# Dominion Energy, Inc: Form 10-K for the period ended Dec 31, 2022

- Company: [Dominion Energy, Inc](/companies/d.md) (CIK 715957)
- Form: 10-K
- Filed: 2023-02-21
- Accepted by EDGAR: Feb 21, 2023, 07:00 ET
- Period: 2022-12-31
- Accession: 0000950170-23-003287
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/715957/000095017023003287/d-20221231.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/715957/000095017023003287/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2022-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 12 months, 2022-01-01 to 2022-12-31 | $17.73bn | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Operating income | 12 months, 2022-01-01 to 2022-12-31 | $1.60bn | us-gaap:OperatingIncomeLoss |
| Income tax | 12 months, 2022-01-01 to 2022-12-31 | $68.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 12 months, 2022-01-01 to 2022-12-31 | $994.0m | us-gaap:NetIncomeLoss |
| Diluted EPS | 12 months, 2022-01-01 to 2022-12-31 | $1.09 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 12 months, 2022-01-01 to 2022-12-31 | $1.09 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 12 months, 2022-01-01 to 2022-12-31 | 824,800,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 12 months, 2022-01-01 to 2022-12-31 | $3.70bn | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Dividends paid | 12 months, 2022-01-01 to 2022-12-31 | $2.21bn | us-gaap:PaymentsOfDividendsCommonStock |
| Cash and equivalents | at 2022-12-31 | $153.0m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2022-12-31 | $9.85bn | us-gaap:AssetsCurrent |
| Total assets | at 2022-12-31 | $104.24bn | us-gaap:Assets |
| Current liabilities | at 2022-12-31 | $13.45bn | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2022-12-31 | $76.36bn | us-gaap:Liabilities |
| Long-term debt | at 2022-12-31 | $41.87bn | us-gaap:LongTermDebt |
| Short-term borrowings | at 2022-12-31 | $3.42bn | us-gaap:ShortTermBorrowings |
| Shareholders' equity | at 2022-12-31 | $27.88bn | us-gaap:StockholdersEquity |

## Business

As filed, 128,852 characters.

### GENERAL

*Dominion Energy*, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and distributors of energy. Dominion Energy is committed to safely delivering sustainable, reliable and affordable energy and achieving net zero carbon and methane emissions by 2050. Dominion Energy’s strategy is to be a leading sustainable provider of electricity, natural gas and related services to customers primarily in the eastern and Rocky Mountain regions of the U.S. As of December 31, 2022, Dominion Energy’s portfolio of assets includes approximately 31.0 GW of electric generating capacity, 10,600 miles of electric transmission lines, 78,500 miles of electric distribution lines and 93,500 miles of gas distribution mains and related service facilities, which are supported by 4,000 miles of gas transmission, gathering and storage pipeline. As of December 31, 2022, Dominion Energy operates in 15 states and serves approximately 7 million customers.

Dominion Energy has commenced a comprehensive business review as discussed in *Future Issues and Other Matters* in Item 7. MD&A. Pending the results of the business review, Dominion Energy continues to focus on expanding and improving its regulated and long-term contracted electric and natural gas utility businesses while transitioning to a cleaner energy future. Its previously announced growth capital expenditure plan for 2022 through 2026 includes a focus on upgrading the electric system in Virginia through investments in additional renewable generation facilities, strategic undergrounding and energy conservation programs. Renewable generation facilities are expected to include significant investments in utility-scale solar and offshore wind projects. In addition, Dominion Energy has either received or applied for license extensions for its regulated nuclear power stations in Virginia. Other drivers for the growth capital plan include renewable natural gas initiatives, the replacement and modernization of gas distribution pipeline and continued upgrades to its gas and electric transmission and distribution networks while also meeting environmental requirements and standards set by various regulatory bodies.

Dominion Energy currently expects approximately 90% of earnings from its primary operating segments to come from state-regulated electric and natural gas utility businesses. Dominion Energy’s nonregulated operations consist primarily of long-term contracted electric generation operations and its investment in Cove Point. Dominion Energy’s operations are conducted through various subsidiaries, including DESC and Virginia Power. DESC is an SEC registrant; however, its Form 10-K is filed separately and is not combined herein.

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

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

### WHERE YOU CAN FIND MORE INFORMATION ABOUT THE COMPANIES

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

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

### ACQUISITIONS AND DISPOSITIONS

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

### Gas Transmission and Storage Operations

#### Sales to BHE and Southwest Gas

In November 2020, Dominion Energy completed the GT&S Transaction with BHE for approximately $2.7 billion in cash proceeds and the assumption by BHE of approximately $5.3 billion of related long-term debt.

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

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

#### Acquisition of Interest in Atlantic Coast Pipeline and Pivotal LNG, Inc.

In March 2020, Dominion Energy completed the acquisition from Southern of its 5% membership interest in Atlantic Coast Pipeline and its 100% ownership interest in Pivotal LNG, Inc., for $184 million in aggregate, plus certain purchase price adjustments. See Note 9 to the Consolidated Financial Statements for additional information, including the cancellation of the Atlantic Coast Pipeline Project. Pivotal LNG, Inc. was included within the GT&S Transaction and sold to BHE in November 2020.

### Hope

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

### Electric Generation Facilities

#### Acquisition of Virginia Power Solar Projects

In 2020 through 2022, Virginia Power entered into and completed the acquisitions of several primarily early-stage solar development projects in Virginia, including both non-jurisdictional facilities and those expected to be recovered under Rider CE.

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

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

In 2020, Virginia Power entered into and completed the acquisition of various solar development projects in Virginia. These projects are expected to cost a total of approximately $595 million once constructed, including initial acquisition costs, and generate approximately 282 MW combined.

See Notes 10 and 13 to the Consolidated Financial Statements for additional information.

#### Acquisition of Nonregulated Solar Projects

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

In 2020, Dominion Energy entered into agreements and completed the acquisition of various nonregulated solar projects in Ohio, South Carolina and Virginia. These projects are expected to cost a total of approximately $470 million once constructed, including the initial acquisition costs, and generate approximately 248 MW combined.

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

#### Sale of Non-Wholly-Owned Nonregulated Solar Facilities

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

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

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

### Equity Method Investments

#### Contributions to and Disposition of Interest in Wrangler

After an initial contribution to Wrangler in 2019, Dominion Energy completed a second contribution in November 2020 consisting of certain retail energy natural gas contracts receiving $74 million in cash and a final contribution in December 2021 of its remaining nonregulated natural gas retail energy marketing operations receiving $127 million in cash, while maintaining its 20% noncontrolling interest in Wrangler. Subsequently in December 2021 and March 2022, Dominion Energy sold 5% and the remaining 15% of its noncontrolling ownership interest in Wrangler to Interstate Gas Supply, Inc. for cash consideration of $33 million and $85 million, respectively.

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

#### Acquisition of Interest in Dominion Privatization

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

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

### HUMAN CAPITAL

One of Dominion Energy's greatest strengths is its employees and Dominion Energy is committed to providing them with a safe, diverse and inclusive workplace. The ability to attract, develop and retain a diverse workforce is integral to the long-term success of Dominion Energy. At December 31, 2022, Dominion Energy had approximately 17,200 full-time employees, of which approximately 4,500 are subject to collective bargaining agreements, including approximately 6,100 full-time employees at Virginia Power, of which approximately 2,500 are subject to collective bargaining agreements.

Safety is the highest priority of Dominion Energy’s five core values with the fundamental goal to send every employee home safe and sound every day. In 2022, Dominion Energy experienced an OSHA Recordable Rate of 0.52 compared to 0.46 in 2021 and 0.41 in 2020. These rates reflect Dominion Energy’s dedication to safety when compared to a 2021 BLS Industry Average OSHA Recordable Rate of 1.7 and a 2020 BLS Industry Average OSHA Recordable Rate of 1.5. As evidence of Dominion Energy’s commitment to safety, annual incentive plans for all employees, except as restricted by any collective bargaining agreements, include a safety performance measure. Furthermore, Dominion Energy has been proactive in protecting its workforce during the global COVID-19 pandemic by establishing safety protocols and adapting its approach as the pandemic has evolved. Dominion Energy also facilitated telecommuting and hybrid work options for many employees and expanded paid time off and other benefits to help employees cope with disruptions caused by the pandemic.

Dominion Energy works to recruit, retain and develop the careers of talented individuals who reflect the communities it serves. To cultivate this diversified workforce, Dominion Energy focuses on workforce diversity, equity and inclusion while fostering an environment where employees can utilize their unique strengths, skills, personalities and life experiences. Dominion Energy is committed to increasing its diverse workforce representation to 40% by year-end 2026; to be adjusted as necessary based on position and market availability. During 2022, Dominion Energy increased diverse representation within its workforce from 35.5% to 37.0%, following an increase during 2021 from 34.7% to 35.5%. For the purposes of measuring diversity, Dominion Energy includes employees who identify their gender as female and/or their race/ethnicity as American Indian or Alaskan Native, Asian, Black or African American, Hispanic or Latino, Native Hawaiian or Other Pacific Islander or Two or More Races. In 2022, 2021 and 2020, the percentage of new hires that are diverse was 48.9%, 57.5% and 50.7%, respectively. Dominion Energy sponsors eight employee resource groups to support and reinforce its culture of inclusiveness by enabling employees with shared interests and backgrounds to work together to create community, provide networking opportunities and encourage professional development. The employee resource groups are aligned to support various forms of diversity, equity and inclusion, including gender, sexual orientation, gender identity and expression, race, veteran status, age, ability and cultural heritage. To further advance these initiatives, annual incentive plans for all employees, except as restricted by any collective bargaining agreements, include a performance measure for participation in diversity, equity and inclusion training.

Dominion Energy attracts and retains its employees by offering competitive compensation and benefits packages, including healthcare, retirement, paid time off, parental leave and other benefits. Dominion Energy also offers a variety of training and development opportunities for all employees with the goal to provide a consistent and progressive approach to training that engages the workforce and fosters a culture of learning. To this end, Dominion Energy offers continuous learning opportunities including tuition assistance programs, professional development resources, access to a career center and a self-guided training program for independent learning as well as leadership development programs. These resources and programs are designed not only to engage and retain talented employees but also to allow Dominion Energy to meet the needs of its customers in an ever-changing industry with a skilled workforce.

### CYBERSECURITY

In an effort to reduce the likelihood and severity of cyber intrusions, the Companies have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of data and systems, including oversight by the Board of Directors as well as the finance and risk oversight board committee. The Companies are subject to mandatory cybersecurity regulatory requirements, interface regularly with a wide range of external organizations and participate in classified briefings to maintain an awareness of current cybersecurity threats and vulnerabilities. The Companies’ current security posture and regulatory compliance efforts are intended to address the evolving and changing cyber threats. See Item 1A. Risk Factors for discussion of related risks.

### OPERATING SEGMENTS

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

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

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

### DOMINION ENERGY VIRGINIA

Dominion Energy Virginia is substantially composed of Virginia Power’s regulated electric transmission, distribution (including customer service) and generation (regulated electric utility and its related energy supply) operations, which serve approximately 2.7 million residential, commercial, industrial and governmental customers in Virginia and North Carolina.

Dominion Energy Virginia’s previously announced growth capital plan includes spending approximately $27 billion from 2022 through 2026 to construct new generation capacity, including the CVOW Commercial Project, to meet its renewable generation targets and growing electricity demand within its service territory in order to maintain reliability and regulatory compliance and to upgrade or add new transmission lines, distribution lines, substations, and other facilities, as well as maintain existing generation capacity. The proposed infrastructure projects and investment commitments are intended to address both continued customer growth and increases in electricity consumption which are primarily driven by new and larger data center customers, as well as support its subsequent license renewal projects as it has received approval for or is seeking 20-year license extensions for the regulated nuclear fleet in Virginia. See *Properties* and *Environmental Strategy* for additional information on this and other utility projects. Data centers, which currently represent approximately 20% of Virginia Power’s electricity sales, have been a source of significant increase in demand which is expected to continue over the next decade. The concentration of data centers primarily in Loudon County, Virginia represents a unique challenge and requires significant investments in electric transmission facilities to meet the growing demand. While an updated growth capital plan is dependent upon completion of the comprehensive business review discussed in *Future Issues and Other Matters* in Item 7. MD&A, it is expected to reflect an acceleration of certain electric transmission projects to serve the rapidly growing data center customer demand.

Virginia Power has also created a ten-year plan through 2028 to transform its electric grid into a smarter, stronger and greener grid. This plan addresses the structural limitations of Virginia Power’s distribution grid in a systematic manner in order to recognize and accommodate fundamental changes and requirements in the energy industry. The objective is to address both customer and system needs by (i) achieving even higher levels of reliability and resiliency against natural and man-made threats, (ii) leveraging technology to enhance the customer experience and improve the operation of the system and (iii) safely and effectively integrating new utility-scale renewable generation and storage as well as customer–level distributed energy resources such as rooftop solar and battery storage. The Virginia Commission has approved portions of this plan through 2023.

Revenue provided by electric distribution and generation operations is based primarily on rates established by the Virginia and North Carolina Commissions. Approximately 81% of revenue comes from serving Virginia jurisdictional customers. Base rates for the Virginia jurisdiction are set using a modified cost-of-service rate model, and are generally designed to allow an opportunity to recover the cost of providing utility service and earn a reasonable return on investments used to provide that service. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures. Electric operations continue to focus on improving service and experience levels while striving to reduce costs and link investments to operational results. SAIDI performance results, excluding major events, were 136 minutes for the three-year average ending 2022, down from the previous three-year average of 141 minutes. This decrease is primarily due to decreased storm activity.

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

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

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

### Competition

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

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

### Regulation

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

### Properties

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

#### CVOW Commercial Project

In September 2019, Virginia Power filed applications with PJM for the CVOW Commercial Project and for certain approvals and rider recovery from the Virginia Commission in November 2021. The total cost of the project is estimated to be approximately $10 billion, excluding financing costs. Virginia Power’s estimate for the 2.6 GW project’s projected levelized cost of energy is approximately $80-90/MWh. Following a competitive procurement process, Virginia Power has entered into fixed price contracts for the major offshore construction and equipment components. The contracts include services denominated in currencies other than the U.S. dollar for approximately €2.6 billion and 5.1 billion kr., which have been included within the cost estimate above. In addition, certain of the fixed price contracts, approximately €0.7 billion, contain commodity indexing provisions linked to steel. As a result, any changes in applicable exchange rates or commodity indices, if not mitigated, could result in a change to the ultimate cost of the project. In May 2022, Virginia Power entered into forward purchase agreements with a notional amount of approximately €3.2 billion to hedge its foreign currency rate risk exposure from certain fixed price contracts for the major offshore construction and equipment components of the CVOW Commercial Project.

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

Virginia Power has completed the conceptual design phase for the project’s onshore electric transmission facilities and selected a recommended route with consideration given for resiliency and minimizing environmental impacts. Any changes to the onshore route necessitated by the receipt of various permitting approvals could result in upward pressure on the estimated cost of the project. In August 2022, the Virginia Commission approved the application for certification of the Virginia Facilities component of the CVOW Commercial Project, the revenue requirement for the initial rate year of Rider OSW and noted that no further action was required with respect to Virginia Power’s foreign currency risk mitigation plan. The Virginia Commission also included a performance standard for operation of the CVOW Commercial Project, which would require that customers be held harmless for any shortfall in energy production below an annual net capacity factor of 42%, as determined on a three-year rolling average, with details on the implementation of such standard to be determined in a future proceeding. Also in August 2022, Virginia Power filed a petition for limited reconsideration relating to the performance standard for operation of the CVOW Commercial Project included in the Virginia Commission’s August order. The Virginia Commission granted reconsideration and suspended in part the August order pending its reconsideration with Rider OSW approved on an interim basis. In October 2022, Virginia Power, Office of the Attorney General of Virginia and other parties filed a settlement agreement with the Virginia Commission for approval. The settlement agreement provides for a voluntary cost sharing mechanism resulting from unforeseen construction cost increases; specifically, that Virginia Power will be eligible to recover 50% of such incremental costs which fall between $10.3 billion and $11.3 billion with no recovery of such incremental costs which fall between $11.3 billion and $13.7 billion. There is no voluntary cost sharing mechanism for any total construction costs in excess of $13.7 billion, the recovery of which would be determined in a future Virginia Commission preceding. The settlement agreement also provides for customers to receive the maximum benefits available under the IRA including that to the extent the IRA reduces the total construction costs, such reductions will also be applied to the cost sharing bands discussed above. In addition, the settlement agreement includes enhanced performance reporting provisions, in lieu of a performance guarantee, for the operation of the CVOW Commercial Project. To the extent the annual net capacity factor is below 42%, as determined on a three-year rolling average, Virginia Power is required to provide detailed explanation of the factors contributing to any shortfall to the Virginia Commission which could determine in a future proceeding a remedy for incremental costs incurred associated with any deemed unreasonable or imprudent actions of Virginia Power. In December 2022, the Virginia Commission approved the settlement agreement and reinstated its August 2022 order granting approval of Rider OSW.

Upon receiving remaining approvals from other permitting entities, Virginia Power anticipates commencing major construction activities in 2023 and the project is expected to be placed in service by the end of 2026. Virginia Power expects to incur approximately 80% of the project costs from 2023 through 2025. Through December 31, 2022, Virginia Power had incurred approximately $1.1 billion of costs. Virginia Power anticipates funding the project consistent with its approved debt to equity capitalization structure. The project is vital for Virginia Power to meet the renewable energy portfolio standard established in the VCEA and is consistent with the criteria within the VCEA for the construction of an offshore wind facility deemed to be in the public interest as well as the guidelines facilitating cost recovery. See additional discussion of the VCEA provisions concerning renewable generation projects in Note 13 to the Consolidated Financial Statements.

#### Electric Generation and Storage Projects

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

- Virginia Power plans to invest approximately $6.8 billion from 2022 to 2026 to acquire or construct several solar facilities totaling approximately 3.4 GW of expected generating capacity when placed in service. Virginia Power has projects under various stages of development which, as of December 31, 2022, represent a potential generating capacity of approximately 6.3 GW. The facilities include both those to serve utility and non-jurisdictional customers. See Notes 10 and 13 to the Consolidated Financial Statements for additional information.
- To support its development of solar generation facilities serving utility customers, Virginia Power plans to invest approximately $0.6 billion from 2022 to 2026 to acquire or construct multiple battery storage facilities in Virginia, totaling approximately 309 MW of expected storage capacity when placed in service. Virginia Power has projects under various stages of development which, as of December 31, 2022, represent a potential storage capacity of approximately 1.2 GW. See Note 13 to the Consolidated Financial Statements for additional information.
- Virginia Power has received a 20-year extension of the operating licenses for its two units at Surry and has commenced the process to extend the operating licenses for its two units at North Anna. See *Nuclear Decommissioning* below for additional information on these facilities.
- Virginia Power continues to consider the construction of a third nuclear unit at a site located at North Anna. See *Future Issues and Other Matters* in Item 7. MD&A for more information on this project.
- Virginia Power is considering the construction of a hydroelectric pumped storage facility in Southwest Virginia.
- Virginia Power is considering the construction of simple cycle combustion turbines in Virginia for reliability purposes.

#### Electric Transmission and Distribution Projects

Virginia Power continues to invest in transmission projects that are a part of PJM’s RTEP process which focus on reliability improvements and replacement of aging infrastructure. The projects that have been authorized by PJM are expected to result in future capital expenditures of approximately $3.0 billion through 2026.

Virginia Power is investing in transmission substation physical security and expects to invest an additional $100 million to $150 million through 2026 to strengthen its electrical system to better protect critical equipment, enhance its spare equipment process and create multiple levels of security.

Virginia legislation provides for the recovery of costs, subject to approval by the Virginia Commission, for Virginia Power to move approximately 4,000 miles of electric distribution lines underground. The program is designed to reduce restoration outage time by moving Virginia Power’s most outage-prone overhead distribution lines underground, has an annual investment cap of approximately $175 million and is expected to be completed by 2029. The Virginia Commission has approved six phases of the program encompassing approximately 1,866 miles of converted lines and $1.1 billion in capital spending (with $1.1 billion recoverable through Rider U).

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

### Sources of Energy Supply

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

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

| Source | 2022 | 2021 | 2020 |
| --- | ---: | ---: | ---: |
| Natural gas | **36%** | 40% | 48% |
| Nuclear(1) | **28** | 29 | 32 |
| Purchased power, net | **23** | 17 | 7 |
| Coal(2) | **8** | 9 | 9 |
| Renewable and Hydro(3) | **5** | 5 | 4 |
| Total | **100%** | 100% | 100% |

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

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

#### (3) Includes solar and biomass.

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

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

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

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

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

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

### Seasonality

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

### Nuclear Decommissioning

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

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

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

The estimated cost to decommission Virginia Power’s four nuclear units is reflected in the table below and is primarily based upon site-specific studies completed in 2019. These cost studies are generally completed every four to five years. The current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire.

Under the current operating licenses, Virginia Power is scheduled to decommission the Surry and North Anna units during the period 2038 to 2112. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. In 2021, Virginia Power was granted an additional 20 years for its operating licenses for the two units at Surry. Under these license extensions, the two units will be allowed to generate electricity through 2052 and 2053. In 2020, Virginia Power submitted a license renewal application for the two units at North Anna. Under this renewal application, the two units will be allowed to generate electricity through 2058 and 2060, if approved. Between the four units, Virginia Power estimates that it could spend approximately $4 billion through 2035 on capital improvements. The existing regulatory framework in Virginia provides rate recovery mechanisms for such costs.

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

*(dollars in millions)*

| Surry | NRC license expiration year | Most recent cost estimate (2022 dollars)(1) | Funds in trusts at December 31, 2022(2) |
| --- | --- | ---: | ---: |
| Unit 1 | **2052** | **$849** | **$905** |
| Unit 2 | **2053** | **839** | **892** |
| North Anna |  |  |  |
| Unit 1(3) | **2038** | **760** | **724** |
| Unit 2(3) | **2040** | **765** | **681** |
| Total |  | **$3,213** | **$3,202** |

*(1) The cost estimates shown above reflect reductions for the expected future recovery of certain spent fuel costs based on Virginia Power’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in Virginia Power’s nuclear decommissioning AROs and includes the expectation that 20-year license extensions are approved for both units at North Anna.*

*(2) Virginia Power did not make any contributions to its nuclear decommissioning trust funds during 2022.*

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

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

### GAS DISTRIBUTION

Gas Distribution includes Dominion Energy’s regulated natural gas sales, transportation, gathering, storage and distribution operations in Ohio, North Carolina, Utah, southwestern Wyoming and southeastern Idaho (through East Ohio, PSNC and Questar Gas) which collectively serve approximately 3.0 million residential, commercial and industrial customers. Gas Distribution also includes nonregulated renewable natural gas facilities in operation and under development, including Dominion Energy’s investment in Align RNG. See *Investments* below for additional information regarding the Align RNG investment.

Gas Distribution’s previously announced growth capital plan includes spending approximately $5 billion from 2022 through 2026 to upgrade existing or add new infrastructure to meet growing energy needs and retain reliability within its service territory as well as investments in renewable natural gas infrastructure projects. Planned capital spending is driven by infrastructure needs from a growing customer base in states with expanding economies, replacing aging assets for reliability, safety and sustainability and meeting demands for natural gas to support the transition from more carbon intensive fuels. An updated growth capital plan is dependent upon completion of the comprehensive business review discussed in *Future Issues and Other Matters* in Item 7. MD&A.

Earnings for Gas Distribution primarily result from rates established by the Ohio, North Carolina, Utah, Wyoming and Idaho Commissions. The profitability of these businesses is dependent on their ability, through the rates they are permitted to charge, to recover costs and earn a reasonable return on their capital investments. Variability in earnings primarily results from changes in operating and maintenance expenditures, as well as changes in rates and the economy, including customer growth.

### Competition

East Ohio offers an Energy Choice program, under which residential customers are encouraged to purchase gas directly from retail suppliers or through a community aggregation program and have it delivered by East Ohio. At December 31, 2022, approximately 1.1 million of East Ohio’s 1.2 million Ohio customers were participating in the Energy Choice program.

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

Questar Gas does not currently face direct competition from other distributors of natural gas for residential and commercial customers in its service territories as state regulations in Utah, Wyoming and Idaho do not allow customers to choose their provider at this time. See *State Regulations* in *Regulation* for additional information.

In all of Dominion Energy’s gas service territories, electric utilities offer electricity as a rival energy source and compete for the space heating, water heating and cooking markets. The principal means to compete against alternative fuels is lower prices, and natural gas historically has maintained its price advantage in the residential and commercial markets. Competition for heating as well as general household and small commercial energy needs generally occurs at the initial installation phase when the customer or builder makes the decision as to which types of equipment to install. As a result, customers tend to use their chosen energy source for the life of the equipment.

### Regulation

Gas Distribution’s operations, including the rates that it may charge customers, are regulated by the Ohio, North Carolina, Utah, Wyoming and Idaho Commissions as well as PHMSA, the EPA and the U.S. Department of Transportation. See *Federal Regulations* and *State Regulations* in *Regulations, Future Issues and Other Matters* in Item 7. MD&A and Notes 13 and 23 to the Consolidated Financial Statements for additional information.

### Properties

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

Dominion Energy has the following significant projects under construction or development to better serve utility customers or expand its service offerings within its utility service territory as well as to support its strategy to achieve net zero emissions.

*East Ohio—*In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In September 2016, the Ohio Commission approved a stipulation filed jointly by East Ohio and the Staff of the Ohio Commission to continue the PIR program and associated cost recovery for another five-year term beginning in 2017, and to permit East Ohio to increase its annual capital expenditures to $200 million by 2018 with a 3% increase per year thereafter subject to the annual cost recovery rate increase caps proposed by East Ohio. In April 2022, the Ohio Commission approved an extension of East Ohio’s PIR program for capital investments through 2026 with continuation of 3% increases of annual capital expenditures per year. See Note 13 to the Consolidated Financial Statements for additional information.

In 2011, East Ohio began CEP which enables East Ohio to defer depreciation expense, property tax expense and carrying costs on capital investments not covered by its PIR program to expand, upgrade or replace its pipeline system and information technology systems as well as investments necessary to comply with the Ohio Commission or other government regulation. In 2022, the Ohio Commission approved recovery of costs incurred in 2019, 2020 and 2021 under an associated rider. See Note 13 to the Consolidated Financial Statements for additional information.

*PSNC—*The North Carolina Commission has authorized PSNC to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. Projected integrity management plan investment, excluding the costs associated with the project noted below, for the period 2023 to 2025 is expected to be approximately $144 million.

During 2020, construction began on 11 miles of transmission pipeline in Buncombe County, NC. After an analysis was performed under the integrity management program, the new transmission line was deemed necessary to offset the capacity losses on the existing line due to lower pressure being utilized in order to meet federal safety requirements. The project is expected to cost approximately $65 million and had approximately 10 miles placed into service in December 2021 with the remaining portion anticipated to be placed into service in 2023.

*Questar Gas—* In 2010, Questar Gas began replacing aging high pressure infrastructure under a cost-tracking mechanism that allows it to place into rate base and earn a return on capital expenditures associated with a multi-year natural gas infrastructure-replacement program upon the completion of each project. As part of the 2022 Utah base rate case, the Utah Commission approved the continuation of the infrastructure-replacement program with an annual spending budget of approximately $85 million, to be adjusted annually for inflation.

In 2018, legislation became effective in Utah which is designed to spur economic growth in rural communities without natural gas service. Pursuant to its 2022 Utah base rate case, Questar Gas is permitted to spend approximately $85 million over the three years, and approximately $215 million in the aggregate, for expansion of distribution facilities to bring natural gas to residential and commercial customers in rural parts of Utah, as approved by the Utah Commission. Additionally, as part of the 2022 Utah base rate case, the Utah Commission also approved the inclusion of $24 million of rural expansion capital investment in rate base, with costs above this amount to be included for future rural expansion cost consideration.

*Non-Utility Renewable Natural Gas—*In December 2019, Dominion Energy announced the formation of a strategic alliance with Vanguard Renewables in collaboration with the Dairy Farmers of America to capture methane from dairy farms and convert it into pipeline quality natural gas. In August 2021, Dominion Energy announced an expansion of the partnership, increasing its commitment up to $1 billion. As of December 31, 2022, 16 dairy renewable natural gas facilities were under construction in Colorado, Nevada, Idaho, Georgia, Kansas, Texas and New Mexico. These facilities are expected to be placed in service in 2023 through 2025 with an estimated total cost of approximately $1.0 billion, excluding financing costs.

### Investments

*Align RNG—*In November 2018, Dominion Energy announced the formation of Align RNG, an equal partnership with Smithfield Foods, Inc. Align RNG expects to invest $500 million to develop assets to capture methane from swine farms across Virginia, North Carolina, Utah and Arizona and convert it into pipeline quality natural gas. In July 2020, Align RNG placed its first project, located in Milford, UT, in service and the project has produced over 160,000 Dths of renewable natural gas. As of December 31, 2022, Align RNG had four additional projects under construction in North Carolina, Arizona and Virginia with an estimated total cost of approximately $200 million. These facilities are expected to be placed in service in 2023 and 2024.

### Sources of Energy Supply

Dominion Energy’s natural gas supply is obtained from various sources including purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, local producers in the Appalachian area, gas marketers and, for Questar Gas specifically, from Wexpro and other producers in the Rocky Mountain region. Wexpro’s gas development and production operations serve over half of Questar Gas’ gas supply requirements in accordance with the Wexpro Agreements, comprehensive agreements with the states of Utah and Wyoming. In addition, these agreements provide for potential cost saving sharing incentives to the extent that the cost of gas supplied to Questar Gas is a certain amount lower than third-party rates.

### Seasonality

Gas Distribution’s customer demand varies seasonally as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. Accordingly, customer demand is highest during the heating season which is generally from November to March; however, implementation of rate mechanisms for transportation services for East Ohio, and gas sales for Questar Gas and PSNC mitigate the earnings impact of weather-related fluctuations.

### DOMINION ENERGY SOUTH CAROLINA

Dominion Energy South Carolina is comprised of DESC’s generation, transmission and distribution of electricity to approximately 782,000 customers in the central, southern and southwestern portions of South Carolina and the distribution of natural gas to approximately 435,000 residential, commercial and industrial customers in South Carolina.

Dominion Energy South Carolina’s previously announced growth capital plan includes spending approximately $2 billion from 2022 through 2026 to upgrade existing or add new infrastructure to meet growing energy needs within its service territory and maintain reliability. An updated growth capital plan is dependent upon completion of the comprehensive business review discussed in *Future Issues and Other Matters* in Item 7. MD&A.

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

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

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

Electric operations continue to focus on improving service and experience levels while striving to reduce costs and link investments to operational results. SAIDI performance results, excluding major events, were 82 minutes for the three-year average ending 2022, consistent with the previous three-year average of 82 minutes.

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

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

### Competition

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

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

### Regulation

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

### Properties

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

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

In 2020, DESC began the upgrade of its electric and gas systems to an AMI whereby smart meters will be installed throughout its service area. As of December 31, 2022, DESC has completed the installation of approximately 765,000 of the planned 1.1 million smart meters. This project is estimated to cost approximately $140 million and be completed in mid-2024.

In January 2022, DESC committed to a plan to retire certain existing gas combustion turbine facilities, including certain units which currently do not have any net summer capability, and replace them with new gas combustion turbine units at the Williams and Parr facilities to increase reliability and reduce emissions. The replacement facilities are expected to be placed in service by the end of 2025 at an estimated cost of approximately $310 million, excluding financing costs, and have a total winter generating capacity of approximately 171 MW.

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

### Sources of Energy Supply

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

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

| Source | 2022 | 2021 | 2020 |
| --- | ---: | ---: | ---: |
| Natural gas | **48%** | 49% | 47% |
| Nuclear(1) | **23** | 20 | 20 |
| Coal | **18** | 20 | 22 |
| Renewable and Hydro(2) | **11** | 11 | 11 |
| Total | **100%** | 100% | 100% |

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

#### (2) Includes solar.

*Natural gas—* DESC purchases natural gas under contracts with producers and marketers on both a short-term and long-term basis at market-based prices. The gas is delivered to DESC through firm transportation agreements with various counterparties, which expire between 2023 and 2084.

*Coal—* DESC primarily obtains coal through short-term and long-term contracts with suppliers located in eastern Kentucky, Tennessee, Virginia and West Virginia that will expire at various times throughout 2023 and 2024. Spot market purchases may occur when needed or when prices are believed to be favorable.

*Nuclear—* DESC primarily utilizes long-term contracts to support its nuclear fuel requirements. DESC, for itself and as agent for Santee Cooper, and Westinghouse are parties to a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, DESC supplies enriched products to Westinghouse, who in turn supplies nuclear fuel assemblies for Summer. Westinghouse is DESC’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements through 2033.

In addition, DESC has contracts covering its nuclear fuel needs for uranium, conversion services and enrichment services. These contracts have varying expiration dates through 2024. DESC believes that it will be able to renew these contracts as they expire or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services and that sufficient capacity for nuclear fuel supplies and processing exists to allow for normal operations of its nuclear generating unit. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal fuel and inventory levels.

### Seasonality

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

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

### Nuclear Decommissioning

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

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

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

The estimated cost to DESC to decommission its 66.7% ownership in Summer is reflected in the table below and is primarily based upon site-specific studies completed in 2020. These cost studies are generally completed every four to five years. Santee Cooper is responsible for the remaining decommissioning costs, proportionate with its 33.3% ownership in Summer. The cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating license expires. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. DESC expects to apply for an operating license renewal for Summer.

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

*(dollars in millions)*

|  | NRC license expiration year | Most recent cost estimate (2022 dollars)(1) | Funds in trusts at December 31, 2022(2) |
| --- | --- | ---: | ---: |
| Summer – Unit 1 | **2042** | **$788** | **$221** |

*(1) The cost estimates shown above reflect reductions for the expected future recovery of certain spent fuel costs based on DESC’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in DESC’s nuclear decommissioning AROs and includes the expectation that a 20-year license extension is obtained.*

*(2) Excludes any funds held in trust by Santee Cooper. DESC made contributions of $3 million to its nuclear decommissioning trust funds during 2022.*

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

### CONTRACTED ASSETS

Contracted Assets includes the operations of Millstone, and associated energy marketing and price risk activities, Dominion Energy’s nonregulated long-term contracted renewable electric generation fleet, solar generation facility development operations and Dominion Energy’s 50% noncontrolling interest in Cove Point.

Contracted Assets’ previously announced growth capital plan includes spending approximately $3 billion from 2022 through 2026 to expand its renewable generation fleet. While an updated growth capital plan is dependent upon completion of the comprehensive business review discussed in *Future Issues and Other Matters* in Item 7. MD&A, it is expected to reflect a decreased investment in new nonregulated solar generation facilities.

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

Dominion Energy’s nonregulated generation fleet includes solar generation facilities in operation or development in nine states, including Virginia. The output of these facilities is sold under long-term power purchase agreements with terms generally ranging from 15 to 25 years. Variability in earnings provided by these assets relates to changes in irradiance levels due to changes in weather. See Notes 3 and 10 to the Consolidated Financial Statements for additional information regarding certain solar projects.

### Competition

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

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

### Regulation

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

### Properties

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

Dominion Energy currently plans to invest approximately $0.5 billion through 2024 to acquire or construct three solar facilities currently under development in Virginia and Ohio totaling approximately 345 MW of expected generating capacity when placed in service. See Note 10 to the Consolidated Financial Statements for additional information.

### Investments

Contracted Assets includes Dominion Energy’s 50% noncontrolling interest in Cove Point. Cove Point’s gas transportation, LNG import and storage operations, as well as the Liquefaction Facility’s capacity, are contracted primarily under long-term fixed reservation fee agreements. The Liquefaction Facility has a firm contracted capacity for LNG loading onto ships of approximately 4.6 Mtpa (0.66 bcfe/day) under normal operating conditions and after accounting for maintenance downtime. In addition to the operations of the Liquefaction Facility, Cove Point receives revenue from firm fee-based contractual arrangements, including negotiated rates, for its pipeline operations and certain LNG storage and terminalling services as provided for in FERC-approved tariffs. Variability in earnings results from changes in operating and maintenance expenditures and, for FERC-regulated operations, changes in rates and demand for services.

See Item 2. Properties for a description of Cove Point’s physical assets.

See Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Cove Point.

### Leasing Arrangement

In December 2020, Dominion Energy signed an agreement (subsequently amended in December 2022) with a lessor to complete construction of and lease a Jones Act compliant offshore wind installation vessel. This vessel is designed to handle current turbine technologies as well as next generation turbines. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $550 million, to fund the estimated project costs. The project is expected to be ready for the 2024 offshore wind turbine installation season. The initial lease term will commence once construction is substantially complete and the vessel is delivered and will mature in November 2027. See Note 15 to the Consolidated Financial Statements for additional information.

### Sources of Energy Supply

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

### Seasonality

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

### Nuclear Decommissioning

Dominion Energy has two licensed, operating nuclear reactors at Millstone in Connecticut. A third Millstone unit ceased operations before Dominion Energy acquired the power station.

As part of Dominion Energy’s acquisition of Millstone, it acquired decommissioning funds for the related units. Dominion Energy believes that the decommissioning funds and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone units. Dominion Energy will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. The most recent site-specific study completed for Millstone was performed in 2019.

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

*(dollars in millions)*

| Millstone | NRC license expiration year | Most recent cost estimate (2022 dollars)(1) | Funds in trusts at December 31, 2022(2) |
| --- | --- | ---: | ---: |
| Unit 1(3) | **N/A** | **$464** | **$685** |
| Unit 2 | **2035** | **694** | **929** |
| Unit 3(4) | **2045** | **787** | **920** |
| Total |  | **$1,945** | **$2,534** |

26

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

*(2) Dominion Energy did not make any contributions to its nuclear decommissioning trust funds related to Millstone during 2022.*

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

*(4) Millstone Unit 3 is jointly owned by Dominion Energy Nuclear Connecticut, Inc., with a 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain. Decommissioning cost is shown at Dominion Energy’s ownership percentage. At December 31, 2022, the minority owners held $53 million of trust funds related to Millstone Unit 3 that are not reflected in the table above.*

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

### CORPORATE AND OTHER

### Corporate and Other Segment-Virginia Power

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

### Corporate and Other Segment-Dominion Energy

Dominion Energy’s Corporate and Other segment includes its corporate, service company and other functions (including unallocated debt) as well as its noncontrolling interest in Dominion Privatization. Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. In addition, Corporate and Other includes the net impact of discontinued operations consisting primarily of Dominion Energy’s equity investment in Atlantic Coast Pipeline as discussed in Note 9 to the Consolidated Financial Statements.

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

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

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

### REGULATION

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

### State Regulations

### Electric

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

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

#### Electric Regulation in Virginia

The Regulation Act provides for a cost-of-service rate model and permits Virginia Power to seek recovery of costs for new generation projects, including pumped hydroelectricity generation and storage facilities as well as extensions of operating licenses of nuclear power generation facilities, FERC-approved transmission costs, underground distribution lines, certain environmental compliance, conservation, energy efficiency and demand response programs and renewable energy facilities and programs through stand-alone riders, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission.

In March 2018, the GTSA reinstated base rate reviews on a triennial basis other than the 2021 Triennial Review. In the triennial review proceedings, earnings that are more than 70 basis points above the utility’s authorized ROE that might have been refunded to customers and served as the basis for a reduction in future rates, may be reduced by Virginia Commission-approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects to include as a CCRO. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that Virginia Power may seek to recover the costs of such projects through a rider if not the subject of a CCRO. Any costs that are the subject of a CCRO are deemed recovered in base rates during the triennial period under review and may not be included in base rates in future triennial review proceedings. In any triennial review in which the Virginia Commission determines that the utility’s earnings are more than 70 basis points above its authorized ROE, base rates are subject to reduction prospectively and customer refunds would be due unless the total CCRO elected by the utility equals or exceeds the amount of earnings in excess of the 70 basis points. For the purposes of measuring any customer refunds or CCRO amounts utilized under the GTSA, associated income taxes are factored into the determination of such amounts.

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

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

#### Electric Regulation in North Carolina

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

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

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

#### Electric Regulation in South Carolina

DESC’s retail electric base rates in South Carolina are regulated on a cost-of-service/rate-of-return basis subject to South Carolina statutes and the rules and procedures of the South Carolina Commission. South Carolina base rates are set by a process that allows DESC to recover its operating costs and an ROIC. If retail electric earnings exceed the authorized ROE established by the South Carolina Commission, retail electric rates may be subject to review and possible reduction, which may decrease DESC’s future earnings. Additionally, if the South Carolina Commission does not allow recovery of costs incurred in providing service on a timely basis, DESC’s future earnings could be negatively impacted. Fuel costs are reviewed annually by the South Carolina Commission, as required by statute, and fuel rates are subject to revision in these annual fuel proceedings. DESC also submits annual filings to the South Carolina Commission for rider recovery related to its DSM programs and pension costs. The DSM rider includes recovery of any net lost revenues and for a shared savings incentive.

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

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

### Gas

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

#### Gas Regulation in Utah, Wyoming and Idaho

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

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

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

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

#### Gas Regulation in Ohio

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

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

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

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

#### Gas Regulation in North Carolina

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

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

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

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

#### Gas Regulation in South Carolina

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

DESC’s natural gas tariffs include a purchased gas adjustment that provides for the recovery of prudently incurred gas costs, including transportation costs. DESC is authorized to adjust its purchased gas rates monthly and makes routine filings with the South Carolina Commission to provide notification of changes in these rates. Costs that are under or over recovered are deferred as regulatory assets or liabilities, respectively, and considered in subsequent purchased gas adjustments. The purchased gas adjustment filings generally cover a prospective twelve-month period. Increases or decreases in purchased gas costs can result in corresponding changes in purchased gas adjustment rates and the revenue generated by those rates. The South Carolina Commission reviews DESC’s gas purchasing policies and practices, including its administration of the purchased gas adjustment, annually. DESC has also received approval from the South Carolina Commission to create DSM programs for its residential and commercial natural gas customers and a rider to retail gas rates for the recovery of the associated program costs and for a shared savings incentive. DESC has also notified the South Carolina Commission that DESC would seek to recover the net lost revenues resulting from the DSM programs through its annual Natural Gas Rate Stabilization Act proceeding.

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

### Federal Regulations

### Federal Energy Regulatory Commission

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

In January 2021, Virginia Power notified PJM that it was electing to satisfy its capacity requirements by becoming a Fixed Resource Requirement Entity that self-supplies the capacity needed to serve load rather than satisfying this requirement by purchasing capacity in PJM’s Reliability Pricing Model capacity market. This change became effective for the delivery year beginning June 2022. This decision does not affect day-to-day operations.

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

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

EPACT included provisions to create an Electric Reliability Organization, which is required to promulgate mandatory reliability standards governing the operation of the bulk power system in the U.S. FERC has certified NERC as the Electric Reliability Organization and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards will be subject to fines of up to $1.5 million per day, per violation and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.

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

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

In February 2021, DESC and the other members of the SEEM submitted the Southeast Energy Exchange Market Agreement to FERC for authorization. This agreement sets forth the framework and rules for establishing and maintaining a new voluntary electronic trading platform designed to enhance the existing bilateral market in the Southeast utilizing zero-charge transmission service. That transmission service, in turn, will be voluntarily provided by participating transmission service providers, including DESC. In October 2021, the Southeast Energy Exchange Market Agreement became effective by operation of law as a result of a split FERC vote. The SEEM platform became operational in November 2022.

### Nuclear Regulatory Commission

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

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

The NRC also requires the Companies to decontaminate their nuclear facilities once operations cease. This process is referred to as decommissioning, and the Companies are required by the NRC to be financially prepared. For information on decommissioning trusts, see *Dominion Energy Virginia-Nuclear Decommissioning, Dominion Energy South Carolina-Nuclear Decommissioning,* and *Contracted Assets-Nuclear Decommissioning* above and Notes 3 and 9 to the Consolidated Financial Statements. See Note 23 to the Consolidated Financial Statements for additional information on spent nuclear fuel.

### Cyber Regulations

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

### Safety Regulations

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

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

### Environmental Regulations

Each of the Companies’ operating segments is subject to substantial laws, regulations and compliance costs with respect to environmental matters. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of significant penalties for noncompliance, including fines, injunctive relief and other sanctions. The cost of complying with applicable environmental laws, regulations and rules is material to the Companies. If compliance expenditures and associated operating costs are not recoverable from customers through regulated rates (in regulated businesses) or market prices (in unregulated businesses), those costs could adversely affect future results of operations and cash flows. The Companies have applied for or obtained the necessary environmental permits for the construction and operation of their facilities. Many of these permits are subject to reissuance and continuing review. For a discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance required to be discussed in this Item, see *Environmental Matters* in *Future Issues and Other Matters* in Item 7. MD&A. Additional information can also be found in Note 23 to the Consolidated Financial Statements.

### Global Climate Change

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

### Air

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

### Water

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

### Waste and Chemical Management

Dominion Energy is subject to various federal and state laws and implementing regulations governing the management, storage, treatment, reuse and disposal of waste materials and hazardous substances, including the Resource Conservation and Recovery Act of 1976, CERCLA, the Emergency Planning and Community Right-to-Know Act of 1986 and the Toxic Substances Control Act of 1976.

Dominion Energy’s operations and construction activities, including activities associated with oil and gas production and gas storage wells, generate waste. Across Dominion Energy, completion water is disposed at commercial disposal facilities. Produced water is either hauled for disposal, evaporated or injected into company and third-party owned underground injection wells. Wells drilled in tight-gas-sand and shale reservoirs require hydraulic-fracture stimulation to achieve economic production rates and recoverable reserves. The majority of Wexpro’s current and future production and reserve potential is derived from reservoirs that require hydraulic-fracture stimulation to be commercially viable. Currently, all well construction activities, including hydraulic-fracture stimulation and management and disposal of hydraulic fracturing fluids, are regulated by federal and state agencies that review and approve all aspects of gas- and oil-well design and operation.

### Protected Species

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

### Other Regulations

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

### ENVIRONMENTAL STRATEGY

Dominion Energy is committed to a safe, sustainable, reliable and affordable energy future. In February 2020, Dominion Energy set a goal to achieve net zero carbon and methane Scope 1 emissions by 2050. In February 2022, Dominion Energy expanded this commitment to cover Scope 2 emissions and material categories of Scope 3 emissions: electricity purchased to power the grid, fuel purchased for its power stations and gas distribution systems and consumption of sales gas by natural gas customers. As part of the net zero commitment, Dominion Energy has specifically committed to interim targets to cut Scope 1 carbon emissions from its electric operations by 55% by 2030, relative to 2005 emissions, and cut Scope 1 methane emissions from its natural gas infrastructure operations by 65% by 2030 and by 80% by 2040, in each case relative to 2010 emissions. As previously announced, Dominion Energy’s commitment is highlighted by its up to $73 billion potential capital investment in projects supporting decarbonization efforts from 2022 to 2035. While the completion of the comprehensive business review discussed in *Future Issues and Other Matters* in Item 7. MD&A could result in a material adjustment to Dominion Energy’s capital expenditure plans, Dominion Energy has announced its commitment to an industry-leading regulated investment opportunity focused on decarbonization. Dominion Energy’s future capital expenditure plan is expected to reflect a decreased investment in new nonregulated solar generation facilities.

To meet its customers’ needs for safe, reliable, and affordable energy and to reach net zero emissions, in the near term Dominion Energy is seeking extension of the licenses of its zero-carbon nuclear fleet at North Anna similar to the license extension received for Surry, rapidly expanding wind and solar generation as well as energy storage, investing in carbon-beneficial renewable natural gas, expanding its industry-leading methane emissions-reduction programs including pursuing innovative uses of clean burning hydrogen and using low-carbon natural gas to support the integration of wind and solar generation facilities as well as energy storage facilities into the grid and requesting offers for responsibly sourced gas or from those suppliers who are committed to net zero. The strategy to meet these objectives consists of three major elements which will significantly reduce GHG emissions:

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

Over the long term, Dominion Energy’s ability to meet its customers’ needs for safe, reliable and affordable energy and achieve net zero emissions will require supportive legislative and regulatory policies, advancements in technology and broader investments across the economy. Dominion Energy will pursue solutions, including pilot programs, of technologies such as large-scale battery storage, carbon capture and storage, small modular reactors and hydrogen if and when they become technologically and economically feasible.

#### Environmental Justice

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

#### Transparency

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

### Clean Energy Diversity

To achieve its net zero commitment, Dominion Energy is pursuing a diverse mix of cleaner, more efficient and lower-emitting methods of generating and delivering energy, while advancing measures to continue dramatically reducing emissions from traditional generation and delivery. Diversifying the energy portfolio enables Dominion Energy to provide customers with cleaner options while protecting the power supply from potential disruption.

Over the past two decades, Dominion Energy has changed the fuel mix it uses to generate electricity, as well as improved the systems that make up its natural gas operations, to achieve a cleaner future. In addition to reducing GHG emissions, Dominion Energy’s environmental strategy has also resulted in measurable reductions of other air pollutants such as NOX, SO2 and mercury and reduced the amount of coal ash generated and the amount of water withdrawn. Dominion Energy achieved GHG and other air pollutant reductions by implementing an integrated environmental strategy that addresses electric energy production and delivery and energy management. As part of this strategy, Dominion Energy has retired, or committed to retire, several of its fossil fuel electric generating facilities, including those powered by coal, oil and gas with the replacement of this capacity coming from the development of renewable energy facilities.

Renewable energy is an important component of a diverse energy mix designed to meet Dominion Energy’s customers’ needs for safe, reliable and affordable energy. Dominion Energy previously announced it expects to invest up to $21 billion from 2022 through 2035 in solar generation to achieve its target of 13.4 GW generating capacity in-service by the end of 2035. While an updated investment plan is dependent upon completion of the comprehensive business review discussed in *Future Issues and Other Matters* in Item 7. MD&A, it is expected to reflect a decreased investment in new nonregulated solar generation facilities. As of December 31, 2022, Dominion Energy had 2.4 GW of solar generation capacity in operation across five states and several projects under various stages of development which represented a potential generating capacity of approximately 7.8 GW. In addition, Dominion Energy previously announced it expects to invest up to $21 billion from 2022 through 2035 in offshore wind generation facilities. Dominion Energy has commenced development of the CVOW Commercial Project, expected to be placed in service by the end of 2026, along with the CVOW Pilot Project which achieved commercial operation in January 2021. To support these renewable generation facilities, Dominion Energy previously announced it expects to invest up to $4 billion in energy storage facilities from 2022 through 2035. As of December 31, 2022, Virginia Power had projects under various stages of development which represented a potential storage capacity of approximately 1.2 GW.

Preservation of Dominion Energy’s existing carbon-free baseload nuclear generation is also an important component of Dominion Energy’s GHG emissions reduction strategy. Dominion Energy previously announced it expects to invest from 2022 through 2035 approximately $4 billion supporting 20-year life extensions of its units at Surry and North Anna. Virginia Power has received a 20-year extension of the operating licenses for its two units at Surry and has commenced the process to extend the operating licenses for its two units at North Anna.

Dominion Energy is pursuing renewable natural gas through its investment in Align RNG, which is developing projects to capture and convert methane emissions from swine farms, and its strategic alliance with Vanguard Renewables in collaboration with the Dairy Farmers of America to develop projects to capture and convert methane emissions from dairy farms across the U.S. Dominion Energy previously announced it expects to invest approximately $2 billion in renewable natural gas facilities from 2022 through 2035.

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

The IRA provides many incentives designed to encourage production of clean energy, reduce carbon emissions, and promote domestic manufacturing. The IRA significantly extends the investment and production tax credits for renewable technologies including wind and solar, and expands the qualifying technologies to include stand-alone storage, hydrogen, renewable natural gas, nuclear and, after

2024, other zero-emissions facilities. The IRA supersedes certain prior renewable energy legislation and contains a two-tiered credit system applicable to both the production and investment tax credits with a lower base credit amount that can be increased up to five times if the taxpayer can satisfy certain labor requirements. See Note 5 to the Consolidated Financial Statements and *Future Issues and Other Matters* in Item 7. MD&A for additional information on the IRA.

### Innovation and Energy Infrastructure Modernization

One of the pillars of Dominion Energy’s net zero strategy is a focus on innovation as way to advance technology and sustainability. This includes investing in and building upon previously proven technology, including large-scale battery storage, hydrogen, advanced nuclear technology and carbon capture technology. Further, Dominion Energy’s previously announced growth capital plan from 2022 through 2026 includes a focus on upgrading the electric system in Virginia through investments in additional renewable generation facilities, smart meters, customer information platform, intelligent grid devices and associated control systems, physical and cyber security investments, strategic undergrounding and energy conservation programs. Dominion Energy also plans to upgrade its gas and electric transmission and distribution networks and meet environmental requirements and standards set by various regulatory bodies. These enhancements are aimed at meeting Dominion Energy’s continued goal of providing safe, reliable service while addressing increasing electricity consumption, making Dominion Energy’s system more responsive to its customers’ desire to more efficiently manage their energy consumption and transforming its grid to be more adaptive to renewable generation resources and battery technologies.

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

See *Operating Segments* for additional information.

### Conservation and Energy Efficiency

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

- Energy audits and assessments;
- Incentives for customers to upgrade or install certain energy efficient measures and/or systems;
- Weatherization assistance to help income-eligible customers reduce their energy usage;
- Home energy planning, which provides homeowners with a step-by-step roadmap to efficiency improvements to reduce gas usage; and
- Rebates for installing high-efficiency equipment and qualified electric vehicle chargers.

### GHG Emissions

Dominion Energy continues to make progress on achieving its net zero emissions commitment. Through 2021, Dominion Energy has reduced direct Scope 1 CO2 equivalent carbon and methane emissions from its electric generation and natural gas operations by 44%. Through 2021, Dominion Energy has reduced carbon emissions from electric generation by 46% since 2005 and reduced methane emissions from its natural gas infrastructure operations by 38% since 2010. For the purposes of these calculations and consistent with GHG protocol requirements for reporting GHG emission reductions over time, both the baseline and 2021 emissions data excludes the operations sold as part of the Q-Pipe Group and Hope.

Dominion Energy’s 2022 emissions data is not yet available.

#### Corporate GHG Inventory

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

Total direct Scope 1 CO2 equivalent emissions reported under Dominion Energy’s Corporate GHG Inventory were 34.9 million metric tons in 2021. Reported CO2 equivalent emissions include CO2, CH4, N2O and SF6 emissions from Dominion Energy’s electric generation operations, electric transmission and distribution operations and natural gas operations. Consistent with its ownership percentage, Dominion Energy’s 2021 emissions data reported under its Corporate GHG Inventory includes emissions from the Q-Pipe Group (through December 2021) as well as the entire year of operations for Hope.

- For Dominion Energy’s electric generation operations, total CO2 equivalent emissions were 31.7 million metric tons in 2021, including 9.5 million metric tons from DESC and 22.2 million metric tons from Virginia Power.
- For Dominion Energy’s electric transmission and distribution operations, direct CO2 equivalent emissions were 0.04 million metric tons in 2021.
- For Dominion Energy’s natural gas assets, total CO2 equivalent emissions were 2.7 million metric tons in 2021, including 0.5 million metric tons associated with the Q-Pipe Group and Hope.
- For Dominion Energy’s proportional interest in Cove Point’s operations, total CO2 equivalent emissions were 0.6 million metric tons in 2021.

#### EPA Mandatory GHG Reporting Program

Dominion Energy has been reporting GHG emissions, including carbon, methane, N2O and SF6, from its natural gas infrastructure, electric generation and power delivery operations to the EPA since 2011 under the EPA mandatory GHG Reporting Program. The EPA’s mandatory GHG Reporting Program requires annual reporting based on full equity asset ownership at the end of the calendar year. Dominion Energy’s 2021 GHG emissions reported under various subparts of the EPA’s Mandatory GHG Reporting Program as of December 31, 2021, which include the operations of Hope, are as follows:

#### Natural Gas Operations – 2021 Emissions

| Segment (metric tons) | Subpart W CH4 Emissions | Subpart C CH4 Emissions | Subparts W & C CH4 Emissions | Subparts W & C CO2 Emissions | Subparts W & C N2O Emissions | Subparts W & C as CO2 Equivalent Emissions |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Distribution | 33,482 |  | 33,482 | 2,168 | — | 839,208 |
| Production(1) | 13,731 |  | 13,731 | 10,028 | 0.02 | 353,311 |
| Transmission pipelines(1) | 573 |  | 573 | 17 |  | 14,340 |
| Transmission compressor stations(1) | 636 | 4.7 | 641 | 249,628 | 0.47 | 265,788 |
| Gathering and boosting | 3,555 |  | 3,555 | 79,542 | 0.16 | 168,472 |
| Storage(1) | 422 | 1.5 | 423 | 79,128 | 0.15 | 89,749 |
| LNG storage | 172 | — | 172 | 630 | — | 4,940 |
| Total(2)(3) | 52,571 | 6.2 | 52,577 | 421,141 | 0.80 | 1,735,808 |

*(1) Includes the operations of the Q-Pipe Group at 100% ownership as required by the EPA.*

#### (2) Totals may not foot due to rounding.

#### (3) Excludes amounts related to Cove Point.

#### Electric Generation Operations – 2021 Emissions

| Company (metric tons) | Subparts C & D CO2 Emissions | Subparts C & D CH4 Emissions | Subparts C & D N2O Emissions | Subparts C & D CH4 Emissions as CO2 Equivalent Emissions | Subparts C & D N2O Emissions as CO2 Equivalent Emissions | Subparts C & D as CO2 Equivalent Emissions |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Virginia Power(1) | 22,426,491 | 1,258 | 175 | 31,447 | 52,031 | 22,509,968 |
| DESC | 9,429,039 | 601 | 83 | 15,030 | 24,815 | 9,468,883 |
| Total(2) | 31,855,530 | 1,859 | 258 | 46,476 | 76,845 | 31,978,852 |

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

#### (2) Totals may not foot due to rounding.

#### Electric Transmission and Distribution Operations – 2021 Emissions

| Company (metric tons) | Subpart DD SF6 Emissions | Subpart DD SF6 as CO2 Equivalent Emissions |
| --- | ---: | ---: |
| Virginia Power | 0.85 | 19,332 |
| DESC | 0.96 | 21,910 |
| Total(1) | 1.81 | 41,242 |

#### (1) Totals may not foot due to rounding.

### ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES

Dominion Energy incurred $251 million, $221 million and $238 million of expenses (including accretion and depreciation) during 2022, 2021 and 2020 respectively, in connection with environmental protection and monitoring activities. Dominion Energy expects these expenses to be approximately $254 million and $235 million in 2023 and 2024, respectively. In addition, capital expenditures related to environmental controls were $91 million, $37 million, and $58 million for 2022, 2021 and 2020, respectively. Dominion Energy expects these expenditures to be approximately $153 million and $173 million for 2023 and 2024, respectively.

## Risk factors

As filed, 64,587 characters.

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

### Regulatory, Legislative and Legal Risks

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

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

At the state level, Virginia Power’s retail base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia Commission in a proceeding that involves the determination of Virginia Power’s actual earned ROE during a historic test period, and the determination of Virginia Power’s authorized ROE prospectively. The GTSA reinstated triennial reviews commencing with the 2021 Triennial 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. Additionally, Virginia Power’s ability to utilize CCROs for certain qualifying projects as provided for in the GTSA may be limited if the Virginia Commission does not approve such projects. Virginia Power makes assessments throughout the review period and will record a regulatory liability for refunds and/or CCRO benefits 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 triennial review. Several proposed legislative bills have been introduced in the Virginia General Assembly which, if ultimately enacted into law, could have a material impact on Virginia Power’s retail base rates and other cost-recovery mechanisms. Items under consideration include frequency of base rate reviews, eliminating CCROs, shifting the recovery of certain costs currently recovered through riders into base rates and adjusting the parameters for determining an acceptable ROE and revenue sharing.

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

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

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

**The Companies are subject to complex governmental regulation, including tax regulation, that could adversely affect their results of operations and subject the Companies to monetary penalties.** The Companies’ operations are subject to extensive federal, state and local laws and regulations and require numerous permits, approvals and certificates from various governmental agencies. Such laws and regulations govern the terms and conditions of the services we offer, our relationships with affiliates, protection of our critical electric infrastructure assets and pipeline safety, among other matters. The Companies are also subject to legislation and associated regulation governing taxation at the federal, state and local level. They must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for existing operations and that the businesses are conducted in accordance with applicable laws. The Companies’ businesses are subject to regulatory regimes which could result in substantial monetary penalties if either of the Companies is found not to be in compliance, including mandatory reliability standards and interaction in the wholesale markets. New laws or regulations, the revision or reinterpretation of existing laws or regulations, changes in enforcement practices of regulators, or penalties imposed for non-compliance with existing laws or regulations may result in substantial additional expense. Recent legislative and regulatory changes that are impacting the Companies include 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, has been 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 has 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 our customers. The outcome of these or future legal proceedings, investigations and examinations, including settlements, may adversely affect the Companies’ financial condition or results of operation.

### Environmental Risks

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

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

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

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

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

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

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

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

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

### Construction Risks

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

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

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

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

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

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

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

The timeline for development and construction of the CVOW Commercial Project may also be negatively impacted by severe weather events or marine wildlife, including migration patterns of endangered and protected species, both of which are outside of the control of the Companies and their contractors. Any significant delays in the project timeline, including from any of the factors discussed above, resulting in both the delay of commencement of construction to 2024 or later combined with a delay to the in-service date to 2028 or later may impact the ability of the Companies to recover the costs of the CVOW Commercial Project.

**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 and various solar projects. Several of the Companies’ key projects are increasingly large-scale, complex and being constructed in constrained geographic areas or in unfamiliar environments such as the marine environment for the Coastal Virginia Offshore Wind projects. The advancement of the Companies’ ventures is also affected by the interventions, litigation or other activities of stakeholder and advocacy groups, some of which oppose natural gas-related and energy infrastructure projects. For example, certain stakeholder groups oppose solar farms due to the increasing quantities of land tracts required for these facilities. Given that these projects provide the foundation for the Companies’ strategic growth plan, if the Companies are unable to obtain or maintain the required regulatory and other, including PJM, approvals, develop the necessary technical expertise, allocate and coordinate sufficient resources, adhere to budgets and timelines, effectively handle public outreach efforts, including its commitment to environmental justice, or otherwise fail to successfully execute the projects, there could be an adverse impact to the Companies’ financial position, results of operations and cash flows. Failure to comply with regulatory approval conditions or an adverse ruling in any future litigation could adversely affect the Companies’ ability to execute their business plan.

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

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

### Operational Risks

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

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

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

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

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

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

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

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

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

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

**Dominion Energy conducts certain operations through partnership arrangements involving third-party investors which may limit Dominion Energy’s operational flexibility or result in an adverse impact on its financial results.** Certain of Dominion

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

For example, Dominion Energy has a noncontrolling 50% interest in Cove Point following the sale of a 25% controlling interest to BHE in November 2020. This controlling interest allows BHE to make decisions affecting Cove Point’s ability to retain its long-term contracts. Cove Point is a party to certain contracts that allow a regulated service provider and a customer to mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated, cost-based recourse rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue as a result of these “negotiated rate” contracts could decrease Cove Point’s earnings and cash flows. The inability to maintain or renew such contracts on favorable terms may have a material impact to Dominion Energy’s results of operations, financial position or cash flows. Dominion Energy is also dependent upon BHE for managing counterparty credit risk relating to Cove Point’s terminal services agreements for its liquefied natural gas export/liquefaction facility. While the counterparties’ obligations are supported by parental guarantees and letters of credit, there is no assurance that such credit support would be sufficient to satisfy the obligations in the event of a counterparty default. In addition, if a controversy arises under either terminal services agreement resulting in a judgment in Cove Point’s favor, Cove Point may need to seek to enforce a final U.S. court judgment in a foreign tribunal, which could involve a lengthy process. Accordingly, there is no assurance that BHE may pursue remedies in the event of default in the same manner as Dominion Energy would if it had unilateral control over such decisions.

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

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

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

### Nuclear Generation Risks

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

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

### Financial, Economic and Market Risks

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

**An inability to access financial markets and, in the case of Dominion Energy, obtain cash from subsidiaries could adversely affect the execution of the Companies’ business plans.** The Companies rely on access to short-term money markets and longer-term capital markets as significant sources of funding and liquidity for business plans with increasing capital expenditure needs, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities. Deterioration in the Companies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or declines in market reputation either for the Companies or their industry in general, or general financial market disruptions outside of the Companies’ control could increase their cost of borrowing or restrict their ability to access one or more financial markets. In addition, any potential adverse conditions arising from or in connection with the comprehensive business review announced in November 2022 could affect the availability and/or cost of capital. Market disruptions could stem from general market disruption due to general credit market or political events, the planned phase out of LIBOR by the end of 2023 or the reform or replacement of other 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 Assets were impaired, resulting in a $1.1 billion after-tax charge.

**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, such as COVID-19, could adversely affect the Companies’ business, results of operations, financial condition, liquidity and/or cash flows.** The effects of the continued outbreak of the COVID-19 pandemic 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. There remains uncertainty regarding the extent and duration of measures to try to contain the virus, such as travel bans and restrictions, quarantines, shelter-in-place orders and shutdowns. Such restrictions may cause operational interruptions and delays in construction projects, which, in the case of renewable energy projects, could delay the expected in-service dates of these projects and financial statement impact of the investment tax credits associated with these projects. For the duration of the outbreak of COVID-19, voluntary suspension, or potential legislative or government action, such as legislation enacted in Virginia in November 2020, may limit the Companies’ ability to collect on overdue accounts or disconnect services for non-payment, which may cause a decrease in the Companies’ results of operations and cash flows.

## Properties

As filed, 14,087 characters.

As of December 31, 2022, Dominion Energy owned its principal executive office in Richmond, Virginia and five other corporate offices. Dominion Energy also leases corporate offices in Richmond, Virginia and other cities in which its subsidiaries operate. Virginia Power shares Dominion Energy’s principal executive office in Richmond, Virginia. In addition, Virginia Power leases certain buildings and equipment.

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

Certain of Virginia Power’s properties are subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. There were no bonds outstanding as of December 31, 2022; however, by leaving the indenture open, Virginia Power retains the flexibility to issue mortgage bonds in the future. Certain of Dominion Energy’s nonregulated generation facilities are also subject to liens. Additionally, DESC’s bond indenture, which secures its First Mortgage Bonds, constitutes a direct mortgage lien on substantially all of its electric utility property.

### DOMINION ENERGY VIRGINIA

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

In addition, Virginia Power’s electric distribution network includes approximately 59,700 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, Virginia Power owns 482 substations and 16 MW of battery storage. Dominion Energy also owns various solar facilities, primarily at schools in Virginia, with an aggregate generation capacity of 21 MW.

The following tables list Virginia Power’s generating units and capability as of December 31, 2022.

### VIRGINIA POWER UTILITY GENERATION

| Plant Gas | Location | Net Summer Capability (MW) |  | Percentage Net Summer Capability |
| --- | --- | ---: | ---: | ---: |
| Greensville County (CC) | Greensville County, VA | 1,629 |  |  |
| Brunswick County (CC) | Brunswick County, VA | 1,376 |  |  |
| Warren County (CC) | Warren County, VA | 1,349 |  |  |
| Ladysmith (CT) | Ladysmith, VA | 783 |  |  |
| Bear Garden (CC) | Buckingham County, VA | 622 |  |  |
| Remington (CT) | Remington, VA | 622 |  |  |
| Possum Point (CC) | Dumfries, VA | 573 |  |  |
| Chesterfield (CC) | Chester, VA | 392 |  |  |
| Elizabeth River (CT) | Chesapeake, VA | 330 |  |  |
| Gordonsville Energy (CC) | Gordonsville, VA | 218 |  |  |
| Gravel Neck (CT) | Surry, VA | 170 |  |  |
| Darbytown (CT) | Richmond, VA | 168 |  |  |
| Total Gas |  | 8,232 |  | 41% |
| **Coal** |  |  |  |  |
| Mt. Storm | Mt. Storm, WV | 1,617 |  |  |
| Chesterfield(1) | Chester, VA | 1,014 |  |  |
| Virginia City Hybrid Energy Center | Wise County, VA | 610 |  |  |
| Clover | Clover, VA | 439 | (2) |  |
| Total Coal |  | 3,680 |  | 18 |
| **Nuclear** |  |  |  |  |
| Surry | Surry, VA | 1,676 |  |  |
| North Anna | Mineral, VA | 1,672 | (3) |  |
| Total Nuclear |  | 3,348 |  | 16 |
| **Hydro** |  |  |  |  |
| Bath County | Warm Springs, VA | 1,808 | (4) |  |
| Gaston | Roanoke Rapids, NC | 220 |  |  |
| Roanoke Rapids | Roanoke Rapids, NC | 95 |  |  |
| Other |  | 1 |  |  |
| Total Hydro |  | 2,124 |  | 10 |
| **Oil** |  |  |  |  |
| Yorktown(1) | Yorktown, VA | 790 |  |  |
| Gravel Neck (CT) | Surry, VA | 198 |  |  |
| Darbytown (CT) | Richmond, VA | 168 |  |  |
| Rosemary (CC) | Roanoke Rapids, NC | 160 |  |  |
| Possum Point (CT) | Dumfries, VA | 72 |  |  |
| Low Moor (CT) | Covington, VA | 48 |  |  |
| Northern Neck (CT) | Lively, VA | 47 |  |  |
| Chesapeake (CT) | Chesapeake, VA | 39 |  |  |
| Total Oil |  | 1,522 |  | 7 |
| **Solar(5)** |  |  |  |  |
| Colonial Trail West | Surry County, VA | 142 |  |  |
| Sadler Solar | Emporia, VA | 100 |  |  |
| Spring Grove | Surry County, VA | 98 |  |  |
| Grassfield | Chesapeake, VA | 20 |  |  |
| Whitehouse Solar | Louisa County, VA | 20 |  |  |
| Woodland Solar | Isle of Wight County, VA | 19 |  |  |
| Scott Solar | Powhatan, VA | 17 |  |  |
| Total Solar |  | 416 |  | 2 |
| **Biomass** |  |  |  |  |
| Altavista(6) | Altavista, VA | 51 |  |  |
| Polyester(6) | Hopewell, VA | 51 |  |  |
| Southampton(6) | Southampton, VA | 51 |  |  |
| Total Biomass |  | 153 |  | 1 |
| **Wind** |  |  |  |  |
| CVOW Pilot Project | Virginia Beach, VA | 12 |  | — |
| **Various** |  |  |  |  |
| Mt. Storm (CT) | Mt. Storm, WV | 11 |  | — |
|  |  | 19,498 |  |  |
| **Power Purchase Agreements** |  | 1,106 |  | 5 |
| Total Utility Generation |  | 20,604 |  | 100% |

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

*(1) Will be retired after it meets its capacity obligation in 2023. See Note 2 to the Consolidated Financial Statements for additional information.*

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

#### (3) Excludes 11.6% undivided interest owned by ODEC.

*(4) Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of FirstEnergy Corp.*

#### (5) All solar facilities are alternating current.

#### (6) In accordance with the VCEA, these units will be retired no later than 2028.

### VIRGINIA POWER NON-JURISDICTIONAL GENERATION

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

#### (1) All solar facilities are alternating current.

### GAS DISTRIBUTION

Gas Distribution’s network is located in Ohio, North Carolina, Utah, southwestern Wyoming and southeastern Idaho. This network includes approximately 74,400 miles of distribution mains and related service facilities which are supported by approximately 3,600 miles of transmission, gathering and storage pipeline. The right-of-way grants for many natural gas pipelines have been obtained from the actual owners of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many natural gas pipelines are on publicly-owned property, where company rights and actions are determined on a case-by-case basis, with results that range from reimbursed relocation to revocation of permission to operate.

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

### DOMINION ENERGY SOUTH CAROLINA

DESC has approximately 3,900 miles and 18,800 miles of electric transmission and distribution lines, respectively, exclusive of service level lines, in South Carolina. The grants for most of DESC’s electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying property titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, DESC owns 459 substations.

DESC’s natural gas system includes approximately 19,100 miles of distribution mains and related service facilities, which are supported by approximately 400 miles of transmission pipeline.

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

The following table lists DESC’s generating units and capability as of December 31, 2022.

| Plant Gas | Location | Net Summer Capability (MW) |  | Percentage Net Summer Capability |
| --- | --- | ---: | ---: | ---: |
| Jasper (CC) (1) | Hardeeville, SC | 903 |  |  |
| Columbia Energy Center (CC) (1) | Gaston, SC | 519 |  |  |
| Urquhart (CC) (1) | Beech Island, SC | 458 |  |  |
| McMeekin | Irmo, SC | 250 |  |  |
| Hagood (CT) (1) | Charleston, SC | 126 |  |  |
| Urquhart Unit 3 | Beech Island, SC | 95 |  |  |
| Urquhart (CT) (1) | Beech Island, SC | 87 |  |  |
| Parr (CT) (1)(2) | Jenkinsville, SC | 47 |  |  |
| Coit (CT) (1)(2) | Columbia, SC | 26 |  |  |
| Total Gas |  | 2,511 |  | 38% |
| **Coal** |  |  |  |  |
| Wateree | Eastover, SC | 684 |  |  |
| Williams | Goose Creek, SC | 605 |  |  |
| Cope (3) | Cope, SC | 415 |  |  |
| Total Coal |  | 1,704 |  | 26 |
| **Hydro** |  |  |  |  |
| Fairfield | Jenkinsville, SC | 576 |  |  |
| Saluda | Irmo, SC | 198 |  |  |
| Other | Various | 18 |  |  |
| Total Hydro |  | 792 |  | 12 |
| **Nuclear** |  |  |  |  |
| Summer | Jenkinsville, SC | 651 | (4) | 10 |
|  |  | 5,658 |  |  |
| **Power Purchase Agreements** |  | 973 | (5) | 14 |
| Total Utility Generation |  | 6,631 |  | 100% |

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

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

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

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

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

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

### CONTRACTED ASSETS

Contracted Assets includes Dominion Energy’s 50% noncontrolling interest in Cove Point. The Cove Point LNG Facility has an operational peak regasification daily send-out capacity of approximately 1.8 million Dths and an aggregate LNG storage capacity of approximately 14.6 bcfe. In addition, Cove Point has a small liquefier that has the potential to create approximately 15,000 Dths/day. The Liquefaction Facility consists of one LNG train with a nameplate outlet capacity of 5.25 Mtpa. Cove Point has authorization from the DOE to export up to 0.77 bcfe/day (approximately 5.75 Mtpa) should the Liquefaction Facility perform better than expected. In addition, Cove Point operates a 136-mile natural gas pipeline that connects the Cove Point LNG Facility to interstate natural gas pipelines.

The following table lists Contracted Assets’ generating units and capability as of December 31, 2022.

| Plant Nuclear | Location | Net Summer Capability (MW) |  | Percentage Net Summer Capability |
| --- | --- | ---: | ---: | ---: |
| Millstone | Waterford, CT | 2,001 | (1) |  |
| Total Nuclear |  | 2,001 |  | 67% |
| Solar(2) |  |  |  |  |
| Hardin I | Hardin County, OH | 150 |  |  |
| Amazon Solar Farm Virginia – Southampton | Newsoms, VA | 100 | (3) |  |
| Amazon Solar Farm Virginia – Accomack | Oak Hall, VA | 80 | (3) |  |
| Greensville | Greensville County, VA | 80 |  |  |
| Innovative Solar 37 | Morven, NC | 79 | (3) |  |
| Wilkinson | Pantego, NC | 74 |  |  |
| Seabrook | Beaufort County, SC | 73 |  |  |
| Moffett Solar 1 | Ridgeland, SC | 71 | (3) |  |
| Summit Farms Solar | Moyock, NC | 60 | (3) |  |
| Midway II | Calipatria, CA | 30 | (3) |  |
| Amazon Solar Farm Virginia – Buckingham | Cumberland, VA | 20 | (3) |  |
| Amazon Solar Farm Virginia – Correctional | Barhamsville, VA | 20 | (3) |  |
| Hecate Cherrydale | Cape Charles, VA | 20 | (3) |  |
| Amazon Solar Farm Virginia – Sussex Drive | Stoney Creek, VA | 20 | (3) |  |
| Amazon Solar Farm Virginia – Scott II | Powhatan, VA | 20 | (3) |  |
| Myrtle | Suffolk, VA | 15 |  |  |
| Trask | Beaufort County, SC | 12 |  |  |
| Hecate Energy Clarke County | White Post, VA | 10 | (3) |  |
| Ridgeland Solar Farm I | Ridgeland, SC | 10 | (3) |  |
| Yemassee | Hampton County, SC | 10 |  |  |
| Blackville | Blackville, SC | 7 |  |  |
| Denmark | Denmark, SC | 6 |  |  |
| Other | Various | 35 | (3) |  |
| Total Solar |  | 1,002 |  | 33 |
| Total Nonregulated Generation |  | 3,003 |  | 100% |

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

#### (2) All solar facilities are alternating current.

#### (3) Dominion Energy’s interest is subject to a lien securing Eagle Solar’s debt.

## Legal proceedings

As filed, 746 characters.

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

## Management's discussion and analysis

As filed, 101,956 characters.

MD&A discusses Dominion Energy’s results of operations, general financial condition and liquidity and Virginia Power’s results of operations as of and for the year ended December 31, 2022 as compared to the year ended December 31, 2021, as applicable. For a discussion of these items for the year ended December 31, 2021 as compared to the year ended December 31, 2020, please see Part II, Item 7. MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 24, 2022. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data. Virginia Power meets the conditions to file under the reduced disclosure format, and therefore has omitted certain sections of MD&A.

### CONTENTS OF MD&A

MD&A consists of the following information:

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

### FORWARD-LOOKING STATEMENTS

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

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

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

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

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

### ACCOUNTING MATTERS

### Critical Accounting Policies and Estimates

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

### Accounting for Regulated Operations

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

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;
- 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 evaluation of Virginia Power’s earnings for the 2021 Triennial Review, in 2020 Virginia Power established a regulatory liability for benefits expected to be provided to Virginia retail electric customers through the use of a

CCRO in accordance with the GTSA. In 2021, Virginia Power made further adjustments to this regulatory liability prior to its ultimate resolution through a comprehensive settlement agreement. See Notes 12 and 13 to the Consolidated Financial Statements for additional information.

### Asset Retirement Obligations

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

Dominion Energy’s AROs include a significant balance related to the future decommissioning of its nonregulated and utility nuclear facilities. These nuclear decommissioning AROs are reported in Dominion Energy Virginia, Dominion Energy South Carolina and Contracted Assets. At December 31, 2022 and 2021, Dominion Energy’s nuclear decommissioning AROs totaled $1.9 billion and $2.0 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, 2022, a 0.25% increase in cost escalation rates would have resulted in an approximate $370 million increase in Dominion Energy’s nuclear decommissioning AROs.

### Income Taxes

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

Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2022 and 2021, Dominion Energy had $117 million and $128 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, 2022 and 2021, Dominion Energy had established $138 million and $140 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 2022, 2021 and 2020 annual test did not result in the recognition of any goodwill impairment.

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

See Note 11 to the Consolidated Financial Statements for additional information.

### Use of Estimates in Long-Lived Asset and Equity Method Investment Impairment Testing

Impairment testing for an individual or group of long-lived assets, including intangible assets with definite lives, and equity method investments 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. When an equity method investment’s carrying amount exceeds its fair value, and the decline in value is deemed to be other-than-temporary, an impairment is recognized to the extent that the fair value is less than its carrying amount. Performing an impairment test on long-lived assets and equity method investments 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 equity method investments 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 Assets 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 $69 million increase to the impairment charge recorded. A 0.25% increase in the discount rate would have resulted in a $13 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 other tests performed in 2022 of long-lived assets or equity method investments which could have resulted in material impairments.

### Held for Sale Classification

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

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

In 2022, Dominion Energy completed the sale of Kewaunee following the receipt of approval for sale from the Wisconsin Commission; which prior to its receipt there had been uncertainty as to the timing of or ability to obtain such approval. Dominion Energy recorded a loss of $649 million primarily related to the difference between the nuclear decommissioning trust and AROs.

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

### Employee Benefit Plans

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

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

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

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

Dominion Energy develops its critical assumptions, which are then compared to the forecasts of an independent investment advisor or an independent actuary, as applicable, to ensure reasonableness. An internal committee selects the final assumptions. Dominion Energy calculated its pension cost using an expected long-term rate of return on plan assets assumption that ranged from 7.00% to 8.35% for 2022, 7.00% to 8.45% for 2021 and 7.00% to 8.60% for 2020. For 2023, the expected long-term rate of return for the pension cost assumption ranged from 7.00% to 8.35% for Dominion Energy’s plans held as of December 31, 2022. Dominion Energy calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 8.35% for 2022, 8.45% for 2021 and 8.50% for 2020. For 2023, the expected long-term rate of return for other postretirement benefit cost assumption is 8.35%.

Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost ranged from 3.06% to 3.19% for pension plans and 3.04% to 5.03% for other postretirement benefit plans in 2022, ranged from 2.73% to 3.29% for pension plans and 2.69% to 2.80% for other postretirement benefit plans in 2021 and ranged from 2.77% to 3.63% for pension plans and 3.07% to 3.52% for other postretirement benefit plans in 2020. Dominion Energy selected a discount rate ranging from 5.65% to 5.75% for pension plans and 5.69% to 5.70% for other postretirement benefit plans for determining its December 31, 2022 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, 2022 was 6.25% and is expected to gradually decrease to 5.00% by 2026-2027 and continue at that rate for years thereafter.

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

*(millions, except percentages)*

|  | Change in Actuarial Assumptions | Increase in 2022 Net Periodic Cost Pension Benefits | Other Postretirement Benefits |
| --- | ---: | ---: | ---: |
| Discount rate | **(0.25)%** | **$17** | **$—** |
| Long-term rate of return on plan assets | **(0.25)%** | **27** | **6** |
| Health care cost trend rate | **1%** | **N/A** | **9** |

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, 2022 by $215 million and its accumulated postretirement benefit obligation at December 31, 2022 by $26 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation at December 31, 2022 by $75 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, (millions, except EPS) | 2022 | $ Change | 2021 | $ Change | 2020 |
| --- | ---: | ---: | ---: | ---: | ---: |
| Net income (loss) attributable to Dominion Energy | **$994** | **$(2,294)** | $3,288 | $3,689 | $(401) |
| Diluted EPS | **1.09** | **(2.89)** | 3.98 | 4.55 | (0.57) |

### Overview

### 2022 VS. 2021

Net income attributable to Dominion Energy decreased 70%, primarily due to a charge associated with the impairment of certain nonregulated solar generation facilities, a loss associated with the sale of Kewaunee, a decrease in net investment earnings on nuclear decommissioning trust funds, a net decrease associated with the impacts of Virginia Power’s 2021 Triennial Review, a charge for RGGI compliance costs deemed recovered through base rates, a charge in connection with a comprehensive settlement agreement for Virginia fuel expenses and dismantling costs associated with the early retirement of certain electric generation facilities at Virginia Power. These decreases were partially offset by the absence of charges associated with the settlement of the South Carolina electric base rate case, increased unrealized gains on economic hedging activities and the absence of a net loss on the sales of non-wholly-owned nonregulated solar facilities.

### Analysis of Consolidated Operations

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

| Year Ended December 31, (millions) | 2022 | $ Change | 2021 | $ Change | 2020 |
| --- | ---: | ---: | ---: | ---: | ---: |
| Operating revenue | **$17,174** | **$3,210** | $13,964 | $(208) | $14,172 |
| Electric fuel and other energy-related purchases | **3,711** | **1,343** | 2,368 | 125 | 2,243 |
| Purchased electric capacity | **59** | **(11)** | 70 | 17 | 53 |
| Purchased gas | **1,582** | **499** | 1,083 | 194 | 889 |
| Other operations and maintenance | **3,984** | **250** | 3,734 | 49 | 3,685 |
| Depreciation, depletion and amortization | **2,830** | **352** | 2,478 | 146 | 2,332 |
| Other taxes | **923** | **14** | 909 | 38 | 871 |
| Impairment of assets and other charges | **2,063** | **1,868** | 195 | (1,910) | 2,105 |
| Losses (gains) on sales of assets | **426** | **318** | 108 | 169 | (61) |
| Earnings from equity method investees | **299** | **23** | 276 | 236 | 40 |
| Other income | **124** | **(1,033)** | 1,157 | 464 | 693 |
| Interest and related charges | **966** | **(388)** | 1,354 | (23) | 1,377 |
| Income tax expense | **68** | **(357)** | 425 | 342 | 83 |
| Net income (loss) from discontinued operations including noncontrolling interests | **9** | **(632)** | 641 | 2,519 | (1,878) |
| Noncontrolling interests | **—** | **(26)** | 26 | 175 | (149) |

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

### 2022 VS. 2021

**Operating revenue** increased 23%, primarily reflecting:

- A $1.8 billion increase in fuel-related revenue as a result of an increase in commodity costs associated with sales to electric utility retail customers ($1.2 billion) and gas utility customers ($586 million);
- A $505 million increase to recover the costs and an authorized return, as applicable, associated with Virginia Power non-fuel riders;
- The absence of a $356 million decrease for refunds provided to retail electric customers in Virginia associated with the settlement of the 2021 Triennial Review;
- A $290 million net increase associated with market prices affecting Millstone, including economic hedging impacts of net realized and unrealized losses on freestanding derivatives ($6 million);
- The absence of a $151 million decrease from an unbilled revenue reduction at Virginia Power;
- A $67 million increase in sales to utility retail customers associated with growth at electric ($46 million) and gas ($21 million) utilities;
- A $66 million increase from gas utility capital cost riders;
- A $57 million increase in sales to electric utility retail customers from an increase in heating degree days during the heating season ($52 million) and a net increase in cooling degree days during the cooling season ($5 million);
- A $38 million net increase from electric utility customers who elect to pay market-based or other negotiated rates, including settlements of economic hedges at Virginia Power;
- A $38 million increase following the approved base rate case for PSNC;
- A $30 million increase in sales to electric utility retail customers associated with economic and other usage factors;
- A $24 million increase in sales to customers from non-jurisdictional solar generation facilities at Virginia Power; and
- A $20 million increase in non-fuel base rates associated with the settlement in 2021 of the South Carolina electric base rate case.

These increases were partially offset by:

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

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

**Purchased gas** increased 46%, primarily due to an increase in commodity costs for gas utilities ($586 million), which are offset in operating revenue and do not impact net income, partially offset by cost saving incentives earned under the Wexpro Agreements ($27 million).

**Other operations and maintenance** increased 7%, primarily reflecting:

- A $84 million increase in certain Virginia Power expenditures which are primarily recovered through state- and FERC-regulated rates and do not impact net income;
- A $51 million increase in storm damage and restoration costs primarily from winter storms in Virginia Power’s service territory;
- A $46 million increase in bad debt expense;
- A $46 million increase in materials and supplies expense primarily as a result of higher prices;
- A $42 million increase in outage costs at Millstone ($26 million) and Virginia Power ($16 million); and
- A $21 million increase in outside services.

These increases were partially offset by:

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

**Depreciation, depletion and amortization** increased 14%, primarily due to various projects being placed into service ($205 million), an increase for amortization of a regulatory asset established in the settlement of the 2021 Triennial Review ($183 million), and an increase in RGGI-related amortization ($128 million), which except for the suspended period of Rider RGGI is offset in operating revenue and does not impact net income, partially offset by depreciation rates revised in the first quarter of 2022 at Virginia Power ($82 million) and a decrease from the sale of non-wholly-owned nonregulated solar facilities ($45 million).

**Impairment of assets and other charges** increased $1.9 billion, primarily reflecting:

- A charge associated with the impairment of certain nonregulated solar generation facilities ($1.5 billion);
- The absence of a benefit from the establishment of a regulatory asset associated with the early retirement of certain coal- and oil-fired generating units associated with the settlement of the 2021 Triennial Review ($549 million);
- A charge in connection with a comprehensive settlement agreement for Virginia fuel expenses ($191 million);
- A charge for RGGI compliance costs deemed recovered through base rates at Virginia Power ($180 million);
- Dismantling costs associated with the early retirement of certain electric generation facilities at Virginia Power ($167 million); and
- A charge for the write-off of inventory ($40 million); partially offset by
- The absence of charges associated with the settlement of the South Carolina electric base rate case ($249 million);
- The absence of charges for CCRO benefits provided to retail electric customers in Virginia associated with Virginia Power’s 2021 Triennial Review ($188 million);
- A decrease in charges associated with litigation acquired in the SCANA Combination ($97 million);
- The absence of a charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to Virginia’s 2021 budget process ($77 million);
- The absence of a charge for corporate office lease termination ($62 million); and
- The absence of a write-off of nonregulated retail software development assets ($20 million).

**Losses on sales of assets** increased $318 million, primarily due to a loss associated with the sale of Kewaunee ($649 million) and the absence of gains on the sale of nonregulated retail energy marketing assets ($87 million), partially offset by the absence of a net loss on the sales of non-wholly-owned nonregulated solar facilities ($211 million), a gain on the contribution of certain privatization operations to Dominion Privatization ($155 million), a gain on the transfer of certain non-utility and utility property in South Carolina ($20 million) and a gain on the sale of certain utility property in South Carolina ($20 million).

**Other income** decreased 89%, primarily due to net investment losses in 2022 compared to net investment gains in 2021 on nuclear decommissioning trust funds ($1.1 billion), partially offset by an increase in non-service components of pension and other postretirement employee benefit plan credits ($109 million) and the absence of charges associated with the settlement of the South Carolina electric base rate case ($18 million).

**Interest and related charges** decreased 29%, primarily due to higher unrealized gains associated with freestanding derivatives ($511 million), higher premiums received on interest rate derivatives ($60 million), a decrease due to junior subordinated note repayments in 2021 ($52 million), benefits associated with the early redemption of certain securities in the third and fourth quarters of 2022 ($35 million) and the absence of charges associated with the early redemption of certain securities in the third quarter of 2021 ($23 million), partially offset by an increase from net debt issuances ($179 million), higher interest rates on commercial paper borrowings ($51 million), higher interest rates on variable rate debt and cash flow interest rate swaps ($29 million) and the absence of a benefit associated with the effective settlement of uncertain tax positions ($21 million).

**Income tax expense** decreased 84%, primarily due to lower pre-tax income including lower state income tax benefits on pre-tax losses from nuclear decommissioning trusts and economic hedges ($455 million) and higher investment tax credits ($36 million), partially offset by tax expense on the sale of Hope’s stock ($90 million) and the absence of benefits from the effective settlement of uncertain tax positions ($38 million) and a state legislative change ($21 million).

**Net income from discontinued operations including noncontrolling interests** decreased 99%, primarily due to the completion of the sale of the Q-Pipe Group in December 2021.

**Noncontrolling interests** decreased $26 million, primarily due to the absence of operations in connection with the sale of certain nonregulated solar generating projects held in partnerships.

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

| Year Ended December 31, (millions) | 2022 | $ Change | 2021 | $ Change | 2020 |
| --- | ---: | ---: | ---: | ---: | ---: |
| Net income | **$1,215** | **$(497)** | $1,712 | $691 | $1,021 |

### Overview

### 2022 VS. 2021

Net income decreased 29%, primarily due to a decrease in net investment earnings on nuclear decommissioning trust funds, a net decrease associated with the impacts of the 2021 Triennial Review, a charge for RGGI compliance costs deemed recovered through base rates, a charge in connection with a comprehensive settlement agreement for Virginia fuel expenses and dismantling costs associated with the early retirement of certain electric generation facilities.

### Analysis of Consolidated Operations

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

| Year Ended December 31, (millions) | 2022 | $ Change | 2021 | $ Change | 2020 |
| --- | ---: | ---: | ---: | ---: | ---: |
| Operating revenue | **$9,654** | **$2,184** | $7,470 | $(293) | $7,763 |
| Electric fuel and other energy-related purchases | **2,913** | **1,178** | 1,735 | 99 | 1,636 |
| Purchased (excess) electric capacity | **46** | **22** | 24 | 41 | (17) |
| Other operations and maintenance | **2,051** | **258** | 1,793 | 7 | 1,786 |
| Depreciation and amortization | **1,736** | **372** | 1,364 | 112 | 1,252 |
| Other taxes | **303** | **(23)** | 326 | (1) | 327 |
| Impairment of assets and other charges (benefits) | **557** | **826** | (269) | (1,362) | 1,093 |
| Other income | **—** | **(146)** | 146 | 66 | 80 |
| Interest and related charges | **642** | **108** | 534 | 18 | 516 |
| Income tax expense | **191** | **(206)** | 397 | 168 | 229 |

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

### 2022 VS. 2021

**Operating revenue** increased 29%, primarily reflecting:

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

These increases were partially offset by:

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

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

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

**Other operations and maintenance** increased 14%, primarily reflecting:

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

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

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

- The absence of a benefit from the establishment of a regulatory asset associated with the early retirement of certain coal- and oil-fired generating units associated with the settlement of the 2021 Triennial Review ($549 million);
- A charge in connection with a comprehensive settlement agreement for Virginia fuel expenses ($191 million);
- A charge for RGGI compliance costs deemed recovered through base rates ($180 million);
- Dismantling costs associated with the early retirement of certain electric generation facilities ($167 million); and
- A charge for the write-off of inventory ($19 million); partially offset by
- The absence of charges for CCRO benefits provided to retail electric customers in Virginia associated with Virginia Power’s 2021 Triennial Review ($188 million); and
- The absence of a charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to Virginia’s 2021 budget process ($77 million).

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

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

**Income tax expense** decreased 52%, primarily due to lower pre-tax income ($182 million) and higher investment tax credits ($66 million), partially offset by the recognition of an intercompany gain related to the transfer and subsequent contribution of existing privatization operations in Virginia to Dominion Privatization ($34 million) and the absence of the benefit from a state legislative change ($16 million).

### SEGMENT RESULTS OF OPERATIONS

Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit or loss. 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, (millions, except EPS) | 2022 Net income (loss) attributable to Dominion Energy | EPS(1) | 2021 Net income (loss) attributable to Dominion Energy | EPS(1) | 2020 Net income (loss) attributable to Dominion Energy | EPS(1) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Dominion Energy Virginia | **$2,008** | **$2.44** | $1,919 | $2.37 | $1,891 | $2.28 |
| Gas Distribution | **697** | **0.85** | 600 | 0.74 | 560 | 0.67 |
| Dominion Energy South Carolina | **505** | **0.61** | 437 | 0.54 | 419 | 0.51 |
| Contracted Assets | **335** | **0.41** | 431 | 0.53 | 402 | 0.48 |
| Corporate and Other | **(2,551)** | **(3.22)** | (99) | (0.20) | (3,673) | (4.51) |
| Consolidated | **$994** | **$1.09** | $3,288 | $3.98 | $(401) | $(0.57) |

*(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, | 2022 | % Change | 2021 | % Change | 2020 |
| --- | ---: | ---: | ---: | ---: | ---: |
| Electricity delivered (million MWh) | **90.0** | **6%** | 85.2 | 2% | 83.3 |
| Electricity supplied (million MWh): |  |  |  |  |  |
| Utility | **90.2** | **5** | 85.7 | (1) | 87.0 |
| Non-Jurisdictional | **1.5** | **50** | 1.0 | 43 | 0.7 |
| Degree days (electric distribution and utility service area): |  |  |  |  |  |
| Cooling | **1,765** | **(1)** | 1,783 | 1 | 1,759 |
| Heating | **3,555** | **11** | 3,210 | 8 | 2,970 |
| Average electric distribution customer accounts (thousands) | **2,724** | **1** | 2,697 | 1 | 2,661 |

69

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

### 2022 VS. 2021

| (millions, except EPS) | Increase (Decrease) Amount | EPS |
| --- | ---: | ---: |
| Weather | **$21** | **$0.03** |
| Customer usage and other factors | **25** | **0.03** |
| Customer-elected rate impacts | **13** | **0.02** |
| Base rate case impacts | **(41)** | **(0.05)** |
| Rider equity return | **64** | **0.08** |
| Storm damage and service restoration | **(17)** | **(0.02)** |
| Planned outage costs | **(12)** | **(0.01)** |
| Depreciation and amortization | **19** | **0.02** |
| Renewable energy investment tax credits | **65** | **0.08** |
| Salaries, wages and benefits & administrative costs | **26** | **0.03** |
| Interest expense, net | **(13)** | **(0.02)** |
| Other | **(61)** | **(0.07)** |
| Share dilution | **—** | **(0.05)** |
| Change in net income contribution | **$89** | **$0.07** |

### 2021 VS. 2020

| (millions, except EPS) | Increase (Decrease) Amount | EPS |
| --- | ---: | ---: |
| Weather | $44 | $0.05 |
| Customer usage and other factors | (26) | (0.03) |
| Customer-elected rate impacts | 46 | 0.06 |
| Rider equity return | 41 | 0.05 |
| Electric capacity | (28) | (0.03) |
| Outages | (14) | (0.02) |
| Depreciation and amortization | (18) | (0.02) |
| Renewable energy investment tax credits | 7 | 0.01 |
| Salaries, wages and benefits & administrative costs | (22) | (0.03) |
| Other | (2) | (0.01) |
| Share accretion | — | 0.06 |
| Change in net income contribution | $28 | $0.09 |

### Gas Distribution

Presented below are selected operating statistics related to Gas Distribution’s operations:

| Year Ended December 31, Gas distribution throughput (bcf): | 2022(1) | % Change | 2021 | % Change | 2020 |
| --- | ---: | ---: | ---: | ---: | ---: |
| Sales | **194** | **6%** | 183 | 2% | 180 |
| Transportation | **1,020** | **5** | 975 | 12 | 868 |
| Heating degree days (gas distribution service area): |  |  |  |  |  |
| North Carolina | **3,009** | **2** | 2,947 | 8 | 2,734 |
| Ohio and West Virginia | **5,514** | **8** | 5,121 | (1) | 5,148 |
| Utah, Wyoming, and Idaho | **5,170** | **6** | 4,874 | (2) | 4,973 |
| Average gas distribution customer accounts (thousands): |  |  |  |  |  |
| Sales | **1,944** | **—** | 1,935 | 2 | 1,897 |
| Transportation | **1,131** | **—** | 1,131 | 1 | 1,123 |

#### (1) Includes Hope through August 2022.

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

### 2022 VS. 2021

| (millions, except EPS) | Increase (Decrease) Amount | EPS |
| --- | ---: | ---: |
| Weather | **$4** | **$—** |
| Customer usage and other factors | **36** | **0.04** |
| Base rate case impacts | **29** | **0.04** |
| Rider equity return | **25** | **0.03** |
| Wexpro cost saving sharing incentives | **21** | **0.03** |
| Sale of Hope | **(11)** | **(0.01)** |
| Interest expense, net | **(16)** | **(0.02)** |
| Other | **9** | **0.01** |
| Share dilution | **—** | **(0.01)** |
| Change in net income contribution | **$97** | **$0.11** |

### 2021 VS. 2020

| (millions, except EPS) | Increase (Decrease) Amount | EPS |
| --- | ---: | ---: |
| Weather | $— | $— |
| Customer usage and other factors | 24 | 0.03 |
| Base rate case impacts | 7 | 0.01 |
| Rider equity return | 40 | 0.05 |
| Salaries, wages and benefits & administrative costs | (8) | (0.01) |
| Interest expense, net | 12 | 0.01 |
| Other | (35) | (0.04) |
| Share accretion | — | 0.02 |
| Change in net income contribution | $40 | $0.07 |

### Dominion Energy South Carolina

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

| Year Ended December 31, | 2022 | % Change | 2021 | % Change | 2020 |
| --- | ---: | ---: | ---: | ---: | ---: |
| Electricity delivered (million MWh) | **23.0** | **3%** | 22.4 | 1% | 22.1 |
| Electricity supplied (million MWh) | **24.1** | **3** | 23.5 | 2 | 23.0 |
| Degree days (electric and gas distribution service areas): |  |  |  |  |  |
| Cooling | **767** | **(11)** | 859 | 8 | 794 |
| Heating | **1,294** | **1** | 1,280 | 19 | 1,074 |
| Average electric distribution customer accounts (thousands) | **777** | **1** | 766 | 2 | 753 |
| Gas distribution throughput (bcf): |  |  |  |  |  |
| Sales | **68** | **(6)** | 72 | 9 | 66 |
| Average gas distribution customer accounts (thousands) | **427** | **4** | 412 | 3 | 399 |

71

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

### 2022 VS. 2021

| (millions, except EPS) | Increase (Decrease) Amount | EPS |
| --- | ---: | ---: |
| Weather | **$21** | **$0.03** |
| Customer usage and other factors | **38** | **0.05** |
| Customer-elected rate impacts | **14** | **0.02** |
| Base rate case & Natural Gas Rate Stabilization Act impacts | **22** | **0.03** |
| Capital cost rider | **(8)** | **(0.01)** |
| Gains on sales of property | **17** | **0.02** |
| Depreciation and amortization | **(15)** | **(0.02)** |
| Interest expense, net | **(16)** | **(0.02)** |
| Other | **(5)** | **(0.02)** |
| Share dilution | **—** | **(0.01)** |
| Change in net income contribution | **$68** | **$0.07** |

### 2021 VS. 2020

| (millions, except EPS) | Increase (Decrease) Amount | EPS |
| --- | ---: | ---: |
| Weather | $(6) | $(0.01) |
| Customer usage and other factors | 34 | 0.04 |
| Customer-elected rate impacts | 10 | 0.01 |
| Base rate case & Natural Gas Rate Stabilization Act impacts | 13 | 0.02 |
| Capital cost rider | (6) | (0.01) |
| Depreciation and amortization | (9) | (0.01) |
| Interest expense, net | 7 | 0.01 |
| Salaries, wages and benefits & administrative costs | (46) | (0.06) |
| Other | 21 | 0.02 |
| Share accretion | — | 0.02 |
| Change in net income contribution | $18 | $0.03 |

### Contracted Assets

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

| Year Ended December 31, | 2022 | % Change | 2021 | % Change | 2020 |
| --- | ---: | ---: | ---: | ---: | ---: |
| Electricity supplied (million MWh) | **17.8** | **(14)%** | 20.8 | 8% | 19.3 |

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

### 2022 VS. 2021

| (millions, except EPS) | Increase (Decrease) Amount | EPS |
| --- | ---: | ---: |
| Margin(1) | **$11** | **$0.01** |
| Sale of non-wholly-owned nonregulated solar facilities | **(20)** | **(0.02)** |
| Planned outage costs | **(19)** | **(0.02)** |
| Renewable energy investment tax credits | **(29)** | **(0.04)** |
| Interest expense, net | **(50)** | **(0.06)** |
| Other | **11** | **0.02** |
| Share dilution | **—** | **(0.01)** |
| Change in net income contribution | **$(96)** | **$(0.12)** |

*(1) Includes earnings associated with a 50% noncontrolling interest in Cove Point.*

### 2021 VS. 2020

| (millions, except EPS) | Increase (Decrease) Amount | EPS |
| --- | ---: | ---: |
| Margin(1) | $28 | $0.03 |
| Planned outage costs | 33 | 0.04 |
| Renewable energy investment tax credits | (43) | (0.05) |
| Absence of contract associated with Fowler Ridge | 14 | 0.02 |
| Other | (3) | — |
| Share accretion | — | 0.01 |
| Change in net income contribution | $29 | $0.05 |

*(1) Includes earnings associated with a 50% noncontrolling interest in Cove Point.*

### Corporate and Other

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

| Year Ended December 31, (millions, except EPS) | 2022 | 2021 | 2020 |
| --- | ---: | ---: | ---: |
| Specific items attributable to operating segments | **$(2,777)** | $(493) | $(1,241) |
| Specific items attributable to Corporate and Other segment | **266** | 590 | (2,166) |
| Total specific items | **(2,511)** | 97 | (3,407) |
| Other corporate operations: |  |  |  |
| Interest expense, net | **(329)** | (410) | (384) |
| Other | **289** | 214 | 118 |
| Total other corporate operations | **(40)** | (196) | (266) |
| Total net expense | **(2,551)** | (99) | (3,673) |
| EPS impact | **$(3.22)** | $(0.20) | $(4.51) |

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 2022, this primarily included a $255 million after-tax benefit for derivative mark-to-market changes. In 2021, this primarily included $641 million of net income from discontinued operations, primarily associated with the Q-Pipe Group, a $64 million after-tax benefit for derivative mark-to-market changes, $62 million of after-tax charges for workplace realignment, primarily related to a corporate office lease termination, and $32 million of after-tax charges for merger and integration-related costs associated with the SCANA Combination. In 2020, this primarily included $2.2 billion of after-tax loss associated with discontinued operations, including the results of operations of the entities included in the GT&S and Q-Pipe Transactions as well as charges associated with the cancellation of the Atlantic Coast Pipeline Project, $82 million of after-tax charges for merger and integration-related costs associated with the SCANA Combination, a $78 million after-tax benefit of derivative mark-to-market changes and a $69 million tax benefit associated with the GT&S Transaction.

### OUTLOOK

Dominion Energy’s 2023 net income is expected to increase on a per share basis as compared to 2022 primarily from the following:

- The absence of a charge associated with the impairment of certain nonregulated solar generation facilities;
- The absence of losses associated with the sale of Kewaunee;
- The absence of charges for certain Virginia Power RGGI compliance costs deemed recovered through base rates;
- The absence of a charge in connection with a comprehensive settlement agreement associated with Virginia fuel expenses; and
- Construction and operation of growth projects in electric utility and gas distribution operations.

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

- A decrease in investment tax credits associated with nonregulated solar generation facilities;
- An increase in interest expense;
- An increase in planned outage days at Millstone; and
- An increase in depreciation and amortization expense.

### 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, (millions) | 2022 | 2021 | 2020 |
| --- | ---: | ---: | ---: |
| Cash, restricted cash and equivalents at beginning of year | **$408** | $247 | $269 |
| Cash flows provided by (used in): |  |  |  |
| Operating activities | **3,700** | 4,037 | 5,227 |
| Investing activities | **(6,746)** | (6,247) | (2,916) |
| Financing activities | **2,979** | 2,371 | (2,333) |
| Net increase (decrease) in cash, restricted cash and equivalents | **(67)** | 161 | (22) |
| Cash, restricted cash and equivalents at end of year | **$341** | $408 | $247 |

#### Operating Cash Flows

Net cash provided by Dominion Energy's operating activities decreased $337 million, inclusive of a $201 million decrease from discontinued operations. Net cash provided by continuing operations decreased $136 million, primarily due to lower deferred fuel cost recoveries ($1.1 billion), current year refund payments to Virginia electric customers associated with the settlement of the 2021 Triennial Review ($319 million) and changes in working capital ($628 million), partially offset by lower margin deposits ($862 million) and an increase of $1.0 billion primarily as the result of higher operating cash flows from electric utility and gas distribution operations driven by riders, customer usage and other factors.

#### Investing Cash Flows

Net cash used in Dominion Energy’s investing activities increased $499 million, primarily due to an increase in plant construction and other property additions ($1.6 billion) and the absence of proceeds from the sale of Q-Pipe Group ($1.5 billion) and the sale of non-wholly-owned nonregulated solar facilities ($495 million), partially offset by the absence of the repayment of the Q-Pipe Transaction deposit ($1.3 billion), a decrease in contributions to equity method affiliates including Atlantic Coast Pipeline ($978 million) and net proceeds from the sale of Hope ($727 million).

#### Financing Cash Flows

Net cash provided by Dominion Energy's financing activities increased $608 million primarily due to settlement of the stock purchase contract component of the 2019 Equity Units ($1.6 billion), higher net issuances of long-term debt ($927 million) and higher net supplemental credit facility borrowings ($450 million), partially offset by the redemption of the Series A Preferred Stock ($1.6 billion) in 2022 and the absence of the issuance of Series C Preferred Stock ($742 million) in 2021.

### 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:

| (millions) At December 31, 2022 | Facility Limit | Outstanding Commercial Paper(1) | Outstanding Letters of Credit | Facility Capacity Available |
| --- | ---: | ---: | ---: | ---: |
| Joint revolving credit facility(2) | **$6,000** | **$3,076** | **$202** | **$2,722** |

*(1) The weighted-average interest rate of the outstanding commercial paper supported by Dominion Energy’s credit facility was 4.73% at December 31, 2022.*

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

#### Dominion Energy Reliability InvestmentSM Program

Dominion Energy has an effective registration statement with the SEC for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability InvestmentSM. The registration 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, 2022, Dominion Energy’s Consolidated Balance Sheets include $347 million presented within short-term debt, with a weighted-average interest rate of 4.24%. The proceeds are used for general corporate purposes and to repay debt.

#### Other Facilities

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

In January 2023, Dominion Energy entered into a $2.5 billion 364-Day term loan facility which bears interest at a variable rate and will mature in January 2024 with the proceeds to be used to repay existing long-term debt and short-term debt upon maturity and for other general corporate purposes. Concurrently, Dominion Energy borrowed an initial $1.0 billion with the proceeds used to repay long-term debt. Dominion Energy may make up to two additional borrowings under this agreement through March 31, 2023, at which point any unused capacity will cease to be available to Dominion Energy.

### Long-Term Debt

#### Sustainability Revolving Credit Facility

Dominion Energy maintains a $900 million Sustainability Revolving Credit Facility which matures in 2024 and bears interest at a variable rate. The facility offers a reduced interest rate margin with respect to borrowed amounts allocated to certain environmental sustainability or social investment initiatives. In May 2022, Dominion Energy borrowed $900 million with the proceeds used to support environmental sustainability and social investment initiatives ($450 million) and for general corporate purposes ($450 million). In June 2022, Dominion Energy repaid $450 million borrowed for general corporate purposes. At December 31, 2022, Dominion Energy had $450 million outstanding under this supplemental credit facility.

#### Issuances and Borrowings of Long-Term Debt

During 2022, 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.

| Month Type | Public / Private | Entity | Principal (millions) | Rate | Stated Maturity |
| --- | --- | --- | ---: | ---: | --- |
| January Senior notes | Public | Virginia Power | **$600** | **2.400%** | **2032** |
| January Senior notes | Public | Virginia Power | **400** | **2.950%** | **2051** |
| May Senior notes | Public | Virginia Power | **600** | **3.750%** | **2027** |
| May Senior notes | Public | Virginia Power | **600** | **4.625%** | **2052** |
| August Senior notes | Public | Dominion Energy | **400** | **4.350%** | **2032** |
| August Senior notes | Public | Dominion Energy | **600** | **4.850%** | **2052** |
| August Senior notes | Private | Questar Gas | **125** | **4.390%** | **2032** |
| August Senior notes | Private | Questar Gas | **125** | **4.700%** | **2052** |
| November Senior notes | Public | Dominion Energy | **850** | **5.375%** | **2032** |
| December Senior notes | Private | East Ohio | **250** | **6.190%** | **2032** |
| December Senior notes | Private | East Ohio | **250** | **6.380%** | **2052** |
| Total issuances and borrowings |  |  | **$4,800** |  |  |

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.

As the comprehensive business review announced in November 2022 is still in progress, Dominion Energy is uncertain as to the amount of long-term debt it anticipates issuing in 2023. Dominion Energy expects to issue long-term debt to satisfy cash needs for capital expenditures and maturing long-term debt to the extent such amounts are not satisfied from cash available from operations following the payment of dividends 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 2022:

|  |  |  |  |  |  |
| --- | --- | ---: | ---: | ---: | --- |
| Month Type | Entity | Principal | (1) | Rate | Stated Maturity |
|  |  | (millions) |  |  |  |
| Debt scheduled to mature in 2022 |  | **$806** |  | **various** |  |
| Early repurchases & redemptions |  |  |  |  |  |
| July Senior notes | Dominion Energy | **5** |  | **4.250%** | **2028** |
| Multiple Senior notes | Dominion Energy | **147** |  | **2.250%** | **2031** |
| Multiple Senior notes | Dominion Energy | **35** |  | **3.300%** | **2041** |
| Multiple Senior notes | Dominion Energy | **37** |  | **1.450%** | **2026** |
| Multiple Senior notes | Dominion Energy | **9** |  | **4.700%** | **2044** |
| Multiple Senior notes | Dominion Energy | **30** |  | **4.600%** | **2049** |
| Total repayments, repurchases and redemptions |  | **$1,069** |  |  |  |

*(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 April 2022, Virginia Power remarketed two series of tax-exempt bonds, with an aggregate outstanding principal of approximately $138 million to new investors. Both bonds will bear interest at a coupon of 1.65% until May 2024, after which they will bear interest at a market rate to be determined at that time.

In October 2022, Dominion Energy remarketed its $27 million Peninsula Ports Authority of Virginia Coal Terminal Revenue Refunding Bonds, Series 2003 due in 2033 to new investors. The bonds will bear interest at a coupon rate of 3.80% until October 2024, after which they will bear interest at a market rate to be determined at that time.

In 2023, Dominion Energy expects to remarket approximately $160 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 17, 2023 are as follows:

|  |  |  |  |
| --- | --- | --- | --- |
|  | Fitch | Moody's | Standard & Poor's |
| **Dominion Energy** |  |  |  |
| Issuer | **BBB+** | **Baa2** | **BBB+** |
| Senior unsecured debt securities | **BBB+** | **Baa2** | **BBB** |
| Junior subordinated notes | **BBB** | **Baa3** | **BBB** |
| Enhanced junior subordinated notes | **BBB-** | **Baa3** | **BBB-** |
| Preferred stock | **BBB-** | **Ba1** | **BBB-** |
| Commercial paper | **F2** | **P-2** | **A-2** |
| 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 364-Day term loan facility entered into in January 2023, and cross-default provisions.

As of December 31, 2022, 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%** | **59.7%** |

*(1) Indebtedness as defined by the agreements excludes certain junior subordinated notes reflected as long-term debt as well as AOCI reflected as equity in the Consolidated Balance Sheets. Capital is inclusive of preferred stock whether classified as equity or mezzanine equity.*

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, 2022, there have been no events of default under Dominion Energy’s covenants.

### Common Stock, Preferred Stock and Other Equity Securities

#### Issuances of Equity Securities

Dominion Energy maintains Dominion Energy Direct® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In 2021, Dominion Energy began issuing new shares of common stock for these direct stock purchase plans. During 2022, Dominion Energy issued 2.4 million of such shares and received proceeds of $179 million.

Dominion Energy also maintains sales agency agreements to effect sales under an at-the-market program. Under the sales agency agreements, Dominion Energy may, from time to time, offer and sell shares of its common stock through the sales agents or enter into one or more forward sale agreements with respect to shares of its common stock. Sales by Dominion Energy through the sales agents or by forward sellers pursuant to a forward sale agreement cannot exceed $1.0 billion in the aggregate. In November 2021, Dominion Energy entered forward sale agreements for approximately 1.1 million shares of its common stock to be settled by November 2022 at an initial forward price of $74.66 per share. Except in certain circumstances, Dominion Energy could have elected physical, cash or net settlement of the forward sale agreements. In November 2022, Dominion Energy provided notice to elect physical settlement of the forward sale agreements and in December 2022 received total proceeds of $78 million.

In addition, Dominion Energy issued shares of its common and preferred stock, as discussed in Notes 19 and 20 to the Consolidated Financial Statements, respectively, as follows:

- In May 2022, Dominion Energy issued 0.9 million shares of its common stock, valued at $72 million, to partially satisfy DESC’s remaining obligation under a settlement agreement with the SCDOR discussed in Note 23 to the Consolidated Financial Statements.
- In June 2022, Dominion Energy issued 0.4 million shares of its common stock, valued at $30 million, to partially satisfy its obligation under a settlement agreement for the State Court Merger Case discussed in Note 23 to the Consolidated Financial Statements.
- In June 2022, Dominion Energy issued 19.4 million shares to settle the stock purchase contract component of the 2019 Equity Units and received proceeds of $1.6 billion. See Note 19 to the Consolidated Financial Statements for additional information.

As the comprehensive business review announced in November 2022 is still in progress, Dominion Energy is uncertain as to the amount of common stock that it anticipates issuing in 2023, including through its at-the-market program. However, Dominion Energy anticipates raising similar amounts of capital through Dominion Energy Direct® in 2023 compared to 2022 and 2021. The raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.

#### Repurchases of Equity Securities

In November 2020, the Board of Directors authorized the repurchase of up to $1.0 billion of Dominion Energy’s common stock. This repurchase program does not include a specific timetable or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors. At December 31, 2022, Dominion Energy had $920 million of available capacity under this authorization.

Dominion Energy does not plan to repurchase shares of common stock in 2023, 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.

In September 2022, Dominion Energy redeemed all outstanding shares of Series A Preferred Stock for $1.6 billion.

### Capital Expenditures

See Note 26 to the Consolidated Financial Statements for Dominion Energy’s historical capital expenditures by segment. Dominion Energy included its total annual planned capital expenditures by each segment for 2022 through 2026 in Item 7. MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 24, 2022. As disclosed therein, Dominion Energy’s total planned capital expenditures were $10.3 billion for 2023, $10.7 billion for 2024, $10.6 billion for 2025 and $7.7 billion for 2026 based on a capital expenditures plan reviewed and endorsed by Dominion Energy’s Board of Directors in December 2021. As a result of the comprehensive business review announced in November 2022, Dominion Energy has not completed an update to its previous plan and, as discussed in *Future Issues and Other Matters*, the implementation of the recommendations could result in a material adjustment to capital allocations. Currently, Dominion Energy expects the total planned capital expenditures for 2023 to be substantially consistent with the previously disclosed amount. In addition, Dominion Energy expects its next capital expenditures plan to reflect an acceleration of electric transmission projects within Dominion Energy Virginia to serve the rapidly growing data center customer demand and a decreased investment in new nonregulated solar generation facilities within Contracted Assets.

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, Gas Distribution, Dominion Energy South Carolina* and *Contracted Assets* in Item 1. Business for additional discussion of various significant capital projects currently under development. The estimates disclosed above are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. Dominion Energy may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.

### Dividends

Dominion Energy believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In December 2022, Dominion Energy’s Board of Directors established an annual dividend rate for 2023 of $2.67 per share of common stock, consistent with the 2022 rate. Dividends are subject to declaration by the Board of Directors. In February 2023, Dominion Energy’s Board of Directors declared dividends payable in March 2023 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, 2022, 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, 2022 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.

| (millions) | Gross Credit Exposure | Credit Collateral | Net Credit Exposure |
| --- | ---: | ---: | ---: |
| Investment grade(1) | **$191** | **$—** | **$191** |
| Non-Investment grade(2) | **37** | **20** | **17** |
| No external ratings: |  |  |  |
| Internally rated—investment grade(3) | **58** | **—** | **58** |
| Internally rated—non-investment grade(4) | **28** | **13** | **15** |
| Total | **$314** | **$33** | **$281** |

79

*(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 51% of the total net credit exposure.*

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

*(3) The five largest counterparty exposures, combined, for this category represented approximately 21% of the total net credit exposure.*

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

### Fuel and Other Purchase Commitments

Dominion Energy is party to various contracts for fuel and purchased power commitments related to both its regulated and nonregulated operations. Total estimated costs for such commitments at December 31, 2022 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.

| (millions) | 2023 | 2024 | 2025 | 2026 | 2027 | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Purchased electric capacity for utility operations | **$71** | **$70** | **$70** | **$72** | **$73** | **$356** |
| Fuel commitments for utility operations | **1,669** | **995** | **599** | **185** | **184** | **3,632** |
| Fuel commitments for nonregulated operations | **198** | **133** | **46** | **37** | **50** | **464** |
| Pipeline transportation and storage | **668** | **587** | **489** | **427** | **376** | **2,547** |
| Total | **$2,606** | **$1,785** | **$1,204** | **$721** | **$683** | **$6,999** |

### 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, 2022. Such obligations include:

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

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

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

### FUTURE ISSUES AND OTHER MATTERS

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

### Business Review

In November 2022, Dominion Energy announced the commencement of a business review of value-maximizing strategic business actions, alternatives to its current business mix and capital allocation and regulatory options which may assist customers to manage costs and provide greater predictability to its long-term, state-regulated utility value proposition. While the ultimate impacts cannot be estimated until the review is completed, which is expected in 2023, implementation of recommendations resulting from the business review could have a material impact on Dominion Energy's future results of operations, financial condition and/or cash flows.

### Potential Virginia Legislation

The 2023 General Assembly session in Virginia has included several proposals which, if ultimately enacted into law, could have a material impact on Virginia Power’s retail base rates and other cost-recovery mechanisms. Items under consideration include the frequency of base rate reviews, eliminating CCROs, shifting recovery of certain costs currently recovered through riders into base rates and adjusting the parameters for determining an acceptable ROE and revenue sharing. Other topics include securitization of deferred fuel costs, offshore wind financing and small modular reactors. As the legislative process remains underway, Dominion Energy is unable to estimate the potential financial statement impacts related to matters currently under consideration by the Virginia General Assembly, but there could be a material impact to its results of operations, financial condition and/or cash flows.

### Future Environmental Regulations

### Climate Change

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

### State Actions Related to Air and GHG Emissions

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

### Inflation Reduction Act

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

### PHMSA Regulation

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

### Dodd-Frank Act

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

### North Anna

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

### Federal Income Tax Laws

### Inflation Reduction Act

The IRA imposes a 15% alternative minimum tax on GAAP net income, as adjusted for certain items, of corporations in excess of $1 billion, for tax years beginning after December 31, 2022. Entities that are subject to the alternative minimum tax may use tax credits to reduce the liability by up to 75% and will receive a tax credit carryforward with an indefinite life that can be claimed against the regular tax in future years. Pending additional 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.

## Market risk

As filed, 10,994 characters.

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

### MARKET RISK SENSITIVE INSTRUMENTS AND RISK MANAGEMENT

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

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

### Commodity Price Risk

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

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

A hypothetical 10% increase in commodity prices would have resulted in a decrease of $52 million and $16 million in the fair value of Dominion Energy’s commodity-based derivative instruments as of December 31, 2022 and 2021, respectively.

A hypothetical 10% increase in commodity prices would have resulted in a decrease of $25 million and $6 million in the fair value of Virginia Power’s commodity-based derivative instruments as of December 31, 2022 and 2021, respectively.

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

### Interest Rate Risk

The Companies manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For variable rate debt outstanding for Dominion Energy, a hypothetical 10% increase in market interest rates would result in a $37 million and $6 million decrease in earnings at December 31, 2022 and 2021, respectively. For variable rate debt outstanding for Virginia Power, a hypothetical 10% increase in market interest rates would result in a $14 million and less than $1 million decrease in earnings at December 31, 2022 and 2021, respectively.

The Companies also use interest rate derivatives, including forward-starting swaps, interest rate swaps and interest rate lock agreements to manage interest rate risk. As of December 31, 2022, Dominion Energy and Virginia Power had $12.7 billion and $3.6 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $274 million and $156 million, respectively, in the fair value of Dominion Energy and Virginia Power’s interest rate derivatives at December 31, 2022. As of December 31, 2021, Dominion Energy and

Virginia Power had $11.4 billion and $2.8 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $191 million and $111 million, respectively, in the fair value of Dominion Energy and Virginia Power’s interest rate derivatives at December 31, 2021.

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

### Foreign Currency Exchange Rate Risk

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

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

### Investment Price Risk

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

Dominion Energy recognized net investment losses (including investment income) on nuclear decommissioning and rabbi trust investments of $888 million and net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $1.1 billion for the years ended December 31, 2022 and 2021, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion Energy recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on debt investments of $196 million and $64 million for the years ended December 31, 2022 and 2021, respectively.

Virginia Power recognized net investment losses (including investment income) on nuclear decommissioning and rabbi trust investments of $426 million and net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $568 million for the years ended December 31, 2022 and 2021, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on debt investments of $106 million and $31 million for the years ended December 31, 2022 and 2021, respectively.

Dominion Energy sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power employees participate in these plans. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns (losses) of $(3.0) billion and $1.5 billion in 2022 and 2021, respectively, versus expected returns of $1.1 billion and $1.0 billion, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. A hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion Energy’s plan assets would result in an increase in the following year's net periodic cost of $26 million and $27 million as of December 31, 2022 and 2021, respectively, for pension benefits and $5 million and $6 million as of December 31, 2022 and 2021, respectively, for other postretirement benefits.

### Risk Management Policies

The Companies have established operating procedures with corporate management to ensure that proper internal controls are maintained. In addition, Dominion Energy has established an independent function at the corporate level to monitor compliance with the credit and commodity risk management policies of all subsidiaries, including Virginia Power. Dominion Energy maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion Energy also monitors the financial condition of existing counterparties on an ongoing basis. Based on these credit policies and the Companies’ December 31, 2022 provision for credit losses, management believes that it is unlikely that a material adverse effect on the Companies’ financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

## Controls and procedures

As filed, 11,645 characters.

### Dominion Energy

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

### Management’s Annual Report on Internal Control over Financial Reporting

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

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

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

SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion Energy’s 2022 Annual Report to contain a management's report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for the report, Dominion Energy tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2022, Dominion Energy makes the following assertions:

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

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

Management evaluated Dominion Energy’s internal control over financial reporting as of December 31, 2022. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion Energy maintained effective internal control over financial reporting as of December 31, 2022.

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

### REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

### Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Dominion Energy, Inc. and subsidiaries (“Dominion Energy”) at December 31, 2022, based on criteria established in *Internal Control — Integrated Framework (2013)* issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, Dominion Energy maintained, in all material respects, effective internal control over financial reporting at December 31, 2022, based on criteria established in *Internal Control — Integrated Framework (2013)* issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements at and for the year ended December 31, 2022, of Dominion Energy and our report dated February 21, 2023, expressed an unqualified opinion on those consolidated financial statements.

### Basis for Opinion

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

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

### Definition and Limitations of Internal Control over Financial Reporting

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

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

/s/ Deloitte & Touche LLP

Richmond, Virginia

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

### Management’s Annual Report on Internal Control over Financial Reporting

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

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

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

SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Virginia Power's 2022 Annual Report to contain a management's report regarding the effectiveness of internal control. As a basis for the report, Virginia Power tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2022, Virginia Power makes the following assertions:

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

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

Management evaluated Virginia Power's internal control over financial reporting as of December 31, 2022. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Virginia Power maintained effective internal control over financial reporting as of December 31, 2022.

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

Filed Feb 21, 2023.
Source: SEC EDGAR, the filing index for accession 0000950170-23-003287. Last ingested by Listed: Nov 6, 2026, 17:22 ET. No prices; not investment advice.