D/Filings/10-K Diff

D 10-K diff: FY 2024-12-31 → FY 2025-12-31

Paragraph-level diff of Risk Factors (Item 1A) and Management's Discussion & Analysis (Item 7).

Item 1A · Risk Factors

+64 paragraphs −63 paragraphs ~63 changed

FY 2024-12-31 (earlier)

Item 1A. Ris k FactorsThe 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.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 or a change in FERC policy could result in rate decreases from current rate levels, which could adversely affect the Companies’ results of operations, cash flows and financial condition. At the state level, Virginia Power’s retail base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia Commission in a 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. 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 April 2024, FERC issued an order that accepted proposed changes to the PJM wholesale capacity market that significantly changed how a generation resource’s capacity value is calculated and decreased the total amount of capacity recognized in the PJM region as eligible to meet reserve requirements. In addition, changes to the interpretation and application of FERC’s market manipulation rules may occur from time to time. A failure to comply with these market manipulation rules could lead to civil and criminal penalties. The Companies are subject to complex governmental regulation, including tax regulation, that could adversely affect their results of operations and subject the Companies to monetary penalties. The Companies’ operations are subject to extensive federal, state and local laws and regulations and require numerous permits, approvals and certificates from various governmental 33 agencies. Such laws and regulations govern the terms and conditions of the services the Companies offer, relationships with affiliates and protection of critical electric infrastructure assets, 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, the imposition of new tariffs, changes in enforcement practices of regulators, or penalties imposed for non-compliance with existing laws or regulations may result in substantial additional expense. Adverse developments in tax laws, credits or other incentives including changes in legislation, administrative interpretations or judicial determinations could result in material modifications to business models or otherwise negatively affect the Companies’ results of operations, financial condition and/or cash flows. 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 CO 2 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, 34 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 EPA’s May 2024 final rule regulates inactive surface impoundments located at the retired generation stations that contained CCR and liquids after 2015, and certain other inactive or previously closed surface impoundments, landfills or other areas that contain accumulations of CCR. The Companies believe that they may have inactive or closed units or areas that could be subject to the final rule at up to 19 different locations, including 12 at Virginia Power. 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 RisksThe 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 construction of the CVOW Commercial Project or decide in the future to delay or cancel the project, the 35 Companies may not be able to recover all or a portion of their investment in the project and may incur substantial cancellation payments under existing contracts or other substantial costs associated with any such delay or cancellation. The Companies’ ability to complete the CVOW Commercial Project within the currently proposed timeline, or at all, and consistent with current cost estimates is subject to various risks and uncertainties, certain of which are beyond the Companies’ control. The construction of the CVOW Commercial Project is dependent on the Companies’ ability to maintain various local, state and federal permits, rights of way and other regulatory approvals and authorizations, including Virginia Commission approval for rider recovery of project costs. In addition, determination of costs allocated by PJM to the project for network upgrades remains subject to change, even after the CVOW Commercial Project is placed in service, as such amounts are driven by the ultimate costs of development of the transmission lines and related facilities that PJM determines is necessary to support various generation facilities within PJM, including the CVOW Commercial Project. The final determination of such costs is outside the control of the CVOW Commercial Project and may be impacted by events affecting the developers of such transmission lines, including any increases in costs for permitting, inflation, tariffs, supply chain constraints or other factors affecting the ultimate costs to complete such facilities. Also, the CVOW Commercial Project may become the subject of litigation or other forms of intervention by third parties, including stakeholders or advocacy groups, that may seek to challenge permits or other regulatory approvals received, including for routing of onshore electric transmission, which could delay or increase the cost of the project. The construction of the CVOW Commercial Project is also dependent on the ability of certain key suppliers and contractors to timely satisfy their obligations under contracts entered into or expected to be entered into. Given the unique equipment and expertise required for this project, the Companies may not be able to remedy in a timely and cost-effective manner, if at all, any failure by one or more of these suppliers or contractors to timely satisfy their contractual obligations. Certain of the fixed price contracts for major offshore construction and equipment components are denominated in Euros and Danish kroner. In May 2022, Virginia Power entered into forward purchase agreements with a notional amount of approximately €3.2 billion. Accordingly, to the extent the instruments do not effectively hedge the Companies’ exposure to these currencies, including by default of the counterparty, adverse fluctuations in the applicable exchange rates would likely adversely affect the cost of the CVOW Commercial Project. Similarly, adverse fluctuations in the price of fuel used for transportation and installation, would likely adversely affect the overall costs to construct the project. In addition, the cost of the CVOW Commercial Project could be adversely affected by the impact of applicable tariffs, if any. The Companies’ ability to recover unforeseen cost increases associated with construction of the CVOW Commercial Project is potentially limited which could negatively impact the Companies’ future financial condition, results of operations and/or cash flows. In accordance with the Virginia Commission’s December 2022 order, the Companies are subject to a cost sharing mechanism in which Virginia Power will be eligible to recover 50% of such incremental costs which fall between $10.3 billion and $11.3 billion with no recovery of such incremental costs which fall between $11.3 billion and $13.7 billion. There is no cost sharing mechanism for any total construction costs in excess of $13.7 billion, the recovery of which would be determined in a future Virginia Commission 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. In October 2024, Virginia Power completed the sale of a 50% noncontrolling interest to Stonepeak. Virginia Power and Stonepeak will each contribute 50% of the remaining capital necessary to fund construction of the CVOW Commercial Project provided the total project cost, excluding financing costs, is less than $11.3 billion. For capital funding necessary, if any, for total project costs, excluding financing costs, of $11.3 billion through $13.7 billion, Stonepeak will have the option to make additional capital contributions. If Stonepeak elects to make additional capital contributions for project costs, excluding financing costs, in excess of $11.3 billion, if any, Virginia Power shall contribute between 67% and 83% of such capital with Stonepeak contributing the remainder. To the extent that Stonepeak elects not to make such contributions, Virginia Power shall receive an increase in its ownership percentage of OSWP for any contributed capital based on a tiered unit price for membership interests in OSWP as set forth in the agreement. Virginia Power and Stonepeak have the right to provide capital contributions for any total project costs, excluding financing costs, in excess of $13.7 billion. The inability of Stonepeak to satisfy its share of funding requirements in a timely manner could have a negative effect on the Companies. In addition, Stonepeak’s interests and objectives may differ from those of the Companies and, accordingly, disputes may arise that may result in delays, litigation or operational impasses.36 The construction of the CVOW Commercial Project involves the use of evolving turbine technology and takes place in a marine environment, which presents unique challenges and requires the use of a specialized workforce and specialized equipment. In addition, the timely installation of the turbines is dependent on the completion and availability of a Jones Act compliant vessel currently under construction.The timeline for construction of the CVOW Commercial Project may also be negatively impacted by severe weather events or marine wildlife, including migration patterns of endangered and protected species, both of which are outside of the control of the Companies and their contractors.The Companies’ infrastructure build and expansion plans often require regulatory approval, including environmental permits, before commencing construction and completing projects. The Companies may not complete the facility construction, conversion or other infrastructure projects that they commence, or they may complete projects on materially different terms, costs or timing than initially estimated or anticipated, and they may not be able to achieve the intended benefits of any such project, if completed. A number of large- and small-scale projects have been announced, including the CVOW Commercial Project, electric transmission lines, facility expansions or renewed licensing, conversions and other infrastructure developments or construction. Additional projects may be considered in the future, such as those necessary to meet the projected demand growth driven by data centers and artificial intelligence, including to address the concentration of data centers primarily in Loudoun County, Virginia. The Companies compete for projects with companies of varying size and financial capabilities, including some that may have competitive advantages. Commencing construction on announced and future projects may require approvals from applicable state and federal agencies, and such approvals could include mitigation costs 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, changes in laws or regulations, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, concerns raised during stakeholder engagement, a decline in the credit strength of counterparties or vendors, inflation, the impact of applicable tariffs or other factors beyond the Companies’ control. 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, 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. Any delays in the timely completion of necessary PJM interconnection projects for new electric generation facilities under development by Virginia Power, including the CVOW Commercial Project, may result in capacity constraints if, and until, such projects are completed. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Any of these or other factors could adversely affect the Companies’ ability to realize the anticipated benefits from the facility construction, electric transmission line, expansion, conversion and other infrastructure projects. The development, construction and commissioning of several large-scale infrastructure projects simultaneously involves significant execution risk. To achieve Dominion Energy’s commitment to net zero emissions by 2050 and comply with the requirements of the VCEA, 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 CVOW Commercial Project. 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. Similarly, certain stakeholder groups oppose new natural gas generation facilities, such as the proposed Chesterfield Energy Reliability Center. Given that these projects provide the foundation for the Companies’ strategic growth plan and to meet projected growth, if the Companies are unable to obtain or maintain the required regulatory and other, including PJM, approvals, develop the necessary technical expertise, allocate and coordinate sufficient resources, adhere to budgets and timelines, effectively handle public outreach efforts, including its commitment to fair treatment, community involvement and effective communication, or otherwise fail to successfully execute the projects, there could be an adverse impact to the Companies’ financial position, results of operations and cash flows. Failure to comply with regulatory approval conditions or an adverse ruling in any future litigation could adversely affect the Companies’ ability to execute their business plan. 37 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 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 RisksThe Companies’ financial performance and condition can be affected by changes in the weather, including the effects of global climate change. Fluctuations in weather can affect demand for the Companies’ services. For example, milder than normal weather can reduce demand for electricity and gas distribution services. In addition, severe weather or acts of nature, including hurricanes, winter storms, wildfires, earthquakes, floods and other natural disasters can stress systems, disrupt operation of the Companies’ facilities and cause service outages, production delays and property damage that require incurring additional expenses. Changes in weather conditions can result in reduced water levels or changes in water temperatures that could adversely affect operations at some of the Companies’ power stations. 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 related services. Demand for the Companies’ services can be driven by changing populations within its utility service territories, significant new commercial or industrial customers or other changes in consumer habits. For example, data centers in Virginia Power’s service territory, particularly in Loudoun County, Virginia, have been a source of significant increase in demand which is expected to continue over the next decade. Technological advances may enhance energy efficiency in end-use devices, including lighting, furnaces and electric heat pumps and could lead to declines in per capita energy consumption. Additionally, regulatory and/or legislative bodies could introduce requirements and/or incentives to reduce energy consumption. Consumer demand for the Companies’ services may also be impacted by any price increases, including those driven by factors beyond the Companies’ control 38 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, expanded use of artificial intelligence, widespread adoption of electric vehicles or other customer changes could require enhancements to the Companies’ infrastructure. As discussed above, the ability of the Companies to construct new facilities is dependent upon factors outside of their control, including obtaining 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 including nuclear accidents, fires, explosions, uncontrolled release of natural gas and other environmental hazards, pole strikes, electric contact cases, the collision of third party equipment with pipelines and avian and other wildlife impacts. Such incidents could result in loss of human life or injuries among employees, customers or the public in general, environmental pollution, damage or destruction of facilities or business interruptions and associated public or employee safety impacts, loss of revenues, increased liabilities, heightened regulatory scrutiny and reputational risk. Further, the location of electric generation, transmission, substations and distribution facilities or natural gas distribution facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks.The Companies conduct certain operations through partnership arrangements involving third-party investors which may limit the Companies’ operational flexibility or result in an adverse impact on its financial results. Certain of the Companies’ operations, including the CVOW Commercial Project, are conducted through entities subject to partnership arrangements under which Dominion Energy or Virginia Power has significant influence but does not control the operations of such entities or in which Dominion Energy or Virginia Power’s control over such entities may be subject to certain rights of third-party investors. Accordingly, while Dominion Energy or Virginia Power may have a certain level of control or influence over these entities, it may not have unilateral, or any, control over the day-to-day operations of these entities or over decisions that may have a material financial impact on the partnership participants, including the Companies. In each case such partnership arrangements operate in accordance with their respective governance documents, and the Companies are dependent upon third parties satisfying their respective obligations, including, as applicable, funding of their required share of capital expenditures. Such third-party investors have their own interests and 39 objectives which may differ from those of the Companies and, accordingly, disputes may arise amongst the owners of such partnership arrangements that may result in delays, litigation or operational impasses. The Companies may be materially adversely affected by negative publicity or the inability of Dominion Energy to meet its stated commitments. From time to time, political and public sentiment may result in a significant amount of adverse press coverage and other adverse public statements affecting the Companies. Any failure by Dominion Energy to realize its commitments to achieve net zero carbon and methane emissions by 2050, enhance the customer experience or other long-term goals could lead to adverse press coverage and other adverse public statements affecting the Companies. The ability to comply with some or all of Dominion Energy’s voluntary commitments may be outside of its control. For example, the ability to reduce emissions while meeting the Companies’ increasing demand growth is expected to be dependent on the technological and economic feasibility of large-scale battery storage, carbon capture and storage, small modular reactors, hydrogen and/or other clean energy technologies. Dominion Energy is also dependent on the actions of third parties to meet 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.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 40 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 RisksChanging 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. 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 41 increase their cost of borrowing or restrict their ability to access one or more financial markets. Market disruptions could stem from general market disruption due to general credit market or political events, the reform or replacement of benchmark rates, the failure of financial institutions on which the Companies rely or the bankruptcy of an unrelated company. Increased costs and restrictions on the Companies’ ability to access financial markets 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 an aggregate $309 million after-tax charge in the fourth quarter of 2023 and first quarter of 2024 for the impairment of certain goodwill associated with the Questar Gas Transaction. 42 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.

FY 2025-12-31 (later)

Item 1A. Ris k FactorsThe Companies’ businesses are influenced by many factors that are difficult to predict, involve risks and uncertainties that may materially affect actual results and are often beyond their control. A number of these risks and uncertainties are identified below. There may be other factors, either not presently known or currently believed not to be material, that may cause actual results to differ materially from those indicated in this report. For additional information concerning any forward-looking statement or projection contained in this report, see Forward-Looking Statements in Item 7. MD&A.Regulatory, Legislative and Legal Risks The rates of the Companies’ principal electric transmission, distribution and generation operations and gas distribution operations are subject to regulatory review. Revenue provided by the Companies’ electric transmission, distribution and generation operations and by gas distribution operations is based primarily on rates approved by state and federal regulatory agencies. The profitability of the Companies’ businesses is dependent on their ability, through the rates that they are permitted to charge, to recover costs and earn a reasonable rate of return on their capital investment.At the federal level, the Companies’ wholesale rates for electric transmission service are regulated by FERC. Rates for electric transmission services are updated annually according to a FERC-approved formula rate mechanism, and may be subject to additional prospective adjustments and retroactive corrections. A failure by the Companies to justify the appropriateness of these rates or a change in FERC policy or the application of FERC policy could result in rate decreases from current rate levels, which could adversely affect the Companies’ results of operations, cash flows and financial condition. At the state level, Virginia Power’s retail base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia Commission in a biennial proceeding that involves the determination of Virginia Power’s actual earned ROE during a historic test period, and the determination of Virginia Power’s authorized ROE prospectively. Under certain circumstances described in the Regulation Act, Virginia Power may be required to refund a portion of its earnings to customers through a refund process and to reduce its rates. Virginia Power makes assessments throughout the review period and will record a regulatory liability for refunds to customers in any period such refunds are determined probable, which could negatively impact the Companies’ results of operations in the period recognized and to cash flows on completion of any biennial review. In states other than Virginia, the Companies’ retail electric base rates for generation and distribution services to customers are regulated on a cost-of-service/rate-of-return basis subject to the statutes, rules and procedures of such states. Dominion Energy’s rates for gas distribution to retail customers are similarly regulated at the state level. If retail electric or gas earnings exceed the returns established by state utility commissions, retail electric rates or gas rates may be subject to review and possible reduction, which may decrease the Companies’ future earnings. Additionally, if any state utility commission does not allow recovery through base rates, on a timely basis, of costs incurred in providing service, the Companies’ financial condition, results of operations and/or cash flows could be negatively impacted. Under certain circumstances, state utility regulators may impose a moratorium on increases to retail base rates for a specified period of time, which could delay recovery of costs incurred in providing service. Additionally, governmental officials, stakeholders and advocacy groups may challenge any of the regulatory reviews or proceedings referred to above. Such challenges may result in changes to the regulatory framework under which the Companies’ currently operate and/or lengthen the time, complexity and costs associated with such regulatory reviews or proceedings. The Companies’ generation business may be negatively affected by possible FERC actions that could change market design in the wholesale markets or affect pricing rules or revenue calculations in the RTO markets. The Companies’ generation stations operating in RTO markets sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these generation stations to take advantage of market price opportunities, but also expose them to market risk. Properly functioning competitive wholesale markets depend upon FERC, PJM and/or ISO-NE’s continuation of clearly identified market rules. From time to time, FERC may investigate and/or receive requests from PJM or ISO-NE to authorize changes in market design. FERC also periodically reviews the Companies’ authority to sell at market-based rates. Changes by FERC, PJM or ISO-NE to the design of the wholesale markets or its interpretation of market rules, the Companies’ authority to sell power at market-based rates, or changes to pricing rules or rules involving revenue calculations, could adversely impact the future results of the Companies’ generation business. For example, in April 2024, FERC issued an order that accepted proposed changes to the PJM wholesale capacity market that significantly changed how a generation resource’s capacity value is calculated and decreased the total amount of capacity recognized in the PJM region as eligible to meet reserve requirements. In addition, changes to the interpretation and application of FERC’s market manipulation rules may occur from time to time. A failure to comply with these market manipulation rules could lead to civil and criminal penalties. The Companies are subject to complex governmental regulation, including tax regulation, that could adversely affect their results of operations and subject the Companies to monetary penalties. The Companies’ operations are subject to extensive federal, state and local laws and regulations and require numerous permits, approvals and certificates from various governmental agencies. Such laws and regulations govern the terms and conditions of the services the Companies offer, relationships with affiliates, protection of critical electric infrastructure assets and mandatory reliability standards and interaction in the wholesale markets, among other matters. The Companies are also subject to legislation and associated regulation governing taxation at the federal, state and local level. They must also comply with environmental legislation and associated regulations. Some such legislation and regulation have not yet been finalized and changes in either interpretation or final laws or regulations could have a negative impact on the Companies. For example, the OBBBA and IRA include various provisions, such as investment and production tax credits and 25 corporate alternative minimum tax, that the Companies have considered in recording their provisions for income taxes. The ultimate impact of these tax laws is subject to pending guidance and interpretations that could adversely impact the Companies’ ability to qualify for and maintain tax credits, which could affect the Companies’ results of operations, financial condition and/or cash flows. Management believes that the necessary approvals have been obtained for existing operations and that the Companies’ businesses are conducted in accordance with applicable laws. The Companies’ businesses are subject to regulatory regimes which could result in substantial monetary penalties if either of the Companies is found not to be in compliance. New laws or regulations, the revision or reinterpretation of existing laws or regulations, the imposition of new tariffs or changes to existing tariffs, changes in enforcement practices of regulators or penalties imposed for non-compliance with existing laws or regulations may result in substantial additional expense. Adverse developments in tax laws, credits or other incentives including changes in legislation, administrative interpretations or judicial determinations could result in modifications to business models or otherwise negatively affect the Companies’ financial condition, results of operations and/or cash flows. Recent legislative and regulatory changes that are impacting or could impact the Companies include legislation enacted in Virginia in April 2023, the IRA, the VCEA, the 2017 Tax Reform Act, the OBBBA and tariffs imposed on various components required for construction of the CVOW Commercial Project or imported solar panels by the U.S. government in 2025 and 2018, respectively. The Companies have been and may continue to be or become subject to legal proceedings and governmental investigations and examinations. The Companies may from time to time be subject to various legal proceedings and governmental investigations and examinations. For example, Dominion Energy, following the SCANA Combination, was subject to numerous federal and state legal proceedings and governmental investigations relating to the decision of SCANA and DESC to abandon construction at the NND Project. Dominion Energy spent substantial amounts of time and money defending these lawsuits and proceedings and on related investigations. In addition, juries have demonstrated a willingness to grant large awards in certain cases, including personal injury claims. Accordingly, actual costs incurred may differ from insured or reserved amounts and may not be recoverable, in whole or in part, by insurance or in rates from customers. The outcome of these or future legal proceedings, investigations and examinations, including settlements, may adversely affect the Companies’ financial condition, results of operation and/or cash flows.Construction RisksThe construction of the CVOW Commercial Project involves significant risks. The CVOW Commercial Project is a large-scale, complex project. Significant delays or cost increases, or an inability to recover certain project costs, could have an adverse effect on the Companies’ financial condition, cash flows and results of operations. If the Companies are unable to complete the construction of the CVOW Commercial Project or decide in the future to delay or cancel the project, the Companies may not be able to recover all or a portion of their investment in the project and may incur substantial cancellation payments under existing contracts or other substantial costs associated with any such delay or cancellation. The Companies’ ability to complete the CVOW Commercial Project within the currently proposed timeline, or at all, and consistent with current cost estimates is subject to various risks and uncertainties, certain of which are beyond the Companies’ control. The construction of the CVOW Commercial Project is dependent on the Companies’ ability to maintain various local, state and federal permits, rights of way and other regulatory approvals and authorizations, including Virginia Commission approval for rider recovery of project costs. In addition, determination of costs allocated by PJM to the project for network upgrades remains subject to change, even after the CVOW Commercial Project is placed in service, as such amounts are driven by the ultimate costs of development of the transmission lines and related facilities that PJM determines is necessary to support various generation facilities within PJM, including the CVOW Commercial Project. The final determination of such costs is outside the control of the CVOW Commercial Project and may be impacted by events affecting the developers of such transmission lines, including any increases in costs for permitting, inflation, tariffs, supply chain constraints or other factors affecting the ultimate costs to complete such facilities. Also, the CVOW Commercial Project may become the subject of litigation or other forms of intervention by third parties, including stakeholders or advocacy groups, that may seek to challenge permits or other regulatory approvals received, including for routing of onshore electric transmission, which could delay or increase the cost of the project. For example, the estimated total project cost and expected placed in service date for the CVOW Commercial Project were negatively impacted by projected installation timeline changes arising from the temporary suspension of work from the BOEM Director’s Order issued in December 2025 until a preliminary injunction was granted by the U.S District Court for the Eastern District of Virginia in January 2026, which allowed work to resume. Any additional suspension of work orders could result in further changes to the estimated total project cost and/or the timeframe turbines are expected to be placed in service. The construction of the CVOW Commercial Project is also dependent on the ability of certain key suppliers and contractors to timely satisfy their obligations under contracts entered into or expected to be entered into. Given the unique equipment and expertise required for this project, the Companies may not be able to remedy in a timely and cost-effective manner, if at all, any failure by one or more of these suppliers or contractors to timely satisfy their contractual obligations. Certain of the fixed price contracts for major offshore construction and equipment components are denominated in Euros and Danish kroner. In May 2022, Virginia Power entered into forward purchase agreements with a notional amount of approximately €3.2 billion. Accordingly, to the extent the instruments do not effectively hedge the Companies’ exposure to these currencies, including by default of the counterparty, adverse fluctuations in the applicable exchange rates would likely adversely affect the cost of the CVOW Commercial Project. Similarly, adverse fluctuations in the price of fuel used for transportation and installation, would likely adversely affect the overall costs to construct the project. In 26 addition, the cost of the CVOW Commercial Project could be adversely affected by the impact of applicable tariffs, including any potential impact of Section 232 investigations. The Companies’ ability to recover unforeseen cost increases associated with construction of the CVOW Commercial Project is potentially limited which could negatively impact the Companies’ future financial condition, results of operations and/or cash flows. In accordance with the Virginia Commission’s December 2022 order, the Companies are subject to a cost sharing mechanism in which Virginia Power will be eligible to recover 50% of such incremental costs which fall between $10.3 billion and $11.3 billion with no recovery of such incremental costs which fall between $11.3 billion and $13.7 billion. There is no cost sharing mechanism for any total construction costs in excess of $13.7 billion, the recovery of which would be determined in a future Virginia Commission proceeding. In addition, the order includes enhanced performance reporting provisions for the operation of the CVOW Commercial Project. To the extent the net annual net capacity factor is below 42%, as determined on a three-year rolling average, Virginia Power is required to provide detailed explanation of the factors contributing to any shortfall to the Virginia Commission which could determine in a future proceeding a remedy for incremental costs incurred associated with any deemed unreasonable or imprudent actions of Virginia Power. Any such action by the Virginia Commission could adversely impact the Companies’ future financial condition, results of operations and/or cash flows.The Companies’ ability to invest the significant financial resources necessary for the CVOW Commercial Project is dependent on the Companies’ access to the financial markets in a timely and cost-effective manner. A decline in the Companies’ credit worthiness, an unfavorable market reputation of either the Companies or their industry or general market disruptions could adversely impact financing costs and increase the overall cost of the project. In October 2024, Virginia Power completed the sale of a 50% noncontrolling interest to Stonepeak. Virginia Power and Stonepeak will each contribute 50% of the remaining capital necessary to fund construction of the CVOW Commercial Project provided the total project cost, excluding financing costs, is less than $11.3 billion. For capital funding necessary, if any, for total project costs, excluding financing costs, of $11.3 billion through $13.7 billion, Stonepeak will have the option to make additional capital contributions. If Stonepeak elects to make additional capital contributions for project costs, excluding financing costs, in excess of $11.3 billion, if any, Virginia Power shall contribute between 67% and 83% of such capital with Stonepeak contributing the remainder. To the extent that Stonepeak elects not to make such contributions, Virginia Power shall receive an increase in its ownership percentage of OSWP for any contributed capital based on a tiered unit price for membership interests in OSWP as set forth in the agreement. Virginia Power and Stonepeak have the right to provide capital contributions for any total project costs, excluding financing costs, in excess of $13.7 billion. The inability of Stonepeak to satisfy its share of funding requirements in a timely manner could have a negative effect on the Companies. In addition, Stonepeak’s interests and objectives may differ from those of the Companies and, accordingly, disputes may arise that may result in delays, litigation or operational impasses.The construction of the CVOW Commercial Project involves the use of evolving turbine technology and takes place in a marine environment, which presents unique challenges and requires the use of a specialized workforce and specialized equipment. In addition, the timely installation of the turbines is dependent on the continued availability of a Jones Act compliant vessel currently under a 20-month lease agreement which commenced in September 2025 between Virginia Power and an affiliated entity.The timeline for construction of the CVOW Commercial Project may also be negatively impacted by severe weather events or marine wildlife, including migration patterns of endangered and protected species, both of which are outside of the control of the Companies and their contractors.The Companies’ infrastructure build and expansion plans often require regulatory approval, including environmental permits, before commencing construction and completing projects. The Companies may not complete the facility construction, conversion or other infrastructure projects that they commence, or they may complete projects on materially different terms, costs or timing than initially estimated or anticipated, and they may not be able to achieve the intended benefits of any such project, if completed. A number of large- and small-scale projects have been announced, including the CVOW Commercial Project, electric transmission lines, facility expansions or renewed licensing, conversions and other infrastructure developments or construction. Additional projects may be considered in the future, such as those necessary to meet the projected demand growth driven by data centers and artificial intelligence, including to address the concentration of data centers primarily in Loudoun County, Virginia. The Companies compete for projects with companies of varying size and financial capabilities, including some that may have competitive advantages. Commencing construction on announced and future projects may require approvals from applicable state and federal agencies, and such approvals could include mitigation costs. Projects may not be able to be completed on time or in accordance with estimated costs as a result of weather conditions, need for new land and right of ways, delays in obtaining or failure to obtain or maintain regulatory and other, including PJM, approvals, changes in laws or regulations or other regulatory or administrative action or inaction, the outcome of legal proceedings and judicial actions, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, concerns raised during stakeholder engagement, a decline in the credit strength of counterparties or vendors, inflation, the impact of applicable tariffs or other factors beyond the Companies’ control. As discussed above, the CVOW Commercial Project experienced a temporary suspension of work which impacted the expected project cost and timeline. In addition, Dominion Energy has been involved with other projects which have experienced certain delays in obtaining and maintaining permits necessary for construction along with construction delays due to judicial actions which impacted the cost and schedule such as the Atlantic Coast Pipeline Project and ultimately led to its cancellation in July 2020. Construction projects necessary to maintain reliability and meet increasing demand may include the construction of dispatchable natural gas generation facilities which may be subject to additional challenges raised by advocacy groups which could adversely impact the timely receipt and maintenance of regulatory 27 approvals. Even if facility construction, expansion, electric transmission line, conversion and other infrastructure projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of the Companies following completion of the projects may not meet expectations. If these infrastructure projects are not completed, are delayed or are subject to unanticipated costs, certain costs may not be approved for recovery or otherwise be recoverable through regulatory mechanisms that may be available. Further, the Companies could become obligated to make delay or termination payments or become obligated for other damages under contracts, could experience the loss or reduction of tax credits or incentives, the inability to transfer related tax credits, or delayed or diminished returns, and could be required to write off all or a portion of their investments in such projects. Start-up and operational issues can arise in connection with the commencement of commercial operations at the Companies’ facilities. Such issues may include failure to meet specific operating parameters, which may require adjustments to meet or amend these operating parameters. Additionally, the Companies may not be able to timely and effectively integrate the projects into their operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Any delays in the timely completion of necessary PJM interconnection projects for new electric generation facilities under development by Virginia Power, including the CVOW Commercial Project, may result in project delays and/or capacity constraints if, and until, such projects are completed. In addition, any increase in network upgrade costs allocated to any such new Virginia Power generation project, or delay in the completion of such necessary upgrades could, respectively, increase the associated project development costs and/or delay the project’s ability to participate in PJM’s capacity market as a capacity resource. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Any of these or other factors could adversely affect the Companies’ ability to realize the anticipated benefits from the facility construction, electric transmission line, expansion, conversion and other infrastructure projects. The development, construction and commissioning of several large-scale infrastructure projects simultaneously involves significant execution risk. To achieve Dominion Energy’s commitment to net zero emissions by 2050 and comply with the requirements of the VCEA and projected demand while maintaining reliability, the Companies are currently simultaneously developing or constructing several electric generation projects, including subsequent license renewal projects at nuclear facilities in Virginia and South Carolina, the CVOW Commercial Project, the Chesterfield Energy Reliability Center, several electric transmission projects and various solar projects. Several of the Companies’ key projects are increasingly large-scale, complex and being constructed in constrained geographic areas or in unfamiliar environments such as the marine environment for the CVOW Commercial Project. The advancement of the Companies’ infrastructure projects is also affected by the interventions, litigation or other activities of stakeholder and advocacy groups, some of which oppose natural gas-related and energy infrastructure projects. For example, certain stakeholder groups oppose solar farms due to the increasing quantities of land tracts required for these facilities. Similarly, certain stakeholder groups oppose new natural gas generation facilities, such as the Chesterfield Energy Reliability Center. Given that these projects provide the foundation for the Companies’ strategic growth plan and are necessary to meet projected demand, if the Companies are unable to obtain or maintain the required regulatory and other, including PJM, approvals, develop the necessary technical expertise, allocate and coordinate sufficient resources, adhere to budgets and timelines, effectively handle public outreach efforts, including its commitment to fair treatment, community involvement and effective communication, or otherwise fail to successfully execute the projects, there could be an adverse impact to the Companies’ financial position, results of operations and cash flows. Failure to comply with regulatory approval conditions or an adverse ruling in any future litigation could adversely affect the Companies’ ability to execute their business plan. The Companies are dependent on their contractors for the successful and timely completion of large-scale infrastructure projects. The construction of such projects is expected to take several years, is typically confined within a limited geographic area or difficult environments and could be subject to delays, supply chain disruption, availability of critical components, cost overruns, inflation, labor disputes or shortages and other factors that could cause the total cost of the project to exceed the anticipated amount . Any of these events could adversely affect the Companies’ financial condition, results of operations and/or cash flows.Further, an inability to obtain financing or otherwise provide liquidity for the projects on acceptable terms could negatively affect the Companies’ financial condition, cash flows, the projects’ anticipated financial results and/or impair the Companies’ ability to execute the business plan for the projects as scheduled.Environmental Risks Compliance with federal and/or state requirements imposing limitations on GHG emissions or efficiency improvements, as well as Dominion Energy’s commitment to achieve net zero carbon and methane emissions by 2050, may result in significant compliance costs, could result in certain of the Companies’ existing electric generation units being uneconomical to maintain or operate and may depend upon technological advancements which may be beyond the Companies’ control. The VCEA establishes renewable energy and CO 2 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 28 put directives in place to start the withdrawal of Virginia from RGGI. In December 2023, the withdrawal took effect. Cost recovery for these initiatives will require approval by the Virginia Commission which may be denied or altered to the detriment of the Companies. For example, the Companies recorded charges in 2022 associated with the Virginia Commission’s approval in June 2022 of Virginia Power’s petition that RGGI compliance costs incurred and unrecovered through July 2022 be recovered through existing base rates in effect during the period incurred. In addition, permitting and other project execution challenges may hinder Virginia Power’s ability to meet the requirements of the VCEA. The Companies could face similar risks if there is further legislation at the federal and/or state level mandating additional limitations on GHG emissions or requiring additional efficiency improvements. Dominion Energy is working to achieve net zero carbon and methane Scope 1 and Scope 2 emissions and material categories of Scope 3 emissions by 2050. To meet this commitment, the Companies expect to construct new electric generation facilities, including renewable facilities such as wind and solar, and have obtained or plan to seek the extension of operating licenses for the Companies’ nuclear generation facilities. The Companies also need to depend on technological improvements not currently in commercial development. Additionally, actions taken in furtherance of Dominion Energy’s net zero commitment may impact existing generation facilities, including as a result of fuel switching and/or the retirement of high-emitting generation facilities and their potential replacement with lower-emitting generation facilities. Further, the ability to realize this commitment will require the Companies to be able to obtain significant financing. These efforts will require approvals from various regulatory bodies for the siting and construction of such new facilities and a determination by the applicable state commissions that costs related to the construction are prudent. Given these and other uncertainties associated with the implementation of Dominion Energy’s net zero commitment, the Companies cannot estimate the aggregate effect of future actions taken in furtherance of this commitment on their results of operations or financial condition or on their customers. However, such actions could render additional existing generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect the Companies’ financial condition, results of operations and/or cash flows. There are also potential negative impacts on Dominion Energy’s natural gas business from its net zero emissions commitment as well as federal or state GHG regulations which may require further GHG emission reductions from the natural gas sector which, in addition to resulting in increased costs, could affect demand for natural gas. Additionally, GHG requirements could result in increased energy conservation and adoption of renewable products, which could impact the natural gas business. Dominion Energy’s renewable natural gas operations could be negatively impacted by factors affecting livestock owned by third-parties, changes in demand for renewable natural gas and/or changes in laws and regulations affecting such facilities. The Companies’ operations and construction activities are subject to a number of environmental laws and regulations which impose significant compliance costs. The Companies’ operations and construction activities are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. Compliance with these legal requirements requires the Companies to commit significant capital toward permitting, emission fees, environmental monitoring, installation and operation of environmental control equipment and purchase of allowances and/or offsets. Additionally, the Companies could be responsible for expenses relating to remediation and containment obligations, including at sites where they have been identified by a regulatory agency as a potentially responsible party. Expenditures relating to environmental compliance have been significant in the past, and the Companies expect that they will remain significant in the future. Certain facilities have become uneconomical to operate and have been shut down, converted to new fuel types or sold. These types of events could occur again in the future. The Companies expect that existing environmental laws and regulations may be revised and/or new laws may be adopted, including regulation of GHG emissions, which could have an adverse impact on the Companies’ business. Risks relating to regulation of GHG emissions from existing fossil fuel-fired electric generating units are discussed in more detail above and below. In addition, further regulation of air quality and GHG emissions under the CAA may be imposed on the natural gas sector. The Companies are also subject to federal water and waste regulations, including regulations concerning cooling water intake structures, coal combustion by-product handling and disposal practices, wastewater discharges from steam electric generating stations, management and disposal of hydraulic fracturing fluids and the potential further regulation of polychlorinated biphenyls. Compliance costs cannot be estimated with certainty due to the inability to predict the requirements and timing of implementation of any new or changing environmental rules or regulations. Other factors which affect the ability to predict future environmental expenditures with certainty include the difficulty in estimating clean-up costs and quantifying liabilities under environmental laws that impose joint and several liabilities on all responsible parties. However, such expenditures, if significant, could make the Companies’ facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect the Companies’ financial condition, results of operations and/or cash flows. The Companies are subject to risks associated with the disposal and storage of coal ash. The Companies historically produced and continue to produce coal ash, or CCRs, as a by-product of their coal-fired generation operations. The ash is stored and managed in impoundments (ash ponds) and landfills located at 11 different facilities, including eight at Virginia Power. The EPA has issued regulations concerning the management and storage of CCRs, which Virginia has adopted. These CCR regulations require the Companies to make additional capital expenditures and increase operating and maintenance expenses. In addition, the Companies will incur expenses and other costs associated with closing, corrective action and ongoing monitoring of certain ash ponds and landfills. The EPA’s May 2024 final rule regulates inactive surface impoundments located at the retired generation stations that contained CCR and liquids after 2015, and certain other inactive or previously closed surface impoundments, landfills or other areas that contain accumulations of CCR. The Companies believe that they may have inactive or closed units or areas that could be subject to the final rule at up to 29 19 different locations, including 12 at Virginia Power. The Companies also may face litigation concerning their coal ash facilities. Further, while the Companies believe that they operate their ash ponds and landfills in compliance with applicable state safety regulations, a release of coal ash with a significant environmental impact could result in significant remediation costs, civil and/or criminal penalties, claims, litigation, increased regulation and compliance costs, and reputational damage, and could impact the financial condition of the Companies.Operational RisksThe Companies’ financial performance and condition can be affected by changes in the weather, including the effects of global climate change. Fluctuations in weather can affect demand for the Companies’ services. For example, milder than normal weather can reduce demand for electricity and gas distribution services. In addition, severe weather or acts of nature, including hurricanes, winter storms, wildfires, earthquakes, floods and other natural disasters can stress systems, disrupt operation of the Companies’ facilities and cause service outages, production delays and property damage that require incurring additional expenses. Changes in weather conditions can result in reduced water levels or changes in water temperatures that could adversely affect operations at some of the Companies’ power stations. In addition, sustained changes in weather patterns could result in decreased output at the Companies’ renewable generation facilities. Furthermore, the Companies’ operations could be adversely affected and their physical plant placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and, for operations located on or near coastlines, a change in sea level or sea temperatures. Due to the location of the Companies’ electric utility service territories and a number of its other facilities in the eastern portions of the states of South Carolina, North Carolina and Virginia which are frequently in the path of hurricanes, the Companies experience the consequences of these weather events to a greater degree than many industry peers. Hostile cyber intrusions could severely impair the Companies’ operations, lead to the disclosure of confidential information, damage the reputation of the Companies and otherwise have an adverse effect on the Companies’ business. The Companies own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run the Companies’ facilities are not completely isolated from external networks. In addition, the Companies’ operations utilize third-party vendors, which may also be subject to cyber security intrusions. There appears to be an increasing level of activity, sophistication and maturity of threat actors, in particular nation state actors, that wish to disrupt the U.S. bulk power system and the U.S. gas transmission or distribution system. Such parties could view the Companies’ computer systems, software or networks as attractive targets for cyber attack. For example, malware has been designed to target software that runs the nation’s critical infrastructure such as power transmission grids and gas pipelines. Emerging technologies, such as advanced forms of automation and artificial intelligence, which are subject to limited government oversight and regulations and evolve rapidly, may result in an increase in the frequency and sophistication of cyber attacks. The Companies’ businesses also require that they and their vendors collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss. A successful cyber attack through third-party or insider action on the systems that control the Companies’ electric generation, electric transmission, electric distribution or gas distribution assets could severely disrupt business operations, preventing the Companies from serving customers or collecting revenues. The breach of certain business systems could affect the Companies’ ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to the Companies’ reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data at the Companies or one of their vendors could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. If a significant breach were to occur, the reputation of the Companies also could be adversely affected. While the Companies maintain property and casualty insurance, along with other contractual provisions, that may cover certain damage caused by potential cyber incidents, all damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a significant cyber incident could adversely affect the Companies’ business, financial condition, results of operations and/or cash flows. The Companies’ financial results can be adversely affected by various factors driving supply and demand for electricity and related services. Demand for the Companies’ services can be driven by changing populations within its utility service territories, significant new commercial or industrial customers or other changes in consumer habits. For example, data centers in Virginia Power’s service territory, particularly in Loudoun County, Virginia, have been a source of significant increase in demand which is expected to continue over the next decade. Technological advances may enhance energy efficiency in end-use devices, including lighting, furnaces and electric heat pumps and could lead to declines in per capita energy consumption. Additionally, regulatory and/or legislative bodies could introduce requirements and/or incentives to reduce energy consumption. Consumer demand for the Companies’ services may also be impacted by any price increases, including those driven by factors beyond the Companies’ control such as inflation or increased prices in natural gas. Further, Virginia Power’s business model is premised upon the cost efficiency of the production, transmission and distribution of large-scale centralized utility generation. However, advances in distributed generation technologies, such as solar cells, gas microturbines, battery storage and fuel cells, may make these alternative generation methods competitive with large-scale utility generation, and change how customers acquire or use the Companies’ services. The widescale implementation of alternative generation methods could negatively impact the 30 reliability of the Companies’ electric grid and/or result in significant costs to enhance the grid. Virginia Power has an exclusive franchise to serve retail electric customers in Virginia. However, Virginia’s Retail Access Statutes allow certain electric generation customers exceptions to this franchise. As market conditions change, Virginia Power’s customers may further pursue exceptions and Virginia Power’s exclusive franchise may erode. Increased energy demand or significant accelerated growth in demand due to new data centers, expanded use of artificial intelligence, widespread adoption of electric vehicles or other customer changes could require enhancements to the Companies’ infrastructure. As discussed above, the ability of the Companies to construct new facilities is dependent upon factors outside of their control, including obtaining and maintaining regulatory approvals and environmental and other permits. Any delays in, or inability to complete, construction or integration of new facilities or expand and/or renew existing facilities could have an adverse effect on the Companies’ financial results. In addition, purchased power from PJM or others may be from generation sources which emit more emissions than the Companies’ facilities, which could negatively impact Dominion Energy’s ability to meet its commitment to net zero emissions. Alternatively, reduced energy demand or significantly slowed growth in demand due to customer adoption of energy efficient technology, conservation, distributed generation, regional economic conditions or the impact of additional compliance obligations, unless substantially offset through regulatory cost allocations, could adversely impact the value of the Companies’ business activities. The Companies’ operations are subject to operational hazards, equipment failures, supply chain disruptions and personnel issues which could negatively affect the Companies. Operation of the Companies’ facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply, pipeline integrity or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental policies or interventions, changes to the environment and performance below expected levels. The Companies’ businesses are dependent upon sophisticated information technology systems and network infrastructure, some of which are provided by third-party vendors under service contracts, the failure of which could prevent them from accomplishing critical business functions. Because the Companies’ transmission facilities, pipelines and other facilities are interconnected with those of third parties, the operation of their facilities and pipelines could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.Operation of the Companies’ facilities below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of the Companies’ facilities and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the Companies’ business. Unplanned outages typically increase the Companies’ operation and maintenance expenses and may reduce their revenues as a result of selling less output or may require the Companies to incur significant costs as a result of operating higher cost units or obtaining replacement output from third parties in the open market to satisfy forward energy and capacity or other contractual obligations. Moreover, if the Companies are unable to perform their contractual obligations, penalties or liability for damages could result. In addition, there are many risks associated with the Companies’ principal operations including nuclear accidents, fires, explosions, uncontrolled release of natural gas and other environmental hazards, pole strikes, electric contact cases, the collision of third party equipment with pipelines and avian and other wildlife impacts. Such incidents could result in loss of human life or injuries among employees, customers or the public in general, environmental pollution, damage or destruction of facilities or business interruptions and associated public or employee safety impacts, loss of revenues, increased liabilities, heightened regulatory scrutiny and reputational risk. Further, the location of electric generation, transmission, substations and distribution facilities or natural gas distribution facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks.The Companies conduct certain operations through partnership arrangements involving third-party investors which may limit the Companies’ operational flexibility or result in an adverse impact on its financial results. Certain of the Companies’ operations, including the CVOW Commercial Project and Valley Link, are conducted through entities subject to partnership arrangements under which Dominion Energy or Virginia Power has significant influence but does not control the operations of such entities or in which Dominion Energy or Virginia Power’s control over such entities may be subject to certain rights of third-party investors. Accordingly, while Dominion Energy or Virginia Power may have a certain level of control or influence over these entities, it may not have unilateral, or any, control over the day-to-day operations of these entities or over decisions that may have a material financial impact on the partnership participants, including the Companies. In each case such partnership arrangements operate in accordance with their respective governance documents, and the Companies are dependent upon third parties satisfying their respective obligations, including, as applicable, funding of their required share of capital expenditures. Such third-party investors have their own interests and objectives which may differ from those of the Companies and, accordingly, disputes may arise amongst the owners of such partnership arrangements that may result in delays, litigation or operational impasses. The Companies may be materially adversely affected by negative publicity or the inability of Dominion Energy to meet its stated commitments. From time to time, political and public sentiment may result in a significant amount of adverse press coverage and other adverse public statements affecting the Companies. Public sentiment may be affected by certain events outside of the Companies’ control, such as outages caused by severe weather events or increases in approved rates to recover higher than anticipated market rates for fuel used in electric generation. Any failure by Dominion Energy to realize its commitments to achieve net zero carbon and methane emissions by 2050, enhance the customer experience or other long-term goals could lead to adverse press coverage and other adverse 31 public statements affecting the Companies. The ability to comply with some or all of Dominion Energy’s voluntary commitments may be outside of its control. For example, the ability to reduce emissions while meeting the Companies’ increasing demand growth is expected to be dependent on the technological and economic feasibility of large-scale battery storage, carbon capture and storage, small modular reactors, hydrogen and/or other clean energy technologies. Dominion Energy is also dependent on the actions of third parties to meet its commitment regarding Scope 2 and Scope 3 emissions. If downstream customers or upstream suppliers do not sufficiently reduce their GHG emissions, Dominion Energy may not achieve its net zero emissions commitment. In addition, while the Atlantic Coast Pipeline Project was cancelled in July 2020 and the legal proceedings and governmental investigations relating to the abandonment of the NND Project have been resolved, there is a risk that lingering negative publicity may continue. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims as well as adverse outcomes. Addressing any adverse publicity, governmental scrutiny or enforcement or other legal proceedings is time consuming and expensive and, regardless of the factual basis for the assertions being made, can have a negative impact on the reputation of the Companies, on the morale and performance of their employees and on their relationships with their respective regulators, customers and commercial counterparties. It may also have a negative impact on the Companies’ ability to take timely advantage of various business and market opportunities. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have an adverse effect on the Companies’ business, financial condition, results of operations and/or cash flows.Dominion Energy’s nonregulated generation business operates in a challenging market, which could adversely affect its results of operations and future growth. The success of Dominion Energy’s contracted generation business depends upon favorable market conditions including the ability to sell power at prices sufficient to cover its operating costs. Dominion Energy operates in active wholesale markets that expose it to price volatility for electricity and nuclear fuel as well as the credit risk of counterparties. Dominion Energy attempts to manage its price risk by entering into long-term power purchase agreements with customers as well as hedging transactions, including short-term and long-term fixed price sales and purchase contracts. The failure of Dominion Energy to maintain, renew or replace its existing long-term contracts on similar terms or with counterparties with similar credit profiles could result in a loss of revenue and/or decreased earnings and cash flows for Dominion Energy. In these wholesale markets, the spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. In many cases, the next unit of electricity supplied would be provided by generating stations that consume fossil fuels, primarily natural gas. Consequently, the open market wholesale price for electricity generally reflects the cost of natural gas plus the cost to convert the fuel to electricity. Therefore, changes in the price of natural gas generally affect the open market wholesale price of electricity. To the extent Dominion Energy does not enter into long-term power purchase agreements or otherwise effectively hedge its output, these changes in market prices could adversely affect its financial results. Dominion Energy purchases nuclear fuel primarily under long-term contracts. Dominion Energy is exposed to nuclear fuel cost volatility for the portion of its nuclear fuel obtained through short-term contracts or on the spot market, including as a result of market supply shortages. Nuclear fuel prices can be volatile and the price that can be obtained for power produced may not change at the same rate as nuclear fuel costs, thus adversely impacting Dominion Energy’s financial results. In addition, in the event that any of the contracted generation facilities experience a forced outage, Dominion Energy may not receive the level of revenue it anticipated.War, acts and threats of terrorism, intentional acts and other significant events could adversely affect the Companies’ operations. The Companies cannot predict the impact that any future terrorist attacks or retaliatory military or other action may have on the energy industry in general or on the Companies’ businesses in particular. Any such future attacks or retaliatory action may adversely affect the Companies’ operations in a variety of ways, including by disrupting the power, fuel and other markets in which the Companies operate or requiring the implementation of additional, more costly security guidelines and measures. The Companies’ infrastructure facilities, including nuclear facilities and projects under construction, could be direct targets or indirect casualties of an act of terror or other physical attack. Any physical compromise of the Companies’ facilities could adversely affect the Companies’ ability to generate, purchase, transmit or distribute electricity, distribute natural gas or otherwise operate their respective facilities in the most efficient manner or at all. For example, in December 2022 electric utilities in North Carolina and Washington experienced physical attacks on substations with the damage causing power outages. In addition, the amount and scope of insurance coverage maintained against losses resulting from any such attack may not be sufficient to cover such losses or otherwise adequately compensate for any business disruptions that could result. Instability in financial markets as a result of terrorism, war, intentional acts, pandemic, credit crises, recession or other factors could result in a significant decline in the U.S. economy and/or increase the cost or limit the availability of insurance or adversely impact the Companies’ ability to access capital on acceptable terms, or at all. Failure to attract and retain key executive officers and an appropriately qualified workforce could have an adverse effect on the Companies’ operations. The Companies’ business strategy is dependent on their ability to recruit, retain and motivate employees. The Companies’ key executive officers include the CEO, CFO and presidents and those responsible for financial, operational, legal, regulatory, accounting, tax, information technology and cybersecurity functions. Competition for skilled management employees in these areas of the Companies’ business operations is high. Certain events, such as an aging workforce, mismatch of skill set, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base and the length of time required for skill development. In this case, costs, including costs for contractors to replace employees, 32 productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees, or future availability and cost of contract labor may adversely affect the ability to manage and operate the Companies’ business. In addition, certain specialized knowledge is required of the Companies’ technical employees for construction and operation of transmission, generation and distribution assets. An inability to attract and retain these employees could adversely affect the Companies’ business and future operating results.Nuclear Generation Risks The Companies have substantial ownership interests in and operate nuclear generating units; as a result, each may incur substantial costs and liabilities. The Companies’ nuclear facilities are subject to operational, environmental, health and financial risks such as the on-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, limitations on the amounts and types of insurance available, potential operational liabilities and extended outages, the costs of replacement power, the costs of maintenance and the costs of securing the facilities against possible terrorist attacks. The Companies maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that future decommissioning costs could exceed amounts in the decommissioning trusts and/or damages could exceed the amount of insurance coverage. If the Companies’ decommissioning trust funds are insufficient, and they are not allowed to recover the additional costs incurred through insurance or regulatory mechanisms, their results of operations could be negatively impacted.The Companies’ nuclear facilities are also subject to complex government regulation which could negatively impact their financial condition, results of operations and/or cash flows. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit, or take some combination of these actions, depending on its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could require the Companies to make substantial expenditures at their nuclear plants. In addition, although the Companies have no reason to anticipate a serious nuclear incident at their plants, if an incident did occur, it could materially and adversely affect their results of operations and/or financial condition. A major incident at a nuclear facility anywhere in the world, such as the nuclear events in Japan in 2011, could cause the NRC to adopt increased safety regulations or otherwise limit or restrict the operation or licensing of domestic nuclear units.Financial, Economic and Market RisksChanging rating agency requirements could negatively affect the Companies’ growth and business strategy. In order to maintain appropriate credit ratings to obtain needed credit at a reasonable cost in light of existing or future rating agency requirements, the Companies may find it necessary to take steps or change their business plans in ways that may adversely affect their growth and earnings. A reduction in the Companies’ credit ratings, including due to a change in rating methodologies, could result in an increase in borrowing costs, loss of access to certain markets, or both, thus adversely affecting operating results and could require the Companies to post additional collateral in connection with some of its price risk management activities. An inability to access financial markets and, in the case of Dominion Energy, obtain cash from subsidiaries could adversely affect the execution of the Companies’ business plans. The Companies rely on access to short-term money markets and longer-term capital markets as significant sources of funding and liquidity for business plans with increasing capital expenditure needs, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities. Deterioration in the Companies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or declines in market reputation either for the Companies or their industry in general, or general financial market disruptions outside of the Companies’ control could increase their cost of borrowing or restrict their ability to access one or more financial markets. Market disruptions could stem from general market disruption due to general credit market or political events, the reform or replacement of benchmark rates, the failure of financial institutions on which the Companies rely or the bankruptcy of an unrelated company. Increased costs and restrictions on the Companies’ ability to access financial markets, including as a result of compliance with certain provisions of the OBBBA, may be severe enough to affect their ability to execute their business plans as scheduled.Dominion Energy is a holding company that conducts all of its operations through its subsidiaries. Accordingly, Dominion Energy’s ability to execute its business plan is further subject to the earnings and cash flows of its subsidiaries and the ability of its subsidiaries to pay dividends or advance or repay funds to it, which may, from time to time, be subject to certain contractual restrictions or restrictions imposed by regulators. Market performance, interest rates and other changes may decrease the value of the Companies’ decommissioning trust funds and Dominion Energy’s benefit plan assets or increase Dominion Energy’s liabilities, which could then require significant additional funding. The performance of the capital markets affects the value of the assets that are held in trusts to satisfy future obligations to decommission the Companies’ nuclear plants and under Dominion Energy’s pension and other postretirement benefit plans. The Companies have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuation and will yield uncertain returns, which may fall below expected return rates. With respect to decommissioning trust funds, a decline in the market value of these assets may increase the funding requirements of the obligations to decommission the Companies’ nuclear plants or require additional NRC-approved funding assurance.A decline in the market value of the assets held in trusts to satisfy future obligations under Dominion Energy’s pension and other postretirement benefit plans may increase the funding requirements under such plans. Additionally, changes in interest rates will affect the liabilities under Dominion Energy’s pension 33 and other postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of retirements or changes in mortality assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans. If the decommissioning trust funds and benefit plan assets are negatively impacted by market fluctuations or other factors, the Companies’ financial condition, results of operations and/or cash flows could be negatively affected. The use of derivative instruments could result in financial losses and liquidity constraints. The Companies use derivative instruments, including futures, swaps, forwards, options and FTRs, to manage commodity, interest rate and/or foreign currency exchange rate risks. The failure of a counterparty to over-the-counter derivative instruments to perform may prevent the Companies from being able to mitigate such risks. In addition, derivative instruments may require posting cash for margin requirements. The CEA requires certain over-the-counter derivatives, or swaps, to be cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, may elect the end-user exception to the CEA’s clearing requirements. The Companies have elected to exempt their swaps from the CEA’s clearing requirements. If, as a result of changes to the rulemaking process, the Companies’ derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs due to decreased market liquidity or increased margin payments. Future impairments of goodwill or other intangible assets or long-lived assets may have a material adverse effect on the Companies’ results of operations. Goodwill is evaluated for impairment annually or more frequently if an event or circumstance occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Other intangible assets and long-lived assets are evaluated for impairment on an annual basis or more frequently whenever events or circumstances indicate that an asset’s carrying value may not be recoverable. If Dominion Energy’s goodwill or the Companies’ other intangible assets or long-lived assets are in the future determined to be impaired, the applicable registrant would be required during the period in which the impairment is determined to record a noncash charge to earnings that may have a material adverse effect on its results of operations. For example, in 2022, Dominion Energy determined that its nonregulated solar generation assets within Contracted Energy were impaired. In addition, Dominion Energy recorded an aggregate $309 million after-tax charge in the fourth quarter of 2023 and first quarter of 2024 for the impairment of certain goodwill associated with the Questar Gas Transaction. Exposure to counterparty performance may adversely affect the Companies’ financial results of operations. The Companies are exposed to credit risks of their counterparties and the risk that one or more counterparties may fail or delay the performance of their contractual obligations, including but not limited to payment for services. Some of Dominion Energy’s operations are conducted through partnership arrangements, as noted above. Counterparties could fail or delay the performance of their contractual obligations for a number of reasons, including the effect of regulations on their operations. Defaults or failure to perform by customers, suppliers, contractors, joint venture partners, financial institutions or other third parties may adversely affect the Companies’ financial condition, results of operations and/or cash flows.Public health crises and epidemics or pandemics could adversely affect the Companies’ business, results of operations, financial condition, liquidity and/or cash flows. The effects of an outbreak of a pandemic, such as COVID-19, and related government responses could include extended disruptions to supply chains and capital markets, reduced labor availability and productivity and a prolonged reduction in economic activity. The effects could also have a variety of adverse impacts on the Companies, including reduced demand for energy, particularly from commercial and industrial customers, impairment of goodwill or long-lived assets and diminished ability of the Companies to access funds from financial institutions and capital markets. Certain measures or restrictions taken to control a pandemic or similar event, such as travel bans and restrictions, quarantines, shelter-in-place orders and shutdowns, may cause operational interruptions and delays in construction projects. In addition, legislative or government action, such as legislation enacted in Virginia in November 2020, may limit the Companies’ ability to collect overdue accounts or disconnect services for non-payment, which may cause a decrease in the Companies’ results of operations and cash flows.

Item 7 · Management's Discussion & Analysis

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FY 2024-12-31 (earlier)

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations MD&A discusses Dominion Energy’s results of operations, general financial condition and liquidity and Virginia Power’s results of operations. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data. Virginia Power meets the conditions to file under the reduced disclosure format, and therefore has omitted certain sections of MD&A. CONTENTS OF MD&A MD&A consists of the following information: • Forward-Looking Statements—Dominion Energy and Virginia Power • Accounting Matters—Dominion Energy • Results of Operations—Dominion Energy and Virginia Power • Segment Results of Operations—Dominion Energy • Outlook—Dominion Energy • Liquidity and Capital Resources—Dominion Energy • Future Issues and Other Matters—Dominion Energy FORWARD-LOOKING STATEMENTS This report contains statements concerning the Companies’ expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “path,” “anticipate,” “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, wildfires, climate changes and changes in water temperatures and availability that can cause outages and property damage to facilities; • The impact of extraordinary external events, such as the pandemic health event resulting from COVID-19, and their collateral consequences, including extended disruption of economic activity in the Companies ’ markets and global supply chains; • Federal, state and local legislative and regulatory developments; • Changes in or interpretations of federal and state tax laws and regulations, including those related to tax credits or other incentives; • The direct and indirect impacts of implementing recommendations resulting from the business review concluded in March 2024; • Risks of operating businesses in regulated industries that are subject to changing regulatory structures; • Changes to regulated electric rates collected by the Companies and regulated gas distribution rates collected by Dominion Energy; • Changes in rules for RTOs and ISOs in which the Companies join and/or participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models; • Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; 53 • Risks associated with entities in which the Companies share ownership with third parties, such as Stonepeak’s noncontrolling interest in the CVOW Commercial Project, including risks that result from lack of sole decision-making authority, disputes that may arise between the Companies and third party participants and difficulties in exiting these arrangements; • Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals; • The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement, intervention or litigation in such projects; • Risks and uncertainties that may impact the Companies’ ability to construct the CVOW Commercial Project within the currently proposed timeline, or at all, and consistent with current cost estimates along with the ability to recover such costs from customers; • Risks and uncertainties associated with the timely receipt of future capital contributions, including optional capital contributions, if any, from Stonepeak associated with the construction of the CVOW Commercial Project; • Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances; • Cost of environmental strategy and compliance, including those costs related to climate change; • Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities; • Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals; • Unplanned outages at facilities in which the Companies have an ownership interest; • The impact of operational hazards, including adverse developments with respect to plant safety or integrity, equipment loss, malfunction or failure, operator error and other catastrophic events; • Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; • Changes in operating, maintenance and construction costs; • The availability of nuclear fuel, natural gas, purchased power or other materials utilized by the Companies to provide electric generation, transmission and distribution and/or gas distribution services to their customers; • Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as 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, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods; • Risks and uncertainties associated with increased energy demand or significant accelerated growth in demand due to new data centers, including the concentration of data centers primarily in Loudoun County, Virginia and the ability to obtain regulatory approvals, environmental and other permits to construct new facilities in a timely manner; • The technological and economic feasibility of large-scale battery storage, carbon capture and storage, small modular reactors, hydrogen and/or other clean energy technologies; 54 • Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures; • Impacts of acquisitions, divestitures, transfers of assets to joint ventures and retirements of assets based on asset portfolio reviews; • Adverse outcomes in litigation matters or regulatory proceedings; • Counterparty credit and performance risk; • Fluctuations in the value of investments held in nuclear decommissioning trusts by the Companies and in benefit plan trusts by Dominion Energy; • Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy’s earnings and the Companies’ liquidity position and the underlying value of their assets; • Fluctuations in interest rates; • Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; • Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; • Political and economic conditions, including tariffs, inflation and deflation; • Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; and • Changes in financial or regulatory accounting principles or policies imposed by governing bodies. Additionally, other risks that 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. In the fourth quarter of 2024, the Companies recorded a net $103 million ($77 million after-tax) charge for Virginia Power’s share of costs not expected to be recovered from customers on the CVOW Commercial Project as a result of a revised total project cost estimate of approximately $10.7 billion, excluding financing costs, that reflects a revised estimate of network upgrade costs assigned by PJM to the CVOW Commercial Project and cost sharing mechanism included in the Virginia Commission’s December 2022 order. The expected total project cost reflects increases driven primarily by projections for onshore electrical interconnection costs and network upgrade costs assigned to the project by PJM, specifically incorporating consideration of PJM’s December 2024 publication of potential transmission network upgrades required for certain generation projects and related cost allocations, including those 55 attributable to the CVOW Commercial Project. Relative to Virginia Power’s November 2024 Rider OSW filing, the updated estimated total project cost reflects an approximately $0.6 billion increase for such onshore and network upgrade costs and an approximately $0.3 billion increase for increased contingency for remaining construction activities, completion of the removal of unexploded ordnance, undersea cable protection system design enhancements, commodity prices for transportation fuel, updates for sea fastener fabrication and installation and other construction and equipment supplier costs. The estimated total project cost reflects the Companies’ best estimate of the remaining construction costs, including contingency of approximately 5% on such remaining amounts. Such estimate could potentially change for items, certain of which are beyond the Companies’ control, including but not limited to actual network upgrade costs allocated by PJM, fuel for transportation and installation, the impact of applicable tariffs, if any, costs to maintain necessary permits, approvals and authorizations, ability of key suppliers and contractors to timely satisfy their obligations under existing contracts, marine wildlife and/or any severe weather events. Any additional increase in such costs in excess of the contingency included in the estimated total project cost would be subject to the cost sharing mechanisms described above and could have a material impact on the Companies’ future financial condition, results of operations and/or cash flows. See Note 10 to the Consolidated Financial Statements for additional information. Dominion Energy evaluates whether or not recovery of its regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makes various assumptions in its analyses. These analyses are generally based on: • Orders issued by regulatory commissions, legislation and judicial actions; • Past experience; • Discussions with applicable regulatory authorities and legal counsel; • Estimated construction costs; • Forecasted earnings; and • Considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events and other natural disasters and unplanned outages of facilities. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. A regulatory liability, if considered probable, will be recorded in the period such assessment is made or reversed into earnings if no longer probable. In connection with the future 2025 Biennial Review, the Companies concluded that it was not probable that Virginia Power would have earnings in excess of an expected authorized ROE of 9.70% for the period January 1, 2023 through December 31, 2024. As a result, no regulatory liability for Virginia Power ratepayer credits to customers has been recorded at December 31, 2024. 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. At December 31, 2024 and 2023, Dominion Energy’s nuclear decommissioning AROs totaled $2.6 billion and $1.9 billion, respectively. 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, 2024, a 0.25% increase in cost escalation rates would have resulted in an approximate $440 million increase in Dominion Energy’s nuclear decommissioning AROs. 56 At December 31, 2024, Dominion Energy’s AROs also include $828 million for future CCR remediation at retired generating stations and other inactive or previously closed surface impoundments, landfills or other areas in connection with the EPA’s May 2024 rule as described in Note 14. Dominion Energy developed cost estimates related to this CCR remediation, which were based on the estimated quantity of CCRs that would be discovered, if any, at locations which are subject to the regulation. The determination of how much CCR, if any, that exists at an individual location is a critical assumption in the development of the Companies’ AROs. The results of the searches of internally and externally available information regarding the existence and quantity of CCR at specific locations, as well as physical searches for CCR, may cause actual results to vary significantly from expectations. Income Taxes Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws and associated regulations involves uncertainty since tax authorities may interpret the laws differently. Ultimate resolution or clarification of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material. Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2024 and 2023, Dominion Energy had $78 million and $110 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, 2024 and 2023, Dominion Energy had established $113 million and $130 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 2024, 2023 and 2022 annual test did not result in the recognition of any goodwill impairment. 57 In general, Dominion Energy estimates the fair value of its reporting units by using a combination of discounted cash flows and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. Fair value estimates are dependent on subjective factors such as Dominion Energy’s estimate of future cash flows, the selection of appropriate discount and growth rates and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in Dominion Energy’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion Energy has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent test had been 10% lower or if the discount rate had been 0.25% higher, the resulting fair values would have still been greater than the carrying values of each of those reporting units tested, indicating that no impairment was present. In addition to the annual goodwill impairment testing described above, Dominion Energy’s calculations during the fourth quarter of 2023 and first quarter of 2024 of the expected gain or loss on the Questar Gas and East Ohio Transactions resulted in an impairment of the related goodwill totaling $238 million and $78 million, respectively, reflected in discontinued operations in Dominion Energy’s Consolidated Statements of Income. See Notes 2 and 11 to the Consolidated Financial Statements for additional information. Use of Estimates in Long-Lived Asset Impairment Testing Impairment testing for an individual or group of long-lived assets, including intangible assets with definite lives, is required when circumstances indicate those assets may be impaired. When a long-lived asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets in the case of long-lived assets and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of a market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing, expectations about the operations of the long-lived assets and the selection of an appropriate discount rate. When determining whether a long-lived asset or asset group has been impaired, management groups assets at the lowest level that has identifiable cash flows. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset or underlying assets of equity method investees, including future production and sales levels, expected fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions. 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 2024 or 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, 58 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 immediately recognized in earnings annually in the fourth quarter of each fiscal year as well as whenever a triggering event occurs that is determined to require remeasurement. Actuarial losses attributable to Dominion Energy’s rate regulated operations are deferred to regulatory assets when it is probable that regulators will permit them to be recovered from customers in future rates. Likewise, actuarial gains attributable to Dominion Energy’s rate regulated operations are deferred to regulatory liabilities when it is probable that regulators will require customer refunds or other benefits through future rates. The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality rates are critical assumptions. Dominion Energy determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of: • Expected inflation and risk-free interest rate assumptions; • Historical return analysis to determine long-term historic returns as well as historic risk premiums for various asset classes; • Expected future risk premiums, asset classes’ volatilities and correlations; • Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and • Investment allocation of plan assets. In December 2024, Dominion Energy revised its long-term strategic target asset allocation for its pension funds to 30% public equity (inclusive of both U.S. equity and non-U.S. equity), 27% fixed income and 43% other alternative investments, such as private equity, private debt and hedge fund investments. Through December 2024, Dominion Energy’s long-term strategic target asset allocation was 26% U.S. equity, 19% non-U.S. equity, 32% fixed income, 3% real assets and 20% other alternative 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 each of 2024, 2023 and 2022. For 2025, the expected long-term rate of return for the pension cost assumption is 7.35% for Dominion Energy’s plans held as of December 31, 2024. Dominion Energy calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 8.35% for each of 2024, 2023 and 2022. For 2025, the expected long-term rate of return for other postretirement benefit cost assumption is 7.35%. Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost ranged from 5.37% to 5.75% for pension plans and 5.40% to 5.74% for other postretirement benefit plans in 2024, ranged from 5.65% to 5.75% for pension plans and 5.69% to 5.70% for other postretirement benefit plans in 2023 and ranged from 3.06% to 3.19% for pension plans and 3.04% to 5.03% for other postretirement benefit plans in 2022. Dominion Energy selected a discount rate ranging from 5.84% to 59 5.87% for pension plans and 5.83% to 5.86% for other postretirement benefit plans for determining its December 31, 2024 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, 2024 was 7.00% and is expected to gradually decrease to 5.00% by 2032 and continue at that rate for years thereafter. The following table illustrates the effect on cost of changing the critical actuarial assumptions discussed above, while holding all other assumptions constant: Increase in 2024 Net Periodic Cost Change in Actuarial Assumptions Pension Benefits Other Postretirement Benefits (millions, except percentages) Discount rate (0.25)% $ 11 $ 1 Long-term rate of return on plan assets (0.25)% 26 5 Health care cost trend rate 1% N/A 8 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, 2024 by $187 million and its accumulated postretirement benefit obligation at December 31, 2024 by $23 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation at December 31, 2024 by $61 million. See Note 22 to the Consolidated Financial Statements for additional information on Dominion Energy’s employee benefit plans. New Accounting Standards See Note 2 to the Consolidated Financial Statements for a discussion of new accounting standards. RESULTS OF OPERATIONS Dominion Energy Presented below is a summary of Dominion Energy’s consolidated results: Year Ended December 31, 2024 $ Change 2023 $ Change 2022 (millions, except EPS) Net income attributable to Dominion Energy $ 2,124 $ 93 $ 2,031 $ 840 $ 1,191 Diluted EPS 2.44 0.11 2.33 1.00 1.33 Overview 2024 VS. 2023 Net income attributable to Dominion Energy increased 5%, primarily due to the absence of a charge to reflect the recognition of deferred taxes on the outside basis of stock associated with East Ohio, PSNC, Questar Gas and Wexpro meeting the classification as held for sale, a decrease in impairments associated with the East Ohio and Questar Gas Transactions, an increase in net investment earnings on nuclear decommissioning trust funds, the absence of depreciation expense associated with the East Ohio, PSNC and Questar Gas Transactions upon meeting the classification as held for sale, higher rider equity returns reflecting increased capital investments at Virginia Power, an increase in sales to electric utility customers attributable to weather and the absence of amortization associated with the 2021 Triennial Review. These increases were partially offset by the closings of the East Ohio, PSNC and Questar Gas Transactions, a charge for costs not expected to be recovered from customers on the CVOW Commercial Project, the absence of a gain and equity method earnings from the sale of Dominion Energy’s remaining noncontrolling interest in Cove Point, increased unrealized losses on economic hedging activities, lower market related impacts on pension and other postretirement plans and the impact of 2023 Virginia legislation. 2023 VS. 2022 Net income attributable to Dominion Energy increased 71%, 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 60 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, a net decrease in dismantling costs associated with the early retirement of certain electric generation facilities at Virginia Power and higher market related impacts on pension and other postretirement plans. 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. Analysis of Consolidated Operations Presented below are selected amounts related to Dominion Energy’s results of operations: Year Ended December 31, 2024 $ Change 2023 $ Change 2022 (millions) Operating revenue $ 14,459 $ 66 $ 14,393 $ 455 $ 13,938 Electric fuel and other energy-related purchases 3,614 (321 ) 3,935 224 3,711 Purchased electric capacity 74 19 55 (4 ) 59 Purchased gas 260 (25 ) 285 (141 ) 426 Other operations and maintenance 3,589 429 3,160 (205 ) 3,365 Depreciation and amortization 2,345 (235 ) 2,580 138 2,442 Other taxes 731 47 684 9 675 Impairment of assets and other charges 600 293 307 (1,094 ) 1,401 Losses (gains) on sales of assets (1 ) 26 (27 ) (439 ) 412 Other income (expense) 822 (162 ) 984 1,101 (117 ) Interest and related charges 1,887 213 1,674 672 1,002 Income tax expense 308 (260 ) 568 509 59 Net income (loss) from discontinued operations including noncontrolling interests 197 322 (125 ) (1,047 ) 922 Noncontrolling interests (53 ) (53 ) — — — An analysis of Dominion Energy’s results of operations follows: 2024 VS. 2023 Operating revenue remained substantially consistent, primarily reflecting: • A $747 million increase to recover the costs and an authorized return, as applicable, associated with Virginia Power non-fuel riders; • A $173 million increase in sales to electric utility retail customers, primarily due to an increase in cooling degree days during the cooling season ($107 million) and an increase in heating degree days during the heating season ($66 million); • A $155 million increase in sales to electric utility retail customers associated with growth; • A $124 million increase from fewer outages at Millstone, including the relative effect of fewer planned outages ($100 million) and unplanned outages ($24 million); • A $90 million net increase from electric utility customers who elect to pay market based or other negotiated rates, including settlements of economic hedges at Virginia Power prior to March 2024; • A $60 million increase in non-fuel base rates associated with the settlement of the electric base rate case in South Carolina; and • A $43 million net increase in transition service agreements primarily associated with the East Ohio, Questar Gas and PSNC Transactions. These increases were substantially offset by: • A $687 million net decrease associated with market prices affecting Millstone, including economic hedging impacts of net realized and unrealized losses on freestanding derivatives ($696 million); 61 • A $336 million net decrease in fuel-related revenue as a result of a decrease in commodity costs associated with sales to electric utility retail customers, including revenue for the deferred fuel securitization and electric utility customers who elect to pay market based or other negotiated rates and related settlements of economic hedges at Virginia Power effective March 2024; • A $184 million decrease from the combination of certain riders into base rates at Virginia Power as a result of 2023 Virginia legislation; • A $139 million decrease in sales to electric utility retail customers associated with economic and other usage factors; • A $24 million decrease in fuel-related revenue as a result of a decrease in commodity costs associated with sales to gas utility customers; and • A $22 million decrease due to one-time credits to customers associated with the 2023 Biennial Review and the electric base rate case in South Carolina. Electric fuel and other energy-related purchases decreased 8%, primarily due to lower commodity costs for electric utilities ($408 million), partially offset by an increase in the use of purchased renewable energy credits at Virginia Power ($47 million), which are offset in operating revenue and do not impact net income. Other operations and maintenance increased 14%, primarily reflecting: • A $111 million increase in certain Virginia Power expenditures which are primarily recovered through state- and FERC-regulated rates and do not impact net income; • A $78 million increase in outside services; • A $71 million increase in salaries, wages and benefits; • A $63 million increase in costs associated with the business review completed in March 2024; • A $43 million increase from the combination of certain riders into base rates as a result of 2023 Virginia legislation; • A $29 million increase in materials and supplies expense; and • A $25 million increase associated with an accrual for remediation costs at a manufactured gas plant site at Virginia Power. These increases were partially offset by: • A $48 million net decrease in outage costs due to lower outage costs at Millstone ($74 million) partially offset by higher outage costs at Virginia Power ($26 million); and • A $21 million decrease in bad debt expense. Depreciation and amortization decreased 9%, primarily reflecting: • The absence of $244 million in amortization of a regulatory asset established in the settlement of the 2021 Triennial Review; • A $67 million decrease in amortization associated with Virginia Power non-fuel riders, which is offset in operating revenue and does not impact net income; • A $35 million decrease due to revised estimated useful lives at Millstone; and • A $17 million decrease due to revised depreciation rates for Bath County. These decreases were partially offset by: • A $55 million increase in RGGI-related amortization, which is offset in operating revenue and does not impact net income; and • A $53 million increase due to various projects being placed into service. Impairment of assets and other charges increased 95%, primarily reflecting: • A charge for costs not expected to be recovered from customers on 100% of the CVOW Commercial Project ($206 million); • Charges for the impairment of certain nonregulated renewable natural gas facilities ($60 million); • A $55 million charge in connection with the electric base rate case in South Carolina primarily to write down certain materials and supplies inventory; 62 • A net increase in dismantling costs and other activities associated with certain retired electric generation facilities at Virginia Power ($55 million); • A charge in connection with a settlement of an agreement ($47 million); • An increase in charges related to the revision of AROs for Millstone Unit 1 ($39 million); and • A charge related to the write-off of certain early-stage development costs at Virginia Power ($30 million). These increases were partially offset by: • A decrease in impairments of corporate office buildings ($73 million); • The absence of a charge for an easement related to the CVOW Commercial Project for which Virginia Power will not seek recovery ($65 million); • The absence of a charge for the write-off of certain previously deferred amounts related to the cessation of certain riders effective July 2023 ($36 million); and • The absence of a charge associated with the abandonment of certain regulated solar generation and other facilities at Virginia Power ($25 million). Gains on sales of assets decreased 96%, primarily due to the absence of a gain on the transfer of certain utility property in South Carolina. Other income decreased 16%, primarily due to lower market related impacts on pension and other postretirement plans ($351 million) and an increase in charitable commitments ($58 million), partially offset by an increase in net investment gains on nuclear decommissioning trust funds ($164 million), an increase in earnings from other investments ($42 million), the absence of Dominion Energy’s share of an impairment of certain property, plant and equipment at Align RNG ($35 million) and an increase in AFUDC associated with rate-regulated projects ($35 million). Interest and related charges increased 13%, primarily reflecting: • Net issuances of long-term debt ($230 million); • Lower unrealized gains in 2024 compared to 2023 associated with freestanding derivatives ($135 million); • Charges incurred due to early debt repayments associated with the business review completed in March 2024 ($20 million); • Increased interest expense associated with rider deferrals ($13 million), which is offset in operating revenue and does not impact net income; and • Higher interest rates on commercial paper and long-term debt ($11 million). These increases were partially offset by: • A decrease in borrowings under the 364-day term loan facilities ($105 million); • Variable rate debt repaid from business review proceeds ($69 million); • A decrease in commercial paper ($30 million); and • Increased premiums received in 2024 compared to 2023 on interest rate derivatives ($17 million). Income tax expense decreased 46%, primarily due to lower pre-tax income ($128 million) and an increase in a nuclear production tax credit ($89 million). Net income from discontinued operations including noncontrolling interests increased $322 million, primarily due to the absence of charges reflecting the recognition of deferred taxes on the outside basis of stock associated with East Ohio, PSNC, Questar Gas and Wexpro meeting the classification as held for sale ($835 million), a decrease in impairments associated with the East Ohio and Questar Gas Transactions ($197 million), the absence of depreciation expense associated with the East Ohio, PSNC and Questar Gas Transactions upon meeting the classification as held for sale ($211 million), the absence of interest expense on variable rate debt secured by Dominion Energy’s interest in Cove Point ($72 million), a gain upon the closing of the Questar Gas Transaction ($42 million), the absence of an impairment charge associated with the impairment of Birdseye ($34 million), the absence of charges associated with the impairment of the Madison solar project ($19 million) and the absence of an impairment charge of certain nonregulated solar assets ($11 million), partially offset by the absence of a gain on the sale of Dominion Energy’s remaining 63 noncontrolling interest in Cove Point ($348 million), the absence of earnings from operations following the closing of the East Ohio Transaction ($299 million) and Questar Gas Transaction ($138 million), the absence of equity method earnings from the sale of Dominion Energy’s noncontrolling interest in Cove Point ($163 million), a loss on the closing of the East Ohio Transaction ($109 million), charges for employee benefit items related to the East Ohio Transaction ($33 million), a loss on the closing of the PSNC Transaction ($31 million) and higher tax expense associated with the PSNC Transaction ($16 million). Noncontrolling interests decreased $53 million, due to the 50% noncontrolling interest in the CVOW Commercial Project sold to Stonepeak in October 2024, consisting of Stonepeak’s share of a charge for costs not expected to be recovered from customers on the CVOW Commercial Project ($103 million) partially offset by its share of the remaining earnings associated with the CVOW Commercial Project subsequent to closing. 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 64 • 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 $439 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 $1.1 billion, primarily due to net investment gains in 2023 compared to net investment losses in 2022 on nuclear decommissioning trust funds ($968 million) and higher market related impacts on pension and other postretirement plans ($218 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 $509 million, primarily due to higher pre-tax income ($573 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). 65 Net income from discontinued operations including noncontrolling interests decreased $1.0 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 ($835 million), an impairment associated with the East Ohio and Questar Gas Transactions ($275 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). Virginia Power Presented below is a summary of Virginia Power’s consolidated results: Year Ended December 31, 2024 $ Change 2023 $ Change 2022 (millions) Net income attributable to Virginia Power $ 1,910 $ 458 $ 1,452 $ 340 $ 1,112 Overview 2024 VS. 2023 Net income attributable to Virginia Power increased 32%, primarily due to the absence of amortization associated with the 2021 Triennial Review, higher rider equity returns reflecting increased capital investments and an increase in sales to electric utility customers attributable to weather and other customer-related factors, partially offset by a charge for costs not expected to be recovered from customers on the CVOW Commercial Project and the impact of 2023 Virginia legislation. 2023 VS. 2022 Net income attributable to Virginia Power 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. Analysis of Consolidated Operations Presented below are selected amounts related to Virginia Power’s results of operations: Year Ended December 31, 2024 $ Change 2023 $ Change 2022 (millions) Operating revenue $ 10,235 $ 662 $ 9,573 $ (81 ) $ 9,654 Electric fuel and other energy-related purchases 2,743 (175 ) 2,918 5 2,913 Purchased electric capacity 68 22 46 — 46 Other operations and maintenance 2,237 386 1,851 (200 ) 2,051 Depreciation and amortization 1,644 (227 ) 1,871 135 1,736 Other taxes 333 35 298 (5 ) 303 Impairment of assets and other charges 292 177 115 (442 ) 557 Other income (expense) 195 64 131 131 — Interest and related charges 848 84 764 122 642 Income tax expense 408 19 389 95 294 Noncontrolling interests (53 ) (53 ) — — — 66 An analysis of Virginia Power’s results of operations follows: 2024 VS. 2023 Operating revenue increased 7%, primarily reflecting: • A $747 million increase to recover the costs and an authorized return, as applicable, associated with non-fuel riders; • A $130 million increase in sales to electric utility retail customers associated with growth; • A $124 million increase in sales to electric utility retail customers, primarily due to an increase in cooling degree days during the cooling season ($78 million) and an increase in heating degree days during the heating season ($46 million); • An $85 million increase from electric utility customers who elect to pay market based or other negotiated rates, including settlements of economic hedges prior to March 2024; and • An $18 million increase in sales to customers from non-jurisdictional solar generation facilities. These increases were partially offset by: • A $184 million decrease from the combination of certain riders into base rates as a result of 2023 Virginia legislation; • A $154 million net decrease in fuel-related revenue as a result of a decrease in commodity costs associated with sales to electric utility retail customers, including revenue for the deferred fuel securitization and electric utility customers who elect to pay market based or other negotiated rates and related settlements of economic hedges effective March 2024; • A $122 million decrease in sales to electric utility retail customers associated with economic and other usage factors; and • A $15 million decrease due to one-time credits to customers associated with the 2023 Biennial Review. Electric fuel and other energy-related purchases decreased 6%, primarily due to lower commodity costs for electric utilities ($226 million), partially offset by an increase in the use of purchased renewable energy credits ($47 million), which are offset in operating revenue and do not impact net income. Purchased electric capacity increased 48%, primarily due to new capacity contracts and changes in existing capacity contracts. Other operations and maintenance increased 21%, primarily reflecting: • A $111 million increase in certain expenditures which are primarily recovered through state- and FERC-regulated rates and do not impact net income; • A $67 million increase in salaries, wages and benefits and administrative costs; • A $48 million increase in outside services; • A $43 million increase from the combination of certain riders into base rates as a result of 2023 Virginia legislation; • A $27 million increase in materials and supplies expense; • A $26 million increase in outage costs; • A $25 million increase associated with an accrual for remediation costs at a manufactured gas plant site; and • A $15 million increase in tree trimming and vegetation management. These increases were partially offset by: • A $19 million decrease in bad debt expense. Depreciation and amortization decreased 12%, primarily reflecting: • The absence of $244 million in amortization of a regulatory asset established in the settlement of the 2021 Triennial Review; • A $67 million decrease in amortization associated with non-fuel riders, which is offset in operating revenue and does not impact net income; and • A $17 million decrease due to revised depreciation rates for Bath County. 67 These decreases were partially offset by: • A $55 million increase in RGGI-related amortization, which is offset in operating revenue and does not impact net income; and • A $42 million increase due to various projects being placed into service. Other taxes increased 12%, primarily due to higher property taxes . Impairment of assets and other charges increased $177 million, primarily reflecting: • A charge for costs not expected to be recovered from customers on 100% of the CVOW Commercial Project ($206 million); • A net increase in dismantling costs and other activities associated with certain retired electric generation facilities ($55 million); and • A charge related to the write-off of certain early-stage development costs ($30 million). These increases were partially offset by: • The absence of a charge for an easement related to the CVOW Commercial Project for which Virginia Power will not seek recovery ($65 million); • The absence of a charge for the write-off of certain previously deferred amounts related to the cessation of certain riders effective July 2023 ($36 million); and • The absence of a charge associated with the abandonment of certain regulated solar generation and other facilities ($25 million). Other income increased 49%, primarily due to an increase in AFUDC associated with rate-regulated projects ($33 million) and an increase in net investment gains on nuclear decommissioning trust funds ($29 million). Interest and related charges increased 11%, primarily due to an increase in long-term debt borrowings ($178 million) and increased interest expense associated with rider deferrals ($13 million), which is offset in operating revenue and does not impact net income, partially offset by a decrease in principal on commercial paper and intercompany borrowings with Dominion Energy ($89 million) and lower interest rates on commercial paper, long-term debt and intercompany borrowings with Dominion Energy ($23 million). Income tax expense increased 5%, primarily due to higher pre-tax income ($106 million), partially offset by a nuclear production tax credit ($89 million). Noncontrolling interests decreased $53 million, due to the 50% noncontrolling interest in the CVOW Commercial Project sold to Stonepeak in October 2024, consisting of Stonepeak’s share of a charge for costs not expected to be recovered from customers on the CVOW Commercial Project ($103 million) partially offset by its share of the remaining earnings associated with the CVOW Commercial Project subsequent to closing. 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 68 • 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). 69 SEGMENT RESULTS OF OPERATIONS Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit or loss. Presented below is a summary of contributions by Dominion Energy’s operating segments to net income (loss) attributable to Dominion Energy: Year Ended December 31, 2024 2023 2022 Net income (loss) attributable to Dominion Energy EPS (1) Net income (loss) attributable to Dominion Energy EPS (1) Net income (loss) attributable to Dominion Energy EPS (1) (millions, except EPS) Dominion Energy Virginia $ 2,011 $ 2.40 $ 1,684 $ 2.01 $ 1,905 $ 2.31 Dominion Energy South Carolina 398 0.47 377 0.45 505 0.61 Contracted Energy 359 0.43 99 0.12 188 0.23 Corporate and Other (644 ) (0.86 ) (129 ) (0.25 ) (1,407 ) (1.82 ) Consolidated $ 2,124 $ 2.44 $ 2,031 $ 2.33 $ 1,191 $ 1.33 (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: Year Ended December 31, 2024 % Change 2023 % Change 2022 Electricity delivered (million MWh) 94.5 5 % 89.9 — % 90.0 Electricity supplied (million MWh): Utility 94.6 5 90.0 — 90.2 Non-Jurisdictional 1.7 6 1.6 7 1.5 Degree days (electric distribution and utility service area): Cooling 1,928 17 1,643 (7 ) 1,765 Heating 2,969 5 2,830 (20 ) 3,555 Average electric distribution customer accounts (thousands) 2,782 1 2,752 1 2,724 Presented below, on an after-tax basis, are the key factors impacting Dominion Energy Virginia’s net income contribution: 2024 VS. 2023 Increase (Decrease) Amount EPS (millions, except EPS) Weather $ 92 $ 0.11 Customer usage and other factors (6 ) (0.01 ) Customer-elected rate impacts 63 0.08 Impact of 2023 Virginia legislation (142 ) (0.17 ) Rider equity return 349 0.42 Electric capacity (19 ) (0.02 ) Storm damage and restoration costs (12 ) (0.01 ) Planned outage costs (24 ) (0.03 ) Nuclear production tax credit 89 0.11 Sale of noncontrolling interest (50 ) (0.06 ) Depreciation and amortization (2 ) — Interest expense, net 39 0.05 Other (50 ) (0.07 ) Share dilution — (0.01 ) Change in net income contribution $ 327 $ 0.39 70 2023 VS. 2022 Increase (Decrease) Amount EPS (millions, except EPS) Weather $ (126 ) $ (0.15 ) Customer usage and other factors 123 0.15 Customer-elected rate impacts (64 ) (0.08 ) Impact of 2023 Virginia legislation (155 ) (0.19 ) Rider equity return 146 0.18 Storm damage and restoration costs 12 0.01 Depreciation and amortization (27 ) (0.03 ) Renewable energy investment tax credits (17 ) (0.02 ) Interest expense, net (38 ) (0.05 ) Other (75 ) (0.09 ) Share dilution — (0.03 ) Change in net income contribution $ (221 ) $ (0.30 ) Dominion Energy South Carolina Presented below are selected operating statistics related to Dominion Energy South Carolina’s operations: Year Ended December 31, 2024 % Change 2023 % Change 2022 Electricity delivered (million MWh) 22.0 — % 21.9 (5 ) % 23.0 Electricity supplied (million MWh) 23.1 — 23.0 (5 ) 24.1 Degree days (electric and gas distribution service areas): Cooling 855 18 725 (5 ) 767 Heating 1,078 18 917 (29 ) 1,294 Average electric distribution customer accounts (thousands) 806 2 790 2 777 Gas distribution throughput (bcf): Sales 63 (5 ) 66 (3 ) 68 Average gas distribution customer accounts (thousands) 460 4 443 4 427 Presented below, on an after-tax basis, are the key factors impacting Dominion Energy South Carolina’s net income contribution: 2024 VS. 2023 Increase (Decrease) Amount EPS (millions, except EPS) Weather $ 37 $ 0.04 Customer usage and other factors 27 0.03 Customer-elected rate impacts 4 — Base rate case & Natural Gas Rate Stabilization Act impacts 41 0.05 Capital cost rider (6 ) (0.01 ) Depreciation and amortization (12 ) (0.01 ) Interest expense, net (21 ) (0.03 ) Other (49 ) (0.05 ) Share dilution — — Change in net income contribution $ 21 $ 0.02 71 2023 VS. 2022 Increase (Decrease) Amount EPS (millions, except EPS) Weather $ (34 ) $ (0.04 ) Customer usage and other factors 11 0.01 Customer-elected rate impacts (37 ) (0.04 ) Base rate case & Natural Gas Rate Stabilization Act impacts 5 0.01 Capital cost rider (8 ) (0.01 ) Gains on sales of property (32 ) (0.04 ) Depreciation and amortization (18 ) (0.02 ) Interest expense, net (25 ) (0.03 ) Other 10 — Share dilution — — Change in net income contribution $ (128 ) $ (0.16 ) Contracted Energy Presented below are selected operating statistics related to Contracted Energy’s operations: Year Ended December 31, 2024 % Change 2023 % Change 2022 Electricity supplied (million MWh) 18.0 22 % 14.8 (17 ) % 17.8 Presented below, on an after-tax basis, are the key factors impacting Contracted Energy’s net income contribution: 2024 VS. 2023 Increase (Decrease) Amount EPS (millions, except EPS) Margin $ 103 $ 0.12 Planned Millstone outages (1)(2) 119 0.14 Unplanned Millstone outages (1) 16 0.02 Depreciation and amortization 22 0.03 Interest expense, net 14 0.02 Other (14 ) (0.02 ) Share dilution — — Change in net income contribution $ 260 $ 0.31 (1) Includes earnings impact from outage costs and lower energy margins. (2) Includes the effect of one planned refueling outage during 2024 as compared to two planned refueling outages in 2023. 2023 VS. 2022 Increase (Decrease) Amount EPS (millions, except EPS) Margin $ 83 $ 0.10 Planned Millstone outages (1) (2) (111 ) (0.13 ) Unplanned Millstone outages (1) (52 ) (0.06 ) Depreciation and amortization 14 0.02 Other (23 ) (0.04 ) Share dilution — — Change in net income contribution $ (89 ) $ (0.11 ) (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. 72 Corporate and Other Presented below are the Corporate and Other segment’s after-tax results: Year Ended December 31, 2024 2023 2022 (millions, except EPS) Specific items attributable to operating segments $ (132 ) $ 405 $ (2,386 ) Specific items attributable to Corporate and Other segment (136 ) (89 ) 860 Net income (expense) from specific items (268 ) 316 (1,526 ) Corporate and other operations: Interest expense, net (537 ) (564 ) (332 ) Equity method investments (1) (5 ) 6 138 Pension and other postretirement benefit plans 277 232 337 Corporate service company costs (79 ) (126 ) (127 ) Other (32 ) 7 103 Net income (expense) from corporate and other operations (376 ) (445 ) 119 Total net expense (644 ) (129 ) (1,407 ) EPS impact $ (0.86 ) $ (0.25 ) $ (1.82 ) (1) Includes gains associated with certain transactions of $115 million recorded in 2022. 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 2024, this primarily included a $278 million after-tax loss associated with lower market related impacts on pension and other postretirement plans, $197 million net income from discontinued operations, primarily associated with operations included in the East Ohio, PSNC and Questar Gas Transactions, including the loss on sale associated with the East Ohio and PSNC Transactions, as well as an impairment charge associated with the Questar Gas Transaction, $69 million in after-tax costs associated with the business review completed in March 2024 and a $27 million after-tax benefit for derivative mark-to-market changes. In 2023, this primarily included an $835 million charge to reflect the recognition of deferred taxes on the outside basis of stock associated with East Ohio, PSNC, Questar Gas and Wexpro meeting the classification as held for sale that reversed when the sales were completed, $710 million net income from discontinued operations, primarily associated with operations included in the East Ohio, PSNC and Questar Gas Transactions and Dominion Energy’s noncontrolling interest in Cove Point, including the gain on sale, as well as an impairment charge associated with the East Ohio and Questar Gas Transactions, a $127 million after-tax benefit for derivative mark-to-market changes, a $69 million after-tax charge associated with the impairment of a corporate office building and a $27 million after-tax benefit for higher market related impacts on pension and other postretirement plans. In 2022, this primarily included $922 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, a $251 million after-tax loss for lower market related impacts on pension and other postretirement plans and a $67 million loss associated with the sale of Hope. OUTLOOK Dominion Energy’s 2025 net income is expected to increase on a per share basis as compared to 2024 primarily from the following: • The absence of a charge for Virginia Power’s share of costs not expected to be recovered from customers on the CVOW Commercial Project; • Construction and operation of growth projects primarily in electric utility operations; • An entire year of impacts from electric base rate cases settled in North Carolina and South Carolina; • Customer growth; • Renewable natural gas projects placed into service; and • Return to normal weather. These increases are expected to be partially offset by the following: • The absence of earnings from operations following the closing of the East Ohio, PSNC and Questar Gas Transactions; 73 • An entire year of 50% noncontrolling interest in the CVOW Commercial Project attributable to Stonepeak; • An increase in depreciation and amortization expense; • An increase in interest expense; • Increased electric capacity expense; • A decrease in benefit associated with nuclear production tax credits; and • Share dilution. LIQUIDITY AND CAPITAL RESOURCES Dominion Energy depends on both cash generated from operations and external sources of liquidity to provide working capital and as a bridge to long-term financings. Dominion Energy’s material cash requirements include capital and investment expenditures, repaying short-term and long-term debt obligations and paying dividends on its common and preferred stock. Analysis of Cash Flows Presented below are selected amounts related to Dominion Energy’s cash flows: Year Ended December 31, 2024 2023 2022 (millions) Cash, restricted cash and equivalents at beginning of year $ 301 $ 341 $ 408 Cash flows provided by (used in): Operating activities (1) 5,018 6,572 3,700 Investing activities (3,183 ) (7,207 ) (6,746 ) Financing activities (1,771 ) 595 2,979 Net increase (decrease) in cash, restricted cash and equivalents 64 (40 ) (67 ) Cash, restricted cash and equivalents at end of year $ 365 $ 301 $ 341 (1) Includes cash outflows of $83 million, $78 million and $63 million for energy efficiency programs in Virginia and $27 million, $27 million and $26 million for DSM programs in South Carolina for the years ended December 31, 2024, 2023 and 2022, respectively. Operating Cash Flows Net cash provided by Dominion Energy’s operating activities decreased $1.6 billion, inclusive of a $448 million decrease from discontinued operations. Net cash provided by continuing operations decreased $1.1 billion primarily due higher net prepayments and deposits ($606 million), lower deferred fuel and purchased gas cost recoveries ($464 million), settlements of interest rate swaps ($232 million), higher income tax payments ($73 million) and $169 million primarily due to lower operating cash flows from electric utility operations, partially offset by an increase from changes in working capital ($437 million). Investing Cash Flows Net cash used in Dominion Energy’s investing activities decreased $4.0 billion, primarily due to net proceeds from the East Ohio, Questar Gas and PSNC Transactions ($9.2 billion) and an increase in distributions from equity method affiliates ($125 million), partially offset by the absence of the net proceeds from the sale of the remaining noncontrolling interest in Cove Point ($3.3 billion), an increase in plant construction and other property additions ($2.0 billion) and higher acquisitions of solar development projects ($205 million). Financing Cash Flows Net cash from Dominion Energy’s financing activities decreased $2.4 billion, primarily due to a $9.5 billion decrease due to net repayments on 364-day term loan facilities in 2024 versus net issuances in 2023, net repayments of short-term debt ($2.0 billion), the repurchase and redemption of the Series B Preferred Stock ($801 million) and net repayment of supplemental credit facility borrowings ($450 million), partially offset by a $6.8 billion increase due to net issuances of long-term debt in 2024 versus net repayments in 2023, an increase from the sale of a noncontrolling interest in, as well as capital contributions from Stonepeak to, OSWP ($2.9 billion) and an increase in the issuance of common stock ($638 million). 74 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: Facility Limit Outstanding Commercial Paper (1) Outstanding Letters of Credit Facility Capacity Available (millions) At December 31, 2024 Joint revolving credit facility (2)(3) $ 6,000 $ 2,061 $ 10 $ 3,929 (1) The weighted-average interest rate of the outstanding commercial paper supported by Dominion Energy’s credit facility was 4.74% at December 31, 2024. (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. (3) In May 2024, the joint revolving credit facility was amended to remove Questar Gas as a co-borrower. Dominion Energy Reliability Investment SM 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 Investment SM . 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, 2024, Dominion Energy’s Consolidated Balance Sheets include $439 million presented within short-term debt, with a weighted-average interest rate of 4.50%. 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 March 2024, Dominion Energy repaid the full $2.5 billion outstanding under its $2.5 billion 364-day term loan facility entered into in January 2023 as amended in January 2024, using after-tax proceeds received in connection with the East Ohio Transaction. The debt was scheduled to mature in July 2024. In March 2024, Dominion Energy repaid $1.8 billion of its $2.25 billion 364-day term loan facility entered into in October 2023, using after-tax proceeds received in connection with the East Ohio Transaction. Subsequently in March 2024, Dominion Energy requested and received a $500 million increase to the amount of the facility and concurrently borrowed $500 million with the proceeds used for general corporate purposes. In May 2024, Dominion Energy repaid the full $976 million outstanding under the facility, using after-tax proceeds received in connection with the Questar Gas Transaction. The debt was scheduled to mature in October 2024. Long-Term Debt Sustainability Revolving Credit Agreement Dominion Energy maintains a $900 million Sustainability Revolving Credit Agreement which, following an amendment in June 2024, matures in June 2025, bears interest at a variable rate and is described in Note 18 to the Consolidated Financial Statements. The facility offers a reduced interest rate margin with respect to borrowed amounts allocated to certain environmental sustainability or social investment initiatives. In May 2024, Dominion Energy used a portion of the proceeds from the issuance of the 2024 Series A 75 JSNs and the 2024 Series B JSNs to repay the outstanding balance of $450 million under the Sustainability Revolving Credit Agreement. Issuances and Borrowings of Long-Term Debt During 2024, 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. See Note 18 to the Consolidated Financial Statements for additional information including use of proceeds and repayment provisions on the securitization bonds issued in February 2024 and the use of proceeds on the 2024 Series A JSNs and 2024 Series B JSNs issued in May 2024. Month Type Public / Private Entity Principal Rate Stated Maturity (millions) January Senior notes Public Virginia Power $ 500 5.000 % 2034 January Senior notes Public Virginia Power 500 5.350 % 2054 February Senior secured deferred fuel cost bonds Public VPFS 439 5.088 % 2029 February Senior secured deferred fuel cost bonds Public VPFS 843 4.877 % 2033 May Junior subordinated notes Public Dominion Energy 1,000 6.875 % (1) 2055 May Junior subordinated notes Public Dominion Energy 1,000 7.000 % (1) 2054 July Senior notes Private PSNC 150 (2) 5.650 % 2034 July Senior notes Private PSNC 150 (2) 6.040 % 2054 August Senior notes Public Virginia Power 600 5.050 % 2034 August Senior notes Public Virginia Power 600 5.550 % 2054 November Junior subordinated notes Public Dominion Energy 1,250 6.625 % (1) 2055 Total issuances and borrowings $ 7,032 (1) Rates subject to periodic reset as described in Note 18 to the Consolidated Financial Statements. (2) The senior notes issued by PSNC were assumed by Enbridge upon closing of the PSNC Transaction in September 2024. In January 2025, DESC issued $450 million of 5.30% first mortgage bonds that mature in 2035. The proceeds were used for general corporate purposes and/or to repay short-term debt. 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. Dominion Energy anticipates, excluding potential opportunistic financings, issuing between approximately $5.5 billion and $8.0 billion of long-term debt during 2025, inclusive of the issuance of bonds at DESC discussed above. Dominion Energy expects to issue long-term debt to satisfy cash needs for capital expenditures, net of reimbursements from Stonepeak for the CVOW Commercial Project, and maturing long-term debt to the extent such amounts are not satisfied from cash available from operations following the payment of dividends and any borrowings made from unused capacity of Dominion Energy’s credit facilities discussed above. The raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances. Repayments, Repurchases and Redemptions of Long-Term Debt Dominion Energy may from time to time reduce its outstanding debt and level of interest expense through redemption of debt securities prior to maturity or repurchases of debt securities in the open market, in privately negotiated transactions, through tender offers or otherwise. The following long-term debt was repaid, repurchased or redeemed in 2024: Month Type Entity Principal (1) Rate Stated Maturity (millions) Debt scheduled to mature in 2024 $ 1,429 various Early repurchases & redemptions February Senior secured notes Eagle Solar 279 4.820 % 2042 October Tax-exempt bonds DETC 27 3.800 % 2033 October Junior subordinated notes Dominion Energy 685 5.750 % 2054 Total repayments, repurchases and redemptions $ 2,420 76 (1) Total amount redeemed prior to maturity includes remaining outstanding principal plus accrued interest. 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 May 2024, Virginia Power remarketed three series of tax-exempt bonds, with an aggregate outstanding principal of $243 million to new investors. All three series of bonds will bear interest at a coupon of 3.80% until May 2027, after which they will bear interest at a market rate to be determined at that time. In 2025, Dominion Energy expects to remarket approximately $225 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 20, 2025 are as follows: Moody’s Standard & Poor’s Fitch Dominion Energy Corporate/Issuer Baa2 BBB+ BBB+ Senior unsecured debt securities Baa2 BBB BBB+ Junior subordinated notes Baa3 BBB- BBB- Preferred stock Ba1 BBB- BBB- Commercial paper P-2 A-2 F2 Outlook Stable Stable Stable A credit rating is not a recommendation to buy, sell or hold securities and should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the applicable rating organization. Financial Covenants As part of borrowing funds and issuing both short-term and long-term debt or preferred securities, Dominion Energy must enter into enabling agreements. These agreements contain customary covenants that, in the event of default, could result in the acceleration of principal and interest payments; restrictions on distributions related to capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to Dominion Energy. Dominion Energy is required to pay annual commitment fees to maintain its joint revolving credit facility. In addition, the credit agreement contains various terms and conditions that could affect Dominion Energy’s ability to borrow under the facility. They include a maximum debt to total capital ratio, which is also included in Dominion Energy’s Sustainability Revolving Credit Agreement entered into in 2021 and amended in June 2024, and cross-default provisions. As of December 31, 2024, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows: Company Maximum Allowed Ratio Actual Ratio (1) Dominion Energy 67.5 % 54.9 % (1) Indebtedness as defined by the agreements excludes certain junior subordinated notes and securitization bonds reflected as long-term debt as well as AOCI reflected as equity in the Consolidated Balance Sheets. 77 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, 2024, there have been no events of default under Dominion Energy’s covenants. Common Stock, Preferred Stock and Other Equity Securities Issuances of Equity Securities Dominion Energy maintains Dominion Energy Direct ® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In August 2023, Dominion Energy began purchasing its common stock on the open market for these direct stock purchase plans, and in March 2024, began issuing new shares of common stock. During 2024, Dominion Energy issued 2.7 million of such shares and received proceeds of $138 million. Dominion Energy also maintains sales agency agreements to effect sales under an at-the-market program. Under the sales agency agreements, Dominion Energy is able, from time to time, to offer and sell shares of its common stock through the sales agents or enter into one or more forward sale agreements with respect to shares of its common stock. In May 2024, Dominion Energy entered into sales agency agreements to effect sales under a new at-the-market program, and through August 2024 entered forward sale agreements for approximately 11.4 million shares of its common stock at a weighted-average initial forward price of $53.23 per share. In December 2024, Dominion Energy provided notice to elect physical settlement of the forward sale agreements and in December 2024 settled the agreements at a weighted-average final forward price of $52.20 and received total proceeds of $594 million. Additionally, from September through December 2024, Dominion Energy entered forward sale agreements for approximately 9.7 million shares of its common stock expected to be settled in the fourth quarter of 2025 at a weighted-average initial forward price of $57.78 per share. Dominion Energy expects to issue equity through programs such as Dominion Energy Direct ® and employee savings plans of approximately $200 million in 2025. In addition, Dominion Energy expects to issue equity, excluding potential opportunistic offerings, through an at-the-market program, including any related forward-sale agreements, of approximately $800 million to $1.0 billion in 2025, inclusive of the shares expected to settle in the fourth quarter of 2025 discussed above. The raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances. Repurchases and Redemptions of Equity Securities As discussed in Note 19 to the Consolidated Financial Statements, in June 2024, Dominion Energy completed a tender offer repurchasing 0.4 million shares of Series B Preferred Stock, and in December 2024 redeemed the remaining 0.4 million shares outstanding. 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, 2024, Dominion Energy had $920 million of available capacity under this authorization. Dominion Energy does not plan to repurchase shares of common stock in 2025, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which does not impact the available capacity under its stock repurchase authorization. Capital Expenditures See Note 26 to the Consolidated Financial Statements for Dominion Energy’s historical capital expenditures by segment. In February 2025, Dominion Energy announced an updated $50.1 billion capital expenditure plan for 2025 through 2029, which includes the impact of Stonepeak’s 50% noncontrolling interest in the CVOW Commercial Project, representing significant investments in reliable, 78 affordable and increasingly clean energy to advance an “all-of-the-above” strategy to address projected demand growth. Dominion Energy’s total planned capital expenditures for each segment for the next five years are presented in the table below: 2025 2026 2027 2028 2029 Total (billions) Dominion Energy Virginia (1) $ 10.2 $ 8.6 $ 7.8 $ 8.3 $ 8.5 $ 43.4 Dominion Energy South Carolina 1.2 1.3 1.2 1.2 1.3 6.2 Contracted Energy 0.5 0.3 0.3 0.5 0.4 2.0 Corporate and Other segment 0.1 0.1 0.1 0.1 0.1 0.7 Total (2) $ 12.1 $ 10.2 $ 9.5 $ 10.2 $ 10.3 $ 52.3 (1) Includes $3.1 billion in 2025, $1.1 billion in 2026 and $0.1 billion in each of 2027, 2028 and 2029 for 100% of the CVOW Commercial Project. (2) Totals may not foot due to rounding. Dominion Energy’s planned growth expenditures are subject to approval by the Board of Directors as well as potentially by regulatory bodies based on the individual project and are expected to include significant investments in support of its 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 early 2025 and are subject to continuing review and adjustment. Actual capital expenditures may vary from these estimates. Dominion Energy may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances. Dividends Dominion Energy believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In December 2024, Dominion Energy’s Board of Directors established an annual dividend rate for 2025 of $2.67 per share of common stock, consistent with the 2024 rate. Dividends are subject to declaration by the Board of Directors. In January 2025, Dominion Energy’s Board of Directors declared dividends payable in March 2025 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, 2024, 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, 2024 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. 79 Gross Credit Exposure Credit Collateral Net Credit Exposure (millions) Investment grade (1) $ 83 $ — $ 83 Non-Investment grade (2) 11 — 11 No external ratings: Internally rated—investment grade (3) 56 — 56 Internally rated—non-investment grade (4) 24 2 22 Total (5) $ 174 $ 2 $ 172 (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 28% of the total net credit exposure. (2) The five largest counterparty exposures, combined, for this category represented approximately 7% of the total net credit exposure. (3) The five largest counterparty exposures, combined, for this category represented approximately 32% of the total net credit exposure. (4) The five largest counterparty exposures, combined, for this category represented approximately 11% of the total net credit exposure. (5) Excludes long-term purchase power agreements entered to satisfy legislative or state regulatory commission requirements. Fuel and Other Purchase Commitments Dominion Energy is party to various contracts for fuel and purchased power commitments related to both its regulated and nonregulated operations. Total estimated costs at December 31, 2024 for such commitments are presented in the table below. These costs represent estimated minimum obligations for various purchased power and capacity agreements and actual costs may differ from amounts presented below depending on actual quantities purchased and prices paid. 2025 2026 2027 2028 2029 Total (millions) Purchased electric capacity for utility operations $ 70 $ 71 $ 72 $ 71 $ 71 $ 355 Fuel commitments for utility operations 1,336 673 420 455 414 3,298 Fuel commitments for nonregulated operations 80 73 69 51 86 359 Pipeline transportation and storage 410 380 344 330 313 1,777 Total $ 1,896 $ 1,197 $ 905 $ 907 $ 884 $ 5,789 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, 2024. 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; and • Employee benefit plan obligations – See Note 22 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. 80 Future Environmental Regulations Climate Change The federal government and states in which Dominion Energy operates have announced various commitments to achieving carbon reduction goals. In February 2021, the U.S. rejoined the Paris Agreement, which establishes a universal framework for addressing GHG emissions. In January 2025, the U.S. announced its intention to withdrawal from the Paris Agreement. States may 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. 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. Recently Issued EPA Rules In May 2024, the EPA released a final rule to tighten aspects of the Mercury and Air Toxics Standards Risk and Technology Review, including the reduction of emissions limits for filterable particulate matter, and requiring the use of continuous emissions monitoring systems to demonstrate compliance. In May 2024, the EPA finalized a package of rules designed to reduce CO 2 emissions from certain fossil fuel-fired electric generating units. The final rule sets standards of performance and emission guidelines for CO 2 emissions from new and reconstructed gas-fired combustion turbines and modified coal-fired steam generating units. The rulemaking package also includes emission guidelines, including emission limits, for existing coal, oil and gas-fired steam generating units. In addition, in March 2024, the EPA published a final rule strengthening the national air quality annual standard for fine particulate matter. Further, Dominion Energy anticipates that the EPA will release additional rulemakings as part of an overall strategy to identify and mitigate PFAS exposure, beyond the national drinking water standards for PFAS issued in April 2024. Until specific state implementation plans are developed for final rules and/or Dominion Energy has sufficient time to develop implementation strategies for these final rules, Dominion Energy is unable to predict whether or to what extent the new rules will ultimately require additional controls or other actions. The expenditures required to implement additional controls or other actions could have a material impact on Dominion Energy’s financial condition and cash flows. Dodd-Frank Act The CEA, as amended by Title VII of the Dodd-Frank Act, requires certain over-the counter derivatives, or swaps, to be cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk may elect the end-user exception to the CEA’s clearing requirements. Dominion Energy utilizes the end-user exception with respect to its swaps. If, as a result of changes to the rulemaking process, Dominion Energy can no longer utilize the end-user exception or otherwise becomes subject to mandatory clearing, exchange trading or margin requirements, it could be subject to higher costs due to decreased market liquidity or increased margin payments. In addition, Dominion Energy’s swap dealer counterparties may attempt to pass-through additional trading costs in connection with changes to the rulemaking process. Due to the evolving rulemaking process, Dominion Energy is currently unable to assess the potential impact of the Dodd-Frank Act’s derivative-related provisions on its financial condition, results of operations or cash flows. North Anna Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. If Virginia Power decides to build a new unit, it would require a Combined Construction Permit and Operating License from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. In June 2017, the NRC issued the Combined Construction Permit and Operating License. Virginia Power has not yet committed to building a new nuclear unit at North Anna. 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 81 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 guidance and while it cannot currently estimate the potential financial statement impacts, it does not expect a material impact to its results of operations. 82

FY 2025-12-31 (later)