virginia and North Carolina Commissions, Virginia Power entered into a lease contract with an affiliated entity for the use of a Jones Act compliant offshore wind installation vessel at a total cost of approximately $240 million plus ancillary services. The vessel was delivered and the 20-month lease term commenced in September 2025. See additional discussion of the affiliated lease agreement in Note 25 to the Consolidated Financial Statements.

Virginia Power anticipates funding the CVOW Commercial Project consistent with its approved debt to equity capitalization structure. Through December 31, 2025, approximately $9.3 billion of costs had been incurred on the project. See Liquidity – Capital Expenditures in Item 7. MD&A for project costs expected to be incurred in 2026 through 2030. In October 2024, Virginia Power closed on the sale of a 50% noncontrolling interest in the project to Stonepeak following satisfaction of regulatory approvals, including from BOEM and the Virginia and North Carolina Commissions. At closing, Virginia Power received $2.6 billion, representing 50% of the CVOW Commercial Project construction costs incurred through closing, less an initial withholding of $145 million. If the total project costs of the CVOW Commercial Project are $9.8 billion, excluding financing costs, or less Virginia Power shall receive $100 million of the initial withholding. Such amount is subject to downward adjustment with Virginia Power receiving no withheld amounts if the total costs, excluding financing costs, of the CVOW Commercial Project exceed $11.3 billion.

Virginia Power and Stonepeak will each contribute 50% of the remaining capital necessary to fund construction of the CVOW Commercial Project provided the total project cost, excluding financing costs, is less than $11.3 billion. For capital funding necessary, if any, for total project costs, excluding financing costs, of $11.3 billion through $13.7 billion, Stonepeak will have the option to make additional capital contributions. If Stonepeak elects to make additional capital contributions for project costs, excluding financing costs, in excess of $11.3 billion, if any, Virginia Power shall contribute between 67% and 83% of such capital with Stonepeak contributing the remainder.  To the extent that Stonepeak elects not to make such contributions, Virginia Power shall receive an increase in its ownership percentage of OSWP for any contributed capital based on a tiered unit price for membership interests in OSWP as set forth in the agreement. Virginia Power and Stonepeak have the right to provide capital contributions for any total project costs, excluding financing costs, in excess of $13.7 billion.

See Note 10 to the Consolidated Financial Statements for additional information. The CVOW Commercial Project is vital for Virginia Power to meet the renewable energy portfolio standard established in the VCEA and is consistent with the criteria within the VCEA for the construction of an offshore wind facility deemed to be in the public interest as well as the guidelines facilitating cost recovery. See additional discussion of the VCEA provisions concerning renewable generation projects in Note 13 to the Consolidated Financial Statements.

Electric Generation and Storage Projects

In addition to the CVOW Commercial Project, Virginia Power is developing, financing and constructing new generation capacity and has also received license extensions on zero carbon nuclear generation facilities to meet its renewable generation targets and growing electricity demand within its service territory. Significant projects under construction or development as well as significant projects under consideration are set forth below:

•Virginia Power plans to invest approximately $6.9 billion from 2026 through 2030 to acquire or construct several solar facilities to serve utility customers. See Notes 10 and 13 to the Consolidated Financial Statements for additional information.

•Virginia Power plans to invest approximately $2.0 billion from 2026 to 2030 to develop battery-storage facilities to serve utility customers.

•Virginia Power has received approval to construct and operate the Chesterfield Energy Reliability Center. The project is

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expected to cost $1.5 billion, excluding financing costs, to have a generating capacity of 944 MW and be placed into service in 2029 to enhance reliability for utility customers. Virginia Power plans to invest approximately $8.3 billion from 2026 to 2030 to develop additional dispatchable natural gas generation facilities to enhance reliability for utility customers.

•Virginia Power received a 20-year extension of the operating licenses for its two units at Surry in 2021 and its two units at North Anna in 2024. See Nuclear Decommissioning below for additional information on these facilities.

•Virginia Power has begun constructing an LNG storage facility which it will operate to serve as a backup fuel source for Brunswick County and Greensville County to support operations and improve system reliability. The facility is expected to cost approximately $550 million, excluding financing costs, and be placed into service by the end of 2027.

•Virginia Power continues to consider the construction of a third nuclear unit at a site located at North Anna. See Future Issues and Other Matters in Item 7. MD&A for additional information on this project.

•In October 2024, Virginia Power completed the acquisition of an approximately 40,000-acre area lease 27 miles off the coast of North Carolina in federal waters and associated project assets in the early stages of development for approximately $160 million. The CVOW South project, if constructed, is expected to have a generating capacity of 800 MW with ultimate development of the project dependent upon the receipt of approvals from the Virginia Commission and other permitting entities. The project would support Virginia Power’s ability to meet the renewable energy portfolio standards established in the VCEA.

Electric Transmission and Distribution Projects

Virginia Power continues to invest in transmission projects that are a part of PJM’s RTEP process which focus on reliability improvements and replacement of aging infrastructure. The projects that have been authorized by PJM are expected to result in future capital expenditures of approximately $8.3 billion from 2026 through 2030.

In October 2024, Dominion Energy announced a joint planning initiative with AEP and FirstEnergy. As part of the initiative, the companies jointly submitted initial project proposals for high-voltage transmission lines in Virginia, Maryland and West Virginia to PJM. In February 2025, Dominion Energy, AEP and FirstEnergy entered into an agreement for the operation of Valley Link to undertake a multi-year process to develop, construct and subsequently operate the new transmission line projects selected by PJM. Under the terms of the joint venture agreement, Dominion Energy will hold a 30% initial interest in Valley Link. Dominion Energy expects to invest approximately $1.0 billion from 2026 through 2030 in connection with this arrangement.

Virginia legislation provides for the recovery of costs, subject to approval by the Virginia Commission, for Virginia Power to move approximately 4,000 miles of electric distribution lines underground. The program is designed to reduce restoration outage time by moving Virginia Power’s most outage-prone overhead distribution lines underground, has an annual investment cap of approximately $387 million and is expected to be completed by 2029. The Virginia Commission has approved eight phases of the program encompassing approximately 2,500 miles of converted lines and $1.4 billion in capital spending recoverable through Rider U and Rider DIST. Additionally, Virginia Power has requested cost recovery for phase nine of the program from the Virginia Commission, encompassing approximately 300 miles of converted lines and $240 million in capital spending, recoverable through Rider DIST.

See Note 13 to the Consolidated Financial Statements for additional information.

Sources of Energy Supply

Virginia Power uses a variety of fuels to power its electric generation fleet and purchases power for utility system load requirements and to satisfy physical forward sale requirements. Some of these agreements have fixed commitments and are detailed further in Fuel and Other Purchase Commitments in Item 7. MD&A.

Presented below is a summary of Virginia Power’s actual system output by energy source:

Source		2025		2024		2023
Natural gas		39	%	40	%	36	%
Nuclear(1)		25		26		29
Purchased power, net		24		22		25
Coal(2)		7		5		5
Renewable and hydro(3)		5		7		5
Total		100	%	100	%	100	%

(1)Excludes ODEC’s 11.6% undivided ownership interest in North Anna.

(2)Excludes ODEC’s 50.0% undivided ownership interest in the Clover power station.

(3)Includes wind, solar, biomass, battery and pumped storage.

Nuclear Fuel—Virginia Power primarily utilizes long-term contracts to support its nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent on the market environment. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal cost and inventory levels.

Fossil Fuel— Virginia Power primarily utilizes natural gas and coal in its fossil fuel plants. All recent fossil fuel plant construction involves natural gas generation.

Virginia Power’s natural gas and oil supply is obtained from various sources including purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, purchases from local producers in the Appalachian area and Marcellus and Utica regions, purchases from gas marketers and withdrawals from underground storage fields owned by third parties. Virginia Power manages a portfolio of natural gas transportation contracts (capacity) that provides for reliable natural gas deliveries to its gas turbine fleet, while minimizing costs.

Virginia Power’s coal supply is obtained through long-term contracts and short-term spot agreements from domestic suppliers.

Biomass— Virginia Power’s biomass supply is obtained through long-term contracts and short-term spot agreements from local suppliers.

Purchased Power— Virginia Power purchases electricity from the PJM spot market and through power purchase agreements with other suppliers to provide for utility system load requirements.

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Seasonality

Virginia Power’s earnings vary seasonally as a result of the impact of changes in temperature, the impact of storms and other catastrophic weather events and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs, respectively. An increase in heating degree days for Virginia Power’s electric utility-related operations does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials and because alternative heating sources are more readily available.

Nuclear Decommissioning

Virginia Power has a total of four licensed, operating nuclear reactors at Surry and North Anna in Virginia.

Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. Amounts collected from ratepayers have been placed into trusts and are invested to fund the expected future costs of decommissioning the Surry and North Anna units.

Virginia Power believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects the long-term investment horizon, since the units will not be decommissioned for decades, and a positive long-term outlook for trust fund investment returns. Virginia Power will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC.

The estimated cost to decommission Virginia Power’s four nuclear units is reflected in the table below and is primarily based upon site-specific studies completed in 2024. These cost studies are generally completed every four to five years. The current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire.

Under the current operating licenses, Virginia Power is scheduled to decommission the Surry and North Anna units during the period 2052 to 2118. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. Under the current operating licenses, the two units at Surry are permitted to generate electricity through 2052 and 2053, and the two units at North Anna are permitted to generate electricity through 2058 and 2060. Between the four units, Virginia Power estimates that it could spend approximately $5 billion through 2035 on capital improvements. The existing regulatory framework in Virginia provides rate recovery mechanisms for such costs.

The estimated decommissioning costs, funds in trust and current license expiration dates for Surry and North Anna are shown in the following table:

		NRC license expiration year		Most recent cost estimate (2025 dollars)(1)				Funds in trusts at December 31, 2025(2)
(dollars in millions)
Surry
Unit 1		2052		$	907			$	1,383
Unit 2		2053			906				1,361
North Anna
Unit 1(3)		2058			859				1,095
Unit 2(3)		2060			864				1,025
Total				$	3,536			$	4,864

(1)The cost estimates shown above reflect reductions for the expected future recovery of certain spent fuel costs based on Virginia Power’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in Virginia Power’s nuclear decommissioning AROs.

(2)Virginia Power did not make any contributions to its nuclear decommissioning trust funds during 2025.

(3)North Anna is jointly owned by Virginia Power (88.4%) and ODEC (11.6%). However, Virginia Power is responsible for 89.26% of the decommissioning obligation. Amounts reflect 89.26% of the decommissioning cost for both of North Anna’s units.

Also see Notes 9, 14 and 23 to the Consolidated Financial Statements for additional information about nuclear decommissioning trust investments, AROs and other aspects of nuclear decommissioning, respectively.

DOMINION ENERGY SOUTH CAROLINA

Dominion Energy South Carolina is composed of DESC’s generation, transmission and distribution of electricity to approximately 0.8 million customers in the central, southern and southwestern portions of South Carolina and the distribution of natural gas to approximately 0.5 million residential, commercial and industrial customers in South Carolina.

Dominion Energy South Carolina’s capital plan for 2026 through 2030 includes spending approximately $8 billion to upgrade existing or add new infrastructure to meet growing energy needs within its service territory and maintain reliability.

Revenue provided by DESC’s electric distribution operations is based primarily on rates established by the South Carolina Commission. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures.

DESC’s electric transmission operations serve its electric distribution operations as well as certain wholesale customers. Revenue provided by such electric transmission operations is based on a FERC-approved formula rate mechanism under DESC’s open access transmission tariff or based on retail rates established by the South Carolina Commission.

Revenue provided by DESC’s electric generation operations is primarily derived from the sale of electricity generated by its utility generation assets and is based on rates established by the South Carolina Commission. Variability in earnings may arise when revenues are impacted by factors not reflected in current rates, such as the impact of weather, customer demand or the timing and nature of expenses or outages.

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Electric operations continue to focus on improving service and experience levels while striving to reduce costs and link investments to operational results. SAIDI performance results, excluding major events, were 84 minutes for the three-year average ending 2025, up from the previous three-year average of 83 minutes.

Revenue provided by DESC’s natural gas distribution operations primarily results from rates established by the South Carolina Commission. Variability in earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, the availability and prices of alternative fuels and the economy.

DESC is a member of the Carolinas Reserve Sharing Group, one of several geographic divisions within the SERC. The SERC is one of seven regional entities with delegated authority from NERC for the purpose of proposing and enforcing reliability standards approved by NERC. In addition, DESC also participates in the SEEM platform, which became operational in November 2022. See Federal Regulations in Regulation for additional information on SEEM.

Competition

There is no competition for electric distribution or generation service within DESC’s retail electric service territory in South Carolina and no such competition is currently permitted. However, competition from third-party owners for development, construction and ownership of certain transmission facilities in DESC’s service territory is permitted pursuant to Order 1000, subject to state and local siting and permitting approvals. This could result in additional competition to build and own transmission infrastructure in DESC’s service area in the future and, as noted previously, could allow Dominion Energy to seek opportunities to build and own facilities in other service territories.

Competition in DESC’s natural gas distribution operations is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and the ability to retain large commercial and industrial customers.

Regulation

DESC’s electric distribution service, including the rates it may charge to jurisdictional customers, is subject to regulation by the South Carolina Commission. DESC’s electric generation operations are subject to regulation by the South Carolina Commission, FERC, NRC, EPA, DOE, U.S. Army Corps of Engineers and other federal, state and local authorities. DESC’s electric transmission service is primarily regulated by FERC and the DOE. DESC’s gas distribution operations are subject to regulation by the South Carolina Commission, PHMSA, the U.S. Department of Transportation and the South Carolina Office of Regulatory Staff, which enforce federal and state pipeline safety requirements. See State Regulations and Federal Regulations in Regulation, Future Issues and Other Matters in Item 7. MD&A and Notes 13 and 23 to the Consolidated Financial Statements for additional information.

Properties

For a description of existing facilities, see Item 2. Properties.

DESC has the following significant projects under construction or development to better serve customers or expand its service offerings within its service territory:

In February 2024, DESC received approval from the South Carolina Commission to provide electric services to two large industrial customers which will require development of new electric transmission facilities.

In January 2025, DESC received approval from the South Carolina Commission to pursue the construction of a new natural gas-fired combustion turbine unit at Urquhart to increase reliability, improve operational flexibility and reduce emissions. This facility is expected to cost approximately $395 million, excluding financing costs, have a total winter generating capacity of approximately 200 MW and be placed into service by the end of 2028. This project is expected to replace certain legacy natural gas-fired combustion turbine and natural gas-fired steam generation facilities at the site.

In December 2025, DESC, along with Santee Cooper, requested approval for the joint construction and operation of a combined cycle electric generating plant and associated facilities with a net capacity of approximately 2.2 GW. The project is currently expected to cost approximately $5 billion in total, excluding financing costs, with costs split equally between the joint owners, and is expected to be placed in service by 2033. These estimates are subject to refinement through the permitting process and the negotiation of contracts for major construction suppliers. The project reflects DESC’s commitment to reliable, affordable and cleaner energy while reinvesting in the local community.

Sources of Energy Supply

DESC uses a variety of fuels to power its electric generation fleet and purchases power for utility system load requirements. Some of these agreements have fixed commitments and are detailed further in Fuel and Other Purchase Commitments in Item 7. MD&A.

Presented below is a summary of DESC’s actual system output by energy source:

Source		2025				2024				2023
Natural gas			42		%		47		%		50		%
Nuclear(1)			23				21				21
Coal			23				21				18
Renewable and hydro(2)			12				11				11
Total			100		%		100		%		100		%

(1)Excludes Santee Cooper’s 33.3% undivided ownership interest in Summer.

(2)Includes solar.

Fossil Fuel— DESC purchases natural gas under contracts with producers and marketers on both a short-term and long-term basis at market-based prices. The gas is delivered to DESC through firm transportation agreements with various counterparties, through 2084.

DESC primarily obtains coal through short-term and long-term contracts with suppliers located in eastern Kentucky, Tennessee, Virginia and West Virginia that will expire at various times through 2026. Spot market purchases may occur when needed or when prices are believed to be favorable.

Nuclear Fuel— DESC primarily utilizes long-term contracts to support its nuclear fuel requirements. DESC, for itself and as agent for Santee Cooper, and Westinghouse are parties to a fuel alliance

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agreement and contracts for fuel fabrication and related services. Under these contracts, DESC supplies enriched products to Westinghouse, who in turn supplies nuclear fuel assemblies for Summer. Westinghouse is DESC’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements through 2036.

In addition, DESC has contracts covering its nuclear fuel needs for uranium, conversion services and enrichment services. These contracts have varying expiration dates through 2032. DESC believes that it will be able to renew these contracts as they expire or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services and that sufficient capacity for nuclear fuel supplies and processing exists to allow for normal operations of its nuclear generating unit. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal fuel and inventory levels.

Seasonality

DESC’s electric business earnings vary seasonally as a result of the impact of changes in temperature, the impact of storms and other catastrophic weather events and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs, respectively. An increase in heating degree days does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials and because alternative heating sources are more readily available.

DESC’s gas distribution and storage business earnings vary seasonally as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. The majority of these earnings are generated during the heating season, which is generally from November to March; however, South Carolina has certain rate mechanisms designed to reduce the impact of weather-related fluctuations.

Nuclear Decommissioning

DESC has a two-thirds interest in one licensed, operating nuclear reactor at Summer in South Carolina.

Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. Amounts collected from ratepayers are placed into trusts and are invested to fund the expected future costs of decommissioning Summer.

DESC believes that the decommissioning funds and their expected earnings will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to this trust. DESC will continue to monitor this trust to ensure that it meets the NRC minimum financial assurance requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC.

The estimated cost to DESC to decommission its 66.7% ownership in Summer is reflected in the table below and is primarily based upon site-specific studies completed in 2025. These cost studies are generally completed every four to five years. Santee Cooper is responsible for the remaining decommissioning costs, proportionate with its 33.3% ownership in Summer. The cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating license expires. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. In 2025, the NRC approved DESC’s request for an additional 20 years for its operating license for Unit 1 at Summer, allowing for generation through 2062. The existing regulatory framework in South Carolina provides a rate recovery mechanism for costs incurred on the relicensing process.

The estimated decommissioning costs, funds in trust and current license expiration dates for Summer are shown in the following table:

		NRC license expiration year		Most recent cost estimate (2025 dollars)(1)				Funds in trusts at December 31, 2025(2)
(dollars in millions)
Summer – Unit 1		2062		$	911			$	291

(1)The cost estimates shown above reflect reductions for the expected future recovery of certain spent fuel costs based on DESC’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in DESC’s nuclear decommissioning AROs.

(2)Excludes any funds held in trust by Santee Cooper. In 2025, DESC made contributions of $3 million to its nuclear decommissioning trust funds as collected from customers during the year.

Also see Notes 9, 14 and 23 to the Consolidated Financial Statements for additional information about nuclear decommissioning trust investments, AROs and other aspects of nuclear decommissioning, respectively.

CONTRACTED ENERGY

Contracted Energy includes the operations of Millstone, and associated energy marketing and price risk activities, and Dominion Energy’s nonregulated long-term contracted renewable electric generation fleet. Contracted Energy also includes nonregulated renewable natural gas facilities, including Dominion Energy’s investment in Align RNG. See Investments below for additional information regarding the Align RNG investment.

Contracted Energy’s capital plan for 2026 through 2030 includes spending approximately $2 billion primarily to support its operations at Millstone.

Contracted Energy derives its earnings primarily from Dominion Energy’s nonregulated generation assets, including associated capacity and ancillary services. Variability in earnings provided by Millstone relates to changes in market-based prices received for electricity and capacity as well as the timing, duration and costs of scheduled and unscheduled outages. Approximately half of Millstone’s output is sold under the Millstone 2019 power purchase agreements, which commenced in October 2019. Market-based prices for electricity are largely dependent on commodity prices and the demand for electricity. Capacity prices are dependent upon resource requirements in relation to the supply available (both existing and new) in the forward capacity auctions, which are held approximately three years in advance of the associated delivery year. Dominion Energy manages the electric price volatility of Millstone by hedging a substantial portion of its expected near-term energy sales not subject to the Millstone 2019 power purchase agreements with derivative instruments.

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Dominion Energy’s nonregulated generation fleet includes solar generation facilities in operation or development in five states, including Virginia. The output of these facilities is sold under long-term power purchase agreements with terms generally ranging from 15 to 25 years. Variability in earnings provided by these assets relates to changes in irradiance levels due to changes in weather. See Note 10 to the Consolidated Financial Statements for additional information regarding certain solar projects.

Competition

Contracted Energy’s renewable generation projects are not currently subject to significant competition as the output from these facilities is primarily sold under long-term power purchase agreements with terms generally ranging from 15 to 25 years. However, in the future, such operations may compete with other power generation facilities to serve certain large-scale customers after the power purchase agreements expire. Competition for the nonregulated fleet is impacted by electricity and fuel prices, new market entrants, construction by others of generating assets and transmission capacity, technological advances in power generation, the actions of environmental and other regulatory authorities and other factors. These competitive factors may negatively impact the nonregulated fleet’s ability to profit from the sale of electricity and related products and services.

Millstone is dependent on its ability to operate in a competitive environment and does not have a predetermined rate structure that provides for an ROIC. Millstone operates within a functioning RTO and primarily competes on the basis of price. Competitors include other generating assets bidding to operate within the RTO. Millstone competes in the wholesale market with other generators to sell a variety of products including energy, capacity and ancillary services. It is difficult to compare various types of generation given the wide range of fuels used by generation facilities, fuel procurement strategies, efficiencies and operating characteristics of the fleet within any given RTO. However, Dominion Energy applies its expertise in operations, dispatch and risk management to maximize the degree to which Millstone is competitive compared to similar assets within the region.

Regulation

Contracted Energy’s generation fleet is subject to regulation by the NRC, EPA, DOE, U.S. Army Corps of Engineers and other federal, state and local authorities. See Federal Regulations in Regulation, Future Issues and Other Matters in Item 7. MD&A and Note 23 to the Consolidated Financial Statements for additional information.

Properties

For a listing of facilities, see Item 2. Properties.

Investments

Align RNG—In November 2018, Dominion Energy announced the formation of Align RNG, an equal partnership with Smithfield Foods, Inc. to capture methane from swine farms across various states and convert it into pipeline quality natural gas. At December 31, 2025, substantially all projects were complete. See Note 9 to the Consolidated Financial Statements for additional information about Dominion Energy’s equity method investment in Align RNG.

Leasing Arrangement

In December 2020, Dominion Energy signed an agreement (most recently amended in February 2026) with a lessor to complete construction of and lease a Jones Act compliant offshore wind installation vessel. This vessel is designed to handle current turbine technologies as well as next generation turbines. The lessor provided equity and obtained financing commitments from debt investors, totaling $715 million, which funded project costs. In September 2025, the vessel was delivered and the five-year lease term commenced. See Note 15 to the Consolidated Financial Statements for additional information.

Sources of Energy Supply

Contracted Energy’s renewable fleet utilizes solar energy to power its electric generation while Millstone utilizes nuclear fuel, which is acquired primarily through a series of 5-year contracts, to power its electric generation. In addition, Dominion Energy occasionally purchases electricity from the ISO-NE spot market to satisfy physical forward sale requirements, as described below. Some of these agreements have fixed commitments and are detailed further in Fuel and Other Purchase Commitments in Item 7. MD&A.

Seasonality

Sales of electricity for Contracted Energy are subject to seasonal variation as a result of the weather, partially mitigated by the Millstone 2019 power purchase agreements.

Nuclear Decommissioning

Dominion Energy has two licensed, operating nuclear reactors at Millstone in Connecticut. Dominion Energy intends to seek approval of 20-year license extensions for both Units 2 and 3, which would allow these units to generate electricity through 2055 and 2065, respectively. A third Millstone unit ceased operations before Dominion Energy acquired the power station.

As part of Dominion Energy’s acquisition of Millstone, it acquired decommissioning funds for the related units. Dominion Energy believes that the decommissioning funds and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone units. Dominion Energy will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. The most recent site-specific study completed for Millstone was performed in 2024.

The estimated decommissioning costs, funds in trust and current license expiration dates for Millstone are shown in the following table:

.

		NRC license expiration year		Most recent cost estimate (2025 dollars)(1)				Funds in trusts at December 31, 2025(2)
(dollars in millions)
Millstone
Unit 1(3)		N/A		$	915			$	1,081
Unit 2		2035			1,102				1,455
Unit 3(4)		2045			1,218				1,475
Total				$	3,235			$	4,011

(1)The cost estimates shown above reflect reductions for the expected future recovery of certain spent fuel costs based on Dominion Energy’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in Dominion Energy’s nuclear decommissioning AROs.

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(2)Dominion Energy did not make any contributions to its nuclear decommissioning trust funds related to Millstone during 2025.

(3)Unit 1 permanently ceased operations in 1998, before Dominion Energy’s acquisition of Millstone.

(4)Millstone Unit 3 is jointly owned by Dominion Energy Nuclear Connecticut, Inc., with a 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain. Decommissioning cost is shown at Dominion Energy’s ownership percentage. At December 31, 2025, the minority owners held $84 million of trust funds related to Millstone Unit 3 that are not reflected in the table above.

Also see Notes 9, 14 and 23 to the Consolidated Financial Statements for additional information about nuclear decommissioning trust investments, AROs and other aspects of nuclear decommissioning, respectively.

CORPORATE AND OTHER

Corporate and Other Segment-Dominion Energy

Dominion Energy’s Corporate and Other segment includes its corporate, service company and other functions (including unallocated debt) as well as its noncontrolling interest in Dominion Privatization. Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. In addition, Corporate and Other includes the net impact of discontinued operations consisting primarily of the operations included in the East Ohio, PSNC and Questar Gas Transactions and a noncontrolling interest in Atlantic Coast Pipeline.

Dominion Energy owns a 50% noncontrolling interest in Dominion Privatization, a partnership with Patriot, which maintains and operates electric and gas distribution infrastructure under service concession arrangements with certain U.S. military installations in Pennsylvania, South Carolina, Texas, Washington D.C. and Virginia.

Dominion Energy owns a 53% noncontrolling interest in Atlantic Coast Pipeline. In July 2020, as a result of the continued permitting delays, growing legal uncertainties and the need to incur significant capital expenditures to maintain project timing before such uncertainties could be resolved, Dominion Energy and Duke Energy announced the cancellation of the Atlantic Coast Pipeline Project.

See Notes 3 and 9 to the Consolidated Financial Statements for additional information.

Corporate and Other Segment-Virginia Power

Virginia Power’s Corporate and Other segment primarily includes certain specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources.

Regulation

The Companies are subject to regulation by various federal, state and local authorities, including the state commissions of Virginia, North Carolina and South Carolina, SEC, FERC, EPA, DOE, PHMSA, NRC, U.S. Army Corps of Engineers, BOEM and U.S. Department of Transportation.

State Regulations

Electric

Virginia Power and DESC’s electric utility retail services are subject to regulation by the Virginia and North Carolina Commissions and the South Carolina Commission, respectively.

Virginia Power and DESC hold CPCNs which authorize them to maintain and operate their electric facilities already in operation and to sell electricity to customers. However, Virginia Power and DESC may not construct generating facilities or large capacity transmission lines without the prior approval of various state and federal government agencies. In addition, the Virginia and North Carolina Commissions and the South Carolina Commission regulate Virginia Power and DESC’s transactions, respectively, with affiliates and transfers of certain facilities. The Virginia and South Carolina Commissions also regulate the issuance of certain securities.

Electric Regulation in Virginia

The Regulation Act provides for a cost-of-service rate model and permits Virginia Power to seek recovery of costs for new generation projects as well as extensions of operating licenses of nuclear power generation facilities, FERC-approved transmission costs, underground distribution lines, certain environmental compliance, conservation, energy efficiency and demand response programs and renewable energy facilities and programs through stand-alone riders, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. If the Virginia Commission does not allow recovery of costs incurred in providing service on a timely basis, Virginia Power’s future earnings could be negatively impacted.

In April 2020, the VCEA replaced Virginia’s voluntary renewable energy portfolio standard for Virginia Power with a mandatory program setting annual renewable energy portfolio standard requirements based on the percentage of total electric energy sold by Virginia Power, excluding existing nuclear generation and certain new carbon-free resources, reaching 100% by the end of 2045. The VCEA includes related requirements concerning deployment of wind, solar and energy storage resources, as well as provides for certain measures to increase net-metering, including an allocation for low-income customers, incentivizes energy efficiency programs and provides for cost recovery related to participation in a carbon trading program.

In April 2023, legislation was enacted that resets the frequency of base rate reviews from a triennial period, as established under the GTSA, to a biennial period commencing with the 2023 Biennial Review. The legislation provided that the Virginia Commission establish an authorized ROE of 9.70% for Virginia Power in the 2023 Biennial Review, and that in subsequent biennial reviews the Virginia Commission is authorized to utilize any methodology it deems to be consistent with the public interest to make future ROE determinations. In all future biennial reviews, if the Virginia Commission determines that Virginia Power’s existing base rates will, on a going-forward basis, produce revenues that are either in excess of or below its authorized rate of return, the Virginia Commission is authorized to reduce or increase such base rates, as applicable and necessary, to ensure that Virginia Power’s base rates are just and reasonable while still allowing Virginia Power to recover its costs and earn a fair rate of return. In addition, beginning with the 2025 Biennial Review, the Virginia Commission may, at

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its discretion, increase or decrease Virginia Power’s authorized ROE by up to 50 basis points based on factors that may include reliability, generating plant performance, customer service and operating efficiency, with the provisions applying to such adjustments to be determined in a future proceeding.

The legislation directed that, beginning with the 2025 Biennial Review, 85% of any earnings determined by the Virginia Commission to be up to 150 basis points above Virginia Power’s authorized ROE shall be credited to customers’ bills as well as 100% of any earnings that are more than 150 basis points above Virginia Power’s authorized ROE. For the purposes of measuring any bill credits due to customers, associated income taxes are factored into the determination of such amounts. In addition, the legislation eliminated Virginia Power’s ability to utilize Virginia Commission-approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects as a CCRO to reduce or offset any earnings otherwise eligible for customer credits as previously permitted under the GTSA.

See Note 13 to the Consolidated Financial Statements for additional information.

Electric Regulation in North Carolina

Virginia Power’s retail electric base rates in North Carolina are regulated on a cost-of-service/rate-of-return basis subject to North Carolina statutes and the rules and procedures of the North Carolina Commission. North Carolina base rates are set by a process that allows Virginia Power to recover its operating costs and an ROIC. If retail electric earnings exceed the authorized ROE established by the North Carolina Commission, retail electric rates may be subject to review and possible reduction by the North Carolina Commission, which may decrease Virginia Power’s future earnings. Additionally, if the North Carolina Commission does not allow recovery of costs incurred in providing service on a timely basis, Virginia Power’s future earnings could be negatively impacted. Fuel rates are subject to revision under annual fuel cost adjustment proceedings. A change in law in 2025 provides for recovery of purchased electric capacity expenses as a component of fuel. Other recent North Carolina legislation provides Virginia Power the option to apply for a multi-year rate plan to establish base rates under a performance-based rate plan rather than a general rate case. Under this optional structure, rates would be set for a multi-year period and be subject to revenue decoupling for residential customers, an annual earnings sharing mechanism and performance-based requirements.

Virginia Power’s transmission service rates in North Carolina are regulated by the North Carolina Commission as part of Virginia Power’s bundled retail service to North Carolina customers.

See Note 13 to the Consolidated Financial Statements for additional information.

Electric Regulation in South Carolina

DESC’s retail electric base rates in South Carolina are regulated on a cost-of-service/rate-of-return basis subject to South Carolina statutes and the rules and procedures of the South Carolina Commission. South Carolina base rates are set by a process that allows DESC to recover its operating costs and an ROIC. If retail electric earnings exceed the authorized ROE established by the South Carolina Commission, retail electric rates may be subject to review and possible reduction, which may decrease DESC’s future earnings. Additionally, if the South Carolina Commission does not allow recovery of costs incurred in providing service on a timely basis, DESC’s future earnings could be negatively impacted.

In May 2025, the Governor of South Carolina signed into law the SCESA, which establishes a rate stabilization mechanism whereby an electric utility, including DESC, may elect to request South Carolina Commission approval to adjust its base rates up or down annually when changes in the utility’s investments, revenues and expenses cause its earned ROE to be more than 50 basis points below or above the ROE approved by the South Carolina Commission in the utility’s latest general rate case. Electric utilities electing rate stabilization would be required to file a general rate case every five years. In addition, any new electric generating facility of more than 250 MW, once completed, would be required to undergo a separate prudency review by the South Carolina Commission before any construction or operating costs related to such facility could be included in the rate stabilization process.

Fuel costs are reviewed annually by the South Carolina Commission, as required by statute, and fuel rates are subject to revision in these annual fuel proceedings. DESC also submits annual filings to the South Carolina Commission for rider recovery related to its DSM programs and pension costs. The DSM rider includes recovery of any net lost revenues and for a shared savings incentive.

Pursuant to the SCANA Merger Approval Order, DESC is recovering capital costs and a return on capital cost rate base related to the NND Project over a 20-year period through a capital cost rider. The capital cost rider also provides for the return to retail electric customers of certain amounts associated with the NND Project. Revenue from the capital cost rider component of retail electric rates will continue to decline over the 20-year period as capital cost rate base is reduced.

See Note 13 to the Consolidated Financial Statements for additional information.

Gas

DESC is subject to regulation of rates and other aspects of its natural gas distribution service by the South Carolina Commission. DESC provides retail natural gas service to customers in areas in which it has received authorization from the South Carolina Commission and in municipalities in which it holds a franchise. DESC’s base rates can be adjusted annually, pursuant to the Natural Gas Rate Stabilization Act, for recovery of costs related to natural gas infrastructure. Base rates are set based on the cost-of-service by rate class approved by the South Carolina Commission in the latest general rate case. Base rates for DESC are based primarily on a rate design methodology in which the majority of operating costs are recovered through volumetric charges. DESC also utilizes a weather normalization adjustment to adjust its base rates during the winter billing months for residential and commercial customers to mitigate the effects of unusually cold or warm weather.

DESC’s natural gas tariffs include a purchased gas adjustment that provides for the recovery of prudently incurred gas costs, including transportation costs. DESC is authorized to adjust its purchased gas rates monthly and makes routine filings with the South Carolina Commission to provide notification of changes in these rates. Costs that are under or over recovered are deferred as regulatory assets or liabilities, respectively, and considered in subsequent purchased gas adjustments. The purchased gas adjustment filings cover a prospective twelve-month period. Increases or decreases in purchased gas costs can result in corresponding changes in purchased gas adjustment rates and the

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revenue generated by those rates. The South Carolina Commission reviews DESC’s gas purchasing policies and practices, including its administration of the purchased gas adjustment, annually. DESC has also received approval from the South Carolina Commission to recover gas DSM program costs and a shared savings incentive from residential and commercial natural gas customers under a rider to retail gas rates. The South Carolina Commission approved DESC to recover net lost revenues resulting from the gas DSM programs through its annual Natural Gas Rate Stabilization Act proceeding.

See Note 13 to the Consolidated Financial Statements for additional information.

Federal Regulations

Federal Energy Regulatory Commission

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and, under its market-based rate authority, sells electricity in the PJM wholesale market and to wholesale purchasers in Virginia and North Carolina. Dominion Energy’s nonregulated generators sell electricity in the PJM, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Ohio, Connecticut, California and South Carolina, under Dominion Energy’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. DESC may make wholesale sales at market-based rates outside its balancing authority pursuant to its market-based sales tariff authorized by FERC. In addition, DESC has FERC approved tariffs to sell wholesale power at capped rates based on its embedded cost of generation. These cost-based sales tariffs could be used to sell to loads within or outside DESC’s service territory. Any such sales are voluntary. FERC also regulates the issuance of certain securities by DESC.

In April 2024, Virginia Power notified PJM that it was changing its election to satisfy its capacity requirements by returning to PJM’s Reliability Pricing Model capacity market, planning to purchase capacity rather than satisfying this requirement by self-supplying the capacity needed to serve load. This change became effective for the delivery year beginning June 2025. This decision does not affect day-to-day operations.

The Companies are subject to FERC’s Standards of Conduct that govern conduct between transmission function employees of interstate gas and electricity transmission providers and the marketing function employees of their affiliates. The rule defines the scope of transmission and marketing-related functions that are covered by the standards and is designed to prevent transmission providers from giving their affiliates undue preferences.

The Companies are also subject to FERC’s affiliate restrictions that (1) prohibit power sales between nonregulated plants and utility plants without first receiving FERC authorization, (2) require the nonregulated and utility plants to conduct their wholesale power sales operations separately and (3) prohibit utilities from sharing market information with nonregulated plant operating personnel. The rules are designed to prohibit utilities from giving the nonregulated plants a competitive advantage.

EPACT included provisions to create an Electric Reliability Organization, which is required to promulgate mandatory reliability standards governing the operation of the bulk power system in the U.S. FERC has certified NERC as the Electric Reliability Organization and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards will be subject to fines of up to $1.6 million per day, per violation and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.

In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.

In October 2011, FERC issued an order approving the settlement of DESC’s formula rate that updates transmission rates on an annual basis, including its ROE. The formula rate is designed to recover the expected revenue requirement for the calendar year and is updated annually based on actual costs. This FERC accepted formula rate enables DESC to earn a return on its investment in electric transmission infrastructure.

In March 2025, FERC affirmed its acceptance of the agreement governing SEEM, which sets forth the framework and rules for establishing and maintaining a voluntary electronic trading platform designed to enhance the existing bilateral market in the Southeast utilizing zero-charge transmission service. That transmission service, in turn, is voluntarily provided by participating transmission service providers, including DESC.

Nuclear Regulatory Commission

All aspects of the operation and maintenance of the Companies’ nuclear power stations are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.

From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining the Companies’ nuclear generating units. See Note 23 to the Consolidated Financial Statements for additional information.

The NRC also requires the Companies to decontaminate their nuclear facilities once operations cease. This process is referred to as decommissioning, and the Companies are required by the NRC to be financially prepared. For information on decommissioning trusts, see Dominion Energy Virginia-Nuclear Decommissioning, Dominion Energy South Carolina-Nuclear Decommissioning, and Contracted Energy-Nuclear Decommissioning above and Note 9 to the Consolidated Financial Statements. See Note 23 to the Consolidated Financial Statements for additional information on spent nuclear fuel.

Cyber Regulations

The Companies plan and operate their facilities in compliance with approved government cyber regulatory requirements. The

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Companies’ employees participate on various regulatory committees, track the development and implementation of standards and maintain proper compliance registration with NERC’s regional organizations. The Companies anticipate incurring additional compliance expenditures over the next several years because of the implementation of new cybersecurity programs such as the Transportation Security Administration’s gas sector cybersecurity policies. In addition, NERC continues to develop additional requirements specifically regarding supply chain standards and control centers that impact the bulk electric system. While the Companies expect to incur additional compliance costs in connection with NERC, Transportation Security Administration and other governmental agency regulations, such expenses are not expected to significantly affect results of operations.

Safety Regulations

Dominion Energy is also subject to federal and state pipeline safety laws and regulations which set forth numerous operation, maintenance and inspection and repair regulations designed to ensure the safety and integrity of Dominion Energy’s pipeline and storage infrastructure.

The Companies are subject to a number of federal and state laws and regulations, including Occupational Safety and Health Administration, and comparable state statutes, whose purpose is to protect the health and safety of workers. The Companies have an internal safety, health and security program designed to monitor and enforce compliance with worker safety requirements, which is routinely reviewed and considered for improvement. The Companies believe that they are in material compliance with all applicable laws and regulations related to worker health and safety. Notwithstanding these preventive measures, incidents may occur that are outside of the Companies’ control.

Environmental Regulations

Each of the Companies’ operating segments is subject to substantial laws, regulations and compliance costs with respect to environmental matters. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of significant penalties for noncompliance, including fines, injunctive relief and other sanctions. The cost of complying with applicable environmental laws, regulations and rules is material to the Companies. If compliance expenditures and associated operating costs are not recoverable from customers through regulated rates (in regulated businesses) or market prices (in unregulated businesses), those costs could adversely affect future results of operations and cash flows. The Companies have applied for or obtained the necessary environmental permits for the construction and operation of their facilities. Many of these permits are subject to reissuance and continuing review.

Global Climate Change

The Companies support a federal climate change program that would provide a consistent, economy-wide approach to addressing this issue. Regardless of federal action, the Companies are seeking to reduce their GHG emissions while also balancing meeting the growing needs of their customers. In 2020, Virginia enacted the VCEA which addresses climate change matters such as the reduction of GHG emissions and renewable energy portfolio standards. Dominion Energy’s CEO and executive operational leadership within each operating segment are responsible for compliance with the laws and regulations governing environmental matters, including GHG emissions, and Dominion Energy’s Board of Directors receives periodic updates on these matters. See State Regulations—Electric—Electric Regulation in Virginia above, Environmental Strategy below, Future Environmental Regulations in Future Issues and Other Matters in Item 7. MD&A and Notes 13 and 23 to the Consolidated Financial Statements for additional information on climate change legislation and regulation.

Air

The CAA is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. Regulated emissions include, but are not limited to, carbon, methane, VOC, NOX, other GHGs, mercury, other toxic metals, hydrogen chloride, SO2 and particulate matter. At a minimum, state-established regulatory programs are required to meet applicable requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of the Companies’ facilities are subject to the CAA’s permitting and other requirements.

Water

The CWA is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. The CWA and analogous state laws impose restrictions and strict controls regarding discharges of effluent into surface waters and require permits to be obtained from the EPA or the analogous state agency for those discharges. Containment berms and similar structures may be required to help prevent accidental releases. The Companies must comply with applicable CWA requirements at their current and former operating facilities. Stormwater related to construction activities is also regulated under the CWA and by state and local stormwater management and erosion and sediment control laws. From time to time, the Companies’ projects and operations may impact tidal and non-tidal wetlands. In these instances, the Companies must obtain authorization from the appropriate federal, state and local agencies prior to impacting wetlands. The authorizing agency may impose significant direct or indirect mitigation costs to compensate for such impacts to wetlands.

Protected Species

The ESA and analogous state laws prohibit activities that can result in harm to specific species of plants and animals, as well as impacts to the habitat on which those species depend. In addition to ESA programs, the Migratory Bird Treaty Act of 1918 and Bald and Golden Eagle Protection Act establish broader prohibitions on harm to protected birds. Many of the Companies’ facilities are subject to requirements of the ESA, Migratory Bird Treaty Act of 1918 and Bald and Golden Eagle Protection Act. The ESA and Bald and Golden Eagle Protection Act require potentially lengthy coordination with the state and federal agencies to ensure potentially affected species are protected. Ultimately, the suite of species protections may restrict company activities to certain times of year, project modifications may be necessary to avoid harm or a permit may be needed for unavoidable taking of the species. The

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authorizing agency may impose mitigation requirements and costs to compensate for harm of a protected species or habitat loss. These requirements and time of year restrictions can result in adverse impacts on project plans and schedules such that the Companies’ businesses may be materially affected.

Other Regulations

Other significant regulations to which the Companies are subject include federal and state laws protecting graves, sacred sites, historic sites and cultural resources, including those of American Indian tribal nations and tribal communities. These can result in compliance and mitigation costs as well as potential adverse effects on project plans and schedules such that the Companies’ businesses may be materially affected.

Environmental Strategy

Dominion Energy’s mission is to provide the reliable, affordable, and increasingly clean energy that powers its customers every day. Dominion Energy is working to achieve its commitment of net zero carbon and methane Scope 1 and Scope 2 emissions and material categories of Scope 3 emissions: electricity purchased to power the grid, fossil fuel purchased for its power stations and gas distribution systems and consumption of sales gas by natural gas customers by 2050.

To meet its customers’ needs for reliable, affordable and increasingly clean energy every day and to reach net zero emissions, in the near term Dominion Energy has obtained or plans to seek license extensions for its zero-carbon nuclear facilities and is expanding wind and solar generation as well as energy storage, investing in carbon-beneficial renewable natural gas and using dispatchable natural gas generation facilities to support the integration of wind and solar generation facilities as well as energy storage facilities into the grid and requesting offers for responsibly sourced gas from those suppliers who are committed to net zero. The strategy to meet these objectives consists of three major elements which will reduce GHG emissions:

•Increasingly clean energy;

•Innovation and energy infrastructure modernization; and

•Conservation and energy efficiency.

Dominion Energy’s path to net zero emissions will not be linear. Year-over-year variations in weather, load growth and other economic factors contributing to demand can, and are expected to, cause fluctuations within Dominion Energy’s emissions reduction journey. Over the long term, Dominion Energy’s ability to meet its customers’ needs for reliable, affordable and increasingly clean energy and achieve net zero emissions will require supportive legislative and regulatory policies, advancements in technology and broader investments across the economy. Dominion Energy will pursue solutions, including pilot programs, of technologies such as large-scale battery storage, carbon capture and storage, small modular reactors and hydrogen if and when they become technologically and economically feasible. As these technologies are developed, modern natural gas generation may be necessary to ensure reliable and affordable service to Dominion Energy’s customers.

Dominion Energy seeks to build partnerships and engage with local communities, stakeholders and customers on environmental issues important to them, including considerations such as fair treatment, representative involvement and effective communication. Dominion Energy commits to respectful stakeholder engagement on decisions regarding the siting and operation of energy infrastructure and strives to include all people and communities, regardless of race, color, national origin or income to ensure a variety of views are considered in its public engagement process.

As part of its broader commitment to transparency, Dominion Energy provides disclosures around carbon and methane emissions. Dominion Energy discloses its environmental commitments, policies and initiatives in a Sustainability and Corporate Responsibility Report as well as a Climate Report in addition to other reports included on Dominion Energy’s dedicated Sustainability website.

Increasingly Clean Energy

To achieve its net zero commitment while maintaining reliability, Dominion Energy utilizes an “all-of-the-above” strategy of cleaner, more efficient and lower-emitting methods of generating and delivering energy, while advancing measures to continue reducing emissions from traditional generation and delivery. Diversifying the energy portfolio enables Dominion Energy to provide customers with cleaner options while protecting the power supply from potential disruption.

Over the past two decades, Dominion Energy has transformed and diversified its generation portfolio, building additional resiliency while advancing decarbonization goals. In addition to reducing GHG emissions, Dominion Energy has also achieved measurable reductions of other air pollutants such as NOX, SO2 and mercury and reduced the amount of coal ash generated and the amount of water withdrawn. Dominion Energy achieved GHG and other air pollutant reductions by implementing an integrated approach to environmental stewardship that addresses electric energy production and delivery and energy management. As part of this effort, Dominion Energy has retired several of its fossil fuel electric generating facilities previously powered by coal, oil and gas, with the replacement of this capacity coming from renewable energy sources or lower-carbon natural gas.

Renewable energy is an important component of an “all-of-the-above” strategy designed to meet Dominion Energy’s customers’ needs for safe, reliable and affordable energy. Dominion Energy’s solar assets in operation or under development represent a total potential generating capacity of 7.8 GW, of which 3.2 GW was in operation across five states at December 31, 2025. Dominion Energy has commenced construction of the CVOW Commercial Project, expected to be placed in service by early 2027, along with the CVOW Pilot Project which achieved commercial operation in January 2021. Virginia Power’s energy storage assets in operation or under development represent a total potential storage capacity of 1.0 GW, of which 32 MW was operational at December 31, 2025.

Preservation of Dominion Energy’s existing carbon-free baseload nuclear generation is also an important component of Dominion Energy’s GHG emissions reduction strategy. Dominion Energy has received 20-year license extensions for its nuclear facilities in Virginia and South Carolina and intends to commence the process to extend the operating licenses for two units at Millstone.

Dominion Energy operates renewable natural gas facilities in collaboration with dairy farmers nationwide to capture and convert methane emissions from dairy farms.

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See Operating Segments and Item 2. Properties for additional information.

The IRA, as modified in certain instances by the OBBBA, provides for incentives designed to encourage production of clean energy, reduce carbon emissions and promote domestic manufacturing, including investment and production tax credits for clean energy technology. See Future Issues and Other Matters in Item 7. MD&A for additional information on the IRA and OBBBA.

Innovation and Energy Infrastructure Modernization

One of the pillars of Dominion Energy’s net zero strategy is a focus on innovation as a way to advance technology and sustainability. This includes investing in and building upon previously proven technology, including large-scale battery storage, hydrogen and advanced nuclear technology. Dominion Energy’s capital expenditure plan for 2026 through 2030 includes a focus on upgrading the electric system in Virginia through investments in renewable generation facilities, smart meters, intelligent grid devices and associated control systems, physical and cyber security investments, strategic undergrounding and energy conservation programs. Dominion Energy also plans to upgrade its gas and electric transmission and distribution networks and meet environmental requirements and standards set by various regulatory bodies. These enhancements are aimed at meeting Dominion Energy’s continued goal of providing safe, reliable service while addressing increasing electricity consumption, making Dominion Energy’s system more responsive to its customers’ desire to more efficiently manage their energy consumption and transforming its grid to be more adaptive to renewable generation resources and battery technologies.

See Operating Segments for additional information.

Conservation and Energy Efficiency

Conservation and load management play a significant role in meeting the growing demand for electricity and natural gas, while also helping to reduce the environmental footprint of Dominion Energy’s customers and lower their bills. Dominion Energy offers various efficiency programs designed to reduce energy consumption in Virginia, North Carolina and South Carolina, including programs such as:

•Energy audits and assessments;

•Incentives for customers to upgrade or install certain energy efficient measures and/or systems;

•Weatherization assistance to help income-eligible customers reduce their energy usage;

•Home energy planning, which provides homeowners with a step-by-step roadmap to efficiency improvements to reduce gas usage; and

•Rebates for installing high-efficiency equipment and qualified electric vehicle chargers.

GHG Emissions

Dominion Energy continues to work toward achieving its net zero emissions commitment. Following the sales of its gas distribution operations, exclusive of DESC’s, to Enbridge, Dominion Energy’s inventory of direct Scope 1 carbon and methane emissions is over 99% attributable to electric generation. Through 2024, Dominion Energy has reduced direct Scope 1 CO2 equivalent carbon and methane emissions from electric generation by 46% since 2005. For the purposes of these calculations and consistent with GHG Protocol requirements for reporting GHG emission reductions over time, both the baseline and 2024 emissions data exclude the gas entities sold in 2024 as part of the East Ohio, Questar Gas and PSNC Transactions.

Dominion Energy’s 2025 emissions data is not yet available.

Corporate GHG Inventory

Dominion Energy maintains a comprehensive Corporate GHG Inventory, which follows methodologies specified in the EPA’s Mandatory GHG Reporting Rule, 40 Code of Federal Regulations Part 98 for calculating emissions, as well as approved industry protocols. In its annual Corporate GHG Inventory, Dominion Energy voluntarily includes greenhouse gas emission estimates from smaller sources that are not required to be included under the EPA’s mandatory GHG Reporting Program, including smaller electric generation, natural gas operations and other sources. Dominion Energy’s Corporate GHG Inventory also includes emissions sources it voluntarily reports to various programs in which it participates. As a result, Dominion Energy’s reported GHG emissions in its Corporate GHG Inventory are higher than what is reported to the EPA. Dominion Energy includes emissions data in its Corporate GHG Inventory based on its ownership percentage of the associated assets at the end of the calendar year.

Total direct Scope 1 CO2 equivalent emissions reported under Dominion Energy’s Corporate GHG Inventory were 31.9 million metric tons in 2024. Reported CO2 equivalent emissions include CO2, CH4, N2O and SF6 emissions from Dominion Energy’s electric generation operations, electric transmission and distribution operations, natural gas operations and corporate operations. Dominion Energy’s 2024 emissions data reported under its Corporate GHG Inventory, which excludes the gas entities sold as part of the East Ohio, Questar Gas and PSNC Transactions, are as follows:

•For Dominion Energy’s electric generation operations, total CO2 equivalent emissions were 31.7 million metric tons in 2024, including 9.9 million metric tons from DESC and 21.8 million metric tons from Virginia Power.

•For Dominion Energy’s electric transmission and distribution operations, direct CO2 equivalent emissions were 0.04 million metric tons.

•For Dominion Energy’s natural gas operations, total CO2 equivalent emissions were 0.08 million metric tons.

•For Dominion Energy’s corporate operations, which includes renewable natural gas operations and Dominion Privatization assets, in addition to building heat and Dominion Energy’s vehicle and aviation fleets, total CO2 equivalent emissions were 0.06 million metric tons.

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EPA Mandatory GHG Reporting Program

Dominion Energy has been reporting GHG emissions, including carbon, methane, N2O and SF6, from its natural gas infrastructure, electric generation and power delivery operations to the EPA since 2011 under the EPA mandatory GHG Reporting Program. The EPA’s mandatory GHG Reporting Program requires annual reporting of emissions from assets operated by Dominion Energy based on full equity asset ownership at the end of the calendar year.

Dominion Energy’s 2024 GHG emissions reported under various subparts of the EPA’s Mandatory GHG Reporting Program at December 31, 2024, which excludes the gas entities sold as part of the East Ohio, Questar Gas and PSNC Transactions are as follows:

Natural Gas Operations

Segment		Subparts W & C CH4 Emissions				Subparts W & C CO2 Emissions				Subparts W & C N2O Emissions				Subparts W & C as CO2  Equivalent Emissions
(metric tons)
Distribution			1,887				65				—				52,913
LNG storage			41				745				—				1,894
Total(1)			1,928				810				—				54,808

(1)Totals may not foot due to rounding.

Electric Generation Operations

Company		Subparts C & D CO2 Emissions				Subparts C & D CH4 Emissions				Subparts C & D N2O Emissions				Subparts C & D CH4 Emissions as CO2 Equivalent Emissions				Subparts C & D N2O Emissions as CO2 Equivalent Emissions				Subparts C & D as CO2 Equivalent Emissions
(metric tons)
Virginia Power(1)			21,971,098				1,036				142				29,010				37,518				22,037,626
DESC			9,717,293				650				91				18,203				23,991				9,759,487
Total(2)			31,688,391				1,686				232				47,213				61,509				31,797,113

(1)Virginia Power totals include biomass, which were not included in the Corporate GHG inventory.

(2)Totals may not foot due to rounding.

Electric Transmission and Distribution Operations

Company		Subpart DD SF6 Emissions				Subpart DD SF6 as CO2 Equivalent Emissions
(metric tons)
Virginia Power			4.93				115,855
DESC			0.66				15,510
Total(1)			5.59				131,365

(1)Totals may not foot due to rounding.

Environmental Protection and Monitoring Expenditures

Dominion Energy incurred $324 million, $314 million and $269 million of expenses (including accretion and depreciation) during 2025, 2024 and 2023 respectively, in connection with environmental protection and monitoring activities. Dominion Energy expects these expenses to be approximately $345 million and $340 million in 2026 and 2027, respectively. In addition, capital expenditures related to environmental controls were $169 million, $216 million and $132 million for 2025, 2024 and 2023, respectively. Dominion Energy expects these expenditures to be approximately $140 million and $85 million for 2026 and 2027, respectively.

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Item 1A. Risk Factors

The Companies’ businesses are influenced by many factors that are difficult to predict, involve risks and uncertainties that may materially affect actual results and are often beyond their control. A number of these risks and uncertainties are identified below. There may be other factors, either not presently known or currently believed not to be material, that may cause actual results to differ materially from those indicated in this report. For additional information concerning any forward-looking statement or projection contained in this report, see Forward-Looking Statements in Item 7. MD&A.

Regulatory, Legislative and Legal Risks

The rates of the Companies’ principal electric transmission, distribution and generation operations and gas distribution operations are subject to regulatory review. Revenue provided by the Companies’ electric transmission, distribution and generation operations and by gas distribution operations is based primarily on rates approved by state and federal regulatory agencies. The profitability of the Companies’ businesses is dependent on their ability, through the rates that they are permitted to charge, to recover costs and earn a reasonable rate of return on their capital investment.

At the federal level, the Companies’ wholesale rates for electric transmission service are regulated by FERC. Rates for electric transmission services are updated annually according to a FERC-approved formula rate mechanism, and may be subject to additional prospective adjustments and retroactive corrections. A failure by the Companies to justify the appropriateness of these rates or a change in FERC policy or the application of FERC policy could result in rate decreases from current rate levels, which could adversely affect the Companies’ results of operations, cash flows and financial condition.

At the state level, Virginia Power’s retail base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia Commission in a biennial proceeding that involves the determination of Virginia Power’s actual earned ROE during a historic test period, and the determination of Virginia Power’s authorized ROE prospectively. Under certain circumstances described in the Regulation Act, Virginia Power may be required to refund a portion of its earnings to customers through a refund process and to reduce its rates. Virginia Power makes assessments throughout the review period and will record a regulatory liability for refunds to customers in any period such refunds are determined probable, which could negatively impact the Companies’ results of operations in the period recognized and to cash flows on completion of any biennial review.

In states other than Virginia, the Companies’ retail electric base rates for generation and distribution services to customers are regulated on a cost-of-service/rate-of-return basis subject to the statutes, rules and procedures of such states. Dominion Energy’s rates for gas distribution to retail customers are similarly regulated at the state level. If retail electric or gas earnings exceed the returns established by state utility commissions, retail electric rates or gas rates may be subject to review and possible reduction, which may decrease the Companies’ future earnings. Additionally, if any state utility commission does not allow recovery through base rates, on a timely basis, of costs incurred in providing service, the Companies’ financial condition, results of operations and/or cash flows could be negatively impacted.

Under certain circumstances, state utility regulators may impose a moratorium on increases to retail base rates for a specified period of time, which could delay recovery of costs incurred in providing service. Additionally, governmental officials, stakeholders and advocacy groups may challenge any of the regulatory reviews or proceedings referred to above. Such challenges may result in changes to the regulatory framework under which the Companies’ currently operate and/or lengthen the time, complexity and costs associated with such regulatory reviews or proceedings.

The Companies’ generation business may be negatively affected by possible FERC actions that could change market design in the wholesale markets or affect pricing rules or revenue calculations in the RTO markets. The Companies’ generation stations operating in RTO markets sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these generation stations to take advantage of market price opportunities, but also expose them to market risk. Properly functioning competitive wholesale markets depend upon FERC, PJM and/or ISO-NE’s continuation of clearly identified market rules. From time to time, FERC may investigate and/or receive requests from PJM or ISO-NE to authorize changes in market design. FERC also periodically reviews the Companies’ authority to sell at market-based rates. Changes by FERC, PJM or ISO-NE to the design of the wholesale markets or its interpretation of market rules, the Companies’ authority to sell power at market-based rates, or changes to pricing rules or rules involving revenue calculations, could adversely impact the future results of the Companies’ generation business. For example, in April 2024, FERC issued an order that accepted proposed changes to the PJM wholesale capacity market that significantly changed how a generation resource’s capacity value is calculated and decreased the total amount of capacity recognized in the PJM region as eligible to meet reserve requirements. In addition, changes to the interpretation and application of FERC’s market manipulation rules may occur from time to time. A failure to comply with these market manipulation rules could lead to civil and criminal penalties.

The Companies are subject to complex governmental regulation, including tax regulation, that could adversely affect their results of operations and subject the Companies to monetary penalties. The Companies’ operations are subject to extensive federal, state and local laws and regulations and require numerous permits, approvals and certificates from various governmental agencies. Such laws and regulations govern the terms and conditions of the services the Companies offer, relationships with affiliates, protection of critical electric infrastructure assets and mandatory reliability standards and interaction in the wholesale markets, among other matters. The Companies are also subject to legislation and associated regulation governing taxation at the federal, state and local level. They must also comply with environmental legislation and associated regulations. Some such legislation and regulation have not yet been finalized and changes in either interpretation or final laws or regulations could have a negative impact on the Companies. For example, the OBBBA and IRA include various provisions, such as investment and production tax credits and

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corporate alternative minimum tax, that the Companies have considered in recording their provisions for income taxes. The ultimate impact of these tax laws is subject to pending guidance and interpretations that could adversely impact the Companies’ ability to qualify for and maintain tax credits, which could affect the Companies’ results of operations, financial condition and/or cash flows. Management believes that the necessary approvals have been obtained for existing operations and that the Companies’ businesses are conducted in accordance with applicable laws. The Companies’ businesses are subject to regulatory regimes which could result in substantial monetary penalties if either of the Companies is found not to be in compliance. New laws or regulations, the revision or reinterpretation of existing laws or regulations, the imposition of new tariffs or changes to existing tariffs, changes in enforcement practices of regulators or penalties imposed for non-compliance with existing laws or regulations may result in substantial additional expense. Adverse developments in tax laws, credits or other incentives including changes in legislation, administrative interpretations or judicial determinations could result in modifications to business models or otherwise negatively affect the Companies’ financial condition, results of operations and/or cash flows. Recent legislative and regulatory changes that are impacting or could impact the Companies include legislation enacted in Virginia in April 2023, the IRA, the VCEA, the 2017 Tax Reform Act, the OBBBA and tariffs imposed on various components required for construction of the CVOW Commercial Project or imported solar panels by the U.S. government in 2025 and 2018, respectively.

The Companies have been and may continue to be or become subject to legal proceedings and governmental investigations and examinations. The Companies may from time to time be subject to various legal proceedings and governmental investigations and examinations. For example, Dominion Energy, following the SCANA Combination, was subject to numerous federal and state legal proceedings and governmental investigations relating to the decision of SCANA and DESC to abandon construction at the NND Project. Dominion Energy spent substantial amounts of time and money defending these lawsuits and proceedings and on related investigations. In addition, juries have demonstrated a willingness to grant large awards in certain cases, including personal injury claims. Accordingly, actual costs incurred may differ from insured or reserved amounts and may not be recoverable, in whole or in part, by insurance or in rates from customers. The outcome of these or future legal proceedings, investigations and examinations, including settlements, may adversely affect the Companies’ financial condition, results of operation and/or cash flows.

Construction Risks

The construction of the CVOW Commercial Project involves significant risks. The CVOW Commercial Project is a large-scale, complex project. Significant delays or cost increases, or an inability to recover certain project costs, could have an adverse effect on the Companies’ financial condition, cash flows and results of operations. If the Companies are unable to complete the construction of the CVOW Commercial Project or decide in the future to delay or cancel the project, the Companies may not be able to recover all or a portion of their investment in the project and may incur substantial cancellation payments under existing contracts or other substantial costs associated with any such delay or cancellation. The Companies’ ability to complete the CVOW Commercial Project within the currently proposed timeline, or at all, and consistent with current cost estimates is subject to various risks and uncertainties, certain of which are beyond the Companies’ control.

The construction of the CVOW Commercial Project is dependent on the Companies’ ability to maintain various local, state and federal permits, rights of way and other regulatory approvals and authorizations, including Virginia Commission approval for rider recovery of project costs. In addition, determination of costs allocated by PJM to the project for network upgrades remains subject to change, even after the CVOW Commercial Project is placed in service, as such amounts are driven by the ultimate costs of development of the transmission lines and related facilities that PJM determines is necessary to support various generation facilities within PJM, including the CVOW Commercial Project. The final determination of such costs is outside the control of the CVOW Commercial Project and may be impacted by events affecting the developers of such transmission lines, including any increases in costs for permitting, inflation, tariffs, supply chain constraints or other factors affecting the ultimate costs to complete such facilities. Also, the CVOW Commercial Project may become the subject of litigation or other forms of intervention by third parties, including stakeholders or advocacy groups, that may seek to challenge permits or other regulatory approvals received, including for routing of onshore electric transmission, which could delay or increase the cost of the project. For example, the estimated total project cost and expected placed in service date for the CVOW Commercial Project were negatively impacted by projected installation timeline changes arising from the temporary suspension of work from the BOEM Director’s Order issued in December 2025 until a preliminary injunction was granted by the U.S District Court for the Eastern District of Virginia in January 2026, which allowed work to resume. Any additional suspension of work orders could result in further changes to the estimated total project cost and/or the timeframe turbines are expected to be placed in service.

The construction of the CVOW Commercial Project is also dependent on the ability of certain key suppliers and contractors to timely satisfy their obligations under contracts entered into or expected to be entered into. Given the unique equipment and expertise required for this project, the Companies may not be able to remedy in a timely and cost-effective manner, if at all, any failure by one or more of these suppliers or contractors to timely satisfy their contractual obligations. Certain of the fixed price contracts for major offshore construction and equipment components are denominated in Euros and Danish kroner. In May 2022, Virginia Power entered into forward purchase agreements with a notional amount of approximately €3.2 billion. Accordingly, to the extent the instruments do not effectively hedge the Companies’ exposure to these currencies, including by default of the counterparty, adverse fluctuations in the applicable exchange rates would likely adversely affect the cost of the CVOW Commercial Project. Similarly, adverse fluctuations in the price of fuel used for transportation and installation, would likely adversely affect the overall costs to construct the project. In

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addition, the cost of the CVOW Commercial Project could be adversely affected by the impact of applicable tariffs, including any potential impact of Section 232 investigations.

The Companies’ ability to recover unforeseen cost increases associated with construction of the CVOW Commercial Project is potentially limited which could negatively impact the Companies’ future financial condition, results of operations and/or cash flows. In accordance with the Virginia Commission’s December 2022 order, the Companies are subject to a cost sharing mechanism in which Virginia Power will be eligible to recover 50% of such incremental costs which fall between $10.3 billion and $11.3 billion with no recovery of such incremental costs which fall between $11.3 billion and $13.7 billion. There is no cost sharing mechanism for any total construction costs in excess of $13.7 billion, the recovery of which would be determined in a future Virginia Commission proceeding. In addition, the order includes enhanced performance reporting provisions for the operation of the CVOW Commercial Project. To the extent the net annual net capacity factor is below 42%, as determined on a three-year rolling average, Virginia Power is required to provide detailed explanation of the factors contributing to any shortfall to the Virginia Commission which could determine in a future proceeding a remedy for incremental costs incurred associated with any deemed unreasonable or imprudent actions of Virginia Power. Any such action by the Virginia Commission could adversely impact the Companies’ future financial condition, results of operations and/or cash flows.

The Companies’ ability to invest the significant financial resources necessary for the CVOW Commercial Project is dependent on the Companies’ access to the financial markets in a timely and cost-effective manner. A decline in the Companies’ credit worthiness, an unfavorable market reputation of either the Companies or their industry or general market disruptions could adversely impact financing costs and increase the overall cost of the project.

In October 2024, Virginia Power completed the sale of a 50% noncontrolling interest to Stonepeak. Virginia Power and Stonepeak will each contribute 50% of the remaining capital necessary to fund construction of the CVOW Commercial Project provided the total project cost, excluding financing costs, is less than $11.3 billion. For capital funding necessary, if any, for total project costs, excluding financing costs, of $11.3 billion through $13.7 billion, Stonepeak will have the option to make additional capital contributions. If Stonepeak elects to make additional capital contributions for project costs, excluding financing costs, in excess of $11.3 billion, if any, Virginia Power shall contribute between 67% and 83% of such capital with Stonepeak contributing the remainder. To the extent that Stonepeak elects not to make such contributions, Virginia Power shall receive an increase in its ownership percentage of OSWP for any contributed capital based on a tiered unit price for membership interests in OSWP as set forth in the agreement. Virginia Power and Stonepeak have the right to provide capital contributions for any total project costs, excluding financing costs, in excess of $13.7 billion. The inability of Stonepeak to satisfy its share of funding requirements in a timely manner could have a negative effect on the Companies. In addition, Stonepeak’s interests and objectives may differ from those of the Companies and, accordingly, disputes may arise that may result in delays, litigation or operational impasses.

The construction of the CVOW Commercial Project involves the use of evolving turbine technology and takes place in a marine environment, which presents unique challenges and requires the use of a specialized workforce and specialized equipment. In addition, the timely installation of the turbines is dependent on the continued availability of a Jones Act compliant vessel currently under a 20-month lease agreement which commenced in September 2025 between Virginia Power and an affiliated entity.

The timeline for construction of the CVOW Commercial Project may also be negatively impacted by severe weather events or marine wildlife, including migration patterns of endangered and protected species, both of which are outside of the control of the Companies and their contractors.

The Companies’ infrastructure build and expansion plans often require regulatory approval, including environmental permits, before commencing construction and completing projects. The Companies may not complete the facility construction, conversion or other infrastructure projects that they commence, or they may complete projects on materially different terms, costs or timing than initially estimated or anticipated, and they may not be able to achieve the intended benefits of any such project, if completed. A number of large- and small-scale projects have been announced, including the CVOW Commercial Project, electric transmission lines, facility expansions or renewed licensing, conversions and other infrastructure developments or construction. Additional projects may be considered in the future, such as those necessary to meet the projected demand growth driven by data centers and artificial intelligence, including to address the concentration of data centers primarily in Loudoun County, Virginia. The Companies compete for projects with companies of varying size and financial capabilities, including some that may have competitive advantages. Commencing construction on announced and future projects may require approvals from applicable state and federal agencies, and such approvals could include mitigation costs. Projects may not be able to be completed on time or in accordance with estimated costs as a result of weather conditions, need for new land and right of ways, delays in obtaining or failure to obtain or maintain regulatory and other, including PJM, approvals, changes in laws or regulations or other regulatory or administrative action or inaction, the outcome of legal proceedings and judicial actions, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, concerns raised during stakeholder engagement, a decline in the credit strength of counterparties or vendors, inflation, the impact of applicable tariffs or other factors beyond the Companies’ control. As discussed above, the CVOW Commercial Project experienced a temporary suspension of work which impacted the expected project cost and timeline. In addition, Dominion Energy has been involved with other projects which have experienced certain delays in obtaining and maintaining permits necessary for construction along with construction delays due to judicial actions which impacted the cost and schedule such as the Atlantic Coast Pipeline Project and ultimately led to its cancellation in July 2020. Construction projects necessary to maintain reliability and meet increasing demand may include the construction of dispatchable natural gas generation facilities which may be subject to additional challenges raised by advocacy groups which could adversely impact the timely receipt and maintenance of regulatory

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approvals. Even if facility construction, expansion, electric transmission line, conversion and other infrastructure projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of the Companies following completion of the projects may not meet expectations. If these infrastructure projects are not completed, are delayed or are subject to unanticipated costs, certain costs may not be approved for recovery or otherwise be recoverable through regulatory mechanisms that may be available. Further, the Companies could become obligated to make delay or termination payments or become obligated for other damages under contracts, could experience the loss or reduction of tax credits or incentives, the inability to transfer related tax credits, or delayed or diminished returns, and could be required to write off all or a portion of their investments in such projects.

Start-up and operational issues can arise in connection with the commencement of commercial operations at the Companies’ facilities. Such issues may include failure to meet specific operating parameters, which may require adjustments to meet or amend these operating parameters. Additionally, the Companies may not be able to timely and effectively integrate the projects into their operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Any delays in the timely completion of necessary PJM interconnection projects for new electric generation facilities under development by Virginia Power, including the CVOW Commercial Project, may result in project delays and/or capacity constraints if, and until, such projects are completed. In addition, any increase in network upgrade costs allocated to any such new Virginia Power generation project, or delay in the completion of such necessary upgrades could, respectively, increase the associated project development costs and/or delay the project’s ability to participate in PJM’s capacity market as a capacity resource. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Any of these or other factors could adversely affect the Companies’ ability to realize the anticipated benefits from the facility construction, electric transmission line, expansion, conversion and other infrastructure projects.

The development, construction and commissioning of several large-scale infrastructure projects simultaneously involves significant execution risk. To achieve Dominion Energy’s commitment to net zero emissions by 2050 and comply with the requirements of the VCEA and projected demand while maintaining reliability, the Companies are currently simultaneously developing or constructing several electric generation projects, including subsequent license renewal projects at nuclear facilities in Virginia and South Carolina, the CVOW Commercial Project, the Chesterfield Energy Reliability Center, several electric transmission projects and various solar projects. Several of the Companies’ key projects are increasingly large-scale, complex and being constructed in constrained geographic areas or in unfamiliar environments such as the marine environment for the CVOW Commercial Project. The advancement of the Companies’ infrastructure projects is also affected by the interventions, litigation or other activities of stakeholder and advocacy groups, some of which oppose natural gas-related and energy infrastructure projects. For example, certain stakeholder groups oppose solar farms due to the increasing quantities of land tracts required for these facilities. Similarly, certain stakeholder groups oppose new natural gas generation facilities, such as the Chesterfield Energy Reliability Center. Given that these projects provide the foundation for the Companies’ strategic growth plan and are necessary to meet projected demand, if the Companies are unable to obtain or maintain the required regulatory and other, including PJM, approvals, develop the necessary technical expertise, allocate and coordinate sufficient resources, adhere to budgets and timelines, effectively handle public outreach efforts, including its commitment to fair treatment, community involvement and effective communication, or otherwise fail to successfully execute the projects, there could be an adverse impact to the Companies’ financial position, results of operations and cash flows. Failure to comply with regulatory approval conditions or an adverse ruling in any future litigation could adversely affect the Companies’ ability to execute their business plan.

The Companies are dependent on their contractors for the successful and timely completion of large-scale infrastructure projects. The construction of such projects is expected to take several years, is typically confined within a limited geographic area or difficult environments and could be subject to delays, supply chain disruption, availability of critical components, cost overruns, inflation, labor disputes or shortages and other factors that could cause the total cost of the project to exceed the anticipated amount. Any of these events could adversely affect the Companies’ financial condition, results of operations and/or cash flows.

Further, an inability to obtain financing or otherwise provide liquidity for the projects on acceptable terms could negatively affect the Companies’ financial condition, cash flows, the projects’ anticipated financial results and/or impair the Companies’ ability to execute the business plan for the projects as scheduled.

Environmental Risks

Compliance with federal and/or state requirements imposing limitations on GHG emissions or efficiency improvements, as well as Dominion Energy’s commitment to achieve net zero carbon and methane emissions by 2050, may result in significant compliance costs, could result in certain of the Companies’ existing electric generation units being uneconomical to maintain or operate and may depend upon technological advancements which may be beyond the Companies’ control. The VCEA establishes renewable energy and CO2 reduction targets for Virginia Power’s generation fleet and grid operations, including the requirement that 100% of Virginia Power’s electricity come from zero-carbon generation by the end of 2045. The legislation mandates the development of 16.1 GW of solar or onshore wind capacity by the end of 2035, which includes specific requirements for utility-scale solar of 3.0 GW by the end of 2024, up to 15.0 GW by the end of 2035 and 1.1 GW of small-scale solar by the end of 2035. The legislation also deems 5.2 GW of offshore wind capacity before 2035 and 2.7 GW of energy storage by the end of 2035 to be in the public interest. The VCEA and related legislation also authorizes Virginia to participate in a program consistent with RGGI, requiring the purchase of carbon credits to offset emissions from Virginia Power’s generating fleet within the state. In January 2022, the Governor of Virginia issued an executive order which

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put directives in place to start the withdrawal of Virginia from RGGI. In December 2023, the withdrawal took effect. Cost recovery for these initiatives will require approval by the Virginia Commission which may be denied or altered to the detriment of the Companies. For example, the Companies recorded charges in 2022 associated with the Virginia Commission’s approval in June 2022 of Virginia Power’s petition that RGGI compliance costs incurred and unrecovered through July 2022 be recovered through existing base rates in effect during the period incurred. In addition, permitting and other project execution challenges may hinder Virginia Power’s ability to meet the requirements of the VCEA. The Companies could face similar risks if there is further legislation at the federal and/or state level mandating additional limitations on GHG emissions or requiring additional efficiency improvements.

Dominion Energy is working to achieve net zero carbon and methane Scope 1 and Scope 2 emissions and material categories of Scope 3 emissions by 2050. To meet this commitment, the Companies expect to construct new electric generation facilities, including renewable facilities such as wind and solar, and have obtained or plan to seek the extension of operating licenses for the Companies’ nuclear generation facilities. The Companies also need to depend on technological improvements not currently in commercial development. Additionally, actions taken in furtherance of Dominion Energy’s net zero commitment may impact existing generation facilities, including as a result of fuel switching and/or the retirement of high-emitting generation facilities and their potential replacement with lower-emitting generation facilities. Further, the ability to realize this commitment will require the Companies to be able to obtain significant financing. These efforts will require approvals from various regulatory bodies for the siting and construction of such new facilities and a determination by the applicable state commissions that costs related to the construction are prudent. Given these and other uncertainties associated with the implementation of Dominion Energy’s net zero commitment, the Companies cannot estimate the aggregate effect of future actions taken in furtherance of this commitment on their results of operations or financial condition or on their customers. However, such actions could render additional existing generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect the Companies’ financial condition, results of operations and/or cash flows.

There are also potential negative impacts on Dominion Energy’s natural gas business from its net zero emissions commitment as well as federal or state GHG regulations which may require further GHG emission reductions from the natural gas sector which, in addition to resulting in increased costs, could affect demand for natural gas. Additionally, GHG requirements could result in increased energy conservation and adoption of renewable products, which could impact the natural gas business. Dominion Energy’s renewable natural gas operations could be negatively impacted by factors affecting livestock owned by third-parties, changes in demand for renewable natural gas and/or changes in laws and regulations affecting such facilities.

The Companies’ operations and construction activities are subject to a number of environmental laws and regulations which impose significant compliance costs. The Companies’ operations and construction activities are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. Compliance with these legal requirements requires the Companies to commit significant capital toward permitting, emission fees, environmental monitoring, installation and operation of environmental control equipment and purchase of allowances and/or offsets. Additionally, the Companies could be responsible for expenses relating to remediation and containment obligations, including at sites where they have been identified by a regulatory agency as a potentially responsible party. Expenditures relating to environmental compliance have been significant in the past, and the Companies expect that they will remain significant in the future. Certain facilities have become uneconomical to operate and have been shut down, converted to new fuel types or sold. These types of events could occur again in the future.

The Companies expect that existing environmental laws and regulations may be revised and/or new laws may be adopted, including regulation of GHG emissions, which could have an adverse impact on the Companies’ business. Risks relating to regulation of GHG emissions from existing fossil fuel-fired electric generating units are discussed in more detail above and below. In addition, further regulation of air quality and GHG emissions under the CAA may be imposed on the natural gas sector. The Companies are also subject to federal water and waste regulations, including regulations concerning cooling water intake structures, coal combustion by-product handling and disposal practices, wastewater discharges from steam electric generating stations, management and disposal of hydraulic fracturing fluids and the potential further regulation of polychlorinated biphenyls.

Compliance costs cannot be estimated with certainty due to the inability to predict the requirements and timing of implementation of any new or changing environmental rules or regulations. Other factors which affect the ability to predict future environmental expenditures with certainty include the difficulty in estimating clean-up costs and quantifying liabilities under environmental laws that impose joint and several liabilities on all responsible parties. However, such expenditures, if significant, could make the Companies’ facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect the Companies’ financial condition, results of operations and/or cash flows.

The Companies are subject to risks associated with the disposal and storage of coal ash. The Companies historically produced and continue to produce coal ash, or CCRs, as a by-product of their coal-fired generation operations. The ash is stored and managed in impoundments (ash ponds) and landfills located at 11 different facilities, including eight at Virginia Power.

The EPA has issued regulations concerning the management and storage of CCRs, which Virginia has adopted. These CCR regulations require the Companies to make additional capital expenditures and increase operating and maintenance expenses. In addition, the Companies will incur expenses and other costs associated with closing, corrective action and ongoing monitoring of certain ash ponds and landfills. The EPA’s May 2024 final rule regulates inactive surface impoundments located at the retired generation stations that contained CCR and liquids after 2015, and certain other inactive or previously closed surface impoundments, landfills or other areas that contain accumulations of CCR. The Companies believe that they may have inactive or closed units or areas that could be subject to the final rule at up to

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19 different locations, including 12 at Virginia Power. The Companies also may face litigation concerning their coal ash facilities.

Further, while the Companies believe that they operate their ash ponds and landfills in compliance with applicable state safety regulations, a release of coal ash with a significant environmental impact could result in significant remediation costs, civil and/or criminal penalties, claims, litigation, increased regulation and compliance costs, and reputational damage, and could impact the financial condition of the Companies.

Operational Risks

The Companies’ financial performance and condition can be affected by changes in the weather, including the effects of global climate change. Fluctuations in weather can affect demand for the Companies’ services. For example, milder than normal weather can reduce demand for electricity and gas distribution services. In addition, severe weather or acts of nature, including hurricanes, winter storms, wildfires, earthquakes, floods and other natural disasters can stress systems, disrupt operation of the Companies’ facilities and cause service outages, production delays and property damage that require incurring additional expenses. Changes in weather conditions can result in reduced water levels or changes in water temperatures that could adversely affect operations at some of the Companies’ power stations. In addition, sustained changes in weather patterns could result in decreased output at the Companies’ renewable generation facilities. Furthermore, the Companies’ operations could be adversely affected and their physical plant placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and, for operations located on or near coastlines, a change in sea level or sea temperatures. Due to the location of the Companies’ electric utility service territories and a number of its other facilities in the eastern portions of the states of South Carolina, North Carolina and Virginia which are frequently in the path of hurricanes, the Companies experience the consequences of these weather events to a greater degree than many industry peers.

Hostile cyber intrusions could severely impair the Companies’ operations, lead to the disclosure of confidential information, damage the reputation of the Companies and otherwise have an adverse effect on the Companies’ business. The Companies own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run the Companies’ facilities are not completely isolated from external networks. In addition, the Companies’ operations utilize third-party vendors, which may also be subject to cyber security intrusions. There appears to be an increasing level of activity, sophistication and maturity of threat actors, in particular nation state actors, that wish to disrupt the U.S. bulk power system and the U.S. gas transmission or distribution system. Such parties could view the Companies’ computer systems, software or networks as attractive targets for cyber attack. For example, malware has been designed to target software that runs the nation’s critical infrastructure such as power transmission grids and gas pipelines. Emerging technologies, such as advanced forms of automation and artificial intelligence, which are subject to limited government oversight and regulations and evolve rapidly, may result in an increase in the frequency and sophistication of cyber attacks. The Companies’ businesses also require that they and their vendors collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.

A successful cyber attack through third-party or insider action on the systems that control the Companies’ electric generation, electric transmission, electric distribution or gas distribution assets could severely disrupt business operations, preventing the Companies from serving customers or collecting revenues. The breach of certain business systems could affect the Companies’ ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to the Companies’ reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data at the Companies or one of their vendors could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. If a significant breach were to occur, the reputation of the Companies also could be adversely affected. While the Companies maintain property and casualty insurance, along with other contractual provisions, that may cover certain damage caused by potential cyber incidents, all damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a significant cyber incident could adversely affect the Companies’ business, financial condition, results of operations and/or cash flows.

The Companies’ financial results can be adversely affected by various factors driving supply and demand for electricity and related services. Demand for the Companies’ services can be driven by changing populations within its utility service territories, significant new commercial or industrial customers or other changes in consumer habits. For example, data centers in Virginia Power’s service territory, particularly in Loudoun County, Virginia, have been a source of significant increase in demand which is expected to continue over the next decade. Technological advances may enhance energy efficiency in end-use devices, including lighting, furnaces and electric heat pumps and could lead to declines in per capita energy consumption. Additionally, regulatory and/or legislative bodies could introduce requirements and/or incentives to reduce energy consumption. Consumer demand for the Companies’ services may also be impacted by any price increases, including those driven by factors beyond the Companies’ control such as inflation or increased prices in natural gas. Further, Virginia Power’s business model is premised upon the cost efficiency of the production, transmission and distribution of large-scale centralized utility generation. However, advances in distributed generation technologies, such as solar cells, gas microturbines, battery storage and fuel cells, may make these alternative generation methods competitive with large-scale utility generation, and change how customers acquire or use the Companies’ services. The widescale implementation of alternative generation methods could negatively impact the

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reliability of the Companies’ electric grid and/or result in significant costs to enhance the grid. Virginia Power has an exclusive franchise to serve retail electric customers in Virginia. However, Virginia’s Retail Access Statutes allow certain electric generation customers exceptions to this franchise. As market conditions change, Virginia Power’s customers may further pursue exceptions and Virginia Power’s exclusive franchise may erode.

Increased energy demand or significant accelerated growth in demand due to new data centers, expanded use of artificial intelligence, widespread adoption of electric vehicles or other customer changes could require enhancements to the Companies’ infrastructure. As discussed above, the ability of the Companies to construct new facilities is dependent upon factors outside of their control, including obtaining and maintaining regulatory approvals and environmental and other permits. Any delays in, or inability to complete, construction or integration of new facilities or expand and/or renew existing facilities could have an adverse effect on the Companies’ financial results. In addition, purchased power from PJM or others may be from generation sources which emit more emissions than the Companies’ facilities, which could negatively impact Dominion Energy’s ability to meet its commitment to net zero emissions. Alternatively, reduced energy demand or significantly slowed growth in demand due to customer adoption of energy efficient technology, conservation, distributed generation, regional economic conditions or the impact of additional compliance obligations, unless substantially offset through regulatory cost allocations, could adversely impact the value of the Companies’ business activities.

The Companies’ operations are subject to operational hazards, equipment failures, supply chain disruptions and personnel issues which could negatively affect the Companies. Operation of the Companies’ facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply, pipeline integrity or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental policies or interventions, changes to the environment and performance below expected levels. The Companies’ businesses are dependent upon sophisticated information technology systems and network infrastructure, some of which are provided by third-party vendors under service contracts, the failure of which could prevent them from accomplishing critical business functions. Because the Companies’ transmission facilities, pipelines and other facilities are interconnected with those of third parties, the operation of their facilities and pipelines could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.

Operation of the Companies’ facilities below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of the Companies’ facilities and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the Companies’ business. Unplanned outages typically increase the Companies’ operation and maintenance expenses and may reduce their revenues as a result of selling less output or may require the Companies to incur significant costs as a result of operating higher cost units or obtaining replacement output from third parties in the open market to satisfy forward energy and capacity or other contractual obligations. Moreover, if the Companies are unable to perform their contractual obligations, penalties or liability for damages could result.

In addition, there are many risks associated with the Companies’ principal operations including nuclear accidents, fires, explosions, uncontrolled release of natural gas and other environmental hazards, pole strikes, electric contact cases, the collision of third party equipment with pipelines and avian and other wildlife impacts. Such incidents could result in loss of human life or injuries among employees, customers or the public in general, environmental pollution, damage or destruction of facilities or business interruptions and associated public or employee safety impacts, loss of revenues, increased liabilities, heightened regulatory scrutiny and reputational risk. Further, the location of electric generation, transmission, substations and distribution facilities or natural gas distribution facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks.

The Companies conduct certain operations through partnership arrangements involving third-party investors which may limit the Companies’ operational flexibility or result in an adverse impact on its financial results. Certain of the Companies’ operations, including the CVOW Commercial Project and Valley Link, are conducted through entities subject to partnership arrangements under which Dominion Energy or Virginia Power has significant influence but does not control the operations of such entities or in which Dominion Energy or Virginia Power’s control over such entities may be subject to certain rights of third-party investors. Accordingly, while Dominion Energy or Virginia Power may have a certain level of control or influence over these entities, it may not have unilateral, or any, control over the day-to-day operations of these entities or over decisions that may have a material financial impact on the partnership participants, including the Companies. In each case such partnership arrangements operate in accordance with their respective governance documents, and the Companies are dependent upon third parties satisfying their respective obligations, including, as applicable, funding of their required share of capital expenditures. Such third-party investors have their own interests and objectives which may differ from those of the Companies and, accordingly, disputes may arise amongst the owners of such partnership arrangements that may result in delays, litigation or operational impasses.

The Companies may be materially adversely affected by negative publicity or the inability of Dominion Energy to meet its stated commitments. From time to time, political and public sentiment may result in a significant amount of adverse press coverage and other adverse public statements affecting the Companies. Public sentiment may be affected by certain events outside of the Companies’ control, such as outages caused by severe weather events or increases in approved rates to recover higher than anticipated market rates for fuel used in electric generation. Any failure by Dominion Energy to realize its commitments to achieve net zero carbon and methane emissions by 2050, enhance the customer experience or other long-term goals could lead to adverse press coverage and other adverse

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public statements affecting the Companies. The ability to comply with some or all of Dominion Energy’s voluntary commitments may be outside of its control. For example, the ability to reduce emissions while meeting the Companies’ increasing demand growth is expected to be dependent on the technological and economic feasibility of large-scale battery storage, carbon capture and storage, small modular reactors, hydrogen and/or other clean energy technologies. Dominion Energy is also dependent on the actions of third parties to meet its commitment regarding Scope 2 and Scope 3 emissions. If downstream customers or upstream suppliers do not sufficiently reduce their GHG emissions, Dominion Energy may not achieve its net zero emissions commitment. In addition, while the Atlantic Coast Pipeline Project was cancelled in July 2020 and the legal proceedings and governmental investigations relating to the abandonment of the NND Project have been resolved, there is a risk that lingering negative publicity may continue. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims as well as adverse outcomes.

Addressing any adverse publicity, governmental scrutiny or enforcement or other legal proceedings is time consuming and expensive and, regardless of the factual basis for the assertions being made, can have a negative impact on the reputation of the Companies, on the morale and performance of their employees and on their relationships with their respective regulators, customers and commercial counterparties. It may also have a negative impact on the Companies’ ability to take timely advantage of various business and market opportunities. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have an adverse effect on the Companies’ business, financial condition, results of operations and/or cash flows.

Dominion Energy’s nonregulated generation business operates in a challenging market, which could adversely affect its results of operations and future growth. The success of Dominion Energy’s contracted generation business depends upon favorable market conditions including the ability to sell power at prices sufficient to cover its operating costs. Dominion Energy operates in active wholesale markets that expose it to price volatility for electricity and nuclear fuel as well as the credit risk of counterparties. Dominion Energy attempts to manage its price risk by entering into long-term power purchase agreements with customers as well as hedging transactions, including short-term and long-term fixed price sales and purchase contracts. The failure of Dominion Energy to maintain, renew or replace its existing long-term contracts on similar terms or with counterparties with similar credit profiles could result in a loss of revenue and/or decreased earnings and cash flows for Dominion Energy.

In these wholesale markets, the spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. In many cases, the next unit of electricity supplied would be provided by generating stations that consume fossil fuels, primarily natural gas. Consequently, the open market wholesale price for electricity generally reflects the cost of natural gas plus the cost to convert the fuel to electricity. Therefore, changes in the price of natural gas generally affect the open market wholesale price of electricity. To the extent Dominion Energy does not enter into long-term power purchase agreements or otherwise effectively hedge its output, these changes in market prices could adversely affect its financial results.

Dominion Energy purchases nuclear fuel primarily under long-term contracts. Dominion Energy is exposed to nuclear fuel cost volatility for the portion of its nuclear fuel obtained through short-term contracts or on the spot market, including as a result of market supply shortages. Nuclear fuel prices can be volatile and the price that can be obtained for power produced may not change at the same rate as nuclear fuel costs, thus adversely impacting Dominion Energy’s financial results. In addition, in the event that any of the contracted generation facilities experience a forced outage, Dominion Energy may not receive the level of revenue it anticipated.

War, acts and threats of terrorism, intentional acts and other significant events could adversely affect the Companies’ operations. The Companies cannot predict the impact that any future terrorist attacks or retaliatory military or other action may have on the energy industry in general or on the Companies’ businesses in particular. Any such future attacks or retaliatory action may adversely affect the Companies’ operations in a variety of ways, including by disrupting the power, fuel and other markets in which the Companies operate or requiring the implementation of additional, more costly security guidelines and measures. The Companies’ infrastructure facilities, including nuclear facilities and projects under construction, could be direct targets or indirect casualties of an act of terror or other physical attack. Any physical compromise of the Companies’ facilities could adversely affect the Companies’ ability to generate, purchase, transmit or distribute electricity, distribute natural gas or otherwise operate their respective facilities in the most efficient manner or at all. For example, in December 2022 electric utilities in North Carolina and Washington experienced physical attacks on substations with the damage causing power outages. In addition, the amount and scope of insurance coverage maintained against losses resulting from any such attack may not be sufficient to cover such losses or otherwise adequately compensate for any business disruptions that could result.

Instability in financial markets as a result of terrorism, war, intentional acts, pandemic, credit crises, recession or other factors could result in a significant decline in the U.S. economy and/or increase the cost or limit the availability of insurance or adversely impact the Companies’ ability to access capital on acceptable terms, or at all.

Failure to attract and retain key executive officers and an appropriately qualified workforce could have an adverse effect on the Companies’ operations. The Companies’ business strategy is dependent on their ability to recruit, retain and motivate employees. The Companies’ key executive officers include the CEO, CFO and presidents and those responsible for financial, operational, legal, regulatory, accounting, tax, information technology and cybersecurity functions. Competition for skilled management employees in these areas of the Companies’ business operations is high. Certain events, such as an aging workforce, mismatch of skill set, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base and the length of time required for skill development. In this case, costs, including costs for contractors to replace employees,

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productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees, or future availability and cost of contract labor may adversely affect the ability to manage and operate the Companies’ business. In addition, certain specialized knowledge is required of the Companies’ technical employees for construction and operation of transmission, generation and distribution assets. An inability to attract and retain these employees could adversely affect the Companies’ business and future operating results.

Nuclear Generation Risks

The Companies have substantial ownership interests in and operate nuclear generating units; as a result, each may incur substantial costs and liabilities. The Companies’ nuclear facilities are subject to operational, environmental, health and financial risks such as the on-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, limitations on the amounts and types of insurance available, potential operational liabilities and extended outages, the costs of replacement power, the costs of maintenance and the costs of securing the facilities against possible terrorist attacks. The Companies maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that future decommissioning costs could exceed amounts in the decommissioning trusts and/or damages could exceed the amount of insurance coverage. If the Companies’ decommissioning trust funds are insufficient, and they are not allowed to recover the additional costs incurred through insurance or regulatory mechanisms, their results of operations could be negatively impacted.

The Companies’ nuclear facilities are also subject to complex government regulation which could negatively impact their financial condition, results of operations and/or cash flows. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit, or take some combination of these actions, depending on its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could require the Companies to make substantial expenditures at their nuclear plants. In addition, although the Companies have no reason to anticipate a serious nuclear incident at their plants, if an incident did occur, it could materially and adversely affect their results of operations and/or financial condition. A major incident at a nuclear facility anywhere in the world, such as the nuclear events in Japan in 2011, could cause the NRC to adopt increased safety regulations or otherwise limit or restrict the operation or licensing of domestic nuclear units.

Financial, Economic and Market Risks

Changing rating agency requirements could negatively affect the Companies’ growth and business strategy. In order to maintain appropriate credit ratings to obtain needed credit at a reasonable cost in light of existing or future rating agency requirements, the Companies may find it necessary to take steps or change their business plans in ways that may adversely affect their growth and earnings. A reduction in the Companies’ credit ratings, including due to a change in rating methodologies, could result in an increase in borrowing costs, loss of access to certain markets, or both, thus adversely affecting operating results and could require the Companies to post additional collateral in connection with some of its price risk management activities.

An inability to access financial markets and, in the case of Dominion Energy, obtain cash from subsidiaries could adversely affect the execution of the Companies’ business plans. The Companies rely on access to short-term money markets and longer-term capital markets as significant sources of funding and liquidity for business plans with increasing capital expenditure needs, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities. Deterioration in the Companies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or declines in market reputation either for the Companies or their industry in general, or general financial market disruptions outside of the Companies’ control could increase their cost of borrowing or restrict their ability to access one or more financial markets. Market disruptions could stem from general market disruption due to general credit market or political events, the reform or replacement of benchmark rates, the failure of financial institutions on which the Companies rely or the bankruptcy of an unrelated company. Increased costs and restrictions on the Companies’ ability to access financial markets, including as a result of compliance with certain provisions of the OBBBA, may be severe enough to affect their ability to execute their business plans as scheduled.

Dominion Energy is a holding company that conducts all of its operations through its subsidiaries. Accordingly, Dominion Energy’s ability to execute its business plan is further subject to the earnings and cash flows of its subsidiaries and the ability of its subsidiaries to pay dividends or advance or repay funds to it, which may, from time to time, be subject to certain contractual restrictions or restrictions imposed by regulators.

Market performance, interest rates and other changes may decrease the value of the Companies’ decommissioning trust funds and Dominion Energy’s benefit plan assets or increase Dominion Energy’s liabilities, which could then require significant additional funding. The performance of the capital markets affects the value of the assets that are held in trusts to satisfy future obligations to decommission the Companies’ nuclear plants and under Dominion Energy’s pension and other postretirement benefit plans. The Companies have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuation and will yield uncertain returns, which may fall below expected return rates.

With respect to decommissioning trust funds, a decline in the market value of these assets may increase the funding requirements of the obligations to decommission the Companies’ nuclear plants or require additional NRC-approved funding assurance.

A decline in the market value of the assets held in trusts to satisfy future obligations under Dominion Energy’s pension and other postretirement benefit plans may increase the funding requirements under such plans. Additionally, changes in interest rates will affect the liabilities under Dominion Energy’s pension

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and other postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of retirements or changes in mortality assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans.

If the decommissioning trust funds and benefit plan assets are negatively impacted by market fluctuations or other factors, the Companies’ financial condition, results of operations and/or cash flows could be negatively affected.

The use of derivative instruments could result in financial losses and liquidity constraints. The Companies use derivative instruments, including futures, swaps, forwards, options and FTRs, to manage commodity, interest rate and/or foreign currency exchange rate risks. The failure of a counterparty to over-the-counter derivative instruments to perform may prevent the Companies from being able to mitigate such risks. In addition, derivative instruments may require posting cash for margin requirements.

The CEA requires certain over-the-counter derivatives, or swaps, to be cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, may elect the end-user exception to the CEA’s clearing requirements. The Companies have elected to exempt their swaps from the CEA’s clearing requirements. If, as a result of changes to the rulemaking process, the Companies’ derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs due to decreased market liquidity or increased margin payments.

Future impairments of goodwill or other intangible assets or long-lived assets may have a material adverse effect on the Companies’ results of operations. Goodwill is evaluated for impairment annually or more frequently if an event or circumstance occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Other intangible assets and long-lived assets are evaluated for impairment on an annual basis or more frequently whenever events or circumstances indicate that an asset’s carrying value may not be recoverable. If Dominion Energy’s goodwill or the Companies’ other intangible assets or long-lived assets are in the future determined to be impaired, the applicable registrant would be required during the period in which the impairment is determined to record a noncash charge to earnings that may have a material adverse effect on its results of operations. For example, in 2022, Dominion Energy determined that its nonregulated solar generation assets within Contracted Energy were impaired. In addition, Dominion Energy recorded an aggregate $309 million after-tax charge in the fourth quarter of 2023 and first quarter of 2024 for the impairment of certain goodwill associated with the Questar Gas Transaction.

Exposure to counterparty performance may adversely affect the Companies’ financial results of operations. The Companies are exposed to credit risks of their counterparties and the risk that one or more counterparties may fail or delay the performance of their contractual obligations, including but not limited to payment for services. Some of Dominion Energy’s operations are conducted through partnership arrangements, as noted above. Counterparties could fail or delay the performance of their contractual obligations for a number of reasons, including the effect of regulations on their operations. Defaults or failure to perform by customers, suppliers, contractors, joint venture partners, financial institutions or other third parties may adversely affect the Companies’ financial condition, results of operations and/or cash flows.

Public health crises and epidemics or pandemics could adversely affect the Companies’ business, results of operations, financial condition, liquidity and/or cash flows. The effects of an outbreak of a pandemic, such as COVID-19, and related government responses could include extended disruptions to supply chains and capital markets, reduced labor availability and productivity and a prolonged reduction in economic activity. The effects could also have a variety of adverse impacts on the Companies, including reduced demand for energy, particularly from commercial and industrial customers, impairment of goodwill or long-lived assets and diminished ability of the Companies to access funds from financial institutions and capital markets. Certain measures or restrictions taken to control a pandemic or similar event, such as travel bans and restrictions, quarantines, shelter-in-place orders and shutdowns, may cause operational interruptions and delays in construction projects. In addition, legislative or government action, such as legislation enacted in Virginia in November 2020, may limit the Companies’ ability to collect overdue accounts or disconnect services for non-payment, which may cause a decrease in the Companies’ results of operations and cash flows.

Item 1B. Unresolved Staff Comments

None.

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Item 1C. Cybersecurity

Risk Management And Strategy

In an effort to reduce the likelihood and severity of cyber intrusions, the Companies have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of data and systems. Consideration of cybersecurity risks is a key component of the Companies’ overall risk management and integrated into processes such as evaluation of potential new vendors or suppliers. The Companies are subject to mandatory cybersecurity regulatory requirements, interface regularly with a wide range of external organizations and participate in classified briefings to maintain an awareness of current cybersecurity threats and vulnerabilities.

The Companies’ corporate intelligence and security program includes both cybersecurity and threat intelligence components as part of its evaluation and mitigation of risks. The evaluation of risks includes consideration of cybersecurity and privacy risk, including potential impact on the Companies’ employees, customers, supply chain and other stakeholders, intelligence briefings on notable cyber events impacting the industry and evaluation of insider threats. The Companies utilize a robust set of internal and third-party assessment tools to test its cyber risk management policies, practices and procedures as well as challenge assumptions upon which its defenses are built. These assessments provide opportunities for self-critical analysis and constructive feedback needed to build cyber resilience. Trainings are routinely provided to employees to help identify, avoid and mitigate cybersecurity threats and to ensure an understanding of the Companies’ cyber risk management policies. In addition, risk assessments are conducted as a component of the evaluation of vendors and suppliers.

The Companies’ current security posture and regulatory compliance efforts are intended to address the evolving and changing cyber threats. During the past three years, the Companies have not experienced any cybersecurity incidents resulting in a material impact to their business strategy, results of operations or financial condition. The Companies have identified the risk that a hostile cyber intrusion could severely impair the Companies’ operations, lead to disclosure of confidential information, damage the Companies’ reputation or otherwise have an adverse effect on the Companies’ business as disclosed under the Operational Risks header within Item 1A. Risk Factors.

Governance

Dominion Energy’s Board of Directors, including its operations committee, provides oversight of the Companies’ risks from cybersecurity threats. Dominion Energy’s Board of Directors as well as its operations committee receive presentations and reports throughout the year on cybersecurity and information security risk from management, including Dominion Energy’s chief security officer, vice president of cybersecurity (CISO) and chief information officer. These presentations and reports address a broad range of topics, including the Companies’ cyber risk management program, updates on recent cybersecurity threats and incidents across the industry, policies and practices, industry trends, threat environment and vulnerability assessments and specific and ongoing efforts to prevent, detect and respond to internal and external critical threats, including management’s hosting in 2025 of its fourth annual practical exercise with external federal, state and local incident response partners. In addition, Dominion Energy’s Board of Directors receives briefings from time to time from outside experts for an independent view on cybersecurity risks, including assessments by independent consulting firms and legal counsel of the Companies’ readiness and resilience.

The Companies utilize an organization structure known as a converged security model that brings together cybersecurity, physical security and threat intelligence within one department led by the chief security officer. The chief security officer joined Dominion Energy in this role in 2018 and has an extensive background in security having retired from the Federal Bureau of Investigation after a more than 20-year career focused on criminal, counter-terrorism, counter-intelligence and cyber investigations. The chief security officer belongs to the Federal Bureau of Investigation’s Domestic Security Alliance Council, the Department of Homeland Security’s Classified Intelligence Forum and is a member of the national Government/Business Executive Forum. In addition to serving on multiple university advisory boards, the chief security officer also serves on the Commonwealth of Virginia’s Informational Technology Advisory Council.

The vice president of cybersecurity (CISO) has over 30 years of experience at Dominion Energy primarily in various roles within the information technology department, including information technology risk management, as well as cybersecurity. The vice president of cybersecurity (CISO) has been involved in designing and evolving the Companies’ cyber risk management policies, practices and procedures. This individual has deep relationships with key external partners and is recognized within the industry and the U.S. as a leading cybersecurity expert.

In addition, management of cybersecurity threats is shared with the chief information officer who is responsible for the Companies’ technology assets including hardware, software, networks, servers and telecommunications. The chief information officer has over 25 years of experience at Dominion Energy primarily in various roles within the information technology department, including information technology risk management. In addition, the chief information officer previously served on the board of the Virginia Cybersecurity Partnership, a collaboration between private industry and the Federal Bureau of Investigation.

The chief security officer, vice president of cybersecurity (CISO) and chief information officer are supported by the senior vice president of administrative services as well as the Companies’ operations, compliance, legal, audit, corporate risk, supply chain, human resources and accounting departments in executing its cybersecurity program. In addition, the chief security officer and chief information officer provide periodic updates concerning recent developments affecting cybersecurity and privacy risk to the Companies’ executive cyber risk council, which includes executive officers responsible for administrative services, corporate affairs, supply chain, corporate secretary and corporate risk along with legal counsel. 

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The Companies maintain a robust, tested and regularly revised Cyber Security Incident Response Plan and a Vendor Compromise Response Plan. These plans detail roles, responsibilities and actions to be taken in response to a detected event whether internal or associated with a third-party service provider. The plans provide clear direction for escalation of information to leadership, including Dominion Energy’s Board of Directors as appropriate, and drive collaboration amongst relevant members of management representing cybersecurity, information technology, operations, supply chain, legal and accounting departments. As necessary, the chief administrative and projects officer, CFO and chief legal officer will advise the CEO on any incidents which could potentially have a material effect on the Companies’ business operations, results of operations or financial condition.

ITEM 2. PROPERTIES

Dominion Energy owns five corporate offices in Richmond, Virginia and other cities in which its subsidiaries operate. Dominion Energy also leases corporate offices in Richmond, Virginia and other cities in which its subsidiaries operate, including its principal executive office in Richmond, Virginia. Virginia Power shares Dominion Energy’s principal executive office in Richmond, Virginia. In addition, Virginia Power leases certain buildings and equipment.

Dominion Energy’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described below by operating segment.

Certain of Virginia Power’s properties are subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. There were no bonds outstanding at December 31, 2025; however, by leaving the indenture open, Virginia Power retains the flexibility to issue mortgage bonds in the future. Additionally, DESC’s bond indenture, which secures its first mortgage bonds, constitutes a direct mortgage lien on substantially all of its electric utility property.

Dominion Energy Virginia

Virginia Power has approximately 7,000 miles of electric transmission lines of 69 kV or more located in Virginia, North Carolina and West Virginia. Portions of Virginia Power’s electric transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, any surplus capacity that may exist in these lines. While Virginia Power owns and maintains its electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance and exchange of capacity and energy for such facilities.

In addition, Virginia Power’s electric distribution network includes approximately 61,000 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, Virginia Power owns 486 substations.

The following tables list Virginia Power’s generating units and capability at December 31, 2025.

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Virginia Power Utility Generation

Plant		Location		Net Summer Capability (MW)		Percentage Net Summer Capability
Gas
Greensville County (CC)		Greensville County, VA		1,605
Brunswick County (CC)		Brunswick County, VA		1,376
Warren County (CC)		Warren County, VA		1,349
Ladysmith (CT)		Ladysmith, VA		782
Bear Garden (CC)		Buckingham County, VA		622
Remington (CT)		Remington, VA		619
Possum Point (CC)		Dumfries, VA		571
Chesterfield (CC)		Chester, VA		386
Elizabeth River (CT)		Chesapeake, VA		327
Gordonsville Energy (CC)		Gordonsville, VA		218
Gravel Neck (CT)		Surry, VA		170
Darbytown (CT)		Richmond, VA		168
Total Gas				8,193		42	%
Nuclear
Surry		Surry, VA		1,676
North Anna		Mineral, VA		1,672	(1)
Total Nuclear				3,348		17
Coal
Mt. Storm		Mt. Storm, WV		1,614
Virginia City Hybrid Energy Center		Wise County, VA		610
Clover		Clover, VA		439	(2)
Total Coal				2,663		13
Hydro
Bath County		Warm Springs, VA		1,758	(3)
Gaston		Roanoke Rapids, NC		220
Roanoke Rapids		Roanoke Rapids, NC		95
Other				1
Total Hydro				2,074		11
Oil
Gravel Neck (CT)		Surry, VA		198
Darbytown (CT)		Richmond, VA		168
Rosemary (CC)		Roanoke Rapids, NC		155
Possum Point (CT)		Dumfries, VA		72
Low Moor (CT)		Covington, VA		48
Northern Neck (CT)		Lively, VA		47
Chesapeake (CT)		Chesapeake, VA		39
Total Oil				727		4
Solar(4)
Colonial Trail West		Surry County, VA		142
Bookers Mill		Farnham, VA		127
Sadler Solar		Emporia, VA		100
Spring Grove		Surry County, VA		98
Fountain Creek		Greensville, VA		80
Piney Creek		Halifax, VA		80
Otter Creek		Mecklenburg County, VA		60
Sycamore		Gretna, VA		42
Camellia		Gloucester County, VA		20
Grassfield		Chesapeake, VA		20
Norge		Williamsburg, VA		20
North Ridge		Powhatan, VA		20
Solidago		Windsor, VA		20
Whitehouse Solar		Louisa County, VA		20
Winterberry		Gloucester County, VA		20
Woodland Solar		Isle of Wight County, VA		19
Quillwort		Powhatan, VA		18
Sebera		Prince George, VA		18
Scott Solar		Powhatan, VA		17
Total Solar				941		4

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Plant		Location		Net Summer Capability (MW)		Percentage Net Summer Capability
Biomass
Altavista		Altavista, VA		51
Polyester		Hopewell, VA		51
Southampton		Southampton, VA		51
Total Biomass				153		1
Battery
Dry Bridge		Chesterfield, VA		20
Scott Battery		Powhatan, VA		12
Total Battery				32		—
Wind
CVOW Pilot Project		Virginia Beach, VA		12		—
Various
Mt. Storm (CT)		Mt. Storm, WV		11		—
Total Excluding Power Purchase Agreements				18,154
Power Purchase Agreements				1,560		8
Total Utility Generation				19,714		100	%

Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.

(1)Excludes 11.6% undivided interest owned by ODEC.

(2)Excludes 50% undivided interest owned by ODEC.

(3)Excludes 23.75% undivided interest owned by LS Power Equity Advisors LLC and 16.25% undivided interest owned by Allegheny Generating Company, a subsidiary of FirstEnergy.

(4)All solar facilities are alternating current.

Virginia Power Non-Jurisdictional Generation

Plant		Location		Net Summer Capability (MW)
Solar(1)
Ft. Powhatan		Disputanta, VA			150
Maplewood		Chatham, VA			120
Belcher		Louisa, VA			88
Gutenberg		Garysburg, NC			80
Grasshopper		Chase City, VA			80
Pecan		Pleasant Hill, NC			75
Chestnut		Halifax County, NC			75
Bedford(2)		Chesapeake, VA			70
Pumpkinseed(2)		Emporia, VA			60
Gloucester		Gloucester County, VA			20
Montross		Westmoreland County, VA			20
Morgans Corner		Pasquotank County, NC			20
Remington		Fauquier County, VA			20
Rochambeau		James City County, VA			20
Oceana		Virginia Beach, VA			18
Hollyfield		Manquin, VA			17
Puller		Topping, VA			15
Total Non-Jurisdictional Generation					948

(1)All solar facilities are alternating current.

(2)Virginia Power in October 2025 proposed to recover the cost of this facility through Rider CE. If approved by the Virginia Commission, this facility will be considered Utility Generation.

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Dominion Energy South Carolina

DESC has approximately 3,800 miles and 19,400 miles of electric transmission and distribution lines, respectively, exclusive of service level lines, in South Carolina. The grants for most of DESC’s electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying property titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, DESC owns 454 substations.

DESC’s natural gas system includes approximately 20,000 miles of distribution mains and related service facilities, which are supported by approximately 400 miles of transmission pipeline.

DESC owns two LNG facilities, one located near Charleston, South Carolina, and the other in Salley, South Carolina. The Charleston facility can store the liquefied equivalent of approximately 1.0 bcf of natural gas, can regasify approximately 6% of its storage capacity per day and can liquefy less than 1% of its storage capacity per day. The Salley facility can store the liquefied equivalent of approximately 0.9 bcf of natural gas and can regasify approximately 10% of its storage capacity per day. The Salley facility has no liquefying capabilities.

The following table lists DESC’s generating units and capability at December 31, 2025.

Plant		Location		Net Summer Capability (MW)		Percentage Net Summer Capability
Gas
Jasper (CC) (1)		Hardeeville, SC		902
Columbia Energy Center (CC) (1)		Gaston, SC		522
Urquhart (CC) (1)		Beech Island, SC		458
McMeekin		Irmo, SC		250
Hagood (CT) (1)		Charleston, SC		118
Urquhart Unit 3		Beech Island, SC		95
Urquhart (CT) (1)		Beech Island, SC		87
Parr (CT) (1)		Jenkinsville, SC		84
Bushy Park (CT) (1)		Goose Creek, SC		42
Total Gas				2,558		37	%
Coal
Wateree		Eastover, SC		684
Williams		Goose Creek, SC		595
Cope (2)		Cope, SC		415
Total Coal				1,694		25
Hydro
Fairfield		Jenkinsville, SC		576
Saluda		Irmo, SC		190
Other		Various		18
Total Hydro				784		12
Nuclear
Summer		Jenkinsville, SC		644	(3)	9
Total Excluding Power Purchase Agreements				5,680
Power Purchase Agreements				1,187	(4)	17
Total Utility Generation				6,867		100	%

Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.

(1)Capable of burning fuel oil as a secondary source.

(2)Capable of burning natural gas as a secondary source.

(3)Excludes 33.3% undivided interest owned by Santee Cooper.

(4)Includes 189 MW from agreements with certain solar facilities within Contracted Energy.

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Contracted Energy

The following table lists Contracted Energy’s generating units and capability at December 31, 2025.

Plant		Location		Net Summer Capability (MW)				Percentage Net Summer Capability
Nuclear
Millstone		Waterford, CT			2,013		(1)
Total Nuclear					2,013				61		%
Solar(2)
Atlanta Farms		Pickaway County, OH			200
Hardin I		Hardin County, OH			150
Amazon Solar Farm Virginia – Southampton		Newsoms, VA			100
Foxhound Solar		Clover, VA			83
Amazon Solar Farm Virginia – Accomack		Oak Hall, VA			80
Greensville		Greensville County, VA			80
Innovative Solar 37		Morven, NC			79
Wilkinson		Pantego, NC			74
Seabrook		Beaufort County, SC			73
Moffett Solar 1		Ridgeland, SC			71
Summit Farms Solar		Moyock, NC			60
Midway II		Calipatria, CA			30
Amazon Solar Farm Virginia – Buckingham		Cumberland, VA			20
Amazon Solar Farm Virginia – Correctional		Barhamsville, VA			20
Hecate Cherrydale		Cape Charles, VA			20
Amazon Solar Farm Virginia – Sussex Drive		Stoney Creek, VA			20
Amazon Solar Farm Virginia – Scott II		Powhatan, VA			20
Myrtle		Suffolk, VA			15
Trask		Beaufort County, SC			12
Hecate Energy Clarke County		White Post, VA			10
Ridgeland Solar Farm I		Ridgeland, SC			10
Yemassee		Hampton County, SC			10
Blackville		Blackville, SC			7
Denmark		Denmark, SC			6
Other		Various			35
Total Solar					1,285				39
Total Nonregulated Generation					3,298				100		%

(1)Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain.

(2)All solar facilities are alternating current.

Additionally, Dominion Energy’s renewable natural gas facilities include 21 facilities in Colorado, Georgia, Idaho, Kansas, New Mexico, Nevada and Texas, which capture methane from dairy farms and convert it into pipeline quality natural gas. These facilities produce approximately 5,500 MMBtu per day. 

Corporate And Other

Dominion Energy owns various solar facilities, primarily at schools in Virginia, with an aggregate generation capacity of 33 MW.

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Item 3. Legal Proceedings

From time to time, the Companies are parties to various legal, environmental or other regulatory proceedings, including in the ordinary course of business. SEC regulations require disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Companies reasonably believe will exceed a specified threshold. Pursuant to the SEC regulations, the Companies use a threshold of $1 million for such proceedings. See Notes 13 and 23 to the Consolidated Financial Statements, which information is incorporated herein by reference, for discussion of certain legal, environmental and other regulatory proceedings to which the Companies are a party.

Item 4. Mine Safety Disclosures

Not applicable.

Information about our Executive Officers

Information concerning the executive officers of Dominion Energy, each of whom is elected annually, is as follows:

Name and Age		Business Experience Past Five Years(1)
Robert M. Blue (58)		Chair of the Board of Directors from April 2021 to present; President and CEO from October 2020 to present; Director from November 2020 to present.
Edward H. Baine (52)		Executive Vice President—Utility Operations and President—Dominion Energy Virginia from July 2025 to present; President—Utility Operations and Dominion Energy Virginia from January 2025 to June 2025; President—Dominion Energy Virginia from October 2020 to December 2024.
Carlos M. Brown (51)		Executive Vice President, Chief Administrative and Projects Officer, and Corporate Secretary and President—DES from June 2025 to present; President—DES and Executive Vice President, Chief Legal Officer and Corporate Secretary from January 2024 to May 2025; Senior Vice President, Chief Legal Officer and General Counsel from September 2022 to December 2023; Senior Vice President, General Counsel and Chief Compliance Officer from December 2019 to August 2022.
Eric S. Carr (52)		Chief Nuclear Officer and President—Nuclear Operations and Contracted Energy from January 2025 to present; President—Nuclear Operations and Chief Nuclear Officer from July 2023 to December 2024; President—Nuclear Operations during June 2023; President and Chief Nuclear Officer for PSEG Nuclear, LLC, a subsidiary of Public Service Enterprise Group, Incorporated, from July 2019 to May 2023.
Regina J. Elbert (45)		Senior Vice President and Chief Legal and Human Resources Officer from June 2025 to present; Senior Vice President and Chief Human Resources Officer from January 2024 to May 2025; Senior Vice President—Human Resources from April 2022 to December 2023; Vice President—Human Resources Business Services from March 2019 to March 2022.
W. Keller Kissam (59)		President—Dominion Energy South Carolina from January 2022 to present; President—Electric Operations of DESC from January 2019 to December 2021.
Gary G. Ratliff (47)		Vice President, Controller and CAO from October 2025 to present; Vice President—Accounting from April 2025 to September 2025; Controller—Corporate Research & Reporting from February 2024 to March 2025; Director—Accounting from September 2015 to January 2024.
Steven D. Ridge (45)		Executive Vice President and CFO from January 2024 to present; Senior Vice President and CFO from November 2022 to December 2023; President of Questar Gas from October 2022 to November 2022; Vice President and General Manager—Western Distribution from October 2021 to September 2022; Vice President—Investor Relations of DES from April 2019 to September 2021.

(1)All positions held at Dominion Energy, unless otherwise noted. Any service listed for Virginia Power, DESC, Questar Gas and DES reflects service at a subsidiary of Dominion Energy.

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Part II

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

Dominion Energy

Dominion Energy’s common stock is listed on the NYSE under the ticker symbol D. At February 16, 2026, there were approximately 106,000 record holders of Dominion Energy’s common stock. The number of record holders is comprised of individual shareholder accounts maintained on Dominion Energy’s transfer agent records and includes accounts with shares held in (1) certificate form, (2) book-entry in the Direct Registration System and (3) book-entry under Dominion Energy Direct®. Discussions of expected dividend payments required by this Item are contained in Liquidity and Capital Resources in Item 7. MD&A.

Purchases of Equity Securities

Period		Total Number of Shares (or Units) Purchased (1)				Average Price Paid per Share (or Unit)(2)				Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs				Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs(3)
10/1/25-10/31/25			68,646			$	60.90				—			$ 0.92 billion
11/1/25-11/30/25			412				58.69				—			0.92 billion
12/1/25-12/31/25			2,516				60.80				—			0.92 billion
Total			71,574			$	60.88				—			$ 0.92 billion

(1)Represents shares of common stock that were tendered by employees to satisfy tax withholding obligations on vested restricted stock.

(2)Represents the weighted-average price paid per share.

(3)In November 2020, the Dominion Energy Board of Directors authorized the repurchase of up to $1.0 billion of shares of common stock. This repurchase program has no expiration date or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors. At December 31, 2025, approximately $920 million remained available under the program.

Virginia Power

There is no established public trading market for Virginia Power’s common stock, all of which is owned by Dominion Energy. Virginia Power may pay cash dividends in 2026 but is neither required to nor restricted, except as described in Note 21 to the Consolidated Financial Statements, from making such payments.

ITEM 6. [RESERVED]

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

MD&A discusses Dominion Energy’s results of operations, general financial condition and liquidity and Virginia Power’s results of operations. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data. Virginia Power meets the conditions to file under the reduced disclosure format, and therefore has omitted certain sections of MD&A.

Contents of MD&A

MD&A consists of the following information:

•Forward-Looking Statements—Dominion Energy and Virginia Power

•Accounting Matters—Dominion Energy

•Results of Operations—Dominion Energy and Virginia Power

•Segment Results of Operations—Dominion Energy

•Outlook—Dominion Energy

•Liquidity and Capital Resources—Dominion Energy

•Future Issues and Other Matters—Dominion Energy

Forward-Looking Statements

This report contains statements concerning the Companies’ expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “path”, “anticipate”, “believe”, “forecast”, “could”, “estimate”, “expect”, “intend”, “may”, “plan”, “outlook”, “predict”, “project”, “should”, “strategy”, “continue”, “target”, “will”, “potential” or other similar words.

The Companies make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:

•Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;

•Extreme weather events and other natural disasters, including, but not limited to, hurricanes, high winds, severe storms, earthquakes, flooding, wildfires, climate changes and changes in water temperatures and availability that can cause outages and property damage to facilities;

•The impact of extraordinary external events, such as the pandemic health event resulting from COVID-19, and their collateral consequences, including extended disruption of economic activity in the Companies’ markets and global supply chains;

•Federal, state and local legislative and regulatory developments;

•Changes in or interpretations of federal and state tax laws and regulations, including those related to tax credits or other incentives;

•Risks of operating businesses in regulated industries that are subject to changing regulatory structures;

•Changes to regulated electric rates collected by the Companies and regulated gas distribution rates collected by Dominion Energy;

•Changes in rules for RTOs and ISOs in which the Companies join and/or participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models;

•Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants;

•Risks associated with entities in which the Companies share ownership with third parties, such as Stonepeak’s noncontrolling interest in the CVOW Commercial Project, including risks that result from lack of sole decision-making authority, disputes that may arise between the Companies and third-party participants and difficulties in exiting these arrangements;

•Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals;

•The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement, intervention or litigation in such projects;

•Risks and uncertainties that may impact the Companies’ ability to construct the CVOW Commercial Project within the currently proposed timeline, or at all, and consistent with current cost estimates along with the ability to recover such costs from customers;

•Risks and uncertainties associated with the timely receipt of future capital contributions, including optional capital contributions, if any, from Stonepeak associated with the construction of the CVOW Commercial Project;

•Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances;

•Cost of environmental strategy and compliance, including those costs related to climate change;

•Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities;

•Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals;

•Unplanned outages at facilities in which the Companies have an ownership interest;

•The impact of operational hazards, including adverse developments with respect to plant safety or integrity,

43

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

equipment loss, malfunction or failure, operator error and other catastrophic events;

•Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities;

•Changes in operating, maintenance and construction costs;

•The availability of nuclear fuel, natural gas, purchased power or other materials utilized by the Companies to provide electric generation, transmission and distribution and/or gas distribution services to their customers;

•Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as cybersecurity threats or incidents;

•Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s nonregulated generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers;

•Competition in the development, construction and ownership of certain electric transmission facilities in the Companies’ service territory in connection with Order 1000;

•Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;

•Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods;

•Risks and uncertainties associated with increased energy demand or significant accelerated growth in demand due to new data centers, including the concentration of data centers primarily in Loudoun County, Virginia and the ability to obtain regulatory approvals, environmental and other permits to construct new facilities in a timely manner;

•The technological and economic feasibility of large-scale battery storage, carbon capture and storage, small modular reactors, hydrogen and/or other clean energy technologies;

•Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures;

•Impacts of acquisitions, divestitures, transfers of assets to joint ventures and retirements of assets based on asset portfolio reviews;

•Adverse outcomes in litigation matters or regulatory proceedings;

•Counterparty credit and performance risk;

•Fluctuations in the value of investments held in nuclear decommissioning trusts by the Companies and in benefit plan trusts by Dominion Energy;

•Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy’s earnings and the Companies’ liquidity position and the underlying value of their assets;

•Fluctuations in interest rates;

•Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;

•Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms;

•Political and economic conditions, including tariffs, inflation and deflation;

•Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; and

•Changes in financial or regulatory accounting principles or policies imposed by governing bodies.

Additionally, other risks that may cause actual results to differ materially from predicted results are set forth in Part I. Item 1A. Risk Factors.

The Companies’ forward-looking statements are based on beliefs and assumptions using information available at the time the statements are made. The Companies caution the reader not to place undue reliance on their forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. The Companies undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

Accounting Matters

Critical Accounting Policies and Estimates

Dominion Energy has identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to its financial condition or results of operations under different conditions or using different assumptions. Dominion Energy has discussed the development, selection and disclosure of each of these policies with the Audit Committee of its Board of Directors.

Accounting for Regulated Operations

The accounting for Dominion Energy’s regulated electric and gas operations differs from the accounting for nonregulated operations in that Dominion Energy is required to reflect the effect of rate regulation in its Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds or other benefits through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. In addition, a loss is recognized if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made.

In 2025, Dominion Energy recorded a net $258 million ($192 million after-tax) of charges for Virginia Power’s share of costs not expected to be recovered from customers on the CVOW

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Commercial Project as a result of a revised total project cost estimate of approximately $11.5 billion (excluding financing costs) which reflects a temporary suspension of work order and an estimated impact of certain tariffs which became effective during 2025 as well as the previously included revised estimate of network upgrade costs assigned by PJM to the CVOW Commercial Project and cost sharing mechanism included in the Virginia Commission’s December 2022 order. The expected total project cost reflects an increase of $0.2 billion, relative to Virginia Power’s October 2025 Rider OSW filing, associated with projected installation timeline changes arising from the temporary suspension of work from the BOEM Director’s Order issued in December 2025 until a preliminary injunction was granted by the U.S District Court for the Eastern District of Virginia in January 2026, which allowed work to resume. The estimated total project costs also include $0.6 billion of tariffs on equipment expected to be delivered from March 2025 through March 2026 that originates from Mexico, Canada, a European Union member or other applicable countries and on equipment expected to be delivered from March 2025 through early 2027 that contains steel. Such amount is inclusive of approximately $0.2 billion associated with tariffs on equipment expected to be delivered from March 2025 through March 2026 that originates from Mexico, Canada, a European Union member or other applicable countries that were the subject of a U.S. Supreme Court’s ruling on February 20, 2026. Dominion Energy is currently unable to estimate the expected impact of the ruling issued by the U.S. Supreme Court on February 20, 2026, on its financial position, results of operations and/or cash flows.

In the fourth quarter of 2024, Dominion Energy recorded a net $103 million ($77 million after-tax) charge for Virginia Power’s share of costs not expected to be recovered from customers on the CVOW Commercial Project as a result of a revised total project cost estimate that included a revised estimate of network upgrade costs assigned by PJM to the CVOW Commercial Project and cost sharing mechanism included in the Virginia Commission’s December 2022 order. The expected total project cost reflects increases driven primarily by projections for onshore electrical interconnection costs and network upgrade costs assigned to the project by PJM, specifically incorporating consideration of PJM’s December 2024 publication of potential transmission network upgrades required for certain generation projects and related cost allocations, including those attributable to the CVOW Commercial Project. Relative to Virginia Power’s November 2024 Rider OSW filing, the estimated total project cost reflects an approximately $0.6 billion increase for such onshore and network upgrade costs and an approximately $0.3 billion increase for increased contingency for remaining construction activities, completion of the removal of unexploded ordnance, undersea cable protection system design enhancements, commodity prices for transportation fuel, updates for sea fastener fabrication and installation and other construction and equipment supplier costs.

The estimated total project cost reflects Dominion Energy’s best estimate of the remaining construction costs, including contingency of approximately 7% on such remaining amounts. Such estimate could potentially change for items, certain of which are beyond Dominion Energy’s control, including but not limited to actual network upgrade costs allocated by PJM, fuel for transportation and installation, the impact of applicable tariffs including any potential impact of Section 232 investigations and litigation ruled on by the U.S. Supreme Court on February 20, 2026, costs to maintain necessary permits, approvals and authorizations, any additional suspension of work orders, ability of key suppliers and contractors to timely satisfy their obligations under existing contracts, marine wildlife and/or any severe weather events. Any additional increase in such costs in excess of the contingency included in the estimated total project cost would be subject to the cost sharing mechanisms described above and could have a material impact on Dominion Energy’s future financial condition, results of operations and/or cash flows. See Note 10 to the Consolidated Financial Statements for additional information.

Dominion Energy evaluates whether or not recovery of its regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makes various assumptions in its analyses. These analyses are generally based on:

•Orders issued by regulatory commissions, legislation and judicial actions;

•Past experience;

•Discussions with applicable regulatory authorities and legal counsel;

•Estimated construction costs;

•Forecasted earnings; and

•Considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events and other natural disasters and unplanned outages of facilities.

If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. A regulatory liability, if considered probable, will be recorded in the period such assessment is made or reversed into earnings if no longer probable. In connection with the future 2027 Biennial Review, Dominion Energy concluded that it was not probable that Virginia Power would have earnings in excess of an expected authorized ROE of 9.80% for the period January 1, 2025 through December 31, 2026. As a result, no regulatory liability for Virginia Power ratepayer credits to customers has been recorded at December 31, 2025. See Note 13 to the Consolidated Financial Statements for additional information.

Asset Retirement Obligations

Dominion Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists and the ARO can be reasonably estimated. These AROs are recognized at fair value as incurred or when sufficient information becomes available to determine fair value and are generally capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Dominion Energy estimates the fair value of its AROs using present value techniques, in which it makes various assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. The impact on measurements of new AROs or remeasurements of existing AROs, using different cost escalation or credit-adjusted risk free rates in the future, may be significant. When Dominion Energy revises any assumptions used to calculate the fair value of existing AROs, it adjusts the carrying amount of both the ARO liability and the related long-lived asset for assets that are in service; for assets that have ceased or are expected to cease operations, Dominion Energy adjusts the carrying amount of the ARO liability with such changes either recognized in income or as a regulatory asset.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

Dominion Energy’s AROs include a significant balance related to the future decommissioning of its nonregulated and utility nuclear facilities. At both December 31, 2025 and 2024, Dominion Energy’s nuclear decommissioning AROs totaled $2.6 billion. The following discusses critical assumptions inherent in determining the fair value of AROs associated with Dominion Energy’s nuclear decommissioning obligations.

Dominion Energy obtains from third-party specialists periodic site-specific base year cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for its nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. These cash flows include estimates on timing of decommissioning, which for regulated nuclear units factors in the probability of NRC approval for license extensions. In addition, Dominion Energy’s cost estimates include cost escalation rates that are applied to the base year costs. Dominion Energy determines cost escalation rates, which represent projected cost increases over time due to both general inflation and increases in the cost of specific decommissioning activities, for each nuclear facility. The selection of these cost escalation rates is dependent on subjective factors which are considered to be critical assumptions. At December 31, 2025, a 0.25% increase in cost escalation rates would have resulted in an approximate $339 million increase in Dominion Energy’s nuclear decommissioning AROs.

At December 31, 2025 and 2024, Dominion Energy’s AROs also include $889 million and $828 million, respectively, for future CCR remediation at retired generating stations and other inactive or previously closed surface impoundments, landfills or other areas in connection with the EPA’s May 2024 rule as described in Note 14. Dominion Energy developed cost estimates related to this CCR remediation, which were based on the estimated quantity of CCRs that would be discovered, if any, at locations which are subject to the regulation. The determination of how much CCR, if any, that exists at an individual location is a critical assumption in the development of the Companies’ AROs. The results of the searches of internally and externally available information regarding the existence and quantity of CCR at specific locations, as well as physical searches for CCR, may cause actual results to vary significantly from expectations.

Income Taxes

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws and associated regulations involves uncertainty since tax authorities may interpret the laws differently. Ultimate resolution or clarification of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2025 and 2024, Dominion Energy had $132 million and $170 million, respectively, of unrecognized tax benefits. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations.

Deferred income tax assets and liabilities are recorded representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion Energy evaluates quarterly the probability of realizing deferred tax assets by considering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. In addition, changes in tax laws or tax rates may require reconsideration of the realizability of existing deferred tax assets. Dominion Energy establishes a valuation allowance when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. At December 31, 2025 and 2024, Dominion Energy had established $143 million and $113 million, respectively, of valuation allowances.

Accounting for Derivative Contracts and Financial Instruments at Fair Value

Dominion Energy uses derivative contracts such as physical and financial forwards, futures, swaps, options and FTRs to manage commodity, interest rate and/or foreign currency exchange rate risks of its business operations. Derivative contracts, with certain exceptions, are reported in the Consolidated Balance Sheets at fair value. The majority of investments held in Dominion Energy’s nuclear decommissioning and rabbi trusts and pension and other postretirement funds are also subject to fair value accounting. See Notes 6 and 22 to the Consolidated Financial Statements for additional information on these fair value measurements.

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, management seeks indicative price information from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, Dominion Energy considers whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if Dominion Energy believes that observable pricing information is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases, Dominion Energy must estimate prices based on available historical and near-term future price information and use of statistical methods, including regression analysis, that reflect its market assumptions.

Dominion Energy maximizes the use of observable inputs and minimizes the use of unobservable inputs when measuring fair value. See Note 6 to the Consolidated Financial Statements for quantitative information on unobservable inputs utilized in Dominion Energy’s fair value measurements of certain derivative contracts.

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Use of Estimates in Goodwill Impairment Testing

In April of each year, Dominion Energy tests its goodwill for potential impairment, and performs additional tests more frequently if an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. The 2025, 2024 and 2023 annual test did not result in the recognition of any goodwill impairment.

In general, Dominion Energy estimates the fair value of its reporting units by using a combination of discounted cash flows and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. Fair value estimates are dependent on subjective factors such as Dominion Energy’s estimate of future cash flows, the selection of appropriate discount and growth rates and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in Dominion Energy’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion Energy has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent test had been 10% lower or if the discount rate had been 0.25% higher, the resulting fair values would have still been greater than the carrying values of each of those reporting units tested, indicating that no impairment was present.

In addition to the annual goodwill impairment testing described above, Dominion Energy’s calculations during the fourth quarter of 2023 and first quarter of 2024 of the expected gain or loss on the Questar Gas and East Ohio Transactions resulted in an impairment of the related goodwill totaling $238 million and $78 million, respectively, reflected in discontinued operations in Dominion Energy’s Consolidated Statements of Income.

See Notes 2 and 11 to the Consolidated Financial Statements for additional information.

Use of Estimates in Long-Lived Asset Impairment Testing

Impairment testing for an individual or group of long-lived assets, including intangible assets with definite lives, is required when circumstances indicate those assets may be impaired. When a long-lived asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets in the case of long-lived assets and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of a market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing, expectations about the operations of the long-lived assets and the selection of an appropriate discount rate. When determining whether a long-lived asset or asset group has been impaired, management groups assets at the lowest level that has identifiable cash flows. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset or underlying assets of equity method investees, including future production and sales levels, expected fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions. There were no tests performed in 2025, 2024 or 2023 of long-lived assets which could have resulted in material impairments.

Employee Benefit Plans

Dominion Energy sponsors noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The projected costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected long-term rate of return on plan assets, discount rates applied to benefit obligations, mortality rates and the anticipated rate of increase in healthcare costs and participant compensation, also have a significant impact on employee benefit costs. The impact of changes in these factors, as well as differences between Dominion Energy’s assumptions and actual experience, is immediately recognized in earnings annually in the fourth quarter of each fiscal year as well as whenever a triggering event occurs that is determined to require remeasurement. Actuarial losses attributable to Dominion Energy’s rate regulated operations are deferred to regulatory assets when it is probable that regulators will permit them to be recovered from customers in future rates. Likewise, actuarial gains attributable to Dominion Energy’s rate regulated operations are deferred to regulatory liabilities when it is probable that regulators will require customer refunds or other benefits through future rates.

The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality rates are critical assumptions. Dominion Energy determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:

•Expected inflation and risk-free interest rate assumptions;

•Historical return analysis to determine long-term historic returns as well as historic risk premiums for various asset classes;

•Expected future risk premiums, asset classes’ volatilities and correlations;

•Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and

•Investment allocation of plan assets. The long-term strategic target asset allocation for Dominion Energy’s pension funds is 30% public equity (inclusive of both U.S. equity and non-U.S. equity), 27% fixed income and 43% other alternative investments which includes private equity, typically through limited partnerships, and credit and absolute return strategies which include investments in debt funds, including public and private debt, and hedge funds.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

Strategic investment policies are established for Dominion Energy’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include those mentioned above such as employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion Energy’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the targets. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns.

Dominion Energy develops its critical assumptions, which are then compared to the forecasts of an independent investment advisor or an independent actuary, as applicable, to ensure reasonableness. An internal committee selects the final assumptions. Dominion Energy calculated its pension cost using an expected long-term rate of return on plan assets assumption of 7.35% for 2025 and that ranged from 7.00% to 8.35% for both 2024 and 2023. For 2026, the expected long-term rate of return for the pension cost assumption is 7.35% for Dominion Energy’s plans held at December 31, 2025. Dominion Energy calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 7.35% for 2025 and 8.35% for both 2024 and 2023. For 2026, the expected long-term rate of return for other postretirement benefit cost assumption is 7.35%.

Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost ranged from 5.84% to 5.87% for pension plans and 5.83% to 5.86% for other postretirement benefit plans in 2025, ranged from 5.37% to 5.75% for pension plans and 5.40% to 5.74% for other postretirement benefit plans in 2024 and ranged from 5.65% to 5.75% for pension plans and 5.69% to 5.70% for other postretirement benefit plans in 2023. Dominion Energy selected a discount rate ranging from 5.59% to 5.69% for pension plans and 5.60% to 5.66% for other postretirement benefit plans for determining its December 31, 2025 projected benefit obligations.

Dominion Energy establishes the healthcare cost trend rate assumption based on analyses of various factors including the specific provisions of its medical plans, actual cost trends experienced and projected and demographics of plan participants. Dominion Energy’s healthcare cost trend rate assumption at December 31, 2025 was 7.00% and is expected to gradually decrease to 5.00% by 2032 and continue at that rate for years thereafter.

The following table illustrates the effect on cost of changing the critical actuarial assumptions discussed above, while holding all other assumptions constant:

				Increase in 2025 Net Periodic Cost
		Change in Actuarial Assumptions		Pension Benefits				Other Postretirement Benefits
(millions, except    percentages)
Discount rate		0.25%		$	5			$	1
Long-term rate of    return on plan    assets		(0.25)%			23				5
Health care cost trend    rate		1%		N/A					4

In addition to the effects on cost, a 0.25% decrease in the discount rate would increase Dominion Energy’s projected pension benefit obligation at December 31, 2025 by $193 million and its accumulated postretirement benefit obligation at December 31, 2025 by $23 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation at December 31, 2025 by $60 million.

See Note 22 to the Consolidated Financial Statements for additional information on Dominion Energy’s employee benefit plans.

New Accounting Standards

See Note 2 to the Consolidated Financial Statements for a discussion of new accounting standards.

Results of Operations

Dominion Energy

Presented below is a summary of Dominion Energy’s consolidated results:

Year Ended December 31,		2025				$ Change				2024				$ Change				2023
(millions, except EPS)
Net income attributable    to Dominion Energy		$	2,998			$	964			$	2,034			$	72			$	1,962
Diluted EPS			3.45				1.12				2.33				0.08				2.25

Overview

2025 vs. 2024

Net income attributable to Dominion Energy increased 47%, primarily due to higher market-related impacts on pension and other postretirement plans, higher rider equity returns reflecting capital investments at Virginia Power, an increase in non-fuel base rates associated with the settlement of the 2024 electric base rate case in South Carolina, the absence of an impairment associated with the Questar Gas Transaction, higher electric utility sales driven by growth and customer usage and an increase in renewable energy tax credits. These increases were partially offset by a 50% noncontrolling interest in the CVOW Commercial Project sold to Stonepeak in October 2024, including impacts of charges for costs not expected to be recovered from customers and the closings of the East Ohio, Questar Gas and PSNC Transactions.

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2024 vs. 2023

Net income attributable to Dominion Energy increased 4%, primarily due to the absence of a charge to reflect the recognition of deferred taxes on the outside basis of stock associated with East Ohio, PSNC, Questar Gas and Wexpro meeting the classification as held for sale, a decrease in impairments associated with the East Ohio and Questar Gas Transactions, an increase in net investment earnings on nuclear decommissioning trust funds, the absence of depreciation expense associated with the East Ohio, PSNC and Questar Gas Transactions upon meeting the classification as held for sale, higher rider equity returns reflecting increased capital investments at Virginia Power, an increase in sales to electric utility customers attributable to weather and the absence of amortization associated with the 2021 Triennial Review. These increases were partially offset by the closings of the East Ohio, PSNC and Questar Gas Transactions, a charge for costs not expected to be recovered from customers on the CVOW Commercial Project, the absence of a gain and equity method earnings from the sale of Dominion Energy’s remaining noncontrolling interest in Cove Point, increased unrealized losses on economic hedging activities, lower market related impacts on pension and other postretirement plans and the impact of 2023 Virginia legislation.

Analysis of Consolidated Operations

Presented below are selected amounts related to Dominion Energy’s results of operations:

Year Ended December 31,		2025				$ Change				2024				$ Change				2023
(millions)
Operating revenue		$	16,506			$	2,047			$	14,459			$	66			$	14,393
Electric fuel and other    energy-related purchases			4,489				875				3,614				(321	)			3,935
Purchased electric capacity			82				8				74				19				55
Purchased gas			297				37				260				(25	)			285
Other operations and    maintenance			3,547				(41	)			3,588				455				3,133
Depreciation and    amortization			2,387				42				2,345				(235	)			2,580
Other taxes			773				42				731				47				684
Impairment of assets and    other charges			517				(83	)			600				293				307
Other income (expense)			1,219				378				841				(155	)			996
Interest and related charges			2,022				129				1,893				214				1,679
Income tax expense			532				121				411				(233	)			644
Net income (loss) from    discontinued operations    including noncontrolling    interests			(14	)			(211	)			197				322				(125	)
Noncontrolling interests			67				120				(53	)			(53	)			—

An analysis of Dominion Energy’s results of operations follows:

2025 vs. 2024

Operating revenue increased 14%, primarily reflecting:

•A $764 million increase to recover the costs and an authorized return, as applicable, associated with Virginia Power non-fuel riders;

•A $582 million net increase in fuel-related revenue as a result of an increase in commodity costs associated with sales to electric utility retail customers ($552 million), including revenue for the deferred fuel securitization and electric utility customers who elect to pay market based or other negotiated rates and related settlements of economic hedges at Virginia Power effective March 2024 and an increase in commodity costs associated with sales to gas utility customers ($30 million);

•A $183 million increase in sales to electric utility retail customers associated with economic and other usage factors;

•A $150 million increase in non-fuel base rates associated with the settlement of the 2024 electric base rate case in South Carolina;

•A $70 million increase in sales to electric utility retail customers associated with growth;

•A $64 million net increase associated with market prices affecting Millstone, including economic hedging impacts of net realized and unrealized losses on freestanding derivatives ($147 million);

•A $41 million increase associated with prices from non-jurisdictional solar generation facilities at Virginia Power;

•A $39 million increase in services provided under transition service agreements primarily associated with the East Ohio, Questar Gas and PSNC Transactions;

•A $30 million increase attributable to sales at Millstone in the day-ahead energy market;

•A $28 million net increase in sales to electric utility retail customers, primarily due to an increase in heating degree days during the heating season ($115 million), partially offset by a decrease in cooling degree days during the cooling season ($87 million);

•A $22 million increase due to the absence of one-time credits to customers associated with the 2023 Biennial Review and the 2024 electric base rate case in South Carolina;

•$21 million in sales of environmental credits generated from renewable natural gas production in 2025; and

•A $20 million increase in sales from nonregulated solar generation facilities.

These increases were partially offset by:

•A $29 million decrease associated with severe weather events affecting Virginia Power.

Electric fuel and other energy-related purchases increased 24%, primarily due to higher commodity costs for electric utilities ($564 million) and an increase in the use of purchased renewable energy credits ($279 million), which are offset in operating revenue and do not impact net income.

Purchased gas increased 14%, primarily due to an increase in commodity costs for gas utility operations, which are offset in operating revenue and do not impact net income.

Other operations and maintenance decreased 1%, primarily reflecting:

•The absence of $80 million of costs associated with the business review completed in March 2024;

•A $64 million decrease in certain Virginia Power expenditures which are primarily recovered through state- and FERC-regulated rates and do not impact net income;

•The absence of a $25 million accrual for remediation costs at a manufactured gas plant site at Virginia Power; and

•A $25 million decrease in outage costs at Virginia Power ($18 million) and Millstone ($7 million).

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

These decreases were partially offset by:

•A $68 million increase in charges associated with severe weather events, including storm damage and restoration costs, affecting Virginia Power;

•A $54 million increase in salaries, wages and benefits; and

•A $41 million increase in outside services.

Depreciation and amortization increased 2%, primarily due to various projects being placed into service ($186 million) and an increase in amortization associated with non-fuel riders ($24 million), which is offset in operating revenue and does not impact net income, partially offset by the absence of RGGI-related amortization ($182 million), which is offset in operating revenue and does not impact net income.

Impairment of assets and other charges decreased 14%, primarily reflecting:

•The absence of charges related to the revision of AROs for Millstone Unit 1 ($122 million);

•The absence of charges for the impairment of certain nonregulated renewable natural gas facilities ($60 million);

•The absence of a $55 million charge in connection with the 2024 electric base rate case in South Carolina primarily to write down certain materials and supplies inventory;

•The absence of a charge in connection with a settlement of an agreement ($47 million);

•The absence of dismantling costs and other activities associated with certain retired electric generation facilities ($40 million);

•The absence of a charge related to the write-off of certain early-stage development costs at Virginia Power ($30 million); and

•The absence of an impairment of a corporate office building ($20 million).

These decreases were partially offset by:

•An increase in charges for costs not expected to be recovered from customers on 100% of the CVOW Commercial Project ($309 million).

Other income increased 45%, primarily due to higher market-related impacts on pension and other postretirement plans ($489 million), an increase in AFUDC associated with rate-regulated projects ($67 million) and a decrease in charitable commitments ($30 million), partially offset by a decrease in non-service components of pension and other postretirement employee benefit plan credits ($120 million), a decrease in net investment gains on nuclear decommissioning trust funds ($44 million) and a decrease in earnings from other investments ($20 million).

Interest and related charges increased 7%, primarily reflecting:

•Net issuances of long-term debt ($242 million); and

•Net losses in 2025 compared to gains in 2024 associated with freestanding derivatives ($55 million).

These increases were partially offset by:

•Variable rate debt repaid from proceeds associated with the business review completed in March 2024 ($69 million);

•Decreased interest expense associated with rider deferrals ($28 million), which is offset in operating revenue and does not impact net income;

•Increases in AFUDC associated with rate-regulated projects ($28 million);

•Lower interest rates on commercial paper ($24 million); and

•The absence of charges incurred due to early debt repayments associated with the business review completed in March 2024 ($20 million).

Income tax expense increased 29%, primarily due to higher pre-tax income ($322 million), partially offset by an increase in renewable energy and other tax credits ($175 million) and lower taxes on earnings within qualified decommissioning trusts ($19 million).

Net income from discontinued operations including noncontrolling interests decreased $211 million, primarily due to the absence of earnings from operations following the closing of the Questar Gas Transaction ($182 million), PSNC Transaction ($134 million) and East Ohio Transaction ($77 million), the absence of a gain on the closing of the Questar Gas Transaction ($42 million) and the absence of a tax benefit associated with the Questar Gas Transaction ($25 million), partially offset by the absence of a loss on the closing of the East Ohio Transaction ($109 million), the absence of an impairment associated with the Questar Gas Transaction ($78 million), the absence of charges for employee benefit items related to the East Ohio Transaction ($33 million), the absence of a loss on the closing of the PSNC Transaction ($31 million) and the absence of tax expense associated with the PSNC Transaction ($16 million).

Noncontrolling interests increased $120 million, due to the 50% noncontrolling interest in the CVOW Commercial Project sold to Stonepeak in October 2024, consisting of Stonepeak’s share of the earnings associated with the CVOW Commercial Project subsequent to closing, which includes a $154 million share of charges for costs not expected to be recovered from customers on the CVOW Commercial Project.

2024 vs. 2023

Operating revenue remained substantially consistent, primarily reflecting:

•A $747 million increase to recover the costs and an authorized return, as applicable, associated with Virginia Power non-fuel riders;

•A $173 million increase in sales to electric utility retail customers, primarily due to an increase in cooling degree days during the cooling season ($107 million) and an increase in heating degree days during the heating season ($66 million);

•A $155 million increase in sales to electric utility retail customers associated with growth;

•A $124 million increase from fewer outages at Millstone, including the relative effect of fewer planned outages ($100 million) and unplanned outages ($24 million);

•A $90 million net increase from electric utility customers who elect to pay market based or other negotiated rates, including settlements of economic hedges at Virginia Power prior to March 2024;

•A $60 million increase in non-fuel base rates associated with the settlement of the electric base rate case in South Carolina; and

50

•A $43 million net increase in transition service agreements primarily associated with the East Ohio, Questar Gas and PSNC Transactions.

These increases were substantially offset by:

•A $687 million net decrease associated with market prices affecting Millstone, including economic hedging impacts of net realized and unrealized losses on freestanding derivatives ($696 million);

•A $336 million net decrease in fuel-related revenue as a result of a decrease in commodity costs associated with sales to electric utility retail customers, including revenue for the deferred fuel securitization and electric utility customers who elect to pay market based or other negotiated rates and related settlements of economic hedges at Virginia Power effective March 2024;

•A $184 million decrease from the combination of certain riders into base rates at Virginia Power as a result of 2023 Virginia legislation;

•A $139 million decrease in sales to electric utility retail customers associated with economic and other usage factors;

•A $24 million decrease in fuel-related revenue as a result of a decrease in commodity costs associated with sales to gas utility customers; and

•A $22 million decrease due to one-time credits to customers associated with the 2023 Biennial Review and the electric base rate case in South Carolina.

Electric fuel and other energy-related purchases decreased 8%, primarily due to lower commodity costs for electric utilities ($408 million), partially offset by an increase in the use of purchased renewable energy credits at Virginia Power ($47 million), which are offset in operating revenue and do not impact net income.

Other operations and maintenance increased 15%, primarily reflecting:

•A $111 million increase in certain Virginia Power expenditures which are primarily recovered through state- and FERC-regulated rates and do not impact net income;

•A $78 million increase in outside services;

•A $71 million increase in salaries, wages and benefits;

•A $63 million increase in costs associated with the business review completed in March 2024;

•A $43 million increase from the combination of certain riders into base rates as a result of 2023 Virginia legislation;

•A $29 million increase in materials and supplies expense;

•A $25 million increase associated with an accrual for remediation costs at a manufactured gas plant site at Virginia Power; and

•A $20 million increase due to the absence of a gain on the transfer of certain utility property in South Carolina.

These increases were partially offset by:

•A $48 million net decrease in outage costs due to lower outage costs at Millstone ($74 million) partially offset by higher outage costs at Virginia Power ($26 million); and

•A $21 million decrease in bad debt expense.

Depreciation and amortization decreased 9%, primarily reflecting:

•The absence of $244 million in amortization of a regulatory asset established in the settlement of the 2021 Triennial Review;

•A $67 million decrease in amortization associated with Virginia Power non-fuel riders, which is offset in operating revenue and does not impact net income;

•A $35 million decrease due to revised estimated useful lives at Millstone; and

•A $17 million decrease due to revised depreciation rates for Bath County.

These decreases were partially offset by:

•A $55 million increase in RGGI-related amortization, which is offset in operating revenue and does not impact net income; and

•A $53 million increase due to various projects being placed into service.

Impairment of assets and other charges increased 95%, primarily reflecting:

•A charge for costs not expected to be recovered from customers on 100% of the CVOW Commercial Project ($206 million);

•Charges for the impairment of certain nonregulated renewable natural gas facilities ($60 million);

•A $55 million charge in connection with the electric base rate case in South Carolina primarily to write down certain materials and supplies inventory;

•A net increase in dismantling costs and other activities associated with certain retired electric generation facilities at Virginia Power ($55 million);

•A charge in connection with a settlement of an agreement ($47 million);

•An increase in charges related to the revision of AROs for Millstone Unit 1 ($39 million); and

•A charge related to the write-off of certain early-stage development costs at Virginia Power ($30 million).

These increases were partially offset by:

•A decrease in impairments of corporate office buildings ($73 million);

•The absence of a charge for an easement related to the CVOW Commercial Project for which Virginia Power will not seek recovery ($65 million);

•The absence of a charge for the write-off of certain previously deferred amounts related to the cessation of certain riders effective July 2023 ($36 million); and

•The absence of a charge associated with the abandonment of certain regulated solar generation and other facilities at Virginia Power ($25 million).

Other income decreased 16%, primarily due to lower market related impacts on pension and other postretirement plans ($351 million) and an increase in charitable commitments ($58 million), partially offset by an increase in net investment gains on nuclear decommissioning trust funds ($171 million), an increase in earnings from other investments ($42 million), the absence of Dominion Energy’s share of an impairment of certain property, plant and equipment at Align RNG ($35 million) and an increase in AFUDC associated with rate-regulated projects ($35 million).

51

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

Interest and related charges increased 13%, primarily reflecting:

•Net issuances of long-term debt ($230 million);

•Lower unrealized gains in 2024 compared to 2023 associated with freestanding derivatives ($135 million);

•Charges incurred due to early debt repayments associated with the business review completed in March 2024 ($20 million);

•Increased interest expense associated with rider deferrals ($13 million), which is offset in operating revenue and does not impact net income; and

•Higher interest rates on commercial paper and long-term debt ($11 million).

These increases were partially offset by:

•A decrease in borrowings under the 364-day term loan facilities ($105 million);

•Variable rate debt repaid from business review proceeds ($69 million);

•A decrease in commercial paper ($30 million); and

•Increased premiums received in 2024 compared to 2023 on interest rate derivatives ($17 million).

Income tax expense decreased 36%, primarily due to lower pre-tax income ($127 million) and an increase in a nuclear production tax credit ($89 million), partially offset by higher taxes on earnings within qualified decommissioning trusts ($26 million).

Net income from discontinued operations including noncontrolling interests increased $322 million, primarily due to the absence of charges reflecting the recognition of deferred taxes on the outside basis of stock associated with East Ohio, PSNC, Questar Gas and Wexpro meeting the classification as held for sale ($835 million), a decrease in impairments associated with the East Ohio and Questar Gas Transactions ($197 million), the absence of depreciation expense associated with the East Ohio, PSNC and Questar Gas Transactions upon meeting the classification as held for sale ($211 million), the absence of interest expense on variable rate debt secured by Dominion Energy’s interest in Cove Point ($72 million), a gain upon the closing of the Questar Gas Transaction ($42 million), the absence of an impairment charge associated with the impairment of Birdseye ($34 million), the absence of charges associated with the impairment of the Madison solar project ($19 million) and the absence of an impairment charge of certain nonregulated solar assets ($11 million), partially offset by the absence of a gain on the sale of Dominion Energy’s remaining noncontrolling interest in Cove Point ($348 million), the absence of earnings from operations following the closing of the East Ohio Transaction ($299 million) and Questar Gas Transaction ($138 million), the absence of equity method earnings from the sale of Dominion Energy’s noncontrolling interest in Cove Point ($163 million), a loss on the closing of the East Ohio Transaction ($109 million), charges for employee benefit items related to the East Ohio Transaction ($33 million), a loss on the closing of the PSNC Transaction ($31 million) and higher tax expense associated with the PSNC Transaction ($16 million).

Noncontrolling interests decreased $53 million, due to the 50% noncontrolling interest in the CVOW Commercial Project sold to Stonepeak in October 2024, consisting of Stonepeak’s share of a charge for costs not expected to be recovered from customers on the CVOW Commercial Project ($103 million) partially offset by its share of the remaining earnings associated with the CVOW Commercial Project subsequent to closing.

Virginia Power

Presented below is a summary of Virginia Power’s consolidated results:

Year Ended December 31,		2025				$ Change				2024				$ Change				2023
(millions)
Net income attributable    to Virginia Power		$	2,101			$	204			$	1,897			$	455			$	1,442

Overview

2025 vs. 2024

Net income attributable to Virginia Power increased 11%, primarily due to higher rider equity returns reflecting capital investments and higher sales driven by growth and customer usage, partially offset by a 50% noncontrolling interest in the CVOW Commercial Project sold to Stonepeak in October 2024, including impacts of charges for costs not expected to be recovered from customers and an increase in interest on long-term debt borrowings and higher average outstanding principal on commercial paper and intercompany borrowings with Dominion Energy.

2024 vs. 2023

Net income attributable to Virginia Power increased 32%, primarily due to the absence of amortization associated with the 2021 Triennial Review, higher rider equity returns reflecting increased capital investments and an increase in sales to electric utility customers attributable to weather and other customer-related factors, partially offset by a charge for costs not expected to be recovered from customers on the CVOW Commercial Project and the impact of 2023 Virginia legislation.

Analysis of Consolidated Operations

Presented below are selected amounts related to Virginia Power’s results of operations:

Year Ended December 31,		2025				$ Change				2024				$ Change				2023
(millions)
Operating revenue		$	11,812			$	1,577			$	10,235			$	662			$	9,573
Electric fuel and other energy-    related purchases			3,591				848				2,743				(175	)			2,918
Purchased electric capacity			71				3				68				22				46
Other operations and    maintenance			2,330				93				2,237				386				1,851
Depreciation and amortization			1,630				(14	)			1,644				(227	)			1,871
Other taxes			362				29				333				35				298
Impairment of assets and    other charges			516				224				292				177				115
Other income (expense)			255				57				198				65				133
Interest and related charges			951				102				849				84				765
Income tax expense			448				25				423				23				400
Noncontrolling interests			67				120				(53	)			(53	)			—

An analysis of Virginia Power’s results of operations follows:

2025 vs. 2024

Operating revenue increased 15%, primarily reflecting:

•A $764 million increase to recover the costs and an authorized return, as applicable, associated with non-fuel riders;

•A $526 million net increase in fuel-related revenue as a result of an increase in commodity costs associated with sales to electric utility retail customers, including revenue for the

52

deferred fuel securitization and electric utility customers who elect to pay market based or other negotiated rates and related settlements of economic hedges effective March 2024;

•A $161 million increase in sales to electric utility retail customers associated with economic and other usage factors;

•A $56 million increase in sales to electric utility retail customers associated with growth;

•A $41 million increase associated with prices from non-jurisdictional solar generation facilities;

•A $25 million net increase in sales to electric utility retail customers, primarily due to an increase in heating degree days during the heating season ($95 million), partially offset by a decrease in cooling degree days during the cooling season ($70 million); and

•A $15 million increase due to the absence of one-time credits to customers associated with the 2023 Biennial Review.

These increases were partially offset by:

•A $29 million decrease associated with severe weather events.

Electric fuel and other energy-related purchases increased 31%, primarily due to higher commodity costs for electric utilities ($538 million) and an increase in the use of purchased renewable energy credits ($279 million), which are offset in operating revenue and do not impact net income.

Other operations and maintenance increased 4%, primarily reflecting:

•A $129 million increase in salaries, wages and benefits and administrative costs;

•A $68 million increase in charges associated with severe weather events, including storm damage and restoration costs; and

•A $53 million increase in outside services.

These increases were partially offset by:

•A $64 million decrease in certain expenditures which are primarily recovered through state- and FERC-regulated rates and do not impact net income;

•The absence of a $25 million accrual for remediation costs at a manufactured gas plant site;

•A $18 million decrease in outage costs; and

•A $15 million decrease in nuclear insurance costs.

Depreciation and amortization decreased 1%, primarily due to the absence of RGGI-related amortization ($182 million), which is offset in operating revenue and does not impact net income, partially offset by an increase due to various projects being placed into service ($134 million) and an increase in amortization associated with non-fuel riders ($24 million), which is offset in operating revenue and does not impact net income.

Impairment of assets and other charges increased 77%, primarily due to an increase in charges for costs not expected to be recovered from customers on 100% of the CVOW Commercial Project ($309 million), partially offset by the absence of dismantling costs and other activities associated with certain retired electric generation facilities ($40 million) and the absence of a charge related to the write-off of certain early-stage development costs ($30 million).

Other income increased 29%, primarily due to an increase in AFUDC associated with rate-regulated projects ($67 million), partially offset by a decrease in net investment gains on nuclear decommissioning trust funds ($12 million).

Interest and related charges increased 12%, primarily due to an increase in long-term debt borrowings ($109 million) and higher average outstanding principal on commercial paper and intercompany borrowings with Dominion Energy ($37 million), partially offset by increases in AFUDC associated with rate-regulated projects ($28 million) and decreased interest expense associated with rider deferrals ($28 million), which is offset in operating revenue and does not impact net income.

Income tax expense increased 6%, primarily due to higher pre-tax income ($57 million), partially offset by an increase in renewable energy and other tax credits ($23 million).

Noncontrolling interests increased $120 million, due to the 50% noncontrolling interest in the CVOW Commercial Project sold to Stonepeak in October 2024, consisting of Stonepeak’s share of the earnings associated with the CVOW Commercial Project subsequent to closing, which includes a $154 million share of charges for costs not expected to be recovered from customers on the CVOW Commercial Project.

2024 vs. 2023

Operating revenue increased 7%, primarily reflecting:

•A $747 million increase to recover the costs and an authorized return, as applicable, associated with non-fuel riders;

•A $130 million increase in sales to electric utility retail customers associated with growth;

•A $124 million increase in sales to electric utility retail customers, primarily due to an increase in cooling degree days during the cooling season ($78 million) and an increase in heating degree days during the heating season ($46 million);

•An $85 million increase from electric utility customers who elect to pay market based or other negotiated rates, including settlements of economic hedges prior to March 2024; and

•An $18 million increase in sales to customers from non-jurisdictional solar generation facilities.

These increases were partially offset by:

•A $184 million decrease from the combination of certain riders into base rates as a result of 2023 Virginia legislation;

•A $154 million net decrease in fuel-related revenue as a result of a decrease in commodity costs associated with sales to electric utility retail customers, including revenue for the deferred fuel securitization and electric utility customers who elect to pay market based or other negotiated rates and related settlements of economic hedges effective March 2024;

•A $122 million decrease in sales to electric utility retail customers associated with economic and other usage factors; and

•A $15 million decrease due to one-time credits to customers associated with the 2023 Biennial Review.

Electric fuel and other energy-related purchases decreased 6%, primarily due to lower commodity costs for electric utilities ($226 million), partially offset by an increase in the use of purchased renewable energy credits ($47 million), which are offset in operating revenue and do not impact net income.

Purchased electric capacity increased 48%, primarily due to new capacity contracts and changes in existing capacity contracts.

53

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

Other operations and maintenance increased 21%, primarily reflecting:

•A $111 million increase in certain expenditures which are primarily recovered through state- and FERC-regulated rates and do not impact net income;

•A $67 million increase in salaries, wages and benefits and administrative costs;

•A $48 million increase in outside services;

•A $43 million increase from the combination of certain riders into base rates as a result of 2023 Virginia legislation;

•A $27 million increase in materials and supplies expense;

•A $26 million increase in outage costs;

•A $25 million increase associated with an accrual for remediation costs at a manufactured gas plant site; and

•A $15 million increase in tree trimming and vegetation management.

These increases were partially offset by:

•A $19 million decrease in bad debt expense.

Depreciation and amortization decreased 12%, primarily reflecting:

•The absence of $244 million in amortization of a regulatory asset established in the settlement of the 2021 Triennial Review;

•A $67 million decrease in amortization associated with non-fuel riders, which is offset in operating revenue and does not impact net income; and

•A $17 million decrease due to revised depreciation rates for Bath County.

These decreases were partially offset by:

•A $55 million increase in RGGI-related amortization, which is offset in operating revenue and does not impact net income; and

•A $42 million increase due to various projects being placed into service.

Other taxes increased 12%, primarily due to higher property taxes.

Impairment of assets and other charges increased $177 million, primarily reflecting:

•A charge for costs not expected to be recovered from customers on 100% of the CVOW Commercial Project ($206 million);

•A net increase in dismantling costs and other activities associated with certain retired electric generation facilities ($55 million); and

•A charge related to the write-off of certain early-stage development costs ($30 million).

These increases were partially offset by:

•The absence of a charge for an easement related to the CVOW Commercial Project for which Virginia Power will not seek recovery ($65 million);

•The absence of a charge for the write-off of certain previously deferred amounts related to the cessation of certain riders effective July 2023 ($36 million); and

•The absence of a charge associated with the abandonment of certain regulated solar generation and other facilities ($25 million).

Other income increased 49%, primarily due to an increase in AFUDC associated with rate-regulated projects ($33 million) and an increase in net investment gains on nuclear decommissioning trust funds ($30 million).

Interest and related charges increased 11%, primarily due to an increase in long-term debt borrowings ($178 million) and increased interest expense associated with rider deferrals ($13 million), which is offset in operating revenue and does not impact net income, partially offset by a decrease in principal on commercial paper and intercompany borrowings with Dominion Energy ($89 million) and lower interest rates on commercial paper, long-term debt and intercompany borrowings with Dominion Energy ($23 million).

Income tax expense increased 6%, primarily due to higher pre-tax income ($106 million), partially offset by a nuclear production tax credit ($89 million).

Noncontrolling interests decreased $53 million, due to the 50% noncontrolling interest in the CVOW Commercial Project sold to Stonepeak in October 2024, consisting of Stonepeak’s share of a charge for costs not expected to be recovered from customers on the CVOW Commercial Project ($103 million) partially offset by its share of the remaining earnings associated with the CVOW Commercial Project subsequent to closing.

Segment Results of Operations

Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit and loss. Presented below is a summary of contributions by Dominion Energy’s operating segments to net income (loss) attributable to Dominion Energy:

		Net Income (Loss) Attributable to Dominion Energy				EPS(1)				Net Income (Loss) Attributable to Dominion Energy				EPS(1)				Net Income (Loss) Attributable to Dominion Energy				EPS(1)
Year Ended December 31,		2025								2024								2023
(millions, except EPS)
Dominion    Energy    Virginia		$	2,325			$	2.72			$	2,011			$	2.40			$	1,684			$	2.01
Dominion    Energy    South    Carolina			535				0.63				398				0.47				377				0.45
Contracted    Energy			438				0.51				359				0.43				99				0.12
Corporate    and Other			(300	)			(0.41	)			(734	)			(0.97	)			(198	)			(0.33	)
Consolidated		$	2,998			$	3.45			$	2,034			$	2.33			$	1,962			$	2.25

(1)Consolidated results are presented on a diluted EPS basis. The dilutive impacts, primarily consisting of potential shares which had not yet been issued, are included within the results of the Corporate and Other segment. EPS contributions for Dominion Energy’s operating segments are presented utilizing basic average shares outstanding for the period.

54

Dominion Energy Virginia

Presented below are selected operating statistics related to Dominion Energy Virginia’s operations:

Year Ended December 31,		2025				% Change				2024				% Change				2023
Electricity delivered    (million MWh)			100.2				6		%		94.5				5		%		89.9
Electricity supplied (million MWh):
Utility			100.3				6				94.6				5				90.0
Non-Jurisdictional			1.7				—				1.7				6				1.6
Degree days (electric distribution and utility service area):
Cooling			1,720				(11	)			1,928				17				1,643
Heating			3,508				18				2,969				5				2,830
Average electric    distribution customer    accounts    (thousands)			2,809				1				2,782				1				2,752

Presented below, on an after-tax basis, are the key factors impacting Dominion Energy Virginia’s net income contribution:

2025 VS. 2024		Increase (Decrease)
		Amount				EPS
(millions, except EPS)
Weather		$	18			$	0.02
Customer usage and other factors			173				0.21
Customer-elected rate impacts			(7	)			(0.01	)
Rider equity return			507				0.60
Storm damage and restoration costs			10				0.01
Planned outage costs			14				0.02
Nuclear production tax credit			—				—
Sale of noncontrolling interest			(275	)			(0.33	)
Depreciation and amortization			(32	)			(0.04	)
Salaries, wages and benefits & administrative    costs			(84	)			(0.10	)
Interest expense, net			(47	)			(0.06	)
Other			37				0.05
Share dilution			—				(0.05	)
Change in net income contribution		$	314			$	0.32

2024 VS. 2023		Increase (Decrease)
		Amount				EPS
(millions, except EPS)
Weather		$	92			$	0.11
Customer usage and other factors			(6	)			(0.01	)
Customer-elected rate impacts			63				0.08
Impact of 2023 Virginia legislation			(142	)			(0.17	)
Rider equity return			349				0.42
Electric capacity			(19	)			(0.02	)
Storm damage and restoration costs			(12	)			(0.01	)
Planned outage costs			(24	)			(0.03	)
Nuclear production tax credit			89				0.11
Sale of noncontrolling interest			(50	)			(0.06	)
Depreciation and amortization			(2	)			—
Interest expense, net			39				0.05
Other			(50	)			(0.07	)
Share dilution			—				(0.01	)
Change in net income contribution		$	327			$	0.39

Dominion Energy South Carolina

Presented below are selected operating statistics related to Dominion Energy South Carolina’s operations:

Year Ended December 31,		2025				% Change				2024				% Change				2023
Electricity delivered    (million MWh)			22.2				1		%		22.0				—		%		21.9
Electricity supplied    (million MWh)			23.3				1				23.1				—				23.0
Degree days (electric distribution service areas):
Cooling			772				(10	)			855				18				725
Heating			1,388				29				1,078				18				917
Gas distribution throughput (bcf):
Sales			68				8				63				(5	)			66
Average distribution customer accounts (thousands):
Electric			818				1				806				2				790
Gas			472				3				460				4				443

Presented below, on an after-tax basis, are the key factors impacting Dominion Energy South Carolina’s net income contribution:

2025 VS. 2024		Increase (Decrease)
		Amount				EPS
(millions, except EPS)
Weather		$	2			$	—
Customer usage and other factors			32				0.04
Customer-elected rate impacts			11				0.01
Base rate case & Natural Gas Rate    Stabilization Act impacts			127				0.15
Capital cost rider			(8	)			(0.01	)
Depreciation and amortization			(17	)			(0.02	)
Salaries, wages and benefits & administrative    costs			(29	)			(0.03	)
Interest expense, net			4				—
Other			15				0.03
Share dilution			—				(0.01	)
Change in net income contribution		$	137			$	0.16

2024 VS. 2023		Increase (Decrease)
		Amount				EPS
(millions, except EPS)
Weather		$	37			$	0.04
Customer usage and other factors			27				0.03
Customer-elected rate impacts			4				—
Base rate case & Natural Gas Rate    Stabilization Act impacts			41				0.05
Capital cost rider			(6	)			(0.01	)
Depreciation and amortization			(12	)			(0.01	)
Interest expense, net			(21	)			(0.03	)
Other			(49	)			(0.05	)
Share dilution			—				—
Change in net income contribution		$	21			$	0.02

Contracted Energy

Presented below are selected operating statistics related to Contracted Energy’s operations:

Year Ended December 31,		2025				% Change				2024				% Change				2023
Electricity supplied    (million MWh)			18.4				2		%		18.0				22		%		14.8
Renewable natural gas    supplied (million MMBtu)			1.1			N/A					—			N/A					—

55

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

Presented below, on an after-tax basis, are the key factors impacting Contracted Energy’s net income contribution:

2025 VS. 2024		Increase (Decrease)
		Amount				EPS
(millions, except EPS)
Margin		$	34			$	0.04
Planned Millstone outages(1)			(4	)			—
Unplanned Millstone outages(1)			8				0.01
Depreciation and amortization			(31	)			(0.04	)
Renewable energy investment tax credits			63				0.08
Renewable energy production tax credits(2)			91				0.11
Salaries, wages and benefits & administrative    costs			(27	)			(0.03	)
Interest expense, net			(14	)			(0.02	)
Other			(41	)			(0.06	)
Share dilution			—				(0.01	)
Change in net income contribution		$	79			$	0.08

(1)Includes earnings impact from outage costs and lower energy margins.

(2)Includes an increase from renewable natural gas facilities of $79 million.

2024 VS. 2023		Increase (Decrease)
		Amount				EPS
(millions, except EPS)
Margin		$	103			$	0.12
Planned Millstone outages(1)(2)			119				0.14
Unplanned Millstone outages(1)			16				0.02
Depreciation and amortization			22				0.03
Interest expense, net			14				0.02
Other			(14	)			(0.02	)
Share dilution			—				—
Change in net income contribution		$	260			$	0.31

(1)Includes earnings impact from outage costs and lower energy margins.

(2)Includes the effect of one planned refueling outage during 2024 as compared to two planned refueling outages in 2023.

Corporate and Other

Presented below are the Corporate and Other segment’s after-tax results:

Year Ended December 31,		2025				2024				2023
(millions, except EPS)
Specific items attributable to operating segments		$	(28	)		$	(222	)		$	336
Specific items attributable to    Corporate and Other segment			60				(136	)			(89	)
Net income (expense) from specific items			32				(358	)			247
Corporate and other operations:
Interest expense, net			(519	)			(537	)			(564	)
Equity method investments			(5	)			(5	)			6
Pension and other postretirement benefit plans			232				277				232
Corporate service company costs			(52	)			(79	)			(126	)
Other			12				(32	)			7
Net expense from corporate and other operations			(332	)			(376	)			(445	)
Total net expense		$	(300	)		$	(734	)		$	(198	)
EPS impact		$	(0.41	)		$	(0.97	)		$	(0.33	)

Corporate and Other includes specific items attributable to Dominion Energy’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. See Note 26 to the Consolidated Financial Statements for discussion of these items in more detail. Corporate and Other also includes specific items attributable to the Corporate and Other segment. In 2025, this primarily included a $97 million after-tax benefit for higher market related impacts on pension and other postretirement plans and a $23 million after-tax loss for derivative mark-to-market changes. In 2024, this primarily included a $278 million after-tax loss associated with lower market related impacts on pension and other postretirement plans, $197 million net income from discontinued operations, primarily associated with operations included in the East Ohio, PSNC and Questar Gas Transactions, including the loss on sale associated with the East Ohio and PSNC Transactions, as well as an impairment charge associated with the Questar Gas Transaction, $69 million in after-tax costs associated with the business review completed in March 2024 and a $27 million after-tax benefit for derivative mark-to-market changes. In 2023, this primarily included an $835 million charge to reflect the recognition of deferred taxes on the outside basis of stock associated with East Ohio, PSNC, Questar Gas and Wexpro meeting the classification as held for sale that reversed when the sales were completed, $710 million net income from discontinued operations, primarily associated with operations included in the East Ohio, PSNC and Questar Gas Transactions and Dominion Energy’s noncontrolling interest in Cove Point, including the gain on sale, as well as an impairment charge associated with the East Ohio and Questar Gas Transactions, a $127 million after-tax benefit for derivative mark-to-market changes, a $69 million after-tax charge associated with the impairment of a corporate office building and a $27 million after-tax benefit for higher market related impacts on pension and other postretirement plans.

Outlook

Dominion Energy’s 2026 net income is expected to increase on a per share basis as compared to 2025 primarily from the following:

•Construction and operation of growth projects primarily in electric utility operations;

•Impacts of the 2025 Biennial Review;

•The absence of charges for Virginia Power’s share of costs not expected to be recovered from customers on the CVOW Commercial Project; and

•Customer growth.

These increases are expected to be partially offset by the following:

•An increase in depreciation and amortization expense;

•An increase in interest expense;

•An increase in planned outage days at Millstone;

•An increase in operations and maintenance expense; and

•Share dilution.

Liquidity And Capital Resources

Dominion Energy depends on both cash generated from operations and external sources of liquidity to provide working capital and as a bridge to long-term financings. Dominion Energy’s material cash requirements include capital and investment expenditures, repaying short-term and long-term debt obligations and paying dividends on its common and preferred stock.

56

Analysis of Cash Flows

Presented below are selected amounts related to Dominion Energy’s cash flows:

Year Ended December 31,		2025				2024				2023
(millions)
Cash, restricted cash and equivalents at    beginning of year		$	365			$	301			$	341
Cash flows provided by (used in):
Operating activities(1)			5,361				5,018				6,572
Investing activities			(12,969	)			(3,183	)			(7,207	)
Financing activities			7,586				(1,771	)			595
Net increase (decrease) in cash, restricted    cash and equivalents			(22	)			64				(40	)
Cash, restricted cash and equivalents at    end of year		$	343			$	365			$	301

(1)Includes cash outflows of $72 million, $83 million and $78 million for energy efficiency programs in Virginia and $27 million for DSM programs in South Carolina for each of the years ended December 31, 2025, 2024 and 2023, respectively.

Operating Cash Flows

Net cash provided by Dominion Energy’s operating activities increased $343 million, inclusive of a $215 million decrease from discontinued operations. Net cash provided by continuing operations increased $558 million, primarily due to higher operating cash flows from electric utility operations driven by riders, customer usage and other factors ($1.3 billion), settlements of interest rate swaps ($635 million) and an increase from tax credit transfers ($184 million), partially offset by lower deferred fuel and purchased gas cost recoveries ($1.2 billion) and a decrease from changes in working capital ($402 million).

Investing Cash Flows

Net cash used in Dominion Energy’s investing activities increased $9.8 billion, primarily due to the absence of net proceeds from the East Ohio, Questar Gas and PSNC Transactions ($9.2 billion), an increase in plant construction and other property additions ($443 million) and the absence of distributions from equity method affiliates in 2024 ($126 million), partially offset by lower acquisitions of solar development projects ($217 million).

Financing Cash Flows

Net cash from Dominion Energy’s financing activities increased $9.4 billion, primarily due to the absence of net repayments on 364-day term loan facilities in 2024 ($4.8 billion), an increase in net issuances of long-term debt ($3.9 billion), a decrease in net repayments of short-term debt ($1.4 billion), an increase in capital contributions from Stonepeak to OSWP, net of distributions from OSWP to Stonepeak ($951 million), the absence of the repurchase and redemption of the Series B Preferred Stock in 2024 ($801 million), an increase in the issuance of common stock ($756 million) and the absence of supplemental credit facility repayments in 2024 ($450 million), partially offset by the impacts from the sale of a noncontrolling interest in OSWP to Stonepeak ($2.6 billion) and a decrease due to the issuance of securitization bonds in 2024 and higher repayments of such bonds in 2025 ($1.4 billion).

Credit Facilities and Short-Term Debt

Dominion Energy generally uses proceeds from short-term borrowings, including commercial paper, to satisfy short-term cash requirements not met through cash from operations. The levels of borrowing may vary significantly during the course of the year, depending on the timing and amount of cash requirements not satisfied by cash from operations. A description of Dominion Energy’s primary available sources of short-term liquidity follows.

Revolving Credit Facilities

Dominion Energy’s short-term financing is primarily supported by its joint revolving credit facility. In April 2025, Dominion Energy amended its joint revolving credit facility to, among other things, increase the facility limit from $6.0 billion to $7.0 billion and extend the maturity date from June 2026 to April 2030. In addition, in April 2025, Dominion Energy entered into a $1.0 billion 364-day revolving credit agreement.

Dominion Energy’s commercial paper and letters of credit outstanding, as well as capacity available under its credit facilities were as follows:

		Facility Limit				Outstanding Commercial Paper(1)				Outstanding Letters of Credit				Facility Capacity Available
(millions)
At December 31, 2025
Joint revolving credit    facility(2)		$	7,000			$	2,035			$	1			$	4,964
364-day revolving credit    facility(3)			1,000				—								1,000
Total		$	8,000			$	2,035			$	1			$	5,964

(1)The weighted-average interest rate of the outstanding commercial paper supported by Dominion Energy’s joint revolving credit facility was 4.08% at December 31, 2025.

(2)This credit facility matures in April 2030, with the potential to be extended by the borrowers to April 2032, and can be used by the borrowers under the credit facility to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $3.0 billion of letters of credit.

(3)This credit facility matures in April 2026 and contains a maximum allowed total debt to total capital ratio consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility. This credit facility can be used to support bank borrowings and the issuance of commercial paper.

Dominion Energy Reliability InvestmentSM Program

Dominion Energy has an effective shelf registration statement with the SEC for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability InvestmentSM. The registration limits the principal amount that may be outstanding at any one time to $1.0 billion. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Dominion Energy Reliability Investment Committee, or its designee, on a weekly basis. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Dominion Energy or at the investor’s option at any time. At December 31, 2025, Dominion Energy’s Consolidated Balance Sheet included $422 million presented within short-term debt, with a weighted-average interest rate of 3.75%. The proceeds are used for general corporate purposes and to repay debt.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

Other Facilities

In addition to the primary sources of short-term liquidity discussed above, from time to time Dominion Energy enters into separate supplementary credit facilities or term loans, including a new approximately $1.3 billion 364-day term loan facility entered into in February 2026, as discussed in Note 17 to the Consolidated Financial Statements.

Long-Term Debt

Sustainability Revolving Credit Agreement

Dominion Energy maintains a Sustainability Revolving Credit Agreement which, in April 2025 was amended to, among other things, increase the facility limit from $900 million to $1.0 billion and extend the maturity date from June 2025 to April 2028. The Sustainability Revolving Credit Agreement bears interest at a variable rate and is described in Note 18 to the Consolidated Financial Statements. At December 31, 2025, Dominion Energy has no borrowings outstanding under this facility. In February 2026, Dominion Energy borrowed $500 million with the proceeds used to support environmental sustainability and social investment initiatives.

Issuances and Borrowings of Long-Term Debt

During 2025, Dominion Energy issued or borrowed the following long-term debt. Unless otherwise noted, the proceeds were used for the repayment of existing indebtedness and for general corporate purposes.

Month		Type		Public / Private		Entity		Principal				Rate				Stated Maturity
								(millions)
January		First mortgage bonds		Public		DESC		$	450				5.300	%		2035
March		Senior notes		Public		Virginia Power			625				5.150	%		2035
March		Senior notes		Public		Virginia Power			625				5.650	%		2055
March		Senior notes		Public		Dominion Energy			800				5.000	%		2030
March		Senior notes		Public		Dominion Energy			700				5.450	%		2035
May		Senior notes		Public		Dominion Energy			1,000				4.600	%		2028
August		Junior subordinated notes		Public		Dominion Energy			825				6.000	%	(1)	2056
August		Junior subordinated notes		Public		Dominion Energy			700				6.200	%	(1)	2056
September		Senior notes		Public		Virginia Power			825				4.900	%		2035
September		Senior notes		Public		Virginia Power			875				5.600	%		2055
October		Junior subordinated notes		Public		Dominion Energy			625				6.000	%	(1)	2056
October		Junior subordinated notes		Public		Dominion Energy			625				6.200	%	(1)	2056
Total issuances and borrowings								$	8,675

(1)Rate subject to periodic reset as described in Note 18 to the Consolidated Financial Statements.

Dominion Energy currently meets the definition of a well-known seasoned issuer under SEC rules governing the registration, communication and offering processes under the Securities Act of 1933, as amended. The rules provide for a streamlined shelf registration process to provide registrants with timely access to capital. This allows Dominion Energy to use automatic shelf registration statements to register any offering of securities, other than those for exchange offers or business combination transactions.

Dominion Energy anticipates, excluding potential opportunistic financings, issuing between approximately $6.0 billion and $9.5 billion of long-term debt during 2026. Dominion Energy expects to issue long-term debt to satisfy cash needs for capital expenditures, net of reimbursements from Stonepeak for the CVOW Commercial Project, and maturing long-term debt to the extent such amounts are not satisfied from cash available from operations following the payment of dividends and any borrowings made from unused capacity of Dominion Energy’s credit facilities discussed above. The raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.

Repayments, Repurchases and Redemptions of Long-Term Debt

Dominion Energy may from time to time reduce its outstanding debt and level of interest expense through redemption of debt securities prior to maturity or repurchases of debt securities in the open market, in privately negotiated transactions, through tender offers or otherwise.

The following long-term debt was repaid, repurchased or redeemed in 2025:

Month

Type

Entity

Principal

(1)

Rate

Stated Maturity

(millions)

Debt scheduled to mature in 2025

Multiple

$

1,663

various

Early repurchases and redemptions

None

Total repayments, repurchases and redemptions

$

1,663

(1)Total amount redeemed prior to maturity, if any, includes remaining principal plus accrued interest.

See Note 18 to the Consolidated Financial Statements for additional information regarding scheduled maturities of Dominion Energy’s long-term debt, including related average interest rates.

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Remarketing of Long-Term Debt

In September 2025, Virginia Power remarketed two series of tax-exempt bonds, with an aggregate outstanding principal of $222 million to new investors. Each series of bonds bear interest at a coupon of 3.125% until October 2030, after which they will bear interest at a market rate to be determined at that time.

In 2026, Dominion Energy does not expect to remarket any of its tax-exempt bonds.

Credit Ratings

Dominion Energy’s credit ratings affect its liquidity, cost of borrowing under credit facilities and collateral posting requirements under commodity contracts, as well as the rates at which it is able to offer its debt securities. The credit ratings for Dominion Energy are affected by its financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and event risk, if applicable, such as major acquisitions or dispositions.

Dominion Energy’s credit ratings and outlooks at February 16, 2026 are as follows:

		Moody’s		Standard & Poor’s		Fitch
Corporate/Issuer		Baa2		BBB+		BBB+
Senior unsecured debt securities		Baa2		BBB		BBB+
Junior subordinated notes		Baa3		BBB-		BBB-
Preferred stock		Ba1		BBB-		BBB-
Commercial paper		P-2		A-2		F2
Outlook		Negative		Stable		Stable

A credit rating is not a recommendation to buy, sell or hold securities and should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the applicable rating organization.

Financial Covenants

As part of borrowing funds and issuing both short-term and long-term debt or preferred securities, Dominion Energy must enter into enabling agreements. These agreements contain customary covenants that, in the event of default, could result in the acceleration of principal and interest payments; restrictions on distributions related to capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to Dominion Energy.

Dominion Energy is required to pay annual commitment fees to maintain its joint revolving credit facility. In addition, the credit agreement contains various terms and conditions that could affect Dominion Energy’s ability to borrow under the facility. They include a maximum debt to total capital ratio, which is also included in Dominion Energy’s $1.0 billion 364-day revolving credit agreement, Dominion Energy’s Sustainability Revolving Credit Agreement and Dominion Energy’s 364-day term loan facility entered in February 2026, and cross-default provisions.

At December 31, 2025, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows:

Company		Maximum Allowed Ratio				Actual Ratio(1)
Dominion Energy			67.5	%			53.5	%

(1)Indebtedness as defined by the agreements excludes certain junior subordinated notes and securitization bonds reflected as long-term debt as well as AOCI reflected as equity in the Consolidated Balance Sheets. In addition, in April 2025, the calculation of equity utilized in the total debt to total capital ratio was updated for a technical clarification for the joint revolving credit facility and the Sustainability Revolving Credit Agreement.

If Dominion Energy or any of its material subsidiaries failed to make payment on various debt obligations in excess of $250 million, or $150 million for DESC, the lenders could require the defaulting company, if it is a borrower under Dominion Energy’s joint revolving credit facility, to accelerate its repayment of any outstanding borrowings and the lenders could terminate their commitments, if any, to lend funds to that company under the credit facility. In addition, if the defaulting company is Virginia Power, Dominion Energy’s obligations to repay any outstanding borrowing under the credit facility could also be accelerated and the lenders’ commitments to Dominion Energy could terminate.

Dominion Energy monitors compliance with these covenants on a regular basis in order to ensure that events of default will not occur. At December 31, 2025, there have been no events of default under Dominion Energy’s covenants.

Common Stock, Preferred Stock and Other Equity Securities

Issuances of Equity Securities

Dominion Energy maintains Dominion Energy Direct® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In August 2023, Dominion Energy began purchasing its common stock on the open market for these direct stock purchase plans, and in March 2024, began issuing new shares of common stock. During 2025, Dominion Energy issued 2.5 million of such shares and received proceeds of $139 million.

Dominion Energy also maintains sales agency agreements to effect sales under at-the-market programs. Under the sales agency agreements, Dominion Energy is able, from time to time, to offer and sell shares of its common stock through the sales agents or enter into one or more forward sale agreements with respect to shares of its common stock. See Note 20 to the Consolidated Financial Statements for additional information.

During the first quarter of 2025, Dominion Energy entered into forward sale agreements under its May 2024 at-the-market program for approximately 8.8 million shares of its common stock at a weighted-average initial forward price of $55.34 per share. Including the forward sale agreements entered into from September through December 2024, Dominion Energy has entered into forward sale agreements for approximately 18.5 million shares of its common stock at a weighted-average initial forward price of $56.62 per share. In December 2025, Dominion Energy provided

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

notice to elect physical settlement of these forward sale agreements and in December 2025 settled the agreements at a weighted-average final forward price of $55.26 per share and received total proceeds of $1.0 billion. During the third quarter of 2025, Dominion Energy entered into forward sale agreements for approximately 2.4 million shares of its common stock expected to be settled by the fourth quarter of 2027 at a weighted-average initial forward price of $59.91 per share.

In February 2025, Dominion Energy entered into a new at-the-market-program, and during the second quarter of 2025, Dominion Energy entered into forward sale agreements for approximately 11.0 million shares of its common stock expected to be settled in the fourth quarter of 2026 at a weighted-average initial forward price of $55.83 per share. During the third quarter of 2025, Dominion Energy entered into forward sale agreements for approximately 9.6 million shares of its common stock expected to be settled by the fourth quarter of 2027 at a weighted-average initial forward price of $61.11 per share. In December 2025, Dominion Energy provided notice to elect physical settlement of approximately 5.4 million shares under the forward sales agreements entered into during the third quarter of 2025 and in December 2025 settled the agreements at a weighted-average final forward price of $60.44 per share and received total proceeds of $325 million.

Dominion Energy expects to issue equity through programs such as Dominion Energy Direct® and employee savings plans of approximately $150 million in 2026. In addition, Dominion Energy expects to issue equity, excluding potential opportunistic offerings, through at-the-market programs of approximately $1.6 billion to $1.8 billion in 2026, inclusive of approximately $1.0 billion from the settlement of forward-sale agreements discussed above. The raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.

Repurchases and Redemptions of Equity Securities

In November 2020, the Board of Directors authorized the repurchase of up to $1.0 billion of Dominion Energy’s common stock. This repurchase program does not include a specific timetable or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors. At December 31, 2025, Dominion Energy had $920 million of available capacity under this authorization.

Dominion Energy does not plan to repurchase shares of common stock in 2026, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which does not impact the available capacity under its stock repurchase authorization.

Capital Expenditures

See Note 26 to the Consolidated Financial Statements for Dominion Energy’s historical capital expenditures by segment. In February 2026, Dominion Energy announced an updated $64.7 billion capital expenditure plan for 2026 through 2030, which includes the impact of Stonepeak’s 50% noncontrolling interest in the CVOW Commercial Project, representing significant investments in reliable, affordable and increasingly clean energy to advance an “all-of-the-above” strategy to address projected demand growth.

Dominion Energy’s total planned capital expenditures for each segment for the next five years are presented in the table below:

		2026				2027				2028				2029				2030				Total
(billions)
Dominion    Energy    Virginia(1)		$	9.6			$	9.2			$	10.6			$	13.7			$	12.7			$	55.8
Dominion    Energy South    Carolina			1.5				1.6				1.7				1.5				1.4				7.6
Contracted    Energy			0.4				0.4				0.3				0.3				0.3				1.7
Corporate and    Other segment			0.1				0.1				0.1				0.1				0.1				0.6
Total(2)		$	11.5			$	11.3			$	12.6			$	15.6			$	14.6			$	65.7

(1)Includes $1.3 billion in 2026, $0.3 billion in 2027, $0.1 billion in 2028, $0.2 billion in 2029 and $0.1 billion in 2030 for 100% of the CVOW Commercial Project.

(2)Totals may not foot due to rounding.

Dominion Energy’s planned growth expenditures are subject to approval by the Board of Directors as well as potentially by regulatory bodies based on the individual project and are expected to include significant investments in support of its “all-of-the-above” strategy. See Dominion Energy Virginia, Dominion Energy South Carolina and Contracted Energy in Item 1. Business for additional discussion of various significant capital projects currently under development. The above estimates are based on a capital expenditures plan reviewed and endorsed by Dominion Energy’s Board of Directors in early 2026 and are subject to continuing review and adjustment. Actual capital expenditures may vary from these estimates. Dominion Energy may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.

Dividends

Dominion Energy believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In December 2025, Dominion Energy’s Board of Directors established an annual dividend rate for 2026 of $2.67 per share of common stock, consistent with the 2025 rate. Dividends are subject to declaration by the Board of Directors. In January 2026, Dominion Energy’s Board of Directors declared dividends payable in March 2026 of 66.75 cents per share of common stock.

See Note 19 to the Consolidated Financial Statements for a discussion of Dominion Energy’s outstanding preferred stock and associated dividend rates.

Subsidiary Dividend Restrictions

Certain of Dominion Energy’s subsidiaries may, from time to time, be subject to certain restrictions imposed by regulators or financing arrangements on their ability to pay dividends, or to advance or repay funds, to Dominion Energy. At December 31, 2025, these restrictions did not have a significant impact on Dominion Energy’s ability to pay dividends on its common or preferred stock or meet its other cash obligations.

See Note 21 to the Consolidated Financial Statements for a description of such restrictions and any other restrictions on Dominion Energy’s ability to pay dividends.

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Collateral and Credit Risk

Collateral requirements are impacted by capital projects, commodity prices, hedging levels, Dominion Energy’s credit ratings and the credit quality of its counterparties. In connection with commodity hedging activities, Dominion Energy is required to provide collateral to counterparties under some circumstances. Under certain collateral arrangements, Dominion Energy may satisfy these requirements by electing to either deposit cash, post letters of credit or, in some cases, utilize other forms of security. From time to time, Dominion Energy may vary the form of collateral provided to counterparties after weighing the costs and benefits of various factors associated with the different forms of collateral. These factors include short-term borrowing and short-term investment rates, the spread over these short-term rates at which Dominion Energy can issue commercial paper, balance sheet impacts, the costs and fees of alternative collateral postings with these and other counterparties and overall liquidity management objectives.

Dominion Energy’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion Energy’s credit exposure at December 31, 2025 for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.

		Gross Credit Exposure				Credit Collateral				Net Credit Exposure
(millions)
Investment grade(1)		$	41			$	—			$	41
Non-investment grade(2)			1				—				1
No external ratings:
Internally rated—    investment grade(3)			175				10				165
Internally rated—non-    investment grade(4)			19				3				16
Total(5)		$	236			$	13			$	223

(1)Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 12% of the total net credit exposure.

(2)The five largest counterparty exposures, combined, for this category represented approximately 1% of the total net credit exposure.

(3)The five largest counterparty exposures, combined, for this category represented approximately 74% of the total net credit exposure.

(4)The five largest counterparty exposures, combined, for this category represented approximately 6% of the total net credit exposure.

(5)Excludes long-term purchase power agreements entered to satisfy legislative or state regulatory commission requirements.

Fuel and Other Purchase Commitments

Dominion Energy is party to various contracts for fuel and purchased power commitments related to both its regulated and nonregulated operations. Total estimated costs at December 31, 2025 for such commitments are presented in the table below. These costs represent estimated minimum obligations for various purchased power and capacity agreements and actual costs may differ from amounts presented below depending on actual quantities purchased and prices paid.

		2026				2027				2028				2029				2030				Total
(millions)
Purchased    electric    capacity    for utility    operations		$	85			$	86			$	85			$	84			$	85			$	425
Fuel    commitments    for utility    operations			1,305				675				539				418				492				3,429
Fuel    commitments    for    nonregulated    operations			118				146				55				109				94				522
Pipeline    transportation    and storage			394				342				333				287				284				1,640
Total		$	1,902			$	1,249			$	1,012			$	898			$	955			$	6,016

Other Material Cash Requirements

In addition to the financing arrangements discussed above, Dominion Energy is party to numerous contracts and arrangements obligating it to make cash payments in future years. Dominion Energy expects current liabilities to be paid within the next twelve months. In addition to the items already discussed, the following represent material expected cash requirements recorded on Dominion Energy’s Consolidated Balance Sheets at December 31, 2025. Such obligations include:

•Operating and finance lease obligations – See Note 15 to the Consolidated Financial Statements;

•Regulatory liabilities – See Note 12 to the Consolidated Financial Statements;

•AROs – See Note 14 to the Consolidated Financial Statements;

•Employee benefit plan obligations – See Note 22 to the Consolidated Financial Statements; and

•Data center customer deposits – See Note 2 to the Consolidated Financial Statements.

In addition, Dominion Energy is party to contracts and arrangements which may require it to make material cash payments in future years that are not recorded on its Consolidated Balance Sheets. Such obligations include:

•Guarantees – See Note 23 to the Consolidated Financial Statements.

Future Issues and Other Matters

See Item 1. Business and Notes 10, 13 and 23 to the Consolidated Financial Statements for additional information on various environmental, regulatory, legal and other matters that may impact Dominion Energy’s future results of operations, financial condition and/or cash flows.

Future Environmental Regulations

Climate Change

The federal government and states in which Dominion Energy operates have announced various commitments to achieving carbon reduction goals. In February 2021, the U.S. rejoined the Paris Agreement, which establishes a universal framework for addressing GHG emissions. In January 2026, the U.S. completed its withdrawal from the Paris Agreement. States may enact legislation relating to climate change matters such as the reduction of GHG

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

emissions and renewable energy portfolio standards, similar to the VCEA. To the extent legislation is enacted at the federal or state level that is more restrictive than the VCEA and/or Dominion Energy’s commitment to achieving net zero emissions by 2050, compliance with such legislation could have a material impact to Dominion Energy’s financial condition and/or cash flows.

Inflation Reduction Act

The IRA includes provisions which impose an annual fee for waste methane emissions from the oil and natural gas industry beginning with emissions reported in calendar year 2024 to the extent that an entity’s emissions exceed a stated threshold, with implementation to be addressed by future rulemaking by the EPA. Pending the completion of such rulemaking, Dominion Energy currently does not expect these provisions to materially affect its future results of operations, financial condition and/or cash flows.

Proposed and/or Recently Issued EPA Rules

In May 2024, the EPA released a final rule to tighten aspects of the Mercury and Air Toxics Standards Risk and Technology Review, including the reduction of emissions limits for filterable particulate matter, and requiring the use of continuous emissions monitoring systems to demonstrate compliance. In June 2025, the EPA released a proposed rule repealing the majority of the May 2024 final rule. Additionally in May 2024, the EPA finalized a package of rules designed to reduce CO2 emissions from certain fossil fuel-fired electric generating units. The final rule set standards of performance and emission guidelines for CO2 emissions from new and reconstructed gas-fired combustion turbines and modified coal-fired steam generating units. The rulemaking package also included emission guidelines, including emission limits, for existing coal, oil and gas-fired steam generating units. In June 2025, the EPA released a proposed rule repealing all greenhouse gas emissions standards from fossil fuel-fired power plants. As an alternative, the EPA simultaneously released a proposed rule eliminating the best system emission reduction determinations, presumptive standards of performance and all related requirements in the emission guidelines for existing steam generating units (including modified coal-fired steam generating units) as well as carbon sequestration requirements for new natural gas-fired, baseload combustion turbines. In addition, in March 2024, the EPA published a final rule strengthening the national air quality annual standard for fine particulate matter. Further, Dominion Energy anticipates that the EPA will release additional rulemakings as part of an overall strategy to identify and mitigate PFAS exposure, beyond the national drinking water standards for PFAS issued in April 2024. Until the EPA ultimately takes final action on the proposed rulemakings and publishes all final rules in the federal register, Dominion Energy is unable to predict whether or to what extent the new rules will ultimately require additional controls or other actions. The effects of these proposed rulemakings could have a material impact on Dominion Energy’s financial condition and cash flows.

Dodd-Frank Act

The CEA, as amended by Title VII of the Dodd-Frank Act, requires certain over-the counter derivatives, or swaps, to be cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk may elect the end-user exception to the CEA’s clearing requirements. Dominion Energy utilizes the end-user exception with respect to its swaps. If, as a result of changes to the rulemaking process, Dominion Energy can no longer utilize the end-user exception or otherwise becomes subject to mandatory clearing, exchange trading or margin requirements, it could be subject to higher costs due to decreased market liquidity or increased margin payments. In addition, Dominion Energy’s swap dealer counterparties may attempt to pass-through additional trading costs in connection with changes to the rulemaking process. Due to the evolving rulemaking process, Dominion Energy is currently unable to assess the potential impact of the Dodd-Frank Act’s derivative-related provisions on its financial condition, results of operations or cash flows.

North Anna

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. If Virginia Power decides to build a new unit, it would require a Combined Construction Permit and Operating License from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. In June 2017, the NRC issued the Combined Construction Permit and Operating License. Virginia Power has not yet committed to building a new nuclear unit at North Anna.

Future Federal Income Tax Guidance

The IRA, among other things, provides for investment and production tax credits for clean energy technologies until at least 2032, provides for transferability of certain tax credits and imposes a 15% alternative minimum tax on corporations with GAAP net income greater than $1 billion, as adjusted for certain items. Entities that are subject to the alternative minimum tax may use tax credits to reduce the liability by up to 75% and will receive a tax credit carryforward with an indefinite life that can be claimed against regular tax in future years. In 2025, the OBBBA modified many of the tax credits for renewable and clean energy technologies created under the IRA. Provisions include the termination of the production and investment tax credits for wind and solar for facilities placed in service after 2027 (except for certain facilities that commence construction by July 2026 and meet certain safe harbor requirements) and a phase out of other production and investment tax credits for certain clean energy facilities, including battery storage and small modular reactors, for projects beginning construction through 2035, after which the credits are fully phased out. The OBBBA restricts the availability of tax credits for certain prohibited foreign entities and projects receiving material assistance from certain foreign entities as well as the extension of the production tax credit for renewable natural gas sold through 2029. Dominion Energy has considered the IRA and the OBBBA in recording its provision for income taxes and continues to evaluate the provisions of these tax laws, the ultimate impact of which is subject to pending guidance and interpretations, the effects of which could be material to Dominion Energy’s results of operations, financial condition and/or cash flows; existing regulatory frameworks provide rate recovery mechanisms that could substantially mitigate such impacts for its regulated electric utilities.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs of Item 7. MD&A. The reader’s attention is directed to those paragraphs and Item 1A. Risk Factors for discussion of various risks and uncertainties that may impact the Companies.

Market Risk Sensitive Instruments and Risk Management

The Companies’ financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates, foreign currency exchange rates and equity securities prices as described below. Commodity price risk is present in the Companies’ electric operations and Dominion Energy’s natural gas procurement and marketing operations due to the exposure to market shifts in prices received and paid for electricity, natural gas and other commodities. The Companies use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to their outstanding debt and future issuances of debt. In addition, the Companies are exposed to investment price risk through various portfolios of equity and debt securities. The Companies’ exposure to foreign currency exchange rate risk is related to certain fixed price contracts associated with the CVOW Commercial Project which it manages through foreign currency exchange rate derivatives. The contracts include services denominated in currencies other than the U.S. dollar for approximately €2.6 billion and 5.1 billion kr. In addition, certain of the fixed price contracts, approximately €0.7 billion, contain commodity indexing provisions linked to steel.

The following sensitivity analyses estimate the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% change in commodity prices, interest rates or foreign currency exchange rates.

Commodity Price Risk

To manage price risk, the Companies hold commodity-based derivative instruments held for non-trading purposes associated with purchases and sales of electricity, natural gas and other energy-related products.

The derivatives used to manage commodity price risk are executed within established policies and procedures and may include instruments such as futures, forwards, swaps, options and FTRs that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the hypothetical change in market prices of commodity-based derivative instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Prices and volatility are principally determined based on observable market prices.

A hypothetical 10% decrease in commodity prices would have resulted in a decrease of $15 million and a hypothetical 10% increase in commodity prices would have resulted in a decrease of $18 million in the fair value of Dominion Energy’s commodity-based derivative instruments at December 31, 2025 and 2024, respectively.

A hypothetical 10% decrease in commodity prices would have resulted in a decrease of $71 million and $15 million in the fair value of Virginia Power’s commodity-based derivative instruments at December 31, 2025 and 2024, respectively.

The impact of a change in energy commodity prices on the Companies’ commodity-based derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net losses from commodity-based financial derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity.

Interest Rate Risk

The Companies manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. For variable rate debt outstanding for Dominion Energy, a hypothetical 10% increase in market interest rates would result in a $10 million and $12 million decrease in earnings at December 31, 2025 and 2024, respectively. For variable rate debt outstanding for Virginia Power, a hypothetical 10% increase in market interest rates would result in a $7 million decrease in earnings at both December 31, 2025 and 2024.

The Companies also use interest rate derivatives, including forward-starting swaps, interest rate swaps and interest rate lock agreements to manage interest rate risk. At December 31, 2025, Dominion Energy and Virginia Power had $10.7 billion and $8.1 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding in combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $459 million and $382 million, respectively, in the fair value of Dominion Energy and Virginia Power’s interest rate derivatives at December 31, 2025. At December 31, 2024, Dominion Energy and Virginia Power had $10.8 billion and $3.8 billion, respectively, of these interest rate derivatives outstanding in combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $157 million and $155 million, respectively, in the fair value of Dominion Energy and Virginia Power’s interest rate derivatives at December 31, 2024.

The impact of a change in interest rates on the Companies’ interest rate-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.

Foreign Currency Exchange Rate Risk

The Companies utilize foreign currency exchange rate swaps to economically hedge the foreign currency exchange risk associated with fixed price contracts related to the CVOW Commercial Project denominated in foreign currencies. At December 31, 2025 and 2024, Dominion Energy had €0.9 billion and €1.1 billion,

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

respectively, in aggregate notional amounts of these foreign currency forward purchase agreements outstanding. A hypothetical 10% increase in the U.S. dollar to Euro exchange rate would have resulted in a decrease of $35 million and $106 million in the fair value of Dominion Energy’s foreign currency swaps at December 31, 2025 and 2024, respectively.

The impact of a change in exchange rates on the Companies’ foreign currency-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net gains and/or losses from foreign exchange derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.

Investment Price Risk

The Companies are subject to investment price risk due to securities held as investments in nuclear decommissioning and rabbi trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in the Companies’ Consolidated Balance Sheets at fair value.

Dominion Energy recognized net investment gains (losses) (including investment income) on nuclear decommissioning and rabbi trust investments of $1.1 billion for both the years ended December 31, 2025 and 2024. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion Energy recorded, in AOCI and regulatory liabilities, a net increase in unrealized (losses) gains on debt investments of $41 million and $(28) million for the years ended December 31, 2025 and 2024, respectively.

Virginia Power recognized net investment gains (losses) (including investment income) on nuclear decommissioning and rabbi trust investments of $555 million and $580 million for the years ended December 31, 2025 and 2024, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains (losses) on debt investments of $23 million and $(10) million for the years ended December 31, 2025 and 2024, respectively.

Dominion Energy sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power employees participate in these plans. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns of $1.2 billion and $738 million in 2025 and 2024, respectively, compared to expected returns of $835 million and $982 million, respectively. Differences between actual and expected returns on plan assets are immediately recognized in earnings annually in the fourth quarter of each fiscal year as well as whenever a plan is determined to qualify for a remeasurement. A hypothetical 0.25% decrease in the expected long-term rate of return on plan assets would have had a $28 million and $31 million impact in the years ending December 31, 2025 and 2024, respectively, to the expected returns on plan assets.

Risk Management Policies

The Companies have established operating procedures with corporate management to ensure that proper internal controls are maintained. In addition, Dominion Energy has established an independent function at the corporate level to monitor compliance with the credit and commodity risk management policies of all subsidiaries, including Virginia Power. Dominion Energy maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion Energy also monitors the financial condition of existing counterparties on an ongoing basis. Based on these credit policies and the Companies’ December 31, 2025 provision for credit losses, management believes that it is unlikely that a material adverse effect on the Companies’ financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

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Item 8. Financial Statements and Supplementary Data

	Page Number
Dominion Energy, Inc.
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)	66
Consolidated Statements of Income for the years ended December 31, 2025, 2024 and 2023	68
Consolidated Statements of Comprehensive Income for the years ended December 31, 2025, 2024 and 2023	69
Consolidated Balance Sheets at December 31, 2025 and 2024	70
Consolidated Statements of Equity at December 31, 2025, 2024 and 2023 and for the years then ended	72
Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023	73
Virginia Electric and Power Company
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)	74
Consolidated Statements of Income for the years ended December 31, 2025, 2024 and 2023	76
Consolidated Statements of Comprehensive Income for the years ended December 31, 2025, 2024 and 2023	77
Consolidated Balance Sheets at December 31, 2025 and 2024	78
Consolidated Statements of Equity at December 31, 2025, 2024 and 2023 and for the years then ended	80
Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023	81
Combined Notes to Consolidated Financial Statements	82

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Dominion Energy, Inc.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Dominion Energy, Inc. and subsidiaries ("Dominion Energy") at December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Dominion Energy at December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), Dominion Energy’s internal control over financial reporting at December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2026, expressed an unqualified opinion on Dominion Energy’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of Dominion Energy’s management. Our responsibility is to express an opinion on Dominion Energy’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Dominion Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated 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 consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the consolidated 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 consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Assets and Liabilities - Impact of Rate Regulation on the Consolidated Financial Statements — Refer to Notes 2, 12 and 13 to the Consolidated Financial Statements

Critical Audit Matter Description

Dominion Energy, through its regulated electric and gas subsidiaries, is subject to rate regulation by certain state public utility commissions and the Federal Energy Regulatory Commission (“FERC”) (collectively, the “relevant commissions”) which have jurisdiction with respect to the rates of electric and gas utility companies. Management has determined its rate-regulated subsidiaries meet the requirements under accounting principles generally accepted in the United States of America to apply the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment, net; regulatory assets; regulatory liabilities; operating revenues; electric fuel and other energy-related purchases; purchased electric capacity; purchased gas; other operations and maintenance expense; depreciation and amortization expense; and impairment of assets and other charges, collectively, the “financial statement impacts of rate regulation.”

Revenue provided by Dominion Energy’s electric transmission, distribution and generation operations and its gas distribution operations is primarily based on rates approved by the relevant commissions. Further, Virginia Electric and Power Company’s (“Virginia Power”) retail base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia State Corporation Commission (the “Virginia Commission”) in a proceeding that involves the determination of Virginia Power’s actual earned return on equity (“ROE”) during a historic test period, and determination of Virginia Power’s authorized ROE prospectively. Under certain circumstances, Virginia Power may be required to credit a portion of its earnings to customers.

When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds or other benefits through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. In addition, a loss is recognized if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Dominion Energy evaluates whether recovery of its regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makes various assumptions in its analyses. These analyses are generally based on orders issued by regulatory commissions, legislation and judicial actions; past experience; discussions with applicable regulatory authorities and legal counsel; estimated construction costs; forecasted earnings; and considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events and other natural disasters, and unplanned outages of facilities.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to

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support its assertions about the financial statement impacts of rate regulation. Management judgments include assessing the likelihood of (1) recovery of its regulatory assets through future rates and (2) whether a regulatory liability is due to customers. Given management’s accounting judgments are based on assumptions about the outcome of future decisions by the relevant commissions, auditing these judgments required specialized knowledge of the 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 assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) recovery of regulatory assets through future rates, and (2) whether a regulatory liability is due to customers. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities; and the monitoring and evaluation of regulatory and legislative developments that may impact the assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable.

•We evaluated Dominion Energy’s disclosures related to the financial statement impacts of rate regulation.

•We read and evaluated orders issued by the relevant commissions, as well as relevant regulatory statutes, interpretations, procedural memorandums, existing laws and other publicly available information to assess whether this external information was properly considered by management in concluding upon the financial statement impacts of rate regulation.

•We considered the likelihood of (1) recovery of regulatory assets through future rates and (2) whether a regulatory liability is due to customers based on precedents established by the relevant commissions’ previous orders and Dominion Energy’s past experience with the relevant commissions, which included testing Dominion Energy’s recorded charges for costs not expected to be recovered from customers on the CVOW Commercial Project.

•For regulatory matters in process, we inspected associated documents and testimony filed with the relevant commissions for any evidence that might contradict management’s assertions.

•We read and analyzed the minutes of the Boards of Directors of Dominion Energy and Dominion Energy’s rate-regulated subsidiaries for discussions of changes in legal, regulatory, or business factors which could impact management’s conclusions with respect to the financial statement impacts of rate regulation.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 23, 2026

We have served as Dominion Energy’s auditor since 1988.

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Dominion Energy, Inc.

Consolidated Statements of Income

Year Ended December 31,		2025				2024				2023
(millions, except per share amounts)
Operating Revenue		$	16,506			$	14,459			$	14,393
Operating Expenses
Electric fuel and other energy-related purchases			4,489				3,614				3,935
Purchased electric capacity			82				74				55
Purchased gas			297				260				285
Other operations and maintenance			3,547				3,588				3,133
Depreciation and amortization			2,387				2,345				2,580
Other taxes			773				731				684
Impairment of assets and other charges			517				600				307
Total operating expenses			12,092				11,212				10,979
Income from operations			4,414				3,247				3,414
Other income (expense)			1,219				841				996
Interest and related charges			2,022				1,893				1,679
Income from continuing operations including noncontrolling interests before income tax expense			3,611				2,195				2,731
Income tax expense			532				411				644
Net Income From Continuing Operations Including Noncontrolling Interests			3,079				1,784				2,087
Net Income (Loss) From Discontinued Operations Including Noncontrolling Interests(1)			(14	)			197				(125	)
Net Income Including Noncontrolling Interests			3,065				1,981				1,962
Noncontrolling Interests			67				(53	)			—
Net Income Attributable to Dominion Energy		$	2,998			$	2,034			$	1,962
Amounts Attributable to Dominion Energy
Net income from continuing operations		$	3,012			$	1,837			$	2,087
Net income (loss) from discontinued operations			(14	)			197				(125	)
Net income attributable to Dominion Energy		$	2,998			$	2,034			$	1,962
EPS - Basic
Net income from continuing operations		$	3.48			$	2.09			$	2.40
Net income (loss) from discontinued operations			(0.02	)			0.24				(0.15	)
Net income attributable to Dominion Energy		$	3.46			$	2.33			$	2.25
EPS - Diluted
Net income from continuing operations		$	3.47			$	2.09			$	2.40
Net income (loss) from discontinued operations			(0.02	)			0.24				(0.15	)
Net income attributable to Dominion Energy		$	3.45			$	2.33			$	2.25

(1)Includes income tax expense of $5 million, $31 million and $1.3 billion for the years ended December 31, 2025, 2024 and 2023, respectively.

The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.

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Dominion Energy, Inc.

Consolidated Statements of Comprehensive Income

Year Ended December 31,		2025				2024				2023
(millions)
Net income including noncontrolling interests		$	3,065			$	1,981			$	1,962
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of $(2), $(4) and $1 tax			5				13				—
Changes in unrealized net gains (losses) on investment securities, net of $(11), $13 and $(27) tax			15				(19	)			47
Changes in net unrecognized pension and other postretirement benefit costs (credits), net of $—,    $1 and $— tax			—				(2	)			—
Amounts reclassified to net income (loss):
Net derivative (gains) losses-hedging activities, net of $(10), $(11) and $(10) tax			29				32				33
Net realized (gains) losses on investment securities, net of $2, $(3) and $3 tax			(5	)			8				(11	)
Net pension and other postretirement benefit costs (credits), net of $2, $4 and $5 tax			(10	)			(12	)			(13	)
Net earnings from equity method investees, net of $—, $— and $(1) tax			—				—				3
Total other comprehensive income (loss)			34				20				59
Comprehensive income including noncontrolling interests			3,099				2,001				2,021
Comprehensive income (loss) attributable to noncontrolling interests			67				(53	)			—
Comprehensive income attributable to Dominion Energy		$	3,032			$	2,054			$	2,021

The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.

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Dominion Energy, Inc.

Consolidated Balance Sheets

At December 31,		2025				2024
(millions)
ASSETS
Current Assets
Cash and cash equivalents(1)		$	250			$	310
Customer receivables (less allowance for doubtful accounts of $31 and $30)(1)			2,531				2,169
Tax receivables			434				—
Other receivables (less allowance for doubtful accounts of $3 and $2)(2)			446				358
Inventories:
Materials and supplies			1,541				1,360
Fossil fuel			392				382
Gas stored			24				22
Derivative assets			335				436
Margin deposit assets			181				104
Prepayments(1)			377				315
Regulatory assets(1)			1,380				992
Other(1)			180				165
Total current assets			8,071				6,613
Investments
Nuclear decommissioning trust funds			9,166				8,051
Investment in equity method affiliates			132				138
Other			378				361
Total investments			9,676				8,550
Property, Plant and Equipment
Property, plant and equipment(1)			106,315				94,844
Accumulated depreciation and amortization			(27,348	)			(25,982	)
Total property, plant and equipment, net			78,967				68,862
Deferred Charges and Other Assets
Goodwill			4,143				4,143
Pension and other postretirement benefit assets			2,658				2,240
Intangible assets, net			1,682				1,136
Derivative assets			623				963
Regulatory assets(1)			8,276				8,288
Other(1)			1,761				1,620
Total deferred charges and other assets			19,143				18,390
Total assets		$	115,857			$	102,415

(1)See Note 16 for amounts attributable to VIEs.

(2)See Note 9 for amounts attributable to related parties.

The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.

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At December 31,		2025				2024
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year(1)		$	2,409			$	1,725
Supplemental credit facility borrowings			—				—
Short-term debt			2,457				2,500
Accounts payable			1,338				1,149
Accrued interest, payroll and taxes(1)			1,244				1,045
Derivative liabilities			111				207
Regulatory liabilities			542				579
Other(2)			2,343				2,084
Total current liabilities			10,444				9,289
Long-Term Debt
Long-term debt			36,778				33,034
Securitization bonds(1)			883				1,054
Junior subordinated notes			5,978				3,223
Supplemental credit facility borrowings			—				—
Other			436				214
Total long-term debt			44,075				37,525
Deferred Credits and Other Liabilities
Deferred income taxes			7,885				7,135
Deferred investment tax credits			1,591				1,070
Regulatory liabilities			9,072				8,761
Asset retirement obligations(1)			7,204				7,074
Derivative liabilities			134				305
Other			2,035				1,454
Total deferred credits and other liabilities			27,921				25,799
Total liabilities			82,440				72,613
Commitments and Contingencies (see Note 23)
Equity
Preferred stock (See Note 19)			991				991
Common stock – no par(3)			25,892				24,383
Retained earnings			2,318				1,641
Accumulated other comprehensive loss			(118	)			(152	)
Shareholders’ equity			29,083				26,863
Noncontrolling interests			4,334				2,939
Total equity			33,417				29,802
Total liabilities and equity		$	115,857			$	102,415

(1)See Note 16 for amounts attributable to VIEs.

(2)See Note 9 for amounts attributable to related parties.

(3)1.8 billion shares authorized; 879 million shares and 852 million shares outstanding at December 31, 2025 and 2024, respectively.

The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.

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Dominion Energy, Inc.

Consolidated Statements of Equity

	Preferred Stock						Common Stock
	Shares			Amount			Shares			Amount			Retained Earnings			AOCI			Shareholders’ Equity			Noncontrolling Interests			Total Equity
(millions except per share amounts)
December 31, 2022		2		$	1,783			835		$	23,605		$	2,276		$	(231	)	$	27,433		$	—		$	27,433
Net income including noncontrolling    interests														1,962						1,962						1,962
Issuance of stock								2			94									94						94
Stock awards (net of change in   unearned compensation)								1			30									30						30
Preferred stock dividends (See    Note 19)														(81	)					(81	)					(81	)
Common dividends ($2.67 per common    share)														(2,233	)					(2,233	)					(2,233	)
Other comprehensive income, net of tax																	59			59						59
Other											(1	)		1						—						—
December 31, 2023		2		$	1,783			838		$	23,728		$	1,925		$	(172	)	$	27,264		$	—		$	27,264
Net income including noncontrolling    interests														2,034						2,034			(53	)		1,981
Issuance of stock								14			732									732						732
Sale of noncontrolling interest in OSWP											(107	)								(107	)		2,615			2,508
Contributions from Stonepeak to OSWP																							377			377
Stock awards (net of change in    unearned compensation)								—			30									30						30
Repurchase and redemption of    preferred stock		(1	)		(791	)														(791	)					(791	)
Preferred stock dividends (See    Note 19)														(78	)					(78	)					(78	)
Common dividends ($2.67 per common    share)														(2,239	)					(2,239	)					(2,239	)
Other comprehensive income, net of tax																	20			20						20
Other					(1	)								(1	)					(2	)					(2	)
December 31, 2024		1		$	991			852		$	24,383		$	1,641		$	(152	)	$	26,863		$	2,939		$	29,802
Net income including noncontrolling    interests														2,998						2,998			67			3,065
Issuance of stock								27			1,488									1,488						1,488
Sale of noncontrolling interest in OSWP											(7	)								(7	)					(7	)
Contributions from Stonepeak to OSWP																							1,569			1,569
Distributions from OSWP to Stonepeak																							(241	)		(241	)
Stock awards (net of change in    unearned compensation)								—			28									28						28
Preferred stock dividends (See    Note 19)														(44	)					(44	)					(44	)
Common dividends ($2.67 per    common share)														(2,278	)					(2,278	)					(2,278	)
Other comprehensive income, net of tax																	34			34						34
Other														1						1						1
December 31, 2025		1		$	991			879		$	25,892		$	2,318		$	(118	)	$	29,083		$	4,334		$	33,417

The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.

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Dominion Energy, Inc.

Consolidated Statements of Cash Flows

Year Ended December 31,		2025				2024				2023
(millions)
Operating Activities
Net income including noncontrolling interests		$	3,065			$	1,981			$	1,962
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation, depletion and amortization (including nuclear fuel)			2,684				2,639				3,128
Deferred income taxes			568				(235	)			1,527
Deferred investment tax credits (benefits)			488				(32	)			(37	)
Impairment of assets and other charges			516				639				695
Losses (gains) on the East Ohio, Questar Gas and PSNC Transactions			—				130				—
Losses (gains) on sales of assets and equity method investments (including Cove Point)			—				—				(657	)
Net (gains) losses on nuclear decommissioning trusts funds and other investments			(546	)			(669	)			(474	)
Other adjustments			(43	)			18				378
Changes in:
Accounts receivable			(862	)			208				147
Inventories			(187	)			(87	)			(198	)
Deferred fuel and purchased gas costs, net			(754	)			727				975
Prepayments and deposits, net			(184	)			(108	)			516
Accounts payable			66				76				(506	)
Accrued interest, payroll and taxes			224				(85	)			175
Net realized and unrealized changes related to derivative activities			730				236				(35	)
Pension and other postretirement benefits			(433	)			(208	)			(476	)
Other operating assets and liabilities			29				(212	)			(548	)
Net cash provided by operating activities			5,361				5,018				6,572
Investing Activities
Plant construction and other property additions (including nuclear fuel)			(12,641	)			(12,198	)			(10,211	)
Acquisition of solar development projects			(12	)			(229	)			(24	)
Proceeds from sale of noncontrolling interest in Cove Point			—				—				3,293
Proceeds from East Ohio, Questar Gas and PSNC Transactions			2				9,243				—
Proceeds from sales of securities			10,492				3,072				2,966
Purchases of securities			(10,591	)			(3,213	)			(3,152	)
Proceeds from sales of assets			—				35				47
Contributions to equity method affiliates			(24	)			(20	)			(104	)
Distributions from equity method affiliates			—				126				1
Other			(195	)			1				(23	)
Net cash used in investing activities			(12,969	)			(3,183	)			(7,207	)
Financing Activities
Issuance (repayment) of short-term debt, net			(43	)			(1,456	)			533
364-day term loan facility borrowings			—				3,000				5,725
Repayment of 364-day term loan facility borrowings			—				(7,750	)			(975	)
Issuance and remarketing of long-term debt			8,897				5,993				3,310
Repayment and repurchase of long-term debt			(1,722	)			(2,740	)			(5,673	)
Issuance of securitization bonds			—				1,282				—
Repayment of securitization bonds			(163	)			(65	)			—
Supplemental credit facility borrowings			—				—				900
Supplemental credit facility repayments			—				(450	)			(900	)
Proceeds from sale of noncontrolling interest in OSWP			(88	)			2,558				—
Contributions from Stonepeak to OSWP			1,569				377				—
Distributions from OSWP to Stonepeak			(241	)			—				—
Series B Preferred Stock repurchase and redemption			—				(801	)			—
Issuance of common stock			1,488				732				94
Common dividend payments			(2,278	)			(2,239	)			(2,233	)
Other			167				(212	)			(186	)
Net cash provided by (used in) financing activities			7,586				(1,771	)			595
Increase (decrease) in cash, restricted cash and equivalents			(22	)			64				(40	)
Cash, restricted cash and equivalents at beginning of period			365				301				341
Cash, restricted cash and equivalents at end of period		$	343			$	365			$	301

See Note 2 for disclosure of supplemental cash flow information.

The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.

73

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of Virginia Electric and Power Company

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Energy, Inc.) and subsidiaries ("Virginia Power") at December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Virginia Power at December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of Virginia Power’s management. Our responsibility is to express an opinion on Virginia Power’s consolidated 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 Virginia Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Virginia Power 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 Virginia Power’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 consolidated 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 consolidated 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 consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the consolidated 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 consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Assets and Liabilities - Impact of Rate Regulation on the Consolidated Financial Statements — Refer to Notes 2, 12 and 13 to the Consolidated Financial Statements

Critical Audit Matter Description

Virginia Power is subject to utility rate regulation by certain state public utility commissions and the Federal Energy Regulatory Commission (“FERC”) (collectively, the “relevant commissions”), which have jurisdiction with respect to the rates of electric utility companies in the territories Virginia Power serves. Management has determined Virginia Power meets the requirements under accounting principles generally accepted in the United States of America to apply the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures such as property, plant, and equipment, net; regulatory assets; regulatory liabilities; operating revenues; electric fuel and other energy-related purchases; purchased electric capacity; other operations and maintenance expense; depreciation and amortization expense; and impairment of assets and other charges (benefits), collectively, the “financial statement impacts of rate regulation”.

Revenue provided by Virginia Power’s electric transmission, distribution and generation operations is primarily based on rates approved by the relevant commissions. Further, Virginia Power’s retail base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia State Corporation Commission (the “Virginia Commission”) in a proceeding that involves the determination of Virginia Power’s actual earned return on equity (“ROE”) during a historic test period and determination of Virginia Power’s authorized ROE prospectively. Under certain circumstances, Virginia Power may be required to credit a portion of its earnings to customers.

When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds or other benefits through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. In addition, a loss is recognized if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Virginia Power evaluates whether recovery of its regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makes various assumptions in its analyses. These analyses are generally based on orders issued by regulatory commissions, legislation and judicial actions; past experience; discussions with applicable regulatory authorities and legal counsel; estimated construction costs; forecasted earnings; and considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events, and other natural disasters, and unplanned outages of facilities.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about the financial statement impacts of rate regulation. Management judgments include assessing the likelihood

74

of (1) recovery of its regulatory assets through future rates and (2) whether a regulatory liability is due to customers. Given management’s accounting judgments are based on assumptions about the outcome of future decisions by the relevant commissions, auditing these judgments required specialized knowledge of the 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 assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) recovery of regulatory assets through future rates, and (2) whether a regulatory liability is due to customers. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities; and the monitoring and evaluation of regulatory and legislative developments that may impact the assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable.

•We evaluated Virginia Power’s disclosures related to the financial statement impacts of rate regulation.

•We read and evaluated orders issued by the relevant commissions, as well as relevant regulatory statutes, interpretations, procedural memorandums, existing laws and other publicly available information to assess whether this external information was properly considered by management in concluding upon the financial statement impacts of rate regulation.

•We considered the likelihood of (1) recovery of regulatory assets through future rates and (2) whether a regulatory liability is due to customers based on precedents established by the relevant commissions’ previous orders and Virginia Power’s past experience with relevant commissions, which included testing Virginia Power’s recorded charges for costs not expected to be recovered from customers on the CVOW Commercial Project.

•For regulatory matters in process, we inspected associated documents and testimony filed with the relevant commissions for any evidence that might contradict management’s assertions.

•We read and analyzed the minutes of the Board of Directors of Dominion Energy, Inc. and the Board of Directors of Virginia Power, for discussions of changes in legal, regulatory, or business factors which could impact management’s conclusions with respect to the financial statement impacts of rate regulation.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 23, 2026

We have served as Virginia Power’s auditor since 1988.

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Virginia Electric and Power Company

Consolidated Statements of Income

Year Ended December 31,		2025				2024				2023
(millions)
Operating Revenue(1)		$	11,812			$	10,235			$	9,573
Operating Expenses
Electric fuel and other energy-related purchases(1)			3,591				2,743				2,918
Purchased electric capacity			71				68				46
Other operations and maintenance:
Affiliated suppliers			518				433				395
Other			1,812				1,804				1,456
Depreciation and amortization			1,630				1,644				1,871
Other taxes			362				333				298
Impairment of assets and other charges			516				292				115
Total operating expenses			8,500				7,317				7,099
Income from operations			3,312				2,918				2,474
Other income (expense)			255				198				133
Interest and related charges(1)			951				849				765
Income before income tax expense			2,616				2,267				1,842
Income tax expense			448				423				400
Net Income Including Noncontrolling Interests		$	2,168			$	1,844			$	1,442
Noncontrolling Interests			67				(53	)			—
Net Income Attributable to Virginia Power		$	2,101			$	1,897			$	1,442

(1)See Note 25 for amounts attributable to affiliates.

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

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Virginia Electric and Power Company

Consolidated Statements of Comprehensive Income

Year Ended December 31,		2025				2024				2023
(millions)
Net income including noncontrolling interests		$	2,168			$	1,844			$	1,442
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of $(1), $(4) and $— tax			5				13				(1	)
Changes in unrealized net gains (losses) on investment securities, net of $—, $2 and $(4) tax			—				(5	)			6
Amounts reclassified to net income (loss):
Net derivative (gains) losses-hedging activities, net of $—, $— and $(1) tax			(1	)			—				—
Net realized (gains) losses on investment securities, net of $(1), $(1) and $— tax			—				3				1
Total other comprehensive income (loss)			4				11				6
Comprehensive income including noncontrolling interests		$	2,172			$	1,855			$	1,448
Comprehensive income (loss) attributable to noncontrolling interests			67				(53	)			—
Comprehensive income attributable to Virginia Power		$	2,105			$	1,908			$	1,448

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

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Virginia Electric and Power Company

Consolidated Balance Sheets

At December 31,		2025				2024
(millions)
ASSETS
Current Assets
Cash and cash equivalents(1)		$	170			$	160
Customer receivables (less allowance for doubtful accounts of $25 and $23)(1)			1,930				1,612
Other receivables (less allowance for doubtful accounts of $3 and $2)			252				168
Affiliated receivables			35				27
Inventories (average cost method)
Materials and supplies			977				849
Fossil fuel			273				299
Derivative assets(2)			212				248
Prepayments(1)			63				64
Regulatory assets(1)			1,110				697
Other(1)			103				130
Total current assets			5,125				4,254
Investments
Nuclear decommissioning trust funds			4,864				4,286
Other			4				4
Total investments			4,868				4,290
Property, Plant and Equipment
Property, plant and equipment(1)			80,121				70,550
Accumulated depreciation and amortization			(19,157	)			(18,033	)
Total property, plant and equipment, net			60,964				52,517
Deferred Charges and Other Assets
Pension and other postretirement benefit assets(2)			729				663
Intangible assets, net			1,310				818
Derivative assets(2)			270				127
Regulatory assets(1)			4,526				4,537
Other(1)(2)			1,451				1,181
Total deferred charges and other assets			8,286				7,326
Total assets		$	79,243			$	68,387

(1)See Note 16 for amounts attributable to VIEs.

(2)See Note 25 for amounts attributable to affiliates.

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

78

At December 31,		2025				2024
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year(1)		$	1,366			$	548
Short-term debt			675				950
Accounts payable(1)			821				660
Payables to affiliates			216				133
Accrued dividend(2)			—				407
Affiliated current borrowings			1,173				500
Accrued interest, payroll and taxes(1)			450				366
Asset retirement obligations			372				321
Regulatory liabilities			374				385
Derivative liabilities (2)			22				139
Other(1)(2)			1,506				1,228
Total current liabilities			6,975				5,637
Long-Term Debt
Long-term debt			20,651				18,874
Securitization bonds(1)			883				1,054
Other			194				110
Total long-term debt			21,728				20,038
Deferred Credits and Other Liabilities
Deferred income taxes			4,921				4,476
Deferred investment tax credits			616				640
Asset retirement obligations(1)			5,108				5,076
Regulatory liabilities			6,530				6,139
Derivative liabilities(2)			9				86
Other(1)(2)			1,817				1,199
Total deferred credits and other liabilities			19,001				17,616
Total liabilities			47,704				43,291
Commitments and Contingencies (see Note 23)
Equity
Common stock – no par(3)			12,487				8,987
Other paid-in capital			999				1,006
Retained earnings			13,687				12,136
Accumulated other comprehensive income			32				28
Shareholder’s equity			27,205				22,157
Noncontrolling interests			4,334				2,939
Total equity			31,539				25,096
Total liabilities and equity		$	79,243			$	68,387

(1)See Note 16 for amounts attributable to VIEs.

(2)See Note 25 for amounts attributable to affiliates.

(3)500,000 shares authorized; 373,881 and 324,245 shares outstanding at December 31, 2025 and 2024, respectively.

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

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Virginia Electric and Power Company

Consolidated Statements of Equity

		Common Stock
		Shares				Amount				Other Paid-In Capital				Retained Earnings				AOCI				Shareholder's Equity				Noncontrolling Interests				Total Equity
(millions, except for shares)		(thousands)
December 31, 2022			275			$	5,738			$	1,113			$	10,054			$	11			$	16,916			$	—			$	16,916
Net income															1,442								1,442								1,442
Issuance of stock to Dominion     Energy			49				3,250																3,250								3,250
Other comprehensive income,     net of tax																			6				6								6
Other							(1	)															(1	)							(1	)
December 31, 2023			324				8,987				1,113				11,496				17				21,613				—				21,613
Net income including     noncontrolling interests															1,897								1,897				(53	)			1,844
Sale of noncontrolling interest     in OSWP											(107	)											(107	)			2,615				2,508
Contributions from Stonepeak     to OSWP																											377				377
Dividends															(1,257	)							(1,257	)							(1,257	)
Other comprehensive income,     net of tax																			11				11								11
December 31, 2024			324				8,987				1,006				12,136				28				22,157				2,939				25,096
Net income including     noncontrolling interests															2,101								2,101				67				2,168
Issuance of stock to Dominion     Energy			50				3,500																3,500								3,500
Sale of noncontrolling interest     in OSWP											(7	)											(7	)			—				(7	)
Contributions from Stonepeak     to OSWP																											1,569				1,569
Distributions from OSWP to     Stonepeak																											(241	)			(241	)
Dividends															(550	)							(550	)							(550	)
Other comprehensive income,     net of tax																			4				4								4
December 31, 2025			374			$	12,487			$	999			$	13,687			$	32			$	27,205			$	4,334			$	31,539

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

80

Virginia Electric and Power Company

Consolidated Statements of Cash Flows

Year Ended December 31,		2025				2024				2023
(millions)
Operating Activities
Net income including noncontrolling interests		$	2,168			$	1,844			$	1,442
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating     activities:
Depreciation and amortization (including nuclear fuel)			1,787				1,802				2,034
Deferred income taxes			270				381				502
Deferred investment tax credits (benefits)			(24	)			(20	)			(5	)
Impairment of assets and other charges			516				292				130
Net (gains) losses on nuclear decommissioning trust funds and other investments			(81	)			(97	)			(68	)
Other adjustments			(93	)			(44	)			237
Changes in:
Accounts receivable			(367	)			51				1
Affiliated receivables and payables			75				46				(188	)
Inventories			(102	)			(65	)			(165	)
Prepayments and deposits, net			(55	)			34				289
Deferred fuel expenses, net			(744	)			304				538
Accounts payable			57				(21	)			(43	)
Accrued interest, payroll and taxes			84				73				23
Net realized and unrealized changes related to derivative activities			108				153				451
Other operating assets and liabilities			257				(147	)			(363	)
Net cash provided by operating activities			3,856				4,586				4,815
Investing Activities
Plant construction and other property additions			(10,333	)			(9,760	)			(6,978	)
Purchases of nuclear fuel			(199	)			(168	)			(194	)
Acquisition of solar development projects			(12	)			(40	)			(24	)
Proceeds from sales of securities			5,741				1,925				1,876
Purchases of securities			(5,808	)			(2,011	)			(1,987	)
Other			(100	)			8				19
Net cash used in investing activities			(10,711	)			(10,046	)			(7,288	)
Financing Activities
Issuance (repayment) of short-term debt, net			(275	)			495				(486	)
Issuance (repayment) of affiliated current borrowings, net			673				—				(1,524	)
Issuance and remarketing of long-term debt			3,172				2,443				2,660
Repayment and repurchase of long-term debt			(572	)			(593	)			(1,308	)
Issuance of common stock			3,500				—				3,250
Issuance of securitization bonds			—				1,282				—
Repayment of securitization bonds			(163	)			(65	)			—
Proceeds from sale of noncontrolling interest in OSWP			(88	)			2,558				—
Contributions from Stonepeak to OSWP			1,569				377				—
Distributions from OSWP to Stonepeak			(241	)			—				—
Common dividend payments to parent			(957	)			(850	)			—
Other			262				(71	)			(53	)
Net cash provided by financing activities			6,880				5,576				2,539
Increase in cash, restricted cash and equivalents			25				116				66
Cash, restricted cash and equivalents at beginning of year			206				90				24
Cash, restricted cash and equivalents at end of year		$	231			$	206			$	90

See Note 2 for disclosure of supplemental cash flow information.

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

81

Combined Notes to Consolidated Financial Statements

Note 1. Nature of Operations

Dominion Energy, headquartered in Richmond, Virginia, provides primarily regulated electricity service in Virginia, North Carolina and South Carolina through its subsidiaries, Virginia Power and DESC, and is one of the nation's leading developers and operators of regulated offshore wind and solar power and the largest producer of carbon-free electricity in New England. Dominion Energy also has nonregulated operations that include long-term contracted electric generation operations.

In connection with the comprehensive business review concluded in March 2024, Dominion Energy sold all of its regulated gas distribution operations, except for DESC’s, to Enbridge through the East Ohio Transaction (completed in March 2024), the Questar Gas Transaction (completed in May 2024) and the PSNC Transaction (completed in September 2024). In addition in September 2023, Dominion Energy completed the sale of its remaining 50% noncontrolling partnership interest in Cove Point to BHE. As discussed in Notes 3 and 9, these operations as well as certain solar generation facility development operations are reflected as discontinued operations in Dominion Energy's Consolidated Financial Statements.

Dominion Energy manages its daily operations through three primary operating segments: Dominion Energy Virginia, Dominion Energy South Carolina and Contracted Energy. Dominion Energy also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) as well as its noncontrolling interest in Dominion Privatization. In addition, Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the operating segments’ performance or in allocating resources including the net impact of the operations reflected as discontinued operations, which in addition to the operations discussed above includes Dominion Energy’s noncontrolling interest in Atlantic Coast Pipeline. See Notes 3 and 9 for additional information.

Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into PJM. All of Virginia Power’s stock is owned by Dominion Energy.

Virginia Power manages its daily operations through one primary operating segment: Dominion Energy Virginia. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources.

See Note 26 for further discussion of the Companies’ operating segments.

Note 2. Significant Accounting Policies

General

The Companies make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues, expenses and cash flows for the periods presented. Actual results may differ from those estimates.

The Companies’ Consolidated Financial Statements include, after eliminating intercompany transactions and balances, their accounts, those of their respective majority-owned subsidiaries and non-wholly-owned entities in which they have a controlling financial interest. For certain partnership structures, income is allocated based on the liquidation value of the underlying contractual arrangements. Stonepeak’s 50% ownership interest in OSWP is reflected as noncontrolling interest in the Companies’ Consolidated Financial Statements.

The Companies report certain contracts, instruments and investments at fair value. See below and Note 6 for further information on fair value measurements.

The Companies consider acquisitions or dispositions in which substantially all of the fair value of the gross assets acquired or disposed of is concentrated into a single identifiable asset or group of similar identifiable assets to be an acquisition or a disposition of an asset, rather than a business. See Notes 3 and 10 for further information on such transactions.

Dominion Energy maintains pension and other postretirement benefit plans and Virginia Power participates in certain of these plans. See Note 22 for further information on these plans.

Certain amounts in the Companies’ 2024 and 2023 Consolidated Financial Statements have been reclassified to conform to the 2025 presentation for comparative purposes; however, such reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.

Amounts disclosed for Dominion Energy are inclusive of Virginia Power, where applicable.

Revision of Previously Issued Consolidated Financial Statements

During the second quarter of 2025, the Companies identified misstatements in their previously issued consolidated financial statements related to income taxes associated with investments held within their qualified nuclear decommissioning trusts, primarily a net understatement of deferred income taxes associated with unrealized gains and losses (reflected in the Corporate and Other segment and attributable to Contracted Energy and Dominion Energy Virginia). The Companies assessed the impacts of the misstatements from both quantitative and qualitative perspectives and determined that the related impacts were not material to any of the Companies' previously issued consolidated financial statements.

As a result, the Companies will revise their previously issued consolidated financial statements. Accordingly, all consolidated financial information contained in these consolidated financial statements and the accompanying notes has been revised to reflect the correction. The Companies will present the revision of their previously issued consolidated financial statements for the three months ended March 31, 2025 in connection with the future filing of their Quarterly Report on Form 10-Q for the three months ended March 31, 2026.

82

The following tables detail the impact of the restatement adjustment to each affected line item in the Companies' Consolidated Statements of Income and Statements of Comprehensive Income for the periods presented:

		Dominion Energy
		2024												2023
Year Ended December 31,		As Previously Reported				Adjustments				As Revised				As Previously Reported				Adjustments				As Revised
(millions, except per share amounts)
Other income (expense)		$	822			$	19			$	841			$	984			$	12			$	996
Interest and related charges			1,887				6				1,893				1,674				5				1,679
Income from continuing operations including    noncontrolling interests before income tax expense			2,182				13				2,195				2,724				7				2,731
Income tax expense			308				103				411				568				76				644
Net income from continuing operations including    noncontrolling interests			1,874				(90	)			1,784				2,156				(69	)			2,087
Net income including noncontrolling interests			2,071				(90	)			1,981				2,031				(69	)			1,962
Net income attributable to Dominion Energy			2,124				(90	)			2,034				2,031				(69	)			1,962
Amounts Attributable to Dominion Energy
Net income from continuing operations			1,927				(90	)			1,837				2,156				(69	)			2,087
Net income attributable to Dominion Energy			2,124				(90	)			2,034				2,031				(69	)			1,962
EPS - Basic
Net income from continuing operations			2.20				(0.11	)			2.09				2.48				(0.08	)			2.40
Net income attributable to Dominion Energy			2.44				(0.11	)			2.33				2.33				(0.08	)			2.25
EPS - Diluted
Net income from continuing operations			2.20				(0.11	)			2.09				2.48				(0.08	)			2.40
Net income attributable to Dominion Energy			2.44				(0.11	)			2.33				2.33				(0.08	)			2.25
Comprehensive Income
Changes in unrealized net gains (losses) on investment    securities(1)			(22	)			3				(19	)			55				(8	)			47
Total other comprehensive income (loss)			17				3				20				67				(8	)			59
Comprehensive income including noncontrolling interests			2,088				(87	)			2,001				2,098				(77	)			2,021
Comprehensive income attributable to Dominion Energy			2,141				(87	)			2,054				2,098				(77	)			2,021

(1)As previously reported, net of $10 million and $(19) million tax for the years ended December 31, 2024 and 2023, respectively. As revised, net of $13 million ($3 million adjustment) and $(27) million ($(8) million adjustment) tax for the years ended December 31, 2024 and 2023, respectively.

		Virginia Power
		2024												2023
Year Ended December 31,		As Previously Reported				Adjustments				As Revised				As Previously Reported				Adjustments				As Revised
(millions)
Other income (expense)		$	195			$	3			$	198			$	131			$	2			$	133
Interest and related charges			848				1				849				764				1				765
Income before income tax expense			2,265				2				2,267				1,841				1				1,842
Income tax expense			408				15				423				389				11				400
Net Income Including Noncontrolling Interests			1,857				(13	)			1,844				1,452				(10	)			1,442
Net Income Attributable to Virginia Power			1,910				(13	)			1,897				1,452				(10	)			1,442
Comprehensive Income
Changes in unrealized net gains (losses) on investment    securities(1)			(5	)			—				(5	)			7				(1	)			6
Total other comprehensive income (loss)			11				—				11				7				(1	)			6
Comprehensive income including noncontrolling interests			1,868				(13	)			1,855				1,459				(11	)			1,448
Comprehensive income attributable to Virginia Power			1,921				(13	)			1,908				1,459				(11	)			1,448

(1)As previously reported, net of $2 million and $(3) million tax for the years ended December 31, 2024 and 2023, respectively. As revised, net of $2 million ($— million adjustment) and $(4) million ($(1) million adjustment) tax for the years ended December 31, 2024 and 2023, respectively.

83

Combined Notes to Consolidated Financial Statements, Continued

The following table details the impact of the restatement adjustment to each affected line item in the Companies' Consolidated Balance Sheets for the periods presented:

		Dominion Energy												Virginia Power
At December, 31 2024		As Previously Reported				Adjustments				As Revised				As Previously Reported				Adjustments				As Revised
(millions)
Deferred income taxes		$	6,412			$	723			$	7,135			$	4,045			$	431			$	4,476
Regulatory liabilities - noncurrent			9,196				(435	)			8,761				6,574				(435	)			6,139
Other deferred credits and other liabilities(1)			1,352				102				1,454				1,138				61				1,199
Total deferred credits and other liabilities			25,409				390				25,799				17,559				57				17,616
Total liabilities			72,223				390				72,613				43,234				57				43,291
Retained earnings			2,035				(394	)			1,641				12,194				(58	)			12,136
Accumulated other comprehensive income (loss)			(156	)			4				(152	)			27				1				28
Shareholders' equity			27,253				(390	)			26,863				22,214				(57	)			22,157
Total equity			30,192				(390	)			29,802				25,153				(57	)			25,096

(1)Other deferred credits and other liabilities for Virginia Power excludes derivative liabilities which were not impacted by the restatement adjustment and have been separately presented on Virginia Power’s Consolidated Balance Sheets in this report.

The following table details the impact of the restatement adjustment to each affected line item in the Companies' Consolidated Statements of Equity for the periods presented:

		Dominion Energy												Virginia Power
Year Ended December 31, 2024		As Previously Reported				Adjustments				As Revised				As Previously Reported				Adjustments				As Revised
(millions)
Retained earnings
Balance at December 31, 2023		$	2,229			$	(304	)		$	1,925			$	11,541			$	(45	)		$	11,496
Net income including noncontrolling interests			2,124				(90	)			2,034				1,910				(13	)			1,897
Balance at December 31, 2024			2,035				(394	)			1,641				12,194				(58	)			12,136
Accumulated other comprehensive income (loss)
Balance at December 31, 2023			(173	)			1				(172	)			16				1				17
Other comprehensive income (loss), net of tax			17				3				20				11				—				11
Balance at December 31, 2024			(156	)			4				(152	)			27				1				28
Shareholders' equity
Balance at December 31, 2023			27,567				(303	)			27,264				21,657				(44	)			21,613
Net income including noncontrolling interests			2,124				(90	)			2,034				1,910				(13	)			1,897
Other comprehensive income (loss), net of tax			17				3				20				11				-				11
Balance at December 31, 2024			27,253				(390	)			26,863				22,214				(57	)			22,157
Total equity
Balance at December 31, 2023			27,567				(303	)			27,264				21,657				(44	)			21,613
Net income including noncontrolling interests			2,071				(90	)			1,981				1,857				(13	)			1,844
Other comprehensive income (loss), net of tax			17				3				20				11				—				11
Balance at December 31, 2024			30,192				(390	)			29,802				25,153				(57	)			25,096

84

		Dominion Energy												Virginia Power
Year Ended December 31, 2023		As Previously Reported				Adjustments				As Revised				As Previously Reported				Adjustments				As Revised
(millions)
Retained earnings
Balance at December 31, 2022		$	2,511			$	(235	)		$	2,276			$	10,089			$	(35	)		$	10,054
Net income including noncontrolling interests			2,031				(69	)			1,962				1,452				(10	)			1,442
Balance at December 31, 2023			2,229				(304	)			1,925				11,541				(45	)			11,496
Accumulated other comprehensive income (loss)
Balance at December 31, 2022			(240	)			9				(231	)			9				2				11
Other comprehensive income (loss), net of tax			67				(8	)			59				7				(1	)			6
Balance at December 31, 2023			(173	)			1				(172	)			16				1				17
Shareholders' equity
Balance at December 31, 2022			27,659				(226	)			27,433				16,949				(33	)			16,916
Net income including noncontrolling interests			2,031				(69	)			1,962				1,452				(10	)			1,442
Other comprehensive income (loss), net of tax			67				(8	)			59				7				(1	)			6
Balance at December 31, 2023			27,567				(303	)			27,264				21,657				(44	)			21,613
Total equity
Balance at December 31, 2022			27,659				(226	)			27,433				16,949				(33	)			16,916
Net income including noncontrolling interests			2,031				(69	)			1,962				1,452				(10	)			1,442
Other comprehensive income (loss), net of tax			67				(8	)			59				7				(1	)			6
Balance at December 31, 2023			27,567				(303	)			27,264				21,657				(44	)			21,613

The following table details the impact of the restatement adjustment to each affected line item in the Companies' Consolidated Statements of Cash Flows for the periods presented:

		Dominion Energy
		2024												2023
Year Ended December 31,		As Previously Reported				Adjustments				As Revised				As Previously Reported				Adjustments				As Revised
(millions)
Net income including noncontrolling interests		$	2,071			$	(90	)		$	1,981			$	2,031			$	(69	)		$	1,962
Operating Activities
Deferred income taxes			(302	)			67				(235	)			1,474				53				1,527
Other operating assets and liabilities			(235	)			23				(212	)			(564	)			16				(548	)
Net cash provided by operating activities			5,018				—				5,018				6,572				—				6,572

		Virginia Power
		2024												2023
Year Ended December 31,		As Previously Reported				Adjustments				As Revised				As Previously Reported				Adjustments				As Revised
(millions)
Net income including noncontrolling interests		$	1,857			$	(13	)		$	1,844			$	1,452			$	(10	)		$	1,442
Operating Activities
Deferred income taxes			384				(3	)			381				504				(2	)			502
Other operating assets and liabilities			(163	)			16				(147	)			(375	)			12				(363	)
Net cash provided by operating activities			4,586				—				4,586				4,815				—				4,815

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. The Companies collect sales, consumption and consumer utility taxes; however, these amounts are excluded from revenue. Dominion Energy’s customer receivables at December 31, 2025 and 2024 included $955 million and $797 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility customers. Virginia Power’s customer receivables at December 31, 2025 and 2024 included $763 million and $611 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers. See Note 25 for amounts attributable to related parties.

The primary types of sales and service activities reported as operating revenue for Dominion Energy are as follows:

Revenue from Contracts with Customers

•Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

•Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates and

85

Combined Notes to Consolidated Financial Statements, Continued

associated hedging activity as well as sales to Virginia Power customers from non-jurisdictional solar generation facilities;

•Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services;

•Regulated gas transportation and storage sales consists of sales of transportation services to off-system customers;

•Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities; and

•Other nonregulated revenue consists primarily of sales of other miscellaneous products, including renewable natural gas and related credits. Other nonregulated revenue also includes revenue associated with services provided to entities presented in discontinued operations under transition services agreements.

Other Revenue

•Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.

The primary types of sales and service activities reported as operating revenue for Virginia Power are as follows:

Revenue from Contracts with Customers

•Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services;

•Nonregulated electric sales consists of sales to customers from non-jurisdictional solar generation facilities;

•Other regulated revenue consists primarily of sales of excess capacity and other commodities and miscellaneous service revenue from electric distribution operations; and

•Other nonregulated revenue consists primarily of revenue from renting space on certain electric transmission poles and distribution towers.

Other Revenue

•Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.

The Companies record refunds to customers as required by state commissions as a reduction to regulated electric sales or regulated gas sales, as applicable. The Companies’ revenue accounted for under the alternative revenue program guidance primarily consists of the equity return for under-recovery of certain riders. Alternative revenue programs compensate the Companies for certain projects and initiatives. Revenues arising from these programs are presented separately from revenue arising from contracts with customers in the categories above.

Revenues from electric and gas sales are recognized over time, as the customers of the Companies consume gas and electricity as it is delivered. Fixed fees are recognized ratably over the life of the contract as the stand-ready performance obligation is satisfied, while variable usage fees are recognized when Dominion Energy has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the performance obligation completed to date. Sales of products and services typically transfer control and are recognized as revenue upon delivery of the product or service. The customer is able to direct the use of, and obtain substantially all of the benefits from, the product at the time the product is delivered. The contract with the customer states the final terms of the sale, including the description, quantity and price of each product or service purchased. Payment for most sales and services varies by contract type but is typically due within a month of billing.

Revenue Included in Discontinued Operations

Operating revenue for the gas distribution operations sold to Enbridge as part of the East Ohio, PSNC and Questar Gas Transactions primarily consists of state-regulated natural gas sales to residential, commercial and industrial customers and related distribution services, state regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of commodities related to nonregulated extraction activities.

Transportation and storage contracts associated with the operations sold to Enbridge as part of the East Ohio, PSNC and Questar Gas Transactions are primarily stand-ready service contracts that include fixed reservation and variable usage fees. Substantially all of the revenue associated with these local gas distribution companies is derived from performance obligations satisfied over time and month-to-month billings according to their respective tariffs.

Credit Risk

Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.

The Companies maintain a provision for credit losses based on factors surrounding the credit risk of their customers, historical trends and other information. Expected credit losses are estimated and recorded based on historical experience, current conditions and reasonable and supportable forecasts that affect the collectability of financial assets held at amortized cost as well as expected credit losses on commitments with respect to financial guarantees.

Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs

Where permitted by regulatory authorities, the differences between the Companies’ actual electric fuel and purchased energy expenses and Dominion Energy’s purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.

Of the cost of fuel used in electric generation and energy purchases to serve Virginia utility customers, at December 31, 2025, approximately 87% is subject to Virginia Power’s deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms. Additionally in

86

2024, Virginia Power securitized $1.3 billion of under-recovered deferred fuel expenses through the issuance of bonds by VPFS. Of the cost of fuel used in electric generation and energy purchases to serve South Carolina utility customers, at December 31, 2025, substantially all is subject to DESC’s deferred fuel accounting.

Virtually all of DESC’s natural gas purchases are either subject to deferral accounting or are recovered from the customer in the same accounting period as the sale. Through the respective closing dates of the East Ohio, Questar Gas and PSNC Transactions, these companies’ natural gas purchases were also either subject to deferral accounting or were recovered from the customer in the same accounting period as the sale.

Income Taxes

A consolidated federal income tax return is filed for Dominion Energy and its subsidiaries, including Virginia Power. In addition, where applicable, combined income tax returns for Dominion Energy and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed.

Virginia Power participates in intercompany tax sharing agreements with Dominion Energy and its subsidiaries. Current income taxes are based on taxable income or loss and credits determined on a separate company basis.

Under the agreements, if a subsidiary incurs a tax loss or earns a credit, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or credit or to the extent the tax loss or credit is absorbed by the taxable income of other Dominion Energy consolidated group members. Otherwise, the net operating loss or credit is carried forward and is recognized as a deferred tax asset until realized.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. The Companies establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.

The Companies recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the Consolidated Balance Sheets and current payables are included in accrued interest, payroll, and taxes on the Consolidated Balance Sheets.

The Companies recognize interest on underpayments and overpayments of income taxes in interest expense and other income (expense), respectively. Penalties are also recognized in other income (expense).

At December 31, 2025, Virginia Power had an income tax-related affiliated receivable of $31 million, comprised of $26 million of federal income taxes and $5 million of state income taxes receivable from Dominion Energy. Virginia Power’s net affiliated balances are expected to be received from Dominion Energy in 2026.

At December 31, 2024, Virginia Power had an income tax-related affiliated receivable of $26 million, comprised of $21 million of federal income taxes and $5 million of state income taxes receivable from Dominion Energy. Virginia Power’s net affiliated balances were received from Dominion Energy in 2025.

Investment tax credits for both regulated and nonregulated operations are deferred and amortized to income tax expense over the service lives of the properties giving rise to the credits beginning in the year qualifying property is placed in service. The Companies recognize the tax benefit related to initial book and tax basis differences as a reduction of income tax expense in the year in which the qualifying property is placed into service, except where cost-of-service rate regulation applies. Production tax credits are recognized as energy is generated and sold. Current tax law allows the election of either the investment tax credit or production tax credit for certain technologies including solar and wind. Such election is made on a project-by-project basis and the choice of credit may vary based on a combination of factors including, but not limited to, capital expenditures and net capacity factors. Current tax law allows that certain energy tax credits can be transferred to a third-party for cash. The Companies account for such tax credit transfers and any related discount as a component of income tax expense.

Cash, Restricted Cash and Equivalents

Cash, restricted cash and equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Current banking arrangements generally do not require checks to be funded until they are presented for payment. The following table illustrates the checks outstanding but not yet presented for payment and recorded in accounts payable for the Companies:

At December 31,		2025				2024
(millions)
Dominion Energy		$	64			$	52
Virginia Power			46				23

Restricted Cash and Equivalents

The Companies hold restricted cash and equivalent balances that primarily consist of amounts held for litigation settlements, customer deposits, federal assistance funds and future debt payments on DECP Holdings’ term loan agreement (through September 2023), on Eagle Solar’s senior note agreement (through February 2024) and on the securitization bonds.

87

Combined Notes to Consolidated Financial Statements, Continued

The following table provides a reconciliation of the total cash, restricted cash and equivalents reported within the Companies’ Consolidated Balance Sheets to the corresponding amounts reported within the Companies’ Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023:

Cash, Restricted Cash and Equivalents at End/Beginning of Year
		December  31, 2025				December  31, 2024				December 31, 2023				December 31, 2022
(millions)
Dominion Energy
Cash and cash    equivalents(1)		$	250			$	310			$	217			$	153
Restricted cash and    equivalents(2)(3)			93				55				84				188
Cash, restricted    cash and    equivalents    shown in the    Consolidated    Statements of    Cash Flows		$	343			$	365			$	301			$	341
Virginia Power
Cash and cash    equivalents		$	170			$	160			$	90			$	22
Restricted cash and    equivalents(3)(4)			61				46				—				2
Cash, restricted    cash and    equivalents    shown in the    Consolidated    Statements of    Cash Flows		$	231			$	206			$	90			$	24

(1)At December 31, 2023 and 2022, Dominion Energy had $33 million and $34 million, respectively, of cash and cash equivalents included in assets held for sale.

(2)At December 31, 2023 and 2022, Dominion Energy had $4 million and $2 million, respectively, of restricted cash and equivalents included in assets held for sale. The remaining balances are presented within other current assets in Dominion Energy’s Consolidated Balance Sheets.

(3)Includes $51 million and $41 million at VPFS attributable to VIEs at December 31, 2025 and 2024, respectively.

(4)Restricted cash and equivalents balances are presented within other current assets in Virginia Power’s Consolidated Balance Sheets.

Supplemental Cash Flow Information

The following table provides supplemental disclosure of cash flow information related to Dominion Energy:

Year Ended December 31,		2025				2024				2023
(millions)
Cash paid during the year for:
Interest and related charges,    excluding capitalized amounts		$	1,799			$	1,900			$	1,991
Income taxes(1)			186				840				286
Significant noncash investing and    financing activities:(2)
Accrued capital expenditures			1,699				1,268				1,085
Leases(3)			338				233				255

(1)Excludes cash proceeds received of $184 million from the transfer of tax credits to third-parties and $13 million of purchases of tax credits from Align RNG for the year ended December 31, 2025. See Notes 5 and 9 for more information.

(2)See Notes 3, 10 and 23 for noncash financing activities related to debt assumed with closing of the East Ohio, Questar Gas and PSNC Transactions, the sale of noncontrolling interest in the CVOW Commercial Project and transfer of property associated with the settlement of litigation.

(3)Includes $77 million of finance leases and $261 million of operating leases entered in 2025, $93 million of finance leases and $140 million of operating leases entered in 2024 and $44 million of finance leases and $211 million of operating leases entered in 2023.

The following table provides supplemental disclosure of cash flow information related to Virginia Power:

Year Ended December 31,		2025				2024				2023
(millions)
Cash paid (received) during the year for:
Interest and related charges,    excluding capitalized amounts		$	901			$	786			$	709
Income taxes(1)			385				25				(47	)
Significant noncash investing activities(2):
Accrued capital expenditures			1,469				992				807
Leases(3)			320				201				203

(1)Excludes cash proceeds received of $168 million from the transfer of tax credits to third-parties for the year ended December 31, 2025. See Note 5 for more information.

(2)See Note 10 for noncash financing activities related to the sale of noncontrolling interest in the CVOW Commercial Project.

(3)Includes $61 million of finance leases and $259 million of operating leases entered in 2025, $77 million of finance leases and $124 million of operating leases entered in 2024 and $30 million of finance leases and $173 million of operating leases entered in 2023.

Distributions from Equity Method Investees

Dominion Energy holds investments that are accounted for under the equity method of accounting and classifies distributions from equity method investees as either cash flows from operating activities or cash flows from investing activities in the Consolidated Statements of Cash Flows according to the nature of the distribution. Distributions received are classified on the basis of the nature of the activity of the investee that generated the distribution as either a return on investment (classified as cash flows from operating activities) or a return of an investment (classified as cash flows from investing activities) when such information is available to Dominion Energy.

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of the Companies’ own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion Energy applies fair value measurements to certain assets and liabilities including commodity, interest rate and/or foreign currency exchange rate derivative instruments and other

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investments including those held in nuclear decommissioning, rabbi and pension and other postretirement benefit plan trusts, in accordance with the requirements discussed above. Virginia Power applies fair value measurements to certain assets and liabilities including commodity, interest rate and/or foreign currency exchange rate derivative instruments and other investments including those held in the nuclear decommissioning trust, in accordance with the requirements discussed above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above.

Inputs and Assumptions

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including industry publications, and to a lesser extent, broker quotes. When evaluating pricing information provided by Designated Contract Market settlement pricing, other pricing services or brokers, the Companies consider the ability to transact at the quoted price, i.e. if the quotes are based on an active market or an inactive market and to the extent which pricing models are used, if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases the unobservable inputs are developed and substantiated using historical information, available market data, third-party data and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships and changes in third-party sources.

For options and contracts with option-like characteristics where observable pricing information is not available from external sources, the Companies generally use a model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. For contracts with unique characteristics, the Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.

The inputs and assumptions used in measuring fair value include the following:

		Derivative Contracts
Inputs and assumptions		Commodity		Interest Rate		Foreign Currency Exchange Rate		Investments
Forward commodity    prices		X
Transaction prices		X
Price volatility		X
Price correlation		X
Volumes		X
Commodity location		X
Interest rate curves				X
Foreign currency    forward exchange    rates						X
Quoted securities    prices and indices								X
Securities trading    information    including volume   and restrictions								X
Maturity								X
Interest rates		X				X		X
Credit quality of    counterparties    and the Companies		X		X		X		X
Credit enhancements		X		X
Notional value				X		X
Time value		X		X		X

Levels

The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

•Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as certain exchange-traded derivatives and exchange-listed equities, U.S. and international equity securities, mutual funds and certain treasury securities and cash and cash equivalents held in nuclear decommissioning trust funds for the Companies and benefit plan trust funds and rabbi trust funds for Dominion Energy.

•Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include commodity forwards and swaps, interest rate swaps, foreign currency exchange rate instruments and certain cash and cash equivalents, corporate debt instruments, government securities and other fixed income investments held in nuclear decommissioning trust funds for the Companies and benefit plan trust funds and rabbi trust funds for Dominion Energy.

•Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for the Companies consist of long-dated commodity derivatives, FTRs, certain natural gas options and other modeled commodity derivatives.

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Combined Notes to Consolidated Financial Statements, Continued

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. Alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments held in nuclear decommissioning and benefit plan trust funds, are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date. Alternative investments recorded at NAV are not classified in the fair value hierarchy.

Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change.

Derivative Instruments

The Companies are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as interest rate and foreign currency exchange rate risks in their business operations. The Companies use derivative instruments such as physical and financial forwards, futures, swaps, options, foreign currency transactions and FTRs to manage the commodity, interest rate and/or foreign currency exchange rate risks of their business operations.

Derivative assets and liabilities are presented gross on the Companies’ Consolidated Balance Sheets. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. All derivatives, except those for which an exception applies, are required to be reported at fair value. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance. See Fair Value Measurements above for additional information about fair value measurements and associated valuation methods for derivatives.

The Companies’ derivative contracts include both over-the-counter transactions and those that are executed on an exchange or other trading platform (exchange contracts) and centrally cleared. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange or clearinghouse to enter, execute or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements and contract default provisions. In addition, the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency or other conditions.

In general, most over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral for over-the-counter and exchange contracts include cash, letters of credit and in some cases, other forms of security, none of which are subject to restrictions.

The Companies do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion Energy had margin assets of $181 million and $104 million associated with cash collateral at December 31, 2025 and 2024, respectively. Dominion Energy had margin liabilities of less than $1 million and $3 million associated with cash collateral at December 31, 2025 and 2024, respectively. Virginia Power had margin assets of less than $1 million and $1 million associated with cash collateral at December 31, 2025 and 2024, respectively. Virginia Power had less than $1 million and no margin liabilities associated with cash collateral at December 31, 2025 and 2024, respectively. See Note 7 for further information about derivatives.

To manage price and interest rate risk, the Companies hold derivative instruments that are not designated as hedges for accounting purposes. However, to the extent the Companies do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices or interest rates. All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses, interest and related charges or discontinued operations based on the nature of the underlying risk.

Changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.

Derivative Instruments Designated as Hedging Instruments

In accordance with accounting guidance pertaining to derivatives and hedge accounting, the Companies designate a portion of their derivative instruments as cash flow hedges for accounting purposes. For derivative instruments that are accounted for as cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.

The Companies’ derivatives designated into cash flow hedges primarily consist of interest rate swaps to hedge the Companies’ exposure to variations in interest rates on long-term debt. For transactions in which the Companies are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item, or as appropriate to regulatory assets or regulatory liabilities. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted

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transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.

Property, Plant and Equipment

Property, plant and equipment is recorded at the lower of original cost or fair value, if impaired. Capitalized costs include labor, materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is generally charged to expense as it is incurred.

Amounts capitalized to property, plant and equipment for capitalized interest costs and AFUDC for the Companies are as follows:

		Dominion Energy												Virginia Power
Year Ended December 31,		2025				2024				2023				2025				2024				2023
(millions)
Capitalized interest costs     and AFUDC debt		$	169			$	152			$	109			$	73			$	46			$	47
AFUDC equity(1)			152				109				50				151				96				39

(1)The Companies include AFUDC equity in other adjustments within operating activities in their Consolidated Statements of Cash Flows.

Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2025, 2024 and 2023, Virginia Power recorded $12 million, $3 million and less than $1 million of AFUDC related to these projects, respectively.

For property subject to cost-of-service rate regulation, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement. Cost of removal collections from utility customers are recorded as regulatory liabilities. For property subject to cost-of-service rate regulation that will be abandoned significantly before the end of its useful life, the net carrying value is reclassified from plant-in-service when it becomes probable it will be abandoned and recorded as a regulatory asset for amounts expected to be collected through future rates.

In 2024 and 2023, Virginia Power had the following charges, recorded in impairment of assets and other charges in its Consolidated Statements of Income (reflected in the Corporate and Other segment), related to early retirements and abandonments:

•In 2024, Virginia Power recorded charges of $40 million ($30 million after-tax) associated with dismantling of certain electric generation facilities. In addition, Virginia Power recorded a $25 million ($18 million after-tax) charge in 2024 related to the write-off of early-stage development costs associated with a hydroelectric pumped storage facility that it is no longer considering constructing.

•In 2023, Virginia Power recorded a charge of $25 million ($19 million after-tax) as a result of the abandonment of long-lived assets associated with certain rooftop solar and other projects before the end of their useful lives.

For property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date.

Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. The Companies’ average composite depreciation rates on utility property, plant and equipment are as follows:

Year Ended December 31,		2025				2024				2023
(percent)
Dominion Energy(1)
Generation			2.71				2.59				2.65
Transmission			2.32				2.32				2.32
Distribution			2.78				2.73				2.72
General and other			3.21				3.97				4.20
Virginia Power
Generation			2.79				2.66				2.75
Transmission			2.28				2.29				2.29
Distribution			2.83				2.77				2.78
General and other			3.26				4.29				4.60

(1) Excludes rates for depreciation reported as discontinued operations.

In December 2023, Dominion Energy revised the estimated useful lives for Millstone Units 2 and 3 to reflect lower depreciation rates as a result of its expectation that a 20-year license extension is approved for these facilities. This revision resulted in a 2024 annual decrease of depreciation expense of $35 million ($26 million after-tax) and increased Dominion Energy’s 2024 EPS by $0.03. For the year ended December 31, 2023, this revision resulted in an inconsequential impact.

In January 2024, Virginia Power revised the depreciation rates for Bath County as a result of its expectation that a license extension of at least 40 years will be approved for this facility. This revision resulted in an annual decrease of depreciation expense of $17 million ($13 million after-tax) and increased Dominion Energy's 2024 EPS by $0.02.

Virginia Power’s non-jurisdictional solar generation property, plant and equipment is depreciated using the straight-line method over an estimated useful life of 35 years.

Capitalized costs of development wells and leaseholds were amortized on a field-by-field basis using the unit-of-production method and the estimated proved developed or total proved gas and oil reserves, at a rate of $1.83 and $1.73 per mcfe in 2024 and 2023, respectively. Depletion associated with Wexpro's operations is reflected within discontinued operations through May 2024. See Note 3 for additional information.

Dominion Energy’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:

Asset		Estimated Useful Lives(1)
Nonregulated generation-nuclear		54-64 years
Nonregulated generation-other		30-35 years
General and other		5-50 years

(1)The estimated useful life for a generation station is made on a unit basis if the facility has multiple generating units and represents the period the unit was placed in service or acquired until the end of its license or estimated service period.

Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. The Companies report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.

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Combined Notes to Consolidated Financial Statements, Continued

Long-Lived and Intangible Assets

The Companies perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 6 for further discussion on the impairment of long-lived assets.

Accounting for Regulated Operations

The accounting for the Companies’ regulated electric and gas operations differs from the accounting for nonregulated operations in that the Companies are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds or other benefits through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. In addition, a loss is recognized if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made.

In 2025, the Companies recorded a net $258 million ($192 million after-tax) of charges for Virginia Power’s share of costs not expected to be recovered from customers on the CVOW Commercial Project as a result of a revised total project cost estimate of approximately $11.5 billion (excluding financing costs) which reflects a temporary suspension of work order and an estimated impact of certain tariffs which became effective during 2025 as well as the previously included revised estimate of network upgrade costs assigned by PJM to the CVOW Commercial Project and cost sharing mechanism included in the Virginia Commission’s December 2022 order. The expected total project cost reflects an increase of $0.2 billion, relative to Virginia Power’s October 2025 Rider OSW filing, associated with projected installation timeline changes arising from the temporary suspension of work from the BOEM Director’s Order issued in December 2025 until a preliminary injunction was granted by the U.S District Court for the Eastern District of Virginia in January 2026, which allowed work to resume. The estimated total project costs also include $0.6 billion of tariffs on equipment expected to be delivered from March 2025 through March 2026 that originates from Mexico, Canada, a European Union member or other applicable countries and on equipment expected to be delivered from March 2025 through early 2027 that contains steel. Such amount is inclusive of approximately $0.2 billion associated with tariffs on equipment expected to be delivered from March 2025 through March 2026 that originates from Mexico, Canada, a European Union member or other applicable countries that were the subject of a U.S. Supreme Court’s ruling on February 20, 2026. Dominion Energy is currently unable to estimate the expected impact of the ruling issued by the U.S. Supreme Court on February 20, 2026, on its financial position, results of operations and/or cash flows.

In the fourth quarter of 2024, the Companies recorded a net $103 million ($77 million after-tax) charge for Virginia Power’s share of costs not expected to be recovered from customers on the CVOW Commercial Project as a result of a revised total project cost estimate that included a revised estimate of network upgrade costs assigned by PJM to the CVOW Commercial Project and cost sharing mechanism included in the Virginia Commission’s December 2022 order. The expected total project cost reflects increases driven primarily by projections for onshore electrical interconnection costs and network upgrade costs assigned to the project by PJM, specifically incorporating consideration of PJM’s December 2024 publication of potential transmission network upgrades required for certain generation projects and related cost allocations, including those attributable to the CVOW Commercial Project. Relative to Virginia Power’s November 2024 Rider OSW filing, the estimated total project cost reflects an approximately $0.6 billion increase for such onshore and network upgrade costs and an approximately $0.3 billion increase for increased contingency for remaining construction activities, completion of the removal of unexploded ordnance, undersea cable protection system design enhancements, commodity prices for transportation fuel, updates for sea fastener fabrication and installation and other construction and equipment supplier costs.

The estimated total project cost reflects the Companies’ best estimate of the remaining construction costs, including contingency of approximately 7% on such remaining amounts. Such estimate could potentially change for items, certain of which are beyond the Companies’ control, including but not limited to actual network upgrade costs allocated by PJM, fuel for transportation and installation, the impact of applicable tariffs including any potential impact of Section 232 investigations and litigation ruled on by the U.S. Supreme Court on February 20, 2026, costs to maintain necessary permits, approvals and authorizations, any additional suspension of work orders, ability of key suppliers and contractors to timely satisfy their obligations under existing contracts, marine wildlife and/or any severe weather events.  Any additional increase in such costs in excess of the contingency included in the estimated total project cost would be subject to the cost sharing mechanisms described above and could have a material impact on the Companies’ future financial condition, results of operations and/or cash flows. See Note 10 for additional information.

The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and make various assumptions in their analyses. These analyses are generally based on:

•Orders issued by regulatory commissions, legislation and judicial actions;

•Past experience;

•Discussions with applicable regulatory authorities and legal counsel;

•Estimated construction costs;

•Forecasted earnings; and

•Considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events and other natural disasters and unplanned outages of facilities.

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Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. A regulatory liability, if considered probable, will be recorded in the period such assessment is made or reversed into earnings if no longer probable. In connection with the future 2027 Biennial Review, the Companies concluded that it was not probable that Virginia Power would have earnings in excess of an expected authorized ROE of 9.80% for the period January 1, 2025 through December 31, 2026. As a result, no regulatory liability for Virginia Power ratepayer credits to customers has been recorded at December 31, 2025. See Note 13 for additional information.

Leases

The Companies lease certain assets including vehicles, real estate, office equipment and other operational assets, including the offshore wind installation vessel described in Note 15, under both operating and finance leases. For the Companies’ operating leases, rent expense is recognized on a straight-line basis over the term of the lease agreement, subject to regulatory framework. Rent expense associated with operating leases, short-term leases and variable leases is primarily recorded in other operations and maintenance expense in the Companies’ Consolidated Statements of Income. Rent expense associated with finance leases results in the separate presentation of interest expense on the lease liability and amortization expense of the related right-of-use asset in the Companies’ Consolidated Statements of Income or, subject to regulatory framework, is deferred within regulatory assets in the Consolidated Balance Sheets and amortized into the Consolidated Statements of Income.

Certain of the Companies’ leases include one or more options to renew, with renewal terms that can extend the lease from one to 70 years. The exercise of renewal options is solely at the Companies’ discretion and is included in the lease term if the option is reasonably certain to be exercised. A right-of-use asset and corresponding lease liability for leases with original lease terms of one year or less are not included in the Consolidated Balance Sheets, unless such leases contain renewal options that the Companies are reasonably certain will be exercised. Additionally, certain of the Companies’ leases contain escalation clauses whereby payments are adjusted for consumer price or other indices or contain fixed dollar or percentage increases. The Companies also have leases with variable payments based upon usage of, or revenues associated with, the leased assets.

The determination of the discount rate utilized has a significant impact on the calculation of the present value of the lease liability included in the Companies’ Consolidated Balance Sheets. For the Companies’ fleet of leased vehicles, the discount rate is equal to the prevailing borrowing rate earned by the lessor. For the Companies’ remaining leased assets, the discount rate implicit in the lease is generally unable to be determined from a lessee perspective. As such, the Companies use internally-developed incremental borrowing rates as a discount rate in the calculation of the present value of the lease liability. The incremental borrowing rates are determined based on an analysis of the Companies’ publicly available unsecured borrowing rates, adjusted for a collateral discount, over various lengths of time that most closely correspond to the Companies’ lease maturities.

In addition, Dominion Energy acts as lessor under certain power purchase agreements in which the counterparty or counterparties purchase substantially all of the output of certain solar facilities. These leases are considered operating in nature. For such leasing arrangements, rental revenue and an associated accounts receivable are recorded when the monthly output of the solar facility is determined. Depreciation on these solar facilities is computed on a straight-line basis primarily over an estimated useful life of 35 years.

Supply Chain Financing

In the fourth quarter of 2025, Dominion Energy entered into a voluntary supply chain finance program that allows its suppliers, at their sole discretion, to sell their receivables from the Companies to a financial institution. Suppliers participating in the program determine which invoices they will sell to the financial institution. Suppliers’ decisions on which invoices are sold do not impact the Companies’ payment terms, which are based on commercial terms negotiated between the Companies and the supplier regardless of program participation. The Companies do not issue any guarantees with respect to the program and do not participate in negotiations between suppliers and the financial institution. The Companies do not have an economic interest in the supplier’s decision to participate in the program. No amounts were outstanding under this program for the Companies at December 31, 2025.

Asset Retirement Obligations

The Companies recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed, for which a legal obligation exists. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is estimated using discounted cash flow analyses. Quarterly, the Companies assess their AROs to determine if circumstances indicate that estimates of the amounts or timing of future cash flows associated with retirement activities have changed. AROs are adjusted when significant changes in the amounts or timing of future cash flows are identified. Dominion Energy reports accretion of AROs and depreciation on asset retirement costs associated with its natural gas pipelines of its distribution business as an adjustment to the related regulatory assets or liabilities when revenue is recoverable from customers for AROs. The Companies report accretion of AROs and depreciation on asset retirement costs associated with decommissioning its nuclear power stations as an adjustment to the regulatory asset or liability for certain jurisdictions. Additionally, the Companies report accretion of AROs and depreciation on asset retirement costs associated with certain rider and prospective rider projects and other electric generation and distribution facilities as an adjustment to the regulatory asset for certain jurisdictions. Accretion of all other AROs and depreciation of all other asset retirement costs are reported in other operations and maintenance expense and depreciation expense, respectively, in the Consolidated Statements of Income.

High Load Equipment Deposits

Beginning in 2025, Virginia Power requires high load customers to

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Combined Notes to Consolidated Financial Statements, Continued

provide certain commitments to Virginia Power, including cash deposits, during the project construction period. If the customer ceases construction of its facility, Virginia Power will attempt to redeploy the equipment to another customer, returning the original deposit and requiring a new deposit from the new customer. If the equipment cannot be redeployed, Virginia Power will retain the cash deposit received. If the customer completes construction and Virginia Power begins delivering electricity, the cash deposit will be returned to the customer. At December 31, 2025, the Companies’ Consolidated Balance Sheets include $321 million of deposits received, included in other deferred credits and other liabilities.

Debt Issuance Costs

The Companies defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. Deferred debt issuance costs are recorded as a reduction in long-term debt in the Consolidated Balance Sheets. Amortization of the issuance costs is reported as interest expense. Unamortized costs associated with redemptions of debt securities prior to stated maturity dates are generally recognized and recorded in interest expense immediately. As permitted by regulatory authorities, gains or losses resulting from the refinancing or redemption of debt allocable to utility operations subject to cost-based rate regulation are deferred and amortized.

Investments

Debt Securities

Dominion Energy accounts for and classifies investments in debt securities as trading or available-for-sale securities. Virginia Power classifies investments in debt securities as available-for-sale securities.

•Debt securities classified as trading securities include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.

•Debt securities classified as available-for-sale securities include all other debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any credit-related impairments) on investments held in nuclear decommissioning trusts are deferred to a regulatory asset or liability, as applicable, for certain jurisdictions subject to cost-based regulation. For all other available-for-sale debt securities, including those held in Dominion Energy’s nonregulated generation nuclear decommissioning trusts, net realized gains and losses (including any credit-related impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax.

In determining realized gains and losses for debt securities, the cost basis of the security is based on the specific identification method.

Credit Impairment

The Companies periodically review their available-for-sale debt securities to determine whether a decline in fair value should be considered credit related. If a decline in the fair value of any available-for-sale debt security is determined to be credit related, the credit-related impairment is recorded to an allowance included in nuclear decommissioning trust funds in the Companies’ Consolidated Balance Sheets at the end of the reporting period, with such allowance for credit losses subject to reversal in subsequent evaluations.

Using information obtained from their nuclear decommissioning trust fixed-income investment managers, the Companies record in earnings, or defer as applicable for certain jurisdictions subject to cost-based regulation, any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, the Companies record the credit loss in earnings or defer as applicable for certain jurisdictions subject to cost-based regulation, with the remaining non-credit portion of the unrealized loss recorded in AOCI. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.

Equity Securities with Readily Determinable Fair Values

Equity securities with readily determinable fair values include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans and securities held by the Companies in the nuclear decommissioning trusts. The Companies record all equity securities with a readily determinable fair value, or for which they are permitted to estimate fair value using NAV (or its equivalent), at fair value in nuclear decommissioning trust funds and other investments in the Consolidated Balance Sheets. Net realized and unrealized gains and losses on equity securities held in the nuclear decommissioning trusts are deferred to a regulatory asset or liability, as applicable, for certain jurisdictions subject to cost-based regulation. For all other equity securities, including those held in Dominion Energy’s nonregulated generation nuclear decommissioning trusts and rabbi trusts, net realized and unrealized gains and losses are included in other income in the Consolidated Statements of Income.

Equity Securities without Readily Determinable Fair Values

The Companies account for illiquid and privately held securities without readily determinable fair values under either the equity method or cost method. Equity securities without readily determinable fair values include:

•Equity method investments when the Companies have the ability to exercise significant influence, but not control, over the investee. Dominion Energy’s investments are included in investments in equity method affiliates in its Consolidated Balance Sheets, except for the liability to Atlantic Coast Pipeline. Dominion Energy records equity method adjustments in other income in its Consolidated Statements of Income, including its proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value

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and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method.

•Cost method investments when the Companies do not have the ability to exercise significant influence over the investee. The Companies’ investments are included in other investments and nuclear decommissioning trust funds. Cost method investments are reported at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same issuer.

Other-Than-Temporary Impairment

The Companies periodically review their equity method investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in the fair value of any security is determined to be other-than-temporary, the investment is written down to its fair value at the end of the reporting period.

Inventories

Materials and supplies, fossil fuel and gas stored inventory is valued using the weighted-average cost method.

In 2024, Dominion Energy wrote off certain inventory balances in connection with the electric base rate case in South Carolina as discussed in Note 13.

Goodwill

Dominion Energy evaluates goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. In the fourth quarter of 2023 and first quarter of 2024, Dominion Energy's current period calculations of the expected gain or loss on the Questar Gas and East Ohio Transactions resulted in an impairment of the related goodwill. There were no other impairments recorded in 2024 and none were recorded in 2025. See Note 3 for additional information.

New Accounting Standards

Income Tax Disclosures

In December 2023, the FASB issued revised accounting guidance for income taxes. The revised guidance requires disclosure of disaggregated information about an entity’s effective tax rate reconciliation as well as additional information on income taxes paid. The new standard is effective for fiscal years beginning after December 15, 2024, with early adoption permitted and allows either prospective or retrospective application. The Companies adopted this revised guidance prospectively which only impacted the Companies’ disclosures with no impacts to their results of operations, cash flows or financial condition.

Climate-Related Disclosures

In March 2024, the SEC issued guidance for climate-related disclosures. The guidance requires disclosure of the financial statement impacts of severe weather events and other natural conditions, including amounts capitalized or expensed as well as any associated recoveries. In addition, the guidance requires disclosure of amounts related to renewable energy credits or carbon offsets if utilized as a material component of plans to achieve climate-related targets or goals. This guidance is currently subject to a stay issued by the SEC. Should this guidance become effective, the Companies expect it to only impact their disclosures with no impacts to their results of operations, cash flows or financial condition.

Expense Disaggregation Disclosures

In November 2024, the FASB issued revised accounting guidance for income statement expense disaggregation disclosures. The revised guidance requires disclosure of disaggregated information about specific expense categories in commonly presented income statement expense captions. The new standard is effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027, with early adoption permitted and allows either prospective or retrospective application. The Companies expect this revised guidance to only impact their disclosures with no impacts to their results of operations, cash flows or financial condition.

Note 3. Acquisitions and Dispositions

Business Review Dispositions

Sale of East Ohio

In September 2023, Dominion Energy entered into an agreement with Enbridge for the East Ohio Transaction, which included the sale of East Ohio and was valued at approximately $6.6 billion, consisting of a purchase price of approximately $4.3 billion in cash and approximately $2.3 billion of assumed indebtedness. The sale closed in March 2024 after all customary closing and regulatory conditions were satisfied, including clearance or approval under or by the Hart-Scott-Rodino Act, CFIUS and FCC. Dominion Energy utilized the after-tax proceeds, as required, to repay outstanding borrowings under 364-day term loan facilities. See Note 17 for additional information. The purchase price was subject to customary post-closing adjustments, including adjustments for cash, indebtedness, net working capital, capital expenditures and net regulatory assets and liabilities. The transaction was structured as a stock sale for tax purposes. In October 2023, as required under the sale agreement, Dominion Energy filed a notice with the Ohio Commission. The internal reorganization in connection with the East Ohio Transaction was subject to approval by the Utah and Wyoming Commissions. Dominion Energy filed for such approvals in September 2023 which were received in November 2023. The internal reorganization was completed in February 2024.

Dominion Energy retained the pension and other postretirement benefit plan assets and obligations, including related income tax and other deferred balances, associated with retiree participants in both East Ohio’s union pension and other postretirement benefit plans and retiree participants of the sale entities in the Dominion Energy Pension Plan and the Dominion Energy Retiree Health and Welfare Plan. Dominion Energy recognized a pre-tax loss of $97 million ($109 million after-tax loss) upon the closing of the transaction, including the write-off of $1.5 billion of goodwill which was not deductible for tax purposes and including the effects of final closing adjustments. In 2023, Dominion Energy recorded a charge of $29 million to reflect the recognition of deferred taxes on the outside basis of East Ohio’s

95

Combined Notes to Consolidated Financial Statements, Continued

stock upon meeting the classification as held for sale. These deferred taxes reversed in the first quarter of 2024 upon closing of the sale and became a component of current income tax expense on the loss on sale disclosed above. See Note 5 for additional information.

At the closing of the East Ohio Transaction, Dominion Energy and Enbridge entered into a transition services agreement pursuant to which Dominion Energy will continue to provide certain services to support the ongoing operations of East Ohio for up to approximately two years. Enbridge has also agreed to provide certain services to Dominion Energy.

Sale of PSNC

In September 2023, Dominion Energy entered into an agreement with Enbridge for the PSNC Transaction, which included the sale of PSNC. The sale closed in September 2024 after all customary closing and regulatory conditions were satisfied, including clearance or approval under or by the Hart-Scott-Rodino Act, CFIUS, FCC and North Carolina Commission. At closing, the transaction was valued at $3.3 billion, consisting of a purchase price of $2.0 billion in cash and $1.3 billion of assumed indebtedness. The purchase price was subject to customary post-closing adjustments, including adjustments for cash, indebtedness, net working capital, capital expenditures and net regulatory assets and liabilities. The transaction was structured as a stock sale for tax purposes. The internal reorganization in connection with the PSNC Transaction was subject to approval by the North Carolina Commission. Dominion Energy filed for such approval in September 2023 which was received in November 2023. The internal reorganization was completed in December 2023.

Dominion Energy retained the entirety of the assets and obligations, including related income tax and other deferred balances, of the pension and other postretirement employee benefit plans associated with the operations included in the transaction and relating to services provided through closing. Dominion Energy recognized a pre-tax loss of $35 million ($31 million after-tax loss) upon the closing of the transaction, including the write-off of $0.7 billion of goodwill which is not deductible for tax purposes and including the effects of final closing adjustments. In 2023, Dominion Energy recorded a charge of $334 million to reflect the deferred taxes on the outside basis of PSNC’s stock upon meeting the classification as held for sale. Dominion Energy recorded an additional charge of $16 million to adjust these deferred taxes to recorded balances as of June 30, 2024. These deferred taxes reversed in the third quarter of 2024 upon closing of the sale and became a component of current income tax expense on the pre-tax loss on sale disclosed above. See Note 5 for additional information.

At the closing of the PSNC Transaction, Dominion Energy and Enbridge entered into a transition services agreement pursuant to which Dominion Energy will continue to provide certain services to support the ongoing operations of PSNC for up to approximately two years. Enbridge has also agreed to provide certain services to Dominion Energy.

Sale of Questar Gas and Wexpro

In September 2023, Dominion Energy entered into an agreement with Enbridge for the Questar Gas Transaction, which included the sale of Questar Gas, Wexpro and related affiliates and was valued at approximately $4.3 billion, consisting of a purchase price of approximately $3.0 billion in cash and approximately $1.3 billion of assumed indebtedness. The sale closed in May 2024 after all customary closing and regulatory conditions were satisfied, including clearance or approval under or by the Hart-Scott-Rodino Act, CFIUS, FCC and Utah and Wyoming Commissions. Dominion Energy utilized the after-tax proceeds, as required, to repay outstanding borrowings under a 364-day term loan facility. See Note 17 for additional information. The purchase price was subject to customary post-closing adjustments, including adjustments for cash, indebtedness, net working capital, capital expenditures and net regulatory assets and liabilities. The transaction was structured as a stock sale for tax purposes. In October 2023, as required under the sale agreement, Dominion Energy filed the notice with the Idaho Commission. The internal reorganization in connection with the Questar Gas Transaction was subject to approval by the Utah and Wyoming Commissions. Dominion Energy filed for such approvals in September 2023 which were received in November 2023. The internal reorganization was completed in February 2024.

Dominion Energy retained the pension and other postretirement benefit plan assets and obligations, including related income tax and other deferred balances, associated with retiree participants of the sale entities in the Dominion Energy Pension Plan and the Dominion Energy Retiree Health and Welfare Plan. Dominion Energy recognized a pre-tax gain of $2 million ($42 million after-tax gain) upon the closing of the transaction, including the write-off of $0.7 billion of goodwill which was not deductible for tax purposes and including the effects of final closing adjustments. In 2023, Dominion Energy recorded a charge of $236 million ($231 million after-tax), including amounts associated with an impairment of goodwill. Based on the recorded balances at March 31, 2024, Dominion Energy recorded an additional charge of $78 million ($78 million after-tax), including amounts associated with an impairment of goodwill, in the first quarter of 2024. Following the internal reorganization noted above and upon closing of the East Ohio Transaction, Dominion Energy recorded a tax benefit of $5 million. In 2023, Dominion Energy recorded a charge of $472 million to reflect the deferred taxes on the outside basis of Questar Gas, Wexpro and related affiliates’ stock upon meeting the classification as held for sale. These deferred taxes reversed in the first quarter of 2024 and became a component of current income tax expense. In addition, Dominion Energy recorded an incremental deferred tax benefit of $10 million to reflect the deferred taxes on the outside basis of Questar Gas, Wexpro and related affiliates’ stock in the first quarter of 2024. These deferred taxes reversed in the second quarter of 2024 upon closing of the sale and became a component of current income tax expense on the pre-tax loss on sale disclosed above. See Note 5 for additional information.

At the closing of the Questar Gas Transaction, Dominion Energy and Enbridge entered into a transition services agreement pursuant to which Dominion Energy will continue to provide certain services to support the ongoing operations of Questar Gas and Wexpro for up to approximately two years. Enbridge has also agreed to provide certain services to Dominion Energy.

Other Sales

In February 2024, Dominion Energy entered into an agreement with AES to sell Birdseye and the Madison solar project for approximately $17 million in cash, subject to customary closing adjustments, which closed in April 2024. Dominion Energy had

96

previously recognized a charge of $68 million ($51 million after-tax) in the fourth quarter of 2023 to adjust the assets down to their realizable fair value. As a result, the gain on the sale recognized by Dominion Energy in the second quarter of 2024, including the effects of final closing adjustments, was inconsequential.

In August 2023, Dominion Energy entered into an agreement and completed the sale of Tredegar Solar Fund I, LLC to Spruce Power for cash consideration of $21 million.

Financial Statement Information for Business Review Dispositions

The following table represents selected information regarding the results of operations, which were reported within discontinued operations in Dominion Energy’s Consolidated Statements of Income:

Year Ended December 31, 2024		East Ohio Transaction(1)				PSNC Transaction(1)				Questar Gas Transaction(1)				Other
(millions)
Operating revenue		$	229			$	488			$	894			$	—
Operating expense(2)			247				313				724				(8	)
Other income (expense)			(17	)			11				2				—
Interest and related charges			15				44				25				—
Income (loss) before income taxes			(50	)			142				147				8
Income tax expense			11				44				54				—
Net income (loss) attributable to Dominion Energy(3)		$	(61	)		$	98			$	93			$	8

(1)Represents amounts attributable to Dominion Energy prior to the closing of the East Ohio Transaction which closed on March 6, 2024, the PSNC Transaction which closed on September 30, 2024 and the Questar Gas Transaction which closed on May 31, 2024.

(2)East Ohio Transaction includes a charge of $45 million ($33 million after-tax) associated with an increase to certain pension retirement benefits attributable to a plan amendment and a contribution to the defined contribution employee savings plan. See Note 22 for further information on these transactions.

(3)Excludes $(69) million of income tax expense (benefit) attributable to consolidated state tax adjustments for the year ended December 31, 2024.

Year Ended December 31, 2023		East Ohio Transaction				PSNC Transaction				Questar Gas Transaction				Other
(millions)
Operating revenue		$	1,037			$	743			$	1,679			$	15
Operating expense(1)			701				517				1,554				111
Other income (expense)			30				11				8				—
Interest and related charges			71				52				68				1
Income (loss) before income taxes			295				185				65				(97	)
Income tax expense(2)			69				431				531				(38	)
Net income (loss) attributable to Dominion Energy(3)		$	226			$	(246	)		$	(466	)		$	(59	)

(1)East Ohio Transaction includes a charge of $50 million ($45 million after-tax) primarily for an impairment of associated goodwill, Questar Gas Transaction includes a charge of $236 million ($231 million after-tax) primarily for an impairment of associated goodwill and Other includes a charge of $68 million ($51 million after-tax) associated with the impairment of nonregulated solar generation facility development operations and a charge of $15 million ($11 million after-tax) associated with the impairment of certain nonregulated solar assets.

(2)Includes amounts to reflect the recognition of deferred taxes on the outside basis of the applicable entities’ stock upon meeting the classification as held for sale.

(3)Excludes $(3) million of income tax expense (benefit) attributable to consolidated state tax adjustments for the year ended December 31, 2023.

Capital expenditures and significant noncash items relating to the disposal groups included the following:

Year Ended December 31, 2024		East Ohio Transaction(1)				PSNC Transaction(1)				Questar Gas Transaction(1)				Other
(millions)
Capital expenditures		$	65			$	287			$	160			$	—
Significant noncash item
Depreciation, depletion and amortization			—				—				—				—

(1)Represents amounts attributable to Dominion Energy prior to the closing of the East Ohio Transaction which closed on March 6, 2024, the PSNC Transaction which closed on September 30, 2024 and the Questar Gas Transaction which closed on May 31, 2024.

Year Ended December 31, 2023		East Ohio Transaction				PSNC Transaction				Questar Gas Transaction				Other
(millions)
Capital expenditures		$	507			$	233			$	449			$	—
Significant noncash items
Depreciation, depletion and amortization			148				90				175				2
Accrued capital expenditures			42				43				32				—

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Combined Notes to Consolidated Financial Statements, Continued

Note 4. Operating Revenue

The Companies’ operating revenue consists of the following:

		Dominion Energy												Virginia Power
Year Ended December 31,		2025				2024				2023				2025				2024				2023
(millions)
Regulated electric sales:
Residential		$	6,080			$	5,436			$	5,141			$	4,631			$	4,133			$	3,863
Commercial			4,050				3,446				3,406				3,113				2,553				2,482
High load(1)			1,811				1,362				1,308				1,811				1,362				1,308
Industrial			729				716				729				301				300				282
Government and other retail			1,284				1,081				1,036				1,211				1,015				965
Wholesale			179				136				176				141				105				116
Nonregulated electric sales			1,239				933				758				127				86				65
Regulated gas sales:
Residential			352				309				293
Commercial			142				136				145
Other			46				67				79
Regulated gas transportation and storage			36				21				18
Other regulated revenues			309				372				253				291				359				238
Other nonregulated revenues(2)(3)(4)			266				167				145				66				46				53
Total operating revenue from contracts    with customers			16,523				14,182				13,487				11,692				9,959				9,372
Other revenues(2)(5)			(17	)			277				906				120				276				201
Total operating revenue		$	16,506			$	14,459			$	14,393			$	11,812			$	10,235			$	9,573

(1)Represents customers in Virginia, including certain data centers, with actual or anticipated forecast demand of 25 MW or higher and annual load factor of 75% or higher.

(2)See Note 25 for amounts attributable to affiliates.

(3)Includes sales of renewable energy credits of $57 million, $31 million and $44 million for the years ended December 31, 2025, 2024 and 2023, respectively, at Dominion Energy and $16 million, $12 million and $29 million for the years ended December 31, 2025, 2024 and 2023, respectively, at Virginia Power.

(4)Includes revenue from transition services agreements of $99 million, $61 million and $18 million for the years ended December 31, 2025, 2024 and 2023, respectively, at Dominion Energy.

(5)Includes alternative revenue of $167 million, $129 million and $162 million at both Dominion Energy and Virginia Power for years ended December 31, 2025, 2024 and 2023, respectively.

Neither Dominion Energy nor Virginia Power have any amounts for revenue to be recognized in the future on multi-year contracts in place at December 31, 2025.

Contract liabilities represent an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration, or the amount that is due, from the customer. At December 31, 2025 and 2024, Dominion Energy’s contract liability balances were $45 million and $52 million, respectively. At December 31, 2025 and 2024, Virginia Power’s contract liability balances were $38 million and $46 million, respectively. The Companies’ contract liabilities are recorded in other current liabilities and other deferred credits and other liabilities in the Consolidated Balance Sheets.

The Companies recognize revenue as they fulfill their obligations to provide service to their customers. During the years ended December 31, 2025 and 2024, Dominion Energy recognized revenue of $50 million and $45 million from the beginning contract liability balance. During the years ended December 31, 2025 and 2024, Virginia Power recognized revenue of $46 million and $40 million, respectively, from the beginning contract liability balance.

Note 5. Income Taxes

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws and associated regulations involves uncertainty, since tax authorities may interpret the laws differently. The Companies are routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

As indicated in Note 2, certain of the Companies’ operations, including accounting for income taxes, are subject to regulatory accounting treatment. For regulated operations, many of the changes in deferred taxes from the 2017 Tax Reform Act represent amounts probable of collection from or return to customers and are presented as components of regulatory assets or liabilities. See Note 12 for additional information.

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Continuing Operations

Details of income tax expense for continuing operations including noncontrolling interests were as follows:

		Dominion Energy												Virginia Power
Year Ended December 31,		2025				2024				2023				2025				2024				2023
(millions)
Current:
Federal		$	(580	)		$	(204	)		$	(361	)		$	163			$	(6	)		$	(102	)
State			54				37				(97	)			39				67				6
Total current expense (benefit)			(526	)			(167	)			(458	)			202				61				(96	)
Deferred:
Federal
Taxes before operating loss carryforwards and investment tax credits			539				521				815				167				324				403
Tax utilization expense of operating loss carryforwards			35				40				45				—				—				—
State			61				52				270				103				59				107
Total deferred expense			635				613				1,130				270				383				510
Investment tax credits			423				(35	)			(28	)			(24	)			(21	)			(14	)
Total income tax expense		$	532			$	411			$	644			$	448			$	423			$	400

In 2025, Dominion Energy’s current income taxes reflect a benefit from continuing operations primarily related to income tax credits generated during 2025. At December 31, 2025, Dominion Energy’s Consolidated Balance Sheet includes $402 million, presented in tax receivables, for the amount of credits generated in 2025 and expected to be carried back to tax year 2024 and refunded. Additionally, Dominion Energy and Virginia Power have recognized a current tax benefit from tax credits generated and transferred to third parties during 2025, as further discussed below.

In 2024, Dominion Energy’s current income taxes reflect a benefit from continuing operations as the income tax expense associated with the East Ohio, PSNC and Questar Gas Transactions, is reflected in discontinued operations. Dominion Energy’s income tax expense from continuing operations reflects the utilization of tax credit carryforwards to offset a portion of the federal tax on the gains from the East Ohio, PSNC and Questar Gas Transactions, presented in discontinued operations.

In 2023, Dominion Energy’s current income taxes reflect a benefit from continuing operations as the income tax expense associated with the East Ohio, PSNC and Questar Gas Transactions and Cove Point operations, including the Cove Point gain, is reflected in discontinued operations. Dominion Energy’s income tax expense from continuing operations reflects the utilization of investment tax credit carryforwards to offset a portion of the federal tax on the Cove Point gain, presented in discontinued operations.

Discontinued Operations

Income tax expense reflected in discontinued operations is $5 million, $31 million and $1.3 billion for the years ended December 31, 2025, 2024 and 2023, respectively. See Note 3 for a discussion of tax expense reflected in discontinued operations during the years ended December 31, 2024 and 2023.  In addition, Dominion Energy recorded tax expense of $278 million associated with completing the sale in September 2023 of its remaining 50% noncontrolling partnership interest in Cove Point to BHE as discussed in Note 9.

Continuing Operations

For continuing operations including noncontrolling interests for the year ended December 31, 2025, the statutory U.S. federal income tax rate reconciles to the Companies’ effective income tax rate as follows:

Year Ended December 31, 2025		Dominion Energy									Virginia Power
(millions, except percentages)		Amount				Rate					Amount				Rate
U.S. federal statutory tax		$	758				21.0		%		$	549				21.0		%
State and local income taxes, net of federal income tax effect(1)			109				3.0					112				4.3
Tax credits:
Production tax credits			(210	)			(5.8	)				(115	)			(4.4	)
Investment tax credit amortization			(87	)			(2.4	)				(21	)			(0.8	)
Nontaxable or nondeductible items:
Regulatory deferrals:
Reversal of excess deferred income taxes			(62	)			(1.7	)				(45	)			(1.7	)
AFUDC—equity			(28	)			(0.8	)				(27	)			(1.0	)
Absence of tax on noncontrolling interest			(14	)			(0.4	)				(14	)			(0.5	)
Changes in unrecognized tax benefits			(28	)			(0.8	)				1				0.1
Other adjustments:
Qualified nuclear decommissioning trust net gains (losses)			87				2.4					11				0.4
Other			7				0.2					(3	)			(0.3	)
Effective tax(2)		$	532				14.7		%		$	448				17.1		%

(1)State taxes in Virginia make up the majority (greater than 50%) of the tax effect in this category.

(2)The Companies had no adjustments related to the following disclosure categories: foreign tax effects, effects of changes in tax law or rates enacted in the current period and effects of cross-border tax laws.

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Combined Notes to Consolidated Financial Statements, Continued

For continuing operations including noncontrolling interests for the years ended December 31, 2024 and 2023, the statutory U.S. federal income tax rate reconciles to the Companies’ effective income tax rate as follows:

		Dominion Energy									Virginia Power
Year Ended December 31,		2024				2023					2024				2023
U.S. federal statutory tax     rate			21.0		%		21.0		%			21.0		%		21.0		%
Increases (reductions)     resulting from:
State taxes, net of     federal benefit			3.6				3.9					4.5				4.7
Investment tax credits			(1.6	)			(1.0	)				(0.9	)			(0.8	)
Production tax credits			(4.8	)			(0.6	)				(4.5	)			(0.8	)
Reversal of excess     deferred income     taxes			(3.1	)			(2.6	)				(2.0	)			(2.6	)
State legislative change			—				(0.1	)				—				—
Qualified nuclear     decommissioning     trust net gains     (losses)			4.4				2.7					0.6				0.6
Changes in state     deferred taxes     associated with     assets held for sale			—				1.1
AFUDC—equity			(0.7	)			—					(0.7	)			—
Settlements of     uncertain     tax positions			(0.7	)			(0.4	)				—				—
Employee stock     ownership plan     deduction			(0.3	)			(0.3	)
Other, net			0.9				(0.1	)				0.6				(0.4	)
Effective tax rate			18.7		%		23.6		%			18.6		%		21.7		%

The IRA created a nuclear production tax credit for electricity produced and sold beginning in 2024 and a clean fuel production tax credit for clean fuel produced and sold beginning in 2025. Dominion Energy’s and Virginia Power’s 2025 effective tax rate includes an $89 million income tax benefit for the nuclear production tax credit, and Dominion Energy’s effective tax rate also includes a $79 million income tax benefit for the clean fuel production tax credit.

In 2025, Dominion Energy and Virginia Power entered into agreements with third parties to transfer tax credits generated in 2024 and 2025. During 2025, Dominion Energy and Virginia Power received cash proceeds of $184 million and $168 million, respectively, related to the transfer of tax credits. In addition, Dominion Energy and Virginia Power expect to receive an additional $108 million and $18 million, respectively, in 2026 which are reflected in other receivables in the Companies’ Consolidated Balance Sheets at December 31, 2025. The Companies expect to continue to explore the ability to efficiently monetize their tax credits through third-party transfer agreements.

Dominion Energy’s and Virginia Power’s 2024 effective tax rate includes an $89 million tax benefit for the estimated net realizable value of the nuclear production tax credit.

The ultimate nuclear and clean fuel production tax credits realized by the Companies could vary significantly based on pending final U.S. Treasury guidance.

Dominion Energy’s 2023 effective tax rate includes a net income tax expense of $29 million associated with the remeasurement of consolidated state deferred taxes as a result of the East Ohio, PSNC and Questar Gas Transactions and sale of Dominion Energy’s 50% noncontrolling partnership interest in Cove Point as discussed in Notes 3 and 9, respectively.

The Companies’ income tax payments (net of refunds received and excluding amounts related to transfers of tax credits) for the year ended December 31, 2025, consist of the following:

		Dominion Energy				Virginia Power(1)
(millions)
Federal(2)		$	115			$	348
State:
Virginia(3)			68				36
Other states(4)			3				1
Total tax payments		$	186			$	385

(1)Virginia Power income tax payments (net of refunds received) include intercompany tax sharing payments and receipts with Dominion Energy as discussed in Note 2.

(2)Excludes income taxes paid by qualified nuclear decommissioning trusts of $37 million and $20 million at Dominion Energy and Virginia Power, respectively.

(3)Virginia income tax payments include Virginia minimum corporate taxes.

(4)There are no other states for which taxes paid exceeded five percent of total income taxes paid (net of refunds) for the Companies.

100

The Companies’ deferred income taxes consist of the following:

		Dominion Energy								Virginia Power
At December 31,		2025				2024				2025				2024
(millions)
Deferred income taxes:
Total deferred income tax assets		$	2,062			$	1,854			$	1,139			$	1,082
Total deferred income tax liabilities			9,947				8,989				6,060				5,558
Total net deferred income tax liabilities		$	7,885			$	7,135			$	4,921			$	4,476
Total deferred income taxes:
Depreciation method and plant basis differences		$	5,557			$	4,878			$	3,899			$	3,765
Excess deferred income taxes			(768	)			(790	)			(570	)			(587	)
Unrecovered nuclear plant cost			391				420
DESC rate refund			(34	)			(49	)
Toshiba Settlement			(119	)			(133	)
Nuclear decommissioning			2,038				1,973				899				781
Deferred state income taxes			1,154				1,010				789				672
Federal benefit of deferred state income taxes			(250	)			(222	)			(166	)			(141	)
Deferred fuel, purchased energy and gas costs			323				189				315				178
Pension benefits			382				345				(126	)			(116	)
Other postretirement benefits			226				174				155				141
Loss and credit carryforwards			(790	)			(680	)			—				—
Deferred unamortized investment tax credits			(352	)			(250	)			(153	)			(159	)
Valuation allowances			143				113				—				—
Partnership basis differences			(91	)			(30	)			(159	)			(98	)
Other			75				187				38				40
Total net deferred income tax liabilities		$	7,885			$	7,135			$	4,921			$	4,476

At December 31, 2025, Dominion Energy had the following deductible loss and credit carryforwards:

		Deductible Amount				Deferred Tax Asset				Valuation Allowance				Expiration Period
(millions)
Federal losses		$	222			$	47			$	—			2037
Federal production and other credits		—					61			—				2036-2045
State losses			2,389				119				(63	)		2026-2045
State minimum tax credits		—					444			—				No expiration
State investment and other credits		—					119				(69	)		2026-2034
Total		$	2,611			$	790			$	(132	)

At December 31, 2025, Virginia Power had no deductible loss or credit carryforwards.

A reconciliation of changes in the Companies’ unrecognized tax benefits follows:

		Dominion Energy												Virginia Power
		2025				2024				2023				2025				2024				2023
(millions)
Balance at January 1,		$	170			$	194			$	197			$	56			$	52			$	50
Prior period positions - increases			7				13				5				1				—				—
Prior period positions - decreases			(45	)			(18	)			(12	)			—				—				—
Current period positions - increases			—				8				4				—				4				2
Settlements with tax authorities			—				(13	)			—				—				—				—
Expiration of statutes of limitations			—				(14	)			—				—				—				—
Balance at December 31,		$	132			$	170			$	194			$	57			$	56			$	52

Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations. For Dominion Energy and its subsidiaries, these unrecognized tax benefits were $59 million, $87 million and $104 million at December 31, 2025, 2024 and 2023, respectively. For Virginia Power, these unrecognized tax benefits were $36 million, $35 million and $32 million at December 31, 2025, 2024 and 2023, respectively. In discontinued operations, these unrecognized tax benefits were $30 million, $32 million and $38 million at December 31, 2025, 2024 and 2023, respectively. For Dominion Energy, the change in these unrecognized tax benefits decreased income tax expense by $28 million, $19 million and $7 million in 2025, 2024 and 2023, respectively. For Virginia Power, the change in these unrecognized tax benefits increased income tax expense by $1 million in 2025 and by an inconsequential amount in 2024 and 2023.

Dominion Energy participates in the IRS Compliance Assurance Process, which provides the opportunity to resolve complex tax matters with the IRS before filing its federal income tax returns, thus achieving certainty for such tax return filing positions agreed to by the IRS. The IRS has completed its audit of tax years through 2019. The statute of limitations has not yet expired for years after 2019. Although Dominion Energy has not received a final letter indicating no changes to its taxable income for tax years 2020 through 2024, no material adjustments are expected. The IRS examination of tax year 2025 is ongoing.

101

Combined Notes to Consolidated Financial Statements, Continued

For each of the major states in which Dominion Energy operates or previously operated, the earliest tax year remaining open for examination is as follows:

State		Earliest Open Tax Year
Pennsylvania(1)		2012
Connecticut		2022
Virginia(2)		2022
Utah(1)		2022
South Carolina		2022

(1)Considered a major state for entities presented in discontinued operations.

(2)Considered a major state for Virginia Power’s operations.

The Companies are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion Energy utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are generally subject to examination.

Note 6. FAIR VALUE MEASUREMENTS

The Companies’ fair value measurements are made in accordance with the policies discussed in Note 2. See Note 7 for additional information about the Companies’ derivative and hedge accounting activities.

The Companies enter into certain physical and financial forwards, futures and options, which are considered Level 3 as they have one or more inputs that are not observable and are significant to the valuation. The discounted cash flow method is used to value Level 3 physical and financial forwards and futures contracts. An option model is used to value Level 3 physical options. The discounted cash flow model for forwards and futures calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return and credit spreads. The inputs into the option models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, the original sales prices and volumes. For Level 3 fair value measurements, certain forward market prices and implied price volatilities are considered unobservable.

The following table presents the Companies’ quantitative information about Level 3 fair value measurements at December 31, 2025. The range and weighted-average are presented in dollars for market price inputs and percentages for price volatility.

								Dominion Energy								Virginia Power
			Valuation Techniques		Unobservable Input			Fair Value (millions)			Range		Weighted-average(1)			Fair Value (millions)				Range		Weighted-average(1)
Assets
Physical and financial forwards:
Electricity			Discounted cash flow		Market price (per MWh)	(3)		$	224		29-111		54
FTRs			Discounted cash flow		Market price (per MWh)	(3)			156		(3)-19		9			$	156			(3)-19		9
Natural gas(2)			Discounted cash flow		Market price (per Dth)	(3)			48		(2)-8		(1)				48			(2)-8		(1)
Physical options:
Natural gas(2)			Option model		Market price (per Dth)	(3)			214		2-9		4				4			3-8		6
					Price volatility	(4)					0%-76%		47%							10%-64%		36%
Total assets								$	642							$	208
Liabilities
Physical and financial forwards:
Electricity			Discounted cash flow		Market price (per MWh)	(3)			15		31-117		62
Total liabilities								$	15

(1)Averages weighted by volume.

(2)Includes basis.

(3)Represents market prices beyond defined terms for Levels 1 and 2.

(4)Represents volatilities unrepresented in published markets.

Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

Significant Unobservable Inputs		Position		Change to Input		Impact on Fair Value Measurement
Market price		Buy		Increase (decrease)		Gain (loss)
Market price		Sell		Increase (decrease)		Loss (gain)
Price volatility		Buy		Increase (decrease)		Gain (loss)
Price volatility		Sell		Increase (decrease)		Loss (gain)

Nonrecurring Fair Value Measurements

See Note 10 for information regarding impairment charges recorded by Dominion Energy associated with corporate office buildings and nonregulated renewable natural gas facilities. See Note 22 for information regarding Dominion Energy’s pension and other postretirement benefit plan remeasurements.

102

In 2023, Dominion Energy recorded a charge of $15 million ($11 million after-tax) presented within discontinued operations in its Consolidated Statements of Income to adjust certain nonregulated solar assets down to their estimated fair value, using a market approach, of $22 million. The valuation is considered a Level 2 fair value measurement given that it is based on bids received. As discussed in Note 3, these assets were sold in August 2023.

Recurring Fair Value Measurements

Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3. Fair value disclosures for assets held in the Companies’ pension and other postretirement benefit plans are presented in Note 22.

The following table presents the Companies’ assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:

		Dominion Energy																Virginia Power
		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
(millions)
December 31, 2025
Assets
Derivatives:
Commodity		$	—			$	87			$	642			$	729			$	—			$	49			$	208			$	257
Interest rate			—				201				—				201				—				197				—				197
Foreign currency exchange rate			—				28				—				28				—				28				—				28
Investments(1):
Equity securities:
U.S.			6,215				—				—				6,215				3,154				—				—				3,154
International			168				—				—				168				96				—				—				96
Fixed income:
Corporate debt instruments			—				10				—				10				—				—				—				—
Government securities			418				74				—				492				332				—				—				332
Cash equivalents and other			46				—				—				46				—				—				—				—
Total assets		$	6,847			$	400			$	642			$	7,889			$	3,582			$	274			$	208			$	4,064
Liabilities
Derivatives:
Commodity		$	—			$	201			$	15			$	216			$	—			$	13			$	—			$	13
Interest rate			—				19				—				19				—				8				—				8
Foreign currency exchange rate			—				10				—				10				—				10				—				10
Total liabilities		$	—			$	230			$	15			$	245			$	—			$	31			$	—			$	31
December 31, 2024
Assets
Derivatives:
Commodity		$ —				$	95			$	399			$	494			$ —				$	45			$	70			$	115
Interest rate		—					875			—					875			—					230			—					230
Foreign currency exchange rate		—					30			—					30			—					30			—					30
Investments(1):
Equity securities:
U.S.			5,403				2			—					5,405				2,769				2			—					2,771
International			165			—				—					165				99			—				—					99
Fixed income:
Corporate debt instruments		—					518			—					518			—					294			—					294
Government securities			138				1,605			—					1,743				85				939			—					1,024
Cash equivalents and other			29			—				—					29			—				—				—				—
Total assets		$	5,735			$	3,125			$	399			$	9,259			$	2,953			$	1,540			$	70			$	4,563
Liabilities
Derivatives:
Commodity		$ —				$	108			$	15			$	123			$ —				$	31			$	2			$	33
Interest rate		—					197			—					197			—				—				—				—
Foreign currency exchange rate		—					192			—					192			—					192			—					192
Total liabilities		$	—			$	497			$	15			$	512			$	—			$	223			$	2			$	225

(1)Includes investments held in the nuclear decommissioning trusts and rabbi trusts. Excludes $2.3 billion and $212 million of assets at Dominion Energy, inclusive of $1.3 billion and $76 million at Virginia Power, at December 31, 2025 and 2024, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

103

Combined Notes to Consolidated Financial Statements, Continued

The following table presents the net change in the Companies’ assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:

		Dominion Energy												Virginia Power
		2025				2024				2023				2025				2024				2023
(millions)
Beginning balance		$	384			$	86			$	422			$	68			$	(116	)		$	221
Total realized and unrealized gains (losses):
Included in earnings:
Operating revenue			(21	)			(6	)			1
Electric fuel and other energy-related purchases			276				(172	)			(273	)			259				(176	)			(278	)
Purchased gas			—				1				—
Discontinued operations			—				(4	)			(1	)
Included in regulatory assets/liabilities			121				297				(414	)			145				202				(349	)
Settlements			(336	)			77				241				(272	)			137				255
Purchases			183				112				104				8				21				35
Transfers out of Level 3			20				(7	)			6
Ending balance		$	627			$	384			$	86			$	208			$	68			$	(116	)

Dominion Energy had a $1 million gain, a $(5) million loss and a $7 million gain included in earnings in the Level 3 fair value category related to assets/liabilities still held at the reporting date for the years ended December 31, 2025, 2024 and 2023, respectively. Virginia Power had no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2025, 2024 and 2023.

Fair Value of Financial Instruments

Substantially all of the Companies’ financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash, restricted cash and equivalents, customer and other receivables, affiliated receivables, short-term debt, affiliated current borrowings, payables to affiliates and accounts payable are representative of fair value because of the short-term nature of these instruments. For the Companies’ financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:

		Dominion Energy								Virginia Power
		Carrying Amount				Estimated Fair Value(1)				Carrying Amount				Estimated Fair Value(1)
(millions)
December 31, 2025
Long-term debt(2)		$	38,897			$	37,481			$	21,800			$	20,593
Securitization bonds(3)			1,054				1,076				1,054				1,076
Junior subordinated notes(2)			5,978				6,217
December 31, 2024
Long-term debt(2)		$	34,533			$	32,167			$	19,224			$	17,578
Securitization bonds(3)			1,217				1,218				1,217				1,218
Junior subordinated notes(2)			3,223				3,372

(1)Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2)Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs and discount or premium. There were no fair value hedges associated with fixed-rate debt at December 31, 2025 and December 31, 2024.

(3)Carrying amount includes current portions included in securities due within one year.

Note 7. Derivatives And Hedge Accounting Activities

See Note 2 for the Companies’ accounting policies, objectives and strategies for using derivative instruments. See Notes 2 and 6 for further information about fair value measurements and associated valuation methods for derivatives.

Cash collateral is used in the table below to offset derivative assets and liabilities. Certain of Dominion Energy’s contracts represent offsetting positions to other existing exchange contracts with collateral requirements. Additionally, certain of Dominion Energy’s over-the-counter transactions are not subject to collateral requirements. These contracts resulted in positions which limit the risk of increased cash collateral requirements. Certain accounts receivable and accounts payable recognized on the Companies’ Consolidated Balance Sheets, letters of credit and other forms of securities, as well as certain other long-term debt, all of which are not included in the tables below, are subject to offset under master netting or similar arrangements and would reduce the net exposure. See Note 24 for further information regarding credit-related contingent features for the Companies derivative instruments.

104

Balance Sheet Presentation

The tables below present the Companies’ derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

	Dominion Energy Gross Amounts Not Offset in the Consolidated Balance Sheet																Virginia Power Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet(1)				Financial Instruments				Cash Collateral Received				Net Amounts				Gross Assets Presented in the Consolidated Balance Sheet(1)				Financial Instruments				Cash Collateral Received				Net Amounts
(millions)
December 31, 2025
Commodity contracts:
Over-the-counter	$	464			$	4			$	—			$	460			$	239			$	4			$	—			$	235
Exchange		48				48				—				—				—				—				—				—
Interest rate contracts:
Over-the-counter		201				5				—				196				197				4				—				193
Foreign currency exchange rate contracts:
Over-the-counter		28				8				—				20				28				8				—				20
Total derivatives, subject to a master netting    or similar arrangement	$	741			$	65			$	—			$	676			$	464			$	16			$	—			$	448
December 31, 2024
Commodity contracts:
Over-the-counter	$	197			$	20			$	—			$	177			$	95			$	14			$	—			$	81
Exchange		55				54				—				1				2				1				—				1
Interest rate contracts:
Over-the-counter		875				197				—				678				230				—				—				230
Foreign currency exchange rate contracts:
Over-the-counter		30				30				—				—				30				30				—				—
Total derivatives, subject to a master netting    or similar arrangement	$	1,157			$	301			$	—			$	856			$	357			$	45			$	—			$	312

(1)Excludes derivative assets of $217 million and $242 million at Dominion Energy at December 31, 2025 and 2024, respectively, and $18 million at Virginia Power, at both December 31, 2025 and 2024, which are not subject to master netting or similar arrangements.

	Dominion Energy Gross Amounts Not Offset in the Consolidated Balance Sheet																Virginia Power Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet(1)				Financial Instruments				Cash Collateral Paid				Net Amounts				Gross Liabilities Presented in the Consolidated Balance Sheet(1)				Financial Instruments				Cash Collateral Paid				Net Amounts
(millions)
December 31, 2025
Commodity contracts:
Over-the-counter	$	38			$	4			$	—			$	34			$	6			$	4			$	—			$	2
Exchange		173				48				125				—				—				—				—				—
Interest rate contracts:
Over-the-counter		19				5				—				14				8				4				—				4
Foreign currency exchange rate contracts:
Over-the-counter		10				8				—				2				10				8				—				2
Total derivatives, subject to a master netting    or similar arrangement	$	240			$	65			$	125			$	50			$	24			$	16			$	—			$	8
December 31, 2024
Commodity contracts:
Over-the-counter	$	42			$	20			$	—			$	22			$	15			$	14			$	—			$	1
Exchange		74				54				20				—				1				1				—				—
Interest rate contracts:
Over-the-counter		197				197				—				—				—				—				—				—
Foreign currency exchange rate contracts:
Over-the-counter		192				30				—				162				192				30				—				162
Total derivatives, subject to a master netting    or similar arrangement	$	505			$	301			$	20			$	184			$	208			$	45			$	—			$	163

(1)Excludes derivative liabilities of $5 million and $7 million at Dominion Energy and $7 million and $17 million at Virginia Power at December 31, 2025 and 2024, respectively, which are not subject to master netting or similar arrangements.

105

Combined Notes to Consolidated Financial Statements, Continued

Volumes

The following table presents the volume of the Companies’ derivative activity at December 31, 2025. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

		Dominion Energy								Virginia Power
		Current				Noncurrent				Current				Noncurrent
Natural Gas (bcf):
Fixed price(1)			42				5				37				5
Basis(2)			217				330				164				268
Electricity (MWh in millions):
Fixed price			9				35
FTRs			40								40
Interest rate(3) (in millions)		$	3,925			$	6,821			$	2,350			$	5,750
Foreign currency exchange rate(3) (in millions)
Danish Krone		674 kr.				76 kr.				674 kr.				76 kr.
Euro		€844				€50				€844				€50

(1)Includes options at Dominion Energy.

(2)Includes options.

(3)Maturity is determined based on final settlement period.

AOCI

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in the Companies’ Consolidated Balance Sheets at December 31, 2025:

		Dominion Energy										Virginia Power
		AOCI After-Tax				Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax				Maximum Term		AOCI After-Tax				Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax				Maximum Term
(millions)										(months)										(months)
Interest rate		$	(137	)		$	(24	)		396		$	32			$	1				396
Total		$	(137	)		$	(24	)				$	32			$	1

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest rate payments) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in interest rates.

106

Fair Value and Gains and Losses on Derivative Instruments

The following tables present the fair values of the Companies’ derivatives and where they are presented in their Consolidated Balance Sheets:

		Dominion Energy								Virginia Power
		Assets				Liabilities				Assets				Liabilities
(millions)
At December 31, 2025
Current derivatives not under cash flow hedge accounting
Commodity		$	295			$	98			$	172			$	12
Interest rate			—				3
Foreign currency exchange rate			25				10				25				10
Current derivatives under cash flow hedge accounting
Interest rate			15				—				15				—
Total current derivatives		$	335			$	111			$	212			$	22
Noncurrent derivatives not under cash flow hedge accounting
Commodity		$	434			$	118			$	85			$	1
Interest rate			2				7
Foreign currency exchange rate			3				—				3				—
Noncurrent derivatives under cash flow hedge accounting
Interest rate			184				9				182				8
Total noncurrent derivatives			623				134				270				9
Total derivatives		$	958			$	245			$	482			$	31
At December 31, 2024
Current derivatives not under cash flow hedge accounting
Commodity		$	171			$	78			$	84			$	32
Interest rate			101				22
Foreign currency exchange rate			27				107				27				107
Current derivatives under cash flow hedge accounting
Interest rate			137				—				137				—
Total current derivatives		$	436			$	207			$	248			$	139
Noncurrent derivatives not under cash flow hedge accounting
Commodity		$	323			$	45			$	31			$	1
Interest rate			544				175
Foreign currency exchange rate			3				85				3				85
Noncurrent derivatives under cash flow hedge accounting
Interest rate			93				—				93				—
Total noncurrent derivatives			963				305				127				86
Total derivatives		$	1,399			$	512			$	375			$	225

The following tables present the gains and losses on the Companies’ derivatives, as well as where the associated activity is presented in their Consolidated Balance Sheets and Statements of Income:

		Dominion Energy												Virginia Power
Derivatives in cash flow hedging relationships		Amount of Gain (Loss) Recognized in AOCI on Derivatives(1)				Amount of Gain (Loss) Reclassified from AOCI  to Income				Increase (Decrease)  in Derivatives Subject to Regulatory Treatment(2)				Amount of Gain (Loss) Recognized in AOCI on Derivatives(1)				Amount of Gain (Loss) Reclassified from AOCI  to Income				Increase  (Decrease)  in Derivatives Subject to Regulatory Treatment(2)
(millions)
Year Ended December 31, 2025
Derivative type and location of gains (losses):
Interest rate(3)		$	7			$	(39	)		$	67			$	6			$	1			$	66
Total		$	7			$	(39	)		$	67			$	6			$	1			$	66
Year Ended December 31, 2024
Derivative type and location of gains (losses):
Interest rate(3)		$	17				(43	)		$	189			$	17			$	—			$	188
Total		$	17			$	(43	)		$	189			$	17			$	—			$	188
Year Ended December 31, 2023
Derivative type and location of gains (losses):
Interest rate(3)		$	(1	)			(43	)		$	5			$	(1	)		$	(1	)		$	4
Total		$	(1	)		$	(43	)		$	5			$	(1	)		$	(1	)		$	4

(1)Amounts deferred into AOCI have no associated effect in the Companies’ Consolidated Statements of Income.

(2)Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in the Companies’ Consolidated Statements of Income.

(3)Amounts recorded in the Companies’ Consolidated Statements of Income are classified in interest and related charges.

107

Combined Notes to Consolidated Financial Statements, Continued

		Amount of Gain (Loss) Recognized in Income on Derivatives(1)(2)
Derivatives not designated as hedging instruments		Dominion Energy												Virginia Power
Year Ended December 31,		2025				2024				2023				2025				2024				2023
(millions)
Derivative type and location of gains (losses):
Commodity:
Operating revenue		$	(221	)		$	116			$	707			$	(59	)		$	140			$	27
Purchased gas			(1	)			—				—
Electric fuel and other energy-related purchases			246				(240	)			(380	)			229				(244	)			(384	)
Discontinued operations			—				(28	)			86
Other operations & maintenance			—				—				2				—				—				2
Interest rate:
Interest and related charges			13				(3	)			84
Discontinued operations			—				—				17
Total		$	37			$	(155	)		$	516			$	170			$	(104	)		$	(355	)

(1)Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in the Companies’ Consolidated Statements of Income.

(2)Excludes amounts related to foreign currency exchange rate derivatives that are deferred to plant under construction within property, plant and equipment and regulatory assets/liabilities that will begin to amortize once the CVOW Commercial Project is placed in service.

Note 8. Earnings Per Share

The following table presents the calculation of Dominion Energy’s basic and diluted EPS:

	2025				2024				2023
(millions, except EPS)
Net income attributable to Dominion Energy from continuing operations	$	3,012			$	1,837			$	2,087
Preferred stock dividends (See Note 19)		(44	)			(68	)			(81	)
Preferred stock deemed dividends (See Note 19)		—				(10	)			—
Net income attributable to Dominion Energy from continuing operations - Basic & Diluted		2,968				1,759				2,006
Net income (loss) attributable to Dominion Energy from discontinued operations - Basic &    Diluted	$	(14	)		$	197			$	(125	)
Average shares of common stock outstanding – Basic		854.1				839.2				836.4
Net effect of dilutive securities(1)		1.2				0.2				0.1
Average shares of common stock outstanding – Diluted		855.3				839.4				836.5
EPS from continuing operations - Basic	$	3.48			$	2.09			$	2.40
EPS from discontinued operations - Basic		(0.02	)			0.24				(0.15	)
EPS attributable to Dominion Energy - Basic	$	3.46			$	2.33			$	2.25
EPS from continuing operations - Diluted	$	3.47			$	2.09			$	2.40
EPS from discontinued operations - Diluted		(0.02	)			0.24				(0.15	)
EPS attributable to Dominion Energy - Diluted	$	3.45			$	2.33			$	2.25

(1)Dilutive securities for 2025 consists of forward sales agreements entered into in the first, second, and third quarter of 2025 and third and fourth quarter of 2024 with certain of these securities settling in 2025 (applying the treasury stock method). Additionally, dilutive securities for 2024 consists of certain of the forward sales agreements entered into in 2024 with certain of these securities settling in 2024 (applying the treasury stock method). Dilutive securities for 2023 consists primarily of stock potentially to be issued to satisfy the obligation under a settlement agreement with the SCDOR (applying the if converted method).

Certain of the forward sales agreements entered into in 2025 and 2024 were potentially dilutive securities but were excluded from the calculation of diluted EPS from continuing operations for the year ended December 31, 2025 and 2024 as the dilutive stock price threshold was not met. See Note 19 for additional information.

Note 9. Investments

Equity and Debt Securities

Rabbi Trust Securities

Equity and fixed income securities and cash equivalents in Dominion Energy’s rabbi trusts and classified as trading totaled $181 million and $160 million at December 31, 2025 and 2024, respectively.

108

Decommissioning Trust Securities

The Companies hold equity and fixed income securities and cash equivalents, and Dominion Energy also holds insurance contracts, in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. The Companies’ decommissioning trust funds are summarized below:

				Dominion Energy														Virginia Power
	Amortized Cost			Total Unrealized Gains			Total Unrealized Losses				Allowance for Credit Losses			Fair Value				Amortized Cost			Total Unrealized Gains			Total Unrealized Losses				Allowance for Credit Losses			Fair Value
(millions)
December 31, 2025
Equity securities:(1)
U.S.	$	1,107		$	5,052		$	(2	)					$	6,157			$	602		$	2,620		$	(2	)					$	3,220
International		44			122			—							166				27			69			—							96
Fixed income securities:(2)
Government securities		448			—			—			$	—			448				332			—			—			$	—			332
Private debt funds(3)		2,143			—			—				—			2,143				1,213			—			—				—			1,213
Insurance contracts(4)		245			—			—				—			245
Cash equivalents and    other(5)		7			—			—				—			7				3			—			—				—			3
Total	$	3,994		$	5,174		$	(2	)	(6)	$	—		$	9,166			$	2,177		$	2,689		$	(2	)	(6)	$	—		$	4,864
December 31, 2024
Equity securities:(1)
U.S.	$	1,220		$	4,157		$	(4	)					$	5,373			$	695		$	2,155		$	(3	)					$	2,847
International		52			111			—							163				34			65			—							99
Fixed income securities:(2)
Corporate debt instruments		516			6			(15	)		$	—			507				303			3			(12	)		$	—			294
Government securities		1,736			7			(39	)			—			1,704				1,038			4			(18	)			—			1,024
Insurance contracts(4)		239			—			—							239
Cash equivalents and    other(5)		65			—			—				—			65				22			—			—				—			22
Total	$	3,828		$	4,281		$	(58	)	(6)	$	—		$	8,051			$	2,092		$	2,227		$	(33	)	(6)	$	—		$	4,286

(1)Unrealized gains and losses on equity securities are included in other income (expense) and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(2)Unrealized gains and losses on fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2. Changes in allowance for credit losses are included in other income (expense).

(3)These private debt funds are generally structured without an explicit termination date. The Companies’ withdrawal and redemption rights begin after an initial multiyear lock-up period. Unless otherwise elected, distributions of income, profits and capital are generally reinvested in the underlying funds. The Companies may elect to receive a portion of future income as cash distributions, subject to fund liquidity restrictions. Generally, the Companies’ interests can be sold in the secondary markets subject to the approval of the general partner. Secondary markets tend to be less liquid especially during periods of market stress.

(4)Includes company owned life insurance contracts measured at cash surrender value.

(5)Dominion Energy includes pending purchases of securities of $40 million and pending sales of securities of $35 million at December 31, 2025 and 2024, respectively. Virginia Power includes pending sales of securities of $3 million and $22 million at December 31, 2025 and 2024, respectively.

(6)Dominion Energy’s fair value of securities in an unrealized loss position was $48 million and $1.4 billion at December 31, 2025 and 2024, respectively. Virginia Power’s fair value of securities in an unrealized loss position was $3 million and $796 million at December 31, 2025 and 2024, respectively.

The portion of unrealized gains and losses that relates to equity securities held within Dominion Energy and Virginia Power’s nuclear decommissioning trusts is summarized below:

		Dominion Energy
Year Ended December 31,		2025				2024				2023
(millions)
Net gains (losses) recognized    during the period		$	913			$	1,020			$	811
Less: Net (gains) losses    recognized during the    period on securities sold    during the period			(4	)			(16	)			(7	)
Unrealized gains (losses)    recognized during the    period on securities still held    at period end(1)		$	909			$	1,004			$	804

(1) Included in other income (expense) and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

		Virginia Power
Year Ended December 31,		2025				2024				2023
(millions)
Net gains (losses) recognized    during the period		$	479			$	532			$	420
Less: Net (gains) losses    recognized during the    period on securities sold    during the period			(8	)			(11	)			7
Unrealized gains (losses)    recognized during the    period on securities still held    at period end(1)		$	471			$	521			$	427

(1) Included in other income (expense) and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

109

Combined Notes to Consolidated Financial Statements, Continued

The fair value of Dominion Energy and Virginia Power’s fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2025 by contractual maturity is as follows:

		Dominion Energy				Virginia Power
(millions)
Due in one year or less			—				—
Due after one year through five years			25				—
Due after five years through ten years			10				—
Due after ten years			413				332
Total		$	448			$	332

Presented below is selected information regarding Dominion Energy and Virginia Power’s equity and fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds.

	Dominion Energy
Year Ended December 31,	2025			2024			2023
(millions)
Proceeds from sales	$	10,492		$	3,072		$	2,966
Realized gains(1)		110			106			92
Realized losses(1)		103			128			169

(1)Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.

	Virginia Power
Year Ended December 31,	2025			2024			2023
(millions)
Proceeds from sales	$	5,741		$	1,925		$	1,876
Realized gains(1)		74			67			50
Realized losses(1)		71			88			99

(1)Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.

Equity Method Investments

Investments that Dominion Energy accounts for under the equity method of accounting are as follows:

Company	Ownership%			Investment Balance							Description
At December 31,				2025			2024
(millions)
Align RNG		50	%	$	92		$	91			Renewable natural gas
Dominion    Privatization		50	%		20			27			Military electric and gas
Other(1)(2)	various				20			20
Total				$	132		$	138

(1)Dominion Energy’s Consolidated Balance Sheets include a liability associated with its investment in Atlantic Coast Pipeline of $4 million and $7 million at December 31, 2025 and 2024, respectively, presented in other current liabilities. See discussion below for additional information.

(2)Includes an inconsequential amount at December 31, 2025 related to Valley Link.

Dominion Energy recorded equity earnings (losses) on its investments of $(6) million, $3 million and $(26) million for the years ended December 31, 2025, 2024 and 2023, respectively, in other income (expense) in its Consolidated Statements of Income. In addition, Dominion Energy recorded equity earnings (losses) of $(6) million, $(12) million and $235 million for the years ended December 31, 2025, 2024 and 2023, respectively, in discontinued operations including amounts related to its investments in Cove Point (through September 2023) and Atlantic Coast Pipeline discussed below. Dominion Energy received distributions from these investments of $6 million, $140 million and $245 million for the years ended December 31, 2025, 2024 and 2023, respectively. At both December 31, 2025 and 2024, the net difference between the carrying amount of Dominion Energy’s investments and its share of underlying equity in net assets was $5 million, which is attributable to capitalized interest.

Cove Point

Prior to the completion of the sale to BHE in September 2023, Dominion held a 50% noncontrolling limited partnership interest in Cove Point which was accounted for as an equity method investment as Dominion Energy had the ability to exercise significant influence over, but not control, Cove Point.

Dominion Energy recorded distributions from Cove Point of $227 million for the year ended December 31, 2023. Dominion Energy made no contributions to Cove Point for the year ended December 31, 2023.

In June 2023, Dominion Energy entered into an agreement with Cove Point for transportation and storage services at market rates for a 20-year period commencing August 2023.

In July 2023, Dominion Energy entered into an agreement to sell its 50% noncontrolling limited partnership interest in Cove Point to BHE for cash consideration of $3.3 billion which closed in September 2023 after all customary closing and regulatory conditions were satisfied, including clearance under the Hart-Scott-Rodino Act and approval from the DOE. The sale is treated as an asset sale for tax purposes. In addition, Dominion Energy received proceeds of $199 million from the settlement of related interest rate derivatives. In connection with closing, Dominion Energy utilized proceeds, as required, to repay DECP Holding’s term loan secured by its noncontrolling interest in Cove Point, which had an outstanding balance of $2.2 billion, and $750 million of outstanding borrowings under Dominion Energy’s two $600 million 364-day term loan facilities entered in July 2023. See Note 17 for additional information on these facilities. Dominion Energy recorded a gain on the sale of its noncontrolling interest in Cove Point of $626 million ($348 million after-tax) within discontinued operations in its Consolidated Statements of Income for the year ended December 31, 2023.

In September 2023, as a result of Dominion Energy entering agreements for the East Ohio, PSNC and Questar Gas Transactions, Dominion Energy’s 50% noncontrolling limited partnership interest in Cove Point also met the requirements to be presented as discontinued operations and held for sale (through the date of disposal) as both disposition activities were executed in connection with Dominion Energy’s comprehensive business review announced in November 2022. In addition, interest expense associated with DECP Holding’s term loan secured by its noncontrolling interest in Cove Point and related interest rate derivatives have been classified as discontinued operations.

Amounts presented in discontinued operations within Dominion Energy's Consolidated Statements of Income for the year ended December 31, 2023 include $218 million for earnings on equity method investees, $120 million of interest expense and $31 million of income tax expense, in addition to the gain on sale and associated tax expense disclosed above.

110

All activity relating to Dominion Energy’s noncontrolling interest in Cove Point is recorded within the Corporate and Other segment.

Atlantic Coast Pipeline

In September 2014, Dominion Energy, along with Duke Energy and Southern, announced the formation of the Atlantic Coast Pipeline for the purpose of constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. Following Dominion Energy’s acquisition from Southern of its 5% interest in Atlantic Coast Pipeline in 2020, Dominion Energy owns a 53% noncontrolling membership interest in Atlantic Coast Pipeline with Duke Energy owning the remaining interest.

Atlantic Coast Pipeline continues to be accounted for as an equity method investment as the power to direct the activities most significant to Atlantic Coast Pipeline is shared with Duke Energy. As a result, Dominion Energy has the ability to exercise significant influence, but not control, over the investee.

In July 2020, as a result of ongoing permitting delays, growing legal uncertainties and the need to incur significant capital expenditures to maintain project timing before such uncertainties could be resolved, Dominion Energy and Duke Energy announced the cancellation of the Atlantic Coast Pipeline Project.

Dominion Energy recorded earnings (losses) on equity method investees of $(6) million ($(4) million after-tax), $(13) million ($(10) million after-tax) and $15 million ($11 million after-tax) for the years ended December 31, 2025, 2024 and 2023, respectively. In connection with Dominion Energy’s decision to sell substantially all of its gas transmission and storage operations, Dominion Energy has reflected the results of its equity method investment in Atlantic Coast Pipeline as discontinued operations in its Consolidated Statements of Income. As a result of its share of equity losses exceeding its investment, Dominion Energy’s Consolidated Balance Sheets at December 31, 2025 and 2024 include a liability of $4 million and $7 million, respectively, presented in other current liabilities and reflecting Dominion Energy’s obligations to Atlantic Coast Pipeline related to AROs.

Dominion Energy recorded contributions of $10 million, $12 million and $95 million during the years ended December 31, 2025, 2024 and 2023, respectively, to Atlantic Coast Pipeline.

Dominion Energy expects it could incur additional losses from Atlantic Coast Pipeline as it completes wind-down activities. While Dominion Energy is unable to precisely estimate the amounts to be incurred by Atlantic Coast Pipeline, the portion of such amounts attributable to Dominion Energy is not expected to be material to Dominion Energy’s results of operations, financial position or statement of cash flows.

All activity relating to Atlantic Coast Pipeline is recorded within the Corporate and Other segment.

Align RNG

In 2025, Dominion Energy entered into and completed the acquisition of tax credits from Align RNG for a total cost of approximately $13 million.

In the fourth quarter of 2023, Dominion Energy reflected its share of an impairment of certain property, plant and equipment at Align RNG totaling $35 million ($26 million after-tax) in other income (expense) in its Consolidated Statements of Income. All activity related to Align RNG is reflected within Contracted Energy.

Dominion Privatization

In February 2024, Dominion Energy received a distribution of $126 million from Dominion Privatization, which was accounted for as a return of an investment. Additionally, at December 31, 2025, Dominion Privatization had a credit facility with Dominion Energy with a maximum capacity of $50 million, of which Dominion Privatization had $10 million of borrowings outstanding reflected in other receivables in Dominion Energy’s Consolidated Balance Sheet.

Note 10. Property, Plant And Equipment

Major classes of property, plant and equipment and their respective balances for the Companies are as follows:

		Dominion Energy								Virginia Power
At December 31,		2025				2024				2025				2024
(millions)
Utility:
Generation		$	28,091			$	26,854			$	20,859			$	20,219
Transmission			19,609				17,856				17,164				15,514
Distribution			25,515				23,572				18,784				17,261
Nuclear fuel			2,439				2,393				1,936				1,823
General and other			1,981				1,865				1,171				1,134
Plant under    construction(1)			19,199				13,816				18,382				12,826
Total utility			96,834				86,356				78,296				68,777
Non-jurisdictional -    including plant    under construction			1,815				1,763				1,815				1,763
Nonutility:
Nonregulated    generation-    nuclear			2,027				1,962				—				—
Nonregulated    generation-solar			1,594				1,207				—				—
Nuclear fuel			1,018				1,173				—				—
Renewable natural     gas			1,734				—
Other-including    plant under    construction			1,293				2,383				10				10
Total nonutility			7,666				6,725				10				10
Total property, plant    and equipment		$	106,315			$	94,844			$	80,121			$	70,550

(1)Includes $8.6 billion and $5.8 billion of costs associated with the CVOW Commercial Project at December 31, 2025 and 2024, respectively. The amounts at December 31, 2025 and 2024 are net of $721 million and $206 million, respectively, of costs not expected to be recovered from customers.

111

Combined Notes to Consolidated Financial Statements, Continued

Jointly-Owned Power Stations

The Companies’ proportionate share of jointly-owned power stations at December 31, 2025 is as follows:

		Bath County Pumped Storage Station(1)				North Anna Units 1 and 2(1)				Clover Power Station(1)				Millstone Unit 3(2)			Summer Unit 1 (2)
(millions, except percentages)
Ownership    interest			60	%			88.4	%			50	%			93.5	%		66.7	%
Plant in service			1,094				3,051				618				1,549			1,580
Accumulated    depreciation			(782	)			(1,451	)			(326	)			(661	)		(775	)
Nuclear fuel			—				835				—				466			503
Accumulated    amortization of    nuclear fuel			—				(644	)			—				(352	)		(307	)
Plant under    construction			16				529				13				96			55

(1) Units jointly owned by Virginia Power.

(2) Units jointly owned by Dominion Energy.

The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. The Companies report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation and amortization, other taxes and other applicable accounts) in the Consolidated Statements of Income.

Canadys Station

As discussed in Note 13, in December 2025, DESC and Santee Cooper filed an application with the South Carolina Commission for approval of a CPCN to jointly construct and operate Canadys Station. At December 31, 2025, Dominion Energy’s Consolidated Balance Sheet includes $10 million within plant under construction reflected in property, plant and equipment for its share of the total costs.

CVOW Commercial Project – Estimated Total Project Cost

In September 2019, Virginia Power filed applications with PJM for the CVOW Commercial Project and for certain approvals and rider recovery from the Virginia Commission in November 2021. The Virginia Commission provided such approvals in August 2022, as revised for certain provisions related to rider recovery in December 2022. The majority of turbines comprising the 2.6 GW project are expected to be placed in service by the end of 2026 with the remainder in early 2027. The estimated total project cost is approximately $11.5 billion (excluding financing costs) which reflects a temporary suspension of work order and an estimated impact of certain tariffs which became effective during 2025 as well as the previously included revised estimate of network upgrade costs assigned by PJM to the CVOW Commercial Project. The Companies’ projected impact of tariffs on expected total project cost is subject to change due to the inherent uncertainty associated with which tariffs, if any, may be in effect and the associated requirements and rates of such tariffs.

The expected total project cost reflects an increase of $0.2 billion, relative to Virginia Power’s October 2025 Rider OSW filing, associated with projected installation timeline changes arising from the temporary suspension of work from the BOEM Director’s Order issued in December 2025 until a preliminary injunction was granted by the U.S District Court for the Eastern District of Virginia in January 2026, which allowed work to resume. The estimated total project costs also include $0.6 billion of tariffs on equipment expected to be delivered from March 2025 through March 2026 that originates from Mexico, Canada, a European Union member or other applicable countries and on equipment expected to be delivered from March 2025 through early 2027 that contains steel. Such amount is inclusive of approximately $0.2 billion associated with tariffs on equipment expected to be delivered from March 2025 through March 2026 that originates from Mexico, Canada, a European Union member or other applicable countries that were the subject of a U.S. Supreme Court’s ruling on February 20, 2026. The actual tariffs to be incurred are dependent upon the tariff requirements and rates, if any, at the time of delivery of the specific component.

As previously considered in Virginia Power’s February 2025 construction update filing, the expected total project cost reflects projections for onshore electrical interconnection costs and network upgrade costs assigned to the project by PJM, specifically incorporating consideration of PJM’s December 2024 publication of potential transmission network upgrades required for certain generation projects and related cost allocations, including those attributable to the CVOW Commercial Project. Relative to Virginia Power’s November 2024 Rider OSW filing, the estimated total project cost reflects an approximately $0.6 billion increase for such onshore and network upgrade costs and an approximately $0.3 billion increase for increased contingency for remaining construction activities, completion of the removal of unexploded ordnance, undersea cable protection system design enhancements, commodity prices for transportation fuel, updates for sea fastener fabrication and installation and other construction and equipment supplier costs. Virginia Power has entered into fixed price contracts for the major offshore construction and equipment components. The contracts include services denominated in currencies other than the U.S. dollar, for which Virginia Power has entered forward contracts to economically hedge.

In accordance with the Virginia Commission’s December 2022 order, the Companies are subject to a cost sharing mechanism in which Virginia Power will be eligible to recover 50% of such incremental costs which fall between $10.3 billion and $11.3 billion with no recovery of such incremental costs which fall between $11.3 billion and $13.7 billion. There is no cost sharing mechanism for any total construction costs in excess of $13.7 billion, the recovery of which would be determined in a future Virginia Commission proceeding. In October 2024, Virginia Power completed the sale of a 50% noncontrolling interest in the CVOW Commercial Project to Stonepeak as discussed below.

As a result of the revised total project cost estimates and cost sharing mechanism, during 2025 Virginia Power recorded charges for costs not expected to be recovered from customers of $515 million within impairments of assets and other charges, which includes $257 million attributable to noncontrolling interests, and an associated income tax benefit of $66 million, in addition to recording in the fourth quarter of 2024 a $206 million charge within impairments of assets and other charges, which includes $103 million attributable to noncontrolling interests, and an associated income tax benefit of $26 million, all reflected in the Corporate and Other segment, in the Companies’

112

Consolidated Statements of Income. The Companies are currently unable to estimate the expected impact of the ruling issued by the U.S. Supreme Court on February 20, 2026, on its financial position, results of operations and/or cash flows.

The estimated total project cost above reflects the Companies’ best estimate of the remaining construction costs, including contingency of approximately 7% on such remaining amounts. Such estimate could potentially change for items, certain of which are beyond the Companies’ control, including but not limited to actual network upgrade costs allocated by PJM, fuel for transportation and installation, the impact of applicable tariffs including any potential impact of Section 232 investigations and litigation ruled on by the U.S. Supreme Court on February 20, 2026, costs to maintain necessary permits, approvals and authorizations, any additional suspension of work orders, ability of key suppliers and contractors to timely satisfy their obligations under existing contracts, marine wildlife and/or any severe weather events.  Any additional increase in such costs in excess of the contingency included in the estimated total project cost would be subject to the cost sharing mechanisms described above and could have a material impact on the Companies’ future financial condition, results of operations and/or cash flows.

Sale of Noncontrolling Interest in CVOW Commercial Project

In February 2024, Virginia Power entered into an agreement to sell a 50% noncontrolling interest in the CVOW Commercial Project to Stonepeak through the formation of OSWP. In October 2024, Virginia Power and Stonepeak closed on the agreement following the receipt of consent by BOEM and satisfaction of other customary closing and regulatory conditions. Consistent with the terms of the agreement, Virginia Power contributed the CVOW Commercial Project and Stonepeak contributed cash to OSWP. The contribution of the CVOW Commercial Project required approvals from the Virginia and North Carolina Commissions, which were received in September 2024. At closing, Virginia Power received $2.6 billion, prior to consideration of customary post-closing adjustments, representing 50% of the CVOW Commercial Project construction costs incurred through closing, less an initial withholding of $145 million. If the total project costs of the CVOW Commercial Project are $9.8 billion, excluding financing costs, or less Virginia Power shall receive $100 million of the initial withholding. Such amount is subject to downward adjustment with Virginia Power receiving no withheld amounts if the total costs, excluding financing costs, of the CVOW Commercial Project exceed $11.3 billion.

Virginia Power and Stonepeak will each contribute 50% of the remaining capital necessary to fund construction of the CVOW Commercial Project provided the total project cost, excluding financing costs, is less than $11.3 billion. For capital funding necessary, if any, for total project costs, excluding financing costs, of $11.3 billion through $13.7 billion, Stonepeak will have the option to make additional capital contributions. If Stonepeak elects to make additional capital contributions for project costs, excluding financing costs, in excess of $11.3 billion, if any, Virginia Power shall contribute between 67% and 83% of such capital with Stonepeak contributing the remainder. To the extent that Stonepeak elects not to make such contributions, Virginia Power shall receive an increase in its ownership percentage of OSWP for any contributed capital based on a tiered unit price for membership interests in OSWP as set forth in the agreement. Virginia Power and Stonepeak have the right to provide capital contributions for any total project costs, excluding financing costs, in excess of $13.7 billion.

OSWP is considered to be a VIE primarily because its equity capitalization is insufficient to support its operations. Virginia Power is considered to be the primary beneficiary and consolidates OSWP with Stonepeak’s interests reflected as noncontrolling interests beginning in the fourth quarter of 2024 as Virginia Power has the power to direct the most significant activities of OSWP, including construction and operation of the CVOW Commercial Project. In the event that OSWP ceases to be a VIE, Virginia Power expects to continue to consolidate OSWP as its ownership interest is expected to be considered a controlling financial interest over the entity through its rights to control operations.

Virginia Power Easement Agreement

In November 2023, Virginia Power entered into an agreement to pay $65 million for an easement related to the CVOW Commercial Project for which it will not seek recovery and therefore recorded a charge of $65 million ($49 million after-tax) within impairment of assets and other charges in its Consolidated Statements of Income (reflected in the Corporate and Other segment).

Nonregulated Solar Projects

The following table presents acquisitions by Dominion Energy of solar projects (reflected in Contracted Energy unless otherwise noted).

Project Name

Date Agreement Entered

Date Agreement Closed

Project Location

Project Cost (millions)(1)

Date of Commercial Operations

MW Capacity

Madison(2)

July 2020

July 2020

Virginia

165

N/A

62

Hardin II

August 2020

Terminated(3)

Atlanta Farms

March 2022

May 2022

Ohio

390

January 2025(4)

200

Foxhound

March 2023

February 2024

Virginia

195

April 2024(4)

83

(1)Includes acquisition costs.

(2)Madison was reflected in the Corporate and Other segment before its sale in April 2024. See Note 3 for discussion.

(3)In January 2023, Dominion Energy terminated its agreement, without penalty, to acquire Hardin II.

(4)Dominion Energy is claiming production tax credits on the energy generated and sold by these projects.

In addition to the facilities discussed above, Dominion Energy has also entered into various agreements to install solar facilities (reflected in the Corporate and Other segment), primarily at schools in Virginia. For the year ended December 31, 2025, Dominion Energy placed in service solar facilities with an aggregate generation capacity of 4 MW at a cost of $9 million and anticipates placing additional

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facilities in service by the end of 2026 with an estimated total projected cost of approximately $10 million and an aggregate generation capacity of 4 MW. Dominion Energy has claimed or expects to claim federal investment tax credits on the projects.

Acquisition of Early Stage Generation Facility

In November 2025, Virginia Power entered into and closed on an agreement to acquire approximately 1,200 acres of land in Virginia and associated electric generation project assets in the early stages of development for $113 million. Under the terms of the agreement, $13 million of the purchase price was paid at closing with the remainder to be paid periodically through 2028. At December 31, 2025, Virginia Power’s Consolidated Balance Sheet includes $25 million in other current liabilities and $75 million in other deferred credits and other liabilities.

Regulated Solar Development Projects

In December 2025 and February 2026, Virginia Power entered into two separate agreements related to the development of certain solar generation facilities. Under the terms of the agreements, Virginia Power will acquire the solar generation facilities following the completion of construction at a purchase price based on the installed capacity, which Virginia Power estimates will be approximately $1.3 billion in aggregate. The solar generation facilities are expected to be completed in 2029 with an aggregate generation capacity of approximately 400 MW. Virginia Power expects to recover the cost of these solar generation facilities through Rider CE.

Acquisition of Offshore Wind Project

In July 2024, Virginia Power entered into an agreement to acquire an approximately 40,000-acre area lease 27 miles off the coast of North Carolina in federal waters and associated project assets in the early stages of development for approximately $160 million. The transaction closed in October 2024 following the receipt of approval from BOEM and other customary regulatory approvals. The CVOW South project, if constructed, is expected to have a generating capacity of 800 MW with ultimate development of the project dependent upon the receipt of approvals from the Virginia Commission and other permitting entities. The project would support Virginia Power’s ability to meet the renewable energy portfolio standards established in the VCEA.

Sales of Corporate Office Buildings

In 2023, Dominion Energy entered into an agreement for the sale of a corporate office building for total cash consideration of $40 million. In the second quarter of 2024, Dominion Energy recorded a charge of $17 million ($12 million after-tax) in impairment of assets and other charges in its Consolidated Statements of Income to adjust the corporate office building down to its estimated fair value, using a market approach, of $23 million. The valuation is considered a Level 3 fair value measurement as it is based on unobservable inputs due to limited comparable market activity. In the third quarter of 2024, Dominion Energy entered into a new agreement to sell the corporate office building, which closed in December 2024 for $19 million, and recorded an inconsequential loss upon closing.

In 2023, Dominion Energy recorded a charge of $93 million ($69 million after-tax) in impairment of assets and other charges in its Consolidated Statements of Income to adjust a corporate office building down to its estimated fair value, using a market approach, of $35 million. The valuation is considered a Level 3 fair value measurement as it is based on unobservable inputs due to limited comparable market activity. Dominion Energy completed the sale in July 2024.

All activity related to the sales of these corporate office buildings is reflected in the Corporate and Other segment.

Nonregulated Renewable Natural Gas Facilities

Dominion Energy recorded impairment charges of $33 million ($25 million after-tax) and $27 million ($21 million after-tax) in the second and third quarters of 2024, respectively, in impairment of assets and other charges in the Consolidated Statements of Income reflected in the Corporate and Other segment, to write down the long-lived assets of certain nonregulated renewable natural gas facilities under development to their estimated fair values which were each less than $1 million. The fair values were estimated using an income approach. The valuations are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risks inherent in future cash flows and market prices.

Sale of Utility Property

In 2023, Dominion Energy completed the sales of certain utility property in South Carolina, as approved by the South Carolina Commission in February 2023, for total cash consideration of $12 million. In connection with the sales, Dominion Energy recognized a gain of $11 million ($8 million after-tax), recorded in other operations and maintenance expense in its Consolidated Statements of Income (reflected in the Corporate and Other segment) for the year ended December 31, 2023.

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Note 11. Goodwill and Intangible Assets

Goodwill

The changes in Dominion Energy’s carrying amount and segment allocation of goodwill are presented below:

	Dominion Energy Virginia				Dominion Energy South Carolina				Contracted Energy				Corporate and Other				Total
(millions)
Balance at December 31, 2023(1)	$	2,106			$	1,521			$	516			$	—			$	4,143
No events affecting goodwill		—				—				—				—				—
Balance at December 31, 2024(1)	$	2,106			$	1,521			$	516			$	—			$	4,143
No events affecting goodwill		—				—				—				—				—
Balance at December 31, 2025(1)	$	2,106			$	1,521			$	516			$	—			$	4,143

(1)Goodwill amounts do not contain any accumulated impairment losses.

Other Intangible Assets

The Companies’ other intangible assets are subject to amortization over their estimated useful lives. Dominion Energy’s amortization expense for software, licenses and other intangible assets was $111 million, $87 million and $160 million for the years ended December 31, 2025, 2024 and 2023, respectively. In 2025, Dominion Energy acquired $962 million of intangible assets, primarily representing renewable energy credits and software, with an estimated weighted-average amortization period of approximately 4 years. Amortization expense for Virginia Power’s software, licenses and other intangible assets was $74 million, $51 million and $123 million for the years ended December 31, 2025, 2024 and 2023, respectively. In 2025, Virginia Power acquired $872 million of intangible assets, primarily representing renewable energy credits and software, with an estimated weighted-average amortization period of 3 years.

The components of intangible assets are as follows:

	2025							2024
At December 31,	Gross Carrying Amount			Accumulated Amortization				Gross Carrying Amount			Accumulated Amortization
(millions)
Dominion Energy
Software, licenses and    other	$	1,950		$	820			$	1,645		$	708
Renewable energy    credits(1)		552			—				199			—
Virginia Power
Software, licenses and    other	$	1,125		$	365			$	911		$	291
Renewable energy    credits(1)		550			—				198			—

(1) Includes $342 million and $370 million of renewable energy credits consumed and retired in 2025 and 2024, respectively. All amounts for renewable energy credits were deferred to regulatory assets upon consumption.

Annual amortization expense for intangible assets, excluding renewable energy credits which are deferred to regulatory assets, is estimated to be as follows:

(millions)		2026			2027			2028			2029			2030
Dominion Energy		$	107		$	97		$	84		$	72		$	46
Virginia Power			70			65			56			50			31

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Combined Notes to Consolidated Financial Statements, Continued

Note 12. Regulatory Assets And Liabilities

Regulatory assets and liabilities include the following:

		Dominion Energy								Virginia Power
At December 31,		2025				2024				2025				2024
(millions)
Regulatory assets:
Deferred cost of fuel used in electric generation(1)		$	213			$	38			$	174			$	3
Securitized cost of fuel used in electric generation(2)			125				124				125				124
Riders OSW and CE(3)			23				7				23				7
Other deferred rider costs for Virginia electric utility(4)			445				286				445				286
Ash pond and landfill closure costs(5)			164				108				164				108
Deferred nuclear refueling outage costs(6)			101				97				101				80
NND Project costs(7)			138				138
Derivatives(8)			3				8				—				6
Other			168				186				78				83
Regulatory assets-current			1,380				992				1,110				697
Unrecognized pension and other postretirement benefit costs(9)			527				486				—				—
Riders OSW and CE(3)			287				117				287				117
Other deferred rider costs for Virginia electric utility(4)			338				534				338				534
Interest rate hedges(10)			165				167				—				—
AROs and related funding(11)			385				387
NND Project costs(7)			1,672				1,811
CCR remediation, ash pond and landfill closure costs(5)			2,868				2,898				2,510				2,560
Deferred cost of fuel used in electric generation(1)			391				—				391				—
Securitized cost of fuel used in electric generation(2)			868				1,040				868				1,040
Derivatives(8)			33				182				—				148
Other			742				666				132				138
Regulatory assets-noncurrent			8,276				8,288				4,526				4,537
Total regulatory assets		$	9,656			$	9,280			$	5,636			$	5,234
Regulatory liabilities:
Deferred cost of fuel used in electric generation(1)			3				92				3				92
Provision for future cost of removal and AROs(12)			101				119				101				119
Reserve for rate credits to electric utility customers(13)			34				73				—				—
Income taxes refundable through future rates(14)			110				88				77				64
Monetization of guarantee settlement(15)			67				67
Derivatives(8)			158				51				135				30
Other			69				89				58				80
Regulatory liabilities-current			542				579				374				385
Income taxes refundable through future rates(14)			2,854				2,988				2,046				2,168
Provision for future cost of removal and AROs(12)			1,950				1,809				1,346				1,210
Nuclear decommissioning trust(16)			2,494				2,115				2,494				2,115
Monetization of guarantee settlement(15)			501				568
Interest rate hedges(10)			461				406				461				406
Reserve for rate credits to electric utility customers(13)			128				161				—				—
Overrecovered other postretirement benefit costs(17)			209				183
Derivatives(8)			228				248				31				25
Other			247				283				152				215
Regulatory liabilities-noncurrent			9,072				8,761				6,530				6,139
Total regulatory liabilities		$	9,614			$	9,340			$	6,904			$	6,524

(1)Reflects deferred fuel expenses as well as, beginning in June 2025, deferred electric capacity expenses for the Virginia and North Carolina jurisdictions of Virginia Power’s electric generation operations. Additionally, Dominion Energy includes deferred fuel expenses for the South Carolina jurisdiction of its electric generation operations. In February 2024, Virginia Power completed a securitization of $1.3 billion of under-recovered fuel costs for its Virginia service territory. See Note 18 for additional information.

(2)Reflects under-recovered fuel costs for Virginia Power’s Virginia service territory securitized through the issuance of bonds by VPFS in February 2024, which are being amortized into electric fuel and other energy-related purchases. See Note 18 for additional information.

(3)Deferred balances for Riders OSW and CE include amounts for shortfall or excess in energy sales, capacity revenue, renewable energy credits and production tax credits as such customer benefit amounts are included as a component, including an equity return, of the revenue requirements associated with each rate adjustment clause. In addition, the deferred Rider OSW balance at December 31, 2025 includes $4 million for future decommissioning activities.

(4)Reflects deferrals under Virginia Power’s electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects. In 2023, Virginia Power recorded a charge of $36 million ($27 million after-tax), included in impairment of assets and other charges in its Consolidated Statements of Income (reflected in the Corporate and Other segment), for the write-off of certain previously deferred amounts related to rate adjustment clauses associated with the recovery of costs related to Bear Garden, Virginia City Hybrid Energy Center and Warren County in connection with the cessation of such riders effective July 2023. See Note 13 for additional information.

(5)Primarily reflects legislation in Virginia which requires any CCR asset located at certain Virginia Power stations to be closed by removing the CCR to an approved landfill or through beneficial reuse. These deferred costs are expected to be collected over a period between 15 and 18 years commencing

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December 2021 through Rider CCR. Virginia Power is entitled to collect carrying costs on uncollected expenditures once expenditures have been made. In addition, reflects amounts related to the EPA’s May 2024 final rule concerning CCR as discussed in Note 14.

(6)Primarily reflects deferred operation and maintenance costs at Virginia Power incurred in connection with the refueling of any nuclear-powered generating plant as required by Virginia legislation. Virginia Power deferred costs will be amortized over the refueling cycle, not to exceed 18 months.

(7)Reflects expenditures by DESC associated with the NND Project, which pursuant to the SCANA Merger Approval Order, will be recovered from DESC electric service customers over a 20-year period ending in 2039.

(8)Represents changes in the fair value of derivatives, excluding separately presented interest rate hedges, that following settlement are expected to be recovered from or refunded to customers.

(9)Represents unrecognized pension and other postretirement employee benefit costs expected to be recovered or refunded through future rates generally over the expected remaining service period of plan participants by certain of Dominion Energy’s rate-regulated subsidiaries.

(10)Reflects interest rate hedges recoverable from or refundable to customers. Certain of these instruments are settled and any related payments are being amortized into interest expense over the life of the related debt, which has a weighted-average useful life of approximately 24 years for both Dominion Energy and Virginia Power at December 31, 2025.

(11)Represents uncollected costs, including deferred depreciation and accretion expense, related to legal obligations associated with the future retirement of generation, transmission and distribution properties. The AROs primarily relate to DESC’s electric generating facilities, including Summer, and are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 105 years.

(12)Rates charged to customers by Dominion Energy and Virginia Power’s regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.

(13)Reflects amounts previously collected from retail electric customers of DESC for the NND Project to be credited over an estimated 11-year period effective February 2019, in connection with the SCANA Merger Approval Order.

(14)Amounts recorded to pass the effect of reduced income taxes from the 2017 Tax Reform Act to customers in future periods, which will primarily reverse at the weighted-average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC equity.

(15)Reflects amounts to be refunded to DESC electric service customers over a 20-year period ending in 2039 associated with the monetization of a bankruptcy settlement agreement.

(16)Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses, changes in fair value and taxes thereon, as applicable) for the future decommissioning of Virginia Power’s utility nuclear generation stations, in excess of the related AROs.

(17)Reflects a regulatory liability for the collection of postretirement benefit costs allowed in rates in excess of expense incurred.

At December 31, 2025, Dominion Energy and Virginia Power regulatory assets include $5.8 billion and $4.1 billion, respectively, on which they do not expect to earn a return during the applicable recovery period. With the exception of certain items discussed above, the majority of these expenditures are expected to be recovered within the next two years.

Note 13. Regulatory Matters

Regulatory Matters Involving Potential Loss Contingencies

As a result of issues generated in the ordinary course of business, the Companies are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders and/or involve significant factual issues that need to be resolved, it is not possible for the Companies to estimate a range of possible loss. For regulatory matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters that the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on the Companies’ financial position, liquidity or results of operations.

Other Regulatory MATTERS

Virginia Regulation – Key Legislation Affecting Operations

Regulation Act and Grid Transformation and Security Act of 2018

The Regulation Act enacted in 2007 instituted a cost-of-service rate model that authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, underground distribution lines, environmental compliance, conservation and energy efficiency programs, renewable energy programs and nuclear license renewals, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission.

If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.

The GTSA reinstated base rate reviews commencing with the 2021 Triennial Review. In the triennial review proceedings, earnings that were more than 70 basis points above the utility’s authorized ROE that might have been refunded to customers and served as the basis for a reduction in future rates, could be reduced by Virginia Commission-approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elected to include in a CCRO. The legislation declared that electric distribution grid

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Combined Notes to Consolidated Financial Statements, Continued

transformation projects are in the public interest and provided that the costs of such projects may be recovered through a rate adjustment clause if not the subject of a CCRO. Any costs that were the subject of a CCRO were deemed recovered in base rates during the triennial period under review and could not be included in base rates in future triennial review proceedings. In any triennial review in which the Virginia Commission determined that the utility’s earnings were more than 70 basis points above its authorized ROE, base rates were subject to reduction prospectively and customer refunds would be due unless the total CCRO elected by the utility equaled or exceeded the amount of earnings in excess of the 70 basis points. For the purposes of measuring any customer refunds or CCRO amounts utilized under the GTSA, associated income taxes were factored into the determination of such amounts. In the 2021 Triennial Review, any such rate reduction was limited to $50 million. This section of the GTSA concerning base rate reviews was amended by 2023 legislation as discussed below.

Virginia 2020 Legislation

In April 2020, the Governor of Virginia signed into law the VCEA, which along with related legislation forms a comprehensive framework affecting Virginia Power’s operations. The VCEA replaces Virginia’s voluntary renewable energy portfolio standard for Virginia Power with a mandatory program setting annual renewable energy portfolio standard requirements based on the percentage of total electric energy sold by Virginia Power, excluding existing nuclear generation and certain new carbon-free resources, reaching 100% by the end of 2045. The VCEA includes related requirements concerning deployment of wind, solar and energy storage resources, as well as provides for certain measures to increase net-metering, including an allocation for low-income customers, incentivizes energy efficiency programs and provides for cost recovery related to participation in a carbon trading program. While the legislation affects several portions of Virginia Power’s operations, key provisions of the GTSA remained in effect, including the triennial review structure and timing, the use of the CCRO and the $50 million cap on revenue reductions in the first triennial review proceeding. Key provisions of the VCEA and related legislation passed include the following:

•Fossil Fuel Electric Generation: The legislation mandates Chesterfield Power Station Units 5 & 6 and Yorktown Power Station Unit 3 to be retired by the end of 2024, Altavista, Southampton and Hopewell to be retired by the end of 2028 and Virginia Power’s remaining fossil fuel units to be retired by the end of 2045, unless the retirement of such generating units will compromise grid reliability or security. In addition, the Virginia Commission shall determine the amortization period for recovery of any appropriate costs due to the early retirement of any electric generation facilities. Virginia Power revised the depreciable lives of Altavista, Southampton and Hopewell for the mandated retirement to the end of 2028, which did not have a material impact to Virginia Power’s results of operations or cash flows given the existing regulatory framework. This section of the VCEA concerning mandatory retirements of certain facilities by the end of 2028 was amended by 2023 legislation as discussed below. As a result, in November 2023 Virginia Power revised the depreciable lives of Altavista, Southampton and Hopewell and implemented useful life assumptions that were effective before the previous revision.

•Renewable Generation: The legislation provides a detailed renewable energy portfolio standard to achieve 100% zero-carbon generation by the end of 2045, excluding existing nuclear generation and certain new carbon-free resources. Components include requirements to petition the Virginia Commission for approval to construct or acquire new generating capacity to reach 16.1 GW of installed solar and onshore wind by the end of 2035, which includes specific requirements for utility-scale solar of 3.0 GW by the end of 2024, up to 15.0 GW by the end of 2035 and 1.1 GW of small-scale solar by the end of 2035. The legislation deems 2.7 GW of energy storage, including up to 800 MW for any one project which may include a pumped storage facility, by the end of 2035 to be in the public interest. The legislation also deems the construction or purchase of an offshore wind facility constructed off the Virginia coast with a capacity of up to 5.2 GW before 2035 to be in the public interest and provides certain presumptions facilitating cost recovery. The costs of such a facility constructed by the utility with a capacity between 2.5 and 3.0 GW will be presumed reasonably and prudently incurred if the Virginia Commission finds that the project meets competitive procurement requirements, the projected cost of the facility does not exceed a specified industry benchmark and the utility commences construction by the end of 2023 or has a plan for the facility to be in service by the end of 2027. Projects to meet these requirements are subject to approval by the Virginia Commission.

•Energy Efficiency: The legislation includes an energy efficiency target of 5% energy savings, as measured from a 2019 baseline, through verifiable energy efficiency programs by the end of 2025 with future targets to be set by the Virginia Commission. Virginia Power has the opportunity to offset the lost revenues with margins on program spend if certain targets are achieved and can also seek recovery of the lost revenues associated with energy efficiency programs if such reductions are found to have caused Virginia Power to earn more than 50 basis points below a fair rate of return on its rates for generation and distribution services. In February 2025, the Virginia Commission issued its order establishing energy savings targets for Virginia Power of 3.00% for 2026, 4.00% for 2027 and 5.00% for 2028, as measured from a 2019 baseline.

•Carbon trading program: The legislation authorizes Virginia to participate in a market-based carbon trading program consistent with RGGI through 2050. In January 2022, the Governor of Virginia issued an executive order which put directives in place to start administrative steps to withdraw Virginia from RGGI. In December 2023, the withdrawal took effect, which remains subject to ongoing legal challenges. All costs of the carbon trading program are recoverable through an environmental rider.

•Low-income customers: The legislation includes the establishment of a percentage of income payment program to be administered by the Virginia Department of Housing and Community Development and the Virginia Department of Social Services. To fund the program, Virginia Power will remit amounts collected from customers under a universal service fee established and set by the Virginia Commission. As such, this program will not affect Virginia Power’s results of operations, financial position or cash flows. In December

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2020, the Virginia Commission issued a final order confirming a revenue requirement of $93 million related to this program. Implementation details and the effective date of the program would be established in future legislation prior to collection of fees from customers. In October 2023, the Virginia Commission approved the collection by Virginia Power of a universal service fee of $71 million from customers during the rate year beginning November 2023, including the impact on certain non-jurisdictional customers which follow Virginia Power’s jurisdictional customer rate methodology.

Virginia 2023 Legislation

In April 2023, legislation was enacted that amended several key provisions of the Regulation Act, as previously amended by the GTSA, and revised portions of the existing regulatory framework affecting Virginia Power’s operations.

The legislation resets the frequency of base rate reviews from a triennial period, as established under the GTSA, to a biennial period commencing with the 2023 Biennial Review. Such biennial reviews shall include the establishment of an authorized ROE to be utilized for base rates and riders, prospective base rates for the upcoming two-year period based on projected cost of service and a determination by the Virginia Commission as to Virginia Power’s base rate earned return for the most recently completed two-year period against the previously authorized ROE, including any potential credits to customers’ bills.

The legislation provides that the Virginia Commission will establish an authorized ROE of 9.70% for Virginia Power in the 2023 Biennial Review, reflecting the average authorized ROE of vertically integrated electric utilities by the applicable regulatory commissions in the peer group jurisdictions of Florida, Georgia, Texas, Tennessee, West Virginia, Kentucky and North Carolina. Subsequent to the 2023 Biennial Review, all provisions related to this peer group benchmarking expire and the Virginia Commission is authorized to utilize any methodology it deems to be consistent with the public interest to make future ROE determinations. In all biennial reviews following the 2023 Biennial Review, if the Virginia Commission determines that Virginia Power’s existing base rates will, on a going-forward basis, produce revenues that are either in excess of or below its authorized rate of return, the Virginia Commission is authorized to reduce or increase such base rates, as applicable and necessary, to ensure that Virginia Power’s base rates are just and reasonable while still allowing Virginia Power to recover its costs and earn a fair rate of return. In addition, beginning with the 2025 Biennial Review, the Virginia Commission may, at its discretion, increase or decrease Virginia Power’s authorized ROE by up to 50 basis points based on factors that may include reliability, generating plant performance, customer service and operating efficiency, with the provisions applying to such adjustments to be determined in a future proceeding.

The legislation directs that if the Virginia Commission determines as part of the 2023 Biennial Review that Virginia Power has earned more than 70 basis points above its authorized ROE of 9.35% established in the 2021 Triennial Review that 85% of the amount of such earnings above this level be credited to customers’ bills. In future biennial reviews, beginning with the biennial review to be filed in 2025, 85% of any earnings determined by the Virginia Commission to be up to 150 basis points above Virginia Power’s authorized ROE shall be credited to customers’ bills as well as 100% of any earnings that are more than 150 basis points above Virginia Power’s authorized ROE. For the purposes of measuring any bill credits due to customers, associated income taxes are factored into the determination of such amounts. In addition, the legislation eliminates Virginia Power’s ability to utilize Virginia Commission-approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects as a CCRO to reduce or offset any earnings otherwise eligible for customer credits as previously permitted under the GTSA.

In addition to the biennial review mechanisms discussed above, the legislation also includes provisions related to other aspects of Virginia Power’s ratemaking framework.

•Riders into base rates: Virginia Power is required to combine certain riders with an aggregate annual revenue requirement of at least $350 million with its base rates effective July 2023. After such riders are combined, they will be considered as part of base rates for the purposes of the biennial review proceedings. The inclusion of such riders cannot serve as the basis for an increase in base rates as part of the 2023 Biennial Review.

•Rider consolidation: Upon determination by the Virginia Commission, certain riders, while remaining separate from base rates, may be consolidated for cost recovery and review purposes.

•Capitalization ratio: The legislation establishes that Virginia Power is required to undertake reasonable efforts to maintain a common equity capitalization to total capitalization ratio through December 2024 of 52.10%.

•Fuel cost securitization: Virginia Power is authorized, on or before July 2024, to petition the Virginia Commission for approval of a financing order for certain deferred fuel costs. Virginia Power is required to permit certain retail customers to opt out of any such deferred fuel cost securitization.

•Electric generation plant retirements: The Virginia Commission shall provide to the Virginia General Assembly, on an annual basis, a report that includes information concerning the reliability impacts of generation unit additions and retirement determinations, along with the potential impact on the purchase of power from generation assets outside of the Virginia jurisdiction, the result of which could impact the depreciable lives of Virginia Power’s electric generation facilities in future periods.

In addition, in May 2023 legislation was enacted that amended certain portions of the VCEA to qualify generation produced by Virginia Power’s biomass electric generating stations as renewable energy and eliminate the mandated retirement of such facilities by the end of 2028.

Virginia Power is incurring and expects to incur significant costs, including capital expenditures, to comply with the legislative requirements discussed above. The legislation allows for cost recovery under the existing or modified regulatory framework through rate adjustment clauses, rates for generation and distribution services or Virginia Power’s fuel factor, as approved by the Virginia Commission. Costs allocated to the North Carolina jurisdiction will be recovered, subject to approval by the North Carolina Commission, in accordance with the existing regulatory framework.

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Combined Notes to Consolidated Financial Statements, Continued

Virginia Regulation – Key Developments

2025 Biennial Review

In March 2025, Virginia Power filed its base rate case and accompanying schedules in support of the 2025 Biennial Review in accordance with legislation enacted in Virginia in April 2023. Virginia Power’s earnings test analysis, as filed, demonstrated it earned a combined ROE of 7.77% on its generation and distribution services for the test period, compared to the ROE of 9.70% authorized by the Virginia Commission. Virginia Power proposed a base rate increase of $822 million effective January 2026 with an incremental base rate increase of $345 million effective January 2027. Virginia Power submitted an update in August 2025 for a proposed base rate increase of $706 million effective January 2026 with an incremental base rate increase of $256 million effective January 2027 to reflect FERC’s approval of a price cap and floor for certain PJM capacity auctions. Alternatively, Virginia Power proposed to include purchased electric capacity expenses as a component of fuel expenses instead of base rates. If the move had been approved, Virginia Power’s proposed base rate increase would have been $458 million effective January 2026 with an incremental base rate increase of $173 million effective January 2027. The base rate proposals reflect necessary investments in assets and operating resources, including the impact of significant inflationary pressures on labor, materials and equipment since the 2023 Biennial Review, required to reliably serve a growing customer base. The proposed base rates reflect an ROE of 10.40% utilizing a common equity capitalization to total capitalization ratio of 52.10%. The ROE authorized by the Virginia Commission will be applied to Virginia Power’s riders prospectively and will also be utilized to measure base rate earnings for the 2027 Biennial Review.

In November 2025, the Virginia Commission approved a base rate increase of $566 million effective January 2026 with an incremental base rate increase of $210 million effective January 2027, but did not approve Virginia Power’s proposal to include purchased electric capacity expenses as a component of fuel expenses instead of base rates. The Virginia Commission also authorized an ROE of 9.80% for Virginia Power that will be applied to Virginia Power’s riders prospectively and that will also be utilized to measure base rate earnings for the 2027 Biennial Review.

Virginia Fuel Expenses

In March 2025, Virginia Power filed its annual fuel factor with the Virginia Commission to recover an estimated $2.6 billion in Virginia jurisdictional projected fuel expense for the rate year beginning July 1, 2025 and a projected $205 million under-recovered balance at June 30, 2025. Virginia Power proposed to include purchased electric capacity expenses as a component of fuel expenses, consistent with its filing in the 2025 Biennial Review. In addition to the projected energy-related fuel expense, Virginia Power projects $120 million of purchased electric capacity expense to be incurred with PJM from January 1, 2026 to June 30, 2026. Virginia Power’s proposed fuel rate, including purchased electric capacity expense, represents a fuel revenue increase of $860 million when applied to projected kilowatt-hour sales for the rate year beginning July 1, 2025. In May 2025, the Virginia Commission ordered that Virginia Power’s proposed total fuel factor rate, excluding the purchased electric capacity expense component, be placed into effect on an interim basis beginning July 1, 2025. In February 2026, the Virginia Commission approved a fuel factor rate, excluding a purchased electric capacity expense component, representing an increase in fuel revenue of $739 million when applied to projected kilowatt-hour sales for the rate year beginning July 1, 2025.

Virginia Power Equity Application

In April 2025, Virginia Power requested approval from the Virginia Commission to issue and sell to Dominion Energy up to $3.5 billion of authorized but unissued shares of its common stock, no par value, through the end of 2025 to maintain adequate credit metrics and efficient access to capital markets while funding necessary capital expenditures. In June 2025, the Virginia Commission approved the request.

Renewable Generation Projects

In October 2024, Virginia Power filed a petition with the Virginia Commission for CPCNs to construct or acquire and operate two utility-scale projects totaling approximately 208 MW of solar generation as part of its efforts to meet the renewable generation development targets under the VCEA. The projects, as of October 2024, are expected to cost approximately $605 million in the aggregate, excluding financing costs, and be placed into service between 2026 and 2028. In April 2025, the Virginia Commission approved the petition.

In October 2025, Virginia Power filed a petition with the Virginia Commission for CPCNs to construct or acquire and operate six utility-scale projects totaling approximately 845 MW of solar generation and two energy storage projects totaling approximately 155 MW as part of its efforts to meet the renewable generation development targets under the VCEA. The projects include Bedford and Pumpkinseed, which were constructed and have been operated as non-jurisdictional generation facilities. The remaining projects are expected to, as of October 2025, cost approximately $2.9 billion, excluding financing costs, and be placed into service between 2028 and 2030. This matter is pending.

GTSA Filing

In March 2025, Virginia Power filed a petition with the Virginia Commission for approval of Phase IIIB, covering 2024 through 2026, of its plan for electric distribution grid transformation projects as authorized by the GTSA. The plan requests approval for mainfeeder hardening work that Virginia Power undertook on three mainfeeders in 2024, proposes to continue the mainfeeder hardening project on 20 additional feeders in 2025 through 2026, proposes the continued implementation of a new outage management system previously approved by the Virginia Commission and requests approval of one new project, a remote sensing, image management and analytical program. For Phase IIIB, the total proposed capital investment is $278 million and the proposed operations and maintenance investment is $5 million. In September 2025, the Virginia Commission approved the petition.

Chesterfield Energy Reliability Center

In March 2025, Virginia Power filed a petition with the Virginia Commission for a CPCN to construct and operate the Chesterfield Energy Reliability Center. The project is expected to cost approximately $1.5 billion in the aggregate, excluding financing costs, have a generating capacity of 944 MW and be placed into service in 2029. In November 2025, the Virginia Commission approved the petition. In December 2025, the Virginia Commission issued an order suspending its previous order and granting reconsideration of the petition. In February 2026, the Virginia

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Commission denied the reconsideration petition and affirmed its November 2025 approval. In February 2026, an appeal was filed with the Supreme Court of Virginia. This matter is pending.

Riders

Significant riders associated with various Virginia Power projects are as follows:

Rider Name

Application Date

Approval Date

Rate Year Beginning

Total Revenue Requirement (millions)(1)

Increase (Decrease) Over Previous Year (millions)

Rider CCR

April 2025

December 2025

January 2026

166

63

Rider CE(2)

October 2024

April 2025

May 2025

182

49

Rider CE(3)

October 2025

Pending

May 2026

325

143

Rider DIST(4)

August 2024

May 2025

June 2025

267

N/A

Rider DIST(5)

August 2025

Pending

June 2026

333

66

Rider GEN

June 2024

February 2025

April 2025

438

N/A

Rider GEN

June 2024

February 2025

April 2026

311

(127

)

Rider OSW(6)

November 2024

August 2025

September 2025

639

153

Rider OSW

October 2025

Pending

September 2026

665

26

Rider RPS

December 2024

August 2025

September 2025

609

251

Rider RPS

December 2025

Pending

September 2026

442

(167

)

Rider SNA(7)

October 2024

July 2025

September 2025

207

138

Rider SNA

October 2025

Pending

September 2026

233

26

Rider T1(8)

May 2025

August 2025

September 2025

1,343

173

DSM Riders(9)

December 2024

August 2025

September 2025

96

10

DSM Riders(10)

December 2025

Pending

September 2026

114

18

(1)In addition, Virginia Power has riders associated with other projects with an aggregate total annual revenue requirement of approximately $54 million at December 31, 2025 and pending applications associated with such riders, including the Chesterfield Energy Reliability Center described above, which if approved, would result in a net increase of approximately $50 million.

(2)Associated with two solar generation projects, two small-scale solar projects and 19 purchased power agreements in addition to previously approved Rider CE projects.

(3)Associated with six solar generation projects, including Bedford and Pumpkinseed (non-jurisdictional generation facilities with an aggregate recorded cost of $251 million at September 30, 2025), two energy storage projects, three small-scale solar projects, 10 purchased power agreements and certain costs associated with expanding solar and storage facilities in addition to previously approved Rider CE projects.

(4)Rider DIST consists of $100 million in total revenue requirement for certain previously approved electric distribution grid transformation projects and $167 million for previously approved phases and proposed phase eight of certain new underground distribution facilities.

(5)This application includes $120 million in total revenue requirement for certain previously approved electric distribution grid transformation projects, $178 million for previously approved phases and proposed phase nine of certain new underground distribution facilities and $35 million for certain previously approved rural broadband capacity projects, including $25 million being collected under a rider associated with rural broadband capacity. If approved, the rider associated with the rural broadband capacity projects would be consolidated into Rider DIST and separate collection of rates under the rural broadband rider would cease effective June 1, 2026.

(6)The Virginia Commission also approved the establishment of a decommissioning trust fund associated with the CVOW Commercial Project. As a result, the applicable amount included within the total revenue requirement for Rider OSW will be allocated for such purposes.

(7)The Virginia Commission also approved Virginia Power’s request for cost recovery of approximately $1.7 billion through Rider SNA for the second phase of the nuclear life extension program which includes investments for calendar years 2025 through 2027.

(8)Consists of $561 million for the transmission component of Virginia Power’s base rates and $782 million for Rider T1.

(9)Associated with three redesigned energy efficiency programs and one new and two redesigned demand response programs with a $218 million cost cap, with the ability to exceed the cost cap by no more than 15%.

(10)Associated with two redesigned energy efficiency programs and seven new demand response programs with a $221 million cost cap, with the ability to exceed the cost cap by no more than 15%. Also in December 2025, Virginia Power filed a petition requesting Virginia Commission approval to conduct a pilot program to evaluate methods to optimize system demand through various technology applications and distributed energy resources, including the establishment of a VPP, as required by the Community Energy Act. In its petition, Virginia Power seeks to utilize certain programs previously approved by the Virginia Commission and incorporate newly proposed programs associated with the DSM Riders. The DSM Riders cost cap includes $64 million associated with the proposed VPP pilot program. The Virginia Commission has consolidated the DSM Riders and VPP pilot program petitions. This matter is pending.

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Combined Notes to Consolidated Financial Statements, Continued

Electric Transmission Projects

Significant Virginia Power electric transmission projects approved or applied for are as follows:

Description and Location of Project

Application Date

Approval Date

Type of Line

Miles of Lines

Cost Estimate (millions)(1)

Construct new Aspen and Golden substations, transmission lines and related    projects in Loudoun County, Virginia

March 2024

February 2025(2)

500- 230 kV

10

705

Construct new Apollo-Twin Creeks transmission lines, new substations and    related projects in Loudoun County, Virginia

March 2024

February 2025(2)

230 kV

2

285

Rebuild and construct new Fentress-Yadkin transmission lines and related    projects in the City of Chesapeake, Virginia

June 2024

February 2025

500 kV

14

205

Partial rebuild, reconductor and construct new Network Takeoff transmission    lines and related projects in the Counties of Fairfax and Loudoun, Virginia

July 2024

March 2025

230 kV

6

170

Rebuild Aquia Harbor-Possum Point transmission lines and related projects    in the Counties of Stafford and Prince William and the City of Fredericksburg,    Virginia

August 2024

March 2025

500- 230 kV

32

210

Partial rebuild, reconductor and construct new New Post transmission lines    and related projects in the Counties of Caroline and Spotsylvania, Virginia

August 2024

May 2025

230 kV

38

120

Construct new Centreport transmission line, substation and related projects in    Stafford County, Virginia

September 2024

June 2025

230 kV

3

55

Partial rebuild and construct new Meadowville transmission lines, substations    and related projects in Chesterfield County, Virginia

October 2024

June 2025

230 kV

11

190

Construct new Carmel Church and Ruther Glen transmission lines, substations    and related projects in Caroline County, Virginia

December 2024

September 2025

230 kV

7

85

Construct new Nebula transmission lines, substation and related projects in    Mecklenburg County, Virginia

January 2025

October 2025

230 kV

15

130

Construct new Culpeper Technology transmission lines, substations and    related projects in the Counties of Culpeper, Orange and Fauquier and the    Town of Culpeper, Virginia

February 2025

Pending

230 kV

13

255

Construct new Technology Boulevard transmission lines, substation and    related projects in Henrico County, Virginia

March 2025

February 2026

230 kV

5

60

Construct new Hornbaker transmission lines, switching station and    related projects in Prince William County, Virginia

March 2025

December 2025

230 kV

5

95

Construct new Golden-Mars transmission lines and related projects in    Loudoun County, Virginia

March 2025

Pending

500- 230 kV

11

525

Construct Duval-Midlothian transmission lines, substation and related    projects in Chesterfield County, Virginia

April 2025

February 2026

230 kV

7

125

Rebuild Chickahominy-Elmont transmission line, new future transmission    line and related projects in the Counties of Charles City, Henrico and    Hanover, Virginia

May 2025

January 2026

500- 230 kV

28

190

Rebuild Septa-Yadkin transmission line, partial rebuild of Suffolk-Thrasher    transmission line and related projects in Isle of Wight County and the Cities    of Chesapeake and Suffolk, Virginia

June 2025

December 2025

500- 230 kV

33

250

Partial rebuild Chesterfield-Lanexa transmission lines in the Counties of    Henrico, Charles City and New Kent, Virginia

September 2025

Pending

230- 115 kV

58

150

Rebuild Charlottesville-Dooms transmission lines in the Counties of    Albemarle and Augusta and the City of Charlottesville, Virginia

October 2025

Pending

230 kV

22

125

Construct West Creek transmission line, substation and related projects    in the County of Goochland, Virginia

January 2026

Pending

230 kV

7

100

(1)Represents the cost estimate included in the application except as updated in the approval if applicable. In addition, Virginia Power had various other transmission projects approved during 2025 with aggregate cost estimates of approximately $65 million.

(2)The final order of the Virginia Commission was appealed to the Supreme Court of Virginia. In February 2026, the Supreme Court of Virginia affirmed the Virginia Commission’s final order.

In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry switching station in Surry County to a new Skiffes Creek switching station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County and the City of Newport News from the proposed new Skiffes Creek switching station to Virginia Power’s existing Whealton substation in the City of Hampton. In February 2019, the transmission line project was placed into service. In March 2019, the U.S. Court of Appeals for the D.C. Circuit issued an order vacating the permit from the U.S. Army Corps of Engineers issued in July 2017 and ordered the U.S. Army Corps of Engineers to do a full environmental impact study of the project. In April 2019, Virginia Power and the U.S. Army Corps of Engineers filed petitions for rehearing with the U.S. Court of Appeals for the D.C. Circuit, asking that the permit from the U.S. Army Corps of Engineers remain in effect while an environmental impact study is performed. In May 2019, the U.S. Court of Appeals for the D.C. Circuit denied the request for rehearing and ordered the U.S. District Court for the D.C. Circuit to consider and issue a ruling on whether the permit should be vacated during the U.S. Army Corps of Engineers’ preparation of an environmental impact statement. In November 2019, the U.S. District Court for the D.C. Circuit issued an order allowing the permit to remain in effect while an environmental impact statement is prepared. In November 2020, the U.S. Army Corps of Engineers issued a draft environmental impact statement noting there is no better alternative. This matter is pending.

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Virginia Regulation – Key Development Affecting 2024

2023 Biennial Review

In February 2024, the Virginia Commission issued its order in the 2023 Biennial Review. In connection with the order, Virginia Power recorded a net benefit of $17 million ($12 million after-tax) in the first quarter of 2024 within impairment of assets and other charges in its Consolidated Statements of Income (reflected in the Corporate and Other segment) for a regulatory asset for previously unrecovered severe weather event costs, which were amortized by the end of 2024.

North Carolina Regulation

Virginia Power Fuel Filing

In August 2025, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. In October 2025, Virginia Power subsequently updated its annual filing following a change in law which provides for recovery of purchased electric capacity expenses as a component of fuel. Virginia Power proposed a total $49 million increase to the fuel component of its electric rates. In January 2026, the North Carolina Commission approved a total $48 million increase to the fuel component of Virginia Power’s electric rates for the rate year beginning February 1, 2026.

South Carolina Regulation

Electric Base Rate Case

In January 2026, DESC filed its retail electric base rate case and schedules with the South Carolina Commission. DESC proposed a non-fuel, base rate increase of $331 million, partially offset by a net decrease in storm damage and DSM components of $9 million. If approved, the overall proposed rate increase of $322 million, or 12.7%, would be effective on and after the first billing cycle of July 2026. The base rate increase was proposed to recover the continued investment in assets and operating resources required to serve DESC’s rapidly expanding customer base and evolving customer needs, while maintaining the safety, reliability, resiliency and efficiency of its system, and to meet increasingly stringent reliability, security and environmental requirements. DESC presented an ROE of 4.78% based upon a fully-adjusted test period. The proposed rates would provide for an earned ROE of 10.50% compared to the currently authorized ROE of 9.94%. This matter is pending.

Cost of Fuel

DESC’s retail electric rates include a cost of fuel component approved by the South Carolina Commission which may be adjusted periodically to reflect changes in the price of fuel purchased by DESC. In February 2025, DESC filed with the South Carolina Commission a proposal to increase the total fuel cost component of retail electric rates. DESC’s proposed adjustment is designed to recover DESC’s current base fuel costs, including its existing under-collected balance, over the 12-month period beginning with the first billing cycle of May 2025. In addition, DESC proposed an increase to its variable environmental and avoided capacity cost component. The net effect is a proposed annual increase of $154 million. In March 2025, DESC and the South Carolina Office of Regulatory Staff filed a settlement agreement with the South Carolina Commission for approval to make certain adjustments to the February 2025 filing that would result in an inconsequential change to the proposed annual increase. In April 2025, the South Carolina Commission approved the settlement agreement, with rates effective with the first billing cycle of May 2025.

In February 2026, DESC filed with the South Carolina Commission a proposal to increase the total fuel cost component of retail electric rates. DESC’s proposed adjustment is designed to recover DESC’s current base fuel costs, including its existing under-collected balance, over the 12-month period beginning with the first billing cycle of May 2026. In addition, DESC proposed an update to its variable environmental and avoided capacity cost component. The net effect is a proposed annual increase of $36 million. This matter is pending.

Electric DSM Programs

DESC has approval for a DSM rider through which it recovers expenditures related to its electric DSM programs. In January 2025, DESC filed an application with the South Carolina Commission seeking approval to recover $46 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. DESC requested that rates be effective with the first billing cycle of May 2025. In April 2025, the South Carolina Commission approved the request, effective with the first billing cycle of May 2025.

In January 2026, DESC filed an application with the South Carolina Commission seeking approval to recover $54 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. DESC requested that rates be effective with the first billing cycle of May 2026. This matter is pending.

Canadys Station

In December 2025, DESC and Santee Cooper filed an application with the South Carolina Commission for approval of a CPCN to jointly construct and operate Canadys Station. Upon completion, DESC and Santee Cooper will each own a 50% undivided interest in the generating station and its electrical output. The application included an expected total cost of approximately $5 billion, excluding financing costs, with costs split equally between the joint owners for the proposed 2.2 GW facility. In addition, the application seeks approval for the construction of a new 230 kV switchyard and related transmission facilities which are expected to cost approximately $100 million, to be jointly owned by DESC and Santee Cooper, with costs split between the joint owners based on a formula reflecting shared use. If approved, Canadys Station and related facilities are expected to be placed into service in 2033. The estimated cost and project timelines are subject to refinement through the permitting process and the negotiation of contracts for major construction suppliers. This matter is pending.

Electric - Transmission Project

In December 2024, DESC filed an application with the South Carolina Commission requesting approval of a CPCN to construct and operate the Ritter-Yemassee Transmission Line #2, comprised of a 17-mile 230 kV transmission line and associated facilities in Colleton and Hampton Counties, South Carolina with an estimated total project cost of $55 million. In April 2025, the South Carolina Commission approved the application.

Natural Gas Rates

In June 2025, DESC filed with the South Carolina Commission its monitoring report for the 12-month period ended March 31, 2025 with a total revenue requirement of $596 million. This revenue requirement represents a $17 million base rate increase under the

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Combined Notes to Consolidated Financial Statements, Continued

terms of the Natural Gas Rate Stabilization Act effective with the first billing cycle of November 2025. In September 2025, the South Carolina Commission approved a total revenue requirement of $594 million, representing a $15 million base rate increase after certain adjustments, effective with the first billing cycle of November 2025.

South Carolina Regulation - Key Development affecting 2024

Electric Base Rate Case

In the third quarter of 2024, Dominion Energy recorded a charge of $58 million ($44 million after tax) (reflected within the Corporate and Other segment), including $50 million to write down certain materials and supplies inventory presented within impairment of assets and other charges, in connection with the electric base rate case filed in March 2024 in South Carolina.

Note 14. Asset Retirement Obligations

AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of the Companies’ long-lived assets. The Companies’ AROs are primarily associated with the decommissioning of their nuclear generation facilities, ash pond and landfill closures and CCR remediation.

The Companies have also identified, but not recognized, AROs related to the retirement of certain electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in the Companies’ generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire or dispose of any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets.

The changes to AROs during 2024 and 2025 were as follows:

(millions)	Dominion Energy				Virginia Power
AROs at December 31, 2023	$	6,075			$	4,653
Obligations incurred during the period(1)		1,126				469
Obligations settled during the period		(347	)			(259	)
Revisions in estimated cash flows(2)		300				342
Accretion		272				192
AROs at December 31, 2024(3)	$	7,426			$	5,397
Obligations incurred during the period(4)		252				195
Obligations settled during the period		(351	)			(307	)
Revisions in estimated cash flows(5)		(69	)			(32	)
Accretion		329				227
AROs at December 31, 2025(3)	$	7,587			$	5,480

(1)Primarily reflects AROs related to CCR remediation as discussed below.

(2)Primarily reflects revisions for increased costs related to the completion of nuclear decommissioning cost studies for Millstone, Surry and North Anna inclusive of a charge of $122 million ($89 million after-tax) within impairment of assets and other charges in Dominion Energy’s Consolidated Statements of Income (reflected in the Corporate and Other segment). In addition, there were downward revisions for CCR remediation costs at Dominion Energy and future ash pond and landfill closure costs of certain electric generation facilities at Virginia Power.

(3)Includes $352 million and $383 million reported in other current liabilities for Dominion Energy at December 31, 2024 and 2025, respectively.

(4)Primarily reflects obligations incurred during construction of the CVOW Commercial Project.

(5)Primarily reflects revisions for expected costs related to the completion of a nuclear decommissioning cost study for Summer resulting in a downward adjustment of $37 million and for Virginia Power’s future ash pond and landfill closure costs discussed below.

Dominion Energy’s AROs at both December 31, 2025 and 2024, include $2.6 billion, with $1.5 billion and $1.4 billion recorded by Virginia Power at December 31, 2025 and 2024, respectively, related to the future decommissioning of their nuclear facilities. The Companies have established trusts dedicated to funding the future decommissioning activities. At December 31, 2025 and 2024, the aggregate fair value of Dominion Energy’s trusts, consisting primarily of private debt funds and equity securities, totaled $9.2 billion and $8.1 billion, respectively. At December 31, 2025 and 2024, the aggregate fair value of Virginia Power’s trusts, consisting primarily of private debt funds and equity securities, totaled $4.9 billion and $4.3 billion, respectively.

AROs at December 31, 2025 and 2024 also include $889 million, with $441 million recorded at Virginia Power, and $828 million, with $404 million recorded at Virginia Power, respectively, related to Dominion Energy’s CCR remediation activities. In May 2024, the EPA released a final rule to regulate inactive surface impoundments located at retired generating stations that contained CCR and liquids after October 2015, and certain other inactive or previously closed surface impoundments, landfills or other areas that contain accumulations of CCR. Dominion Energy believes that it may have inactive or closed units or areas that could be subject to the final rule at up to 19 different stations, including 12 at Virginia Power. In 2025, Virginia Power increased its ARO by $16 million to reflect an obligation incurred related to updated information concerning one facility with a corresponding increase recorded primarily to a regulatory asset for amounts recoverable through retail electric rates, including riders, for an electric generation station that has been retired. In 2024, Dominion Energy and Virginia Power recorded an increase to their AROs of $1.1 billion and $420 million, respectively, with a corresponding increase of $536 million and $234 million, respectively, to regulatory assets for amounts recoverable through retail electric rates, including riders, for electric generation stations that have been retired, $505 million and $152 million, respectively, to property, plant and equipment for amounts recoverable for electric generation stations that are currently in service and $34 million to other deferred charges and other assets for amounts associated with nonjurisdictional customers at Virginia Power. Subsequently in 2024, Dominion Energy recorded an adjustment to decrease the ARO and related property, plant and equipment by $215 million to reflect updated information concerning one facility. The actual AROs related to CCRs may vary substantially from the estimates used to record the obligation.

In addition, AROs at December 31, 2025 and 2024 include $3.1 billion and $3.2 billion, respectively, related to Virginia Power’s future ash pond and landfill closure costs. In 2025, Virginia Power revised its estimated cash flow projections associated with ash pond and landfill closure costs at certain of its

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utility generation facilities attributable to changes in the scheduling of certain projects and as a result recorded a decrease to its AROs of $31 million with a corresponding decrease recorded primarily to regulatory assets for amounts recoverable through riders. In 2024, Virginia Power revised its estimated cash flow projections associated with ash pond and landfill closure costs at certain of its utility generation facilities attributable to changes in the scheduling of certain projects and as a result recorded a decrease to its AROs of $64 million with a corresponding decrease of $56 million to regulatory assets for amounts recoverable through riders and $8 million to other deferred charges and other assets for amounts associated with nonjurisdictional customers. Regulatory mechanisms, primarily associated with legislation enacted in Virginia in 2019, provide for recovery of costs to be incurred. See Note 12 for additional information.

AROs at December 31, 2025 and 2024 also include $220 million and $38 million, respectively, related to the decommissioning of the CVOW Commercial Project. As discussed in Note 13, a decommissioning trust fund, funded by the revenue requirement included in Rider OSW, has been approved to provide for the costs of future decommissioning activities.

Asset Retirement Obligations - Key Development Affecting 2023

In 2023, Dominion Energy reevaluated its estimated cash flows associated with Millstone Unit 1, concurrent with a revision in the timing of expected cash flows associated with the expected approval of a 20-year useful life extension of Millstone Units 2 and 3. This resulted in an increase to its AROs at Millstone Unit 1 and a related charge of $83 million ($60 million after-tax) within impairment of assets and other charges in its Consolidated Statements of Income (reflected in the Corporate and Other segment).

Note 15. Leases

At December 31, 2025 and 2024, the Companies had the following lease assets and liabilities recorded in the Consolidated Balance Sheets:

		Dominion Energy								Virginia Power(1)
At December 31,		2025				2024				2025				2024
(millions)
Lease assets:
Operating lease assets(2)		$	639			$	588			$	644			$	410
Finance lease assets(3)			541				267				239				146
Total lease assets		$	1,180			$	855			$	883			$	556
Lease liabilities:
Operating lease liabilities(4)		$	39			$	36			$	163			$	22
Finance lease liabilities(5)			119				62				45				35
Total lease liabilities -     current			158				98				208				57
Operating lease liabilities(6)			697				644				500				399
Finance lease liabilities(7)			436				214				194				110
Total lease liabilities -    noncurrent			1,133				858				694				509
Total lease liabilities		$	1,291			$	956			$	902			$	566

(1)See Note 25 for additional information about Virginia Power’s operating lease assets and liabilities with an affiliated entity for the use of a Jones Act compliant offshore wind installation vessel.

(2)Balances are included in other deferred charges and other assets in the Companies’ Consolidated Balance Sheets

(3)Balances are included in property, plant and equipment in the Companies’ Consolidated Balance Sheets, net of $251 million and $199 million for Dominion Energy, and $105 million and $88 million for Virginia Power, at December 31, 2025 and 2024, respectively, of accumulated amortization.

(4)Balances are in other current liabilities in the Companies’ Consolidated Balance Sheets.

(5)Balances are included in securities due within one year in the Companies’ Consolidated Balance Sheets

(6)Balances are included in other deferred credits and other liabilities in the Companies’ Consolidated Balance Sheets.

(7)Balances are included in other long-term debt in the Companies’ Consolidated Balance Sheets.

In September 2025, Virginia Power recorded a right-of-use asset and offsetting lease obligation of $228 million upon commencement of an operating lease with an affiliated entity for the use of a Jones Act compliant offshore wind installation vessel. See Note 25 for additional information.

In addition to the amounts disclosed above, Dominion Energy’s Consolidated Balance Sheets at December 31, 2025 and 2024 includes property, plant and equipment of $374 million and $382 million, respectively, related to facilities subject to power purchase agreements under which Dominion Energy is the lessor. There was $48 million and $38 million of accumulated depreciation related to these facilities recorded in Dominion Energy’s Consolidated Balance Sheets at December 31, 2025 and 2024, respectively.

For the years ended December 31, 2025, 2024 and 2023, total lease cost associated with the Companies’ leasing arrangements consisted of the following:

		Dominion Energy												Virginia Power(1)
Year Ended December 31,		2025				2024				2023				2025				2024				2023
(millions)
Finance lease cost:
Amortization(2)		$	56			$	54			$	50			$	28			$	24			$	24
Interest(3)			10				14				13				5				5				4
Operating lease cost(4)			92				81				70				72				60				43
Short-term lease cost(5)			22				22				32				58				16				23
Variable lease cost			5				6				6				2				2				2
Total lease cost		$	185			$	177			$	171			$	165			$	107			$	96

(1)See Note 25 for additional information about Virginia Power’s operating lease cost for an affiliated entity for the use of a Jones Act compliant offshore wind installation vessel.

(2)Dominion Energy includes $3 million for the year ended December 31, 2023, reflected in discontinued operations in its Consolidated Statements of Income.

(3)Dominion Energy includes $1 million for the year ended December 31, 2023, reflected in discontinued operations in its Consolidated Statements of Income.

(4)Dominion Energy includes $5 million for the year ended December 31, 2023, reflected in discontinued operations in its Consolidated Statements of Income.

(5)Dominion Energy includes $2 million for the year ended December 31, 2023, reflected in discontinued operations in its Consolidated Statements of Income.

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Combined Notes to Consolidated Financial Statements, Continued

For the years ended December 31, 2025, 2024 and 2023, cash paid for amounts included in the measurement of the lease liabilities consisted of the following amounts, included in the Companies’ Consolidated Statements of Cash Flows:

		Dominion Energy												Virginia Power
Year Ended December 31,		2025				2024				2023				2025				2024				2023
(millions)
Operating cash    flows for    finance leases		$	14			$	14			$	13			$	5			$	5			$	4
Operating cash    flows for    operating    leases			117				106				105				125				74				64
Financing cash    flows for    finance leases			70				50				47				28				23				19

In addition to the amounts disclosed above, Dominion Energy’s Consolidated Statements of Income for the years ended December 31, 2025, 2024 and 2023, include $18 million, $18 million and $21 million, respectively, of rental revenue, included in operating revenue and $10 million for each of the years ended December 31, 2025, 2024 and 2023 of depreciation expense, included in depreciation and amortization, related to facilities subject to power purchase agreements under which Dominion Energy is the lessor.

In April 2024, Dominion Energy agreed to pay $47 million in connection with a settlement of an agreement related to the offshore wind installation vessel then under development and recorded a charge of $47 million ($35 million after-tax) in the first quarter of 2024 (reflected in the Corporate and Other segment) within impairment of assets and other charges in its Consolidated Statements of Income.

At December 31, 2025 and 2024, the weighted-average remaining lease term and weighted discount rate for the Companies’ finance and operating leases were as follows:

		Dominion Energy				Virginia Power
December 31,		2025		2024		2025		2024
Weighted-average    remaining lease term -    finance leases		7 years		5 years		11 years		5 years
Weighted-average    remaining lease term -    operating leases		31 years		31 years		23 years		32 years
Weighted-average    discount rate - finance    leases		6.19%		5.61%		6.95%		6.71%
Weighted-average    discount rate -    operating leases		4.52%		4.42%		4.66%		5.13%

The Companies’ lease liabilities have the following maturities:

Maturity of Lease Liabilities		Dominion Energy								Virginia Power
(millions)		Operating				Finance				Operating				Finance
2026		$	48			$	131			$	66			$	58
2027			70				135				200				50
2028			38				126				70				43
2029			45				109				31				35
2030			35				76				21				25
After 2030			1,116				201				727				200
Total undiscounted    lease payments			1,352				778				1,115				411
Present value    adjustment			(616	)			(223	)			(452	)			(172	)
Present value of    lease liabilities		$	736			$	555			$	663			$	239

Offshore Wind Vessel Leasing Arrangement

In December 2020, Dominion Energy signed an agreement (most recently amended in February 2026) with a lessor to complete construction of and lease a Jones Act compliant offshore wind installation vessel. This vessel is designed to handle current turbine technologies as well as next generation turbines. The lessor provided equity and obtained financing commitments from debt investors, totaling $715 million, which funded project costs. In September 2025, the vessel was delivered and the five-year lease term commenced.

Upon commencement, the lease for the offshore wind vessel was classified as a finance lease. At the end of the initial lease term, Dominion Energy can (i) extend the term of the lease for an additional term, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the outstanding project costs, or (iii) subject to certain terms and conditions, sell the property on behalf of the lessor to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the outstanding project costs, Dominion Energy may be required to make a payment to the lessor for the difference between the outstanding project costs and sale proceeds. No end-of-term options were deemed reasonably certain of exercise at commencement date. Dominion Energy is considered the owner of the leased property for tax purposes, and as a result, is entitled to tax deductions for depreciation and interest expense. At commencement, Dominion Energy recorded a right-of-use asset and offsetting lease obligation of $214 million, representing the present value of consideration over the five-year term at the rate implicit in the lease.

Note 16. Variable Interest Entities

The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.

Dominion Energy

At December 31, 2025, Dominion Energy owns a 53% membership interest in Atlantic Coast Pipeline. Dominion Energy concluded

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that Atlantic Coast Pipeline is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion Energy has concluded that it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance, as the power to direct is shared with Duke Energy. Dominion Energy is obligated to provide capital contributions based on its ownership percentage. Dominion Energy’s maximum exposure to loss is limited to any future investment. See Note 9 for additional details regarding the nature of this entity.

At December 31, 2025, Dominion Energy owns a 30% membership interest in Valley Link. Dominion Energy concluded that Valley Link is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion Energy has concluded that it is not the primary beneficiary of Valley Link as it does not have the power to direct the activities of Valley Link that most significantly impact its economic performance, as the power to direct is shared with AEP and FirstEnergy. Dominion Energy is obligated to provide capital contributions proportionate to its ownership percentage. Dominion Energy’s maximum exposure to loss is limited to its investment as well as any obligations under guarantees provided. See Note 23 for additional information.

Dominion Energy and Virginia Power

The Companies’ nuclear decommissioning trust funds and Dominion Energy’s rabbi trusts hold investments in limited partnerships or similar type entities, as discussed in Note 9. Dominion Energy and Virginia Power concluded that these partnership investments are VIEs due to the limited partners lacking the characteristics of a controlling financial interest. Dominion Energy and Virginia Power have concluded neither is the primary beneficiary as they do not have the power to direct the activities that most significantly impact these VIEs’ economic performance. Dominion Energy and Virginia Power are obligated to provide capital contributions to the partnerships as required by each partnership agreement based on their ownership percentages. Dominion Energy and Virginia Power’s maximum exposure to loss is limited to their current and future investments.

Virginia Power

Virginia Power purchased shared services from DES, an affiliated VIE, of $597 million, $494 million and $463 million for the years ended December 31, 2025, 2024 and 2023, respectively. Virginia Power’s Consolidated Balance Sheets included amounts due to DES of $46 million and $38 million at December 31, 2025 and 2024, respectively, recorded in payables to affiliates. Virginia Power determined that it is not the primary beneficiary of DES as it does not have power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it. DES provides accounting, legal, finance and certain administrative and technical services to all Dominion Energy subsidiaries, including Virginia Power. Virginia Power has no obligation to absorb more than its allocated share of DES costs.

As described in Note 18, Virginia Power formed VPFS in October 2023, a wholly-owned special purpose subsidiary which is considered to be a VIE, for the sole purpose of securitizing certain of Virginia Power’s under-recovered deferred fuel balance through the issuance of senior secured deferred fuel cost bonds. The Companies’ Consolidated Balance Sheets included balances for VPFS as follows:

		December 31, 2025				December 31, 2024
(millions)
Assets
Prepayments		$	1			$	—
Regulatory assets-current			125				124
Other current assets(1)			51				41
Regulatory assets-noncurrent			868				1,040
Total assets		$	1,045			$	1,205
Liabilities
Securities due within one     year		$	171			$	163
Accrued interest, payroll     and taxes			9				10
Securitization bonds			883				1,054
Total liabilities		$	1,063			$	1,227

(1)See Note 2 for additional information about restricted cash and equivalents at VPFS.

As described in Note 10, in October 2024 Virginia Power completed the sale of a 50% noncontrolling interest in the CVOW Commercial Project to Stonepeak through the sale of an interest in OSWP, which is considered to be a VIE. The Companies’ Consolidated Balance Sheets included balances for OSWP as follows:

		December 31, 2025				December 31, 2024
(millions)
Assets
Cash and cash equivalents		$	149			$	70
Customer receivables			—				—
Prepayments			—				10
Regulatory assets-current			15				6
Property, plant and equipment			8,799				5,844
Regulatory assets-noncurrent			150				52
Other deferred charges and     other assets			9				—
Total assets		$	9,122			$	5,982
Liabilities
Accounts payable		$	2			$	—
Accrued interest, payroll     and taxes			2				—
Other current liabilities			16				—
Asset retirement obligations-     noncurrent			220				38
Other deferred credits and     other liabilities			—				—
Total liabilities		$	240			$	38

Note 17. Short-Term Debt and Credit Agreements

The Companies use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion Energy utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by capital

127

Combined Notes to Consolidated Financial Statements, Continued

projects, commodity prices, hedging levels, Dominion Energy’s credit ratings and the credit quality of its counterparties.

Dominion Energy

Dominion Energy’s short-term financing is primarily supported by its joint revolving credit facility. In April 2025, Dominion Energy amended its joint revolving credit facility to, among other things, increase the facility limit from $6.0 billion to $7.0 billion, increase the letters of credit support from $2.0 billion to $3.0 billion and extend the maturity date from June 2026 to April 2030. The key financial covenants in the facility are unchanged except for a technical clarification to the calculation of equity utilized in the total debt to total capital ratio.

Dominion Energy’s commercial paper and letters of credit outstanding, as well as its capacity available under the credit facility discussed above and its 364-day revolving credit agreement, were as follows:

		Facility Limit				Outstanding Commercial Paper(1)				Outstanding Letters of Credit				Facility Capacity Available
(millions)
At December 31, 2025
Joint revolving credit    facility(2)		$	7,000			$	2,035			$	1			$	4,964
364-day revolving credit    facility(3)			1,000				—								1,000
Total		$	8,000			$	2,035			$	1			$	5,964
At December 31, 2024
Joint revolving credit    facility(2)		$	6,000			$	2,061			$	10			$	3,929
Total		$	6,000			$	2,061			$	10			$	3,929

(1) The weighted-average interest rate of the outstanding commercial paper supported by Dominion Energy’s joint revolving credit facility was 4.08% and 4.74% at December 31, 2025 and 2024, respectively.

(2)This credit facility matures in April 2030, with the potential to be extended by the borrowers to April 2032, and can be used by the borrowers under the credit facility to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $3.0 billion of letters of credit, for working capital and other general corporate purposes. Through February 2026, Dominion Energy had $14 million in letters of credit issued and outstanding under this facility.

(3)This credit facility, entered into in April 2025 with certain lenders, matures in April 2026 and contains a maximum allowed total debt to total capital ratio consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility. This credit facility can be used to support bank borrowings and the issuance of commercial paper.

DESC’s short-term financing is supported through its access as a co-borrower to the joint revolving credit facility discussed above with the Companies. At December 31, 2025, the sub-limit for DESC was $900 million.

In March 2025, FERC granted DESC authority through March 2027 to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act) in amounts not to exceed $1.8 billion outstanding with maturity dates of one year or less. In addition, in March 2025, FERC granted GENCO authority through March 2027 to issue short-term indebtedness not to exceed $300 million outstanding with maturity dates of one year or less.

In addition to the credit facilities mentioned above, Dominion Energy’s credit facilities and agreements also consist of the following:

•An agreement entered into with a financial institution in March 2023, which it expects to allow it to issue up to $100 million in letters of credit. At December 31, 2025 and 2024, $26 million and $48 million in letters of credit were issued and outstanding under this agreement, respectively.

•An agreement entered into with a financial institution in June 2024, subsequently amended in January 2025, which it expects to allow it to issue up to a combined $275 million in letters of credit at either Dominion Energy or Virginia Power. At December 31, 2025 and 2024, Dominion Energy had $102 million and $88 million in letters of credit issued and outstanding under this agreement, including $81 million and $77 million for Virginia Power, respectively.

•An agreement entered into with a financial institution in January 2025, which it expects to allow it to issue up to a combined $150 million in letters of credit, with $50 million available to Dominion Energy and $100 million available to Virginia Power. At December 31, 2025, Dominion Energy had $150 million in letters of credit issued and outstanding under this agreement, including $100 million for Virginia Power. In January 2026, Dominion Energy amended this agreement to allow it to issue up to an expected combined $250 million in letters of credit, with $50 million available to Dominion Energy and $200 million available to Virginia Power. Through February 2026, Dominion Energy had $250 million in letters of credit issued and outstanding under this agreement, including $200 million for Virginia Power.

•An agreement entered into with a financial institution in September 2025, subsequently amended in December 2025, which it expects to allow it to issue up to $500 million in letters of credit with $100 million available to Dominion Energy and $400 million available to Virginia Power. At December 31, 2025, Dominion Energy had $379 million in letters of credit issued and outstanding under this agreement, all of which was issued and outstanding for Virginia Power. Through February 2026, Dominion Energy had $358 million in letters of credit issued and outstanding under this agreement, including $351 million for Virginia Power.

Dominion Energy has an effective shelf registration statement with the SEC for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability InvestmentSM. The registration limits the principal amount that may be outstanding at any one time to $1.0 billion. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Dominion Energy Reliability Investment Committee, or its designee, on a weekly basis. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Dominion Energy or at the investor’s option at any time. At December 31, 2025 and 2024, Dominion Energy’s Consolidated Balance Sheets include $422 million and $439 million, respectively, presented within short-term debt with weighted-average interest rates of 3.75% and 4.50%, respectively. The proceeds are used for general corporate purposes and to repay debt.

In February 2026, Dominion Energy entered into an approximately $1.3 billion 364-day term loan facility which bears

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interest at a variable rate, contains a maximum allowed total debt to total capital ratio consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility and will mature in February 2027, with the proceeds to be used to repay existing debt and for other general corporate purposes. In February 2026, Dominion Energy borrowed an initial $500 million with the proceeds used for general corporate purposes. Subsequently in February 2026, Dominion Energy provided notice to borrow an additional $300 million under this facility.

In January 2023, Dominion Energy entered into a $2.5 billion 364-day term loan facility which bore interest at a variable rate and was scheduled to mature in January 2024 with the proceeds to be used to repay existing long-term debt and short-term debt upon maturity and for other general corporate purposes. Concurrently, Dominion Energy borrowed an initial $1.0 billion with the proceeds used to repay long-term debt. In February and March 2023, Dominion Energy borrowed $500 million and $1.0 billion, respectively, with the proceeds used for general corporate purposes and to repay long-term debt. In January 2024, the facility was amended to mature July 2024. The amended agreement contained certain mandatory early repayment provisions, including that any after-tax proceeds in connection with the East Ohio, Questar Gas and PSNC Transactions be applied to any outstanding borrowings under the facility. In March 2024, Dominion Energy repaid the full $2.5 billion outstanding using after-tax proceeds received in connection with the East Ohio Transaction. The maximum allowed total debt to total capital ratio under the facility was consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility.

In July 2023, Dominion Energy entered into two $600 million 364-day term loan facilities which bore interest at a variable rate and were scheduled to mature in July 2024 with the proceeds to be used to repay existing long-term debt and short-term debt upon maturity and for other general corporate purposes. Subsequently in July 2023, Dominion Energy borrowed an initial $750 million in the aggregate under these facilities with the proceeds used to repay short-term debt and for general corporate purposes. Dominion Energy was permitted to make up to three additional borrowings under each agreement through November 2023, at which point any unused capacity would cease to be available to Dominion Energy. The agreements contained certain mandatory early repayment provisions, including that any after-tax proceeds in connection with a sale of Dominion Energy’s noncontrolling interest in Cove Point, following the repayment of DECP Holding’s term loan secured by its noncontrolling interest in Cove Point, be applied to any outstanding borrowings under the facilities. In September 2023, Dominion Energy repaid the $750 million borrowing with after-tax proceeds from the sale of Dominion Energy’s noncontrolling interest in Cove Point, as discussed in Note 9. Subsequently in September 2023, Dominion Energy borrowed $225 million in the aggregate under these facilities with the proceeds used to repay short-term debt and for general corporate purposes. In October 2023, Dominion Energy repaid the $225 million borrowing and terminated the facilities along with any remaining unused commitments.

In October 2023, Dominion Energy entered into a $2.25 billion 364-day term loan facility which bore interest at a variable rate with the proceeds to be used for general corporate purposes, which was scheduled to mature in October 2024. Concurrently, Dominion Energy borrowed an initial $1.0 billion with the proceeds used for general corporate purposes, including to repay short-term and long-term debt. In November and December 2023, Dominion Energy borrowed $500 million and $750 million, respectively, with the proceeds used for general corporate purposes. Dominion Energy also had the ability through August 2024 to request an increase in the amount of this facility by up to an additional $500 million. The agreement contained certain mandatory early repayment provisions, including that any after-tax proceeds in connection with the East Ohio, PSNC and Questar Gas Transactions, following the repayment of the 364-day term loan facility entered into in January 2023, be applied to any outstanding borrowings under this facility. In March 2024, Dominion Energy repaid $1.8 billion using after-tax proceeds received in connection with the East Ohio Transaction. Subsequently in March 2024, Dominion Energy requested and received a $500 million increase to the amount of the facility and concurrently borrowed $500 million with the proceeds used for general corporate purposes. In May 2024, Dominion Energy repaid the full $976 million outstanding under the facility, using after-tax proceeds received in connection with the Questar Gas Transaction. The maximum allowed total debt to total capital ratio under this facility was consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility.

Virginia Power

Virginia Power’s short-term financing is supported through its access as co-borrower to Dominion Energy’s $7.0 billion joint revolving credit facility, as most recently amended in April 2025.

Virginia Power’s share of commercial paper and letters of credit outstanding under the joint revolving credit facility with Dominion Energy and DESC were as follows:

		Facility Limit				Outstanding Commercial Paper(1)				Outstanding Letters of Credit
(millions)
At December 31, 2025
Joint revolving credit    facility(2)		$	7,000			$	675			$	—
At December 31, 2024
Joint revolving credit    facility(2)			6,000				950				10

(1)The weighted-average interest rates of the outstanding commercial paper supported by the credit facility was 4.04% and 4.73% at December 31, 2025 and 2024, respectively.

(2)The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy and DESC. The sub-limit for Virginia Power is set pursuant to the terms of the facility but can be changed at the option of the borrowers multiple times per year. At December 31, 2025, the sub-limit for Virginia Power was $4.0 billion. If Virginia Power has liquidity needs in excess of its current sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion Energy. This credit facility matures in April 2030, with the potential to be extended by the borrowers to April 2032. The credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $3.0 billion (or the sub-limit, whichever is less) of letters of credit, for working capital and other general corporate purposes.

129

Combined Notes to Consolidated Financial Statements, Continued

In addition to the credit facility mentioned above, Virginia Power’s credit facilities and agreements also consist of the following:

•An agreement entered into with a financial institution in March 2023, which it expects to allow it to issue up to $300 million in letters of credit. At December 31, 2025 and 2024, $281 million and $112 million, respectively, in letters of credit were issued and outstanding under this agreement. Through February 2026, Virginia Power had $157 million in letters of credit issued and outstanding under this agreement.

•An agreement entered into with a financial institution in June 2024, subsequently amended in January 2025, which it expects to allow it to issue up to a combined $275 million in letters of credit at either Dominion Energy or Virginia Power. At December 31, 2025 and 2024, Virginia Power had $81 million and $77 million, out of Dominion Energy’s total $102 million and $88 million, respectively, in letters of credit issued and outstanding under this agreement.

•An agreement entered into with a financial institution in January 2025, which it expects to allow it to issue up to a combined $150 million in letters of credit, with $50 million available to Dominion Energy and $100 million available to Virginia Power. At December 31, 2025, Virginia Power had $100 million in letters of credit issued and outstanding under this agreement. In January 2026, Dominion Energy amended this agreement to allow it to issue up to an expected combined $250 million in letters of credit, with $50 million available to Dominion Energy and $200 million available to Virginia Power. Through February 2026, Virginia Power had $200 million in letters of credit issued and outstanding under this agreement.

•An agreement entered into with a financial institution in September 2025, subsequently amended in December 2025, which it expects to allow it to issue up to $500 million in letters of credit with $100 million available to Dominion Energy and $400 million available to Virginia Power. At December 31, 2025, Virginia Power had $379 million in letters of credit issued and outstanding under this agreement. Through February 2026, Virginia Power had $351 million in letters of credit issued and outstanding under this agreement.

•Agreements entered into with financial institutions in September 2025, which it expects to allow it to issue up to $2.0 billion in letters of credit. At December 31, 2025, Virginia Power had $1.0 billion in letters of credit issued and outstanding under these agreements. Through February 2026, Virginia Power had $1.4 billion in letters of credit issued and outstanding under these agreements.

Note 18. Long-Term Debt

	2025 Weighted- average Coupon(1)				Dominion Energy								Virginia Power
At December 31,					2025				2024				2025				2024
(millions, except percentages)
Sustainability Revolving Credit Agreement, variable rate, due 2028(2)					$	—			$	—
Unsecured Senior Notes:
1.45% to 7.00%, due 2025 to 2052(3)		4.36	%			12,526				11,176
Junior Subordinated Notes:
Payable to Affiliated Trust, 8.40%, due 2031		8.40	%			10				10
6.00% to 7.00%, due 2054 to 2056		6.48	%			6,025				3,250
Virginia Power:
Unsecured Senior Notes, 2.30% to 8.875%, due 2025 to 2055		4.53	%			21,385				18,785			$	21,385			$	18,785
Tax-Exempt Financings, 3.125% to 3.80%, due 2032 to 2041(4)		3.52	%			625				625				625				625
Senior Secured Deferred Fuel Cost Bonds, 4.877% and 5.088%, due 2029    and 2033		4.92	%			1,054				1,217				1,054				1,217
DESC:
First Mortgage Bonds, 2.30% to 6.625%, due 2028 to 2065		5.24	%			4,584				4,134
Tax-Exempt Financings(5):
Variable rate due 2038		3.36	%			35				35
3.625% and 4.00%, due 2028 and 2033		3.90	%			54				54
GENCO, variable rate due 2038		3.36	%			33				33
Other		3.56	%			1				1
Total Principal					$	46,332			$	39,320			$	23,064			$	20,627
Securities due within one year(6)						(2,290	)			(1,662	)			(1,321	)			(513	)
Unamortized discount, premium and debt issuance costs, net						(403	)			(347	)			(209	)			(186	)
Finance leases						436				214				194				110
Total long-term debt					$	44,075			$	37,525			$	21,728			$	20,038

(1)Represents weighted-average coupon rates for debt outstanding at December 31, 2025.

(2)This $1.0 billion supplemental credit facility, entered in 2021, most recently amended in April 2025, offers a reduced interest rate margin with respect to borrowed amounts allocated to certain environmental sustainability or social investment initiatives. Proceeds of the supplemental credit facility also may be used for general corporate purposes, but such proceeds are not eligible for a reduced interest rate margin. In March 2023, Dominion Energy borrowed $450 million with the proceeds used for general corporate purposes. In April 2023, Dominion Energy repaid $450 million borrowed for general corporate purposes. In September 2023, Dominion Energy borrowed $450 million under this facility with the proceeds used for general corporate purposes. In October 2023, Dominion Energy repaid $450 million borrowed for general corporate purposes. In May 2024, Dominion Energy repaid $450 million borrowed to support environmental sustainability and social investment initiatives. In April 2025, the facility was amended to, among other things, extend

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the maturity date from June 2025 to April 2028, increase the commitment from $900 million to $1.0 billion and update certain pricing terms. In February 2026, Dominion Energy borrowed $500 million with the proceeds used to support environmental sustainability and social investment initiatives.

(3)Includes debt assumed by Dominion Energy from the merger of its former CNG subsidiary.

(4)These financings relate to certain pollution control equipment at Virginia Power’s generating facilities.

(5)Industrial revenue bonds totaling $68 million are secured by letters of credit that expire, subject to renewal, in the fourth quarter of 2026.

(6)Dominion Energy and Virginia Power’s weighted-average rate for securities due within one year was 2.80% and 3.34%, respectively, at December 31, 2025.

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2025 were as follows:

		2026				2027				2028				2029				2030				Thereafter				Total
(millions, except percentages)
Dominion Energy
First Mortgage Bonds		$	—			$	—			$	53			$	—			$	—			$	4,531			$	4,584
Unsecured Senior Notes			2,120				1,783				2,195				500				2,300				25,014				33,912
Senior Secured Deferred Fuel Cost Bonds			171				180				190				198				208				107				1,054
Tax-Exempt Financings			—				—				39				—				—				708				747
Junior Subordinated Notes			—				—				—				—				—				6,035				6,035
Total		$	2,291			$	1,963			$	2,477			$	698			$	2,508			$	36,395			$	46,332
Weighted-average Coupon			2.80	%			3.86	%			4.31	%			3.44	%			4.02	%			5.09	%
Virginia Power
Unsecured Senior Notes		$	1,150			$	1,350			$	700			$	500			$	—			$	17,685			$	21,385
Senior Secured Deferred Fuel Cost Bonds			171				180				190				198				208				107				1,054
Tax-Exempt Financings			—				—				—				—				—				625				625
Total		$	1,321			$	1,530			$	890			$	698			$	208			$	18,417			$	23,064
Weighted-average Coupon			3.34	%			3.77	%			4.03	%			3.44	%			4.88	%			4.73	%

The Companies’ credit facilities and debt agreements, both short-term and long-term, contain customary covenants and default provisions. At December 31, 2025, there were no events of default under these covenants.

Senior Secured Deferred Fuel Cost Bonds

In February 2024, VPFS issued $439 million of 5.088% senior secured deferred fuel cost bonds with a scheduled final payment date of May 2027 and a final maturity date of May 2029 and $843 million of 4.877% senior secured deferred fuel cost bonds with a scheduled final payment date of May 2031 and a final maturity date of May 2033. The full principal of each tranche of bonds is payable semi-annually according to a sinking fund schedule. Interest on each tranche of bonds accrues from the date of issuance and is payable semi-annually. Payment on the bonds commenced in November 2024. The scheduled final payment date for the applicable tranche is the date by which all interest and principal for such tranche is expected to be paid in full. The final maturity date of the applicable tranche is the legal maturity date for such tranche. The bonds are not subject to optional redemption prior to their stated maturity. VPFS as the issuer of the bonds is a bankruptcy remote, wholly-owned special purpose subsidiary of Virginia Power formed in October 2023 for the sole purpose of securitizing certain of Virginia Power’s under-recovered deferred fuel balance through the issuance of deferred fuel cost bonds. VPFS is considered to be a VIE primarily because its equity capitalization is insufficient to support its operations. Virginia Power is considered the primary beneficiary and consolidates VPFS as it has the power to direct the most significant activities of VPFS, including performing servicing activities such as billing and collecting the deferred fuel cost charges. Pursuant to the financing order issued by the Virginia Commission in November 2023, Virginia Power sold to VPFS its right to receive revenues from the non-bypassable deferred fuel cost charges from Virginia Power’s retail customers in Virginia, except for certain exempt customers, as deferred fuel cost property. The securitization bondholders have recourse solely with respect to the deferred fuel cost property owned by VPFS and no recourse to any other assets of Dominion Energy or Virginia Power. Any deferred fuel cost charges collected by Virginia Power to pay for bond servicing and other qualified costs are deferred fuel cost property solely owned by VPFS. Any deferred fuel cost charges collected by Virginia Power are remitted to a trustee and are not available to other creditors of Virginia Power or Dominion Energy.

Junior Subordinated Notes

In October 2014, Dominion Energy issued $685 million of October 2014 hybrids that bore interest at 5.75% per year until October 1, 2024. In October 2024, Dominion Energy redeemed all $685 million in outstanding principal amount at par plus accrued interest including interest accrued at a floating rate effective October 2024. The notes would have otherwise matured in 2054. Dominion Energy recorded a charge of $7 million ($5 million after-tax) within interest expense in its Consolidated Statements of Income in connection with this early redemption.

In May 2024, Dominion Energy issued $2.0 billion of junior subordinated notes, consisting of $1.0 billion of 2024 Series A JSNs and $1.0 billion of 2024 Series B JSNs that mature in 2055 and 2054, respectively. The 2024 Series A JSNs will bear interest at 6.875% until February 1, 2030. The interest rate will reset every five years beginning on February 1, 2030, to equal the then-current five-year U.S. Treasury rate plus a spread of 2.386%, provided that the interest rate will not reset below 6.875%. The 2024 Series B JSNs will bear interest at 7.0% until June 1, 2034. The interest rate will reset every five years beginning on June 1, 2034, to equal the then-current five-year U.S. Treasury rate plus a spread of 2.511%, provided that the interest rate will not reset below 7.0%. Dominion Energy may defer interest payments on the 2024 Series A JSNs or 2024 Series B JSNs on one or more occasions for up to 10

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Combined Notes to Consolidated Financial Statements, Continued

consecutive years. If interest payments on the 2024 Series A JSNs and the 2024 Series B JSNs are deferred, Dominion Energy may not, subject to certain limited exceptions, declare or pay any dividends or other distributions on, or redeem, repurchase or otherwise acquire any of its capital stock during the deferral period. Also, during the deferral period, Dominion Energy may not make any payments on or redeem or repurchase any debt securities or make any payments under any guarantee of debt that, in each case, is equal or junior in right of payment to the 2024 Series A JSNs and the 2024 Series B JSNs. Dominion Energy used the proceeds from this issuance for general corporate purposes including the repayment of short-term debt, the repayment of amounts outstanding under the Sustainability Revolving Credit Agreement as discussed above and the repurchase of Series B Preferred Stock as discussed in Note 19.

In November 2024, Dominion Energy issued $1.25 billion of 2024 Series C JSNs that mature in 2055. The 2024 Series C JSNs will bear interest at 6.625% until May 15, 2035. The interest rate will reset every five years beginning on May 15, 2035, to equal the then-current-five-year U.S. Treasury rate plus a spread of 2.207%. Dominion Energy may defer interest payments on the 2024 Series C JSNs on one or more occasions for up to 10 consecutive years. If interest payments on the 2024 Series C JSNs are deferred, Dominion Energy may not, subject to certain limited exceptions, declare or pay any dividends or other distributions on, or redeem, repurchase or otherwise acquire any of its capital stock during the deferral period. Also, during the deferral period, Dominion Energy may not make any payments on or redeem or repurchase any debt securities or make any payments under any guarantee of debt that, in each case, is equal or junior in right of payment to the 2024 Series C JSNs. Dominion Energy used the proceeds from the issuance for general corporate purposes and to repay short-term debt.

In August 2025, Dominion Energy issued $1.5 billion of junior subordinated notes, consisting of $825 million of 2025 Series A JSNs and $700 million of 2025 Series B JSNs that both mature in 2056. In October 2025, Dominion Energy issued an additional $1.3 billion of junior subordinated notes, consisting of $625 million of additional 2025 Series A JSNs and $625 million of additional 2025 Series B JSNs. The 2025 Series A JSNs will bear interest at 6.0% until February 15, 2031. The interest rate will reset every five years beginning on February 15, 2031, to equal the then-current five-year U.S. Treasury rate plus a spread of 2.262%, provided that the interest rate will not reset below 6.0%. The 2025 Series B JSNs will bear interest at 6.20% until February 15, 2036. The interest rate will reset every five years beginning on February 15, 2036, to equal the then-current five-year U.S. Treasury rate plus a spread of 2.006%, provided that the interest rate will not reset below 6.20%. Dominion Energy may defer interest payments on the 2025 Series A JSNs and/or 2025 Series B JSNs on one or more occasions for up to 10 consecutive years. If interest payments on the 2025 Series A JSNs or the 2025 Series B JSNs are deferred, Dominion Energy may not, subject to certain limited exceptions, declare or pay any dividends or other distributions on, or redeem, repurchase or otherwise acquire any of its capital stock during the deferral period. Also, during the deferral period, Dominion Energy may not make any payments on or redeem or repurchase any debt securities or make any payments under any guarantee of debt that, in each case, is equal or junior in right of payment to the 2025 Series A JSNs and the 2025 Series B JSNs. Dominion Energy used the proceeds from the issuance for general corporate purposes and to repay short-term debt.

Derivative Restructuring

In June 2020, Dominion Energy amended a portfolio of interest rate swaps with a notional value of $2.0 billion, extending the mandatory termination dates from 2020 and 2021 to December 2024. As a result of this noncash financing activity with an embedded interest rate swap, Dominion Energy recorded $326 million in other long-term debt representing the net present value of the initial fair value measurement of the new contract with an imputed interest rate of 1.19%, with an embedded interest rate derivative that had a fair value of zero at inception. In 2021 and 2022, Dominion Energy settled certain of the outstanding interest rate swaps which would have otherwise matured in December 2024. In December 2024, Dominion Energy settled the remaining $144 million of outstanding interest rate swaps.

In August 2020, Virginia Power amended a portfolio of interest rate swaps with a notional value of $900 million, extending the mandatory termination dates from 2020 to December 2023. As a result of this noncash financing activity with an embedded interest rate swap, Virginia Power recorded $443 million in other long-term debt representing the net present value of the initial fair value measurement of the new contract with an imputed interest rate of 0.34%, with an embedded interest rate derivative that had a fair value of zero at inception. The interest rate swaps were in a hedge relationship prior to the transaction. Virginia Power de-designated the hedge relationships prior to the transaction and then designated the new interest rate swap in a hedge relationship after the transaction. In March 2023, Virginia Power settled the remaining $448 million of outstanding interest rate swaps which would have otherwise matured in December 2023.

Eagle Solar

In February 2024, Eagle Solar redeemed the remaining principal outstanding of $279 million of its 4.82% senior secured notes. The debt, which otherwise would have matured in 2042, was nonrecourse to Dominion Energy and was secured by Eagle Solar's interest in certain solar facilities. Dominion Energy recognized a charge of $10 million during the year ended December 31, 2024 within interest expense in its Consolidated Statements of Income in connection with the early redemption of these notes.

Tax-Exempt Financing

In October 2024, Dominion Energy redeemed all $27 million in outstanding principal amount of its 3.80% Peninsula Ports Authority of Virginia Coal Terminal Revenue Refunding Bonds at par plus accrued interest. The bonds would have otherwise matured in 2033.

Note 19. Preferred Stock

Dominion Energy is authorized to issue up to 20 million shares of preferred stock, which may be designated into separate classes. At both December 31, 2025 and 2024, Dominion Energy had issued and outstanding 1.0 million shares of the Series C Preferred Stock.

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DESC is authorized to issue up to 20 million shares of preferred stock. At both December 31, 2025 and 2024, DESC had issued and outstanding 1,000 shares of preferred stock, all of which were held by SCANA and are eliminated in consolidation.

Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference; however, none were issued and outstanding at December 31, 2025 or 2024.

Series B Preferred Stock

In December 2019, Dominion Energy issued 800,000 shares of Series B Preferred Stock for $791 million, net of $9 million of issuance costs. The preferred stock had a liquidation preference of $1,000 per share and paid a 4.65% dividend per share on the liquidation preference. Dividends were paid cumulatively on a semi-annual basis, commencing June 15, 2020. The dividend rate for the Series B Preferred Stock was scheduled to reset every five years beginning on December 15, 2024 to equal the then-current five-year U.S. Treasury rate plus a spread of 2.993%.

Dominion Energy was permitted to, at its option, redeem the Series B Preferred Stock in whole or in part on December 15, 2024 or on any subsequent fifth anniversary of such date at a price equal to $1,000 per share plus any accumulated and unpaid dividends. Dominion Energy was also permitted to, at its option, redeem the Series B Preferred Stock in whole but not in part at a price equal to $1,020 per share plus any accumulated and unpaid dividends at any time within a certain period of time following any change in the criteria ratings agencies use to assign equity credit to securities such as the Series B Preferred Stock that had certain adverse effects on the equity credit actually received by the Series B Preferred Stock.

In June 2024, Dominion Energy completed a tender offer repurchasing 0.4 million shares of Series B Preferred Stock and in December 2024 redeemed the remaining 0.4 million shares outstanding. Dominion Energy recorded dividends of $24 million ($42.86 per share) for the year ended December 31, 2024, excluding deemed dividends of $10 million representing deferred issuance costs, legal and bank fees and excise tax associated with the repurchase and redemption, and $37 million ($46.50 per share) for the year ended December 31, 2023.

Series C Preferred Stock

In December 2021, Dominion Energy issued 750,000 shares of Series C Preferred Stock for $742 million, net of $8 million of issuance costs. Also in December 2021, Dominion Energy issued 250,000 shares of Series C Preferred Stock valued at $250 million to the qualified benefit pension plans. The preferred stock has a liquidation preference of $1,000 per share and currently pays a 4.35% dividend per share on the liquidation preference. Dividends are paid cumulatively on a semi-annual basis, commencing April 15, 2022. Dominion Energy recorded dividends of $44 million ($43.50 per share) for each of the years ended December 31, 2025, 2024 and 2023. The dividend rate for the Series C Preferred Stock will be reset every five years beginning on April 15, 2027 to equal the then-current five-year U.S. Treasury rate plus a spread of 3.195%. Unless all accumulated and unpaid dividends on the Series C Preferred Stock have been declared and paid, Dominion Energy may not make any distributions on any of its capital stock ranking equal or junior to the Series C Preferred Stock as to dividends or upon liquidation, including through dividends, redemptions, repurchases or otherwise.

Dominion Energy may, at its option, redeem the Series C Preferred Stock in whole or in part anytime from and including January 15, 2027 through and including April 15, 2027 or during any subsequent fifth anniversary of such period at a price equal to $1,000 per share plus any accumulated and unpaid dividends. Dominion Energy may also, at its option, redeem the Series C Preferred Stock in whole but not in part at a price equal to $1,020 per share plus any accumulated and unpaid dividends at any time within a certain period of time following any change in the criteria ratings agencies use to assign equity credit to securities such as the Series C Preferred Stock that has certain adverse effects on the equity credit actually received by the Series C Preferred Stock.

Holders of the Series C Preferred Stock have no voting rights except in the limited circumstances provided for in the terms of the Series C Preferred Stock or as otherwise required by applicable law. The Series C Preferred Stock is not subject to any sinking fund or other obligation of ours to redeem, repurchase or retire the Series C Preferred Stock. The preferred stock contains no conversion rights.

Note 20. Equity

Common Stock

Dominion Energy

During 2025, 2024 and 2023, Dominion Energy recorded, net of fees and commissions, $1.5 billion, $732 million and $94 million from the issuance of approximately 27 million, 14 million and 2 million shares of common stock, respectively, as described below.

Dominion Energy Direct® and Employee Savings Plans

Dominion Energy maintains Dominion Energy Direct® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January 2021, Dominion Energy began issuing new shares of common stock for these direct stock purchase plans. In August 2023, Dominion Energy began purchasing its common stock on the open market for these direct stock purchase plans, and in March 2024, began issuing new shares of common stock. During 2025, 2024 and 2023, Dominion Energy issued 2.5 million, 2.7 million and 1.7 million, respectively, of such shares and received proceeds of $139 million, $138 million and $94 million, respectively.

At-the-Market Programs

May 2024 At-the-Market Program

In May 2024, Dominion Energy entered into sales agency agreements to effect sales under an at-the-market program. Under the sales agency agreements, Dominion Energy may, from time to time, offer and sell shares of its common stock through the sales agents or enter into one or more forward sale agreements with respect to shares of its common stock. Sales by Dominion Energy through the sales agents or by forward sellers pursuant to a forward sale agreement cannot exceed $1.8 billion in the aggregate. Except in certain circumstances, Dominion Energy can elect physical, cash or net settlement of the forward sale agreements. Through August 2024, Dominion Energy entered into forward sale agreements for approximately 11.4 million shares of its common stock at a weighted-average initial forward price of $53.23 per share. In

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Combined Notes to Consolidated Financial Statements, Continued

December 2024, Dominion Energy provided notice to elect physical settlement of the forward sale agreements and in December 2024 settled the agreements at a weighted-average final forward price of $52.20 per share and received total proceeds of $594 million.

From September through December 2024, Dominion Energy entered into forward sale agreements for approximately 9.7 million shares of its common stock at a weighted-average initial forward price of $57.78 per share. During the first quarter of 2025, Dominion Energy entered into forward sale agreements for approximately 8.8 million shares of its common stock at a weighted-average initial forward price of $55.34 per share. In December 2025, Dominion Energy provided notice to elect physical settlement of the forward sale agreements and in December 2025 settled the agreements at a weighted-average final forward price of $55.26 per share and received total proceeds of $1.0 billion.

During the third quarter of 2025, Dominion Energy entered into forward sale agreements for approximately 2.4 million shares of its common stock expected to be settled by the fourth quarter of 2027, at a weighted-average initial forward price of $59.91 per share.

February 2025 At-the-Market Program

In February 2025, Dominion Energy entered into sales agency agreements to effect sales under a new at-the-market program. Under the sales agency agreements, Dominion Energy may, from time to time, offer and sell shares of its common stock through the sales agents or enter into one or more forward sale agreements with respect to shares of its common stock. Sales by Dominion Energy through the sales agents or by forward sellers pursuant to the forward sale agreements could not initially exceed $1.2 billion in the aggregate, with Dominion Energy having the ability from time to time to increase such amount at its option. Except in certain circumstances, Dominion Energy can elect physical, cash or net settlement of the forward sale agreements. During the second quarter of 2025, Dominion Energy entered into forward sale agreements for approximately 11.0 million shares of its common stock expected to be settled in the fourth quarter of 2026 at a weighted-average initial forward price of $55.83 per share.

During the third quarter of 2025, Dominion Energy entered into forward sale agreements for approximately 9.6 million shares of its common stock expected to be settled by the fourth quarter of 2027 at a weighted-average initial forward price of $61.11 per share. In December 2025, Dominion Energy provided notice to elect physical settlement of approximately 5.4 million shares under these forward sales agreements, and in December 2025 settled the agreements at a weighted-average final forward price of $60.44 per share and received total proceeds of $325 million.

In October 2025, Dominion Energy increased the maximum authorized amount of capacity available under this at-the-market program by $1.8 billion.

Repurchase of Common Stock

Dominion Energy did not repurchase any shares in 2025, 2024 or 2023, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which do not count against its stock repurchase authorization.

In November 2020, the Board of Directors authorized the repurchase of up to $1.0 billion of Dominion Energy’s common stock, with $0.9 billion available at December 31, 2025. This repurchase program does not include a specific timetable or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors.

Virginia Power

In 2025, Virginia Power issued 49,636 shares of its common stock to Dominion Energy for $3.5 billion. The proceeds were utilized to reduce the aggregate amount outstanding under its intercompany credit facility with Dominion Energy. Virginia Power issued the shares pursuant to a Virginia Commission order authorizing the issuance of up to $3.5 billion of common stock through the end of 2025 in order to maintain adequate credit metrics and efficient access to capital markets while funding necessary capital expenditures, as discussed in Note 13.

Virginia Power did not issue any shares of its common stock to Dominion Energy in 2024.

In the fourth quarter of 2023, Virginia Power issued 49,522 shares of its common stock to Dominion Energy for $3.25 billion with the proceeds utilized to repay substantially all of the outstanding borrowings under Virginia Power’s intercompany credit facility with Dominion Energy. Virginia Power issued the shares pursuant to a Virginia Commission order authorizing the issuance of up to $3.25 billion of common stock to Dominion Energy through the end of 2023 as part of its reasonable efforts to maintain a common equity capitalization to total capitalization ratio of 52.10% through December 2024 in accordance with legislation enacted in Virginia in April 2023 as discussed in Note 13.

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Accumulated Other Comprehensive Income (Loss)

Dominion Energy

The following table presents Dominion Energy’s changes in AOCI (net of tax) and reclassifications out of AOCI by component:

		Total Derivative- Hedging Activities(1)				Investment Securities				Pension and other postretirement benefit costs(2)				Total
(millions)
Year Ended December 31, 2025
Beginning balance		$	(229	)		$	(19	)		$	38			$	(210	)
Beginning balance, tax		58				9					(9	)		58
Beginning balance, net of tax			(171	)			(10	)			29				(152	)
Other comprehensive income before reclassifications: gains (losses)			5				15				—				20
Amounts reclassified from AOCI (gains) losses:
Interest and related charges			39												39
Other income (expense)							(7	)			(12	)			(19	)
Total			39				(7	)			(12	)			20
Income tax expense (benefit)			(10	)			2				2				(6	)
Total, net of tax			29				(5	)			(10	)			14
Net current period other comprehensive income (loss)			34				10				(10	)			34
Ending balance, net of tax			(137	)			—				19				(118	)
Ending balance, tax			46				—				(7	)			39
Ending balance		$	(183	)		$	—			$	26			$	(157	)
Year Ended December 31, 2024
Beginning balance		$	(289	)		$	2			$	57			$	(230	)
Beginning balance, tax			73				(1	)			(14	)			58
Beginning balance, net of tax			(216	)			1				43				(172	)
Other comprehensive income before reclassifications: gains (losses)			13				(19	)			(2	)			(8	)
Amounts reclassified from AOCI (gains) losses:
Interest and related charges			43												43
Other income (expense)			—				11				(16	)			(5	)
Total			43				11				(16	)			38
Income tax expense (benefit)			(11	)			(3	)			4				(10	)
Total, net of tax			32				8				(12	)			28
Net current period other comprehensive income (loss)			45				(11	)			(14	)			20
Ending balance, net of tax			(171	)			(10	)			29				(152	)
Ending balance, tax			58				9				(9	)			58
Ending balance		$	(229	)		$	(19	)		$	38			$	(210	)

(1)Comprised entirely of interest rate derivative hedging activities.

(2)Comprised entirely of prior service cost. See Note 22 for additional information.

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Combined Notes to Consolidated Financial Statements, Continued

Virginia Power

The following table presents Virginia Power’s changes in AOCI (net of tax) and reclassification out of AOCI by component:

		Total Derivative- Hedging Activities(1)				Investment Securities				Total
(millions)
Year Ended December 31, 2025
Beginning balance		$	38			$	(1	)		$	37
Beginning balance, tax			(10	)			1				(9	)
Beginning balance, net of tax			28				—				28
Other comprehensive income before reclassifications: gains (losses)			5				—				5
Amounts reclassified from AOCI (gains) losses:
Interest and related charges			(1	)							(1	)
Other income (expense)							1				1
Total			(1	)			1				—
Income tax expense (benefit)			—				(1	)			(1	)
Total, net of tax			(1	)			—				(1	)
Net current period other comprehensive income (loss)			4				—				4
Ending balance, net of tax			32				—				32
Ending balance, tax			(11	)			—				(11	)
Ending balance			43				—				43
Year Ended December 31, 2024
Beginning balance		$	20			$	1			$	21
Beginning balance, tax			(5	)			1				(4	)
Beginning balance, net of tax			15				2				17
Other comprehensive income before reclassifications: gains (losses)			13				(5	)			8
Amounts reclassified from AOCI (gains) losses:
Other income (expense)			—				4				4
Total			—				4				4
Income tax expense (benefit)			—				(1	)			(1	)
Total, net of tax			—				3				3
Net current period other comprehensive income (loss)			13				(2	)			11
Ending balance, net of tax			28				—				28
Ending balance, tax			(10	)			1				(9	)
Ending balance		$	38			$	(1	)		$	37

(1)Comprised entirely of interest rate derivative hedging activities.

Stock-Based Awards

The 2024 Incentive Compensation Plan permits stock-based awards that include restricted stock, performance grants, goal-based stock, stock options and stock appreciation rights. The Non-Employee Directors Compensation Plan permits grants of restricted stock and stock options. Under provisions of these plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are set at the discretion of the Compensation and Talent Development Committee of the Board of Directors or the Board of Directors itself, as provided under each plan. No options are outstanding under either plan. At December 31, 2025, approximately 26 million shares were available for future grants under these plans.

In 2023, goal-based stock awards were granted in lieu of cash-based performance grants to certain officers who have not achieved a certain targeted level of share ownership prior to 2024. Beginning in 2024, officers were granted performance share awards settling in shares or cash or, for officers who have not achieved a certain targeted level of share ownership at the time of grant, settling in shares. At both December 31, 2025 and 2024, unrecognized compensation cost related to these awards was inconsequential.

Dominion Energy measures and recognizes compensation expense relating to share-based payment transactions over the vesting period based on the fair value of the equity or liability instruments issued. Dominion Energy’s results for the years ended December 31, 2025, 2024 and 2023 include $46 million, $53 million and $44 million, respectively, of compensation costs and $10 million, $12 million and $10 million, respectively, of income tax benefits related to Dominion Energy’s stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion Energy’s Consolidated Statements of Income. Excess Tax Benefits are classified as a financing cash flow.

Restricted Stock

Restricted stock grants are made to officers under Dominion Energy’s LTIP and may also be granted to certain key non-officer employees. The fair value of Dominion Energy’s restricted stock awards is equal to the closing price of Dominion Energy’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period.

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The following table provides a summary of restricted stock activity for the years ended December 31, 2025, 2024 and 2023:

		Shares (millions)				Weighted-average Grant Date Fair Value
Nonvested at December 31, 2022			1.4			$	75.56
Granted			1.0				48.99
Vested			(0.4	)			79.89
Cancelled and forfeited			(0.1	)			53.36
Nonvested at December 31, 2023			1.9			$	61.34
Granted			0.7				55.58
Vested			(0.5	)			71.05
Cancelled and forfeited			(0.2	)			43.13
Nonvested at December 31, 2024			1.9			$	57.10
Granted			0.5				59.19
Vested			(0.4	)			73.43
Cancelled and forfeited			(0.1	)			58.03
Nonvested at December 31, 2025			1.9			$	53.94

At December 31, 2025, unrecognized compensation cost related to nonvested restricted stock awards totaled $61 million and is expected to be recognized over a weighted-average period of 1.9 years. The fair value of restricted stock awards that vested was $27 million, $25 million and $20 million in 2025, 2024 and 2023, respectively. Employees may elect to have shares of restricted stock withheld upon vesting to satisfy tax withholding obligations. The number of shares withheld will vary for each employee depending on the vesting date fair market value of Dominion Energy stock and the applicable federal, state and local tax withholding rates.

Cash-Based Performance Grants

Prior to 2024, cash-based performance grants were issued to Dominion Energy’s officers under Dominion Energy’s LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.

In February 2022, a cash-based performance grant was made to officers. Payout of the performance grant occurred in January 2025 based on the achievement of three performance metrics during 2022, 2023 and 2024: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group, Cumulative Operating EPS and Non-Carbon Emitting Generation Capacity Performance. There was an additional opportunity to earn a portion of the award based on Dominion Energy’s relative price-earnings ratio performance. The total of the payout under the grant was $5 million, all of which was accrued at December 31, 2024.

In February 2023, a cash-based performance grant was made to officers. Payout of the performance grant occurred in January 2026 based on the achievement of three performance metrics during 2023, 2024 and 2025: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group over a 3-year and a 2-year period and Non-Carbon Emitting Generation Capacity Performance. For officers other than the CEO, there is an additional opportunity to earn a portion of the award based on Dominion Energy’s relative price-earnings ratio performance. The total of the payout under the grant was $8 million, all of which was accrued at December 31, 2025.

Performance Share Awards

Performance share awards are granted under Dominion Energy’s LTIP. The performance share awards are settled in cash at the end of the three-year performance period if certain ownership requirements are satisfied. If the ownership requirements have not been met at the time of grant, then the performance share awards are settled in common stock.

In February 2024, a performance share grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2027, based on the achievement of three performance metrics during 2024, 2025 and 2026: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group, Cumulative Operating EPS and Non-Carbon Emitting Generation Capacity Performance. At December 31, 2025, the targeted amount of the three-year grant was $18 million and a liability of $13 million had been accrued for this award.

In February 2025, a performance share grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2028, based on the achievement of three performance metrics during 2025, 2026 and 2027: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group, Cumulative Operating EPS and Non-Carbon Emitting Generation Capacity Performance. At December 31, 2025, the targeted amount of the three-year grant was $22 million and a liability of $7 million had been accrued for this award.

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Combined Notes to Consolidated Financial Statements, Continued

Note 21. Dividend Restrictions

The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be inconsistent with the public interest. At December 31, 2025, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

The North Carolina Commission, in its order approving the SCANA Combination, limited cumulative dividends payable to Dominion Energy by Virginia Power to (i) the amount of retained earnings the day prior to closing of the SCANA Combination plus (ii) any future earnings recorded by Virginia Power after such closing. In addition, notice to the North Carolina Commission is required if payment of dividends causes the equity component of Virginia Power’s capital structure to fall below 45%.

There is no specific restriction from the South Carolina Commission on the payment of dividends paid by DESC. Pursuant to the SCANA Merger Approval Order, the amount of any DESC dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry.

DESC’s bond indenture under which it issues first mortgage bonds contains provisions that could limit the payment of cash dividends on its common stock. DESC's bond indenture permits the payment of dividends on DESC's common stock only either (1) out of its Surplus (as defined in the bond indenture) or (2) in case there is no Surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year.

At December 31, 2025, DESC’s retained earnings exceed the balance established by the Federal Power Act as a reserve on earnings attributable to hydroelectric generation plants. As a result, DESC is permitted to pay dividends without additional regulatory approval provided that such amounts would not bring the retained earnings balance below the established threshold.

See Notes 18 and 19 for a description of potential restrictions on common stock dividend payments by Dominion Energy in connection with the deferral of interest payments on the junior subordinated notes or a failure to pay dividends on the Series C Preferred Stock.

Note 22. Employee Benefit Plans

Defined Benefit Plans

Dominion Energy provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Under the terms of its benefit plans, Dominion Energy reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Dominion Energy maintains qualified noncontributory defined benefit pension plans covering virtually all employees who commenced employment prior to July 2021. Retirement benefits are based primarily on years of service, age and the employee’s compensation. Dominion Energy’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension programs also provide benefits to certain retired executives under company-sponsored nonqualified employee benefit plans. The nonqualified plans are funded through contributions to grantor trusts. Dominion Energy also provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service.

Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates, mortality rates and the rate of compensation increases.

Dominion Energy uses December 31 as the measurement date for all of its employee benefit plans. Dominion Energy immediately recognizes the change in the fair value of plan assets and liabilities and net actuarial gains and losses annually in the fourth quarter of each fiscal year as well as whenever a triggering event occurs that is determined to require remeasurement. Actuarial losses attributable to Dominion Energy’s rate regulated operations are deferred to regulatory assets when it is probable that regulators will permit them to be recovered from customers in future rates. Likewise, actuarial gains attributable to Dominion Energy’s rate regulated operations are deferred to regulatory liabilities when it is probable that regulators will require customer refunds or other benefits through future rates.

Dominion Energy’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns of $1.2 billion and $738 million in 2025 and 2024, respectively, versus expected returns of $835 million and $982 million, respectively. Any investment-related declines in these trusts are immediately recognized in earnings and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.

Pension and Other Postretirement Benefit Plan Remeasurements

As a result of the East Ohio and Questar Gas Transactions in 2024, Dominion Energy remeasured its pension and other postretirement benefit plans. The remeasurements resulted in $217 million ($162 million after-tax) of higher market related impacts on pension and other postretirement plans related to the East Ohio and Questar Gas Transactions, reflected in other income (expense) in Dominion Energy’s Consolidated Statement of Income. The discount rates used for the remeasurements related to the East Ohio and Questar Gas Transactions were 5.62% and 5.75% for the pension plans and 5.61%-5.62% and 5.74% for the other postretirement benefit plans, respectively. All other assumptions used for the remeasurements were consistent with the measurement as of December 31, 2023.

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Funded Status

The following table summarizes the changes in pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status for Dominion Energy:

		Pension Benefits								Other Postretirement Benefits
Year Ended December 31,		2025				2024				2025				2024
(millions, except percentages)
Changes in benefit obligation:
Benefit obligation at beginning of year		$	7,652			$	8,431			$	1,018			$	1,109
Service cost			76				83				11				11
Interest cost			433				431				57				57
Benefits paid			(533	)			(504	)			(82	)			(88	)
Actuarial loss (gain) during the year			241				(404	)			(17	)			(43	)
Plan amendments			(5	)			30				—				—
Settlements and curtailments(1)			(13	)			(415	)			—				(28	)
Benefit obligation at end of year		$	7,851			$	7,652			$	987			$	1,018
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year		$	8,478			$	9,087			$	2,203			$	2,062
Actual return gain on plan assets			931				503				254				235
Employer contributions			33				76				—				—
Benefits paid			(533	)			(504	)			(63	)			(54	)
Plan amendments			(5	)			—				—				—
Settlements(2)			(13	)			(684	)			—				(40	)
Fair value of plan assets at end of year		$	8,891			$	8,478			$	2,394			$	2,203
Funded status at end of year		$	1,040			$	826			$	1,407			$	1,185
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets		$	1,073			$	883			$	1,585			$	1,356
Other current liabilities			(5	)			(7	)			(13	)			(13	)
Noncurrent pension and other postretirement benefit liabilities(3)			(28	)			(50	)			(165	)			(158	)
Net amount recognized		$	1,040			$	826			$	1,407			$	1,185
Significant assumptions used to determine benefit obligations at December 31:
Discount rate		5.59%-5.69%				5.84%-5.87%				5.60%-5.66%				5.83%-5.86%
Weighted-average rate of increase for compensation		4.38%				4.40%				n/a				n/a
Crediting interest rate for cash balance and similar plans		4.34%-4.44%				4.59%-4.62%				n/a				n/a

(1)2025 and 2024 include amounts related to settlements of nonqualified pension obligations. Additionally, 2024 amounts include settlements and curtailment related to the East Ohio and Questar Gas Transactions.

(2)2025 and 2024 include amounts related to settlements of nonqualified pension obligations. Additionally, 2024 amounts include settlements related to the East Ohio and Questar Gas Transactions.

(3)Presented within other deferred credits and other liabilities in Dominion Energy's Consolidated Balance Sheets.

Actuarial losses recognized during 2025 in Dominion Energy’s pension benefit obligations were $241 million primarily driven by a decrease in the discount rate and the result of a completed experience study. Actuarial gains recognized during 2024 in Dominion Energy’s pension benefit obligations were $404 million primarily driven by an increase in the discount rate. Actuarial gains recognized during 2025 in Dominion Energy’s other postretirement benefit obligations were $17 million primarily driven by the result of a completed experience study and partially offset by a decrease in the discount rate. Actuarial gains recognized during 2024 in Dominion Energy’s other postretirement benefit obligations were $43 million primarily driven by an increase in the discount rate.

The ABO for all of Dominion Energy’s defined benefit pension plans was $7.6 billion and $7.4 billion at December 31, 2025 and 2024, respectively.

Under its funding policies, Dominion Energy evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, Dominion Energy determines the amount of contributions for the current year, if any, at that time. Dominion Energy expects to make $24 million of minimum required contributions to its qualified defined benefit pension plans in 2026. Dominion Energy also considers voluntary contributions from time to time, either in the form of cash or equity securities.

Certain of Dominion Energy’s subsidiaries fund other postretirement benefit costs through VEBAs. Dominion Energy’s remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion Energy did not make any contributions to VEBAs associated with its other postretirement plans in 2025 and 2024. Dominion Energy is not required to make any contributions to its VEBAs associated with its other postretirement plans in 2026. Dominion Energy considers voluntary contributions from time to time, either in the form of cash or equity securities.

The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets for Dominion Energy:

		Pension Benefits								Other Postretirement Benefits
At December 31,		2025				2024				2025				2024
(millions)
Benefit obligation		$	718			$	724			$	177			$	171
Fair value of plan assets			685				666				—				—

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Combined Notes to Consolidated Financial Statements, Continued

The following table provides information on the ABO and fair value of plan assets for Dominion Energy’s pension plans with an ABO in excess of plan assets:

At December 31,		2025				2024
(millions)
Accumulated benefit obligation		$	26			$	715
Fair value of plan assets			—				666

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for Dominion Energy’s plans:

		Estimated Future Benefit Payments
		Pension Benefits				Other Postretirement Benefits
(millions)
2026		$	545			$	83
2027			553				82
2028			560				80
2029			568				80
2030			573				79
2031-2035			2,913				386

Plan Assets

Dominion Energy’s overall objective for investing its pension and other postretirement plan assets is to achieve appropriate long-term rates of return commensurate with prudent levels of risk. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The long-term strategic target asset allocation for Dominion Energy’s pension funds is 30% public equity (inclusive of both U.S. equity and non-U.S. equity), 27% fixed income and 43% other alternative investments. Public equity includes investments in U.S. and non-U.S. large-cap, mid-cap and small-cap companies. Fixed income includes government securities and cash. The public equity and fixed income investments are in individual securities as well as mutual funds and exchange traded funds. Other alternative investments include private equity, typically through limited partnerships, and credit and absolute return strategies which include investments in debt funds, including public and private debt, and hedge funds.

Strategic investment policies are established for Dominion Energy’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion Energy’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities.

For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 2.

The fair values of Dominion Energy’s pension plan assets by asset category are as follows:

At December 31,		2025																2024
(millions)		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
Cash and cash equivalents		$	1			$	2			$	—			$	3			$	395			$	—			$	—			$	395
Common and preferred stocks:
U.S.			565				—				—				565				1,004				—				—				1,004
International			604				—				—				604				723				1				—				724
Insurance contracts			—				135				73				208				—				139				73				212
Corporate debt instruments			113				870				—				983				70				486				11				567
Government securities			61				2,027				—				2,088				16				1,303				—				1,319
Total recorded at fair value		$	1,344			$	3,034			$	73			$	4,451			$	2,208			$	1,929			$	84			$	4,221
Assets recorded at NAV(1):
Commingled funds/collective trust funds															2,025																1,771
Alternative investments:
Real estate funds															25																37
Private equity funds															1,449																1,304
Debt funds															205																188
Hedge funds															613																319
Total recorded at NAV														$	4,317															$	3,619
Total investments(2)														$	8,768															$	7,840

(1)These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient are not required to be categorized in the fair value hierarchy.

(2)Excludes net assets related to non interest-bearing cash of $39 million, pending sales of securities and advanced subscription of $64 million and net accrued income of $34 million, and includes net assets related to pending purchases of securities of $14 million at December 31, 2025. Excludes net assets related to pending sales of securities of $633 million and net accrued income of $21 million, and includes net assets related to pending purchases of securities of $16 million at December 31, 2024.

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The fair values of Dominion Energy’s other postretirement plan assets by asset category are as follows:

At December 31,		2025																2024
(millions)		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
Cash and cash equivalents		$	—			$	—			$	—			$	—			$	7			$	—			$	—			$	7
Common and preferred stocks:
U.S.			498				—				—				498				946				—				—				946
International			60				—				—				60				74				—				—				74
Insurance contracts			—				8				4				12				—				8				5				13
Corporate debt instruments			173				51				—				224				183				30				1				214
Government securities			416				394				—				810				165				82				—				247
Total recorded at fair value		$	1,147			$	453			$	4			$	1,604			$	1,375			$	120			$	6			$	1,501
Assets recorded at NAV(1):
Commingled funds/collective trust funds															433																495
Alternative investments:
Real estate funds															7																9
Private equity funds															172																147
Debt funds															16																12
Hedge funds															140																20
Total recorded at NAV														$	768															$	683
Total investments(2)														$	2,372															$	2,184

(1)These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient are not required to be categorized in the fair value hierarchy.

(2)Excludes net assets related to non interest-bearing cash of $2 million, pending sales of securities and advanced subscription of $15 million and net accrued income of $7 million, and includes net assets related to pending purchases of securities of $2 million at December 31, 2025. Excludes net assets related to pending sales of securities and advanced subscription of $19 million and net accrued income of $2 million, and includes net assets related to pending purchases of securities of $2 million at December 31, 2024.

The following table presents the net change in the Dominion Energy’s pension and other postretirement plan assets included in the Level 3 fair value category:

		Pension Benefits												Other Postretirement Benefits
(millions)		2025				2024				2023				2025				2024				2023
Beginning balance		$	84			$	—			$	—			$	6			$	—			$	—
Total realized and    unrealized (losses) gains			—				—				—				(1	)			—				—
Purchases			—				11				—				—				1				—
Sales			(11	)			—				—				(1	)			—				—
Transfers into Level 3			—				73				—				—				5				—
Ending balance		$	73			$	84			$	—			$	4			$	6			$	—

The plan assets investments are determined based on the fair values of the investments and the underlying investments, which have been determined as follows:

•Cash and Cash Equivalents—Represents interest-bearing cash, foreign cash and money market funds. Interest-bearing cash and money market funds are valued at cost plus accrued interest. The foreign cash balances are valued at the amount held and translated on the reporting date based on prevailing exchange rates. Foreign cash and money market funds are classified as Level 1. The interest-bearing cash is held in variation margin and with various brokers, which are less liquid and therefore are classified as Level 2.

•Common and Preferred Stocks—Investments are valued at the closing price reported on the active market on which the individual securities are traded. Investments in certain preferred stocks are classified as Level 2 and are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings.

•Insurance Contracts—Investments in Group Annuity Contracts are stated at fair value based on the fair value of the underlying securities as provided by the managers and include investments in U.S. government securities, corporate debt instruments and state and municipal debt securities.

•Corporate Debt Instruments—Investments are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available for comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar instruments, the instrument is valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks or a broker quote, if available.

•Government Securities—Investments are valued using pricing models maximizing the use of observable inputs for similar securities.

•Commingled Funds/Collective Trust Funds—Commingled funds/collective trust funds invest in debt and equity securities and other instruments with characteristics similar to those of the funds’ benchmarks. The primary objectives of the funds are to seek investment returns that approximate the overall performance of their benchmark indexes. These benchmarks are major equity indices, fixed income indices and money market indices that focus on growth, income and liquidity strategies, as applicable. Investments in commingled funds/collective trust funds are stated at the NAV as determined by the issuer of the commingled funds/collective trust funds and are based on the fair value of the underlying investments held by the fund less its liabilities. The NAV is used as a practical expedient to estimate fair value. The commingled funds/collective trust funds do not have any unfunded commitments, and do not have any applicable

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Combined Notes to Consolidated Financial Statements, Continued

liquidation periods or defined terms/periods to be held. The majority of these funds have redemption restrictions allowing investors to redeem capital on a periodic basis.

•Alternative Investments—Investments in private real estate funds, private equity funds, debt funds, including public and private debt, and hedge funds are stated at fair value based on the NAV of the plan’s proportionate share of the partnership, joint venture or other alternative investment’s fair value as determined by reference to audited financial statements or NAV statements provided by the investment manager. The NAV, which is used as a practical expedient to estimate fair value, is adjusted for contributions and distributions occurring between the investment manager and Dominion Energy’s measurement date. These valuations also involve assumptions and methods that are reviewed, evaluated, and adjusted, if necessary, by Dominion Energy.

Net Periodic Benefit (Credit) Cost

The service cost component of net periodic benefit (credit) cost is reflected in other operations and maintenance expense in Dominion Energy’s Consolidated Statements of Income, except for $5 million and $18 million for the years ended December 31, 2024 and 2023, respectively, presented in discontinued operations. The non-service cost components of net periodic benefit (credit) cost are reflected in other income (expense) in Dominion Energy’s Consolidated Statements of Income, except for $12 million and $(46) million for the years ended December 31, 2024 and 2023, respectively, presented in discontinued operations. The components of the provision for net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities for Dominion Energy plans are as follows:

		Pension Benefits												Other Postretirement Benefits
Year Ended December 31,		2025				2024				2023				2025				2024				2023
(millions, except percentages)
Service cost		$	76			$	83			$	96			$	11			$	11			$	14
Interest cost			433				431				442				57				57				61
Expected return on plan assets			(676	)			(811	)			(864	)			(159	)			(171	)			(151	)
Amortization of prior service cost (credit)			1				1				—				(26	)			(36	)			(36	)
Net actuarial (gain) loss(1)			(14	)			(96	)			304				(112	)			(107	)			(125	)
Settlements, curtailments and special    termination benefits(2)			—				(56	)			—				—				(4	)			—
Plan amendment			—				22				—				—				—				—
Net periodic benefit (credit) cost		$	(180	)		$	(426	)		$	(22	)		$	(229	)		$	(250	)		$	(237	)
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Prior service cost			—				6				2				—				4				—
Less amounts included in net periodic    benefit cost:
Amortization of prior service (cost) credit			(1	)			(1	)			—				26				36				36
Total recognized in other comprehensive    income and regulatory assets and liabilities		$	(1	)		$	5			$	2			$	26			$	40			$	36
Significant assumptions used to determine periodic cost:
Discount rate		5.84%-5.87%				5.37%-5.75%				5.65%-5.75%				5.83%-5.86%				5.40%-5.74%				5.69%-5.70%
Expected long-term rate of return on plan    assets		7.35%				7.00%-8.35%				7.00%-8.35%				7.35%				8.35%				8.35%
Weighted-average rate of increase for    compensation		4.40%				4.28%				4.38%				n/a				n/a				n/a
Crediting interest rate for cash balance and    similar plans		4.59%-4.62%				4.12%-4.50%				4.40%-4.50%				n/a				n/a				n/a
Healthcare cost trend rate(3)														7.00%				7.00%				7.00%
Rate to which the cost trend rate is assumed    to decline (the ultimate trend rate)(3)														5.00%				5.00%				5.00%
Year that the rate reaches the ultimate trend    rate(3)														2032				2031				2030

(1)Excludes amortization expense (benefit) from regulatory assets and liabilities of $7 million, $2 million and $39 million for the years ended December 31, 2025, 2024 and 2023, respectively, reflected in other income (expense) in Dominion Energy’s Consolidated Statement of Income.

(2)2024 amounts relate primarily to the East Ohio Transaction.

(3)Assumptions used to determine net periodic cost for the following year.

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The components of AOCI and regulatory assets and liabilities for Dominion Energy’s plans that have not been recognized as components of net periodic benefit (credit) cost are as follows:

		Pension Benefits								Other Postretirement Benefits
At December 31,		2025				2024				2025				2024
(millions)
Regulatory assets and    liabilities:
Net actuarial loss (gain)		$	523			$	496			$	(99	)		$	(65	)
Prior service cost (credit)			7				8				(27	)			(41	)
AOCI:
Prior service cost (credit)			2				2				(28	)			(40	)
Total		$	532			$	506			$	(154	)		$	(146	)

The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality are critical assumptions in determining net periodic benefit (credit) cost. Dominion Energy develops non-investment related assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions used for Dominion Energy’s pension and other postretirement plans including discount rates, expected long-term rates of return, healthcare cost trend rates and mortality rates.

Dominion Energy determines the expected long-term rates of return on plan assets for its pension plans and other postretirement benefit plans by using a combination of:

•Expected inflation and risk-free interest rate assumptions;

•Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes;

•Expected future risk premiums, asset classes’ volatilities and correlations;

•Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and

•Investment allocation of plan assets.

Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans.

Mortality rates are developed from actual and projected plan experience for postretirement benefit plans. Dominion Energy’s actuary conducts an experience study periodically as part of the process to select its best estimate of mortality. Dominion Energy considers both standard mortality tables and improvement factors as well as the plans’ actual experience when selecting a best estimate.

Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion Energy’s retiree healthcare plans. Dominion Energy establishes the healthcare cost trend rate assumption based on analyses of various factors including the specific provisions of its medical plans, actual cost trends experienced and projected and demographics of plan participants.

Other Employee Matters

In 2024, Dominion Energy recorded a charge of $23 million ($17 million after-tax) within discontinued operations in the Consolidated Statements of Income attributable to a contribution to its defined contribution employee savings plan associated with the closing of the East Ohio Transaction. In addition, in 2024, Dominion Energy recorded a charge of $13 million ($10 million after-tax) in other operations and maintenance expense in the Consolidated Statements of Income related to a severance accrual for certain employees in connection with the business review.

Virginia Power Participation in Defined Benefit Plans

Virginia Power employees are covered by the Dominion Energy Pension Plan described above. As a participating employer, Virginia Power is subject to Dominion Energy’s funding policy, which is to contribute annually an amount that is in accordance with ERISA. Virginia Power made no contribution payments to the Dominion Energy Pension Plan during 2025, 2024 and 2023. Virginia Power’s net periodic pension cost related to this plan was $89 million, $49 million and $34 million in 2025, 2024 and 2023, respectively. Net periodic benefit (credit) cost is reflected in other operations and maintenance expense in Virginia Power’s Consolidated Statements of Income. The funded status of various Dominion Energy subsidiary groups and employee compensation are the basis for determining the share of total pension costs for participating Dominion Energy subsidiaries. See Note 25 for Virginia Power amounts due to/from Dominion Energy related to this plan.

Retiree healthcare and life insurance benefits, for Virginia Power employees are covered by the Dominion Energy Retiree Health and Welfare Plan described above. Virginia Power’s net periodic benefit (credit) cost related to this plan was $(64) million, $(72) million and $(60) million in 2025, 2024 and 2023, respectively. Net periodic benefit (credit) cost is reflected in other operations and maintenance expense in Virginia Power’s Consolidated Statements of Income. Employee headcount is the basis for determining the share of total other postretirement benefit costs for participating Dominion Energy subsidiaries. See Note 25 for Virginia Power amounts due to/from Dominion Energy related to this plan.

Dominion Energy holds investments in trusts to fund employee benefit payments for the pension and other postretirement benefit plans in which Virginia Power’s employees participate. Any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that Virginia Power will provide to Dominion Energy for its share of employee benefit plan contributions.

Virginia Power funds other postretirement benefit costs through VEBAs. During 2025, 2024 and 2023, Virginia Power made no contributions to the VEBAs and does not expect to contribute to the VEBAs in 2026.

Defined Contribution Plans

Dominion Energy also sponsors defined contribution employee savings plans that cover substantially all employees. During 2025, 2024 and 2023, Dominion Energy recognized $90 million, $82 million and $85 million, respectively, as employer matching contributions to these plans, excluding discontinued operations. Virginia Power also participates in these employee savings plans. During 2025, 2024 and 2023, Virginia Power recognized $32 million, $29 million and $26 million, respectively, as employer matching contributions to these plans.

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Combined Notes to Consolidated Financial Statements, Continued

Note 23. Commitments and Contingencies

As a result of issues generated in the ordinary course of business, the Companies are involved in legal proceedings before various courts and are periodically subject to governmental examinations (including by regulatory authorities), inquiries and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations that the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. The Companies maintain various insurance programs, including general liability insurance coverage which provides coverage for personal injury or wrongful death cases. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the Companies’ financial position, liquidity or results of operations.

Environmental Matters

The Companies are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

Air

The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, state-established regulatory programs are required to meet applicable requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of the Companies’ facilities are subject to the CAA’s permitting and other requirements.

Ozone Standards

The EPA published final non-attainment designations for the October 2015 ozone standards in June 2018 with states required to develop plans to address the new standard. Certain states in which the Companies operate have developed plans, and had such plans approved or partially approved by the EPA, which are not expected to have a material impact on the Companies’ results of operations or cash flows. In March 2023, the EPA issued a final rule specifying an interstate federal implementation plan to comply with certain aspects of planning for the 2015 ozone standards which was applicable in August 2023 for certain states, including Virginia. The interstate federal implementation plan imposes tighter NOX emissions limits during the ozone season and includes provisions for the use of allowances to cover such emissions. Unless and until implementation plans for the 2015 ozone standards are fully developed and approved and in effect for all states in which the Companies operate, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. The expenditures required to implement additional controls could have a material impact on the Companies’ results of operations, financial condition and/or cash flows.

Carbon Regulations

In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and exceed a significant emissions rate of 75,000 tons per year of CO2 equivalent emissions. Until the EPA ultimately takes final action on this rulemaking, the Companies cannot predict the impact to their results of operations, financial condition and/or cash flows.

Water

The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. The Companies must comply with applicable aspects of the CWA programs at their operating facilities.

Regulation 316(b)

In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Dominion Energy and Virginia Power currently have 14 and eight facilities, respectively, that are subject to the final regulations. Dominion Energy is also working with the EPA and state regulatory agencies to assess the applicability of Section 316(b) to eight hydroelectric facilities, including three Virginia Power facilities. The Companies anticipate that they may have to install impingement control technologies at certain of these stations that have once-through cooling systems. The Companies are currently evaluating the need

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or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technological, and cost benefit studies. DESC is conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications at certain facilities to ensure compliance with this rule. While the impacts of this rule could be material to the Companies’ results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina and Virginia provide rate recovery mechanisms that could substantially mitigate any such impacts for the regulated electric utilities.

Effluent Limitations Guidelines

In September 2015, the EPA released a final rule to revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category. The final rule established updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. In April 2017, the EPA granted two separate petitions for reconsideration of the Effluent Limitations Guidelines final rule and stayed future compliance dates in the rule. Also in April 2017, the U.S. Court of Appeals for the Fifth Circuit granted the EPA’s request for a stay of the pending consolidated litigation challenging the rule while the EPA addresses the petitions for reconsideration. In September 2017, the EPA signed a rule to postpone the earliest compliance dates for certain waste streams regulations in the Effluent Limitations Guidelines final rule from November 2018 to November 2020; however, the latest date for compliance for these regulations was December 2023. In October 2020, the EPA released the final rule that extended the latest dates for compliance with individual facilities’ compliance dates that would vary based on circumstances and the determination by state regulators and may range from 2021 to 2028. In May 2024, the EPA released a final rule revising the 2015 and 2020 Effluent Limitations Guidelines, establishing more stringent standards for wastewater discharges for the Steam Electric Power Generating Category, which apply primarily to wastewater discharges at coal and oil steam generating stations. In December 2025, the EPA released a final rule that, among other things, extended the deadlines promulgated in the May 2024 final rule. Individual facilities’ compliance dates will vary based on circumstances and the determination by state regulators and may range from 2029 to 2034. Dominion Energy expects to complete wastewater treatment technology retrofits and modifications at its Williams generating station, with a similar project at its Wateree generation station under evaluation, to meet the requirements with the existing regulatory framework in South Carolina providing rate recovery mechanisms for costs of the projects. As discussed in Note 14, the Companies recorded an increase to their AROs in 2024 in connection with the expected compliance costs associated with the EPA’s May 2024 final rule concerning CCR. The Companies expect that such AROs would satisfy any AROs that would have otherwise been necessary for compliance with the EPA’s May 2024 Effluent Limitations, as amended by the December 2025 final rule. Dominion Energy is currently unable to estimate what costs, if any, may be required in addition to the project for the Williams generating station, a potential project at the Wateree generating station and the recorded AROs to meet the requirements to operate certain facilities past 2034. However, Dominion Energy expects that while such costs for facility improvements, if required, could be material to the Companies’ financial condition and/or cash flows, the existing regulatory frameworks in Virginia and South Carolina provide rate recovery mechanisms that could substantially mitigate any such impacts.

Waste Management and Remediation

The operations of the Companies are subject to a variety of state and federal laws and regulations governing the management and disposal of solid and hazardous waste, and release of hazardous substances associated with current and/or historical operations. The CERCLA, as amended, and similar state laws, may impose joint, several and strict liability for cleanup on potentially responsible parties who owned, operated or arranged for disposal at facilities affected by a release of hazardous substances. In addition, many states have created programs to incentivize voluntary remediation of sites where historical releases of hazardous substances are identified and property owners or responsible parties decide to initiate cleanups.

From time to time, the Companies may be identified as a potentially responsible party in connection with the alleged release of hazardous substances or wastes at a site. Under applicable federal and state laws, the Companies could be responsible for costs associated with the investigation or remediation of impacted sites, or subject to contribution claims by other responsible parties for their costs incurred at such sites. The Companies also may identify, evaluate and remediate other potentially impacted sites under voluntary state programs. Remediation costs may be subject to reimbursement under the Companies’ insurance policies, rate recovery mechanisms or both. Except as described below, the Companies do not believe these matters will have a material effect on results of operations, financial condition and/or cash flows.

Dominion Energy has determined that it is associated with former manufactured gas plant sites, including certain sites associated with Virginia Power. At four sites associated with Dominion Energy, remediation work has been substantially completed under federal or state oversight. Where required, the sites are following state-approved groundwater monitoring programs. Dominion Energy has proposed remediation plans for one site at Virginia Power and expects to commence remediation activities in 2026 depending on receipt of final permits and approvals. At December 31, 2025 and 2024, Dominion Energy had $53 million and $56 million, respectively, of reserves recorded including a charge of $25 million ($19 million after-tax) that Virginia Power recorded in 2024, reflected in other operations and maintenance expense in the Consolidated Statements of Income. At December 31, 2025 and 2024, Virginia Power had $48 million and $50 million of reserves recorded, respectively. Dominion Energy is associated with three additional sites, including two associated with Virginia Power, which are not under investigation by any state or federal environmental agency nor the subject of any current or proposed plans to perform remediation activities. Due to the uncertainty surrounding such sites, the Companies are unable to make an estimate of the potential financial statement impacts.

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Combined Notes to Consolidated Financial Statements, Continued

Other Legal Matters

The Companies are defendants in a number of lawsuits and claims involving unrelated incidents of property damage and personal injury. Due to the uncertainty surrounding these matters, the Companies are unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on results of operations, financial condition and/or cash flows. In 2024, Dominion Energy resolved a claim associated with operations included in the East Ohio Transaction and at December 31, 2024, Dominion Energy’s Consolidated Balance Sheet includes a $30 million offsetting reserve and insurance receivable for this claim. The related charge in Dominion Energy’s Consolidated Statement of Income for the year ended December 31, 2024 is inconsequential.

SCANA Legal Proceedings

The following describes certain legal proceedings involving Dominion Energy, SCANA or DESC relating primarily to events occurring before closing of the SCANA Combination. No reference to, or disclosure of, any proceeding, item or matter described below shall be construed as an admission or indication that such proceeding, item or matter is material. For certain of these matters, and unless otherwise noted therein, Dominion Energy is unable to estimate a reasonable range of possible loss and the related financial statement impacts, but for any such matter there could be a material impact to its results of operations, financial condition and/or cash flows. For the matters for which Dominion Energy is able to reasonably estimate a probable loss, Dominion Energy's Consolidated Balance Sheets at December 31, 2025 and 2024 included an inconsequential amount of reserves primarily related to personal injury or wrongful death cases. During the years ended December 31, 2025, 2024 and 2023, charges included in Dominion Energy’s Consolidated Statements of Income were inconsequential.

Matters Fully Resolved Prior to 2025 Impacting the Consolidated

Financial Statements

Governmental Proceedings and Investigations

In June 2018, DESC received a notice of proposed assessment of approximately $410 million, excluding interest, from the SCDOR following its audit of DESC’s sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the NND Project, is based on the SCDOR’s position that DESC’s sales and use tax exemption for the NND Project does not apply because the facility will not become operational. In December 2020, the parties reached an agreement in principle in the amount of $165 million to resolve this matter. In June 2021, the parties executed a settlement agreement which allows DESC to fund the settlement amount through a combination of cash, shares of Dominion Energy common stock or real estate with an initial payment of at least $43 million in shares of Dominion Energy common stock. In 2021 and 2022, Dominion Energy issued shares of its common stock to partially satisfy its obligation under the settlement agreement. In June 2022, DESC requested approval from the South Carolina Commission to transfer certain real estate with a total settlement value of $51 million to satisfy its remaining obligation under the settlement agreement. In July 2022, the South Carolina Commission voted to approve the request and issued its final order in August 2022. In 2022, DESC transferred certain non-utility property to the SCDOR to partially satisfy its obligation under the settlement agreement. In October 2022, DESC filed for approval to transfer the remaining real estate with FERC which was received in November 2022. In March 2023, DESC transferred utility property with a fair value of $10 million to the SCDOR resulting in a gain of $9 million ($7 million after-tax), recorded in other operations and maintenance expense (reflected in the Corporate and Other segment) in Dominion Energy’s Consolidated Statements of Income for the year ended December 31, 2023. In June 2023, DESC transferred the remaining utility property with a fair value of $11 million to the SCDOR resulting in a gain of $11 million ($8 million after-tax), recorded in other operations and maintenance expense (reflected in the Corporate and Other segment) in Dominion Energy’s Consolidated Statements of Income for the year ended December 31, 2023. In July 2023, DESC made a less than $1 million cash payment to the SCDOR to fully satisfy its remaining obligation, including applicable interest, under the settlement agreement.

Nuclear Operations

Nuclear Decommissioning – Minimum Financial Assurance

The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. The 2025 calculation for the NRC minimum financial assurance amount, aggregated for Dominion Energy and Virginia Power’s nuclear units, excluding joint owners’ assurance amounts and Millstone Unit 1, as this unit is in a decommissioning state, was $3.5 billion and $2.0 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 2025 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2025 U.S. Bureau of Labor Statistics indices. Dominion Energy believes that decommissioning funds and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone units. In addition, Dominion Energy believes that the decommissioning funds and their expected earnings will be sufficient to cover expected decommissioning costs for the Summer unit, particularly when combined with future ratepayer collections and contributions. The Companies believe the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects a positive long-term outlook for trust fund investment returns as the decommissioning of the units will not be complete for decades. The Companies will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirement, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. See Note 9 for additional information on nuclear decommissioning trust investments.

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Nuclear Insurance

The Price-Anderson Amendments Act of 1988 provides the public up to $16.3 billion of liability protection on a per site, per nuclear incident basis, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. During the first quarter of 2024, the total liability protection per nuclear incident available to all participants in the Secondary Financial Protection Program increased from $16.2 billion to $16.3 billion. These increases do not impact Dominion Energy’s responsibility per active unit under the Price-Anderson Amendments Act of 1988. The Companies have purchased $500 million of coverage from commercial insurance pools for Millstone, Summer, Surry and North Anna with the remainder provided through the mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $166 million for each of their licensed reactors not to exceed $25 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. The current levels of nuclear property insurance coverage for Millstone, Summer, Surry and North Anna are all $1.06 billion.

The Companies’ nuclear property insurance coverage for Millstone, Summer, Surry and North Anna meets the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site. This includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion Energy and Virginia Power’s maximum retrospective premium assessment for the current policy period is $58 million and $31 million, respectively. Based on the severity of the incident, the Board of Directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. The Companies have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination. Additionally, DESC maintains an excess property insurance policy with the European Mutual Association for Nuclear Insurance. The policy provides coverage to Summer for property damage and outage costs up to $1 million. The European Mutual Association for Nuclear Insurance policy permits retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, DESC’s share of the retrospective premium assessment would not exceed an inconsequential amount.

Millstone, Virginia Power and Summer also purchase accidental outage insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program, the Companies are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion Energy and Virginia Power’s maximum retrospective premium assessment for the current policy period is $39 million and $11 million, respectively.

ODEC, a part owner of North Anna, Santee Cooper, a part owner of Summer and Massachusetts Municipal and Green Mountain, part owners of Millstone’s Unit 3, are responsible to the Companies for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.

Spent Nuclear Fuel

The Companies entered into contracts with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by the Companies’ contracts with the DOE. The Companies have previously received damages award payments and settlement payments related to these contracts.

By mutual agreement of the parties, the settlement agreements are extendable to provide for resolution of damages incurred after 2013. The settlement agreements for the Surry, North Anna and Millstone nuclear power stations have been extended and provided for periodic payments for damages incurred through December 31, 2025. In December 2025, the DOE notified the Companies that it intends to extend these agreements through December 31, 2028 and future additional extensions are contemplated by the settlement agreements. A similar agreement for Summer extends until the DOE has accepted the same amount of spent fuel from the facility as if it has fully performed its contractual obligations.

In 2025, Virginia Power received payments of $26 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2023 through December 31, 2023. In addition, Dominion Energy received payments of $14 million for resolution of claims incurred at Millstone for the period of July 1, 2023 through June 30, 2024 and $3 million for resolution of its share of claims incurred at Summer for the period of January 1, 2024 through December 31, 2024.

In 2024, Virginia Power received payments of $16 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2022 through December 31, 2022. In addition, Dominion Energy received payments of $11 million for resolution of claims incurred at Millstone for the period of July 1, 2022 through June 30, 2023 and $2 million for resolution of its share of claims incurred at Summer for the period of January 1, 2023 through December 31, 2023.

In 2023, Virginia Power received payments of $22 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2021 through December 31, 2021. In addition, Dominion Energy received payments of $8 million for resolution of claims incurred at Millstone for the period of July 1, 2021 through June 30, 2022 and $6 million for resolution of its share of claims incurred at Summer for the period of January 1, 2022 through December 31, 2022.

The Companies continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion Energy’s receivables for spent nuclear fuel-related costs totaled $70 million and $83 million at December 31, 2025 and 2024, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $53 million and $62 million at December 31, 2025 and 2024, respectively.

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Combined Notes to Consolidated Financial Statements, Continued

The Companies will continue to manage their spent fuel until it is accepted by the DOE.

Offshore Wind Decommissioning – Minimum Financial Assurance

BOEM requires entities holding a commercial lease for offshore wind facilities to provide financial assurance, as annually determined by BOEM, for future decommission of such facilities including those under development. Decommissioning costs include removing or decommissioning all facilities, projects, cables, pipelines and obstructions, as well as clearing the seafloor of all obstructions created by activities on the leased acreage. The most recent financial assurance calculation received from BOEM for the CVOW Commercial Project, based on its expected completion, was $1.6 billion. As discussed in Note 13, Virginia Power’s November 2024 application for Rider OSW filed with the Virginia Commission was approved in August 2025 and included a proposal for Virginia Power to establish a decommissioning trust fund associated with the CVOW Commercial Project. The applicable amount included within the total revenue requirement of Rider OSW will be allocated for such purposes. To the extent that the minimum financial assurance requirements are not able to be met from such decommissioning trust funds, Virginia Power may be required to utilize parent company guarantees, surety bonding or other financial instruments recognized by BOEM.

Long-Term Purchase Agreements

At December 31, 2025, Dominion Energy had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that a third party has used to secure financing for the facility that will provide the contracted goods or services:

		2026				2027				2028				2029				2030				Thereafter				Total
(millions)
Purchased    electric    capacity(1)		$	85			$	86			$	85			$	84			$	85			$	456			$	881

(1)Commitments represent estimated amounts payable for energy under power purchase contracts with qualifying facilities which expire at various dates through 2040. Energy payments are generally based on fixed dollar amounts per month and totaled $71 million and $60 million for the years ended December 31, 2025 and 2024, respectively.

Guarantees, Surety Bonds and Letters of Credit

Dominion Energy enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third-parties. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion Energy would be obligated to satisfy such obligation. To the extent that a liability subject to a guarantee has been incurred by one of Dominion Energy’s consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion Energy is not required to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once obligations have been paid. Dominion Energy currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.

At December 31, 2025, Dominion Energy had issued the following subsidiary guarantees:

		Maximum Exposure
(millions)
Commodity transactions(1)		$	2,878
Nuclear obligations(2)			198
Solar(3)			85
Other(4)			366
Total(5)(6)		$	3,527

(1)Guarantees related to commodity commitments of certain subsidiaries. These guarantees were provided to counterparties in order to facilitate physical and financial transaction related commodities and services.

(2)Guarantees primarily related to certain DGI subsidiaries regarding all aspects of running a nuclear facility.

(3)Includes guarantees to facilitate the development of solar projects.

(4)Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations, construction projects and insurance programs. Due to the uncertainty of workers’ compensation claims, the parental guarantee has no stated limit.

(5)Excludes Dominion Energy’s guarantee of an offshore wind installation vessel discussed in Note 15.

(6)In July 2016, Dominion Energy signed an agreement with a lessor to construct and lease a new corporate office property in Richmond, Virginia and commenced an initial five-year lease term in August 2019, with certain options at the end of the term to extend the lease, purchase or sell the property. In July 2024, the agreement was amended to reflect Dominion Energy’s election to extend the lease term through July 2029. At the end of the lease term, Dominion Energy can (i) extend the term of the lease for at least one year, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property on behalf of the lessor to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the project costs, Dominion Energy may be required to make a payment to the lessor equal to the recorded lease balance.

In addition, Dominion Energy had issued an additional $20 million of guarantees at December 31, 2025, primarily to support third-parties. No amounts related to these guarantees have been recorded.

In 2025, Dominion Energy entered into two guarantee agreements to support a portion of Valley Link’s financing obligations under a $180 million revolving credit facility and up to $120 million of letters of credit. Dominion Energy’s obligation under these guarantees is only triggered if a Valley Link project is cancelled and Valley Link cannot pay outstanding balances related to the cancelled project. Dominion Energy’s maximum potential loss exposure under the terms of the guarantees is limited to 30% of outstanding borrowings, an equal percentage to Dominion Energy’s ownership in Valley Link. At December 31, 2025, Valley Link had borrowed $41 million against the revolving credit facility and had $90 million outstanding letters of credit. No amounts related to these guarantees has been recorded at Dominion Energy.

Dominion Energy also had issued three guarantees at December 31, 2025 related to Cove Point, previously an equity method investment, in support of terminal services and transportation. Two of the Cove Point guarantees have a cumulative

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maximum exposure of $1.9 billion while the other one guarantee has no maximum limit. No amounts related to these guarantees have been recorded.

Additionally, at December 31, 2025, Dominion Energy had purchased $528 million of surety bonds, including $456 million at Virginia Power, and authorized the issuance of letters of credit by financial institutions, as discussed in Note 17, to facilitate commercial transactions by its subsidiaries with third-parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.

Indemnifications

As part of commercial contract negotiations in the normal course of business, the Companies may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Companies are unable to develop an estimate of the maximum potential amount of any other future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2025, the Companies believe any other future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position.

Charitable Commitments

Dominion Energy’s Consolidated Balance Sheets include $43 million and $32 million in other deferred credits and other liabilities at December 31, 2025 and 2024, respectively and $15 million and $21 million in other current liabilities at December 31, 2025 and 2024, respectively, for charitable commitments. In 2025 and 2024, Dominion Energy made unconditional promises to charitable organizations and as a result recorded charges totaling $42 million ($42 million after-tax) and $72 million ($54 million after-tax) in other income (expense) in its Consolidated Statements of Income for the years ended December 31, 2025 and 2024, respectively, reflected in the Corporate and Other segment. These commitments are primarily to be funded at various intervals through 2032.

Note 24. Credit Risk

Dominion Energy

As a diversified energy company, Dominion Energy transacts primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Southeast regions of the U.S. Dominion Energy does not believe that this geographic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Energy is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations.

Dominion Energy’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion Energy transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include marketing of nonregulated generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of any collateral. At December 31, 2025, Dominion Energy’s credit exposure totaled $223 million. Of this amount, investment grade counterparties, including those internally rated, represented 92%. No single counterparty, whether investment grade or non-investment grade, exceeded $143 million of exposure.

Virginia Power

Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2025, Virginia Power’s exposure related to wholesale customers totaled $16 million. Of this amount, investment grade counterparties, including those internally rated, represented 57%. No single counterparty, whether investment grade or non-investment grade, exceeded $3 million of exposure.

Credit-Related Contingent Provisions

Certain of Dominion Energy and Virginia Power’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion Energy and Virginia Power to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered, Dominion Energy would have been required to post additional collateral to its counterparties of $29 million, with none related to Virginia Power, at December 31, 2025, and $13 million, with $12 million related to Virginia Power, at December 31, 2024. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. At both December 31, 2025 and 2024, Dominion Energy and Virginia Power had no amounts of collateral posted related to derivatives with credit related contingent provisions that are in a liability position and not fully collateralized with cash. There were no letters of credits posted as collateral at December 31, 2025 or 2024 for either Dominion Energy or Virginia Power. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized

149

Combined Notes to Consolidated Financial Statements, Continued

with cash for Dominion Energy was $29 million, with none related to Virginia Power, at December 31, 2025, and $13 million, with $12 million related to Virginia Power, at December 31, 2024, which does not include the impact of any offsetting asset positions.

See Note 7 for further information about derivative instruments.

Note 25. Related-party Transactions

Dominion Energy’s transactions with equity method investments are described in Note 9. Virginia Power engages in related party transactions primarily with other Dominion Energy subsidiaries (affiliates). Virginia Power’s receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power is included in Dominion Energy’s consolidated federal income tax return and, where applicable, combined income tax returns for Dominion Energy are filed in various states. See Note 2 for further information. A discussion of Virginia Power’s significant related party transactions follows.

Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of forward commodity purchases, to manage commodity price risks associated with purchases of natural gas. See Note 7 for additional information. At December 31, 2025, Virginia Power’s derivative assets and liabilities with affiliates were $22 million and $12 million, respectively. At December 31, 2024, Virginia Power’s derivative assets and liabilities with affiliates were $19 million and $17 million, respectively.

Virginia Power participates in certain Dominion Energy benefit plans as described in Note 22. At December 31, 2025 and 2024, Virginia Power’s amounts due to Dominion Energy associated with the Dominion Energy Pension Plan and reflected in other deferred credits and other liabilities in the Consolidated Balance Sheets were $594 million and $505 million, respectively. At December 31, 2025 and 2024, Virginia Power’s amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $729 million and $663 million, respectively.

DES and other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage.

The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES to Virginia Power on the basis of direct and allocated methods in accordance with Virginia Power’s services agreements with DES. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.

Presented below are Virginia Power’s significant transactions with DES and other affiliates:

Year Ended December 31,		2025				2024				2023
(millions)
Commodity purchases from affiliates		$	941			$	585			$	582
Services provided by affiliates(1)(2)			823				667				605
Services provided to affiliates			16				22				20

(1)Includes capitalized expenditures of $305 million, $234 million and $210 million for the years ended December 31, 2025, 2024 and 2023, respectively.

(2)Excludes amounts related to Virginia Power's operating lease with an affiliated entity as discussed below and in Note 15.

Virginia Power has borrowed funds from Dominion Energy under short-term borrowing arrangements. Virginia Power’s intercompany credit facility with Dominion Energy has a maximum capacity of $3.0 billion. In December 2024, Virginia Power amended this facility to extend the maturity date to December 2027. There were $1.2 billion and $500 million in short-term demand note borrowings from Dominion Energy at December 31, 2025 and 2024, respectively. The weighted-average interest rate of these borrowings was 4.03% and 4.71% at December 31, 2025 and 2024, respectively. Virginia Power had no outstanding borrowings, net of repayments under the Dominion Energy money pool for its nonregulated subsidiaries at December 31, 2025 and 2024. Interest charges related to Virginia Power’s borrowings from Dominion Energy were $42 million, $29 million and $80 million for the years ended December 31, 2025, 2024 and 2023, respectively.

In 2025, Virginia Power declared and paid a dividend of $550 million. In the fourth quarter of 2024, Virginia Power declared a dividend of $407 million, which was paid in 2025.

In 2025 and 2023, Virginia Power issued common stock to Dominion Energy as discussed in Note 20. There were no such issuances of Virginia Power common stock to Dominion Energy in 2024.

See Note 15 for discussion of Virginia Power’s lease, classified as an operating lease with a 20-month term, with an affiliated entity for the use of a Jones Act compliant offshore wind installation vessel. At December 31, 2025, Virginia Power’s Consolidated Balance Sheet reflects $185 million other deferred charges and other assets for its right-of-use asset and $188 million of affiliated lease payables comprised of $141 million presented in other current liabilities and $47 million presented in other deferred credits and other liabilities. For the year ended December 31, 2025, Virginia Power capitalized $18 million of such affiliated lease cost associated with the CVOW Commercial Project.

150

Note 26. Operating Segments

The Companies are organized primarily on the basis of products and services sold in the U.S. A description of the operations included in the Companies’ primary operating segments is as follows:

Primary Operating Segment		Description of Operations		Dominion Energy		Virginia Power
Dominion Energy    Virginia		Regulated electric distribution		X		X
		Regulated electric transmission		X		X
		Regulated electric generation    fleet(1)		X		X
Dominion Energy    South Carolina		Regulated electric distribution		X
		Regulated electric transmission		X
		Regulated electric generation    fleet		X
		Regulated gas distribution and    storage		X
Contracted Energy(2)		Nonregulated electric generation    fleet		X

(1)Includes Virginia Power’s non-jurisdictional solar generation operations.

(2)Includes renewable natural gas and offshore wind installation vessel operations.

In addition to the operating segments above, the Companies also report a Corporate and Other segment.

Dominion Energy

The Corporate and Other Segment of Dominion Energy includes its corporate, service company and other functions (including unallocated debt) as well as its noncontrolling interest in Dominion Privatization. In addition, Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources, including the net impact of the operations reflected as discontinued operations, which includes the entities included in the East Ohio (through March 2024), Questar Gas (through May 2024) and PSNC (through September 2024) Transactions, a noncontrolling interest in Cove Point (through September 2023), certain solar generation facility development operations (through April 2024) and a noncontrolling interest in Atlantic Coast Pipeline as discussed in Notes 3 and 9.

Dominion Energy’s CODM is the CEO. The Dominion Energy CODM uses net income (loss) as the primary profit or loss measure at each segment. The Dominion Energy CODM considers budget-to-actual variances on a quarterly basis when making decisions about allocating operating and capital resources to each segment, when assessing the performance of each segment and when determining the compensation of certain employees.

In 2025, Dominion Energy reported after-tax net expenses of $300 million in the Corporate and Other segment, including $32 million of after-tax net income for specific items with $28 million of after-tax net expenses attributable to its operating segments.

The net expenses for specific items attributable to Dominion Energy’s operating segments in 2025 primarily related to the impact of the following items:

•$258 million ($192 million after-tax) of charges for Virginia Power’s share of costs not expected to be recovered from customers on the CVOW Commercial Project, attributable to Dominion Energy Virginia;

•A $124 million ($94 million after-tax) net unrealized loss related to economic hedging activities, attributable to Contracted Energy; and

•A $106 million ($79 million after-tax) loss associated with severe weather events, attributable to Dominion Energy Virginia; partially offset by

•A $507 million ($335 million after-tax) gain related to investments in nuclear decommissioning trust funds, attributable to:

•Contracted Energy ($290 million after-tax); and

•Dominion Energy Virginia ($45 million after-tax).

In 2024, Dominion Energy reported after-tax net expenses of $734 million in the Corporate and Other segment, including $358 million of after-tax net expenses for specific items with $222 million of after-tax net expenses attributable to its operating segments.

The net expenses for specific items attributable to Dominion Energy’s operating segments in 2024 primarily related to the impact of the following items:

•A $232 million ($176 million after-tax) net unrealized loss related to economic hedging activities, attributable to Contracted Energy;

•A $122 million ($89 million after-tax) charge related to the revision of AROs for Millstone Unit 1, attributable to Contracted Energy;

•A $103 million ($77 million after-tax) charge for Virginia Power’s share of costs not expected to be recovered from customers on the CVOW Commercial Project, attributable to Dominion Energy Virginia;

•$60 million ($46 million after-tax) of charges for the impairment of certain nonregulated renewable natural gas facilities, attributable to Contracted Energy;

•A $58 million ($44 million after-tax) charge in connection with the electric base rate case in South Carolina, attributable to Dominion Energy South Carolina;

•A $47 million ($35 million after-tax) charge in connection with a settlement of an agreement, attributable to Contracted Energy;

•$40 million ($30 million after-tax) of charges for dismantling costs associated with the early retirement of certain electric generation facilities, attributable to Dominion Energy Virginia;

•A $30 million ($22 million after-tax) charge related to the write-off of certain early-stage development costs, attributable to Dominion Energy Virginia; and

•A $25 million ($19 million after-tax) charge associated with an accrual for remediation costs at a manufactured gas plant site, attributable to Dominion Energy Virginia; partially offset by

•A $559 million ($344 million after-tax) gain related to investments in nuclear decommissioning trust funds, attributable to:

•Contracted Energy ($295 million after-tax); and

•Dominion Energy Virginia ($49 million after-tax).

In 2023, Dominion Energy reported after-tax net expenses of $198 million in the Corporate and Other segment, including $247 million of after-tax net income for specific items with $336 million of after-tax net income attributable to its operating segments.

151

Combined Notes to Consolidated Financial Statements, Continued

The net income for specific items attributable to Dominion Energy’s operating segments in 2023 primarily related to the impact of the following items:

•A $586 million ($447 million after-tax) net unrealized gain related to economic hedging activities, attributable to Contracted Energy;

•A $406 million ($236 million after-tax) gain related to investments in nuclear decommissioning trust funds, attributable to:

•Contracted Energy ($203 million after-tax); and

•Dominion Energy Virginia ($33 million after-tax); and

•A $28 million ($21 million after-tax) benefit related to real estate transactions, including gains on the transfer of property to satisfy litigation associated with the NND Project, attributable to Dominion Energy South Carolina; partially offset by

•A $244 million ($182 million after-tax) charge for amortization of a regulatory asset established in connection with the settlement of the 2021 Triennial Review, attributable to Dominion Energy Virginia;

•An $83 million ($60 million after-tax) charge related to the revision of AROs for Millstone Unit 1, attributable to Contracted Energy;

•A $65 million ($48 million after-tax) charge for an easement related to the CVOW Commercial Project for which Virginia Power will not seek recovery, attributable to Dominion Energy Virginia;

•A $36 million ($27 million after-tax) charge for the write-off of certain previously deferred amounts related to the cessation of certain riders effective July 2023, attributable to Dominion Energy Virginia;

•A $35 million ($26 million after-tax) decrease from Dominion Energy’s share of an impairment of certain property, plant and equipment at Align RNG, attributable to Contracted Energy; and

•A $25 million ($19 million after-tax) charge associated with the abandonment of certain regulated solar generation and other facilities, attributable to Dominion Energy Virginia.

The following table presents segment information pertaining to Dominion Energy’s 2025 operations:

Year Ended December 31, 2025		Dominion Energy Virginia				Dominion Energy South Carolina				Contracted Energy				Corporate and Other				Adjustments & Eliminations				Consolidated Total
(millions)
Total revenue from external customers		$	11,843			$	3,568			$	1,140			$	(45	)		$	—			$	16,506
Intersegment revenue			(3	)			10				39				1,217				(1,263	)			—
Total Operating Revenue			11,840				3,578				1,179				1,172				(1,263	)			16,506
Electric fuel and other energy-related     purchases(1)			3,591				795				114				—				(11	)			4,489
Purchased electric capacity(1)			71				13				—				—				(2	)			82
Purchased gas(1)			—				291				6				—				—				297
Other operations and maintenance(1)(2)			2,264				691				532				1,806				(1,229	)			4,064
Depreciation and amortization(1)			1,623				569				118				91				(14	)			2,387
Other taxes(1)			361				303				58				62				(11	)			773
Total Operating Expenses			7,910				2,662				828				1,959				(1,267	)			12,092
Interest and related charges(1)			957				273				55				939				(202	)			2,022
Income tax expense (benefit)(1)			514				123				(22	)			(83	)			—				532
Equity in earnings (losses) of equity method     investees(3)			—				—				1				(7	)			—				(6	)
Other income (expense)(3)			167				1				(6	)			933				(9	)			1,086
Interest income(3)			23				14				125				174				(197	)			139
Net Loss from Discontinued Operations    Including Noncontrolling Interests			—				—				—				(14	)			—				(14	)
Noncontrolling Interests(3)			324				—				—				(257	)			—				67
Net Income (Loss) Attributable to Dominion     Energy			2,325				535				438				(300	)			—				2,998
Investment in equity method investees(4)			—				—				92				40				—				132
Capital expenditures			10,548				1,174				831				101				(1	)			12,653
Total assets (billions)			80.8				19.3				12.1				10.2				(6.5	)			115.9

(1)The significant expense categories and amounts in the segment information presented above align with the segment-level information that is regularly provided to Dominion Energy’s CODM.

(2)Includes impairment of assets and other charges.

(3)Items designated are other segment items for each reportable segment.

(4)Excludes liability to Atlantic Coast Pipeline.

152

The following table presents segment information pertaining to Dominion Energy’s 2024 operations:

Year Ended December 31, 2024		Dominion Energy Virginia				Dominion Energy South Carolina				Contracted Energy				Corporate and Other				Adjustments & Eliminations				Consolidated Total
(millions)
Total revenue from external customers		$	10,226			$	3,295			$	1,099			$	(161	)		$	—			$	14,459
Intersegment revenue			9				9				10				1,002				(1,030	)			—
Total Operating Revenue			10,235				3,304				1,109				841				(1,030	)			14,459
Electric fuel and other energy-related     purchases(1)			2,743				775				102				—				(6	)			3,614
Purchased electric capacity(1)			68				8				—				—				(2	)			74
Purchased gas(1)			—				260				—				—				—				260
Other operations and maintenance(1)(2)			2,217				671				487				1,827				(1,014	)			4,188
Depreciation and amortization(1)			1,635				546				76				88				—				2,345
Other taxes(1)			332				292				53				62				(8	)			731
Total Operating Expenses			6,995				2,552				718				1,977				(1,030	)			11,212
Interest and related charges(1)			856				276				36				912				(187	)			1,893
Income tax expense (benefit)(1)			446				80				121				(236	)			—				411
Equity in earnings (losses) of equity method     investees(3)			—				—				9				(6	)			—				3
Other income (expense)(3)			100				(5	)			(15	)			614				—				694
Interest income(3)			23				7				131				170				(187	)			144
Net Income from Discontinued Operations    Including Noncontrolling Interests			—				—				—				197				—				197
Noncontrolling Interests(3)			50				—				—				(103	)			—				(53	)
Net Income (Loss) Attributable to Dominion     Energy			2,011				398				359				(734	)			—				2,034
Investment in equity method investees(4)			—				—				91				47				—				138
Capital expenditures			9,968				1,105				772				582				—				12,427
Total assets (billions)			70.0				18.4				9.5				10.2				(5.7	)			102.4

(1)The significant expense categories and amounts in the segment information presented above align with the segment-level information that is regularly provided to Dominion Energy’s CODM.

(2)Includes impairment of assets and other charges.

(3)Items designated are other segment items for each reportable segment.

(4)Excludes liability to Atlantic Coast Pipeline.

153

Combined Notes to Consolidated Financial Statements, Continued

The following table presents segment information pertaining to Dominion Energy’s 2023 operations:

Year Ended December 31, 2023		Dominion Energy Virginia				Dominion Energy South Carolina				Contracted Energy				Corporate and Other				Adjustments & Eliminations				Consolidated Total
(millions)
Total revenue from external customers		$	9,575			$	3,369			$	835			$	614			$	—			$	14,393
Intersegment revenue			(2	)			6				16				939				(959	)			—
Total Operating Revenue			9,573				3,375				851				1,553				(959	)			14,393
Electric fuel and other energy-related    purchases(1)			2,918				947				80				—				(10	)			3,935
Purchased electric capacity(1)			46				12				—				—				(3	)			55
Purchased gas(1)			—				285				—				—				—				285
Other operations and maintenance(1)(2)			1,842				612				544				1,381				(939	)			3,440
Depreciation and amortization(1)			1,622				531				105				322				—				2,580
Other taxes(1)			298				285				48				60				(7	)			684
Total Operating Expenses			6,726				2,672				777				1,763				(959	)			10,979
Interest and related charges(1)			772				249				44				820				(206	)			1,679
Income tax expense(1)			473				79				25				67				—				644
Equity in earnings (losses) of equity method    investees(3)			—				—				(34	)			8				—				(26	)
Other income (expense)(3)			65				(4	)			22				820				—				903
Interest income(3)			17				6				106				196				(206	)			119
Net Loss From Discontinued Operations    Including Noncontrolling Interests			—				—				—				(125	)			—				(125	)
Net Income (Loss) Attributable to Dominion    Energy			1,684				377				99				(198	)			—				1,962
Capital expenditures			7,196				957				740				1,342				—				10,235

(1)The significant expense categories and amounts in the segment information presented above align with the segment-level information that is regularly provided to Dominion Energy’s CODM.

(2)Includes impairment of assets and other charges.

(3)Items designated are other segment items for each reportable segment.

Intersegment sales and transfers for Dominion Energy are based on contractual arrangements and may result in intersegment profit or loss that is eliminated in consolidation, including amounts related to entities presented within discontinued operations.

Virginia Power

The Corporate and Other Segment of Virginia Power primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources.

Virginia Power’s CODM is the CEO. The Virginia Power CODM uses net income (loss) as the primary profit or loss measure at each segment. The Virginia Power CODM considers budget-to-actual variances on a quarterly basis when making decisions about allocating operating and capital resources to each segment, when assessing the performance of each segment and when determining the compensation of certain employees.

In 2025, Virginia Power reported after-tax net expenses of $225 million in the Corporate and Other segment, including $225 million of after-tax net expenses for specific items all of which were attributable to its operating segment.

The net expenses for specific items attributable to its operating segment in 2025 primarily related to the impact of the following items:

•$258 million ($192 million after-tax) of charges for Virginia Power’s share of costs not expected to be recovered from customers on the CVOW Commercial Project; and

•A $106 million ($79 million after-tax) loss associated with severe weather events; partially offset by

•A $72 million ($45 million after-tax) gain related to investments in nuclear decommissioning trust funds.

In 2024, Virginia Power reported after-tax net expenses of $114 million in the Corporate and Other segment, including $115 million of after-tax net expenses for specific items all of which were attributable to its operating segment.

The net expenses for specific items attributable to its operating segment in 2024 primarily related to the impact of the following items:

•A $103 million ($77 million after-tax) charge for Virginia Power’s share of costs not expected to be recovered from customers on the CVOW Commercial Project;

•$40 million ($30 million after-tax) of charges for dismantling costs associated with the early retirement of certain electric generation facilities;

•A $30 million ($22 million after-tax) charge related to the write-off of certain early-stage development costs; and

•A $25 million ($19 million after-tax) charge associated with an accrual for remediation costs at a manufactured gas plant site; partially offset by

•A $82 million ($49 million after-tax) gain related to investments in nuclear decommissioning trust funds.

In 2023, Virginia Power reported after-tax net expenses of $242 million in the Corporate and Other segment, including $242 million of after-tax net expenses for specific items all of which were attributable to its operating segment.

154

The net expenses for specific items attributable to its operating segment in 2023 primarily related to the impact of the following items:

•A $244 million ($182 million after-tax) charge for amortization of a regulatory asset established in connection with the settlement of the 2021 Triennial Review;

•A $65 million ($48 million after-tax) charge for an easement related to the CVOW Commercial Project for which Virginia Power will not seek recovery;

•A $36 million ($27 million after-tax) charge for the write-off of certain previously deferred amounts related to the cessation of certain riders effective July 2023; and

•A $25 million ($19 million after-tax) charge associated with the abandonment of certain regulated solar generation and other facilities; partially offset by

•A $58 million ($33 million after-tax) gain related to investments in nuclear decommissioning trust funds.

The following table presents segment information pertaining to Virginia Power’s operations:

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Filing: 10-K - DOMINION ENERGY, INC (D)
Accession Number: 0001193125-26-063120

		Dominion Energy Virginia				Corporate and Other				Consolidated Total
(millions)
Year Ended December 31, 2025
Operating Revenue		$	11,841			$	(29	)		$	11,812
Electric fuel and other energy-related purchases(1)			3,591				—				3,591
Purchased electric capacity(1)			71				—				71
Other operations and maintenance(1)(2)			2,264				582				2,846
Depreciation and amortization(1)			1,623				7				1,630
Other taxes(1)			361				1				362
Total Operating Expenses			7,910				590				8,500
Interest and related charges(1)			957				(6	)			951
Income tax expense (benefit)(1)			514				(66	)			448
Other income (expense)(3)			167				63				230
Interest income(3)			23				2				25
Noncontrolling Interests(3)			324				(257	)			67
Net Income (Loss) Attributable to Virginia Power			2,326				(225	)			2,101
Capital expenditures			10,544				—				10,544
Total assets (billions)			79.2				—

FAQ

What is Dominion Energy (D) planning to spend on capital projects through 2030?

Dominion Energy plans about $65 billion of capital expenditures from 2026 through 2030. Spending focuses on offshore wind, large-scale solar, battery storage, new dispatchable gas generation, grid transformation, and transmission and distribution resiliency to meet rising demand, especially from data centers.

How significant is the CVOW Commercial offshore wind project for Dominion Energy (D)?

The CVOW Commercial Project is a 2.6 GW offshore wind facility with an estimated total cost of about $11.5 billion. It is central to meeting Virginia’s renewable portfolio standards and involves extensive construction, tariff and network upgrade considerations, plus a 50% noncontrolling interest sale to Stonepeak.

What major asset sales has Dominion Energy (D) completed recently?

Dominion Energy completed several large gas distribution sales to Enbridge, including East Ohio, Questar Gas and PSNC transactions, each with multi-billion-dollar cash proceeds and assumed debt. It also sold its remaining 50% Cove Point LNG interest to BHE for about $3.3 billion in cash proceeds.

How reliant is Dominion Energy (D) on regulated utility earnings?

Dominion Energy currently expects roughly 95% of earnings to come from state-regulated utility operations in Virginia, North Carolina and South Carolina. Nonregulated activities are primarily long-term contracted generation, including the Millstone nuclear station and renewable projects under long-term power purchase agreements.

What are Dominion Energy Virginia’s main growth drivers within Dominion Energy (D)?

Dominion Energy Virginia plans roughly $55 billion of 2026–2030 spending, driven by data-center led load growth, the 2.6 GW CVOW offshore wind buildout, utility-scale solar, battery storage, new gas generation, grid transformation initiatives, and large PJM-directed transmission investments under the regional transmission expansion plan.

How well funded are Dominion Energy’s nuclear decommissioning obligations?

For Virginia Power’s Surry and North Anna units, most recent decommissioning cost estimates total about $3.5 billion, while related trust funds hold roughly $4.9 billion as of December 31, 2025. Millstone’s estimated decommissioning costs are about $3.2 billion, versus $4.0 billion in associated trust funds.