NYSE: D

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.

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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

18

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

19

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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