Dominion Energy, Inc: Form 10-K for the period ended Dec 31, 2023

GENERAL

Dominion Energy, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and distributors of energy. Dominion Energy is committed to providing reliable, affordable and increasingly clean energy every day and to achieving net zero carbon emissions by 2050. Dominion Energy’s strategy is to be a leading provider of electricity, natural gas and related services to customers primarily in the eastern region of the U.S. As of December 31, 2023, Dominion Energy’s portfolio of assets includes approximately 29.5 GW of electric generating capacity, 10,600 miles of electric transmission lines, 79,300 miles of electric distribution lines and 94,800 miles of gas distribution mains and related service facilities, which are supported by 4,000 miles of gas transmission, gathering and storage pipeline. As of December 31, 2023, Dominion Energy operates in 15 states and serves approximately 7 million customers. Such amounts are inclusive of Dominion Energy’s gas distribution operations expected to be sold to Enbridge during 2024.

Dominion Energy is in the final stages of its comprehensive business review announced in November 2022 as discussed in Future Issues and Other Matters in Item 7. MD&A. In connection with the comprehensive business review, Dominion Energy entered into agreements in September 2023 to sell all of its regulated gas distribution operations, except for DESC’s, to Enbridge. In addition, Dominion Energy completed the sale in September 2023 of its remaining 50% noncontrolling partnership interest in Cove Point to BHE under the agreement entered into in July 2023. Pending the final results of the business review, Dominion Energy continues to focus on expanding and improving its regulated electric utilities and long-term contracted businesses while transitioning to a cleaner energy future. Its capital expenditure plan for 2024 includes a focus on upgrading the electric system in Virginia through investments in additional renewable generation facilities, strategic undergrounding and energy conservation programs as well as upgrades to its electric transmission and distribution networks while also meeting environmental requirements and standards set by various regulatory bodies. Renewable generation facilities are expected to include significant investments in utility-scale solar and the CVOW Commercial Project. In addition, Dominion Energy has either received or applied for license extensions for its regulated nuclear power stations in Virginia and South Carolina and intends to apply for license extensions for Millstone.

Dominion Energy currently expects approximately 90% of earnings from its primary operating segments to come from state-regulated primarily electric utility businesses. 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 http://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, http://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 September 2023, Dominion Energy entered into an agreement for 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. This transaction is expected to close in 2024, contingent on meeting regulatory conditions, including receipt of any remaining approvals.

In September 2023, Dominion Energy entered into an agreement for the PSNC Transaction with Enbridge for $2.2 billion in cash consideration and the assumption by Enbridge of approximately $1.0 billion of related long-term debt. This transaction is expected to close in 2024, contingent on meeting regulatory conditions, including receipt of any remaining approvals.

In September 2023, Dominion Energy entered into an agreement for 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. This transaction is expected to close in 2024, contingent on meeting regulatory conditions, including receipt of any remaining approvals.

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

Gas Transmission and Storage Operations

Sale to Southwest Gas

In December 2021, Dominion Energy completed the sale of the Q-Pipe Group to Southwest Gas for approximately $1.5 billion in cash proceeds and the assumption by Southwest Gas of $430 million of related long-term debt. See Note 3 to the Consolidated Financial Statements for additional information.

Hope

In August 2022, Dominion Energy completed the sale of 100% of the equity interests in Hope to Ullico for $690 million in cash consideration, subject to customary closing adjustments. See Note 3 to the Consolidated Financial Statements for additional information.

Electric Generation Facilities

Acquisition of Virginia Power Solar Projects

In 2022 and 2021, Virginia Power entered into and completed the acquisitions of several primarily early-stage solar development projects in Virginia, which are primarily expected to be recovered under Rider CE.

In 2022, Virginia Power entered into and completed the acquisitions of various solar development projects in Virginia. These projects are expected to cost a total of approximately $1.1 billion once constructed, including initial acquisition costs, and generate approximately 537 MW combined.

In 2021, Virginia Power entered into and completed the acquisition of various solar development projects in Virginia. These projects are expected to cost a total of approximately $1.4 billion once constructed, including initial acquisition costs, and generate approximately 697 MW combined.

See Note 13 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 is expected to cost a total of $205 million once constructed, including the initial acquisition cost, and generate approximately 83 MW.

In 2022, Dominion Energy entered into an agreement and completed the acquisition of a nonregulated solar project in Ohio. The project is expected to cost a total of $390 million once constructed, including the initial acquisition cost, and generate approximately 200 MW.

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

Sale of Non-Wholly-Owned Nonregulated Solar Facilities

In 2021, Dominion Energy completed the sale of SBL Holdco, which held Dominion Energy’s remaining 67% controlling interest in certain nonregulated solar projects, to Terra Nova Renewable Partners for cash proceeds of $209 million and the assumption by Terra Nova Renewable Partners of $265 million of related long-term debt.

In 2021, Dominion Energy completed the sale of its remaining 50% controlling interest in Four Brothers and Three Cedars to Clearway for cash proceeds of $331 million.

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

Equity Method Investments

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.

Contributions to and Disposition of Interest in Wrangler

Dominion Energy completed a final contribution to Wrangler in December 2021 of its remaining nonregulated natural gas retail energy marketing operations receiving $127 million in cash, while maintaining its 20% noncontrolling interest in Wrangler. Subsequently in December 2021 and March 2022, Dominion Energy sold 5% and the remaining 15%, respectively, of its noncontrolling ownership interest in Wrangler to Interstate Gas Supply, Inc. for cash consideration of $33 million and $85 million, respectively.

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

Acquisition of Interest in Dominion Privatization

In February 2022, Dominion Energy entered into an agreement to form Dominion Privatization, a joint venture with Patriot. Under the agreement, during 2022 Dominion Energy contributed its existing privatization operations in Virginia, Texas, Pennsylvania and South Carolina, excluding contracts held by DESC, and Patriot contributed cash. Dominion Energy received total consideration of $335 million, comprised of $168 million in cash proceeds and a 50% noncontrolling ownership interest in Dominion Privatization with an initial fair value of $167 million.

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

HUMAN CAPITAL

One of Dominion Energy’s greatest strengths is its employees and Dominion Energy is committed to providing them with a safe, diverse and inclusive workplace. The ability to attract, develop and retain a diverse workforce is integral to the long-term success of Dominion Energy. At December 31, 2023, Dominion Energy had approximately 17,700 full-time employees, of which approximately 4,600 are subject to collective bargaining agreements, including approximately 6,400 full-time employees at Virginia Power, of which approximately 2,600 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 2023, Dominion Energy experienced an OSHA Recordable Rate of 0.45 compared to 0.52 in 2022 and 0.46 in 2021. These rates reflect Dominion Energy’s dedication to safety when compared to a BLS Industry Average OSHA Recordable Rate of 1.7 in both 2022 and 2021. 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. In addition, Dominion Energy was proactive in protecting its workforce during the global COVID-19 pandemic by establishing safety protocols and adapting its approach as the pandemic evolved. Dominion Energy also facilitated telecommuting and hybrid work options for many employees and expanded paid time off and other benefits to help employees cope with disruptions caused by the pandemic.

Dominion Energy works to recruit, retain and develop the careers of talented individuals who reflect the communities it serves. To cultivate this diversified workforce, Dominion Energy focuses on workforce diversity, equity and inclusion while fostering an environment where employees can utilize their unique strengths, skills, personalities and life experiences. Dominion Energy is committed to increasing its diverse workforce representation to 40% by year-end 2026; to be adjusted as necessary based on position and market availability. During 2023, Dominion Energy increased diverse representation within its workforce from 37.0% to 37.7%, following an increase during 2022 from 35.5% to 37.0% and an increase during 2021 from 34.7% to 35.5%. For the purposes of measuring diversity, Dominion Energy includes employees who 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. In 2023, 2022 and 2021, the percentage of new hires that are diverse was 49.0%, 48.9% and 57.5%, respectively. Dominion Energy sponsors nine employee resource groups to support and reinforce its culture of inclusiveness by enabling employees with shared interests and backgrounds to work together to create community, provide networking opportunities and encourage professional development. The employee resource groups are aligned to support various forms of diversity, equity and inclusion, including gender, sexual orientation, gender identity and expression, race, veteran status, age, ability and cultural heritage. To further advance these initiatives, annual incentive plans for all employees, except as restricted by any collective bargaining agreements, include a performance measure for participation in diversity, equity and inclusion training.

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 a variety of training and development opportunities for all employees with the goal to provide a consistent and progressive approach to training that engages the workforce and fosters a culture of learning. To this end, Dominion Energy offers continuous learning opportunities including tuition assistance programs, professional development resources, access to a career center and a self-guided training program for independent learning as well as leadership development programs. 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.

While daily operations are managed through the operating segments previously discussed, assets remain wholly-owned by the Companies and their respective legal subsidiaries.

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, industrial and governmental customers in Virginia and North Carolina.

Dominion Energy Virginia’s capital plan for 2024 includes spending approximately $9 billion to construct new generation capacity, including the CVOW Commercial Project, 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, which represent 24% and 21% of Virginia Power’s electricity sales for the years ended December 31, 2023 and 2022, respectively, 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 facilities to meet the growing demand.

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 79% 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 130 minutes for the three-year average ending 2023, down from the previous three-year average of 136 minutes. This decrease is primarily due to decreased 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 wholesale electricity markets. 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 could result in additional competition to build and own transmission infrastructure in Virginia Power’s service area in the future and could allow Dominion Energy to seek opportunities to build and own facilities in other service territories. 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.

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 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 total cost of the project is estimated to be approximately $10 billion, excluding financing costs. Virginia Power’s estimate for the 2.6 GW project’s projected levelized cost of energy is approximately $75-85/MWh. Following a competitive procurement process, Virginia Power has entered into fixed price contracts for the major offshore construction and equipment components. The contracts include services denominated in currencies other than the U.S. dollar for 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. As a result, any changes in applicable exchange rates or commodity indices, if not mitigated, could result in a change to the ultimate cost of the project. 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. As of December 31, 2023, approximately 92% of the costs subject to exchange rate or commodity indices have been fixed.

In March 2022, the Virginia Commission approved Virginia Power’s application filed in December 2021 for approval of a lease contract with an affiliated entity for the use of a Jones Act compliant offshore wind installation vessel currently under development. In April 2022, Virginia Power filed an application with the North Carolina Commission for approval of the same lease contract and received approval in January 2023. In January 2023, Virginia Power entered into the lease contract with commencement of the 20-month lease term in August 2025 at a total cost of approximately $240 million plus ancillary services.

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 and noted that no further action was required with respect to Virginia Power’s foreign currency risk mitigation plan. The Virginia Commission also included a performance standard for operation of the CVOW Commercial Project, which would require that customers be held harmless for any shortfall in energy production below an annual net capacity factor of 42%, as determined on a three-year rolling average, with details on the implementation of such standard to be determined in a future proceeding. Also in August 2022, Virginia Power filed a petition for limited reconsideration relating to the performance standard for operation of the CVOW Commercial Project included in the Virginia Commission’s August order. The Virginia Commission granted reconsideration and suspended in part the August order pending its reconsideration with Rider OSW approved on an interim basis. In October 2022, Virginia Power, Office of the Attorney General of Virginia and other parties filed a settlement agreement with the Virginia Commission for approval. 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 preceding. 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. In December 2022, the Virginia Commission approved the settlement agreement and reinstated its August 2022 order granting approval of Rider OSW. See Note 13 to the Consolidated Financial Statements for additional information on Rider OSW.

Virginia Power commenced major onshore construction activities in November 2023 following the receipt of a record of decision from BOEM in October 2023 for construction of the CVOW Commercial Project. In January 2024, Virginia Power received the final approval from BOEM authorizing offshore construction and necessary permits from the U.S. Army Corps of Engineers for offshore construction. As a result, Virginia Power anticipates commencing major offshore construction activities in the first half of 2024. The project is expected to be placed in service by the end of 2026. Virginia Power expects to incur approximately 80% of the project costs from 2023 through 2025. Through December 31, 2023, Virginia Power had incurred approximately $2.9 billion of costs. Virginia Power anticipates funding the project consistent with its approved debt to equity capitalization structure. In February 2024, Virginia Power entered into an agreement to sell a 50% noncontrolling interest in the CVOW Commercial Project to Stonepeak through the formation of OSWP. The agreement, subject to applicable regulatory approvals, is expected to provide for funding of 50% of the estimated total project costs of the CVOW Commercial Project, subject to certain adjustments. 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, Virginia Power is developing, financing and constructing new generation capacity as well as seeking 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 $1.1 billion in 2024 to acquire or construct several solar facilities to serve utility customers. See Note 13 to the Consolidated Financial Statements for additional information.
• Virginia Power has received a 20-year extension of the operating licenses for its two units at Surry and has commenced the process to extend the operating licenses for its two units at North Anna. Virginia Power plans to invest approximately $375 million associated with the relicensing process in 2024. See Nuclear Decommissioning below for additional information on these facilities.
• 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.
• Virginia Power is considering the construction of a hydroelectric pumped storage facility in Southwest Virginia.
• Virginia Power is considering the construction of simple cycle combustion turbines in Virginia for reliability purposes.

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 $1.0 billion in 2024.

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 $242 million and is expected to be completed by 2029. The Virginia Commission has approved six phases of the program encompassing approximately 1,866 miles of converted lines and $1.1 billion in capital spending (with $1.1 billion recoverable through Rider U).

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:

(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 solar and biomass.

*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.

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 2019. 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 2038 to 2112. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. In 2021, Virginia Power was granted an additional 20 years for its operating licenses for the two units at Surry. Under these license extensions, the two units will be allowed to generate electricity through 2052 and 2053. In 2020, Virginia Power submitted a license renewal application for the two units at North Anna. Under this renewal application, the two units will be allowed to generate electricity through 2058 and 2060, if approved. Between the four units, Virginia Power estimates that it could spend approximately $4 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:

(dollars in millions)

(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 and includes the expectation that 20-year license extensions are approved for both units at North Anna.

(2) Virginia Power did not make any contributions to its nuclear decommissioning trust funds during 2023.

(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 comprised 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 0.4 million residential, commercial and industrial customers in South Carolina.

Dominion Energy South Carolina’s capital plan for 2024 includes spending approximately $1 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.

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 82 minutes for the three-year average ending 2023, consistent with the previous three-year average of 82 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.

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, as well as PHMSA, the U.S. Department of Transportation and the South Carolina Office of Regulatory Staff for enforcement of 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 2020, DESC began the upgrade of its electric and gas systems to an AMI whereby smart meters will be installed throughout its service area. As of December 31, 2023, DESC has completed the installation of approximately 976,000 of the planned 1.1 million smart meters. This project is estimated to cost approximately $140 million and be completed by the end of 2024.

In January 2022, DESC committed to a plan to retire certain existing gas combustion turbine facilities, including certain units which currently do not have any net summer capability, and replace them with new gas combustion turbine units at the Williams and Parr facilities to increase reliability and reduce emissions. The replacement facilities are expected to be placed in service by the end of

2025 at an estimated cost of approximately $340 million, excluding financing costs, and have a total winter generating capacity of approximately 171 MW.

To maintain reliability, DESC commenced development in 2023 of a wastewater treatment facility at its Williams facility. The project will allow DESC to comply with the effluent limitation guidelines and is expected to be placed in service by the end of 2025 at an estimated cost of approximately $165 million, excluding financing costs.

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.

Sources of Energy Supply

DESC uses a variety of fuels to power its electric generation fleet and purchases power for utility system load requirements.

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

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

(2) Includes solar.

Natural gas— 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, which expire between 2024 and 2084.

Coal— 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 throughout 2024 and 2026. Spot market purchases may occur when needed or when prices are believed to be favorable.

Nuclear— 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 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 Dominion Energy 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 2020. 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 August 2023, DESC filed an application with the NRC to renew the operating license for Unit 1 at Summer for an additional 20 years. A relicensing would extend its life 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:

(dollars in millions)

(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 and includes the expectation that a 20-year license extension is obtained.

(2) Excludes any funds held in trust by Santee Cooper. DESC made contributions of $3 million to its nuclear decommissioning trust funds during 2023.

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 in operation and under development, 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 2024 includes spending approximately $0.5 billion primarily to support its operations at Millstone and develop renewable natural gas projects.

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.

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 Notes 3 and 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.

*Non-Utility Renewable Natural Gas—*In December 2019, Dominion Energy announced the formation of a strategic alliance with Vanguard Renewables in collaboration with the Dairy Farmers of America to capture methane from dairy farms and convert it into pipeline quality natural gas. In August 2021, Dominion Energy announced an expansion of the partnership, increasing its commitment up to $1 billion. As of December 31, 2023, 21 dairy renewable natural gas facilities were under construction in Colorado, Nevada, Idaho, Georgia, Kansas, Texas and New Mexico. These facilities are expected to be placed in service in 2024 and 2025 with an estimated total cost of approximately $1.1 billion, excluding financing costs. Dominion Energy expects to invest approximately $200 million in 2024.

Investments

*Align RNG—*In November 2018, Dominion Energy announced the formation of Align RNG, an equal partnership with Smithfield Foods, Inc. As of December 31, 2023, Align RNG had four projects under construction in North Carolina, Arizona and Virginia with an estimated total cost of approximately $210 million. These facilities are expected to be placed in service in 2024 through 2027.

Leasing Arrangement

In December 2020, Dominion Energy signed an agreement (subsequently amended in December 2022 and May 2023) 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 is providing equity and has obtained financing commitments from debt investors, totaling $625 million, to fund the estimated project costs. The project is expected to be completed in late 2024 or early

2025. The initial lease term will commence once construction is substantially complete and the vessel is delivered and will mature in November 2027. 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 2019.

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

(dollars in millions)

(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.

(2) Dominion Energy did not make any contributions to its nuclear decommissioning trust funds related to Millstone during 2023.

(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, 2023, the minority owners held $63 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’s regulated natural gas sales, transportation, gathering, storage and distribution operations included in the East Ohio, PSNC and Questar Gas Transactions operate in Ohio, North Carolina, Utah, southwestern Wyoming and southeastern Idaho and collectively serve approximately 3.0 million residential, commercial and industrial customers. Earnings for East Ohio, PSNC and Questar Gas primarily result from rates established by the Ohio, North Carolina, Utah, Wyoming and Idaho Commissions. The profitability of these businesses is dependent on their ability, through the rates they are permitted to charge, to recover costs and earn a reasonable return on their capital investments. Variability in earnings primarily results from changes in operating and maintenance expenditures, as well as changes in rates and the economy, including customer growth.

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, South Carolina, Ohio, Utah, Wyoming and Idaho, SEC, FERC, EPA, DOE, PHMSA, NRC, U.S. Army Corps of Engineers 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 Commission and the North Carolina Commission regulate Virginia Power’s and the South Carolina Commission regulates DESC’s transactions with affiliates and transfers of certain facilities. The Virginia, North Carolina 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, including pumped hydroelectricity generation and storage facilities 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.

The GTSA reinstated base rate reviews commencing with the 2021 Triennial Review. In the triennial review proceedings, earnings that were more than 70 basis points above the utility’s authorized ROE that might have been refunded to customers and served as the basis for a reduction in future rates, could be reduced by Virginia Commission-approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elected to include in a CCRO. The legislation declared that electric distribution grid transformation projects are in the public interest and provided that the costs of such projects may be recovered through a rate adjustment clause if not the subject of a CCRO. Any costs that were the subject of a CCRO were deemed recovered in base rates during the triennial period under review and could not be included in base rates in future triennial review proceedings. In any triennial review in which the Virginia Commission determined that the utility’s earnings are more than 70 basis points above its authorized ROE, base rates were subject to reduction prospectively and customer refunds would be due unless the total CCRO elected by the utility equaled or exceeded the amount of earnings in excess of the 70 basis points. For the purposes of measuring any customer refunds or CCRO amounts utilized under the GTSA, associated income taxes were factored into the determination of such amounts. This section of the GTSA concerning base rate reviews was amended by 2023 legislation as discussed below.

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 provides that the Virginia Commission will establish an authorized ROE of 9.70% for Virginia Power in the 2023 Biennial Review, and that subsequent to the 2023 Biennial Review 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 its discretion, increase or decrease Virginia Power’s authorized ROE by up to 50 basis points based on factors that may include reliability, generating plant performance, customer service and operating efficiency, with the provisions applying to such adjustments to be determined in a future proceeding.

The legislation directs that if the Virginia Commission determines as part of the 2023 Biennial Review that Virginia Power has earned more than 70 basis points above its authorized ROE of 9.35% established in the 2021 Triennial Review that 85% of the amount of such earnings above this level be credited to customers’ bills. In future biennial reviews, beginning with the biennial review to be filed in 2025, 85% of any earnings determined by the Virginia Commission to be up to 150 basis points above Virginia Power’s authorized ROE shall be credited to customers’ bills as well as 100% of any earnings that are more than 150 basis points above Virginia Power’s authorized ROE. For the purposes of measuring any bill credits due to customers, associated income taxes are factored into the determination of such amounts. In addition, the legislation eliminates Virginia Power’s ability to utilize Virginia Commission-approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects as a CCRO to reduce or offset any earnings otherwise eligible for customer credits as previously permitted under the GTSA.

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. 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. 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

Questar Gas and Wexpro’s natural gas development, production, transportation and distribution services, including the rates it may charge its customers, are regulated by the state commissions of Utah, Wyoming and Idaho. East Ohio, PSNC and DESC’s natural gas distribution services, including the rates they may charge their customers, are regulated by the state commissions of Ohio, North Carolina and South Carolina, respectively.

Gas Regulation in Utah, Wyoming and Idaho

Questar Gas is subject to regulation of rates and other aspects of its business by the Utah, Wyoming and Idaho Commissions. The Idaho Commission has contracted with the Utah Commission for rate oversight of Questar Gas’ operations in a small area of southeastern Idaho. When necessary, Questar Gas seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. Base rates for Questar Gas are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges. The volumetric charges for the residential and small commercial customers in Utah and Wyoming are subject to revenue decoupling and adjusted for changes in usage per customer.

Questar Gas makes routine separate filings with the Utah and Wyoming Commissions to reflect changes in the costs of purchased gas. Questar Gas’ purchased gas adjustment allows it to recover from customers all prudently incurred gas costs, including transportation costs, and certain related uncollectible expenses. A large portion of these purchased gas costs are subject to rate recovery through the Wexpro Agreement and Wexpro II Agreement. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas recovery filings generally cover a prospective twelve-month period. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

The Utah Commission has approved a standalone cost recovery mechanism to recover specified costs and a return for infrastructure projects between general base rate cases.

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

Gas Regulation in Ohio

East Ohio is subject to regulation of rates and other aspects of its business by the Ohio Commission. When necessary, East Ohio seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. A straight-fixed-variable rate design, in which the majority of operating costs are recovered through a monthly charge rather than a volumetric charge, is utilized to establish rates for a majority of East Ohio’s customers pursuant to a 2008 rate case settlement.

East Ohio makes routine filings with the Ohio Commission to reflect changes in the costs of gas purchased for operational balancing on its system. These purchased gas costs are subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The rider filings cover unrecovered gas costs plus prospective annual demand costs. Increases or decreases in gas cost rider rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

The Ohio Commission has also approved several stand-alone cost recovery mechanisms to recover specified costs and a return for infrastructure, information technology and integrity or compliance-related projects between general base rate cases.

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

Gas Regulation in North Carolina

PSNC is subject to regulation of rates and other aspects of its business by the North Carolina Commission. When necessary, PSNC seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. Base rates for PSNC are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges. The volumetric charges for the residential and commercial customers are subject to revenue decoupling and adjusted for changes in usage per customer.

PSNC makes routine separate filings with the North Carolina Commission to reflect changes in the costs of purchased gas. PSNC’s purchased gas adjustment allows it to recover from customers all prudently incurred gas costs, including transportation costs, and the related portion of uncollectible expenses. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas recovery filings are made periodically to reflect prospective costs and recovery. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

The North Carolina Commission has also approved a stand-alone cost recovery mechanism to recover specified capital costs and a return for pipeline integrity management infrastructure projects between general base rate cases.

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

Gas Regulation in South Carolina

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 generally 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 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 create DSM programs for its residential and commercial natural gas customers and a rider to retail gas rates for the recovery of the associated program costs and for a shared savings incentive. DESC has also notified the

South Carolina Commission that DESC would seek to recover the net lost revenues resulting from the 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 January 2021, Virginia Power notified PJM that it was electing to satisfy its capacity requirements by becoming a Fixed Resource Requirement Entity that self-supplies the capacity needed to serve load rather than satisfying this requirement by purchasing capacity in PJM’s Reliability Pricing Model capacity market. This change became effective for the delivery year beginning June 2022. 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 $1.5 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 February 2021, DESC and the other members of the SEEM submitted the Southeast Energy Exchange Market Agreement to FERC for authorization. This agreement sets forth the framework and rules for establishing and maintaining a new voluntary electronic trading platform designed to enhance the existing bilateral market in the Southeast utilizing zero-charge transmission service. That transmission service, in turn, will be voluntarily provided by participating transmission service providers, including DESC. In October 2021, the Southeast Energy Exchange Market Agreement became effective by operation of law as a result of a split FERC vote. The SEEM platform became operational in November 2022. Certain parties appealed FERC's authorization of SEEM to the U.S. Court of Appeals for the District of Columbia. In July 2023, the U.S. Court of Appeals for the District of Columbia remanded the authorization of SEEM to FERC for further proceedings. This matter is pending.

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 Notes 3 and 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 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 cyber security directives. 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 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*, Environmental Matters* in Future Issues and Other Matters in Item 7. MD&A and Note 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, delegated states are required to establish regulatory programs 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.

Waste and Chemical Management

Dominion Energy is subject to various federal and state laws and implementing regulations governing the management, storage, treatment, reuse and disposal of waste materials and hazardous substances, including the Resource Conservation and Recovery Act of 1976, CERCLA, the Emergency Planning and Community Right-to-Know Act of 1986 and the Toxic Substances Control Act of 1976. Dominion Energy’s operations and construction activities, including activities associated with oil and gas production and gas storage wells, generate waste. Across Dominion Energy, completion water is disposed at commercial disposal facilities. Produced water is either hauled for disposal, evaporated or injected into company and third-party owned underground injection wells. Wells drilled in tight-gas-sand and shale reservoirs require hydraulic-fracture stimulation to achieve economic production rates and recoverable reserves. The majority of Wexpro’s current and future production and reserve potential is derived from reservoirs that require hydraulic-fracture stimulation to be commercially viable. Currently, all well construction activities, including hydraulic-fracture stimulation and management and disposal of hydraulic fracturing fluids, are regulated by federal and state agencies that review and approve all aspects of gas- and oil-well design and operation.

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 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 environmental 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 is committed to providing reliable, affordable and increasingly clean energy every day. In February 2020, Dominion Energy set a goal to achieve net zero carbon and methane Scope 1 emissions by 2050. In February 2022, Dominion Energy expanded this commitment to cover 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.

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 is seeking extension of the licenses of its zero-carbon nuclear fleet at North Anna similar to the license extension received for Surry, expanding wind and solar generation as well as energy storage, investing in carbon-beneficial renewable natural gas, expanding its industry-leading methane emissions-reduction programs including pursuing innovative uses of clean burning hydrogen and using low-carbon natural gas 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 or 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:

• Clean energy diversity;
• Innovation and energy infrastructure modernization; and
• Conservation and energy efficiency.

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.

Environmental Justice

Dominion Energy seeks to build partnerships and engage with local communities, stakeholders and customers on environmental issues important to them, including environmental justice considerations such as fair treatment, inclusive involvement and effective communication. Dominion Energy commits to inclusiveness during its 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 diversity of views are considered in its public engagement process.

Transparency

As part of its broader commitment to transparency, Dominion Energy increased its 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 Environmental, Social and Governance website.

Clean Energy Diversity

To achieve its net zero commitment, Dominion Energy is pursuing a diverse mix 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 changed the fuel mix it uses to generate electricity, as well as improved the systems that make up its natural gas operations, to achieve a cleaner future. In addition to reducing GHG emissions, Dominion Energy’s environmental strategy has also resulted in 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 environmental strategy that addresses electric energy production and delivery and energy management. As part of this strategy, Dominion Energy has retired, or committed to retire, several of its fossil fuel electric generating facilities, including those powered by coal, oil and gas with the replacement of this capacity coming from the development of increasingly clean and renewable energy facilities.

Renewable energy is an important component of a diverse energy mix designed to meet Dominion Energy’s customers’ needs for safe, reliable and affordable energy. As of December 31, 2023, Dominion Energy had 2.5 GW of solar generation capacity in operation across five states and several projects under various stages of development which represented a potential generating capacity of approximately 6.5 GW. Dominion Energy has commenced construction of the CVOW Commercial Project, expected to be placed in service by the end of 2026, along with the CVOW Pilot Project which achieved commercial operation in January 2021. As of December 31, 2023, Virginia Power had energy storage projects under various stages of development which represented a potential storage capacity of approximately 1.1 GW.

Preservation of Dominion Energy’s existing carbon-free baseload nuclear generation is also an important component of Dominion Energy’s GHG emissions reduction strategy. Virginia Power has received a 20-year extension of the operating licenses for its two units at Surry and has commenced the process to extend the operating licenses for its two units at North Anna. In addition, DESC has commenced the process to extend the operating license for one unit at Summer. Dominion Energy also intends to commence the process to extend the operating licenses for two units at Millstone.

Dominion Energy expects to operate renewable natural gas facilities through its strategic alliance with Vanguard Renewables in collaboration with the Dairy Farmers of America to develop projects to capture and convert methane emissions from dairy farms.

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

The IRA provides many incentives designed to encourage production of clean energy, reduce carbon emissions, and promote domestic manufacturing. The IRA significantly extends the investment and production tax credits for renewable technologies including wind and solar, and expands the qualifying technologies to include stand-alone storage, hydrogen, renewable natural gas, nuclear and, after 2024, other zero-emissions facilities. The IRA supersedes certain prior renewable energy legislation and contains a two-tiered credit system applicable to both the production and investment tax credits with a lower base credit amount that can be increased up to five times if the taxpayer can satisfy certain labor requirements. See Note 5 to the Consolidated Financial Statements and Future Issues and Other Matters in Item 7. MD&A for additional information on the IRA.

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 plan in 2024 includes a focus on upgrading the electric system in Virginia through investments in additional 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.

Dominion Energy has also implemented infrastructure improvements and improved operational practices to reduce the GHG emissions for its natural gas facilities. Dominion Energy is also pursuing the construction or upgrade of regulated infrastructure in its natural gas businesses. Dominion Energy has made voluntary commitments as part of the EPA’s Natural Gas STAR Methane Challenge Program to continue to reduce methane emissions as part of these improvements. In addition, Dominion Energy is a member of the One Future Coalition, an industry group with members pledging to limit methane emissions to below 1% of gas throughput across the entire natural gas value chain.

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, Ohio, South Carolina, Utah and Wyoming, 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 make progress on achieving its net zero emissions commitment. Through 2022, Dominion Energy has reduced direct Scope 1 CO2 equivalent carbon and methane emissions by 46%. Through 2022, Dominion Energy has reduced direct carbon emissions from electric generation by 47% since 2005 and reduced methane emissions from its natural gas infrastructure operations by 38% since 2010. For the purposes of these calculations and consistent with GHG Protocol requirements for reporting GHG emission reductions over time, both the baseline and 2022 emissions data includes the gas entities expected to be sold as part of the East Ohio, Questar Gas and PSNC Transactions as well as Dominion Energy’s 50% noncontrolling interest in Cove Point.

Dominion Energy’s 2023 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 compressor stations 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 and for the period in which the operations are owned by Dominion Energy.

Total direct Scope 1 CO2 equivalent emissions reported under Dominion Energy’s Corporate GHG Inventory were 33.3 million metric tons in 2022. 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. Consistent with its ownership percentage, Dominion Energy’s 2022 emissions data reported under its Corporate GHG Inventory includes emissions from Hope (through August 2022), as well as the entire year of operations for the gas entities expected to be sold as part of the East Ohio, Questar Gas, and PSNC Transactions and Dominion Energy’s 50% noncontrolling interest in Cove Point.

• For Dominion Energy’s electric generation operations, total CO2 equivalent emissions were 30.6 million metric tons in 2022, including 9.3 million metric tons from DESC and 21.3 million metric tons from Virginia Power.
• For Dominion Energy’s electric transmission and distribution operations, direct CO2 equivalent emissions were 0.08 million metric tons in 2022.
• For Dominion Energy’s natural gas operations, total CO2 equivalent emissions were 1.9 million metric tons in 2022, including 0.06 million metric tons associated with Hope.
• For Dominion Energy’s proportional interest in Cove Point’s operations, total CO2 equivalent emissions were 0.6 million metric tons in 2022.
• 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 0.09 million metric tons in 2022.

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 2022 GHG emissions reported under various subparts of the EPA’s Mandatory GHG Reporting Program as of December 31, 2022, which includes the gas entities expected to be sold as part of the East Ohio, Questar Gas and PSNC Transactions are as follows:

Natural Gas Operations – 2022 Emissions

(1) Totals may not foot due to rounding.

(2) Excludes amounts related to Cove Point.

Electric Generation Operations – 2022 Emissions

(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 – 2022 Emissions

(1) Totals may not foot due to rounding.

ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES

Dominion Energy incurred $269 million, $251 million and $221 million of expenses (including accretion and depreciation) during 2023, 2022 and 2021 respectively, in connection with environmental protection and monitoring activities. Dominion Energy expects these expenses to be approximately $265 million and $260 million in 2024 and 2025, respectively. In addition, capital expenditures related to environmental controls were $132 million, $91 million, and $37 million for 2023, 2022 and 2021, respectively. Dominion Energy expects these expenditures to be approximately $225 million and $190 million for 2024 and 2025, respectively.

The Companies’ businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond their control. A number of these factors have been identified below. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in Item 7. MD&A. As discussed in Future Issues in Item 7. MD&A, Dominion Energy has commenced a comprehensive business review. The outcomes of the business review and the implementation of the resulting recommendations may be subject to various risks and uncertainties (some of which may include the risks and uncertainties discussed below or other risks and uncertainties that cannot yet be determined) that could have a material impact on the Companies’ future results of operations, cash flows and/or financial condition.

Regulatory, Legislative and Legal Risks

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

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

At the state level, Virginia Power’s retail base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia Commission in a proceeding that involves the determination of Virginia Power’s actual earned ROE during a historic test period, and the determination of Virginia Power’s authorized ROE prospectively. The GTSA reinstated base rate reviews commencing with the 2021 Triennial Review. Legislation enacted in Virginia in April 2023 reset the frequency of base rate reviews to a biennial period commencing with the 2023 Biennial Review. Under certain circumstances described in the Regulation Act, Virginia Power may be required to refund a portion of its earnings to customers through a refund process and to reduce its rates. Virginia Power makes assessments throughout the review period and will record a regulatory liability for refunds to customers in any period it is determined probable, which could be material to the Companies’ results of operations in the period recognized and to cash flows on completion of any biennial review.

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

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

The Companies’ generation business may be negatively affected by possible FERC actions that could change market design in the wholesale markets or affect pricing rules or revenue calculations in the RTO markets. The Companies’ generation stations operating in RTO markets sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these generation stations to take advantage of market price opportunities, but also expose them to market risk. Properly functioning competitive wholesale markets depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize RTOs to make changes in market design. FERC also periodically reviews the Companies’ authority to sell at market-based rates. Material changes by FERC to the design of the wholesale markets or its interpretation of market rules, the Companies’ authority to sell power at market-based rates, or changes to pricing rules or rules involving revenue calculations, could adversely impact the future results of the Companies’ generation business. For example, in September 2021, FERC issued a final order that allows distributed energy resource aggregators to compete in regional wholesale electric markets. This rule followed a previous order which mandated that distributed energy resources be allowed to participate in wholesale markets. RTOs, including PJM, are responsible for issuing implementation rules to FERC for approval. In addition, changes to the interpretation and application of FERC’s market manipulation rules may occur from time to time. A failure to comply with these market manipulation rules could lead to civil and criminal penalties.

The Companies are subject to complex governmental regulation, including tax regulation, that could adversely affect their results of operations and subject the Companies to monetary penalties. The Companies’ operations are subject to extensive federal, state and local laws and regulations and require numerous permits, approvals and certificates from various governmental agencies. Such laws and regulations govern the terms and conditions of the services the Companies offer, relationships with affiliates, protection of critical electric infrastructure assets and pipeline safety, among other matters. The Companies are also subject to legislation and associated regulation governing taxation at the federal, state and local level. They must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for existing operations and that the businesses are conducted in accordance with applicable laws. The Companies’ businesses are subject to regulatory regimes which could result in substantial monetary penalties if either of the Companies is found not to be in compliance, including mandatory reliability standards and interaction in the wholesale markets. New laws or regulations, the revision or reinterpretation of existing laws or regulations, changes in enforcement practices of regulators, or penalties imposed for non-compliance with existing laws or regulations may result in substantial additional expense. Recent legislative and regulatory changes that are impacting the Companies include legislation enacted in Virginia in April 2023, the IRA, the VCEA, the 2017 Tax Reform Act and tariffs imposed on imported solar panels by the U.S. government in 2018.

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

Environmental Risks

Compliance with federal and/or state requirements imposing limitations on GHG emissions or efficiency improvements, as well as Dominion Energy’s commitment to achieve net zero carbon and methane emissions by 2050, may result in significant compliance costs, could result in certain of the Companies’ existing electric generation units being uneconomical to maintain or operate and may depend upon technological advancements which may be beyond the Companies’ control. Virginia has adopted the VCEA which establishes renewable energy and CO2 reduction targets for Virginia Power’s generation fleet and grid operations, including the requirement that 100% of Virginia Power’s electricity come from zero-carbon generation by the end of 2045. The legislation mandates the development of 16.1 GW of solar or onshore wind capacity by the end of 2035, which includes specific requirements for utility-scale solar of 3.0 GW by the end of 2024, up to 15.0 GW by the end of 2035 and 1.1 GW of small-scale solar by the end of 2035. The legislation also deems 5.2 GW of offshore wind capacity before 2035 and 2.7 GW of energy storage by the end of 2035 to be in the public interest. The VCEA and related legislation also authorizes Virginia to participate in a program consistent with RGGI, requiring the purchase of carbon credits to offset emissions from Virginia Power’s generating fleet within the state. In January 2022, the Governor of Virginia issued an executive order which put directives in place to start the withdrawal of Virginia from RGGI. In December 2023, the withdrawal took effect. Cost recovery for these initiatives will require approval by the Virginia Commission which may be denied or materially altered to the detriment of the Companies. For example, the Companies recorded charges in 2022 associated with the Virginia Commission’s approval in June 2022 of Virginia Power’s petition that RGGI compliance costs incurred and unrecovered through July 2022 be recovered through existing base rates in effect during the period incurred. In addition, permitting and other project execution challenges may hinder Virginia Power’s ability to meet the requirements of the VCEA. The Companies could face similar risks if there is further legislation at the federal and/or state level mandating additional limitations on GHG emissions or requiring additional efficiency improvements.

In February 2020, Dominion Energy announced its commitment to achieve net zero carbon and methane Scope 1 emissions by 2050. In February 2022, Dominion Energy expanded this commitment to cover Scope 2 emissions and material categories of Scope 3 emissions. To meet this commitment, the Companies expect to construct new electric generation facilities, including renewable facilities such as wind and solar, and to seek the extension of operating licenses for the Companies’ nuclear generation facilities. The Companies also need to depend on technological improvements not currently in commercial development. Additionally, actions taken in furtherance of Dominion Energy’s net zero commitment may impact existing generation facilities, including as a result of fuel switching and/or the retirement of high-emitting generation facilities and their potential replacement with lower-emitting generation facilities. Further, the ability to realize this commitment will require the Companies to be able to obtain significant financing. These efforts will require approvals from various regulatory bodies for the siting and construction of such new facilities and a determination by the applicable state commissions that costs related to the construction are prudent. Given these and other uncertainties associated with the implementation of Dominion Energy’s net zero commitment, the Companies cannot estimate the aggregate effect of future actions taken in furtherance of this commitment on their results of operations or financial condition or on their customers. However, such actions could render additional existing generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect the Companies’ results of operations, financial performance or liquidity.

There are also potential impacts on Dominion Energy’s natural gas business from its net zero emissions commitment as well as federal or state GHG regulations which may require further GHG emission reductions from the natural gas sector which, in addition to resulting in increased costs, could affect demand for natural gas. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products, which could impact the natural gas business. Dominion Energy’s renewable natural gas projects, expected to be a key component of Dominion Energy’s environmental strategy, require approvals from various regulatory bodies for the siting and construction of such facilities.

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

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

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

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

The EPA has issued regulations concerning the management and storage of CCRs, which Virginia has adopted. These CCR regulations require the Companies to make additional capital expenditures and increase operating and maintenance expenses. In addition, the Companies will incur expenses and other costs associated with closing, corrective action and ongoing monitoring of certain ash ponds and landfills. The Companies also may face litigation concerning their coal ash facilities.

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

Construction Risks

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

The development and construction of the CVOW Commercial Project is dependent on the Companies’ ability to obtain and maintain various local, state and federal permits, rights of way and other regulatory approvals, including Virginia Commission approval for rider recovery of project costs. In addition, the design and route of the project’s onshore electric transmission, network upgrades and other facilities remain subject to regulatory and PJM review and approval. Changes in the design and route of these onshore facilities, including an increase in amount of undergrounding, would likely increase project costs. Also, the CVOW Commercial Project may become the subject of litigation or other forms of intervention by third parties, including stakeholders or advocacy groups, that may impact the timing and receipt of permits or other regulatory approvals or otherwise delay or increase the cost of the project. The Companies’ ability to recover unforeseen cost increases associated with construction of the CVOW Commercial Project is potentially limited which could negatively impact the Companies’ future financial condition, results of operations and/or cash flows. In accordance with the Virginia Commission’s order in December 2022, the Companies are subject to a cost sharing mechanism in which Virginia Power will be eligible to recover 50% of such incremental costs which fall between $10.3 billion and $11.3 billion with no recovery of such incremental costs which fall between $11.3 billion and $13.7 billion. There is no cost sharing mechanism for any total construction costs in excess of $13.7 billion, the recovery of which would be determined in a future Virginia Commission preceding. In addition, the order includes enhanced performance reporting provisions for the operation of the CVOW Commercial Project. To the extent the net annual net capacity factor is below 42%, as determined on a three-year rolling average, Virginia Power is required to provide detailed explanation of the factors contributing to any shortfall to the Virginia Commission which could determine in a future proceeding a remedy for incremental costs incurred associated with any deemed unreasonable or imprudent actions of Virginia Power. Any such action by the Virginia Commission could adversely impact the Companies’ future financial condition, results of operations and/or cash flows.

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

The development and construction of the CVOW Commercial Project is also dependent on the ability of certain key suppliers and contractors to timely satisfy their obligations under contracts entered into or expected to be entered into. Given the unique equipment and expertise required for this project, the Companies may not be able to remedy in a timely and cost-effective manner, if at all, any failure by one or more of these suppliers or contractors to timely satisfy their contractual obligations. Certain of the fixed price contracts for major offshore construction and equipment components are denominated in Euros and Danish kroner, including those which 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. Accordingly, to the extent the instruments do not effectively hedge the Companies’ exposure to these currencies, including by default of the counterparty, adverse fluctuations in the applicable exchange rates would likely adversely affect the cost of the CVOW Commercial Project. Similarly, adverse fluctuations in the price of certain raw materials, including steel, would likely, to the extent not hedged by the Companies, adversely affect the overall costs incurred to develop and construct the project.

The development and construction of the CVOW Commercial Project involves the use of evolving turbine technology and will take place in a marine environment, which presents unique challenges and will require the use of a specialized workforce and specialized equipment. In addition, the timely installation of the turbines is dependent on the completion and availability of a Jones Act compliant vessel currently under construction.

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

In connection with the February 2024 agreement to sell a 50% noncontrolling interest to Stonepeak, certain activities prior to closing require the consent of Stonepeak. Stonepeak’s interests and objectives may differ from those of the Companies and, accordingly, disputes may arise that may result in delays, litigation or operational impasses.

The Companies’ infrastructure build and expansion plans often require regulatory approval, including environmental permits, before commencing construction and completing projects. The Companies may not complete the facility construction, pipeline, conversion or other infrastructure projects that they commence, or they may complete projects on materially different terms, costs or timing than initially estimated or anticipated, and they may not be able to achieve the intended benefits of any such project, if completed. A number of large and small scale projects have been announced, including the CVOW

Commercial Project, electric transmission lines, pipeline replacements, facility expansions or renewed licensing, conversions and other infrastructure developments or construction. Additional projects may be considered in the future. The Companies compete for projects with companies of varying size and financial capabilities, including some that may have competitive advantages. Commencing construction on announced and future projects may require approvals from applicable state and federal agencies, and such approvals could include mitigation costs which may be material to the Companies. Projects may not be able to be completed on time or in accordance with estimated costs as a result of weather conditions, need for new land and right of ways, delays in obtaining or failure to obtain regulatory and other, including PJM, approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, concerns raised during stakeholder engagement, a decline in the credit strength of counterparties or vendors, inflation, or other factors beyond the Companies’ control. For example, Dominion Energy has been involved with projects which have experienced certain delays in obtaining and maintaining permits necessary for construction along with construction delays due to judicial actions which impacted the cost and schedule such as the Atlantic Coast Pipeline Project and ultimately led to its cancellation in July 2020. Even if facility construction, pipeline, expansion, electric transmission line, conversion and other infrastructure projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of the Companies following completion of the projects may not meet expectations.

Start-up and operational issues can arise in connection with the commencement of commercial operations at the Companies’ facilities. Such issues may include failure to meet specific operating parameters, which may require adjustments to meet or amend these operating parameters. Additionally, the Companies may not be able to timely and effectively integrate the projects into their operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Any of these or other factors could adversely affect the Companies’ ability to realize the anticipated benefits from the facility construction, pipeline, electric transmission line, expansion, conversion and other infrastructure projects.

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

The Companies are dependent on their contractors for the successful and timely completion of large-scale infrastructure projects. The construction of such projects is expected to take several years, is typically confined within a limited geographic area or difficult environments and could be subject to delays, supply chain disruption, cost overruns, inflation, labor disputes or shortages and other factors that could cause the total cost of the project to exceed the anticipated amount and adversely affect the Companies’ financial performance and/or impair the Companies’ ability to execute the business plan for the project as scheduled.

Further, an inability to obtain financing or otherwise provide liquidity for the projects on acceptable terms, including any potential adverse conditions arising from or in connection with the comprehensive business review announced in November 2022, could negatively affect the Companies’ financial condition, cash flows, the projects’ anticipated financial results and/or impair the Companies’ ability to execute the business plan for the projects as scheduled.

Operational Risks

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

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

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

The Companies’ financial results can be adversely affected by various factors driving supply and demand for electricity and gas and related services. Demand for the Companies’ services can be driven by changing populations within its utility service territories, significant new commercial or industrial customers or other changes in consumer habits. For example, data centers in Virginia Power’s service territory have been a source of significant increase in demand which is expected to continue over the next decade. Technological advances required by federal laws mandate new levels of energy efficiency in end-use devices, including lighting, furnaces and electric heat pumps and could lead to declines in per capita energy consumption. Additionally, certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Likewise, certain regulatory and legislative bodies have introduced or are considering actions which could limit the use or installation of new natural gas appliances. Consumer demand for the Companies’ services may also be impacted by any price increases, including those driven by factors beyond the Companies’ control such as inflation or increased prices in natural gas. Further, Virginia Power’s business model is premised upon the cost efficiency of the production, transmission and distribution of large-scale centralized utility generation. However, advances in distributed generation technologies, such as solar cells, gas microturbines, battery storage and fuel cells, may make these alternative generation methods competitive with large-scale utility generation, and change how customers acquire or use the Companies’ services. The widescale implementation of alternative generation methods could negatively impact the reliability of the Companies’ electric grid and/or result in significant costs to enhance the grid. Virginia Power has an exclusive franchise to serve retail electric customers in Virginia. However, Virginia’s Retail Access Statutes allow certain electric generation customers exceptions to this franchise. As market conditions change, Virginia Power’s customers may further pursue exceptions and Virginia Power’s exclusive franchise may erode.

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

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

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

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

The Companies may be materially adversely affected by negative publicity or the inability of Dominion Energy to meet its stated commitments. From time to time, political and public sentiment may result in a significant amount of adverse press coverage and other adverse public statements affecting the Companies. Any failure by Dominion Energy to realize its commitments to achieve net zero carbon and methane emissions by 2050, increase workforce diversity, enhance the customer experience or other long-term goals could lead to adverse press coverage and other adverse public statements affecting the Companies. The ability to comply with some or all of Dominion Energy’s voluntary commitments may be outside of its control. For example, Dominion Energy is dependent on the actions of third parties to meet the expanded commitment regarding Scope 2 emissions and Scope 3 emissions. If downstream customers or upstream suppliers do not sufficiently reduce their GHG emissions, Dominion Energy may not achieve its net zero emissions goal. In addition, while the Atlantic Coast Pipeline Project was cancelled in July 2020 and the legal proceedings and governmental investigations relating to the abandonment of the NND Project have been resolved, there is a risk that lingering negative publicity may continue. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims as well as adverse outcomes.

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

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

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

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

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

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

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

Failure to attract and retain key executive officers and an appropriately qualified workforce could have an adverse effect on the Companies’ operations. The Companies’ business strategy is dependent on their ability to recruit, retain and motivate employees. The Companies’ key executive officers are the CEO, CFO, COO and presidents and those responsible for financial, operational, legal, regulatory, accounting, tax, information technology and cybersecurity functions. Competition for skilled management employees in these areas of the Companies’ business operations is high. Certain events, such as an aging workforce, mismatch of skill set, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base and the length of time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees, or future availability and cost of contract labor may adversely affect the ability to manage and operate the Companies’ business. In addition, certain specialized knowledge is required of the Companies’ technical employees for construction and operation of transmission, generation and distribution assets. The Companies’ inability to attract and retain these employees could adversely affect their business and future operating results.

Nuclear Generation Risks

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

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

Financial, Economic and Market Risks

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

Dominion Energy may be unable to complete one or all the proposed sales of certain regulated gas distribution operations to Enbridge under the current terms and/or expected timing. The ability of Dominion Energy to complete the East Ohio, PSNC and Questar Gas Transactions, each of which are not conditioned upon the completion of the others, is dependent upon receiving clearance or approval under or by the Hart-Scott-Rodino Act, CFIUS, FCC and applicable state utility commissions, including the North Carolina, Utah and Wyoming Commissions, as well as other customary closing and regulatory conditions. The ability to obtain any remaining requisite regulatory approvals for each sale as well as the timing of such approvals is outside of Dominion Energy’s control. In addition, the terms and conditions associated with such approvals may result in additional requirements or obligations which may be burdensome or potentially result in the inability to complete one or all of the proposed sales under the current terms and/or expected timing. Such events could negatively impact Dominion Energy’s ability to implement certain of the recommendations in connection with the comprehensive business review announced in November 2022 as well as have a material adverse effect on Dominion Energy’s reputation, its financial condition, results of operations or cash flows.

The Companies may be unable to complete the proposed sale of a 50% noncontrolling interest in the CVOW Commercial Project to Stonepeak under the current terms and/or expected timing. The ability of Virginia Power to complete the proposed sale of a 50% noncontrolling interest in the CVOW Commercial Project to Stonepeak through the formation of OSWP, is dependent upon receiving approval from the Virginia and North Carolina Commissions, consent from BOEM and other customary closing and regulatory conditions. The ability to obtain requisite regulatory approval as well as the timing of such approvals is outside of the Companies’ control. In addition, the terms and conditions associated with such approvals may result in additional requirements or obligations which may be burdensome or potentially result in the inability to complete the proposed transaction under the current terms and/or expected timing. Such events could negatively impact Dominion Energy’s ability to implement certain of the recommendations in connection with the comprehensive business review announced in November 2022 as well as have a material adverse effect on the Companies’ reputation, its financial condition, results of operations or cash flows.

An inability to access financial markets and, in the case of Dominion Energy, obtain cash from subsidiaries could adversely affect the execution of the Companies’ business plans. The Companies rely on access to short-term money markets and longer-term capital markets as significant sources of funding and liquidity for business plans with increasing capital expenditure needs, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities.

Deterioration in the Companies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or declines in market reputation either for the Companies or their industry in general, or general financial market disruptions outside of the Companies’ control could increase their cost of borrowing or restrict their ability to access one or more financial markets. In addition, any potential adverse conditions arising from or in connection with the comprehensive business review announced in November 2022 could affect the availability and/or cost of capital. Market disruptions could stem from general market disruption due to general credit market or political events, the reform or replacement of benchmark rates, the failure of financial institutions on which the Companies rely or the bankruptcy of an unrelated company. Increased costs and restrictions on the Companies’ ability to access financial markets may be severe enough to affect their ability to execute their business plans as scheduled.

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

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

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

A decline in the market value of the assets held in trusts to satisfy future obligations under Dominion Energy’s pension and other postretirement benefit plans may increase the funding requirements under such plans. Additionally, changes in interest rates will affect the liabilities under Dominion Energy’s pension and other postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of retirements or changes in mortality assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans.

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

The use of derivative instruments could result in financial losses and liquidity constraints. The Companies use derivative instruments, including futures, swaps, forwards, options and FTRs, to manage commodity, interest rate and/or foreign currency exchange rate risks.

The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The CEA, as amended by Title VII of the Dodd-Frank Act, requires certain over-the-counter derivatives, or swaps, to be cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, may elect the end-user exception to the CEA’s clearing requirements. The Companies have elected to exempt their swaps from the CEA’s clearing requirements. If, as a result of changes to the rulemaking process, the Companies’ derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs due to decreased market liquidity or increased margin payments. In addition, the Companies’ swap dealer counterparties may attempt to pass-through additional trading costs in connection with changes to or the elimination of rulemaking that implements Title VII of the Dodd-Frank Act.

Future impairments of goodwill or other intangible assets or long-lived assets may have a material adverse effect on the Companies’ results of operations. Goodwill is evaluated for impairment annually or more frequently if an event or circumstance occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Other intangible assets and long-lived assets are evaluated for impairment on an annual basis or more frequently whenever events or circumstances indicate that an asset’s carrying value may not be recoverable. If Dominion Energy’s goodwill or the Companies’ other intangible assets or long-lived assets are in the future determined to be impaired, the applicable registrant would be required during the period in which the impairment is determined to record a noncash charge to earnings that may have a material adverse effect on the registrant’s results of operations. For example, in the fourth quarter of 2022, Dominion Energy determined that its nonregulated solar generation assets within Contracted Energy were impaired, resulting in a $685 million after-tax charge. In addition, Dominion Energy recorded a $286 million after-tax charge in the fourth quarter of 2023 for the impairment of certain goodwill associated with the East Ohio and Questar Gas Transactions.

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

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

Risk Management and Strategy

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

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

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

Governance

Dominion Energy’s Board of Directors, including its finance and risk oversight committee, provides oversight of the Companies’ risks from cybersecurity threats. Dominion Energy’s Board of Directors as well as its finance and risk oversight committee receive presentations and reports throughout the year on cybersecurity and information security risk from management, including Dominion

Energy’s chief security officer, director of cybersecurity and chief information officer. These presentations and reports address a broad range of topics, including the Companies’ cyber risk management program, updates on recent cybersecurity threats and incidents across the industry, policies and practices, industry trends, threat environment and vulnerability assessments and specific and ongoing efforts to prevent, detect and respond to internal and external critical threats, including management’s hosting in 2023 of its second practical exercise with external federal, state and local incident response partners. In addition, Dominion Energy’s Board of Directors receives briefings from time to time from outside experts for an independent view on cybersecurity risks, including an assessment by an independent consulting firm of management’s response in a ransomware tabletop drill.

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

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

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

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

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

As of December 31, 2023, Dominion Energy owned its principal executive office in Richmond, Virginia and five other corporate offices. Dominion Energy also leases corporate offices in Richmond, Virginia and other cities in which its subsidiaries operate. Virginia Power shares Dominion Energy’s principal executive office in Richmond, Virginia. In addition, Virginia Power leases certain buildings and equipment.

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

Certain of Virginia Power’s properties are subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. There were no bonds outstanding as of December 31, 2023; however, by leaving the indenture open, Virginia Power retains the flexibility to issue mortgage bonds in the future. Certain of Dominion Energy’s nonregulated generation facilities are also subject to liens. Additionally, DESC’s bond indenture, which secures its First Mortgage Bonds, constitutes a direct mortgage lien on substantially all of its electric utility property.

DOMINION ENERGY VIRGINIA

Virginia Power has approximately 6,700 miles of electric transmission lines of 69 kV or more located in North Carolina, Virginia and West Virginia. Portions of Virginia Power’s electric transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, any surplus capacity that may exist in these lines. While Virginia Power owns and maintains its electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance and exchange of capacity and energy for such facilities.

In addition, Virginia Power’s electric distribution network includes approximately 60,300 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, Virginia Power owns 484 substations.

The following tables list Virginia Power’s generating units and capability as of December 31, 2023.

VIRGINIA POWER UTILITY GENERATION

49

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

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

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

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

(4) All solar facilities are alternating current.

VIRGINIA POWER NON-JURISDICTIONAL GENERATION

(1) All solar facilities are alternating current.

DOMINION ENERGY SOUTH CAROLINA

DESC has approximately 3,900 miles and 19,000 miles of electric transmission and distribution lines, respectively, exclusive of service level lines, in South Carolina. The grants for most of DESC’s electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying property titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, DESC owns 457 substations.

DESC’s natural gas system includes approximately 18,800 miles of distribution mains and related service facilities, which are supported by approximately 400 miles of transmission pipeline.

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

The following table lists DESC’s generating units and capability as of December 31, 2023.

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

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

(2) Expected to be retired by the end of 2025.

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

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

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

CONTRACTED ENERGY

The following table lists Contracted Energy’s generating units and capability as of December 31, 2023.

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

(2) All solar facilities are alternating current.

(3) Dominion Energy’s interest was subject to a lien securing Eagle Solar’s debt prior to its redemption in February 2024.

CORPORATE AND OTHER

The operations included in the East Ohio, PSNC and Questar Gas Transactions are located in Ohio, North Carolina, Utah, southwestern Wyoming and southeastern Idaho. This network includes approximately 76,000 miles of distribution mains and related service facilities which are supported by approximately 3,600 miles of transmission, gathering and storage pipeline. The right-of-way grants for many natural gas pipelines have been obtained from the actual owners of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many natural gas pipelines are on publicly-owned property, where company rights and actions are determined on a case-by-case basis, with results that range from reimbursed relocation to revocation of permission to operate.

East Ohio’s integrated underground storage facilities have more than 60 bcf of working gas capacity to serve base and peak demand. PSNC owns one LNG facility that stores the liquefied equivalent of 1.0 bcf of natural gas, can regasify approximately 10% of its storage capacity per day and can liquefy less than 1% of its storage capacity per day. Questar Gas also owns one LNG facility that stores the liquefied equivalent of 1.2 bcf of natural gas, can regasify approximately 12% of its storage capacity per day and can liquefy less than 1% of its storage capacity per day.

Dominion Energy also owns various solar facilities, primarily at schools in Virginia, with an aggregate generation capacity of 27 MW.

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

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

CONTENTS OF MD&A

MD&A consists of the following information:

• Forward-Looking Statements—Dominion Energy and Virginia Power
• Accounting Matters—Dominion Energy
• Results of Operations—Dominion Energy and Virginia Power
• Segment Results of Operations—Dominion Energy
• Outlook—Dominion Energy
• Liquidity and Capital Resources—Dominion Energy
• Future Issues and Other Matters—Dominion Energy

FORWARD-LOOKING STATEMENTS

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

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

• Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;
• Extreme weather events and other natural disasters, including, but not limited to, hurricanes, high winds, severe storms, earthquakes, flooding, climate changes and changes in water temperatures and availability that can cause outages and property damage to facilities;
• The impact of extraordinary external events, such as the pandemic health event resulting from COVID-19, and their collateral consequences, including extended disruption of economic activity in the Companies’ markets and global supply chains;
• Federal, state and local legislative and regulatory developments, including changes in or interpretations of federal and state tax laws and regulations;
• The direct and indirect impacts of implementing recommendations resulting from the business review announced in November 2022;
• Risks of operating businesses in regulated industries that are subject to changing regulatory structures;
• Changes to regulated electric rates collected by the Companies and regulated gas distribution, transportation and storage rates collected by Dominion Energy;
• Changes in rules for RTOs and ISOs in which the Companies join and/or participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models;
• Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants;
• Risks associated with entities in which Dominion Energy shares ownership with third parties, including risks that result from lack of sole decision making authority, disputes that may arise between Dominion Energy and third party participants and difficulties in exiting these arrangements;
• Changes in future levels of domestic and international natural gas production, supply or consumption;
• Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals;
• The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement, intervention or litigation in such projects;
• Risks and uncertainties that may impact the Companies’ ability to develop and construct the CVOW Commercial Project within the currently proposed timeline, or at all, and consistent with current cost estimates along with the ability to recover such costs from customers;
• Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances;
• Cost of environmental strategy and compliance, including those costs related to climate change;
• Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities;
• Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals;
• Unplanned outages at facilities in which the Companies have an ownership interest;
• The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error and other catastrophic events;
• Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities;
• Changes in operating, maintenance and construction costs;
• Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity;
• Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s nonregulated generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers;
• Competition in the development, construction and ownership of certain electric transmission facilities in the Companies’ service territory in connection with Order 1000;
• Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;
• Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Energy’s pipeline system, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods;
• Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures;
• Impacts of acquisitions, divestitures, transfers of assets to joint ventures and retirements of assets based on asset portfolio reviews;
• The expected timing and likelihood of the completion of any or all of the East Ohio, PSNC and Questar Gas Transactions, including the ability to obtain the requisite regulatory approvals and the terms and conditions of such approvals;
• The expected timing and likelihood of the completion of the proposed sale of a 50% noncontrolling interest in the CVOW Commercial Project to Stonepeak, including the ability to obtain the requisite regulatory approvals and the terms and conditions of such approvals;
• Adverse outcomes in litigation matters or regulatory proceedings;
• Counterparty credit and performance risk;
• Fluctuations in the value of investments held in nuclear decommissioning trusts by the Companies and in benefit plan trusts by Dominion Energy;
• Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy’s earnings and the Companies’ liquidity position and the underlying value of their assets;
• Fluctuations in interest rates;
• The effectiveness to which existing economic hedging instruments mitigate fluctuations in currency exchange rates of the Euro and Danish Krone associated with certain fixed price contracts for the major offshore construction and equipment components of the CVOW Commercial Project;
• Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;
• Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms;
• Political and economic conditions, including inflation and deflation;
• Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; and
• Changes in financial or regulatory accounting principles or policies imposed by governing bodies.

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

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

ACCOUNTING MATTERS

Critical Accounting Policies and Estimates

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

Accounting for Regulated Operations

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

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

• Orders issued by regulatory commissions, legislation and judicial actions;
• Past experience;
• Discussions with applicable regulatory authorities and legal counsel;
• Estimated construction costs;
• Forecasted earnings; and
• Considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events and other natural disasters and unplanned outages of facilities.

If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. A regulatory liability, if considered probable, will be recorded in the period such assessment is made or reversed into earnings if no longer probable. In connection with the 2023 Biennial Review, the Companies have concluded that it is not probable that Virginia Power will have earnings in excess of 70 basis points above its authorized ROE for the period January 1, 2021 through December 31, 2022 currently under review with the Virginia Commission or in excess of an expected authorized ROE of 9.70% for the period January 1, 2023 through December 31, 2024 in connection with the future 2025 Biennial Review. As a result, no regulatory liability for Virginia Power ratepayer credits to customers has been recorded at December 31, 2023. See Note 13 to the Consolidated Financial Statements for additional information.

Asset Retirement Obligations

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

Dominion Energy’s AROs include a significant balance related to the future decommissioning of its nonregulated and utility nuclear facilities. These nuclear decommissioning AROs are reported in Dominion Energy Virginia, Dominion Energy South Carolina and Contracted Energy. At both December 31, 2023 and 2022, Dominion Energy’s nuclear decommissioning AROs totaled $1.9 billion. The following discusses critical assumptions inherent in determining the fair value of AROs associated with Dominion Energy’s nuclear decommissioning obligations.

Dominion Energy obtains from third-party specialists periodic site-specific base year cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for its nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. These cash flows include estimates on timing of decommissioning, which for regulated nuclear units factors in the probability of NRC approval for license extensions. In addition, Dominion Energy’s cost estimates include cost escalation rates that are applied to the base year costs. Dominion Energy determines cost escalation rates, which represent projected cost increases over time due to both general inflation and increases in the cost of specific decommissioning activities, for each nuclear facility. The selection of these cost escalation rates is dependent on subjective factors which are considered to be critical assumptions. At December 31, 2023, a 0.25% increase in cost escalation rates would have resulted in an approximate $390 million increase in Dominion Energy’s nuclear decommissioning AROs.

Income Taxes

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

Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2023 and 2022, Dominion Energy had $110 million and $117 million, respectively, of unrecognized tax benefits. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations.

Deferred income tax assets and liabilities are recorded representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion Energy evaluates quarterly the probability of realizing deferred tax assets by considering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. In addition, changes in tax laws or tax rates may require reconsideration of the realizability of existing deferred tax assets. Dominion Energy establishes a valuation allowance when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. At December 31, 2023 and 2022, Dominion Energy had established $130 million and $137 million, respectively, of valuation allowances.

Accounting for Derivative Contracts and Financial Instruments at Fair Value

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

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

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

Use of Estimates in Goodwill Impairment Testing

In April of each year, Dominion Energy tests its goodwill for potential impairment, and performs additional tests more frequently if an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. The 2023, 2022 and 2021 annual test did not result in the recognition of any goodwill impairment.

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

In addition to the annual goodwill impairment testing described above, in December 2023, Dominion Energy’s current period calculation of the expected gain or loss on the Questar Gas and East Ohio Transactions resulted in an impairment of the related goodwill totaling $286 million, reflected in discontinued operations in Dominion Energy’s Consolidated Statements of Income. Until each of the Questar Gas, PSNC and East Ohio Transactions are complete, the current financial position of each disposal group relative to the expected purchase price, including related post-closing adjustments, could result in significant fluctuations potentially resulting in additional impairment of the related goodwill balances, which are reflected in current assets held for sale in Dominion Energy’s Consolidated Balance Sheets.

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

Use of Estimates in Long-Lived Asset Impairment Testing

Impairment testing for an individual or group of long-lived assets, including intangible assets with definite lives, is required when circumstances indicate those assets may be impaired. When a long-lived asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets in the case of long-lived assets, and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of a market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing, expectations about the operations of the long-lived assets and the selection of an appropriate discount rate. When determining whether a long-lived asset or asset group has been impaired, management groups assets at the lowest level that has identifiable cash flows. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset or underlying assets of equity method investees, including future production and sales levels, expected fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions. In 2022, Dominion Energy determined that its nonregulated solar generation assets within Contracted Energy were impaired. The estimates of future cash flows and selection of a discount rate are considered to be critical assumptions. A 10% decrease in projected future pre-tax cash flows would have resulted in a $52 million increase to the impairment charge recorded. A 0.25% increase in the discount rate would have resulted in a $9 million increase to the impairment charge recorded. See Note 10 to the Consolidated Financial Statements for further information concerning the impairment related to certain of Dominion Energy’s nonregulated solar generation assets. There were no tests performed in 2023 of long-lived assets which could have resulted in material impairments.

Held for Sale Classification

Dominion Energy recognizes the assets and liabilities of a disposal group as held for sale in the period (i) it has approved and committed to a plan to sell the disposal group, (ii) the disposal group is available for immediate sale in its present condition, (iii) an active program to locate a buyer and other actions required to sell the disposal group have been initiated, (iv) the sale of the disposal group is probable, (v) the disposal group is being actively marketed for sale at a price that is reasonable in relation to its current fair value and (vi) it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn. Dominion Energy initially measures a disposal group that is classified as held for sale at the lower of its carrying value or fair value less any costs to sell. Any loss resulting from this measurement is recognized in the period in which the held for sale criteria are met. Conversely, gains are not recognized on the sale of a disposal group until closing. Upon designation as held for sale, Dominion Energy stops recording depreciation expense and assesses the fair value of the disposal group less any costs to sell at each reporting period and until it is no longer classified as held for sale.

The determination as to whether the sale of the disposal group is probable may include significant judgments from management related to the expectation of obtaining approvals from applicable regulatory agencies such as state utility regulatory commissions, FERC or the U.S. Federal Trade Commission. This analysis is generally based on orders issued by regulatory commissions, past experience and discussions with applicable regulatory authorities and legal counsel.

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

Employee Benefit Plans

Dominion Energy sponsors noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The projected costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected long-term rate of return on plan assets, discount rates applied to benefit obligations, mortality rates and the anticipated rate of increase in healthcare costs and participant compensation, also have a significant impact on employee benefit costs. The impact of changes in these factors, as well as differences between Dominion Energy’s assumptions and actual experience, is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants, rather than immediately.

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

• Expected inflation and risk-free interest rate assumptions;
• Historical return analysis to determine long-term historic returns as well as historic risk premiums for various asset classes;
• Expected future risk premiums, asset classes’ volatilities and correlations;
• Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and
• Investment allocation of plan assets. The long-term strategic target asset allocation for Dominion Energy’s pension funds is 26% U.S. equity, 19% non-U.S. equity, 32% fixed income, 3% real assets and 20% other alternative investments, such as private equity investments.

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

Dominion Energy develops its critical assumptions, which are then compared to the forecasts of an independent investment advisor or an independent actuary, as applicable, to ensure reasonableness. An internal committee selects the final assumptions. Dominion Energy calculated its pension cost using an expected long-term rate of return on plan assets assumption that ranged from 7.00% to 8.35% for 2023, 7.00% to 8.35% for 2022 and 7.00% to 8.45% for 2021. For 2024, the expected long-term rate of return for the pension cost assumption ranged from 7.00% to 8.35% for Dominion Energy’s plans held as of December 31, 2023. Dominion Energy calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 8.35% for 2023, 8.35% for 2022 and 8.45% for 2021. For 2024, the expected long-term rate of return for other postretirement benefit cost assumption is 8.35%.

Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost ranged from 5.65% to 5.75% for pension plans and 5.69% to 5.70% for other postretirement benefit plans in 2023, ranged from 3.06% to 3.19% for pension plans and 3.04% to 5.03% for other postretirement benefit plans in 2022 and ranged from 2.73% to 3.29% for pension plans and 2.69% to 2.80% for other postretirement benefit plans in 2021. Dominion Energy selected a discount rate ranging from 5.37% to 5.47% for pension plans and 5.40% to 5.42% for other postretirement benefit plans for determining its December 31, 2023 projected benefit obligations.

Dominion Energy establishes the healthcare cost trend rate assumption based on analyses of various factors including the specific provisions of its medical plans, actual cost trends experienced and projected and demographics of plan participants. Dominion Energy’s healthcare cost trend rate assumption as of December 31, 2023 was 7.00% and is expected to gradually decrease to 5.00% by 2031 and continue at that rate for years thereafter.

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

(millions, except percentages)

In addition to the effects on cost, a 0.25% decrease in the discount rate would increase Dominion Energy’s projected pension benefit obligation at December 31, 2023 by $224 million and its accumulated postretirement benefit obligation at December 31, 2023 by $26 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation at December 31, 2023 by $72 million.

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

New Accounting Standards

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

RESULTS OF OPERATIONS

Dominion Energy

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

Overview

2023 VS. 2022

Net income attributable to Dominion Energy increased 51%, primarily due to the absences of a charge associated with the impairment of certain nonregulated solar generation facilities, a loss associated with the sale of Kewaunee, a charge for RGGI compliance costs deemed recovered through base rates and a charge in connection with a comprehensive settlement agreement for Virginia fuel expenses. In addition, there was an increase in net investment earnings on nuclear decommissioning trust funds, a gain on the sale of Dominion Energy’s remaining noncontrolling interest in Cove Point, increased unrealized gains on economic hedging activities and a net decrease in dismantling costs associated with the early retirement of certain electric generation facilities at Virginia Power. These increases were partially offset by a charge to reflect the recognition of deferred taxes on the outside basis of stock associated with East Ohio, PSNC, Questar Gas and Wexpro meeting the classification as held for sale, an impairment associated with the East Ohio and Questar Gas Transactions, a decrease in sales to electric utility customers attributable to weather and a decrease from the impact of 2023 Virginia legislation.

2022 VS. 2021

Net income attributable to Dominion Energy decreased 61%, primarily due to a charge associated with the impairment of certain nonregulated solar generation facilities, a loss associated with the sale of Kewaunee, a decrease in net investment earnings on nuclear decommissioning trust funds, a net decrease associated with the impacts of Virginia Power’s 2021 Triennial Review, a charge for RGGI compliance costs deemed recovered through base rates, a charge in connection with a comprehensive settlement agreement for Virginia fuel expenses and dismantling costs associated with the early retirement of certain electric generation facilities at Virginia Power. These decreases were partially offset by the absence of charges associated with the settlement of the South Carolina electric base rate case and increased unrealized gains on economic hedging activities.

Analysis of Consolidated Operations

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

63

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

2023 VS. 2022

Operating revenue increased 3%, primarily reflecting:

• A $794 million net increase associated with market prices affecting Millstone, including economic hedging impacts of net realized and unrealized gains on freestanding derivatives ($1.1 billion);
• A $298 million increase to recover the costs and an authorized return, as applicable, associated with Virginia Power non-fuel riders;
• A $125 million net increase in fuel-related revenue as a result of an increase in commodity costs associated with sales to electric utility retail customers ($223 million) and a decrease in commodity costs associated with sales to gas utility customers ($98 million);
• A $102 million increase in sales to electric utility retail customers associated with economic and other usage factors;
• A $66 million increase in sales to electric utility retail customers associated with growth; and
• The absence of a $20 million decrease associated with storm damage primarily from winter storms in Virginia.

These increases were partially offset by:

• A $212 million decrease in sales to electric utility retail customers, primarily due to a decrease in heating degree days during the heating season ($148 million) and a decrease in cooling degree days during the cooling season ($64 million);
• A $206 million decrease from the combination of certain riders into base rates at Virginia Power as a result of 2023 Virginia legislation;
• A $170 million decrease from planned outages ($94 million) and unplanned outages ($76 million) at Millstone;
• A $135 million net decrease from electric utility customers who elect to pay market based or other negotiated rates, including settlements of economic hedges at Virginia Power;
• A $109 million decrease from the sale of Hope; and
• A $27 million decrease in PJM off-system sales at Virginia Power.

Electric fuel and other energy-related purchases increased 6%, primarily due to higher commodity costs for electric utilities ($223 million) and an increase in the use of purchased renewable energy credits at Virginia Power ($55 million), partially offset by a decrease in PJM off-system sales at Virginia Power ($27 million); all of which are offset in operating revenue and do not impact net income.

Purchased gas decreased 33%, primarily due to a decrease in commodity costs for gas utility operations ($98 million), which are offset in operating revenue and do not impact net income, and a decrease from the sale of Hope ($43 million).

Other operations and maintenance decreased 6%, primarily reflecting:

• A $187 million decrease in certain Virginia Power expenditures which are primarily recovered through state- and FERC-regulated rates and do not impact net income;
• A $100 million decrease in storm damage and restoration costs in Virginia Power’s service territory;
• A $25 million decrease from the sale of Hope; and
• A $22 million decrease from materials and supplies expense.

These decreases were partially offset by:

• A $76 million increase in outage costs at Millstone ($66 million) and Virginia Power ($10 million);
• A $32 million increase from the combination of certain riders into base rates at Virginia Power as a result of 2023 Virginia legislation; and
• A $30 million increase in outside services.

Depreciation and amortization increased 6%, primarily due to various projects being placed into service ($159 million), partially offset by decrease due to the impairment of certain nonregulated solar generation facilities in 2022 ($19 million).

Impairment of assets and other charges decreased 78%, primarily reflecting:

• The absence of a charge associated with the impairment of certain nonregulated solar generation facilities ($829 million);
• The absence of a charge in connection with a comprehensive settlement agreement for Virginia fuel expenses ($191 million);
• A net decrease in dismantling costs and other activities associated with certain retired electric generation facilities at Virginia Power ($182 million);
• The absence of a charge for RGGI compliance costs deemed recovered through base rates at Virginia Power ($180 million); and
• The absence of a charge for the write-off of inventory ($40 million).

These decreases were partially offset by:

• The impairment of a corporate office building ($93 million);
• A charge related to the revision of AROs for Millstone Unit 1 ($83 million);
• A charge for an easement related to the CVOW Commercial Project for which Virginia Power will not seek recovery ($65 million);
• A charge for the write-off of certain previously deferred amounts related to the cessation of certain riders effective July 2023 ($36 million); and
• A charge associated with the abandonment of certain regulated solar generation and other facilities at Virginia Power ($25 million).

Gains on sales of assets increased $453 million, primarily due to the absence of a loss associated with the sale of Kewaunee ($649 million), partially offset by the absence of a gain on the contribution of certain privatization operations to Dominion Privatization ($155 million).

Other income increased $883 million, primarily due to net investment gains in 2023 compared to net investment losses in 2022 on nuclear decommissioning trust funds ($968 million), partially offset by Dominion Energy’s share of an impairment of certain property, plant and equipment at Align RNG ($35 million).

Interest and related charges increased 67%, primarily due to increased commercial paper and long-term debt borrowings ($198 million), higher interest rates on commercial paper and long-term debt ($178 million), lower unrealized gains in 2023 compared to 2022 associated with freestanding derivatives ($173 million), higher interest rates on variable rate debt and cash flow interest rate swaps ($124 million), lower premiums received on interest rate derivatives ($60 million), and the absence of benefits associated with the early redemption of certain securities in the third and fourth quarters of 2022 ($35 million), partially offset by increased interest costs subject to recovery through riders ($38 million).

Income tax expense increased $462 million, primarily due to higher pre-tax income ($521 million) and an increase in consolidated state deferred income taxes associated with the East Ohio, PSNC and Questar Gas Transactions and the sale of Dominion Energy’s 50% noncontrolling interest in Cove Point ($29 million), partially offset by the absence of tax expense on the sale of Hope’s stock ($90 million) and decreased consolidated state deferred income taxes on pre-tax gains from nuclear decommissioning trusts and economic hedges ($12 million).

Net income from discontinued operations including noncontrolling interests decreased $1.1 billion, primarily due to charges reflecting the recognition of deferred taxes on the outside basis of stock associated with East Ohio, PSNC, Questar Gas and Wexpro meeting the classification as held for sale that will reverse when the sale is completed ($825 million), an impairment associated with the East Ohio and Questar Gas Transactions ($323 million), lower unrealized gains in 2023 compared to 2022 on interest rate derivatives for economic hedging of debt secured by Dominion Energy’s interest in Cove Point ($169 million), a decrease in equity method earnings from the sale of Dominion Energy’s noncontrolling interest in Cove Point ($44 million), a charge associated with the impairment of Birdseye ($34 million), an increase in interest expense primarily associated with debt issuances in 2022 ($31 million), the absence of a gain associated with the Q-Pipe Group for the finalization of the working capital adjustment in the first quarter of 2022 ($20 million) and an impairment charge of certain nonregulated solar assets ($11 million), partially offset by the gain on the sale of Dominion Energy’s remaining noncontrolling interest in Cove Point ($348 million), a net decrease in charges associated with the impairment of the Madison solar project ($57 million) and an increase following the approved base rate case for Questar Gas ($42 million).

2022 VS. 2021

Operating revenue increased 22%, primarily reflecting:

• A $1.3 billion increase in fuel-related revenue as a result of an increase in commodity costs associated with sales to electric utility retail customers ($1.2 billion) and gas utility customers ($99 million);
• A $505 million increase to recover the costs and an authorized return, as applicable, associated with Virginia Power non-fuel riders;
• The absence of a $356 million decrease for refunds provided to retail electric customers in Virginia associated with the settlement of the 2021 Triennial Review;
• A $290 million net increase associated with market prices affecting Millstone, including economic hedging impacts of net realized and unrealized losses on freestanding derivatives ($6 million);
• The absence of a $151 million decrease from an unbilled revenue reduction at Virginia Power;
• A $57 million increase in sales to electric utility retail customers from an increase in heating degree days during the heating season ($52 million) and a net increase in cooling degree days during the cooling season ($5 million);
• A $54 million increase in sales to utility retail customers associated with growth at electric ($46 million) and gas ($8 million) utilities;
• A $38 million net increase from electric utility customers who elect to pay market-based or other negotiated rates, including settlements of economic hedges at Virginia Power;
• A $30 million increase in sales to electric utility retail customers associated with economic and other usage factors;
• A $24 million increase in sales to customers from non-jurisdictional solar generation facilities at Virginia Power; and
• A $20 million increase in non-fuel base rates associated with the settlement in 2021 of the South Carolina electric base rate case.

These increases were partially offset by:

• A $155 million decrease from the sale of non-wholly-owned nonregulated solar facilities;
• An $80 million decrease as a result of the contribution of certain nonregulated gas retail energy contracts to Wrangler;
• A $55 million decrease reflecting a reduction in base rates associated with the settlement of the 2021 Triennial Review;
• A $49 million decrease from the sale of Hope;
• A $26 million decrease from a planned outage at Millstone; and
• A $20 million decrease associated with storm damage primarily from winter storms in Virginia.

Electric fuel and other energy-related purchases increased 57%, primarily due to higher commodity costs for electric utilities ($1.2 billion) and an increase in the use of purchased renewable energy credits at Virginia Power ($58 million), which are offset in operating revenue and do not impact net income.

Other operations and maintenance increased 6%, primarily reflecting:

• An $84 million increase in certain Virginia Power expenditures which are primarily recovered through state- and FERC-regulated rates and do not impact net income;
• A $51 million increase in storm damage and restoration costs primarily from winter storms in Virginia Power’s service territory;
• A $42 million increase in outage costs at Millstone ($26 million) and Virginia Power ($16 million);
• A $36 million increase in materials and supplies expense primarily as a result of higher prices;
• A $33 million increase in bad debt expense; and
• An $18 million increase in outside services.

These increases were partially offset by:

• The absence of a $44 million charge related to a revision in estimated recovery of spent nuclear fuel costs associated with the decommissioning of Kewaunee; and
• A $31 million decrease in merger and integration-related costs associated with the SCANA Combination.

Depreciation and amortization increased 15%, primarily due to various projects being placed into service ($183 million), an increase for amortization of a regulatory asset established in the settlement of the 2021 Triennial Review ($183 million), and an increase in RGGI-related amortization ($128 million), which except for the suspended period of Rider RGGI is offset in operating revenue and does not impact net income, partially offset by depreciation rates revised in the first quarter of 2022 at Virginia Power ($82 million) and a decrease from the sale of non-wholly-owned nonregulated solar facilities ($45 million).

Impairment of assets and other charges increased $1.2 billion, primarily reflecting:

• A charge associated with the impairment of certain nonregulated solar generation facilities ($829 million);
• The absence of a benefit from the establishment of a regulatory asset associated with the early retirement of certain coal- and oil-fired generating units associated with the settlement of the 2021 Triennial Review ($549 million);
• A charge in connection with a comprehensive settlement agreement for Virginia fuel expenses ($191 million);
• A charge for RGGI compliance costs deemed recovered through base rates at Virginia Power ($180 million);
• Dismantling costs associated with the early retirement of certain electric generation facilities at Virginia Power ($167 million); and
• A charge for the write-off of inventory ($40 million).

These increases were partially offset by:

• The absence of charges associated with the settlement of the South Carolina electric base rate case ($249 million);
• The absence of charges for CCRO benefits provided to retail electric customers in Virginia associated with Virginia Power’s 2021 Triennial Review ($188 million);
• A decrease in charges associated with litigation acquired in the SCANA Combination ($97 million);
• The absence of a charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to Virginia’s 2021 budget process ($77 million);
• The absence of a charge for corporate office lease termination ($62 million); and
• The absence of a write-off of nonregulated retail software development assets ($20 million).

Losses on sales of assets increased 3%, primarily due to a loss associated with the sale of Kewaunee ($649 million) and the absence of gains on the sale of nonregulated retail energy marketing assets ($87 million), partially offset by the absence of a net loss on the sales of non-wholly-owned nonregulated solar facilities ($513 million), a gain on the contribution of certain privatization operations to Dominion Privatization ($155 million), a gain on the transfer of certain non-utility and utility property in South Carolina ($20 million) and a gain on the sale of certain utility property in South Carolina ($20 million).

Other income decreased 90%, primarily due to net investment losses in 2022 compared to net investment gains in 2021 on nuclear decommissioning trust funds ($1.1 billion), partially offset by an increase in non-service components of pension and other postretirement employee benefit plan credits ($100 million) and the absence of charges associated with the settlement of the South Carolina electric base rate case ($18 million).

Interest and related charges decreased 20%, primarily due to higher unrealized gains associated with freestanding derivatives ($270 million), higher premiums received on interest rate derivatives ($60 million), a decrease due to junior subordinated note repayments in 2021 ($52 million), benefits associated with the early redemption of certain securities in the third and fourth quarters of 2022 ($35 million) and the absence of charges associated with the early redemption of certain securities in the third quarter of 2021 ($23 million), partially offset by an increase from net debt issuances ($90 million), higher interest rates on commercial paper borrowings ($51 million), higher interest rates on variable rate debt and cash flow interest rate swaps ($41 million) and the absence of a benefit associated with the effective settlement of uncertain tax positions ($21 million).

Income tax expense increased $294 million, primarily due to the absence of investment tax credits recognized in connection with the sale of SBL Holdco and the 50% controlling interest in Four Brothers and Three Cedars ($392 million), tax expense on the sale of Hope’s stock ($90 million), the absence of benefits from the effective settlement of uncertain tax positions ($38 million), and a state legislative change ($21 million), partially offset by lower pre-tax income including lower state income tax benefits on pre-tax losses from nuclear decommissioning trusts and economic hedges ($236 million).

Net income from discontinued operations including noncontrolling interests decreased 34%, primarily due to the completion of the sale of the Q-Pipe Group in December 2021 ($638 million), a charge associated with the impairment of the Madison solar project ($76 million) and higher interest rates on variable rate debt secured by Dominion Energy’s interest 50% noncontrolling interest in Cove Point ($54 million), partially offset by unrealized gains in 2022 compared to unrealized losses in 2021 on interest rate derivatives for economic hedging of debt secured by Dominion Energy’s 50% noncontrolling interest in Cove Point ($188 million), an increase from gas utility capital cost riders ($25 million) and cost saving incentive earned under the Wexpro Agreements ($21 million).

Noncontrolling interests decreased $20 million, primarily due to the absence of operations in connection with the sale of certain nonregulated solar generating projects held in partnerships.

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

Overview

2023 VS. 2022

Net income increased 31%, primarily due to the absences of a charge for RGGI compliance costs deemed recovered through base rates and a charge in connection with a comprehensive settlement agreement for Virginia fuel expenses as well as an increase in net investment earnings on nuclear decommissioning trust funds, a decrease in storm damage and service restoration costs and a net decrease in dismantling costs associated with the early retirement of certain electric generation facilities, partially offset by a decrease in sales to electric utility customers attributable to weather and the impact of 2023 Virginia legislation.

2022 VS. 2021

Net income decreased 33%, primarily due to a decrease in net investment earnings on nuclear decommissioning trust funds, a net decrease associated with the impacts of the 2021 Triennial Review, a charge for RGGI compliance costs deemed recovered through base rates, a charge in connection with a comprehensive settlement agreement for Virginia fuel expenses and dismantling costs associated with the early retirement of certain electric generation facilities.

Analysis of Consolidated Operations

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

68

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

2023 VS. 2022

Operating revenue decreased 1%, primarily reflecting:

• A $206 million decrease from the combination of certain riders into base rates as a result of 2023 Virginia legislation;
• A $167 million decrease in sales to electric utility retail customers from a decrease in heating degree days during the heating season ($118 million) and a decrease in cooling degree days during the cooling season ($49 million);
• An $86 million net decrease from electric utility customers who elect to pay market based or other negotiated rates, including settlements of economic hedges;
• A $27 million decrease in PJM off-system sales; and
• A $19 million decrease from the absence of privatization operations.

These decreases were partially offset by:

• A $298 million increase to recover the costs and an authorized return, as applicable, associated with non-fuel riders;
• A $126 million increase in sales to electric utility retail customers associated with economic and other usage factors; and
• A $37 million increase in sales to electric utility retail customers associated with growth.

Electric fuel and other energy-related purchases increased $5 million, primarily due to an increase in the use of purchased renewable energy credits ($55 million), partially offset by a decrease in PJM off-system sales ($27 million); both of which are offset in operating revenue and do not impact net income and a decrease in purchased power costs ($13 million).

Other operations and maintenance decreased 10%, primarily reflecting:

• A $187 million decrease in certain expenses which are primarily recovered through state- and FERC-regulated rates and do not impact net income; and
• A $100 million decrease in storm damage and restoration costs.

These decreases were partially offset by:

• A $56 million increase in salaries, wages and benefits and administrative costs;
• A $32 million increase from the combination of certain riders into base rates as a result of 2023 Virginia legislation;
• A $27 million increase in outside services; and
• A $15 million increase in bad debt expense.

Impairment of assets and other charges (benefits) decreased 79%, primarily reflecting:

• The absence of a charge in connection with a comprehensive settlement agreement for Virginia fuel expenses ($191 million);
• A net decrease in dismantling costs and other activities associated with certain retired electric generation facilities ($182 million);
• The absence of a charge for RGGI compliance costs deemed recovered through base rates ($180 million); and
• A net decrease in charges for the write-off of inventory ($14 million).

These decreases were partially offset by:

• A charge for an easement related to the CVOW Commercial Project for which Virginia Power will not seek recovery ($65 million);
• A charge for the write-off of certain previously deferred amounts related to the cessation of certain riders effective July 2023 ($36 million); and
• A charge associated with the abandonment of certain regulated solar generation and other facilities ($25 million).

Other income increased $131 million, primarily due to net investment gains in 2023 compared to net investment losses in 2022 on nuclear decommissioning trust funds.

Interest and related charges increased 19%, primarily due to an increase in the average outstanding balance of commercial paper and intercompany borrowings with Dominion Energy, and increased long-term debt ($124 million) and higher interest rates on commercial paper, long-term debt and intercompany borrowings with Dominion Energy ($39 million), partially offset by increased interest costs subject to recovery through riders ($38 million).

Income tax expense increased 32%, primarily due to higher pre-tax income ($117 million) and lower investment tax credits ($17 million), partially offset by the absence of the recognition of a deferred intercompany gain related to the transfer and subsequent contribution of existing privatization operations in Virginia to Dominion Privatization ($34 million).

2022 VS. 2021

Operating revenue increased 29%, primarily reflecting:

• A $1.1 billion increase in fuel-related revenue as a result of a net increase in commodity costs associated with sales to electric utility retail customers;
• A $505 million increase to recover the costs and an authorized return, as applicable, associated with non-fuel riders;
• The absence of a $356 million decrease for refunds provided to retail electric customers in Virginia associated with the settlement of the 2021 Triennial Review;
• The absence of a $151 million decrease from an unbilled revenue reduction;
• A $29 million net increase in sales to retail customers from an increase in heating degree days during the heating season ($47 million), partially offset by a decrease in cooling degree days during the cooling season ($18 million);
• A $26 million increase in sales to electric utility retail customers associated with growth;
• A $24 million increase in sales to customers from non-jurisdictional solar generation facilities; and
• A $19 million net increase from electric utility customers who elect to pay market-based or other negotiated rates, including settlements of economic hedges.

These increases were partially offset by:

• A $55 million decrease reflecting a reduction in base rates associated with the settlement of the 2021 Triennial Review.

Electric fuel and other energy-related purchases increased 68%, primarily due to higher commodity costs for electric utilities ($1.1 billion) and an increase in the use of purchased renewable energy credits ($58 million), which are offset in operating revenue and do not impact net income.

Purchased electric capacity increased 92%, primarily due to an increase in expense related to the annual PJM capacity performance market effective June 2021.

Other operations and maintenance increased 14%, primarily reflecting:

• An $84 million increase in certain expenses which are primarily recovered through state- and FERC-regulated rates and do not impact net income;
• A $51 million increase in storm damage and service restoration costs primarily from winter storms;
• A $28 million increase in bad debt expense;
• A $26 million increase in materials and supplies expense primarily as a result of higher prices;
• A $19 million increase in outside services;
• A $17 million increase in nuclear insurance costs; and
• A $16 million increase in planned outage costs.

Depreciation and amortization increased 27%, primarily due to an increase for amortization of a regulatory asset established in the settlement of the 2021 Triennial Review ($183 million), an increase due to various projects being placed into service ($144 million) and an increase in RGGI-related amortization ($128 million), which except for the suspended period of Rider RGGI is offset in operating revenue and does not impact net income, partially offset by depreciation rates revised in the first quarter of 2022 ($82 million).

Impairment of assets and other charges (benefits) increased $826 million, primarily reflecting:

• The absence of a benefit from the establishment of a regulatory asset associated with the early retirement of certain coal- and oil-fired generating units associated with the settlement of the 2021 Triennial Review ($549 million);
• A charge in connection with a comprehensive settlement agreement for Virginia fuel expenses ($191 million);
• A charge for RGGI compliance costs deemed recovered through base rates ($180 million);
• Dismantling costs associated with the early retirement of certain electric generation facilities ($167 million); and
• A charge for the write-off of inventory ($19 million).

These increases were partially offset by:

• The absence of charges for CCRO benefits provided to retail electric customers in Virginia associated with Virginia Power’s 2021 Triennial Review ($188 million); and
• The absence of a charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to Virginia’s 2021 budget process ($77 million).

Other income decreased $146 million, primarily due to net investment losses in 2022 compared to net investment gains in 2021 on nuclear decommissioning trust funds.

Interest and related charges increased 20%, primarily due to an increase from net debt issuances in 2022 and 2021 ($60 million), higher interest rates on commercial paper borrowings ($17 million) and an increase in principal and interest rates on intercompany borrowings with Dominion Energy ($14 million).

Income tax expense decreased 34%, primarily due to lower pre-tax income ($182 million) and higher investment tax credits ($11 million), partially offset by the recognition of a deferred intercompany gain related to the transfer and subsequent contribution of existing privatization operations in Virginia to Dominion Privatization ($34 million), and the absence of the benefit of a state legislative change ($16 million).

SEGMENT RESULTS OF OPERATIONS

Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit or loss. In September 2023, Dominion Energy revised its operating segments subsequent to entering agreements for the East Ohio, PSNC and Questar Gas Transactions as well as completing the sale of its noncontrolling interest in Cove Point. In addition, certain operations were reclassified in December 2023 to the Corporate and Other segment. See Notes 1 and 26 to the Consolidated Financial Statements for additional information. The historical information presented herein has been recast to reflect the current segment presentation.

Presented below is a summary of contributions by Dominion Energy’s operating segments to net income (loss) attributable to Dominion Energy:

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

Dominion Energy Virginia

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

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

2023 VS. 2022

72

2022 VS. 2021

Dominion Energy South Carolina

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

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

2023 VS. 2022

73

2022 VS. 2021

Contracted Energy

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

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

2023 VS. 2022

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

(2) Includes the effect of two planned refueling outages during 2023 as compared to one planned outage in 2022.

2022 VS. 2021

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

Corporate and Other

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

(1) Includes gains associated with certain transactions of $115 million and $55 million recorded in 2022 and 2021, respectively. See Note 9 to the Consolidated Financial Statements for additional information.

Corporate and Other includes specific items attributable to Dominion Energy’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. See Note 26 to the Consolidated Financial Statements for discussion of these items in more detail. Corporate and Other also includes specific items attributable to the Corporate and Other segment. In 2023, this primarily included an $825 million charge to reflect the recognition of deferred taxes on the outside basis of stock associated with East Ohio, PSNC, Questar Gas and Wexpro meeting the classification as held for sale that will reverse when the sales are completed, $662 million net income from discontinued operations, primarily associated with operations included in the East Ohio, PSNC and Questar Gas Transactions and Dominion Energy’s noncontrolling interest in Cove Point, including the gain on sale, as well as an impairment charge associated with the East Ohio and Questar Gas Transactions, a $127 million after-tax benefit for derivative mark-to-market changes and a $69 million after-tax charge associated with the impairment of a corporate office building. In 2022, this primarily included $894 million net income from discontinued operations, primarily associated with operations included in the East Ohio, PSNC and Questar Gas Transactions and Dominion Energy’s noncontrolling interest in Cove Point, a $254 million after-tax benefit for derivative mark-to-market changes and a $78 million loss associated with the sale of Hope. In 2021, this primarily included $1.4 billion net income from discontinued operations, primarily associated with the Q-Pipe Group, operations included in the East Ohio, PSNC and Questar Gas Transactions and Dominion Energy’s noncontrolling interest in Cove Point, a $64 million after-tax benefit for derivative mark-to-market changes, $62 million of after-tax charges for workplace realignment, primarily related to a corporate office lease termination and $32 million of after-tax charges for merger and integration-related costs associated with the SCANA Combination.

OUTLOOK

Dominion Energy’s 2024 net income is expected to increase on a per share basis as compared to 2023 primarily from the following:

• The absence of charges associated with the East Ohio, PSNC and Questar Gas Transactions;
• A return to normal weather in its electric service territories;
• The absence of amortization of a regulatory asset established in connection with the settlement of the 2021 Triennial Review;
• A reduction in planned and unplanned outages at Millstone;
• A reduction in interest expense from the utilization of sales proceeds to reduce debt;
• A reduction in interest expense following the securitization of certain Virginia Power deferred fuel costs; and
• Construction and operation of growth projects primarily in electric utility operations.

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

• The absence of operations associated with the expected closings of the East Ohio, PSNC and Questar Gas Transactions;
• The absence of operations associated with the sale of Dominion Energy’s remaining noncontrolling interest in Cove Point and gain on sale; and
• The combination of certain riders into base rates at Virginia Power for the entire year.

LIQUIDITY AND CAPITAL RESOURCES

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

Analysis of Cash Flows

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

(1) Includes cash outflows of $78 million, $63 million and $53 million for energy efficiency programs in Virginia and $27 million, $26 million and $21 million for DSM programs in South Carolina for the years ended December 31, 2023, 2022 and 2021, respectively.

Operating Cash Flows

Net cash provided by Dominion Energy’s operating activities increased $2.9 billion, inclusive of a $366 million decrease from discontinued operations. Net cash provided by continuing operations increased $3.2 billion primarily due to higher deferred fuel and purchased gas cost recoveries ($2.7 billion), a decrease in refund payments to Virginia electric customers associated with the settlement of the 2021 Triennial Review ($293 million), lower margin deposits ($258 million), an increase from changes in working capital ($311 million) and a $173 million increase primarily due to lower income tax payments, partially offset by an increase in interest payments driven by higher interest rates and borrowings ($530 million).

Investing Cash Flows

Net cash used in Dominion Energy’s investing activities increased $461 million, primarily due to an increase in plant construction and other property additions ($2.6 billion), absence of net proceeds from the sale of Hope ($727 million), a decrease in proceeds from the sale of assets and equity method investments ($205 million), higher cost of removal less salvage ($161 million), the absence of withdrawals from Kewaunee’s nuclear decommissioning trust ($80 million) and increased contributions to equity method affiliates ($61 million), substantially offset by net proceeds from the sale of the remaining noncontrolling interest in Cove Point ($3.3 billion) and lower acquisitions of solar development projects ($143 million).

Financing Cash Flows

Net cash provided by Dominion Energy’s financing activities decreased $2.4 billion primarily due to a $5.9 billion decrease due to net repayments of long-term debt in 2023 versus net issuances in 2022, a decrease in common stock issuance ($1.8 billion) including the absence of the settlement of the stock purchase contract component of the 2019 Equity Units in 2022 ($1.6 billion), lower net issuances of short-term debt ($576 million) and net repayment of credit facility borrowings ($450 million), partially offset by net borrowings on 364-day term loan facilities ($4.8 billion) and the absence of the redemption of Series A Preferred Stock in 2022 ($1.6 billion).

Credit Facilities and Short-Term Debt

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

Joint Revolving Credit Facility

Dominion Energy maintains a $6.0 billion joint revolving credit facility which provides for a discount in the pricing of certain annual fees and amounts borrowed by Dominion Energy under the facility if Dominion Energy achieves certain annual renewable electric generation and diversity and inclusion objectives.

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

(1) The weighted-average interest rate of the outstanding commercial paper supported by Dominion Energy’s credit facility was 5.69% at December 31, 2023.

(2) This credit facility matures in June 2026, with the potential to be extended by the borrowers to June 2028, and can be used by the borrowers under the credit facility to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

Dominion Energy Reliability InvestmentSM Program

Dominion Energy has an effective registration statement with the SEC for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability InvestmentSM. The registration statement limits the principal amount that may be outstanding at any one time to $1.0 billion. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Dominion Energy Reliability Investment Committee, or its designee, on a weekly basis. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Dominion Energy or at the investor’s option at any time. At December 31, 2023, Dominion Energy’s Consolidated Balance Sheets include $409 million presented within short-term debt, with a weighted-average interest rate of 5.50%. The proceeds are used for general corporate purposes and to repay debt.

Other Facilities

In addition to the primary sources of short-term liquidity discussed above, from time to time Dominion Energy enters into separate supplementary credit facilities or term loans as discussed in Note 17 to the Consolidated Financial Statements.

In January 2023, Dominion Energy entered into a $2.5 billion 364-day term loan facility which bears interest at a variable rate and was scheduled to mature in January 2024 with the proceeds to be used to repay existing long-term debt and short-term debt upon maturity and for other general corporate purposes. Concurrently, Dominion Energy borrowed an initial $1.0 billion with the proceeds used to repay long-term debt. In February and March 2023, Dominion Energy borrowed $500 million and $1.0 billion, respectively, with the proceeds used for general corporate purposes and to repay long-term debt. At December 31, 2023, Dominion Energy’s Consolidated Balance Sheet includes $2.5 billion with respect to such facility presented within securities due within one year. In January 2024, the facility was amended and will mature in July 2024. The amended agreement contains certain mandatory early repayment provisions, including that any after-tax proceeds in connection with the East Ohio, Questar Gas and PSNC Transactions be applied to any outstanding borrowings under the facility. The maximum allowed total debt to total capital ratio under the facility is consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility.

In July 2023, Dominion Energy entered into two $600 million 364-day term loan facilities which bore interest at a variable rate and were scheduled to mature in July 2024 with the proceeds to be used to repay existing long-term debt and/or short-term debt upon maturity and for other general corporate purposes. Subsequently in July 2023, Dominion Energy borrowed an initial $750 million in the aggregate under these facilities with the proceeds used to repay short-term debt and for general corporate purposes. Dominion Energy was permitted to make up to three additional borrowings under each agreement through November 2023, at which point any unused capacity would cease to be available to Dominion Energy. The agreements contained certain mandatory early repayment provisions, including that any after-tax proceeds in connection with a sale of Dominion Energy’s noncontrolling interest in Cove Point, following the repayment of DECP Holding’s term loan secured by its noncontrolling interest in Cove Point, be applied to any outstanding borrowings under the facilities. In September 2023, Dominion Energy repaid the $750 million borrowing with after-tax proceeds from the sale of Dominion Energy’s noncontrolling interest in Cove Point, as discussed in Note 9. Subsequently in September 2023, Dominion Energy borrowed $225 million in the aggregate under these facilities with the proceeds used to repay short-term debt and for general corporate purposes. In October 2023, Dominion Energy repaid the $225 million borrowing and terminated the facilities along with any remaining unused commitments.

In October 2023, Dominion Energy entered into a $2.25 billion 364-day term loan facility which bears interest at a variable rate and will mature in October 2024 with the proceeds to be used for general corporate purposes. Concurrently, Dominion Energy borrowed an initial $1.0 billion with the proceeds used for general corporate purposes, including to repay short-term and long-term debt. In November and December 2023, Dominion Energy borrowed $500 million and $750 million, respectively, with the proceeds used for general corporate purposes. Dominion Energy also has the ability through August 2024 to request an increase in the amount of this facility by up to an additional $500 million. The agreement contains certain mandatory early repayment provisions, including that any after-tax proceeds in connection with the East Ohio, PSNC and Questar Gas Transactions, following the repayment of the 364-day term loan facility entered into in January 2023, be applied to any outstanding borrowings under this facility. At December 31, 2023, Dominion Energy’s Consolidated Balance Sheet includes $2.25 billion with respect to such facility presented within securities due within one year. The maximum allowed total debt to total capital ratio under this facility is consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility.

Long-Term Debt

Sustainability Revolving Credit Facility

Dominion Energy maintains a $900 million Sustainability Revolving Credit Facility which matures in June 2024 and bears interest at a variable rate. The facility offers a reduced interest rate margin with respect to borrowed amounts allocated to certain environmental sustainability or social investment initiatives. In March 2023, Dominion Energy borrowed $450 million with the proceeds used for general corporate purposes. In April 2023, Dominion Energy repaid $450 million borrowed for general corporate purposes. In September 2023, Dominion Energy borrowed $450 million under this facility with the proceeds used for general corporate purposes. In October 2023, Dominion Energy repaid $450 million borrowed for general corporate purposes. At December 31, 2023, Dominion Energy had $450 million outstanding under this supplemental credit facility, borrowed to support environmental sustainability and social investment initiatives.

Issuances and Borrowings of Long-Term Debt

During 2023, Dominion Energy issued or borrowed the following long-term debt. Unless otherwise noted, the proceeds were used for the repayment of existing long-term indebtedness and for general corporate purposes.

In January 2024, Virginia Power issued $500 million of 5.00% senior notes and $500 million of 5.35% senior notes that mature in 2034 and 2054, respectively. The proceeds were used for general corporate purposes and/or to repay short-term debt. In February 2024, Virginia Power completed a securitization of $1.3 billion of deferred fuel costs for its Virginia service territory. See Note 18 to the Consolidated Financial Statements for additional information.

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

Pending any impacts from the completion of the on-going comprehensive business review announced in November 2022, Dominion Energy anticipates, excluding potential opportunistic financings and deferred fuel securitization, issuing approximately $4 billion of long-term debt during 2024, inclusive of $1.0 billion issued at Virginia Power in January 2024. Dominion Energy expects to issue long-term debt to satisfy cash needs for capital expenditures and maturing long-term debt to the extent such amounts are not satisfied from cash available from operations following the payment of dividends, after-tax proceeds from the completion of the East Ohio, PSNC and Questar Gas Transactions remaining after the repayment of 364-day term loan facilities, after-tax proceeds from the completion of the proposed sale of a 50% noncontrolling interest in the CVOW Commercial Project and any borrowings made from unused capacity of Dominion Energy’s credit facilities discussed above. The raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.

Repayments, Repurchases and Redemptions of Long-Term Debt

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

The following long-term debt was repaid, repurchased or redeemed in 2023:

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

In February 2024, Eagle Solar redeemed the remaining principal outstanding of $279 million on its 4.82% secured senior notes which otherwise would have matured in 2042. See Note 18 to the Consolidated Financial Statements for additional information.

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

Remarketing of Long-Term Debt

In June 2023, Virginia Power remarketed three series of tax-exempt bonds, with an aggregate outstanding principal of $160 million to new investors. All three series of bonds will bear interest at a coupon of 3.65% until October 2027, after which they will bear interest at a market rate to be determined at that time.

In 2024, Dominion Energy expects to remarket approximately $270 million of its tax-exempt bonds.

Credit Ratings

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

Credit ratings and outlooks as of February 16, 2024 are as follows:

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

Financial Covenants

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

Dominion Energy is required to pay annual commitment fees to maintain its joint revolving credit facility. In addition, the credit agreement contains various terms and conditions that could affect Dominion Energy’s ability to borrow under the facility. They include a maximum debt to total capital ratio, which is also included in Dominion Energy’s Sustainability Revolving Credit Agreement entered into in 2021 and the 364-day term loan facilities entered into in January 2023 and October 2023, and cross-default provisions.

As of December 31, 2023, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows:

(1) Indebtedness as defined by the agreements excludes certain junior subordinated notes reflected as long-term debt as well as AOCI reflected as equity in the Consolidated Balance Sheets.

If Dominion Energy or any of its material subsidiaries fails to make payment on various debt obligations in excess of $100 million, the lenders could require the defaulting company, if it is a borrower under Dominion Energy’s joint revolving credit facility, to accelerate its repayment of any outstanding borrowings and the lenders could terminate their commitments, if any, to lend funds to that company under the credit facility. In addition, if the defaulting company is Virginia Power, Dominion Energy’s obligations to repay any outstanding borrowing under the credit facility could also be accelerated and the lenders’ commitments to Dominion Energy could terminate.

Dominion Energy monitors compliance with these covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2023, there have been no events of default under Dominion Energy’s covenants.

Common Stock, Preferred Stock and Other Equity Securities

Issuances of Equity Securities

Dominion Energy maintains Dominion Energy Direct® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In 2021, Dominion Energy began issuing new shares of common stock for these direct stock purchase plans. In August 2023, Dominion Energy began purchasing its common stock on the open market for these direct stock purchase plans. During 2023, Dominion Energy issued 1.7 million of such shares and received proceeds of $94 million.

Dominion Energy also maintained sales agency agreements to effect sales under an at-the-market program. Under the sales agency agreements, Dominion Energy was able, from time to time, to offer and sell shares of its common stock through the sales agents or enter into one or more forward sale agreements with respect to shares of its common stock. Dominion Energy did not issue any shares or enter into any forward sale agreements under this program in 2023 prior to its expiration in June 2023.

Pending any impacts from the completion of the on-going comprehensive business review announced in November 2022, Dominion Energy expects to issue equity through programs such as Dominion Energy Direct® and employee savings plans of similar amounts in 2024 compared to 2023. The raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.

Repurchases of Equity Securities

In November 2020, the Board of Directors authorized the repurchase of up to $1.0 billion of Dominion Energy’s common stock. This repurchase program does not include a specific timetable or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors. At December 31, 2023, Dominion Energy had $920 million of available capacity under this authorization.

Dominion Energy does not plan to repurchase shares of common stock in 2024, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which does not impact the available capacity under its stock repurchase authorization.

Capital Expenditures

See Note 26 to the Consolidated Financial Statements for Dominion Energy’s historical capital expenditures by segment. As a result of the comprehensive business review announced in November 2022, Dominion Energy has not completed a long-term capital expenses plan and, as discussed in Future Issues and Other Matters, the implementation of the recommendations resulting from the business review could result in a material adjustment to capital allocations. Dominion Energy’s total planned capital expenditures for each segment for 2024 are presented in the table below:

(1) Includes $3.3 billion for 100% of the CVOW Commercial Project.

(2) Includes $0.6 billion related to gas distribution operations expected to be sold to Enbridge.

(3) Totals may not foot due to rounding.

Dominion Energy’s planned growth expenditures are subject to approval by the Board of Directors as well as potentially by regulatory bodies based on the individual project and are expected to include significant investments in support of its clean energy profile. See Dominion Energy Virginia, Dominion Energy South Carolina and Contracted Energy in Item 1. Business for additional discussion of various significant capital projects currently under development. The above estimates are based on a capital expenditures plan reviewed and endorsed by Dominion Energy’s Board of Directors in January 2024 and are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. Dominion Energy may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.

Dividends

Dominion Energy believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In December 2023, Dominion Energy’s Board of Directors established an annual dividend rate for 2024 of $2.67 per share of common stock, consistent with the 2023 rate. Dividends are subject to declaration by the Board of Directors. In January 2024, Dominion Energy’s Board of Directors declared dividends payable in March 2024 of 66.75 cents per share of common stock.

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

Subsidiary Dividend Restrictions

Certain of Dominion Energy’s subsidiaries may, from time to time, be subject to certain restrictions imposed by regulators or financing arrangements on their ability to pay dividends, or to advance or repay funds, to Dominion Energy. At December 31, 2023, these restrictions did not have a significant impact on Dominion Energy’s ability to pay dividends on its common or preferred stock or meet its other cash obligations.

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

Collateral and Credit Risk

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

Dominion Energy’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion Energy’s credit exposure as of December 31, 2023 for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.

(1) Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 54% of the total net credit exposure.

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

(3) The five largest counterparty exposures, combined, for this category represented approximately 11% of the total net credit exposure.

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

Fuel and Other Purchase Commitments

Dominion Energy is party to various contracts for fuel and purchased power commitments related to both its regulated and nonregulated operations. Total estimated costs for such commitments at December 31, 2023 are presented in the table below. These costs represent estimated minimum obligations for various purchased power and capacity agreements and actual costs may differ from amounts presented below depending on actual quantities purchased and prices paid.

Other Material Cash Requirements

In addition to the financing arrangements discussed above, Dominion Energy is party to numerous contracts and arrangements obligating it to make cash payments in future years. Dominion Energy expects current liabilities to be paid within the next twelve months. In addition to the items already discussed, the following represent material expected cash requirements recorded on Dominion Energy’s Consolidated Balance Sheets at December 31, 2023. Such obligations include:

• Operating and financing lease obligations – See Note 15 to the Consolidated Financial Statements;
• Regulatory liabilities – See Note 12 to the Consolidated Financial Statements;
• AROs – See Note 14 to the Consolidated Financial Statements;
• Employee benefit plan obligations – See Note 22 to the Consolidated Financial Statements; and
• Charitable commitments – See Note 23 to the Consolidated Financial Statements.

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

• Off-balance sheet leasing arrangements – See Note 15 to the Consolidated Financial Statements; and
• Guarantees – See Note 23 to the Consolidated Financial Statements.

FUTURE ISSUES AND OTHER MATTERS

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

Business Review

In November 2022, Dominion Energy announced the commencement of a business review of value-maximizing strategic business actions, alternatives to its current business mix and capital allocation and regulatory options which may assist customers to manage costs and provide greater predictability to its long-term, state-regulated utility value proposition. In April 2023, the legislative process in Virginia was substantially completed resulting in new legislation which shifts $350 million of annual revenue requirement for costs recovered through riders into base rates effective July 2023, eliminates the ability of Virginia Power to utilize CCROs and adjusts the parameters for determining an authorized ROE and revenue sharing. In addition, new legislation allows Virginia Power to apply for the securitization of certain deferred fuel costs as well as seek approval for a noncontrolling equity financing partner for the CVOW Commercial Project. In September 2023, Dominion Energy entered agreements to sell East Ohio, PSNC, Questar Gas and Wexpro to Enbridge and completed the sale of its 50% noncontrolling limited partner interest in Cove Point to BHE under the agreement signed in July 2023 as discussed in Notes 3 and 9 to the Consolidated Financial Statements. In February 2024, Virginia Power completed the securitization of $1.3 billion of deferred fuel costs as discussed in Notes 13 and 18 to the Consolidated Financial Statements. In February 2024, Dominion Energy entered into an agreement to sell a 50% noncontrolling equity interest in the CVOW Commercial Project to Stonepeak, as discussed in Note 10 to the Consolidated Financial Statements, representing the final strategic component of the on-going business review. Dominion Energy is in the process of finalizing its long-term financial plan which will allow for the conclusion of the review. The implementation of recommendations resulting from the business review, including the items discussed above, is expected to have a material impact on Dominion Energy's future results of operations, financial condition and/or cash flows; however, the full impacts cannot be estimated until the review is completed.

Future Environmental Regulations

Climate Change

The federal government and several states in which Dominion Energy operates have announced a commitment to achieving carbon reduction goals. In February 2021, the U.S. rejoined the Paris Agreement, which establishes a universal framework for addressing GHG emissions. States may also enact legislation relating to climate change matters such as the reduction of GHG emissions and renewable energy portfolio standards, similar to the VCEA. To the extent legislation is enacted at the federal or state level that is more restrictive than the VCEA and/or Dominion Energy’s commitment to achieving net zero emissions by 2050, compliance with such legislation could have a material impact to Dominion Energy’s financial condition and/or cash flows.

State Actions Related to Air and GHG Emissions

In August 2017, the Ozone Transport Commission released a draft model rule for control of NOX emissions from natural gas pipeline compressor fuel-fire prime movers. States within the ozone transport region, including states in which Dominion Energy has natural gas operations, are expected to develop reasonably achievable control technology rules for existing sources based on the Ozone Transport Commission model rule. States outside of the Ozone Transport Commission may also consider the model rules in setting new reasonably achievable control technology standards. Several states in which Dominion Energy operates, including Virginia and Ohio, are developing or have announced plans to develop state-specific regulations to control GHG emissions, including methane. Dominion Energy cannot currently estimate the potential financial statement impacts related to these matters, but there could be a material impact to its financial condition and/or cash flows.

Inflation Reduction Act

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

Proposed EPA Rules

In March 2023, the EPA released a proposed rule to further revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category, which apply primarily to wastewater discharges at coal and oil steam generating stations. Also in March 2023, the EPA released its first proposed rule to establish national drinking water standards for PFAS. Dominion Energy anticipates that the EPA will release additional rulemakings as part of an overall strategy to identify and mitigate PFAS exposure. In April 2023, the EPA released a proposal to tighten aspects of the Mercury and Air Toxics Standards, including the reduction of emissions limits for filterable particulate matter, and requiring the use of continuous emissions monitoring systems to demonstrate compliance. In May 2023, the EPA proposed a package of rules designed to reduce CO2 emissions from certain fossil fuel-fired electric generating units. The proposal sets standards of performance and emission guidelines for CO2 emissions from new gas-fired combustion turbines and modified coal-fired steam generating units. The proposed rulemaking package also proposes emission guidelines, including presumptive emission limits, for existing coal, oil and gas-fired steam generating units and certain gas-fired combustion turbines. Also in May 2023, the EPA released a proposed rule to regulate inactive surface impoundments located at retired generating stations that contained CCR and liquids after October 2015, and certain other inactive or previously closed surface impoundments, landfills or other areas that contain accumulations of CCR. Until the EPA ultimately takes final action on these rulemakings, Dominion Energy is unable to predict whether or to what extent the new rules will ultimately require additional controls. The expenditures required to implement additional controls could have a material impact on Dominion Energy’s financial condition and cash flows.

PHMSA Regulation

The most recent reauthorization of PHMSA included new provisions on historical records research, maximum-allowed operating pressure validation, use of automated or remote-controlled valves on new or replaced lines, increased civil penalties and evaluation of expanding integrity management beyond high-consequence areas. PHMSA has not yet issued new rulemaking on most of these items.

Dodd-Frank Act

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

North Anna

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

Federal Income Tax Laws

Inflation Reduction Act

The IRA imposes a 15% alternative minimum tax on GAAP net income, as adjusted for certain items, of corporations in excess of $1 billion, for tax years beginning after December 31, 2022. Entities that are subject to the alternative minimum tax may use tax credits to reduce the liability by up to 75% and will receive a tax credit carryforward with an indefinite life that can be claimed against the regular tax in future years. Pending final guidance, the alternative minimum tax is not expected to have an effect on the assessment of the realizability of Dominion Energy’s deferred tax assets or a material impact on Dominion Energy’s future results of operations or cash flows.

Tax Repairs Guidance

In April 2023, the IRS issued safe harbor guidance to taxpayers on the treatment of amounts paid to repair, maintain, replace, or improve natural gas distribution property, including whether expenditures should be deducted as repairs or capitalized and depreciated on tax returns. The guidance includes safe harbor tax accounting methods which a taxpayer may choose to elect and provides special transition rules and incentives that vary depending on which tax year is the year of change. Dominion Energy is evaluating this new guidance and while it cannot currently estimate the potential financial statement impacts, it does not expect a material impact to its results of operations, financial condition and/or cash flows based on its expectation that the East Ohio, PSNC and Questar Gas Transactions will close in 2024.

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

MARKET RISK SENSITIVE INSTRUMENTS AND RISK MANAGEMENT

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

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

Commodity Price Risk

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

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

A hypothetical 10% increase in commodity prices would have resulted in a decrease of $62 million and $52 million in the fair value of Dominion Energy’s commodity-based derivative instruments as of December 31, 2023 and 2022, respectively.

A hypothetical 10% increase in commodity prices would have resulted in a decrease of $24 million and $25 million in the fair value of Virginia Power’s commodity-based derivative instruments as of December 31, 2023 and 2022, respectively.

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

Interest Rate Risk

The Companies manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. For variable rate debt outstanding for Dominion Energy, a hypothetical 10% increase in market interest rates would result in a $56 million and $37 million decrease in earnings at December 31, 2023 and 2022, respectively. For variable rate debt outstanding for Virginia Power, a hypothetical 10% increase in market interest rates would result in a $5 million and $14 million decrease in earnings at December 31, 2023 and 2022, respectively.

The Companies also use interest rate derivatives, including forward-starting swaps, interest rate swaps and interest rate lock agreements to manage interest rate risk. As of December 31, 2023, Dominion Energy and Virginia Power had $16.3 billion and $3.3 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $120 million and $151 million, respectively, in the fair value of Dominion Energy and Virginia Power’s interest rate derivatives at December 31, 2023. As of December 31, 2022, Dominion Energy and

Virginia Power had $12.7 billion and $3.6 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $274 million and $156 million, respectively, in the fair value of Dominion Energy and Virginia Power’s interest rate derivatives at December 31, 2022.

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

Foreign Currency Exchange Rate Risk

The Companies utilize foreign currency exchange rate swaps to economically hedge the foreign currency exchange risk associated with fixed price contracts related to the CVOW Commercial Project denominated in foreign currencies. As of December 31, 2023 and 2022, Dominion Energy had €2.1 billion and €2.9 billion, respectively, in aggregate notional amounts of these foreign currency forward purchase agreements outstanding. A hypothetical 10% increase in exchange rates would have resulted in a decrease of $202 million and $284 million in the fair value of Dominion Energy’s foreign currency swaps at December 31, 2023 and 2022, respectively.

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

Investment Price Risk

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

Dominion Energy recognized net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $879 million and net investment losses (including investment income) on nuclear decommissioning and rabbi trust investments of $888 million for the years ended December 31, 2023 and 2022, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion Energy recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on debt investments of $117 million and a net decrease in unrealized gains on debt investments of $196 million for the years ended December 31, 2023 and 2022, respectively.

Virginia Power recognized net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $448 million and net investment losses (including investment income) on nuclear decommissioning and rabbi trust investments of $426 million for the years ended December 31, 2023 and 2022, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on debt investments of $66 million and a net decrease in unrealized gains on debt investments of $106 million for the years ended December 31, 2023 and 2022, respectively.

Dominion Energy sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power employees participate in these plans. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns (losses) of $1.2 billion and $(3.0) billion in 2023 and 2022, respectively, versus expected returns of $1.0 billion and $1.1 billion, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. A hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion Energy’s plan assets would result in an increase in the following year’s net periodic cost of $26 million as of both December 31, 2023 and 2022, for pension benefits and $5 million as of both December 31, 2023 and 2022, respectively, for other postretirement benefits.

Risk Management Policies

The Companies have established operating procedures with corporate management to ensure that proper internal controls are maintained. In addition, Dominion Energy has established an independent function at the corporate level to monitor compliance with the credit and commodity risk management policies of all subsidiaries, including Virginia Power. Dominion Energy maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion Energy also monitors the financial condition of existing counterparties on an ongoing basis. Based on these credit policies and the Companies’ December 31, 2023 provision for credit losses, management believes that it is unlikely that a material adverse effect on the Companies’ financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

Dominion Energy

Senior management of Dominion Energy, including Dominion Energy’s CEO and CFO, evaluated the effectiveness of Dominion Energy’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion Energy’s CEO and CFO have concluded that Dominion Energy’s disclosure controls and procedures are effective. There were no changes that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion Energy’s internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting

Management of Dominion Energy understands and accepts responsibility for Dominion Energy’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion Energy continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as Dominion Energy does throughout all aspects of its business.

Dominion Energy maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

The Audit Committee of the Board of Directors of Dominion Energy, composed entirely of independent directors, meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss auditing, internal control, and financial reporting matters of Dominion Energy and to ensure that each is properly discharging its responsibilities. Both the independent registered public accounting firm and the internal auditors periodically meet alone with the Audit Committee and have free access to the Audit Committee at any time.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion Energy’s 2023 Annual Report to contain a management’s report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for the report, Dominion Energy tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2023, Dominion Energy makes the following assertions:

Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion Energy.

There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

Management evaluated Dominion Energy’s internal control over financial reporting as of December 31, 2023. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion Energy maintained effective internal control over financial reporting as of December 31, 2023.

Dominion Energy’s independent registered public accounting firm is engaged to express an opinion on Dominion Energy’s internal control over financial reporting, as stated in their report which is included herein.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Dominion Energy, Inc. and subsidiaries (“Dominion Energy”) at December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, Dominion Energy maintained, in all material respects, effective internal control over financial reporting at December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements at and for the year ended December 31, 2023, of Dominion Energy and our report dated February 23, 2024, expressed an unqualified opinion on those consolidated financial statements and included an explanatory paragraph regarding Dominion Energy’s election to change its method of accounting for investment tax credits from the flow-through method to the deferral method.

Basis for Opinion

Dominion Energy’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Dominion Energy’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Dominion Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Richmond, Virginia

Senior management of Virginia Power, including Virginia Power’s CEO and CFO, evaluated the effectiveness of Virginia Power’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Virginia Power’s CEO and CFO have concluded that Virginia Power’s disclosure controls and procedures are effective. There were no changes that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Virginia Power’s internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting

Management of Virginia Power understands and accepts responsibility for Virginia Power’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Virginia Power continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.

Virginia Power maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

The Board of Directors also serves as Virginia Power’s Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Virginia Power’s auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Virginia Power’s 2023 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, Virginia Power tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2023, Virginia Power makes the following assertions:

Management is responsible for establishing and maintaining effective internal control over financial reporting of Virginia Power.

There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

Management evaluated Virginia Power’s internal control over financial reporting as of December 31, 2023. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Virginia Power maintained effective internal control over financial reporting as of December 31, 2023.

This annual report does not include an attestation report of Virginia Power’s registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Virginia Power’s independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.