DOMINION ENERGY, INC
Item 1. Business
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’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, 2020, Dominion Energy’s portfolio of assets includes approximately 30.2 GW of electric generating capacity, 10,500 miles of electric transmission lines, 85,600 miles of electric distribution lines and 94,200 miles of gas distribution mains and related service facilities, which are supported by 6,200 miles of gas transmission, gathering and storage pipeline. In addition, Dominion Energy owns approximately 2,400 miles of gas transmission, gathering and storage pipeline through entities under agreement to be sold to BHE. As of December 31, 2020, Dominion Energy operates in 16 states and serves more than 7 million customers.
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 growth capital expenditure plan for 2021 through 2025 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 is currently seeking license extensions for its regulated nuclear power stations in Virginia. Other drivers for the growth capital plan include renewable natural gas initiatives and the replacement and modernization of gas distribution pipeline. Dominion Energy also plans to continue upgrading its gas and electric transmission and distribution networks while also meeting environmental requirements and standards set by various regulatory bodies.
Dominion Energy has continued its transition to a more state-regulated earnings mix as evidenced by its capital investments in regulated infrastructure, the SCANA and Dominion Energy Questar Combinations, the partially completed sale of substantially all of its gas transmission and storage operations to BHE and the divestiture of interests in certain nonregulated generating facilities and natural gas gathering and processing investments. Dominion Energy 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 of primarily long-term contracted electric generation operations and its investment in Cove Point. Dominion Energy’s operations are conducted through various subsidiaries, including Virginia Power.
In January 2019, Dominion Energy completed the SCANA Combination in a stock-for-stock merger valued at $13.4 billion. SCANA, which operates as a wholly-owned subsidiary of Dominion Energy, is primarily engaged in the generation, transmission and distribution of electricity in the central, southern and southwestern portions of South Carolina and in the distribution of natural gas in North Carolina and South Carolina. DESC, a wholly-owned subsidiary of SCANA, is consolidated by Dominion Energy and remains 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
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 October 2020, Dominion Energy entered into an agreement for the Q-Pipe Transaction with BHE for $1.3 billion in cash consideration and the assumption by BHE of approximately $430 million of related long-term debt. This transaction is expected to close in early 2021, contingent on clearance or approval under the Hart-Scott-Rodino Act and other customary closing and regulatory conditions.
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 to acquire 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.
Purchase of Dominion Energy Midstream Units
In January 2019, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned by Dominion Energy through the issuance of 22.5 million shares of Dominion Energy common stock. See Note 20 to the Consolidated Financial Statements for additional information. Dominion Energy Midstream was included within the GT&S Transaction and sold to BHE in November 2020.
Sale of Interest in Cove Point
In December 2019, Dominion Energy completed the sale of a 25% noncontrolling interest in Cove Point to Brookfield in exchange for cash consideration of $2.1 billion, subject to working capital adjustments. See Note 3 to the Consolidated Financial Statements for additional information.
In addition, a 25% controlling interest in Cove Point was included within the GT&S Transaction and sold to BHE in November 2020.
SCANA
In January 2019, Dominion Energy and SCANA completed a stock-for-stock merger valued at $13.4 billion, inclusive of SCANA’s outstanding debt, which totaled $6.9 billion at closing. SCANA operates as a wholly-owned subsidiary of Dominion Energy. See Note 3 to the Consolidated Financial Statements for additional information.
Electric Generation Facilities
Acquisition of Virginia Power Solar Projects
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 $580 million once constructed, including initial acquisition costs, and generate approximately 282 MW.
In 2019, Virginia Power entered into agreements to acquire various solar development projects in Virginia, with the acquisitions completed in 2019 and 2020. These projects are expected to cost a total of approximately $765 million once constructed, including initial acquisition costs, and generate approximately 448 MW combined.
In 2018, Virginia Power entered into agreements to acquire various solar development projects in North Carolina and Virginia. These projects closed in 2019 with a total cost of $297 million, including initial acquisition costs, and generate 175 MW combined.
See Notes 10 and 13 to the Consolidated Financial Statements for additional information.
Acquisition of Nonregulated Solar Projects
In 2020, Dominion Energy entered into agreements and completed the acquisition of various nonregulated solar projects in Ohio, South Carolina and Virginia with one project expected to close in 2022. These projects are expected to cost a total of approximately $730 million once constructed, including the initial acquisition cost, and generate approximately 398 MW combined.
In 2019, Dominion Energy completed the acquisition of various nonregulated solar projects in North Carolina, South Carolina and Virginia. These projects cost $415 million to construct, including the initial acquisition cost, and generate approximately 242 MW combined.
See Note 10 to the Consolidated Financial Statements for additional information.
Sale of Certain Nonregulated Generation Facilities
In December 2018, Dominion Energy completed the sale of Fairless and Manchester for total consideration of $1.2 billion, subject to customary closing adjustments. See Note 10 to the Consolidated Financial Statements for additional information.
Equity Method Investments
Acquisition of Interest in Wrangler
In December 2019, Dominion Energy acquired a 20% noncontrolling interest in Wrangler along with $301 million in cash as part of its initial contribution of certain retail energy marketing operations. In November 2020, Dominion Energy completed the second contribution consisting of certain retail energy natural gas contracts, receiving $74 million in cash and maintaining its 20% noncontrolling interest in Wrangler. See Note 9 to the Consolidated Financial Statements for additional information.
Sale of Interest in Blue Racer
In December 2018, Dominion Energy completed the sale of its 50% limited partner interest in Blue Racer for total consideration of $1.2 billion. In addition, the purchaser agreed to pay additional consideration contingent upon the achievement of certain financial performance milestones of Blue Racer from 2019 through 2021. 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, 2020, Dominion Energy had approximately 17,300 full-time employees, of which approximately 4,700 are subject to collective bargaining agreements, including approximately 6,000 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 2020, Dominion Energy experienced an OSHA Recordable Rate of 0.41 compared to 0.62 in 2019. These rates reflect Dominion Energy’s dedication to safety when compared to a 2019 BLS Industry Average OSHA Recordable Rate of 2.05. 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, including requirements to wear face coverings and maintain physical distancing as well as new procedures for enhanced cleaning and temperature screening. Dominion Energy also facilitated telecommuting 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 and inclusion while fostering an environment where employees can utilize their unique strengths, skills, personalities and life experiences. In October 2020, Dominion Energy announced its commitment to increase workforce diversity by 1% annually until it achieves at least 40% diverse representation. During 2020, Dominion Energy increased diverse representation within its workforce from 33.2% to 34.6%. For the purposes of measuring diversity, Dominion Energy includes non-minority female, minority male, minority female and undeclared female. In 2020 and 2019, the percentage of new hires that are diverse was 50% and 45%, 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 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 and inclusion training.
Dominion Energy attracts and retains its employees by offering competitive compensation and benefits packages, including healthcare, retirement, paid time off, parental leave and other benefits. Dominion Energy also offers a variety of training and development opportunities for all employees with the goal to provide a consistent and progressive approach to training that engages the workforce and fosters a culture of learning. To this end, Dominion Energy offers continuous learning opportunities including tuition assistance programs, professional development resources, access to a career center and a self-guided training program for independent learning as well as leadership development programs. These resources and programs are designed not only to engage and retain talented employees but also to allow Dominion Energy to meet the needs of its customers in an ever-changing industry with a skilled workforce.
OPERATING SEGMENTS
Beginning in September 2020, 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 nonregulated retail energy marketing operations, including Dominion Energy’s noncontrolling interest in Wrangler. 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 of Dominion Energy’s gas transmission and storage operations as discussed in Note 3 to the Consolidated Financial Statements and its 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
The Dominion Energy Virginia Operating Segment 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.
Virginia Power’s growth capital plan includes spending approximately $24 billion from 2021 through 2025 to upgrade or add new transmission lines, distribution lines, substations, and other facilities, as well as maintain existing and construct new generation capacity to meet its renewable generation targets and growing electricity demand within its service territory in order to maintain reliability and regulatory compliance. 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 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.
Virginia Power has also created a ten-year plan to transform its electric grid into a smarter, stronger and greener grid. This plan will address 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. In 2019 and 2020, the Virginia Commission approved portions of this plan.
Revenue provided by electric distribution and generation operations is based primarily on rates established by the Virginia and North Carolina Commissions. Approximately 82% 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 146 minutes for the three-year average ending 2020, up from the previous three-year average of 138 minutes. This increase is primarily due to increased storm activity.
Earnings may 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 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 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.
Virginia Power is developing, financing and constructing new generation capacity as well as seeking license extensions on zero carbon generation facilities to meet its renewable generation targets and growing electricity demand within its service territory. Significant projects under construction or development are set forth below:
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Virginia Power plans to acquire or construct several solar facilities, including facilities currently under development, totaling approximately 2.2 GW of expected generating capacity and approximately $4.1 billion of investments. See Notes 10 and 13 to the Consolidated Financial Statements for more information.
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Virginia Power has submitted applications with the NRC for 20-year extensions of its operating licenses at North Anna and Surry. See Nuclear Decommissioning below for more information on these facilities.
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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 for more information on this project.
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Virginia Power is considering the construction of an approximately $2 billion hydroelectric pumped storage facility in Southwest Virginia.
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Virginia Power has announced an approximately $400 million project to replace approximately 1,250 diesel buses with electric buses at school districts in Virginia by 2026.
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In November 2018, Virginia Power received approval from the Virginia Commission for its petition seeking a prudency determination as provided in the GTSA with respect to the Coastal Virginia Offshore Wind Pilot project, consisting of two 6 MW wind turbine generators located 27 miles off the coast of Virginia Beach, Virginia in federal waters, and for a CPCN for the generation tie line connecting the generators to shore. This project was placed into service in January 2021 at a cost of approximately $300 million.
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In September 2019, Virginia Power filed applications with PJM for the Coastal Virginia Offshore Wind Commercial project to interconnect 2,640 MW of wind energy off the coast of Virginia adjacent to the Coastal Virginia Offshore Wind Pilot project. The project is expected to be placed in service by the end of 2026 with total cost of the project estimated at approximately $8 billion.
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Virginia Power is considering the construction of simple cycle combustion turbines in Virginia for reliability purposes with an expected total cost of approximately $750 million.
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 capital expenditures of approximately $1.5 billion from 2021 through 2025.
Virginia Power is investing in transmission substation physical security and expects to invest an additional $110 million to $160 million through 2025 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 2028. The Virginia Commission has approved four phases of the program encompassing approximately 1,350 miles of converted lines and $545 million in capital spending (with $523 million recoverable through Rider U).
See Note 13 to the Consolidated Financial Statements for more 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 included as contractual obligations in Future Cash Payments for Contractual Obligations and Planned Capital Expenditures in Item 7. MD&A.
Presented below is a summary of Virginia Power’s actual system output by energy source:
(1)
Excludes ODEC’s 11.6% undivided ownership interest in North Anna.
(2)
Excludes ODEC’s 50.0% undivided ownership interest in the Clover power station.
(3)
Includes solar and biomass.
Nuclear Fuel-Virginia Power primarily utilizes long-term contracts to support its nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent on the market environment. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal cost and inventory levels.
Fossil Fuel- Virginia Power primarily utilizes natural gas and coal in its fossil fuel plants. All recent fossil fuel plant construction involves natural gas generation.
Virginia Power’s natural gas and oil supply is obtained from various sources including purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, purchases from local producers in the Appalachian area and Marcellus and Utica regions, purchases from gas marketers and withdrawals from underground storage fields owned by third parties. Virginia Power manages a portfolio of natural gas transportation contracts (capacity) that provides for reliable natural gas deliveries to its gas turbine fleet, while minimizing costs.
Virginia Power’s coal supply is obtained through long-term contracts and short-term spot agreements from domestic suppliers.
Biomass- Virginia Power’s biomass supply is obtained through long-term contracts and short-term spot agreements from local suppliers.
Purchased Power- Virginia Power purchases electricity from the PJM spot market and through power purchase agreements with other suppliers to provide for utility system load requirements.
Seasonality
Virginia Power’s earnings vary seasonally as a result of the impact of changes in temperature, the impact of storms and other catastrophic weather events, and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs, respectively. An increase in heating degree days for Virginia Power’s electric utility-related operations does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials and because alternative heating sources are more readily available.
Nuclear Decommissioning
Virginia Power has a total of four licensed, operating nuclear reactors at Surry and North Anna in Virginia.
Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. Amounts collected from ratepayers are 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 2032 to 2078. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. In 2018, Virginia Power applied for renewal of its operating licenses for an additional 20 years for the two nuclear units at Surry. Under these renewal applications, the two nuclear units will be allowed to generate electricity through 2052 and 2053, if approved. Virginia Power also submitted a license renewal application for the two units at North Anna in 2020. Under these renewal applications, the two nuclear 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 $3 billion to $4 billion over the next several years 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:
(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 all units.
(2)
Virginia Power did not make any contributions to its nuclear decommissioning trust funds during 2020.
(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 further information about nuclear decommissioning trust investments, AROs and nuclear decommissioning, respectively.
GAS DISTRIBUTION
The Gas Distribution Operating Segment of Dominion Energy includes Dominion Energy’s regulated natural gas sales, transportation, gathering, storage and distribution operations in Ohio, West Virginia, North Carolina, Utah, southwestern Wyoming and southeastern Idaho (through East Ohio, Hope, PSNC and Questar Gas) which collectively serve approximately 3.1 million residential, commercial and industrial customers. The Gas Distribution Operating Segment 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 growth capital plan includes spending approximately $5 billion from 2021 through 2025 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 outside its service territory. 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.
Earnings for the Gas Distribution Operating Segment of Dominion Energy primarily result from rates established by the Ohio, West Virginia, 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.
Competition
Questar Gas and Hope do not currently face direct competition from other distributors of natural gas for residential and commercial customers in their service territories as state regulations in Utah, Wyoming and Idaho for Questar Gas, and West Virginia for Hope, do not allow customers to choose their provider at this time. See State Regulations in Regulation for additional information.
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, 2020, 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.
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, West Virginia, North Carolina, Utah, Wyoming and Idaho Commissions as well as PHMSA and the U.S. Department of Transportation. See Federal Regulations and State Regulations in Regulation for more 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 December 2020, East Ohio filed an application with the Ohio Commission to extend the PIR program for an additional five years with continuation of 3% increases per year. See Note 13 to the Consolidated Financial Statements for further 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. See Note 13 to the Consolidated Financial Statements for further information.
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 2019 base rate case, the Utah Commission approved an annual spending budget of $72 million for the replacement program, 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. The legislation allows Questar Gas to spend up to $50 million over three years, and up to $125 million over five years, 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. See Note 13 to Consolidated Financial Statements for more information.
The Utah Commission has provided approval for Questar Gas to construct an LNG storage facility with a liquefaction rate of 8.2 million cubic feet per day. The project is expected to cost approximately $200 million, excluding financing costs, and is anticipated to be placed into service in late 2022.
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 2020 project noted below, for the period 2021 to 2023 is expected to be approximately $111 million.
During 2019, construction began on 38 miles of transmission pipeline between Franklinton, North Carolina and Clayton, North Carolina, which will provide the capacity necessary to support the growing natural gas demand in PSNC’s service territory. The project is expected to cost approximately $155 million, excluding financing costs, and is anticipated to be placed into service in 2021.
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 $55 million and is anticipated to be placed into service in late 2021.
Non-Utility Renewable Natural Gas-In December 2019, Dominion Energy announced the formation of a nationwide partnership 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. Dominion Energy expects to invest $200 million to develop the related assets. During 2020, construction began of a renewable natural gas facility in Greeley, Colorado, expected to cost approximately $70 million, excluding financing costs, and to be placed in service in late 2022.
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, Arizona and California 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 produced 11,200 Dths of renewable natural gas through December 31, 2020.
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 Agreement and the Wexpro II Agreement, comprehensive agreements with the states of Utah and Wyoming.
Seasonality
Gas Distribution’s 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. Historically, the majority of these earnings have been generated 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 have reduced the earnings impact of weather-related fluctuations.
DOMINION ENERGY SOUTH CAROLINA
The Dominion Energy South Carolina Operating Segment is comprised of DESC’s generation, transmission and distribution of electricity to approximately 758,000 customers in the central, southern and southwestern portions of South Carolina and the distribution of natural gas to approximately 405,000 residential, commercial and industrial customers in South Carolina.
DESC’s growth capital plan includes spending approximately $2 billion from 2021 through 2025 to upgrade existing or add new infrastructure to meet growing energy needs within its service territory and maintain reliability.
Revenue provided by DESC’s electric distribution operations is based primarily on rates established by the South Carolina Commission. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures.
DESC’s electric transmission operations serve its electric distribution operations as well as certain wholesale customers. Revenue provided by such electric transmission operations is based on a FERC-approved formula rate mechanism under DESC’s open access transmission tariff or based on retail rates established by the South Carolina Commission.
Revenue provided by DESC’s electric generation operations is primarily derived from the sale of electricity generated by its utility generation assets and is based on rates established by the South Carolina Commission. Variability in earnings may arise when revenues are impacted by factors not reflected in current rates, such as the impact of weather, customer demand or the timing and nature of expenses or outages. Electric operations continue to focus on improving service and experience levels while striving to reduce costs and link investments to operational results. SAIDI performance results, excluding major events, were 87 minutes for the three-year average ending 2020, compared to the previous three-year average of 85 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 Virginia-Carolinas Reliability 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.
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 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 for more 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. DESC has completed the installation of over 132,000 of the planned 1.1 million smart meters. This project is estimated to cost approximately $140 million and will be completed in March 2023.
In 2020, DESC continued several electric transmission projects in connection with two new nuclear plants under development by Southern. These transmission projects are required to be in place prior to these plants beginning operations to maintain reliability.
These projects, costing approximately $75 million in aggregate, will go into service in phases through 2022. The first phase of approximately six miles was completed in November 2020 with another phase of approximately 13 miles scheduled to be completed in early 2021.
Sources of Energy Supply
DESC uses a variety of fuels to power its electric generation fleet and purchases power for utility system load requirements. Presented below is a summary of DESC’s actual system output by energy source:
(1)
Dominion Energy did not acquire DESC until January 2019. These amounts represent data obtained as part of the due diligence performed by Dominion Energy prior to the SCANA Combination.
(2)
Excludes Santee Cooper’s 33.3% undivided ownership interest in Summer.
(3)
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 South Carolina through firm transportation agreements with various counterparties, which expire between 2021 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. These contracts provide for approximately 2.1 million tons annually. These contracts will expire at various times throughout 2021 and 2022. 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 is considering 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:
(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 2020.
CONTRACTED ASSETS
The Contracted Assets Operating Segment includes the operations of Millstone, and associated energy marketing and price risk activities, Dominion Energy’s nonregulated long-term contracted renewable electric generation fleet and Dominion Energy’s 50% noncontrolling interest in Cove Point.
Contracted Asset’s growth capital plan includes spending $2 billion from 2021 through 2025 to expand its renewable generation fleet.
The Contracted Assets Operating Segment 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 numerous renewable generation facilities, including solar generation in operation or development in ten 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 compete 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, 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 Army Corps of Engineers and other federal, state and local authorities. See Regulation, Future Issues and Other Matters in Item 7, MD&A and Notes 13 and 23 to the Consolidated Financial Statements for more information.
Properties
For a listing of facilities, see Item 2. Properties.
Dominion Energy plans to acquire or construct certain solar facilities in the Mid-Atlantic and Midwest. See Note 10 to the Consolidated Financial Statements for more 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, as well as for its FERC-regulated operations any changes in rates and the 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.
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 included as contractual obligations in Future Cash Payments for Contractual Obligations and Planned Capital Expenditures 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. In May 2013, Dominion Energy ceased operations at its single Kewaunee unit in Wisconsin and commenced decommissioning activities using the SAFSTOR methodology. The planned decommissioning completion date is 2073, which is within the NRC allowed 60-year window.
As part of Dominion Energy’s acquisition of both Millstone and Kewaunee, it acquired decommissioning funds for the related units. Any funds remaining in Kewaunee’s trust after decommissioning is completed are required to be refunded to Wisconsin ratepayers. Dominion Energy believes that the amounts currently available in the decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee 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 studies completed for Millstone and for Kewaunee were performed in 2019 and 2018, respectively.
The estimated decommissioning costs, funds in trust and current license expiration dates for Millstone and Kewaunee are shown in the following table:
(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 or Kewaunee during 2020.
(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, 2020, the minority owners held $55 million of trust funds related to Millstone Unit 3 that are not reflected in the table above.
(5)
Permanently ceased operations in 2013.
Also see Notes 14 and 23 to the Consolidated Financial Statements for further information about AROs and nuclear decommissioning, respectively, and Note 9 to the Consolidated Financial Statements for information about nuclear decommissioning trust investments.
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 nonregulated retail energy marketing operations, including Dominion Energy’s noncontrolling interest in Wrangler. 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 of Dominion Energy’s gas transmission and storage operations as discussed in Note 3 to the Consolidated Financial Statements and its equity investment in Atlantic Coast Pipeline as discussed in Note 9 to the Consolidated Financial Statements.
Dominion Energy owns a 20% noncontrolling interest in Wrangler, which was formed in September 2019. Wrangler’s operations, contributed by Dominion Energy in 2020 and 2019, consist of nonregulated natural gas retail energy marketing business serving customers in Ohio and Georgia as well as other southeastern states in the U.S. Dominion Energy expects to contribute its remaining retail energy marketing operations, primarily serving customers in Pennsylvania, to Wrangler by the end of 2021.
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.
Dominion Energy Questar Pipeline provides gas transportation and storage services in the Rocky Mountain region of the U.S. These operations are currently presented in held-for-sale and discontinued operations effective July 2020 until closing of the Q-Pipe Transaction with BHE, which is expected in early 2021.
See Notes 3 and 9 to the Consolidated Financial Statements for more 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, West Virginia, Utah, Wyoming and Idaho, SEC, FERC, EPA, DOE, PHMSA, NRC, 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 and energy efficiency 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 may not be recovered in base rates for the service life of the projects 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. In the 2021 Triennial Review, any such rate reduction is limited to $50 million.
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 directs Virginia to participate 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.
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 offers to its retail electric customers several DSM programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. DESC submits annual filings to the South Carolina Commission related to these programs. As actual DSM program costs are incurred, they are deferred as regulatory assets and recovered through a rider approved by the South Carolina Commission. The rider also provides for 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 Notes 3 and 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’s natural gas distribution services, including the rates it may charge its customers, are regulated by the Ohio Commission. Hope’s natural gas distribution services, including the rates it may charge its customers, are regulated by the West Virginia Commission. DESC and PSNC’s natural
gas distribution services, including the rates they may charge their customers, are regulated by the South Carolina Commission and North Carolina Commission, 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. 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 West Virginia
Hope is subject to regulation of rates and other aspects of its business by the West Virginia Commission. When necessary, Hope 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 Hope are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges.
Hope makes routine separate filings with the West Virginia Commission to reflect changes in the costs of purchased gas. The majority of 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 purchased gas cost 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 West Virginia Commission has also approved a stand-alone 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 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 certain related 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.
In connection with the SCANA Combination, PSNC agreed not to file an application for a general rate case with the North Carolina Commission before April 2021 other than for rate adjustments as described above.
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.
See Note 13 to the Consolidated Financial Statements for additional information.
Federal Regulations
Federal Energy Regulatory Commission
Electric
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 sells electricity 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, Indiana, Ohio, Connecticut, Tennessee, Georgia, California, South Carolina and Utah, 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, Virginia Power and DESC have FERC approved tariffs to sell wholesale power at capped rates based on their respective embedded cost of generation. These cost-based sales tariffs could be used to sell to loads within or outside Virginia Power and DESC’s respective service territories. Any such sales are voluntary.
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 $1.3 million per day, per violation and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.
The Companies plan and operate their facilities in compliance with approved NERC reliability requirements. The Companies’ employees participate on various NERC 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. In addition, NERC has redefined critical assets which expanded the number of assets subject to NERC reliability standards, including cybersecurity assets. 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 requirements and initiatives, such expenses are not expected to significantly affect results of operations.
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.
Gas
FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion Energy Questar Pipeline.
Dominion Energy’s remaining interstate gas transmission and storage activities, which are currently classified as held for sale, are conducted on an open access basis, in accordance with certificates, tariffs and service agreements on file with FERC and FERC regulations.
Dominion Energy operates in compliance with FERC standards of conduct, which prohibit the sharing of certain non-public transmission information or customer specific data by its interstate gas transmission and storage companies with non-transmission function employees. Pursuant to these standards of conduct, Dominion Energy also makes certain informational postings available on Dominion Energy’s website.
See Note 3 to the Consolidated Financial Statements for a discussion of the Q-Pipe Transaction.
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 further 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 information on spent nuclear fuel.
Safety Regulations
Dominion Energy is also subject to the Pipeline Safety Improvement Act of 2002 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, which mandate inspections of interstate and intrastate natural gas transmission and storage pipelines, particularly those located in areas of high-density population. Dominion Energy has evaluated its natural gas transmission and storage properties, as required by the U.S. Department of Transportation regulations under these Acts, and has implemented a program of identification, testing and potential remediation activities. These activities are ongoing.
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 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 address all 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. Dominion Energy must comply with applicable CWA requirements at its 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, Dominion Energy’s projects and operations may impact tidal and non-tidal wetlands. In these instances, Dominion Energy 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 has set a goal to achieve net zero emissions by 2050. This goal covers carbon and methane emissions from both electric generation and natural gas operations. As part of the net zero commitment, Dominion Energy has specifically committed to cut methane emissions from its natural gas infrastructure operations by 65% by 2030 and by 80% by 2040, in each case relative to 2010 emissions.
To reach net zero emissions, in the near term Dominion Energy is seeking extension of the licenses of its zero-carbon nuclear fleet in Virginia, rapidly expanding wind and solar generation, investing in carbon-beneficial renewable natural gas, expanding its industry-leading methane emissions-reduction programs, and using low-carbon natural gas to support the integration of wind and solar generation facilities into the grid. The strategy to meet these objectives consists of three major elements which will significantly reduce GHG emissions:
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Clean energy diversity;
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Innovation and energy infrastructure modernization; and
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Conservation and energy efficiency.
Over the long term, Dominion Energy’s ability to 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 increase inclusiveness of its stakeholder engagement on decisions regarding the siting and operation of energy infrastructure. Dominion Energy strives to include to all people and communities, regardless of race, color, national origin, or income to ensure a diversity of views in our 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 aggressive voluntary measures to continue dramatically reducing emissions from traditional generation and delivery.
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 and reliable energy mix. Dominion Energy continues to add utility-scale solar capacity and currently has the third largest utility-owned solar fleet in the U.S. with 2.2 GW in operations across 10 states as of December 31, 2020. Dominion Energy also has approximately 2.5 GW of solar generating capacity under development, including agreements for acquisitions of projects, for facilities expected to commence commercial operations in 2021 through 2025 in Virginia, South Carolina and Ohio, representing approximately $4.7 billion of investment. Dominion Energy expects to continue to make
significant investments in solar generation to achieve its target of 13.4 GW generating capacity in-service by the end of 2035. In addition, Dominion Energy is pursuing offshore wind with the 2.6 GW Coastal Virginia Offshore Wind Commercial project, expected to be placed in service by the end of 2026, along with the Coastal Virginia Offshore Wind Pilot project which achieved commercial operation in January 2021.
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 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. Preservation of Dominion Energy’s existing carbon-free baseload nuclear generation is also an important component of Dominion Energy’s GHG emissions reduction strategy. Accordingly, Virginia Power has commenced the process to extend the operating licenses for its four nuclear units at Surry and North Anna.
See Operating Segments and Item 2. Properties for additional information.
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 growth capital plan from 2021 through 2025 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 and making Dominion Energy’s system more responsive to customers’ desire to more efficiently manage their energy consumption as well as 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, which the entities acquired in the SCANA Combination are expected to join in 2021. 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. 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:
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Energy audits and assessments;
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Incentives for customers to upgrade or install certain energy efficient measures and/or systems;
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Weatherization assistance to help income-eligible customers reduce their energy usage;
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Home energy planning, which provides homeowners with a step-by-step roadmap to efficiency improvements to reduce gas usage; and
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Rebates for installing high-efficiency equipment.
GHG Emissions
Dominion Energy’s integrated environmental strategy supports a reduction in GHG emissions. Through 2019, Dominion Energy has reduced carbon emissions from its electric generating units (based on ownership percentage) by 57% since 2005 and reduced methane
emissions from its natural gas infrastructure operations by 25% since 2010. Dominion Energy’s 2020 emissions data is not yet available. Emissions for fiscal year 2019 include the assets acquired as a part of the SCANA Combination, such as DESC’s electric generation operations and DESC and PSNC’s natural gas operations. Dominion Energy’s 2019 emissions data presented below also includes the operations of gas transmission and distribution operations sold or to be sold to BHE as part of the GT&S Transaction and the Q-Pipe Transaction.
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. Dominion Energy’s Corporate GHG Inventory used for reporting purposes 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 also 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 Dominion Energy voluntarily reports to various programs it participates in. As a result, Dominion Energy’s reported methane emissions in its Corporate GHG Inventory are higher than what is reported to the EPA.
Total CO2 equivalent emissions reported under Dominion Energy’s Corporate GHG Inventory were 36.9 million metric tons in 2019. 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.
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For Dominion Energy’s electric generation operations, total CO2 equivalent emissions (based on ownership percentage) were 31.9 million metric tons in 2019, including 9.9 million metric tons from DESC and 22.0 million metric tons from Virginia Power.
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For Dominion Energy’s electric transmission and distribution operations, direct CO2 equivalent emissions were 0.05 million metric tons in 2019.
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For Dominion Energy’s natural gas assets, total CO2 equivalent emissions were 4.95 million metric tons in 2019.
Dominion Energy’s 2019 GHG emissions as reported under various subparts of the EPA’s Mandatory GHG Reporting Program as of December 31, 2020, are as follows:
Natural Gas Operations - 2019 Emissions
Electric Generation Operations - 2019 Emissions
(1)
Virginia Power totals include biomass, which were not included in the Corporate GHG inventory.
Electric Transmission and Distribution Operations - 2019 Emissions
(1)
DESC does not trigger EPA mandatory GHG reporting.
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
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.
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.
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 these regulatory reviews. Such challenges may lengthen the time, complexity and costs associated with such regulatory reviews.
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 December 2019, FERC issued an order on PJM’s Minimum Offer Price Rule proposals finding the PJM tariff unjust and unreasonable and directed PJM to expand the Minimum Offer Price Rule to all existing and new generation resources benefitting from a state subsidy to address the effects of state subsidies on new and existing resources on the PJM capacity market. The expanded Minimum Offer Price Rule will set a floor price on new and existing renewable and non-renewable state subsidized resources that do not seek a FERC exemption, increasing their risk of failing to clear the capacity auction and not obtaining a capacity payment and obligation. 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 regulation 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. These operations are also subject to legislation 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 any 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 VCEA, the 2017 Tax Reform Act and tariffs imposed on imported solar panels by the U.S. government in 2018.
Through the SCANA Combination, Dominion Energy acquired SCANA and DESC which have been and continue to be subject to numerous legal proceedings and ongoing governmental investigations and examinations. While a significant portion of the federal and state legal proceedings and governmental investigations have been settled, SCANA and DESC remain defendants in multiple lawsuits and investigations relating to the decision to abandon construction at the NND Project. Among other things, the lawsuits and investigations allege misrepresentation, failure to properly manage the NND Project, unfair trade practices and violation of anti-trust laws. Additionally, pursuant to the SCANA Merger Agreement and applicable indemnification agreements, SCANA is indemnifying former directors and officers of SCANA and DESC who are defendants in federal and state legal proceedings relating to the decision to abandon construction at the NND Project and the subsequent SCANA Combination. Among other things, the lawsuits allege breaches of various fiduciary duties.
The outcome of these legal proceedings, investigations and examinations, including settlements, is uncertain and may adversely affect Dominion Energy’s 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 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 16,100 MW of solar or onshore wind capacity by the end of 2035, 5,200 MW of offshore wind capacity before 2035, and 2,700 MW of energy storage by the end of 2035. The VCEA also directs Virginia Power 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. 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. 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 emissions by 2050. To meet this commitment, the Companies expect to construct new electric generation facilities, including renewable facilities such as wind and solar, and 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 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. 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 pipelines, electric transmission lines, 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 approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, a decline in the credit strength of counterparties or vendors, 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. 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, 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 Coastal Virginia Offshore Wind projects and various solar projects. Several of the Companies’ key projects are increasingly large-scale, complex and being constructed in constrained geographic areas or in unfamiliar environments such as the marine environment for the Coastal Virginia Offshore Wind projects. The advancement of the Companies’ ventures is also affected by the interventions, litigation or other activities of stakeholder and advocacy groups, some of which oppose natural gas-related and energy infrastructure projects. For example, certain stakeholder groups oppose solar farms due to the increasing quantities of land tracts required for these facilities. Given that these projects provide the foundation for the Companies’ strategic growth plan, if the Companies are unable to obtain or maintain the required approvals, develop the necessary technical expertise, allocate and coordinate sufficient resources, adhere to budgets and timelines, effectively handle public outreach efforts, 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, cost overruns, labor disputes and other factors that could cause the total cost of the project to exceed the anticipated amount and adversely affect the Companies’ financial performance and/or impair the Companies’ ability to execute the business plan for the project as scheduled.
Further, an inability to obtain financing or otherwise provide liquidity for the projects on acceptable terms could negatively affect the Companies’ financial condition, cash flows, the projects’ anticipated financial results and/or impair the Companies’ ability to execute the business plan for the projects as scheduled.
Operational 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.
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. 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 our services. 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. From time to time, political and public sentiment in connection with significant transactions and infrastructure projects, such as the SCANA Merger and the abandonment of the NND Project, may result in a significant amount of adverse press coverage and other adverse public statements affecting the Companies. 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. Additionally, any failure by the Companies to realize voluntary targets set with respect to the reduction of GHG emissions or other long-term goals could lead to adverse press coverage and other adverse public statements affecting the Companies. 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.
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.
In addition, for certain contracted generation solar facilities in which Dominion Energy maintains a controlling interest, third-party investors hold certain protective rights. These rights may impact the ability of Dominion Energy to make certain decisions, such as the retention or distribution of available cash, significant acquisitions or dispositions of assets by those entities or the ability to sell or transfer its ownership interests.
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 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.
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. 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 Executive Chairman, CEO, CFO, COO and presidents and those responsible for financial, operational, legal, regulatory and accounting 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. 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, currency and financial market risks. In addition, Dominion Energy purchases and sells commodity-based contracts for hedging purposes.
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. 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, including the goodwill recorded in connection with the SCANA Combination, or the Companies’ other intangible assets or long-lived assets are in the future determined to be impaired, the applicable Company 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 Company’s results.
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.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
As of December 31, 2020, 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, 2020; 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 58,900 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 473 substations. Dominion Energy also owns various solar facilities, primarily at schools in Virginia, with an aggregate generation capacity of 9 MW.
The following tables list Virginia Power’s generating units and capability as of December 31, 2020.
VIRGINIA POWER UTILITY GENERATION
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
(1)
All solar facilities are alternating current.
GAS DISTRIBUTION
Gas Distribution’s network is located in Ohio, West Virginia, North Carolina, Utah, southwestern Wyoming and southeastern Idaho. This network includes approximately 75,500 miles of distribution mains and related service facilities which are supported by approximately 5,700 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.
DOMINION ENERGY SOUTH CAROLINA
DESC has approximately 3,800 miles and 26,700 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 442 substations.
DESC’s natural gas system includes approximately 18,700 miles of distribution mains and related service facilities, which are supported by approximately 500 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 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 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, 2020.
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1)
Capable of burning fuel oil as a secondary source.
(2)
Excludes the Hardeeville gas combustion turbine which currently does not have any net summer capability.
(3)
Capable of burning natural gas as a secondary source.
(4)
Excludes 33.3% undivided interest owned by Santee Cooper.
(5)
Includes 157MW 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, 2020.
(1)
Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain.
(2)
All solar facilities are alternating current.
(3)
Excludes 50% noncontrolling interest owned by GIP. Dominion Energy’s interest is subject to a lien securing Dominion Solar Projects III, Inc.’s debt.
(4)
Dominion Energy’s interest is subject to a lien securing Eagle Solar’s debt.
(5)
Excludes 33% noncontrolling interest owned by Terra Nova Renewable Partners. Dominion Energy’s interest is subject to a lien securing SBL Holdco’s debt.
Item 3. Legal Proceedings
From time to time, the Companies are parties to various legal, environmental or other regulatory proceedings, including in the ordinary course of business. SEC regulations require disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Companies reasonably believe will exceed a specified threshold. Pursuant to the SEC regulations, the Companies use a threshold of $1 million for such proceedings. See Notes 13 and 23 to the Consolidated Financial Statements, which information is incorporated herein by reference, for discussion of certain legal, environmental and other regulatory proceedings to which the Companies are a party.
Item 4. Mine Safety Disclosures
Not applicable.
Information about our Executive Officers
Information concerning the executive officers of Dominion Energy, each of whom is elected annually, is as follows:
Name and Age
Business Experience Past Five Years(1)
Thomas F. Farrell, II (66)
Executive Chairman of the Board of Directors from October 2020 to present; President and CEO from April 2007 to September 2020.
Robert M. Blue (53)
President and CEO from October 2020 to present; Director from November 2020 to present; Executive Vice President and Co-COO from December 2019 to September 2020; Executive Vice President and President & CEO-Power Delivery Group from May 2017 to November 2019; Senior Vice President and President & CEO-Dominion Virginia Power from January 2017 to May 2017; Senior Vice President-Law, Regulation & Policy from February 2016 to December 2016; Senior Vice President-Regulation, Law, Energy Solutions and Policy from May 2015 to January 2016.
James R. Chapman (51)
Executive Vice President, CFO and Treasurer from January 2019 to present; Senior Vice President, CFO and Treasurer from November 2018 to December 2018; Senior Vice President-Mergers & Acquisitions and Treasurer from February 2016 to October 2018; Vice President-Corporate Finance and Mergers & Acquisitions and Assistant Treasurer from May 2015 to January 2016.
Diane Leopold (54)
Executive Vice President and COO from October 2020 to present; Executive Vice President and Co-COO from December 2019 to September 2020; Executive Vice President and President & CEO-Gas Infrastructure Group from May 2017 to November 2019; Senior Vice President and President & CEO-Dominion Energy from January 2017 to May 2017; President of East Ohio from January 2014 to September 2020.
Edward H. Baine (47)
President-Dominion Energy Virginia from October 2020 to present; Senior Vice President-Power Delivery of Virginia Power from December 2019 to September 2020; Senior Vice President-Distribution of Virginia Power from February 2016 to November 2019; Senior Vice President-Transmission and Customer Service of Virginia Power from June 2015 to January 2016.
P. Rodney Blevins (56)
President-Dominion Energy South Carolina from December 2019 to present; President & Chief Executive Officer-Southeast Energy Group from January 2019 to November 2019; Senior Vice President and Chief Information Officer from January 2014 to December 2018.
Carlos M. Brown (46)
Senior Vice President, General Counsel and Chief Compliance Officer from December 2019 to present; Senior Vice President and General Counsel from January 2019 to November 2019; Vice President and General Counsel from January 2017 to December 2018; Deputy General Counsel-Litigation, Labor, and Employment of DES from July 2016 to December 2016; Director-Power Generation Station II of DES from July 2015 to June 2016.
Michele L. Cardiff (53)
Senior Vice President, Controller and CAO from October 2020 to present; Vice President, Controller and CAO from April 2014 to September 2020.
William L. Murray (53)
Senior Vice President-Corporate Affairs & Communications from February 2019 to present; Vice President-State & Electric Public Policy of DES from May 2017 to January 2019; Senior Policy Director-Public Policy of DES from April 2016 to May 2017; Managing Director-Corporate Public Policy of DES from June 2007 to March 2016.
Donald R. Raikes (58)
President-Gas Distribution of Dominion Energy from December 2019 to present and of Hope, East Ohio, PSNC, and Questar Gas from October 2019 to September 2020; President of Hope, East Ohio, PSNC, and Questar Gas from October 2020 to present; Senior Vice President-Gas Transmission Operations of DCP, Dominion Energy Midstream and Dominion Energy Questar Pipeline from February 2019 to September 2019; Senior Vice President-Dominion Midstream Operations of DCP, Dominion Energy Midstream and Dominion Energy Questar Pipeline from August 2017 to January 2019; Senior Vice President-Pipeline Customer Service & Business Development of DCP and DETI from May 2017 to August 2017; Senior Vice President-Customer Service and Business Development of DCP and DETI from November 2014 to May 2017.
Name and Age
Business Experience Past Five Years(1)
Daniel G. Stoddard (58)
Senior Vice President, Chief Nuclear Officer and President-Contracted Assets from September 2020 to present; Senior Vice President, Chief Nuclear Officer and President-Contracted Generation from December 2019 to August 2020; Senior Vice President and Chief Nuclear Officer of Virginia Power from October 2016 to present; Senior Vice President-Nuclear Operations of Virginia Power from May 2011 to September 2016.
(1)
All positions held at Dominion Energy, unless otherwise noted. Any service listed for Virginia Power, DETI, East Ohio, Hope, PSNC, Questar Gas, Dominion Energy Midstream, Dominion Energy Questar Pipeline, DCP and DES reflects service at a current or previous subsidiary of Dominion Energy.
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
DOMINION ENERGY
Dominion Energy’s common stock is listed on the NYSE under the ticker symbol D. At February 12, 2021, there were approximately 130,000 record holders of Dominion Energy’s common stock. The number of record holders is comprised of individual shareholder accounts maintained on Dominion Energy’s transfer agent records and includes accounts with shares held in (1) certificate form, (2) book-entry in the Direct Registration System and (3) book-entry under Dominion Energy Direct®. Discussions of expected dividend payments required by this Item are contained in Liquidity and Capital Resources in Item 7. MD&A.
Purchases of Equity Securities
(1)
Represents shares of common stock that were tendered by employees to satisfy tax withholding obligations on vested restricted stock.
(2)
Includes (i) 19,786 shares of common stock that were tendered by employees to satisfy tax withholding obligations on vested restricted stock;(ii) 1,647,192 shares of common stock purchased in open market transactions for an aggregate of approximately $132 million; and (iii) 1,382,635 shares of common stock delivered upon the completion of the purchase periods under two prepaid accelerated share repurchase agreements entered into by Dominion Energy in September 2020.
(3)
Includes (i) 2,045,345 shares of common stock purchased in open market transactions for an aggregate of approximately $163 million and (ii) 5,342,058 shares of common stock delivered to Dominion Energy under an accelerated share repurchase program. Dominion Energy entered into a prepaid accelerated share repurchase agreement with a financial institution in December 2020 to purchase $400 million in shares of common stock. No additional shares will be delivered under this agreement as the repurchase period ended in December 2020.
(4)
Represents the weighted-average price paid per share.
(5)
In July 2020, the Dominion Energy Board of Directors authorized the repurchase of up to $3.0 billion in shares of common stock and rescinded its prior repurchase authorization approved in February 2005 and modified in June 2007. Dominion Energy completed repurchases under this authorization in December 2020. In November 2020, the Dominion Energy Board of Directors authorized the repurchase of up to $1.0 billion of shares of common stock in addition to the repurchase program authorized in July 2020. This repurchase program has no expiration date or price or volume targets and may be modified suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors.
VIRGINIA POWER
There is no established public trading market for Virginia Power’s common stock, all of which is owned by Dominion Energy. Virginia Power intends to pay quarterly cash dividends in 2021 but is neither required to nor restricted, except as described in Note 21 to the Consolidated Financial Statements, from making such payments.
Item 6. Selected Financial Data
The following table should be read in conjunction with the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data.
Dominion Energy’s Consolidated Financial Statements include the results of operations acquired in the SCANA Combination effective January 2019.
DOMINION ENERGY
(1)
Operating revenue, net income and earnings per share exclude amounts presented in discontinued operations related to the gas transmission and storage operations sold to, or under contract to be sold to, BHE as well as Dominion Energy’s investment in Atlantic Coast Pipeline. Long-term debt excludes amounts reflected as held-for-sale. See Note 3 to Dominion Energy’s Consolidated Financial Statements for more information regarding the amounts presented as discontinued operations or held-for-sale.
(2)
Includes $559 million after-tax charge associated primarily with the planned early retirement of certain electric generation facilities, $496 million of after-tax charges for an impairment attributable to Dominion Energy’s interests in certain nonregulated solar generation facilities and a contract termination in connection with the sale of Fowler Ridge, $191 million of after-tax charges for expected CCRO and customer arrears forgiveness for Virginia utility customers and $93 million of after-tax charges associated with litigation acquired in the SCANA Combination, partially offset by a $264 million after-tax net gain related to nuclear decommissioning trust funds.
(3)
Includes merger and integration-related costs associated with the SCANA Combination of $1.8 billion after-tax (inclusive of $756 million after-tax charge for refunds of amounts previously collected for the NND Project, $480 million after-tax charge for litigation acquired in the SCANA Combination and $286 million after-tax charge related to a voluntary retirement program), $585 million after-tax charges associated primarily with the planned early retirement of certain electric generation facilities, automated meter reading infrastructure and the termination of a contract with a non-utility generator, partially offset by a $429 million after-tax net gain related to nuclear decommissioning trust funds.
(4)
Includes $568 million after-tax gains on sales of certain nonregulated generation facilities and equity method investments partially offset by $164 million after-tax charge related to the impairment of certain gathering and processing assets and a $160 million after-tax charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers.
(5)
Includes $851 million of tax benefits resulting from the remeasurement of deferred income taxes to the new corporate income tax rate, partially offset by $96 million of after-tax charges associated with equity method investments in wind-powered generation facilities.
(6)
Includes a $122 million after-tax charge related to future ash pond and landfill closure costs at certain utility generation facilities.
(7)
Includes finance leases.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
MD&A discusses Dominion Energy’s results of operations and general financial condition and Virginia Power’s results of operations. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data. Virginia Power meets the conditions to file under the reduced disclosure format, and therefore has omitted certain sections of MD&A.
CONTENTS OF MD&A
MD&A consists of the following information:
•
Forward-Looking Statements
•
Accounting Matters-Dominion Energy
•
Dominion Energy
•
Results of Operations
•
Segment Results of Operations
•
Virginia Power
•
Results of Operations
•
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;
•
Federal, state and local legislative and regulatory developments, including changes in or interpretations of federal and state tax laws and regulations;
•
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;
•
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 compliance, including those costs related to climate change;
•
Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities;
•
Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals;
•
Unplanned outages at facilities in which the Companies have an ownership interest;
•
The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events;
•
Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities;
•
Changes in operating, maintenance and construction costs;
•
Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity;
•
Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s nonregulated generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers;
•
Competition in the development, construction and ownership of certain electric transmission facilities in the Companies’ service territory in connection with Order 1000;
•
Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;
•
Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Energy’s pipeline system, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods;
•
Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures;
•
Impacts of acquisitions, divestitures, transfers of assets to joint ventures and retirements of assets based on asset portfolio reviews;
•
The expected timing and likelihood of completion of the Q-Pipe Transaction, including the ability to obtain the requisite regulatory approvals and the terms and conditions of such regulatory approvals;
•
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;
•
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 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. 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, 2020, Dominion Energy’s nuclear decommissioning AROs totaled $1.9 billion. The following discusses critical assumptions inherent in determining the fair value of AROs associated with Dominion Energy’s nuclear decommissioning obligations.
Dominion Energy obtains from third-party specialists periodic site-specific base year cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for its nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. These cash flows include estimates on timing of decommissioning, which for regulated nuclear units factors in the probability of NRC approval for license extensions. In addition, Dominion Energy’s cost estimates include cost escalation rates that are applied to the base year costs. Dominion Energy determines cost escalation rates, which represent projected cost increases over time due to both general inflation and increases in the cost of specific decommissioning activities, for each nuclear facility. The selection of these cost escalation rates is dependent on subjective factors which are considered to be critical assumptions.
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, 2020 Dominion Energy had $167 million 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. 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, 2020, Dominion Energy had established $155 million 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 and interest 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.
USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING
As of December 31, 2020, Dominion Energy’s Consolidated Balance Sheets include $7.4 billion presented within goodwill. The majority of the balance relates to the SCANA Combination, as discussed in Note 3 to the Consolidated Financial Statements, the Dominion Energy Questar Combination in 2016 and the acquisition of the former CNG in 2000. In connection with Dominion Energy entering agreements for the sale of substantially all of its gas transmission and storage business to BHE, associated goodwill of $1.6 billion was reclassified to assets held for sale in the Consolidated Balance Sheets. During 2020, $1.4 billion of this amount was written off at the completion of the GT&S Transaction.
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. In addition, in the third quarter of 2020, Dominion Energy performed impairment tests immediately before and after the realignment of its operating segments. The 2020 annual test and any interim tests 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 tests had been 10% lower, 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 2020, Dominion Energy determined that it had an impairment of its contracted nonregulated solar assets in partnerships outside of its core electric service territories. See Notes 6 and 10 to the Consolidated Financial Statements for a discussion of the impairment related to Dominion Energy’s non-wholly-owned nonregulated solar facilities.
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 strategic target asset allocation for Dominion Energy’s pension funds is 28% U.S. equity, 18% non-U.S. equity, 35% fixed income, 3% real estate and 16% 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 non-investment related assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions. Dominion Energy calculated its pension cost using an expected long-term rate of return on plan assets assumption that ranged from 7.00% to 8.60% for 2020, 7.00% to 8.65% for 2019 and 8.75% for 2018. For 2021, the expected long-term rate of return for the pension cost assumption ranged from 7.00% to 8.45% for Dominion Energy’s plans held as of December 31, 2020. Dominion Energy calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 8.50% for 2020, 2019 and 2018. For 2021, the expected long-term rate of return for other postretirement benefit cost assumption is 8.45%. The rate used in calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets.
Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost ranged from 2.77% to 3.63% for pension plans and 3.07% to 3.52% for other postretirement benefit plans in 2020, ranged from 3.57% to 4.43% for pension plans and 4.05% to 4.41% for other postretirement benefit plans in 2019 and ranged from 3.80% to 3.81% for pension plans and 3.76% for other postretirement benefit plans in 2018. Dominion Energy selected a discount rate ranging from 2.73% to 2.95% for pension plans and 2.69% to 2.80% for other postretirement benefit plans for determining its December 31, 2020 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, 2020 was 6.25% and is expected to gradually decrease to 5.00% by 2025-2026 and continue at that rate for years thereafter.
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.
DOMINION ENERGY
Results of Operations
Presented below is a summary of Dominion Energy’s consolidated results:
Overview
2020 VS. 2019
Net income attributable to Dominion Energy decreased $1.8 billion, primarily due to charges presented in discontinued operations associated with the cancellation of the Atlantic Coast Pipeline Project and related portions of the Supply Header Project, a decrease in net investment earnings on nuclear decommissioning trust funds, an increase in charges associated with the planned early retirements of certain electric generation facilities in Virginia, an impairment charge associated with interests in certain nonregulated solar generation facilities, a contract termination charge in connection with the sale of Fowler Ridge, a charge for benefits expected to be provided to retail electric customers in Virginia through the use of a CCRO in accordance with the GTSA and a charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020. These decreases in net income were partially offset by the absence of charges for refunds of amounts previously collected from retail electric customers of DESC for the NND Project and for certain regulatory assets and property, plant and equipment acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery, the planned early retirement of certain Virginia Power automated meter reading infrastructure and a voluntary retirement program and a decrease in charges associated with litigation acquired in the SCANA Combination.
2019 VS. 2018
Net income attributable to Dominion Energy decreased 45%, primarily due to charges for refunds of amounts previously collected from retail electric customers of DESC for the NND Project, litigation acquired in the SCANA Combination, a voluntary retirement program, the planned early retirement of certain Virginia Power electric generation facilities and the absence of gains on the sales of certain equity method investments. These decreases were partially offset by an increase in net investment earnings on nuclear decommissioning trust funds and the operations acquired in the SCANA Combination.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion Energy’s results of operations:
An analysis of Dominion Energy’s results of operations follows:
2020 VS. 2019
Operating revenue decreased 2%, primarily reflecting:
•
A $700 million decrease in the fuel cost component included in utility rates as a result of a net decrease in commodity costs associated with sales to electric utility retail customers ($651 million) and gas utility customers ($49 million);
•
A $625 million decrease as a result of the contribution of SEMI to Wrangler in December 2019;
•
A $121 million decrease in sales to electric utility retail customers from a decrease in cooling degree days during the cooling season ($76 million) and a net decrease in heating degree days during the heating season ($45 million);
•
A $73 million decrease due to unfavorable pricing ($36 million) and lower volumes ($37 million) at Millstone, including the effects of the Millstone 2019 power purchase agreements;
•
A $71 million decrease in sales to DESC electric retail customers from the capital cost rider;
•
A $58 million decrease in sales to electric utility retail customers associated with usage factors impacted by COVID-19;
•
A $45 million decrease due to the absence of various contracts at Virginia Power; and
•
A $34 million decrease in sales to electric retail customers associated with economic and other usage factors.
These decreases were partially offset by:
•
The absence of a $1.0 billion charge for refunds of amounts previously collected from retail electric customers of DESC for the NND Project;
•
A $387 million increase from Virginia Power riders;
•
A $64 million increase in off-system PJM sales; and
•
A $45 million increase in sales to electric retail customers due to customer growth.
Electric fuel and other energy-related purchases decreased 22%, primarily due to decreased fuel costs associated with electric utility retail customers ($681 million), which are offset in operating revenue and do not impact net income, partially offset by PJM off-system sales ($64 million) and the absence of various contracts at Virginia Power ($34 million).
Purchased electric capacity decreased 40%, primarily due to a decrease in expense related to the annual PJM capacity performance market effective June 2019 ($51 million) and a Virginia Power contract termination with a non-utility generator ($13 million) partially offset by an increase in expense associated with sales to DESC electric utility retail customers ($30 million), which is offset in operating revenue and does not impact net income, and an increase in expense related to the annual PJM capacity performance market effective June 2020 ($15 million).
Purchased gas decreased 43%, primarily due to the contribution of SEMI to Wrangler in December 2019 ($579 million) and a decrease in net commodity costs for gas utilities ($49 million), which are offset in operating revenue and do not impact net income.
Other operations and maintenance decreased 3%, primarily reflecting:
•
A decrease in merger and integration-related costs associated with the SCANA Combination ($364 million), including the absence of a charge related to a voluntary retirement program ($251 million);
•
A $49 million decrease in salaries, wages and benefits; and
•
A $32 million decrease due to the contribution of SEMI to Wrangler.
These decreases were partially offset by:
•
A $144 million increase in certain Virginia Power expenditures, which are primarily recovered through state and FERC rates and do not impact net income;
•
The absence of a benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019 ($113 million);
•
A $56 million increase in outside services; and
•
A $41 million increase related to the effects of COVID-19, primarily associated with enhanced safety measures.
Depreciation, depletion and amortization increased 2%, primarily due to various projects being placed into service ($102 million) partially offset by the absence of depreciation from certain electric generation facilities that were, or have been, committed to be retired early ($58 million) and a decrease reflecting the expected approval of the nuclear plant life extensions from the NRC ($31 million).
Impairment of assets and other charges increased 38%, primarily due to:
•
A $665 million charge associated with certain nonregulated solar generation facilities;
•
An increase in charges associated with the planned early retirements of certain electric generation facilities in Virginia ($402 million);
•
A $221 million contract termination charge in connection with the sale of Fowler Ridge;
•
A charge for benefits expected to be provided to retail electric customers in Virginia through the use of a CCRO in accordance with the GTSA ($130 million);
•
A charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020 ($127 million); and
•
An increase in dismantling costs associated with certain Virginia Power electric generation facilities ($54 million).
These increases were partially offset by:
•
A decrease in charges associated with litigation acquired in the SCANA Combination ($551 million);
•
The absence of a $160 million charge related to Virginia Power’s planned early retirement of certain automated meter reading infrastructure;
•
The absence of a $135 million charge related to Virginia Power’s contract termination with a non-utility generator;
•
A decrease in charges for property, plant and equipment acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery ($103 million);
•
The absence of a $62 million charge related to the abandonment of a project at a Virginia Power electric generating facility; and
•
The absence of a $26 million charge for the abandonment of certain property, plant and equipment.
Gains on sales of assets decreased 60%, primarily due to a decrease in gains on the sale of nonregulated retail energy marketing assets.
Other income decreased 10%, primarily reflecting a decrease in net investment earnings on nuclear decommissioning trust funds ($217 million), an increase in charitable commitments ($65 million), primarily for social justice, and charges associated with litigation acquired in the SCANA Combination ($25 million), partially offset by the absence of a charge related to a voluntary retirement program ($111 million), an increase from equity method earnings from Cove Point following closing of the GT&S Transaction ($40 million) and an increase in non-service components of pension and other postretirement employee benefit plan credits ($33 million).
Interest and related charges decreased 7%, primarily reflecting unrealized gains associated with freestanding derivatives ($84 million), lower interest expense from early redemptions of certain securities in 2019 and 2020 ($41 million), reductions in commercial paper borrowings ($34 million) and increases in AFUDC on regulated construction projects ($28 million), partially offset by increased borrowings in response to COVID-19 ($42 million) and charges associated with the early redemption of certain securities in the first quarter of 2020 ($25 million).
Income tax expense decreased 60%, primarily due to a reduction in consolidated state deferred income taxes associated with gas transmission and storage operations ($45 million) and the absence of a charge for certain income tax-related regulatory assets acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery ($194 million), partially offset by income tax expense primarily associated with the impairment of nonregulated solar generating assets held in partnerships attributable to the noncontrolling interest ($55 million) and a lower current year benefit from finalizing changes in tax status of certain subsidiaries in connection with the Dominion Energy Gas Restructuring ($24 million).
Net income from discontinued operations including noncontrolling interests decreased $2.6 billion, primarily due to charges associated with the cancellation of the Atlantic Coast Pipeline Project and related portions of the Supply Header Project.
Noncontrolling interests decreased $167 million, primarily due to impairments associated with certain nonregulated solar generation facilities ($267 million), partially offset by the sale of a 25% noncontrolling limited partnership interest in Cove Point to Brookfield in December 2019 ($97 million).
2019 VS. 2018
Operating revenue increased 29%, primarily reflecting:
•
A $3.1 billion increase from operations acquired in the SCANA Combination, including a $1.0 billion charge for refunds of amounts previously collected from retail electric customers of DESC for the NND Project;
•
A $348 million increase from Virginia Power riders;
•
The absence of a $215 million charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers; and
•
A $57 million increase due to favorable pricing at Millstone, including the effects of the Millstone 2019 power purchase agreements.
These increases were partially offset by:
•
A $456 million decrease from the absence of certain nonregulated generation facilities sold in 2018;
•
A $83 million decrease in the fuel cost component included in utility rates as a result of a net decrease in commodity costs associated with sales to Virginia Power utility customers; and
•
A $45 million decrease in sales to Virginia Power retail customers from lower heating degree days during the heating season, partially offset by a $25 million increase from higher cooling degree days during the cooling season.
Electric fuel and other energy-related purchases increased 7%, primarily due to a $576 million increase from operations acquired in the SCANA Combination, partially offset by a decrease in fuel costs due to the absence of certain nonregulated generation facilities in 2018 ($245 million), decreased fuel costs associated with Virginia Power utility customers ($83 million), which are offset in operating revenue and do not impact net income, and a decrease in Virginia Power fuel costs due to the expiration of an energy supply contract ($40 million).
Purchased electric capacity decreased 28%, primarily due to a decrease in expense related to the annual PJM capacity performance market effective June 2019 ($63 million) and a Virginia Power contract termination with a non-utility generator ($37 million), partially offset by an increase in expense from operations acquired in the SCANA Combination ($49 million) and the annual PJM capacity performance market effective June 2018 ($26 million).
Purchased gas increased $956 million, primarily due an increase from operations acquired in the SCANA Combination.
Other operations and maintenance increased 36%, primarily reflecting:
•
A $735 million increase from operations acquired in the SCANA Combination;
•
An increase in merger and integration-related costs associated with the SCANA Combination ($427 million), including a charge related to a voluntary retirement program ($251 million); and
•
A $116 million increase in certain Virginia Power transmission and generation-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income.
These increases were partially offset by:
•
A $113 million benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019;
•
The absence of an $81 million charge associated primarily with future ash pond and landfill closure costs in connection with the enactment of Virginia legislation in April 2018; and
•
A $43 million decrease from the absence of certain nonregulated generation facilities sold in 2018.
Depreciation, depletion and amortization increased 38%, primarily due to property, plant and equipment acquired in the SCANA Combination ($559 million), including amortization of NND Project costs ($127 million), an increase from various growth projects being placed into service ($140 million) and the absence of a benefit for the retroactive application of depreciation rates for regulated
nuclear plants to comply with Virginia Commission requirements ($31 million), partially offset by the planned early retirement of certain Virginia Power electric generation facilities and automated meter reading infrastructure ($40 million) and the sale of certain nonregulated electric generation facilities in 2018 ($37 million).
Other taxes increased 52%, primarily due to the SCANA Combination ($258 million), an increase in property tax charges for growth projects placed into service ($56 million) and a charge related to a voluntary retirement program ($21 million).
Impairment of assets and other charges increased $1.5 billion, primarily due to:
•
Charges associated with litigation acquired in the SCANA Combination ($641 million);
•
A $346 million charge related to the early retirement of certain Virginia Power electric generation facilities;
•
A $160 million charge related to Virginia Power’s planned early retirement of certain automated meter reading infrastructure;
•
A $135 million charge related to Virginia Power’s contract termination with a non-utility generator;
•
A $105 million charge for property, plant and equipment acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery;
•
A $62 million charge related to the abandonment of a project at a Virginia Power electric generating facility; and
•
The abandonment of certain property, plant and equipment ($26 million).
Gains on sales of assets decreased 43%, primarily due to the absence of the sale of Fairless and Manchester ($210 million) partially offset by an increase in gains on sales of nonregulated retail energy marketing assets ($82 million).
Other income decreased 8%, primarily reflecting the absence of equity method earnings and gain from the sale of Dominion Energy’s 50% limited partnership interest in Blue Racer ($603 million), a charge related to a voluntary retirement program ($111 million) and the absence of a gain on the sale of Dominion Energy’s 25% limited partnership interest in Catalyst Old River Hydroelectric Limited Partnership ($87 million). These decreases were partially offset by an increase in net investment earnings on nuclear decommissioning trust funds ($720 million).
Interest and related charges increased 16%, primarily due to debt acquired in the SCANA Combination net of debt redeemed in 2019 ($314 million), partially offset by the absence of charges associated with the early redemption of certain debt securities in 2018 ($69 million) and reduced interest on long-term debt due to net debt repayments in 2018 and 2019 ($57 million).
Income tax expense decreased 60%, primarily due to lower pre-tax income ($383 million), the impacts of changes in tax status of certain subsidiaries in connection with the Dominion Energy Gas Restructuring ($48 million), higher investment tax credits ($39 million) and the absence of 2017 Tax Reform Act impacts ($46 million), partially offset by a charge for certain income tax-related regulatory assets acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery ($194 million) and the absence of a state legislative change ($20 million).
Net income from discontinued operations including noncontrolling interests increased 58%, primarily due to the operations of the Liquefaction Facility for the entire year and the absence of charges for impairment of certain gathering and processing assets and disallowance of FERC-regulated plant.
Noncontrolling interests decreased 82%, primarily due to the acquisition of the public interest in Dominion Energy Midstream in January 2019.
Outlook
Dominion Energy’s 2021 net income is expected to increase on a per share basis as compared to 2020 primarily from the following:
•
The absence of charges associated with the cancellation of the Atlantic Coast Pipeline Project and related portions of the Supply Header Project;
•
The absence of charges associated with the impairment of interests in certain nonregulated solar generation facilities, the early retirement of certain electric generation facilities and contract termination in connection with the sale of Fowler Ridge;
•
The absence of charges for expected CCRO and customer arrears forgiveness for Virginia utility customers;
•
A reduction in merger and integration related costs associated with the SCANA Combination;
•
A reduction in charges associated with litigation acquired in the SCANA Combination;
•
Construction and operation of growth projects in electric utility and gas distribution operations;
•
Share accretion as a result of repurchases of common stock completed in 2020; and
•
A decrease in planned outage days at Millstone.
These increases are expected to be partially offset by the following:
•
The absence of operations sold to BHE as part of the GT&S Transaction and the Q-Pipe Transaction;
•
An increase in electric capacity expenses at Virginia Power; and
•
An increase in operations and maintenance expenses.
SEGMENT RESULTS OF OPERATIONS
Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit or loss. In September 2020, Dominion Energy updated its operating segments following the July 2020 agreement to sell substantially all of its gas transmission and storage operations to BHE. The historical information presented herein has been recast to reflect the current segment presentation. Presented below is a summary of contributions by Dominion Energy’s operating segments to net income (loss) attributable to Dominion Energy:
Dominion Energy Virginia
Presented below are operating statistics related to Dominion Energy Virginia’s operations:
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy Virginia’s net income contribution:
2020 VS. 2019
2019 VS. 2018
Gas Distribution
Presented below are selected operating statistics related to Gas Distribution’s operations:
(1) Includes PSNC effective January 2019.
Presented below, on an after-tax basis, are the key factors impacting Gas Distribution’s net income contribution:
2020 VS. 2019
2019 VS. 2018
Dominion Energy South Carolina
Presented below are selected operating statistics related to Dominion Energy South Carolina’s operations:
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy South Carolina’s net income contribution:
2020 VS. 2019
2019 VS. 2018
Contracted Assets
Presented below are selected operating statistics related to Contracted Asset’s operations:
Presented below, on an after-tax basis, are the key factors impacting Contracted Asset’s net income contribution:
2020 VS. 2019
(1)
Includes earnings associated with a 50% noncontrolling interest in Cove Point.
2019 VS. 2018
(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:
TOTAL SPECIFIC ITEMS
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 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. In 2019, this primarily included $521 million of after-tax earnings for the results of operations of the entities included in the GT&S and Q-Pipe Transactions and $135 million of after-tax transaction and transition costs associated with the SCANA Combination. In 2018, this primarily included $390 million of after-tax gains on the sales of certain equity method investments, $244 million of after-tax earnings for the results of operations of the entities included in the GT&S and Q-Pipe Transactions, $51 million of after-tax charges associated with the early redemption of certain debt securities and $31 million of after-tax transaction and transition costs associated with the Dominion Energy Questar Combination and SCANA Combination.
VIRGINIA POWER
Results of Operations
Presented below is a summary of Virginia Power’s consolidated results:
Overview
2020 VS. 2019
Net income decreased 11%, primarily due to an increase in charges related to the planned early retirements of certain electric generation facilities, a charge for benefits expected to be provided to retail electric customers in Virginia through the use of a CCRO in accordance with the GTSA, a charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020 and the absence of a benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019. These decreases were partially offset by the absence of charges related to the planned early retirement of certain automated meter reading infrastructure, a voluntary retirement program and a contract termination with a non-utility generator.
2019 VS. 2018
Net income decreased 10%, primarily due to charges associated with the planned early retirement of certain electric generation facilities and automated meter reading infrastructure, a voluntary retirement program and a contract termination with a non-utility generator. These decreases were partially offset by increases related to higher rider equity returns, the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019 and the absence of charges associated with Virginia legislation enacted in March 2018 and April 2018.
Analysis of Consolidated Operations
Presented below are selected amounts related to Virginia Power’s results of operations:
An analysis of Virginia Power’s results of operations follows:
2020 VS. 2019
Operating revenue decreased 4%, primarily reflecting:
•
A $561 million decrease in the fuel cost component included in utility rates as a result of a net decrease in commodity costs associated with sales to electric utility retail customers;
•
A $100 million decrease in sales to retail customers from a decrease in cooling degree days during the cooling season ($33 million) and a decrease in heating degree days during the heating season ($67 million);
•
A $66 million decrease in sales to electric retail customers associated with economic and other usage factors;
•
A $45 million decrease due to the absence of various contracts; and
•
A $29 million decrease in sales to electric retail customers associated with usage factors impacted by COVID-19; partially offset by
•
A $387 million increase from riders;
•
A $64 million increase in off-system PJM sales; and
•
A $35 million increase in sales to electric retail customers due to customer growth.
Electric fuel and other energy-related purchases decreased 25%, primarily due to decreased fuel costs associated with electric utility retail customers ($561 million), which are offset in operating revenue and do not impact net income, partially offset by PJM off-system sales ($64 million) and the absence of various contracts ($34 million).
Purchased electric capacity decreased $57 million, primarily due to a decrease in expense related to the annual PJM capacity performance market effective June 2019 ($51 million) and a contract termination with a non-utility generator ($13 million) partially offset by an increase in expense related to the annual PJM capacity performance market effective June 2020 ($15 million).
Other operations and maintenance increased 2%, primarily reflecting:
•
A $144 million increase in certain expenses which are primarily recovered through state and FERC rates and do not impact net income;
•
The absence of a benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019 ($113 million);
•
A $27 million increase in outside services; and
•
A $22 million increase related to the effects of COVID-19.
These increases were partially offset by:
•
The absence of a charge related to a voluntary retirement program ($190 million);
•
A $39 million decrease in salaries, wages and benefits and administrative costs;
•
A $38 million decrease in outage costs; and
•
A $26 million decrease in storm damage and service restoration costs.
Depreciation and amortization increased 2%, primarily due to various projects being placed into service ($114 million), partially offset by the absence of depreciation from certain electric generation facilities that were, or have committed to be, retired early ($58 million) and a decrease reflecting the expected approval of the nuclear plant life extensions from the NRC ($31 million).
Impairment of assets and other charges increased 44%, primarily due to:
•
An increase in charges associated with the planned early retirements of certain electric generation facilities ($402 million);
•
A charge for benefits expected to be provided to retail electric customers in Virginia through the use of a CCRO in accordance with the GTSA ($130 million);
•
A charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020 ($127 million); and
•
An increase in dismantling costs associated with certain electric generation facilities ($54 million); partially offset by
•
The absence of a charge related to the planned early retirement of certain automated meter reading infrastructure ($160 million);
•
The absence of a $135 million charge related to contract termination with a non-utility generator;
•
The absence of a $62 million charge related to the abandonment of a project at an electric generating facility;
•
The absence of a $21 million charge for disallowance of state-regulated plant; and
•
The absence of a $17 million charge related to the abandonment of certain property, plant and equipment.
Other income decreased 18%, primarily reflecting a decrease in net investment earnings on nuclear decommissioning trust funds.
Income tax expense decreased 13%, primarily due to lower pre-tax income.
2019 VS. 2018
Operating revenue increased 6%, primarily reflecting:
•
A $348 million increase from riders; and
•
The absence of a $215 million charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers; partially offset by
•
A $83 million decrease in the fuel cost component included in utility rates as a result of a net decrease in commodity costs associated with sales to electric utility retail customers; and
•
A $45 million decrease in sales to retail customers from lower heating degree days during the heating season, partially offset by a $25 million increase from higher cooling degree days during the cooling season.
Electric fuel and other energy-related purchases decreased 6% primarily due to decreased fuel costs associated with electric utility retail customers ($83 million), which are offset in operating revenue and do not impact net income, and a decrease in Virginia Power fuel costs due to the expiration of an energy supply contract ($40 million).
Purchased electric capacity decreased 67%, primarily due to a decrease in expense related to the annual PJM capacity performance market effective June 2019 ($63 million) and a contract termination with a non-utility generator ($37 million), partially offset by the annual PJM capacity performance market effective June 2018 ($26 million).
Other operations and maintenance increased 4%, primarily reflecting:
•
A $190 million charge related to a voluntary retirement program; and
•
A $116 million increase in certain transmission and generation-related expenses. These expenses were primarily recovered through state and FERC rates and did not impact net income; partially offset by
•
A $113 million benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019;
•
The absence of an $81 million charge associated primarily with future ash pond and landfill closure costs in connection with the enactment of Virginia legislation in April 2018; and
•
A $25 million decrease in storm damage and service restoration costs.
Depreciation and amortization increased 8%, primarily due to various projects being placed into service ($92 million) and the absence of a benefit for the retroactive application of depreciation rates for regulated nuclear plants to comply with Virginia Commission requirements ($31 million), partially offset by the absence of depreciation from certain electric generation facilities and automated meter reading infrastructure that were retired early ($40 million).
Impairment of assets and other charges increased $757 million, primarily reflecting:
•
A $346 million charge related to the early retirement of certain electric generation facilities;
•
A $160 million charge related to the planned early retirement of certain automated meter reading infrastructure;
•
A $135 million charge related to contract termination with a non-utility generator; and
•
A $62 million charge related to the abandonment of a project at an electric generating facility.
Other income increased $76 million, primarily reflecting an increase in net investment earnings on nuclear decommissioning trust funds.
Income tax expense decreased 12%, primarily due to lower pretax income ($29 million) and the absence of 2017 Tax Reform Act impacts ($23 million), partially offset by lower investment tax credits ($14 million).
LIQUIDITY AND CAPITAL RESOURCES
Dominion Energy depends on both internal and external sources of liquidity to provide working capital and as a bridge to long-term debt financings. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.
At December 31, 2020, Dominion Energy had $5.3 billion of unused capacity under its credit facility. See additional discussion below under Credit Facilities and Short-Term Debt.
A summary of Dominion Energy’s cash flows is presented below:
Operating Cash Flows
Net cash provided by Dominion Energy's operating activities increased $23 million, including approximately $707 million from discontinued operations. Net cash provided by continuing operations decreased primarily due to litigation settlements related to the SCANA Combination, higher contributions to Dominion Energy’s qualified pension plan, payments related to a voluntary retirement plan, and a contract termination in connection with the sale of Fowler Ridge, partially offset by the absence of a contract termination payment to a non-utility generator and net changes in other working capital items.
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 2020, Dominion Energy’s Board of Directors established an annual dividend rate for 2021 of $2.52 per share of common stock, a 33% decrease over the 2020 rate. This reduction in the annual dividend rate reflects the absence of income from operations sold to BHE as part of the GT&S Transaction and Q-Pipe Transaction as well as a revision to Dominion Energy’s target payout ratio to align with industry peers. Dividends are subject to declaration by the Board of Directors. In January 2021, Dominion Energy’s Board of Directors declared dividends payable in March 2021 of 63 cents per share of common stock.
Dominion Energy’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, and which are discussed in Item 1A. Risk Factors.
Credit Risk
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, 2020 for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.
(1)
Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 61% of the total net credit exposure.
(2)
The five largest counterparty exposures, combined, for this category represented less than 1% of the total net credit exposure.
(3)
The five largest counterparty exposures, combined, for this category represented approximately 33% of the total net credit exposure.
(4)
The five largest counterparty exposures, combined, for this category represented approximately 2% of the total net credit exposure.
Investing Cash Flows
Net cash used in Dominion Energy’s investing activities decreased $1.7 billion, primarily due to proceeds from the GT&S and Q-Pipe Transactions, partially offset by an increase in plant construction and other property additions, the absence of cash acquired in the SCANA Combination, the acquisition of an investment in Pivotal LNG, Inc. and an additional 5% investment in Atlantic Coast Pipeline and a decrease in the proceeds from the sale of assets and equity method investments.
Financing Cash Flows and Liquidity
Dominion Energy relies on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by its operations. As discussed in Credit Ratings, Dominion Energy’s ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.
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.
From time to time, Dominion Energy may reduce its outstanding debt and level of interest expense through redemption of debt securities prior to maturity and repurchases in the open market, in privately negotiated transactions, through tender offers or otherwise.
Net cash used in Dominion Energy's financing activities increased $1.6 billion primarily due to repurchases of common stock in 2020, lower issuances of common stock, the absence of the 2019 Equity Units and the Series B Preferred Stock issuances and the absence of proceeds from the sale of a 25% noncontrolling interest in Cove Point, partially offset by higher issuances and lower repayments of long-term debt.
Credit Facilities and Short-Term Debt
Dominion Energy uses short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion Energy utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by 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 commercial paper and letters of credit outstanding, as well as capacity available under its credit facility, were as follows:
(1)
The weighted-average interest rate of the outstanding commercial paper supported by Dominion Energy’s credit facility was 0.29% at December 31, 2020.
(2)
This credit facility matures in March 2023 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 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, 2020, Dominion Energy’s Consolidated Balance Sheets include $268 million presented within short-term debt. The proceeds are used for general corporate purposes and to repay debt.
In March 2020, Dominion Energy entered into a $900 million 364-Day Revolving Credit Agreement. The agreement bears interest at a variable rate. At December 31, 2020, $225 million was outstanding under the agreement. The proceeds from these borrowings were used to provide for general working capital and other general corporate purposes. The maximum allowed total debt to total capital ratio under this agreement is consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility.
In March 2020, Dominion Energy borrowed $500 million under a 364-Day Term Loan Credit Agreement that bore interest at a variable rate. The proceeds were used to provide for general working capital and other general corporate purposes. In November 2020, Dominion Energy repaid the outstanding balance in full.
In April 2020, Dominion Energy borrowed $625 million under a 364-Day Term Loan Credit Agreement that bore interest at a variable rate. The proceeds were used to provide for general working capital and other general corporate purposes. In June 2020, Dominion Energy repaid the outstanding balance in full.
Long-Term Debt
During 2020, Dominion Energy issued the following long-term public debt:
During 2020, Dominion Energy also issued the following long-term private debt:
•
In March 2020, PSNC issued, through private placement, $200 million of 4.05% senior notes that mature in 2030. These proceeds were used for general corporate purposes.
•
In June 2020, East Ohio issued, through private placement, $500 million of 1.30% senior notes, $500 million of 2.00% senior notes and $800 million of 3.00% senior notes that mature in 2025, 2030 and 2050, respectively. East Ohio used the proceeds from this offering to repay intercompany promissory notes with Dominion Energy Gas and a portion of its intercompany revolving credit agreement balance with Dominion Energy.
During 2020, Dominion Energy also remarketed the following long-term debt:
•
In June 2020, Virginia Power remarketed one series of tax-exempt bonds, with an aggregate outstanding principal of $105 million to new investors. The bonds will bear interest at a coupon rate of 1.20% until May 2024, after which they will bear interest at a market rate to be determined at that time.
•
In September 2020, Virginia Power remarketed three series of tax-exempt bonds, with an aggregate outstanding principal of $322 million to new investors. One of the bonds will bear interest at a coupon rate of 0.45% until April 2022, after which it will bear interest at a market rate to be determined at that time. Two of the bonds will bear interest at a coupon rate of 0.75% until September 2025, after which they will bear interest at a market rate to be determined at that time.
During 2020, Dominion Energy repaid, repurchased or redeemed $2.9 billion of long-term debt, including redemption premiums. The following long-term debt was repaid, repurchased or redeemed before its stated maturity:
•
In February 2020, Dominion Energy redeemed the remaining principal outstanding of $111 million and $286 million of its June 2006 hybrids and its September 2006 hybrids, respectively, both of which would have otherwise matured in 2066. All purchases
were conducted in compliance with the applicable RCC, each of which was terminated in February 2020. Expenses related to the early redemption of the hybrids were $10 million reflected within interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2020.
•
In March 2020, SCANA redeemed its floating rate senior notes at the remaining principal balance of $66 million plus accrued interest. The notes would have otherwise matured in June 2034. Expenses related to the early redemption of the senior notes were $7 million reflected within interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2020.
•
In March 2020, SCANA redeemed the remaining principal outstanding of $183 million of its 4.75% medium-term notes and $155 million of its 4.125% medium-term notes plus accrued interest and make-whole premiums. The notes would have otherwise matured in May 2021 and February 2022, respectively. Total expenses related to the early redemption of the medium-term notes were $14 million reflected within interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2020.
•
In April 2020, Dominion Energy purchased and canceled $7 million of its 2.579% junior subordinated notes scheduled to mature in July 2020. In June 2020, Dominion Energy prepaid the remaining balance of $993 million.
In addition, in 2020 both Dominion Energy and Virginia Power amended portfolios of interest rate swaps extending the mandatory termination dates resulting in an increase in long-term debt. See Note 18 to the Consolidated Financial Statements for more information.
In February 2021, PSNC entered into an agreement with certain investors to issue through private placement in March 2021, $150 million 3.10% 30-year senior notes. The proceeds will be used for the repayment of existing indebtedness and for general corporate purposes.
Issuance of Common Stock
During 2020, Dominion Energy issued approximately 6.7 million shares of common stock, valued at $520 million, for a litigation settlement and through various programs including Dominion Energy Direct®.
Dominion Energy maintains Dominion Energy Direct® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In August 2020, Dominion Energy began purchasing its common stock on the open market for these direct stock purchase plans. In January 2021, Dominion Energy began issuing new shares of common stock for these direct stock purchase plans. During 2020, Dominion Energy received cash of $159 million from the issuance of 2.1 million of such shares through Dominion Energy Direct® and employee savings plans.
In September 2020, Dominion Energy issued 4.1 million shares of its common stock to satisfy its obligation under a settlement agreement for the Santee Cooper Ratepayer Case discussed in Note 20 to the Consolidated Financial Statements. These shares were immediately repurchased as discussed below.
In August 2020, Dominion Energy entered into sales agency agreements to effect sales under a new at-the-market program. Under the sales agency agreements, Dominion Energy may, from time to time, offer and sell shares of its common stock through the sales agents or enter into one or more forward sale agreements with respect to shares of its common stock. Sales by Dominion Energy through the sales agents or by forward sellers pursuant to a forward sale agreement cannot exceed $1.0 billion in the aggregate. Dominion Energy has not issued any shares or entered into any forward sale agreements under this new program.
Repurchase of Common Stock
During 2020, Dominion Energy repurchased 38.9 million shares of Dominion Energy common stock for $3.1 billion through an open market agreement, accelerated share repurchase agreements and a private transaction as discussed below.
In July 2020, in contemplation of Dominion Energy entering the July 2020 agreement to sell substantially all of its gas transmission and storage operations to BHE, the Board of Directors authorized the repurchase of up to $3.0 billion of Dominion Energy’s common stock and rescinded its prior repurchase authorization approved in February 2005 and modified in June 2007. Dominion Energy completed repurchases under this authorization in December 2020. In November 2020, the Board of Directors authorized the repurchase of up to $1.0 billion of Dominion Energy’s common stock in addition to the repurchase program authorized in July 2020. 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.
In August 2020, Dominion Energy began repurchasing shares under an open market agreement with a financial institution. Through the end of 2020, Dominion Energy repurchased 10.9 million shares of Dominion Energy common stock for $857 million.
In September 2020, Dominion Energy entered into two prepaid accelerated share repurchase agreements and made payments totaling $1.5 billion for the ultimate receipt of 18.6 million shares of Dominion Energy common stock. In December 2020, Dominion Energy entered into another prepaid accelerated share repurchase agreement and paid $400 million for the ultimate receipt of 5.3 million shares of Dominion Energy common stock.
In September 2020, Dominion Energy repurchased 4.1 million shares of Dominion Energy common stock in a private transaction for $323 million.
See Note 20 to the Consolidated Financial Statements for more information.
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 22, 2021 follow:
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.
Debt Covenants
As part of borrowing funds and issuing debt (both short-term and long-term) 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 and cross-default provisions.
As of December 31, 2020, the calculated total debt to total capital ratio, pursuant to the terms of the agreement, was as follows:
(1)
Indebtedness as defined by the bank agreements excludes certain junior subordinated notes reflected as long-term debt as well as AOCI reflected as equity in the Consolidated Balance Sheets.
If Dominion Energy or any of its material subsidiaries fails to make payment on various debt obligations in excess of $100 million, the lenders could require the defaulting company, if it is a borrower under Dominion Energy’s 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.
The term loan and revolving credit agreements Dominion Energy entered into in the first quarter of 2020 have a maximum allowed total debt to total capital ratio consistent with the ratio under the credit facility discussed above.
Dominion Energy monitors compliance with these debt covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2020, there have been no events of default under Dominion Energy’s debt covenants.
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, 2020, these restrictions did not have a significant impact on Dominion Energy’s ability to pay dividends on its common 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.
Future Cash Payments for Contractual Obligations and Planned Capital Expenditures
Contractual Obligations
Dominion Energy is party to numerous contracts and arrangements obligating it to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services and financial derivatives. Presented below is a table summarizing cash payments that may result from contracts to which Dominion Energy is a party as of December 31, 2020. For purchase obligations and other liabilities, amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts presented below. The table excludes all amounts classified as current liabilities in the Consolidated Balance Sheets, other than current maturities of long-term debt, interest payable and certain derivative instruments. The majority of Dominion Energy’s current liabilities will be paid in cash in 2021.
(1)
Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders.
(2)
Includes interest payments over the terms of the debt and payments on stock purchase contracts. Interest is calculated using the applicable interest rate or forward interest rate curve at December 31, 2020 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity. See Note 18 to the Consolidated Financial Statements. Does not reflect Dominion Energy’s ability to defer stock purchase contract payments on the 2019 Equity Units, initially in the form of corporate units.
(3)
Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.
(4)
Includes capital, operations and maintenance commitments.
(5)
Excludes regulatory liabilities, AROs, employee benefit plan obligations and charitable commitments, which are not contractually fixed as to timing and amount. See Notes 12, 14, 22 and 23 to the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, $105 million of income taxes payable associated with unrecognized tax benefits are excluded. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year. See Note 5 to the Consolidated Financial Statements.
(6)
Includes interest rate swap agreements.
Planned Capital Expenditures
Dominion Energy’s planned capital expenditures, including contributions for equity method investments, are expected to total approximately $8.1 billion, $7.4 billion and $8.7 billion in 2021, 2022 and 2023, respectively. Dominion Energy’s planned expenditures are expected to include construction and expansion of electric generation, including renewable energy, and natural gas distribution, construction improvements and expansion of electric transmission and distribution assets, purchases of nuclear fuel and maintenance.
Dominion Energy expects to fund its capital expenditures with cash from operations and a combination of securities issuances and short-term borrowings. Planned capital expenditures include capital projects that are subject to approval by regulators and the Board of Directors.
See Dominion Energy Virginia, Gas Distribution, Dominion Energy South Carolina and Contracted Assets -Properties in Item 1. Business for a discussion of Dominion Energy’s expansion plans.
The above estimates are based on a capital expenditures plan reviewed and endorsed by Dominion Energy’s Board of Directors in late 2020 and are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. Dominion Energy may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.
Use of Off-Balance Sheet Arrangements
Corporate Office Leasing Arrangement
In December 2019, Dominion Energy signed an agreement with a lessor, as amended in May 2020, to construct and lease a new corporate office property in Richmond, Virginia. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $465 million, to fund the estimated project costs. If Dominion Energy ultimately proceeds with the project through completion, the project is expected to be completed by September 2024. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs, which totaled $61 million as of December 31, 2020. If the project is terminated under certain events, Dominion Energy could be required to pay up to 100% of the then funded amount.
The lease term will commence once construction is substantially complete and the facility is able to be occupied and will end in December 2027. At the end of the initial lease term, Dominion Energy can (i) extend the term of the lease for an additional five years, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property on behalf of the lessor to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the project costs, Dominion Energy may be required to make a payment to the lessor, up to 83% of project costs, for the difference between the project costs and sale proceeds.
Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.
Offshore Wind Vessel Leasing Arrangement
In December 2020, Dominion Energy signed an agreement 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 completed by the end of 2023. Dominion Energy has been appointed to act as the
construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs, which totaled $187 million as of December 31, 2020. If the project is terminated under certain events of default, Dominion Energy could be required to pay up to 100% of the then funded amount.
The initial lease term will commence once construction is substantially complete and the vessel is delivered and will mature in November 2027. At the end of the initial lease term, Dominion Energy can (i) extend the term of the lease for an additional term, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the outstanding project costs or, (iii) subject to certain terms and conditions, sell the property on behalf of the lessor to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the outstanding project costs, Dominion Energy may be required to make a payment to the lessor for the difference between the outstanding project costs and sale proceeds.
Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.
Guarantees
Dominion Energy primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the provisions of FASB guidance that dictate a guarantor’s accounting and disclosure requirements for guarantees, including indirect guarantees of indebtedness of others. In addition, Dominion Energy has provided guarantees to support certain of its equity method investees, including Atlantic Coast Pipeline and Cove Point. See Notes 9 and 23 to the Consolidated Financial Statements for additional information.
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.
Environmental Matters
Dominion Energy is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.
Environmental Protection and Monitoring Expenditures
Dominion Energy incurred $238 million, $260 million and $198 million of expenses (including accretion and depreciation) during 2020, 2019, and 2018 respectively, in connection with environmental protection and monitoring activities. Dominion Energy expects these expenses to be approximately $234 million and $231 million in 2021 and 2022, respectively. In addition, capital expenditures related to environmental controls were $58 million, $134 million, and $104 million for 2020, 2019, and 2018, respectively. Dominion Energy expects these expenditures to be approximately $63 million and $81 million for 2021 and 2022, respectively.
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.
In October 2020, the EPA published a proposal to revise the 2016 Cross State Air Pollution Rule Update to address interstate air quality impacts for the 2008 ozone National Ambient Air Quality Standards. The EPA’s proposed rule will affect 12 states including Virginia and West Virginia and proposes to either issue new or amend existing NOX Ozone Season emission budgets. The EPA is proposing to require implementation of the revised emission budgets beginning with the 2021 ozone season (May 1 through September 30, 2021). Such revisions could necessitate that the Companies install additional control technology at certain facilities and/or limit the ability of facilities to run at certain times or at all. 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.
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.
Southeast Energy Exchange Market
In February 2021, DESC and the other members of the Southeast Energy Exchange Market 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. This matter is pending.
COVID-19
Dominion Energy continues to monitor the global outbreak of COVID-19 and developments affecting its workforce, suppliers and other aspects of its business, such as construction projects, and will take additional precautions as Dominion Energy believes are warranted. In addition, Dominion Energy continues to review both customer demand and its ability to collect customer receivables. As a result of the COVID-19 pandemic, Virginia legislation was enacted in November 2020 related to a moratorium on utility disconnections resulting in the forgiveness of certain past due accounts. Other state legislatures or utility commissions could impose similar measures which could have a material impact to Dominion Energy’s results of operations, financial position and/or cash flows.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs of Item 7. MD&A. The reader’s attention is directed to those paragraphs and Item 1A. Risk Factors for discussion of various risks and uncertainties that may impact the Companies.
MARKET RISK SENSITIVE INSTRUMENTS AND RISK MANAGEMENT
The Companies’ financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates 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 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% decrease in commodity prices would have resulted in an increase of $2 million and a decrease of $50 million in the fair value of Dominion Energy’s commodity-based derivative instruments as of December 31, 2020 and December 31, 2019, respectively.
A hypothetical 10% decrease in commodity prices would have resulted in a decrease of $35 million and $54 million in the fair value of Virginia Power’s commodity-based derivative instruments as of December 31, 2020 and December 31, 2019, 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 and Virginia Power, a hypothetical 10% increase in market interest rates would not have resulted in a material change in earnings at December 31, 2020 or 2019.
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, 2020, Dominion Energy and Virginia Power had $6.9 billion and $2.1 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 $124 million and $75 million, respectively, in the fair value of Dominion Energy and Virginia Power interest rate derivatives at December 31, 2020. As of December 31, 2019, Dominion Energy and Virginia Power had $6.4 billion and $1.9 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 $135 million and $88 million, respectively, in the fair value of Dominion Energy and Virginia Power interest rate derivatives at December 31, 2019.
Prior to completing the GT&S Transaction, Dominion Energy held foreign currency swaps for the purpose of hedging the foreign currency exchange risk associated with Euro denominated debt. As of December 31, 2019, Dominion Energy had €250 million in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would not have resulted in a material decrease in fair value of Dominion Energy’s foreign currency swaps at December 31, 2019.
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.
Investment Price Risk
The Companies are subject to investment price risk due to securities held as investments in nuclear decommissioning and rabbi trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in the Consolidated Balance Sheets at fair value.
Dominion Energy recognized net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $0.7 billion and $1.0 billion for the years ended December 31, 2020 and 2019, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion Energy recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on debt investments of $57 million and $74 million for the years ended December 31, 2020 and 2019, respectively.
Virginia Power recognized net investment gains (including investment income) on nuclear decommissioning trust investments of $287 million and $481 million for the years ended December 31, 2020 and 2019, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on debt investments of $29 million and $30 million for the years ended December 31, 2020 and 2019, respectively.
Dominion Energy sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power employees participate in these plans. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns (losses) of $1.9 billion and $2.1 billion in 2020 and 2019, respectively, versus expected returns of $933 million and $848 million, 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 net periodic cost of $25 million and $23 million as of December 31, 2020 and 2019, respectively, for pension benefits and $5 million as of both December 31, 2020 and 2019 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, 2020 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.
Item 8. Financial Statements and Supplementary Data
Page
Number
Dominion Energy, Inc.
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018
Consolidated Statements of Comprehensive Income for the years ended December 31, 2020, 2019 and 2018
Consolidated Balance Sheets at December 31, 2020 and 2019
Consolidated Statements of Equity at December 31, 2020, 2019 and 2018 and for the years then ended
Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018
Virginia Electric and Power Company
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018
Consolidated Statements of Comprehensive Income for the years ended December 31, 2020, 2019 and 2018
Consolidated Balance Sheets at December 31, 2020 and 2019
Consolidated Statements of Common Shareholder’s Equity at December 31, 2020, 2019 and 2018 and for the years then ended
Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018
Combined Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Dominion Energy, Inc.
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Dominion Energy, Inc. and subsidiaries ("Dominion Energy") at December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Dominion Energy at December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), Dominion Energy's internal control over financial reporting at December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2021, expressed an unqualified opinion on Dominion Energy's internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of Dominion Energy's management. Our responsibility is to express an opinion on Dominion Energy's consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Dominion Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Regulatory Assets and Liabilities - Impact of Rate Regulation on the Consolidated Financial Statements - Refer to Notes 2, 12 and 13 to the Consolidated Financial Statements
Critical Audit Matter Description
Dominion Energy, through its regulated electric and gas subsidiaries, is subject to rate regulation by certain state public utility commissions and the Federal Energy Regulatory Commission (“FERC”) (collectively, the “relevant commissions”) which have jurisdiction with respect to the rates of electric utility and natural gas distribution and transmission companies. Management has determined its rate-regulated subsidiaries meet the requirements under accounting principles generally accepted in the United States of America to apply the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment, net; regulatory assets; regulatory liabilities; operating revenues; other operations and maintenance expense; depreciation, depletion and amortization expense; and impairment of assets and other charges, collectively, the “financial statement impacts of rate regulation.”
Revenue provided by Dominion Energy’s electric transmission, distribution and generation operations and its gas transmission and distribution operations is based primarily on rates approved by the relevant commissions. Further, Virginia Electric and Power Company’s (“Virginia Power”) retail base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia State Corporation Commission (the “Virginia Commission”) in a proceeding that involves the determination of Virginia Power’s actual earned return on equity (“ROE”) during a historic test period,
and determination of Virginia Power’s authorized ROE prospectively. Under certain circumstances, Virginia Power may be required to refund a portion of its earnings to customers.
In connection with the evaluation of Virginia Power’s earnings for the four-year test period ended December 31, 2020, Virginia Power recorded a charge of $130 million for the year ended December 31, 2020 for benefits it expects to provide to its customers through the use of a customer credit reinvestment offset in accordance with the Virginia Grid Transformation and Security Act of 2018 (“GTSA”). This evaluation included consideration of the regulatory treatment of a charge of $754 million ($561 million after-tax) recorded in the first quarter of 2020, associated with Virginia Power’s commitment to retire certain coal- and oil-fired generating units before the end of their useful lives. Virginia Power determined it was appropriate to consider this charge to be recovered as a component of Virginia Power’s base rates under the GTSA. This determination required management judgment.
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 through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Dominion Energy evaluates whether recovery of its regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makes various assumptions in its analyses. These analyses are generally based on orders issued by regulatory commissions, legislation and judicial actions; past experience; discussions with applicable regulatory authorities and legal counsel; forecasted earnings; and considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events, and other natural disasters, and unplanned outages of facilities.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about the financial statement impacts of rate regulation. Management judgments include assessing the likelihood of (1) recovery of its regulatory assets through future rates and (2) whether a regulatory liability is due to customers. Given management’s accounting judgments are based on assumptions about the outcome of future decisions by the relevant commissions, auditing these judgments required specialized knowledge of the accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable included the following, among others:
•
We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) recovery of regulatory assets through future rates, and (2) whether a regulatory liability is due to customers. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities; and the monitoring and evaluation of regulatory and legislative developments that may impact the assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable.
•
We evaluated Dominion Energy’s disclosures related to the financial statement impacts of rate regulation.
•
We read and evaluated orders issued by the relevant commissions, as well as relevant regulatory statutes, interpretations, procedural memorandums, filings made by interveners, existing laws and other publicly available information to assess whether this external information was properly considered by management in concluding upon the financial statement impacts of rate regulation.
•
We assessed the regulatory treatment of significant non-recurring charges, including the $754 million charge recorded by Virginia Power in the first quarter of 2020 in connection with the early retirement decision impacting certain coal- and oil-fired generating units by considering existing precedent for the treatment of such charges, relevant legislation and regulatory orders.
•
We considered the likelihood of (1) recovery of regulatory assets through future rates and (2) whether a regulatory liability is due to customers based on precedents established by the relevant commissions’ previous orders and Dominion Energy’s past experience with the relevant commissions.
•
For regulatory matters in process, we inspected associated documents and testimony filed with the relevant commissions for any evidence that might contradict management’s assertions.
•
We read and analyzed the minutes of the Boards of Directors of Dominion Energy and Dominion Energy’s rate-regulated subsidiaries for discussions of changes in legal, regulatory, or business factors which could impact management’s conclusions with respect to the financial statement impacts of rate regulation.
Impairment of Non-Wholly-Owned Nonregulated Solar Facilities- Refer to Note 10 to the Consolidated Financial Statements
Critical Audit Matter Description
Dominion Energy performs an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets with finite lives may not be recoverable. A long-lived asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount.
In the third quarter of 2020, Dominion Energy performed a strategic review of its long-term intentions for its contracted nonregulated solar generation assets in partnerships outside of its core electric service territories in consideration of the impact of the Virginia Clean Economy Act and Dominion Energy’s decision to sell substantially all of its gas transmission and storage operations. Based on an evaluation of Dominion Energy’s interests in these long-lived assets for recoverability under a probability weighted approach, Dominion Energy determined the assets were impaired. As a result, Dominion Energy recorded a charge of $665 million ($293 million after-tax attributable to Dominion Energy and $267 million attributable to noncontrolling interest) in impairment of assets and other charges in its Consolidated Statements of Income for year ended December 31, 2020 to adjust the property, plant and equipment down to its estimated fair value of $1.4 billion. The fair value was estimated using an income approach. The valuation is considered a Level 3 fair value measurement due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risks inherent in the future cash flows and market prices.
We identified the impairment of the contracted nonregulated solar generation assets held in partnerships as a critical audit matter due to the high degree of auditor judgment and an increased level of effort, including the need to involve our fair value specialists, when performing audit procedures to evaluate (1) the timing of management’s identification of the triggering event requiring the recoverability test, (2) the reasonableness of the probabilities assigned by management to the scenarios utilized within the recoverability model (3) the estimates underlying the future cash flows in scenarios utilized and, (4) the selection of a discount rate in deriving the fair value of the assets.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the impairment of the solar generation assets held in partnerships included the following, among others:
•
We tested the effectiveness of management’s controls over the impairment evaluation, including those over the identification of triggering events requiring recoverability tests, and those addressing the appropriateness of the key assumptions used in the recoverability test, including those addressing the probabilities assigned to the scenarios utilized and those addressing key assumptions utilized in estimation of the fair value of the assets, including selection of a discount rate.
•
We evaluated whether the timing of the identification of the triggering event was appropriate, as well as the reasonableness of probabilities management assigned to scenarios utilized in the recoverability test by:
o
Reading and analyzing the minutes of the Boards of Directors of Dominion Energy for discussions of changes in legal, regulatory, or business factors which could impact management’s conclusions with respect to the probabilities assigned to the scenarios utilized.
o
Making inquiries of executive management, and
o
Obtaining and considering the timing and content of business unit presentations concerning management’s future plans with respect to the solar partnerships.
•
We evaluated the reasonableness of the fair value model by:
o
Testing the mathematical accuracy of the model,
o
Evaluating the reasonableness of the forecasted cash flows by comparing cash flow projections to current executed contracts, historical revenues and gross margins, and industry trends, and
o
With the assistance of our fair value specialists, evaluating the reasonableness of the discount rate utilized in the model by developing a range of independent estimates and comparing those to the discount rate selected by management.
•
We evaluated Dominion Energy’s disclosures related to the financial statement impacts of the impairment.
Earnings (loss) from equity method investees- Presentation of Loss from Atlantic Coast Pipeline in Discontinued Operations - Refer to Note 9 to the Consolidated Financial Statements
Critical Audit Matter Description
Dominion Energy holds a 53% noncontrolling interest in Atlantic Coast Pipeline, LLC (“Atlantic Coast Pipeline”) which since its formation in September 2014 had been focused on the construction of an approximately 600-mile natural gas pipeline.
Atlantic Coast Pipeline determined that the pipeline was probable of abandonment in June 2020, and it fully impaired the related asset under construction which resulted in an equity method loss to Dominion Energy of $2.3 billion. In connection with Dominion Energy’s decision to sell substantially all of its gas transmission and storage operations, which it determined to be a strategic shift, Dominion Energy has reflected the results of its equity method investment in Atlantic Coast Pipeline as discontinued operations in its Consolidated Statements of Income.
Auditing the conclusion that the equity method earnings (loss) associated with Dominion Energy’s investment in Atlantic Coast Pipeline was appropriately presented in discontinued operations involved significant judgment in applying the accounting standards as to when an equity method investee can be considered abandoned.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the assessment of whether the equity method loss associated with Dominion Energy’s investment in Atlantic Coast Pipeline was appropriately presented in discontinued operations included the following, among others:
•
We tested the effectiveness of controls over management’s technical accounting assessment of the presentation of the equity method earnings (loss) from Atlantic Coast Pipeline.
•
With the assistance of professionals in our firm having expertise in discontinued operations, we evaluated management’s conclusions regarding the presentation of the equity method earnings (loss) from Atlantic Coast Pipeline by considering the applicable generally accepted accounting standards.
•
We evaluated Dominion Energy’s disclosures related to the presentation of equity method earnings (loss) on Atlantic Coast Pipeline as discontinued operations.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 25, 2021
We have served as Dominion Energy’s auditor since 1988.
Dominion Energy, Inc.
Consolidated Statements of Income
(1)
See Note 9 for amounts attributable to related parties.
(2)
Includes income tax expense (benefit) of $(204) million, $142 million and $58 million for the years ended December 31, 2020, 2019 and 2018, respectively.
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
Dominion Energy, Inc.
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
Dominion Energy, Inc.
Consolidated Balance Sheets
(1)
See Note 9 for amounts attributable to related parties.
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
(1) See Note 9 for amounts attributable to related parties.
(2) 1.8 billion shares authorized; 806 million shares and 838 million shares outstanding at December 31, 2020 and 2019, respectively.
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
Dominion Energy, Inc.
Consolidated Statements of Equity
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
Dominion Energy, Inc.
Consolidated Statements of Cash Flows
See Note 2 for disclosure of supplemental cash flow information.
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of Virginia Electric and Power Company
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Energy, Inc.) and subsidiaries ("Virginia Power") at December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, common shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Virginia Power at December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of Virginia Power's management. Our responsibility is to express an opinion on Virginia Power's consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Virginia Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Virginia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Virginia Power’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Liabilities - Impact of Rate Regulation on the Consolidated Financial Statements - Refer to Notes 2, 12 and 13 to the Consolidated Financial Statements
Critical Audit Matter Description
Virginia Power is subject to utility rate regulation by certain state public utility commissions and the Federal Energy Regulatory Commission (“FERC”) (collectively, the “relevant commissions”), which have jurisdiction with respect to the rates of electric utility companies in the territories Virginia Power serves. Management has determined Virginia Power meets the requirements under accounting principles generally accepted in the United States of America to apply the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures such as property, plant, and equipment, net; regulatory assets; regulatory liabilities; operating revenues; other operations and maintenance expense; depreciation and amortization expense; and impairment of assets and other charges, collectively, the “financial statement impacts of rate regulation”.
Revenue provided by Virginia Power’s electric transmission, distribution and generation operations is based on rates approved by the relevant commissions. Further, Virginia Power’s retail base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia State Corporation Commission (the “Virginia Commission”) in a proceeding that involves the determination of Virginia Power’s actual earned return on equity (“ROE”) during a historic test period and determination of Virginia Power’s authorized ROE prospectively. Under certain circumstances, Virginia Power may be required to refund a portion of its earnings to customers.
In connection with the evaluation of Virginia Power’s earnings for the four-year test period ended December 31, 2020, Virginia Power recorded a charge of $130 million for the year ended December 31, 2020 for benefits it expects to provide to its customers through the use of a customer credit reinvestment offset in accordance with the Virginia Grid Transformation and Security Act of 2018 (“GTSA”). This evaluation included consideration of the regulatory treatment of a charge of $754 million ($561 million after-tax) recorded in the first quarter of 2020, associated with Virginia Power’s commitment to retire certain coal- and oil-fired generating units before the end of their useful lives. Virginia Power determined it was appropriate to consider this charge to be recovered as a component of Virginia Power’s base rates under the GTSA. This determination required management judgment.
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 through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Virginia Power evaluates whether recovery of its regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makes various assumptions in its analyses. These analyses are generally based on orders issued by regulatory commissions, legislation and judicial actions; past experience; discussions with applicable regulatory authorities and legal counsel; forecasted earnings; and considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events, and other natural disasters, and unplanned outages of facilities.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about the financial statement impacts of rate regulation. Management judgments include assessing the likelihood of (1) recovery of its regulatory assets through future rates and (2) whether a regulatory liability is due to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commission, auditing these judgments required specialized knowledge of the accounting for rate regulation and the rate setting process due its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable included the following, among others:
•
We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery of regulatory assets through future rates, and (2) whether a regulatory liability is due to customers. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities; and the monitoring and evaluation of regulatory and legislative developments that may impact the assessment of whether recovery of regulatory assets through future rates or a regulatory liability due to customers is probable.
•
We evaluated Virginia Power’s disclosures related to the financial statement impacts of rate regulation.
•
We read and evaluated orders issued by the relevant commissions, as well as relevant regulatory statutes, interpretations, procedural memorandums, filings made by interveners, existing laws and other publicly available information to assess whether this external information was properly considered by management in concluding upon the financial statement impacts of rate regulation.
•
We assessed the regulatory treatment of significant nonrecurring charges, including the $754 million charge recorded by Virginia Power in the first quarter of 2020 in connection with the early retirement decision impacting certain coal- and oil-fired generating units by considering existing precedent for the treatment of such charges, relevant legislation and regulatory orders.
•
We considered the likelihood of (1) recovery of regulatory assets through future rates and (2) whether a regulatory liability is due to customers based on precedents established by the relevant commissions’ previous orders and Virginia Power’s past experience with relevant commissions.
•
For regulatory matters in process, we inspected associated documents and testimony filed with the relevant commissions for any evidence that might contradict management’s assertions.
•
We read and analyzed the minutes of the Board of Directors of Dominion Energy, Inc. and the Board of Directors of Virginia Power, for discussions of changes in legal, regulatory, or business factors which could impact management’s conclusions with respect to the financial statement impacts of rate regulation.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 25, 2021
We have served as Virginia Power's auditor since 1988.
Virginia Electric and Power Company
Consolidated Statements of Income
(1)
See Note 25 for amounts attributable to affiliates.
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Balance Sheets
(1)
See Note 25 for amounts attributable to affiliates.
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
(1)
See Note 25 for amounts attributable to affiliates.
(2)
500,000 shares authorized; 274,723 shares outstanding at December 31, 2020 and 2019.
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Common Shareholder’s Equity
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Cash Flows
See Note 2 for disclosure of supplemental cash flow information.
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Combined Notes to Consolidated Financial Statements
NOTE 1. NATURE OF OPERATIONS
Dominion Energy, headquartered in Richmond, Virginia, is one of the nation’s largest producers and distributors of energy. Dominion Energy’s operations are conducted through various subsidiaries, including Virginia Power. Dominion Energy’s operations also include DESC, regulated gas distribution operations primarily in the eastern and Rocky Mountain regions of the U.S., nonregulated electric generation and, following the completion of the GT&S Transaction in November 2020, a noncontrolling interest in Cove Point. See Note 3 for a description of the sale of substantially all of Dominion Energy’s gas transmission and storage operations to BHE through the GT&S Transaction completed in November 2020 and the proposed Q-Pipe Transaction of Dominion Energy’s remaining regulated gas transmission and storage services in the Rocky Mountain region of the U.S.
Beginning in September 2020, Dominion Energy manages its daily operations through four primary operating segments: Dominion Energy Virginia, Gas Distribution, Dominion Energy South Carolina and Contracted Assets. Dominion Energy also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) as well as nonregulated retail energy marketing operations, including Dominion Energy’s noncontrolling interest in Wrangler. 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 of Dominion Energy’s gas transmission and storage operations as discussed in Note 3 and its equity investment in Atlantic Coast Pipeline as discussed in Note 9.
Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Power’s stock is owned by Dominion Energy.
Virginia Power manages its daily operations through one primary operating segment: Dominion Energy Virginia. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources.
See Note 26 for further discussion of the Companies’ operating segments.
NOTE 2. SIGNIFICANT ACCOUNTING POLICIES
General
The Companies make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues, expenses and cash flows for the periods presented. Actual results may differ from those estimates.
The Companies’ Consolidated Financial Statements include, after eliminating intercompany transactions and balances, their accounts, those of their respective majority-owned subsidiaries and non-wholly-owned entities in which they have a controlling financial interest. For certain partnership structures, income is allocated based on the liquidation value of the underlying contractual arrangements. At December 31, 2020 Dominion Energy owns 50% of the voting interests in Four Brothers and Three Cedars and has a controlling financial interest over the entities through its right to control operations. In August 2018, NRG’s ownership interest in Four Brothers and Three Cedars was transferred to GIP. GIP’s ownership interest in Four Brothers and Three Cedars, Terra Nova Renewable Partners’ 33% interest in certain Dominion Energy nonregulated solar projects, Brookfield’s 25% interest in Cove Point (effective December 2019 until November 2020) and the non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019) are reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. Terra Nova Renewable Partners has a future option to buy all or a portion of Dominion Energy’s remaining 67% ownership in certain nonregulated projects upon the occurrence of certain events, including any proposed sale by Dominion Energy of its interest.
The Companies report certain contracts, instruments and investments at fair value. See Note 6 for further information on fair value measurements.
The Companies consider acquisitions or dispositions in which substantially all of the fair value of the gross assets acquired or disposed of is concentrated into a single identifiable asset or group of similar identifiable assets to be an acquisition or a disposition of an asset, rather than a business. See Notes 3 and 10 for further information on such transactions.
Dominion Energy maintains pension and other postretirement benefit plans and Virginia Power participates in certain of these plans. See Note 22 for further information on these plans.
Certain amounts in the Companies’ 2019 and 2018 Consolidated Financial Statements and Notes have been reclassified to conform to the 2020 presentation for comparative purposes; however, such reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.
Amounts disclosed for Dominion Energy are inclusive of Virginia Power, where applicable.
Operating Revenue
Operating revenue is recorded on the basis of services rendered, commodities delivered, or contracts settled and includes amounts yet to be billed to customers. The Companies collect sales, consumption and consumer utility taxes; however, these amounts are excluded from revenue. Dominion Energy’s customer receivables at December 31, 2020 and 2019 included $1.1 billion and $829 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility customers. Virginia Power’s customer receivables at December 31, 2020 and 2019 included $740 million and $512 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers. See Note 25 for amounts attributable to related parties.
The primary types of sales and service activities reported as operating revenue for Dominion Energy are as follows:
Revenue from Contracts with Customers
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Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;
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Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates and associated hedging activity;
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Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services;
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Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties and associated hedging activity;
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Regulated gas transportation and storage sales consist of state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers, sales of gathering services and sales of transportation services to off-system customers;
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Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities; and
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Other nonregulated revenue consists primarily of sales of commodities related to nonregulated extraction activities and other miscellaneous products. Other nonregulated revenue also includes sales of energy-related products and services from Dominion Energy’s retail energy marketing operations, sales to Virginia Power customers from non-jurisdictional solar generation facilities and service concession arrangements.
Other Revenue
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Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.
The primary types of sales and service activities reported as operating revenue for Virginia Power are as follows:
Revenue from Contracts with Customers
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Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services;
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Other regulated revenue consists primarily of sales of excess capacity and other commodities and miscellaneous service revenue from electric distribution operations; and
•
Other nonregulated revenue consists primarily of sales to customers from non-jurisdictional solar generation facilities, revenue from renting space on certain electric transmission poles and distribution towers and service concession arrangements.
Other Revenue
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Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.
The Companies record refunds to customers as required by state commissions as a reduction to regulated electric sales or regulated gas sales, as applicable. The Companies’ revenue accounted for under the alternative revenue program guidance primarily consists of the equity return for under-recovery of certain riders. Alternative revenue programs compensate the Companies for certain projects and initiatives. Revenues arising from these programs are presented separately from revenue arising from contracts with customers in the categories above.
Revenues from electric and gas sales are recognized over time, as the customers of the Companies consume gas and electricity as it is delivered. Fixed fees are recognized ratably over the life of the contract as the stand-ready performance obligation is satisfied, while variable usage fees are recognized when Dominion Energy has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the performance obligation completed to date. Sales of products and services typically transfer control and are recognized as revenue upon delivery of the product or service. The customer is able to direct the use of, and obtain substantially all of the benefits from, the product at the time the product is delivered. The contract with the customer states the final terms of the sale, including the description, quantity and price of each product or service purchased. Payment for most sales and services varies by contract type, but is typically due within a month of billing.
Operating revenue for the gas transmission and storage operations sold or to be sold to BHE as part of the GT&S Transaction and the Q-Pipe Transaction primarily consists of FERC-regulated sales of transmission and storage services, LNG terminalling services, sales of extracted products and associated hedging activities and NGL activities, including gathering and processing and sales of production and condensate as well as services performed for Atlantic Coast Pipeline. This revenue is included in discontinued operations in Dominion Energy’s Consolidated Statements of Income.
Transportation and storage contracts associated with the operations sold or to be sold to BHE as part of the GT&S Transaction and the Q-Pipe Transaction are primarily stand-ready service contracts that include fixed reservation and variable usage fees. LNG terminalling services, included in discontinued operations, are also stand-ready service contracts, primarily consisting of fixed fees, offset by service credits associated with the start-up phase of the Liquefaction Facility. NGLs received during natural gas processing are recorded in discontinued operations at fair value as service revenue recognized over time, and revenue continues to be recognized from the subsequent sale of the NGLs to customers upon delivery.
Credit Risk
Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.
The Companies maintain a provision for credit losses based on factors surrounding the credit risk of their customers, historical trends and other information. Effective January 2020, expected credit losses are estimated and recorded based on historical experience, current conditions and reasonable and supportable forecasts that affect the collectability of financial assets held at amortized cost as well as expected credit losses on commitments with respect to financial guarantees.
Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs
Where permitted by regulatory authorities, the differences between the Companies’ actual electric fuel and purchased energy expenses and Dominion Energy’s purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.
Of the cost of fuel used in electric generation and energy purchases to serve Virginia utility customers, at December 31, 2020, approximately 85% is subject to Virginia Power’s deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms. Of the cost of fuel used in electric generation and energy purchases to serve South Carolina utility customers, at December 31, 2020, approximately 96% is subject to DESC’s deferred fuel accounting.
Virtually all of East Ohio, Questar Gas, Hope, DESC and PSNC’s natural gas purchases are either subject to deferral accounting or are recovered from the customer in the same accounting period as the sale.
Income Taxes
A consolidated federal income tax return is filed for Dominion Energy and its subsidiaries, including Virginia Power. In addition, where applicable, combined income tax returns for Dominion Energy and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed.
Virginia Power participates in intercompany tax sharing agreements with Dominion Energy and its subsidiaries. Current income taxes are based on taxable income or loss and credits determined on a separate company basis.
Under the agreements, if a subsidiary incurs a tax loss or earns a credit, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or credit or to the extent the tax loss or credit is absorbed by the taxable income of other Dominion Energy consolidated group members. Otherwise, the net operating loss or credit is carried forward and is recognized as a deferred tax asset until realized.
Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. The Companies establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.
The Companies recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.
If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the Consolidated Balance Sheets and current payables are included in accrued interest, payroll and taxes on the Consolidated Balance Sheets.
The Companies recognize interest on underpayments and overpayments of income taxes in interest expense and other income, respectively. Penalties are also recognized in other income.
At December 31, 2020, Virginia Power had an income tax-related affiliated payable of $19 million, comprised of $17 million of federal income taxes and $2 million of state income taxes due to Dominion Energy. These affiliated balances are expected to be paid to Dominion Energy.
At December 31, 2019, Virginia Power had an income tax-related affiliated payable of $35 million, comprised of $15 million of federal income taxes and $20 million of state income taxes due to Dominion Energy. Virginia Power’s net affiliated balances were paid to Dominion Energy.
Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.
Cash, Restricted Cash and Equivalents
Cash, restricted cash and equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.
Current banking arrangements generally do not require checks to be funded until they are presented for payment. The following table illustrates the checks outstanding but not yet presented for payment and recorded in accounts payable for the Companies:
Restricted Cash and Equivalents
The Companies hold restricted cash and equivalent balances that primarily consist of amounts held for litigation settlements, customer deposits and future debt payments on SBL Holdco and Dominion Solar Projects III, Inc.’s term loan agreements and on Eagle Solar’s senior note agreement.
The following table provides a reconciliation of the total cash, restricted cash and equivalents reported within the Companies’ Consolidated Balance Sheets to the corresponding amounts reported within the Companies’ Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018:
(1)
At December 31, 2020, December 31, 2019, December 31, 2018 and December 31, 2017, Dominion Energy had $7 million, $31 million, $110 million and $21 million of cash and cash equivalents included in current assets held for sale, respectively.
(2)
At December 31, 2020, December 31, 2019, December 31, 2018 and December 31, 2017, Dominion Energy had $3 million, $12 million, $89 million and $39 million of restricted cash included in current assets held for sale, respectively.
(3)
Restricted cash and equivalent balances are presented within other current assets in the Companies’ Consolidated Balance Sheets.
Supplemental Cash Flow Information
The following table provides supplemental disclosure of cash flow information related to Dominion Energy:
(1)
See the New Accounting Standards section below for noncash investing and financing activities related to the adoption of a new accounting standard for leasing arrangements.
(2)
See Note 3 for noncash investing and financing activities related to the SCANA Combination.
(3)
See Note 5 for noncash activities related to the sale of a noncontrolling interest in Cove Point.
(4)
See Note 9 for noncash investing activities related to the acquisition of a noncontrolling interest in Wrangler.
(5)
See Notes 18,19 and 20 for noncash financing activities related to the acquisition of the public interest in Dominion Energy Midstream, the remarketing of RSNs, the issuance of stock purchase contracts associated with the 2019 Equity Units, the contribution of stock to Dominion Energy’s qualified defined benefit pension plan, derivative restructuring and the issuance of common stock associated with the settlement of litigation. See Note 23 for non-cash investing activities related to property, plant and equipment conveyed to satisfy litigation.
(6)
Includes $46 million of finance leases and $127 million of operating leases at December 31, 2020 and $113 million of finance leases and $44 million of operating leases at December 31, 2019.
The following table provides supplemental disclosure of cash flow information related to Virginia Power:
(1)
See the New Accounting Standards section below for noncash investing and financing activities related to the adoption of a new accounting standard for leasing arrangements.
(2)
See Note 18 for non-cash financing activities related to derivative restructuring.
(3)
Includes $32 million of finance leases as of December 31, 2020 and $20 million of finance leases and $35 million of operating leases as of December 31, 2019.
Distributions from Equity Method Investees
Dominion Energy holds investments that are accounted for under the equity method of accounting and classifies distributions from equity method investees as either cash flows from operating activities or cash flows from investing activities in the Consolidated Statements of Cash Flows according to the nature of the distribution. Distributions received are classified on the basis of the nature of the activity of the investee that generated the distribution as either a return on investment (classified as cash flows from operating activities) or a return of an investment (classified as cash flows from investing activities) when such information is available to Dominion Energy.
Derivative Instruments
The Companies are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as interest rate risk in their business operations. The Companies use derivative instruments such as physical and financial forwards, futures, swaps, options and FTRs to manage the commodity and interest rate risks of their business operations.
All derivatives, except those for which an exception applies, are required to be reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives.
The Companies do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion Energy had margin assets of $19 million and $42 million associated with cash collateral at December 31, 2020 and 2019, respectively. Dominion Energy had margin liabilities of $5 million and $2 million associated with cash collateral at December 31, 2020 and 2019, respectively. Virginia Power had margin assets of $1 million and less than $1 million associated with cash collateral at December 31, 2020 and 2019, respectively. Virginia Power had no margin liabilities associated with cash collateral at December 31, 2020 and 2019. See Note 7 for further information about derivatives.
To manage price risk, the Companies hold derivative instruments that are not designated as hedges for accounting purposes. However, to the extent the Companies do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices. All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses, interest and related charges or discontinued operations based on the nature of the underlying risk.
Changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.
Derivative Instruments Designated as Hedging Instruments
In accordance with accounting guidance pertaining to derivatives and hedge accounting, the Companies designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For derivative instruments that are accounted for as cash flow hedges or fair value hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.
Cash Flow Hedges-A majority of the Companies’ hedge strategies represents cash flow hedges of the variable price risk primarily associated with the purchase of natural gas. The Companies also use interest rate swaps to hedge their exposure to variable interest rates on long-term debt. For transactions in which the Companies are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.
Fair Value Hedges-Dominion Energy has also designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting.
Property, Plant and Equipment
Property, plant and equipment is recorded at lower of original cost or fair value, if impaired. Capitalized costs include labor, materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is generally charged to expense as it is incurred.
In 2020, 2019, and 2018, Dominion Energy capitalized interest costs and AFUDC to property, plant and equipment of $103 million, $78 million and $109 million, respectively. In 2020, 2019, and 2018, Virginia Power capitalized AFUDC to property, plant and equipment of $60 million, $34 million and $56 million, respectively.
Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2020, 2019, and 2018, Virginia Power recorded $11 million, $11 million and $4 million of AFUDC related to these projects, respectively.
For property subject to cost-of-service rate regulation, including the Companies’ electric distribution, electric transmission and generation property and Dominion Energy’s natural gas distribution property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities. For property subject to cost-of-service rate regulation that will be abandoned significantly before the end of its useful life, the net carrying value is reclassified from plant-in-service when it becomes probable it will be abandoned and recorded as a regulatory asset for amounts expected to be collected through future rates.
In 2020 and 2019, the Companies had the following charges, primarily recorded in impairment of assets and other charges in the Consolidated Statements of Income (reflected in the Corporate and Other segment), related to early retirements:
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In March 2020, Virginia Power committed to retire certain coal- and oil-fired generating units before the end of their useful lives based on economic and other factors, including but not limited to market power prices and the VCEA. These units will
be retired after they meet their capacity obligations to PJM in 2023. As a result, Virginia Power recorded a charge of $751 million ($559 million after-tax). This charge is considered a component of Virginia Power’s base rates deemed recovered under the GTSA, subject to review as discussed in Note 13. Also in 2020, Virginia Power recorded charges of $54 million ($40 million after-tax) associated with dismantling certain of these electric generation facilities.
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In January 2019, Virginia Power committed to a plan to retire certain automated metering reading infrastructure associated with its electric operations before the end of its estimated useful life and replace such equipment with more current AMI technology. As a result, Virginia Power recorded a charge of $160 million ($119 million after-tax). This charge is considered a component of Virginia Power’s base rates deemed recovered under the GTSA, subject to review as discussed in Note 13.
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In March 2019, Virginia Power committed to retire certain electric generating units before the end of their useful lives and completed the retirement of certain units at six facilities representing 1,292 MW of electric generating capacity, which had previously been placed in cold reserve. An additional unit at Possum Point power station was retired after meeting its capacity obligation to PJM in December 2020. As a result, Virginia Power recorded a charge of $346 million ($257 million after-tax). This charge is considered a component of Virginia Power’s base rates deemed recovered under the GTSA, subject to review as discussed in Note 13.
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In May 2019, Virginia Power abandoned a coal rail project at its Mt. Storm generating facility. As a result, Virginia Power recorded a charge of $62 million ($46 million after-tax).
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In September 2019, the Companies abandoned certain property, plant and equipment before the end of its useful life. As a result, Dominion Energy recorded a charge of $26 million ($19 million after-tax) and Virginia Power recorded a charge of $17 million ($12 million after-tax).
For property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date.
Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. The Companies’ average composite depreciation rates on utility property, plant and equipment are as follows:
(1)
Excludes rates for depreciation reported as discontinued operations.
In 2020, Virginia Power updated depreciation rates for its nuclear plants to reflect lower depreciation rates as a result of expected approval of license extensions from the NRC. For the year ended December 31, 2020, this adjustment resulted in a decrease of $31 million ($23 million after-tax) in depreciation expense in Virginia Power’s Consolidated Statements of Income and an increase to Dominion Energy’s EPS of $0.03 per share.
In 2018, Virginia Power revised depreciation rates for regulated nuclear plants to comply with Virginia Commission requirements. For the year ended December 31, 2018, this adjustment resulted in a decrease of $60 million ($44 million after-tax) in depreciation expense in Virginia Power’s Consolidated Statements of Income and an increase to Dominion Energy’s EPS of $0.07 per share. This change resulted in an annual decrease in depreciation expense of $30 million ($23 million after-tax).
Virginia Power’s non-jurisdictional property, plant and equipment is depreciated using the straight-line method over an estimated useful life of 30 years.
Capitalized costs of development wells and leaseholds are amortized on a field-by-field basis using the unit-of-production method and the estimated proved developed or total proved gas and oil reserves, at a rate of $1.97 and $1.80 per mcfe in 2020 and 2019, respectively.
Dominion Energy’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:
Depreciation and amortization related to Virginia Power’s nonutility property, plant and equipment and Dominion Energy’s exploration and production properties was immaterial for the years ended December 31, 2020, 2019, and 2018.
Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. The Companies report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.
Long-Lived and Intangible Assets
The Companies perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 6 for further discussion on the impairment of long-lived assets.
Regulatory Assets and Liabilities
The accounting for the Companies’ regulated electric and gas operations differs from the accounting for nonregulated operations in that the Companies are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred.
The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and make various assumptions in their analyses. These analyses are generally based on:
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Orders issued by regulatory commissions, legislation and judicial actions;
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Past experience;
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Discussions with applicable regulatory authorities and legal counsel;
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Forecasted earnings; and
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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.
Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. A regulatory liability, if considered probable, will be recorded in the period such assessment is made or reversed into earnings if no longer probable. See Notes 12 and 13 to the Consolidated Financial Statements for additional information.
Leases
The Companies lease certain assets including vehicles, real estate, office equipment and other operational assets under both operating and finance leases. For the Companies’ operating leases, rent expense is recognized on a straight-line basis over the term of the lease agreement, subject to regulatory framework. Rent expense associated with operating leases, short-term leases and variable leases is primarily recorded in other operations and maintenance expense in the Companies’ Consolidated Statements of Income. Rent expense associated with finance leases results in the separate presentation of interest expense on the lease liability and amortization expense of the related right-of-use asset in the Companies’ Consolidated Statements of Income.
Certain of the Companies’ leases include one or more options to renew, with renewal terms that can extend the lease from one to 70 years. The exercise of renewal options is solely at the Companies’ discretion and is included in the lease term if the option is reasonably certain to be exercised. A right-of-use asset and corresponding lease liability for leases with original lease terms of one year or less are not included in the Consolidated Balance Sheets, unless such leases contain renewal options that the Companies are reasonably certain will be exercised. Additionally, certain of the Companies’ leases contain escalation clauses whereby payments are adjusted for consumer price or other indices or contain fixed dollar or percentage increases. The Companies also have leases with variable payments based upon usage of, or revenues associated with, the leased assets.
The determination of the discount rate utilized has a significant impact on the calculation of the present value of the lease liability included in the Companies’ Consolidated Balance Sheets. For the Companies’ fleet of leased vehicles, the discount rate is equal to the prevailing borrowing rate earned by the lessor. For the Companies’ remaining leased assets, the discount rate implicit in the lease is generally unable to be determined from a lessee perspective. As such, the Companies use internally-developed incremental borrowing rates as a discount rate in the calculation of the present value of the lease liability. The incremental borrowing rates are determined based on an analysis of the Companies’ publicly available unsecured borrowing rates, adjusted for a collateral discount, over various lengths of time that most closely correspond to the Companies’ lease maturities.
In addition, Dominion Energy acts as lessor under certain power purchase agreements in which the counterparty or counterparties purchase substantially all of the output of certain solar facilities. These leases are considered operating in nature. For such leasing arrangements, rental revenue and an associated accounts receivable are recorded when the monthly output of the solar facility is determined. Depreciation on these solar facilities is computed on a straight-line basis over an estimated useful life of 30 years.
Asset Retirement Obligations
The Companies recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed, for which a legal obligation exists. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is estimated using discounted cash flow analyses. Quarterly, the Companies assess their AROs to determine if circumstances indicate that estimates of the amounts or timing of future cash flows associated with retirement activities have changed. AROs are adjusted when significant changes in the amounts or timing of future cash flows are identified. Dominion Energy reports accretion of AROs and depreciation on asset retirement costs associated with its natural gas pipelines as an adjustment to the related regulatory assets or liabilities when revenue is recoverable from customers for AROs. The Companies report accretion of AROs and depreciation on asset retirement costs associated with decommissioning its nuclear power stations as an adjustment to the regulatory asset or liability for certain jurisdictions. Additionally, the Companies report accretion of AROs and depreciation on asset retirement costs associated with certain rider and prospective rider projects as an adjustment to the regulatory asset for certain jurisdictions. Accretion of all other AROs and depreciation of all other asset retirement costs are reported in other operations and maintenance expense and depreciation expense, respectively, in the Consolidated Statements of Income.
Debt Issuance Costs
The Companies defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. Deferred debt issuance costs are recorded as a reduction in long-term debt in the Consolidated Balance Sheets. Amortization of the issuance costs is reported as interest expense. Unamortized costs associated with redemptions of debt securities prior to stated maturity dates are generally recognized and recorded in interest expense immediately. As permitted by regulatory authorities, gains or losses resulting from the refinancing or redemption of debt allocable to utility operations subject to cost-based rate regulation are deferred and amortized.
Investments
Debt and Equity Securities with Readily Determinable Fair Values
Dominion Energy accounts for and classifies investments in debt securities as trading or available-for-sale securities. Virginia Power classifies investments in debt securities as available-for-sale securities.
•
Debt securities classified as trading securities include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.
•
Debt securities classified as available-for-sale securities include all other debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any credit-related impairments) on investments held in nuclear decommissioning trusts are deferred to a regulatory asset or liability, as applicable, for certain jurisdictions subject to cost-based regulation. For all other available-for-sale debt securities, including those held in Dominion Energy’s nonregulated generation nuclear decommissioning trusts, net realized gains and losses (including any credit-related impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax.
In determining realized gains and losses for debt securities, the cost basis of the security is based on the specific identification method.
Equity securities with readily determinable fair values include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans and securities held by the Companies in the nuclear decommissioning trusts. The Companies record all equity securities with a readily determinable fair value, or for which they are permitted to estimate fair value using NAV (or its equivalent), at fair value in nuclear decommissioning trust funds and other investments in the Consolidated Balance Sheets. However, the Companies may elect a measurement alternative for equity securities without a readily determinable fair value. Under the measurement alternative, equity securities are reported at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. The Companies qualitatively assess equity securities reported using the measurement alternative to determine whether an investment is impaired on an ongoing basis. Net realized and unrealized gains and losses on equity securities held in the nuclear decommissioning trusts are deferred to a regulatory asset or liability, as applicable, for certain jurisdictions subject to cost-based regulation. For all other equity securities, including those held in Dominion Energy’s nonregulated generation nuclear decommissioning trusts and rabbi trusts, net realized and unrealized gains and losses are included in other income in the Consolidated Statements of Income.
Equity Securities without Readily Determinable Fair Values
The Companies account for illiquid and privately held securities without readily determinable fair values under either the equity method or cost method. Equity securities without readily determinable fair values include:
•
Equity method investments when the Companies have the ability to exercise significant influence, but not control, over the investee. Dominion Energy’s investments are included in investments in equity method affiliates in its Consolidated Balance Sheets, except for the liability to Atlantic Coast Pipeline or where such investments are classified as held for sale. Dominion Energy records equity method adjustments in other income in its Consolidated Statements of Income, including its proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method.
•
Cost method investments when the Companies do not have the ability to exercise significant influence over the investee. The Companies’ investments are included in other investments and nuclear decommissioning trust funds. Cost method investments are reported at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same issuer.
Other-Than-Temporary Impairment
The Companies periodically review their equity method investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in the fair value of any security is determined to be other-than-temporary, the investment is written down to its fair value at the end of the reporting period.
Credit Impairment
Effective January 2020, the Companies periodically review their available-for-sale debt securities to determine whether a decline in fair value should be considered credit related. If a decline in the fair value of any available-for-sale debt security is determined to be
credit related, the credit-related impairment is recorded to an allowance included in nuclear decommissioning trust funds in the Companies’ Consolidated Balance Sheets at the end of the reporting period, with such allowance for credit losses subject to reversal in subsequent evaluations.
Using information obtained from their nuclear decommissioning trust fixed-income investment managers, the Companies record in earnings, or defer as applicable for certain jurisdictions subject to cost-based regulation, any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, the Companies record the credit loss in earnings or defer as applicable for certain jurisdictions subject to cost-based regulation, with the remaining non-credit portion of the unrealized loss recorded in AOCI. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.
Inventories
Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory is valued using the weighted-average cost method, except for East Ohio gas distribution operations, which are valued using the LIFO method. Under the LIFO method, current stored gas inventory was valued at $2 million and $19 million at December 31, 2020 and December 31, 2019, respectively. Based on the average price of gas purchased during 2020 and 2019, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by $52 million and $60 million, respectively.
Gas Imbalances
Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion Energy values these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Dominion Energy from other parties are reported in other current assets and imbalances that Dominion Energy owes to other parties are reported in other current liabilities in the Consolidated Balance Sheets.
Goodwill
Dominion Energy evaluates goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount.
New Accounting Standards
Debt with Conversion Options and Contracts in an Entity’s Own Equity
In August 2020, the FASB issued revised accounting guidance for debt with conversion options and contracts in an entity’s own equity. The revised guidance eliminates the ability to assert cash settlement and exclude potential shares from the diluted EPS calculation for a contract that may be settled in stock or cash. The effective date is for interim and annual reporting periods beginning January 1, 2022 and may be adopted through a modified retrospective or fully retrospective method of transition. Upon adoption, Dominion Energy will apply the if-converted method to calculate diluted EPS in connection with any potentially dilutive instruments, or components of instruments, that may be settled in stock or cash, such as the Series A Preferred Stock.
Revenue Recognition
In May 2014, the FASB issued revised accounting guidance for revenue recognition from contracts with customers. The Companies adopted this revised accounting guidance for interim and annual reporting periods beginning January 1, 2018 using the modified retrospective method. Upon the adoption of the standard, Dominion Energy recorded the cumulative-effect of a change in accounting principle of $3 million to retained earnings, and to establish a contract asset related to changes in the timing of revenue recognition for three existing contracts with customers at DETI.
Financial Instruments
In January 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of financial instruments. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018 and the Companies adopted the standard using the modified retrospective method. Upon adoption of this guidance for equity securities held at January 1, 2018, The Companies recorded the cumulative-effect of a change in accounting principle to reclassify net unrealized gains from AOCI to retained earnings and to recognize equity securities previously categorized as cost method investments at fair value (using NAV) in nuclear decommissioning trust funds in the Consolidated Balance Sheets and a cumulative-effect adjustment to retained earnings. Dominion Energy and Virginia Power reclassified approximately $1.1 billion ($734 million after-tax) and $119 million ($73 million after-tax), respectively, of net unrealized gains from AOCI to retained earnings. The Companies also
recorded approximately $36 million ($22 million after-tax) in net unrealized gains on equity securities previously classified as cost method investments, of which $3 million was recorded to retained earnings and $33 million was recorded to regulatory liabilities for net unrealized gains subject to cost-based regulation. As a result of adopting this revised accounting guidance, Dominion Energy recorded unrealized losses on equity securities, net of regulatory deferrals, of $190 million ($142 million after-tax) in other income in the Consolidated Statements of Income for the year ended December 31, 2018, resulting in an $0.22 loss per share for the year ended December 31, 2018. Virginia Power recorded unrealized losses on equity securities, net of regulatory deferrals, of $24 million ($18 million after-tax) in other income in the Consolidated Statements of Income for the year ended December 31, 2018.
Leases
In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases classified as operating leases, while also refining the definition of a lease. In addition, lessees are required to disclose key information about the amount, timing and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged.
The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2019. The Companies adopted this revised accounting guidance using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Companies utilized the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Companies also applied the other practical expedients, which required no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. In connection with the adoption of this revised accounting guidance, Dominion Energy and Virginia Power recorded $504 million and $209 million, respectively, of offsetting right-of-use assets and liabilities for operating leases in effect at the adoption date. As a result of the GT&S and Q-Pipe Transactions, $43 million of such right-of-use assets and liabilities for operating leases recorded were associated with discontinued operations. See Note 15 for additional information.
Derecognition and Partial Sales of Nonfinancial Assets
In February 2017, the FASB issued revised accounting guidance clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018, and the Companies adopted the standard using the modified retrospective method. Upon adoption of the standard, Dominion Energy recorded the cumulative-effect of a change in accounting principle to reclassify $127 million from noncontrolling interests to common stock related to the sale of a noncontrolling interest in certain nonregulated solar projects completed in December 2015 and January 2016.
Tax Reform
In February 2018, the FASB issued revised accounting guidance to provide clarification on the application of the 2017 Tax Reform Act for balances recorded within AOCI. The revised guidance provides for stranded amounts within AOCI from the impacts of the 2017 Tax Reform Act to be reclassified to retained earnings. The Companies adopted this guidance for interim and annual reporting periods beginning January 1, 2018 on a prospective basis. In connection with the adoption of this guidance, Dominion Energy reclassified a benefit of $289 million from AOCI to retained earnings and Virginia Power reclassified a benefit of $3 million from AOCI to retained earnings. The amounts reclassified reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of the Companies’ AOCI.
NOTE 3. ACQUISITIONS AND DISPOSITIONS
Dominion Energy
Disposition of Gas Transmission & Storage Operations to BHE
In July 2020, Dominion Energy entered into an agreement with BHE with a total value of approximately $10 billion, comprised of approximately $4.0 billion of cash consideration (subject to customary closing adjustments) plus the assumption of long-term debt, to sell substantially all of its gas transmission and storage operations, including processing assets, as well as noncontrolling partnership interests in Iroquois, JAX LNG and White River Hub and a controlling interest in Cove Point (consisting of 100% of the general partner interest and 25% of the total limited partner interests). The agreement provides that Dominion Energy retains the assets and obligations of the pension and other postretirement employee benefit plans associated with the operations included in the transaction and relating to services provided through closing. In October 2020, pursuant to a provision in the agreement with BHE, Dominion Energy elected to exclude Dominion Energy Questar Pipeline and certain other affiliated entities from the transaction as approval under the Hart-Scott-Rodino Act had not been obtained by mid-September 2020. Concurrently in October 2020, Dominion Energy
and BHE entered into a separate agreement under which Dominion Energy will sell Dominion Energy Questar Pipeline and certain other affiliated entities to BHE for cash consideration of $1.3 billion and the assumption of related long-term debt.
In November 2020, Dominion Energy completed the GT&S Transaction and received cash proceeds of $2.7 billion. This transaction is structured as an asset sale for tax purposes. Dominion Energy retained a 50% noncontrolling interest in Cove Point that is accounted for as an equity method investment upon closing of the GT&S Transaction as Dominion Energy has the ability to exercise significant influence over, but not control, Cove Point. The retained 50% noncontrolling interest in Cove Point was recognized at its initial fair value of $2.8 billion on the date of close estimated using an income approach and a market approach. The valuation is considered a Level 3 fair value measurement due to the use of significant judgment and unobservable inputs, including projected timing and amount of future cash flows and a discount rate reflecting risks inherent in the future cash flows and market prices. Upon closing the GT&S Transaction, Dominion Energy recognized a gain of $127 million (net of a $1.4 billion write-off of goodwill and a $222 million closing adjustment paid to BHE in December 2020) and an associated tax expense of $336 million, presented in net income (loss) from discontinued operations including noncontrolling interest in Dominion Energy’s Consolidated Statements of Income.
In connection with closing of the GT&S Transaction, Dominion Energy and BHE entered into a transition services agreement under which Dominion Energy will continue to provide specified administrative services to support the operations of the disposed business for up to 24 months after closing. In addition, BHE will provide certain administrative services to Dominion Energy. Dominion Energy recorded revenue of $4 million associated with the transition service agreement in operating revenue in the Consolidated Statements of Income for the year ended December 31, 2020.
Also in November 2020, BHE provided a $1.3 billion deposit to Dominion Energy on the Q-Pipe Transaction. Dominion Energy will be required to repay all or substantially all of this deposit, or issue to BHE an equivalent value in shares of Dominion Energy common stock at Dominion Energy’s option, if the Q-Pipe Transaction does not close by December 30, 2021. Dominion Energy may not solicit or accept offers from alternative buyers for all or a material portion of the Q-Pipe Transaction until after March 31, 2021 and either party may terminate the Q-Pipe Transaction if closing has not occurred on or before June 30, 2021. If the Hart-Scott-Rodino Act approval has not been obtained by June 30, 2021, upon BHE’s request, Dominion Energy will seek an alternative buyer for all or a material portion of the Q-Pipe Transaction. The Q-Pipe Transaction is structured as an asset sale for tax purposes and is expected to close in early 2021, contingent on clearance or approval under the Hart-Scott-Rodino Act, and other customary closing and regulatory conditions. Based on the recorded balances at December 31, 2020, Dominion Energy expects to recognize a pre-tax gain of approximately $450 million ($320 million after tax) upon closing, including the write-off of $191 million of goodwill, but excluding the effects of any closing adjustments.
The operations included in both the GT&S Transaction and the Q-Pipe Transaction are presented in held-for-sale and discontinued operations effective July 2020. As a result, the previously reported amounts have been recast to reflect this presentation and depreciation and amortization ceased on the applicable assets. As Cove Point had previously been consolidated within Dominion Energy’s financial statements, balances associated with Cove Point prior to the closing of the GT&S Transaction are presented within held-for-sale and discontinued operations. See Note 9 for further information regarding Dominion Energy’s equity method investment in Cove Point.
The following table represents selected information regarding the results of operations, which are reported within discontinued operations in Dominion Energy’s Consolidated Statements of Income:
(1)
Operations associated with the GT&S Transaction are through the November 1, 2020 settlement date.
(2)
GT&S Transaction includes a charge of $482 million ($359 million after-tax) recorded in the second quarter of 2020 associated with the probable abandonment of a significant portion of the Supply Header Project as well as the establishment of a $75 million ARO as a result of the cancellation of the Atlantic Coast Pipeline Project. It also includes charges of $219 million ($165 million after-tax) associated with the impairment of certain gathering and processing assets, $127 million ($92 million after-tax) associated with the disallowance of FERC-regulated plant and $37 million ($28 million after-tax) write-off associated with the Eastern Market Access Project all recorded in 2018.
(3)
GT&S Transaction includes gains on sales of assets recorded in 2018 totaling $115 million ($83 million after-tax), associated with the conveyance of Marcellus Shale and Utica and Point Pleasant Shale acreage underneath its natural gas storage fields.
(4)
GT&S Transaction includes a loss of $237 million ($178 million after-tax) recorded in the third quarter of 2020 associated with cash flow hedges of debt-related items that were determined to be probable of not occurring.
The carrying amounts of major classes of assets and liabilities relating to the disposal groups, which are reported as held for sale in Dominion Energy’s Consolidated Balance Sheets, were as follows:
(1)
All amounts at December 31, 2020 are classified as current in Dominion Energy’s Consolidated Balance Sheets.
(2)
Includes cash and cash equivalents of $20 million as of December 31, 2019 within the GT&S Transaction and $7 million and $11 million as of December 31, 2020 and December 31, 2019, respectively, within the Q-Pipe Transaction.
(3)
Comprised of equity method investments in Iroquois and JAX LNG within the GT&S Transaction and White River Hub within the Q-Pipe Transaction.
(4)
Includes goodwill of $1.4 billion at December 31, 2019 within the GT&S Transaction and $191 million at both December 31, 2020 and December 31, 2019 within the Q-Pipe Transaction.
(5)
Includes current portions of long-term debt of $699 million as of December 31, 2019, within the GT&S Transaction.
Capital expenditures and significant noncash items relating to the disposal groups included the following:
(1)
Operations associated with the GT&S Transaction are through the November 1, 2020 settlement date.
In October 2020, Dominion Energy settled various derivatives related to, but not included in, the GT&S Transaction for a payment of $165 million.
Acquisition of SCANA
In January 2019, Dominion Energy issued 95.6 million shares of Dominion Energy common stock, valued at $6.8 billion, representing 0.6690 of a share of Dominion Energy common stock for each share of SCANA common stock, in connection with the completion of the SCANA Combination. SCANA, through its regulated subsidiaries, is primarily engaged in the generation, transmission and distribution of electricity in the central, southern and southwestern portions of South Carolina and in the distribution of natural gas in North Carolina and South Carolina. In addition, at the closing of the SCANA Combination, SCANA marketed natural gas to retail customers in the southeast U.S. Following completion of the SCANA Combination, SCANA operates as a wholly-owned subsidiary of Dominion Energy. In addition, SCANA’s debt totaled $6.9 billion at closing. The SCANA Combination expanded Dominion Energy’s portfolio of regulated electric generation, transmission and distribution and regulated natural gas distribution infrastructure operations.
Merger Conditions
Refunds to Customers
As a condition to the SCANA Merger Approval Order, DESC will provide refunds and restitution of $2.0 billion over 20 years with capital support from Dominion Energy.
In September and October 2017, DESC received proceeds totaling $1.1 billion in full satisfaction of its share of a settlement agreement among DESC, Santee Cooper and Toshiba Corporation in connection with Westinghouse and WECTEC, both wholly-owned subsidiaries of Toshiba Corporation and responsible for the engineering and construction of the NND Project, filing for bankruptcy. The purchase price allocation below includes a previously established regulatory liability at DESC totaling $1.1 billion, of which $67 million was considered current, associated with the monetization of the bankruptcy settlement with Toshiba Corporation. In accordance with the terms of the SCANA Merger Approval Order, this regulatory liability, net of amounts that may be required to satisfy any liens against NND Project property, totaling $1.0 billion will be refunded to DESC electric service customers over a 20-year period ending in 2039.
Additionally, in the first quarter of 2019, DESC recorded a reduction in operating revenue and a corresponding regulatory liability of $1.0 billion, of which $137 million was considered current, representing a refund of amounts previously collected from retail electric customers of DESC for the NND Project to be credited over an estimated 11-year period, effective February 2019. As a result, Dominion Energy’s Consolidated Statements of Income for the year ended December 31, 2019 includes a $756 million after-tax charge which is reflected in the Corporate and Other segment.
NND Project
As a condition to the SCANA Merger Approval Order, DESC committed to excluding from rate recovery $2.4 billion of costs related to the NND Project and $180 million of costs associated with the purchase of the Columbia Energy Center power station. Regulatory assets included in SCANA’s historical balance sheet at December 31, 2018 reflected these disallowances.
The remaining regulatory asset associated with the NND Project of $2.8 billion, of which $138 million was considered current, will be collected over a 20-year period, including a return on investment. In January 2019, DESC filed the capital cost rider in accordance with the terms of the SCANA Merger Approval Order for rates effective in February 2019 for DESC’s retail electric customers. The South Carolina Commission approved this filing in January 2019.
Other Terms and Conditions
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DESC agreed not to file an application for a general rate case with the South Carolina Commission with a requested effective date earlier than January 2021. See Note 13 for information on the status of DESC’s ongoing base rate case;
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PSNC will not file an application for a general rate case with the North Carolina Commission any earlier than April 2021;
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Dominion Energy committed to increasing SCANA’s historical level of corporate contributions to charities by $1 million per year over five years beginning in 2019;
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Dominion Energy will maintain DESC and PSNC’s headquarters in Cayce, South Carolina and Gastonia, North Carolina, respectively; and
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Dominion Energy will seek to minimize reductions in local employment by allowing some DES employees supporting shared and common services functions and activities to be located in Cayce, South Carolina where it makes economic and practical sense to do so.
Purchase Price Allocation
SCANA’s assets acquired and liabilities assumed have been measured at estimated fair value at closing and are included in the Dominion Energy South Carolina and Gas Distribution operating segments. The majority of the operations acquired are subject to the rate setting authority of FERC and the North and South Carolina Commissions and are therefore accounted for pursuant to ASC 980, Regulated Operations. The fair values of SCANA’s assets and liabilities subject to rate-setting and cost recovery provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the unaudited pro forma financial information, reflect any adjustments related to these amounts.
The fair value of SCANA’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions discussed above and the fair values of SCANA’s investments accounted for under the equity method were determined using the income approach and the market approach. The valuation of SCANA’s long-term debt is considered a Level 2 fair value measurement. All other valuations are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future market prices.
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was reflected as goodwill. The goodwill reflects the value associated with enhancing Dominion Energy’s portfolio of regulated operations in the growing southeast region of the U.S. The goodwill recognized is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to goodwill.
The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at closing, which reflects certain adjustments related to income taxes, as discussed in Note 5, from the preliminary valuation recognized during the measurement period.
(1)
Includes $389 million of cash, restricted cash and equivalents, of which $115 million is considered restricted.
(2)
Includes $31 million for equity method investments. The fair value adjustment on the equity method investments is considered to be equity method goodwill and is not amortized.
(3)
Includes $105 million of certain property, plant and equipment associated with the NND Project for which Dominion Energy committed to forgo recovery in accordance with the SCANA Merger Approval Order. As a result, Dominion Energy’s Consolidated Statements of Income for the year ended December 31, 2019 include a charge of $105 million ($79 million after-tax), included in impairment of assets and other charges (reflected in the Corporate and Other segment).
(4)
Nonregulated property, plant and equipment, excluding land, will be depreciated on a straight-line basis over the remaining useful lives of such property, primarily ranging from 5 to 78 years.
(5)
Includes $258 million of certain income tax-related regulatory assets associated with the NND Project for which Dominion Energy committed to forgo recovery in accordance with the SCANA Merger Approval Order. See Note 5 for additional information.
(6)
Intangible assets have an estimated weighted-average amortization period of approximately five years.
(7)
Includes $40 million outstanding under letters of credit advances, which were repaid in January 2019, as well as $173 million outstanding commercial paper under various credit facilities. All such credit facilities were terminated in 2019.
(8)
Includes a $379 million pension and other postretirement benefit liability.
(9)
Includes stock-based compensation awards with a fair value of $21 million.
Results of Operations and Unaudited Pro Forma Information
The impact of the SCANA Combination on Dominion Energy’s operating revenue was an increase of $3.3 billion and $3.1 billion for the years ended December 31, 2020 and 2019, respectively, in the Consolidated Statements of Income. The impact of the SCANA Combination on Dominion Energy’s net income attributable to Dominion Energy was an increase of $277 million and a decrease of $1.1 billion for the years ended December 31, 2020 and 2019, respectively, in the Consolidated Statements of Income.
Dominion Energy incurred merger and integration-related costs of $97 million for the year ended December 31, 2020, all of which is recorded in other operations and maintenance expense in the Consolidated Statements of Income. Dominion Energy incurred merger and integration-related costs of $646 million for the year ended December 31, 2019. The amount for the year ended December 31, 2019 includes $427 million for a charge related to a voluntary retirement program. See Note 22 for additional information. Of the remaining merger and integration-related costs, $210 million is recorded in other operations and maintenance expense and $9 million was recorded in interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2019. During the year ended December 31, 2018, Dominion Energy incurred merger and integration-related costs of $27 million, recorded primarily in other operations and maintenance expense in the Consolidated Statements of Income. These costs consist of professional fees, the charitable contribution commitment described above, employee-related expenses, certain financing costs and other miscellaneous costs.
The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion Energy assuming the SCANA Combination had taken place on January 1, 2018. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.
(1)
Amounts include adjustments for non-recurring costs directly related to the SCANA Combination.
Sale of Interest in Cove Point
In October 2019, Dominion Energy signed an agreement to sell its 25% noncontrolling limited partnership interests in Cove Point to Brookfield. In December 2019, the sale was completed and Dominion Energy received cash consideration of $2.1 billion, subject to working capital adjustments. The sale was accounted for by Dominion Energy following the guidance for a change in a parent company’s ownership interest in a consolidated subsidiary. Because Dominion Energy controlled Cove Point both before and after the sale of the noncontrolling interest, the changes in Dominion Energy’s ownership interest in Cove Point was accounted for as an equity transaction and no gain or loss was recognized.
NOTE 4. OPERATING REVENUE
The Companies’ operating revenue consists of the following:
(1)
See Notes 9 and 25 for amounts attributable to related parties and affiliates.
(2)
Amounts above include sales which are considered to be goods transferred at a point in time. For the years ended December 31, 2020, 2019 and 2018, such amounts included $22 million, $37 million and $19 million, respectively, at Dominion Energy, primarily consisting of sales of commodities related to nonregulated extraction activities and other miscellaneous products. Additionally, amounts above include sales of renewable energy credits. For the years ended December 31, 2020, 2019 and 2018, such sales were $20 million, $24 million and $17 million, respectively, at Dominion Energy and $11 million, $17 million and $11 million, respectively, at Virginia Power.
(3)
Amounts above include alternative revenue of $119 million and $82 million for the year ended December 31, 2020 at Dominion Energy and Virginia Power, $66 million and $52 million for year ended December 31, 2019 at Dominion Energy and Virginia Power, respectively, and $15 million for year ended December 31, 2018 at both Dominion Energy and Virginia Power.
(4)
Amounts above include revenue associated with services provided to entities presented in discontinued operations of $4 million for the year ended December 31, 2020 and $6 million for both years ended December 31, 2019 and 2018.
The table below discloses the aggregate amount of the transaction price allocated to fixed-price performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and when Dominion Energy expects to recognize this revenue. These revenues relate to contracts containing fixed prices where Dominion Energy will earn the associated revenue over time as it stands ready to perform services provided. This disclosure does not include revenue related to performance obligations that are part of a contract with original durations of one year or less. In addition, this disclosure does not include expected consideration related to performance obligations for which Dominion Energy elects to recognize revenue in the amount it has a right to invoice.
(1)
Includes $1 million for Virginia Power in 2021.
Contract liabilities represent an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration, or the amount that is due, from the customer. At December 31, 2020 and 2019, Dominion Energy’s contract liability balances were $130 million and $102 million, respectively. At December 31, 2020 and 2019, Virginia Power’s contract liability balances were $36 million and $24 million, respectively. The Companies’ contract liabilities are recorded in other current liabilities and other deferred credits and other liabilities in the Consolidated Balance Sheets. The Companies’ recognize revenue as they fulfill their obligations to provide service to their customers. During the years ended December 31, 2020 and 2019, Dominion Energy recognized revenue of $97 million and $85 million from the beginning contract liability balance. During the years ended December 31, 2020 and 2019, Virginia Power recognized revenue of $24 million and $22 million, respectively, from the beginning contract liability balance.
NOTE 5. INCOME TAXES
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws and associated regulations involves uncertainty, since tax authorities may interpret the laws differently. The Companies are routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.
The Companies have accounted for the effects of the 2017 Tax Reform Act, although additional changes could occur as guidance is issued and finalized as described below.
In March 2020, the CARES Act was enacted which includes several significant business tax provisions that modify or temporarily suspend certain provisions of the 2017 Tax Reform Act. The CARES Act provisions are intended to improve cash flow and liquidity by, among other things, providing a temporary five-year carryback for certain net operating losses, accelerating the refund of previously generated corporate alternative minimum tax credits and temporarily increased the business interest limitation to 50% of adjusted taxable income for certain businesses. Dominion Energy utilized the income tax provisions of the CARES Act to accelerate the recognition of certain tax attributes, but they did not provide a material benefit.
In July 2020, the U.S. Department of Treasury issued final regulations providing guidance about the limitation on the deduction for business interest expenses under the 2017 Tax Reform Act as modified by the CARES Act. For consolidated groups such as Dominion Energy that have both regulated and nonregulated operations, these rules may result in a temporary disallowance of a portion of Dominion Energy’s interest deductions in the future, although any interest disallowed has an indefinite carryforward period.
In December 2020, federal legislation was enacted that, among other things, provides a two-year extension of the beginning construction deadline for, and delays the phase-down of, the solar energy investment tax credit as well as extending the deadlines and phase-down rules for certain other renewable tax credits. The legislation provides that offshore wind facilities are eligible for the investment tax credit if construction on those facilities begins before 2026 with no phase-out. In addition, the U.S. Department of Treasury and the IRS issued guidance for offshore wind that extended the continuity of construction safe harbor to 10 years, which significantly enhances the ability for these projects to qualify for renewable energy tax credits.
As indicated in Note 2, certain of the Companies’ operations, including accounting for income taxes, are subject to regulatory accounting treatment. For regulated operations, many of the changes in deferred taxes from the 2017 Tax Reform Act represent amounts probable of collection from or return to customers, and were recorded as either an increase to a regulatory asset or liability. See Note 13 for more information and current year developments.
Continuing Operations
Details of income tax expense for continuing operations including noncontrolling interests were as follows:
In 2020, Dominion Energy’s current income taxes reflect a benefit from continuing operations as the current income tax expense associated with gas transmission and storage operations, including taxes on the gain, is reflected in discontinued operations. Dominion Energy’s income tax expense reflects the utilization of investment tax credit carryforwards to offset a portion of the federal tax gain on the sale. In addition, an $18 million income tax benefit is reflected in common shareholders’ equity associated with state deferred taxes on assets and liabilities retained in connection with the GT&S Transaction.
In 2019, the Dominion Energy Gas Restructuring caused changes in tax status at certain of its subsidiaries. The impacts of the changes in tax status decreased deferred income tax expense from continuing operations by $48 million at Dominion Energy. In addition, Dominion Energy recognized a taxable gain resulting from the sale of a 25% noncontrolling interest in Cove Point. The direct tax effects of the transactions included a provision for current income taxes ($362 million) and an offsetting benefit for deferred income taxes ($147 million) and were charged to common shareholders’ equity. The utilization of $208 million federal tax credit carryforwards offsetting a portion of the federal tax liability from the transaction were also charged to common shareholders’ equity. In total, the taxes recorded in common shareholders’ equity resulting from this transaction were $215 million.
Discontinued Operations
Income tax expense (benefit) reflected in discontinued operations is $(204) million, $142 million and $58 million for the years ended December 31, 2020, 2019 and 2018, respectively. The 2020 income tax expense reflects a charge of $81 million for the write-off of tax-related regulatory assets associated with the Atlantic Coast Pipeline Project and the absence of a $236 million benefit on non-deductible goodwill written off in connection with the GT&S Transaction.
Continuing Operations
For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to the Companies’ effective income tax rate as follows:
For the Companies’ rate-regulated entities, deferred taxes will reverse at the weighted average rate used to originate the deferred tax liability, which in some cases will be 35%. The Companies have recorded an estimate of excess deferred income tax amortization in 2020, and changes in estimates of amounts probable of collection from or return to customers. The reversal of these excess deferred income taxes will impact the effective tax rate, and rates charged to customers. See Note 13 for current year developments.
Dominion Energy’s 2020 effective tax rate reflects an income tax benefit of $45 million associated with the remeasurement of consolidated state deferred taxes with the classification of gas transmission and storage operations as held for sale. In addition, Dominion Energy’s effective tax rate reflects an income tax expense of $55 million attributable to the noncontrolling interest primarily associated with the impairment of non-wholly-owned nonregulated solar facilities held in partnerships discussed in Note 10.
In connection with the SCANA Combination, Dominion Energy committed to forgo, or limit, the recovery of certain income tax-related regulatory assets associated with the NND Project. Dominion Energy’s effective tax rate reflects deferred income tax expense of $194 million in satisfaction of this commitment. Dominion Energy’s effective tax rate also reflects the changes in consolidated state income taxes resulting from the SCANA Combination.
In 2018, the Companies applied the provisions of proposed regulations addressing the availability of federal bonus depreciation for the period beginning after September 27, 2017 through December 31, 2017. The application of these changes increased Dominion Energy’s 2017 net operating loss carryforward, the benefit of which will be recognized at the 21% rate. As a result, Dominion Energy’s effective tax rate reflects a $23 million increase to deferred income tax expense associated with the remeasurement of this deferred tax asset. The effects of these changes at Virginia Power were immaterial. These amounts and adjustments represent the Companies’ best estimate based on available information, and could be subject to change based on additional guidance in yet to be finalized regulations. In addition, changes in estimates of amounts probable of return to or collection from customers increased deferred income tax expense at Virginia Power by $23 million and increased regulatory liabilities by $31 million. At Dominion Energy, similar changes in estimates decreased income tax expense by $5 million, which is reflected in income tax expense from continuing operations in the Consolidated Statements of Income, and regulatory liabilities by $8 million, which are reflected in noncurrent liabilities of discontinued operations on the 2019 Consolidated Balance Sheets. In addition, Dominion Energy effective tax rates reflects the impacts of a state legislative change enacted in the second quarter of 2018 that was retroactive to January 1, 2018 associated with discontinued operations.
The Companies’ deferred income taxes consist of the following:
At December 31, 2020, Dominion Energy had the following deductible loss and credit carryforwards:
At December 31, 2020, Virginia Power had the following deductible loss and credit carryforwards:
A reconciliation of changes in the Companies’ unrecognized tax benefits follows:
(1)
Acquired unrecognized tax benefits reflect $106 million plus increases in prior period positions of $76 million and decreases in prior period positions of $53 million that were recorded through purchase accounting.
Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations. For Dominion Energy and its subsidiaries, these unrecognized tax benefits were $140 million, $141 million and $37 million at December 31, 2020, 2019, and 2018, respectively. For Dominion Energy, the change in these unrecognized tax benefits decreased income tax expense by $6 million in 2020 and increased income tax expense by $3 million and $6 million in 2019 and 2018, respectively, in continuing operations. For discontinued operations, the change in these unrecognized tax benefits increased income tax expense by $5 million in 2020 and decreased income tax expense by less than $1 million in both 2019 and 2018. For Virginia Power, these unrecognized tax benefits were less than $1 million at December 31, 2019 and $2 million at December 31, 2018. For Virginia Power, the change in these unrecognized tax benefits decreased income tax expense by $2 million in both 2019 and 2018.
Dominion Energy participates in the IRS Compliance Assurance Process which provides the opportunity to resolve complex tax matters with the IRS before filing its federal income tax returns, thus achieving certainty for such tax return filing positions agreed to by the IRS. In 2018, Dominion Energy submitted carryback claims for specified liability losses involving prior tax years. The IRS concluded its examination of these claims in 2020 with no material adjustments. The IRS has completed its audit of tax years through 2018. The statute of limitations has not yet expired for years after 2016. Although Dominion Energy has not received a final letter indicating no changes to its taxable income for tax year 2019, no material adjustments are expected. The IRS examination of tax year 2020 is ongoing.
It is reasonably possible that settlement negotiations and expiration of statutes of limitations could result in a decrease in unrecognized tax benefits in 2021 by up to $69 million for Dominion Energy. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, earnings could increase by up to $7 million for Dominion Energy. Otherwise, with regard to 2020 and prior years, the Companies cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2021.
For each of the major states in which Dominion Energy operates, the earliest tax year remaining open for examination is as follows:
(1)
Considered a major state for entities presented in discontinued operations.
(2)
Considered a major state for Virginia Power’s operations
The Companies are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion Energy utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are generally subject to examination.
NOTE 6. FAIR VALUE MEASUREMENTS
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of the Companies’ own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion Energy applies fair value measurements to certain assets and liabilities including commodity, interest rate, and foreign currency derivative instruments, and other investments including those held in nuclear decommissioning, Dominion Energy’s rabbi, and pension and other postretirement benefit plan trusts, in accordance with the requirements discussed above. Virginia Power applies fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments and other investments including those held in the nuclear decommissioning trust, in accordance with the requirements discussed above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above.
Inputs and Assumptions
Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including industry publications, and to a lesser extent, broker quotes. When evaluating pricing information provided by Designated Contract Market settlement pricing, other pricing services, or brokers, the Companies consider the ability to transact at the quoted price, i.e. if the quotes are based on an active market or an inactive market and to the extent which pricing models are used, if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases the unobservable inputs are developed and substantiated using historical information, available market data, third-party data and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships and changes in third-party sources.
For options and contracts with option-like characteristics where observable pricing information is not available from external sources, the Companies generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. The Companies use other option models under special circumstances, including but not limited to Spread Approximation Model and a Swing Option Model. For contracts with unique characteristics, the
Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.
The inputs and assumptions used in measuring fair value include the following:
For commodity derivative contracts:
•
Forward commodity prices
•
Transaction prices
•
Price volatility
•
Price correlation
•
Volumes
•
Commodity location
•
Interest rates
•
Credit quality of counterparties and the Companies
•
Credit enhancements
•
Time value
For interest rate derivative contracts:
•
Interest rate curves
•
Credit quality of counterparties and the Companies
•
Notional value
•
Credit enhancements
•
Time value
For foreign currency derivative contracts:
•
Foreign currency forward exchange rates
•
Interest rates
•
Credit quality of counterparties and the Companies
•
Notional value
•
Credit enhancements
•
Time value
For investments:
•
Quoted securities prices and indices
•
Securities trading information including volume and restrictions
•
Maturity
•
Interest rates
•
Credit quality
Levels
The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:
•
Level 1-Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as certain exchange-traded derivatives, and exchange-listed equities, U.S. and international equity securities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for the Companies and benefit plan trust funds and rabbi trust funds for Dominion Energy.
•
Level 2-Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include commodity forwards and swaps, interest rate swaps and cash and cash equivalents, corporate debt instruments, government securities and other fixed income investments held in nuclear decommissioning trust funds for the Companies and foreign currency swaps, benefit plan trust funds and rabbi trust funds for Dominion Energy.
•
Level 3-Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for the Companies consist of long-dated commodity derivatives, FTRs, certain natural gas options and other modeled commodity derivatives.
The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. Alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments held in nuclear decommissioning and benefit plan trust funds, are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date. Alternative investments recorded at NAV are not classified in the fair value hierarchy.
Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change.
Level 3 Valuations
The Companies enter into certain physical and financial forwards, futures, options and swaps, which are considered Level 3 as they have one or more inputs that are not observable and are significant to the valuation. The discounted cash flow method is used to value Level 3 physical and financial forwards and futures contracts. An option model is used to value Level 3 physical options. The discounted cash flow model for forwards and futures calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return, and credit spreads. The option model calculates mark-to-market valuations using variations of the Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, the original sales prices and volumes. For Level 3 fair value measurements, certain forward market prices and implied price volatilities are considered unobservable.
The following table presents Dominion Energy’s quantitative information about Level 3 fair value measurements at December 31, 2020. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.
(1)
Averages weighted by volume.
(2)
Includes basis.
(3)
Represents market prices beyond defined terms for Levels 1 and 2.
(4)
Represents volatilities unrepresented in published markets.
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
Nonrecurring Fair Value Measurements
Dominion Energy
See Note 9 for information regarding nonrecurring fair value measurements associated with Dominion Energy’s retained noncontrolling interest in Cove Point, charges related to Fowler Ridge, Dominion Energy’s sale of its interest in Blue Racer and Dominion Energy’s retained noncontrolling interest in businesses and assets contributed to Wrangler. See Note 10 for information regarding an impairment charge recorded associated with non-wholly-owned nonregulated solar facilities in partnerships.
Recurring Fair Value Measurements
Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3. Fair value disclosures for assets held in Dominion Energy’s pension and other postretirement benefit plans are presented in Note 22.
Dominion Energy
The following table presents Dominion Energy’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
(1)
Includes investments held in the nuclear decommissioning trusts and rabbi trusts. Excludes $340 million and $274 million of assets at December 31, 2020 and 2019, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.
The following table presents the net change in Dominion Energy’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2020, 2019 and 2018.
Virginia Power
The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at December 31, 2020. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.
(1)
Averages weighted by volume.
(2)
Includes basis.
(3)
Represents market prices beyond defined terms for Levels 1 and 2.
(4)
Represents volatilities unrepresented in published markets.
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
The following table presents Virginia Power’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
(1)
Includes investments held in the nuclear decommissioning trusts. Excludes $167 million and $159 million of assets at December 31, 2020 and 2019, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.
The following table presents the net change in Virginia Power’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2020, 2019 and 2018.
Fair Value of Financial Instruments
Substantially all of the Companies’ financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash, restricted cash and equivalents, customer and other receivables, affiliated receivables, short-term debt, affiliated current borrowings, payables to affiliates and accounts payable are representative of fair value because of the short-term nature of these instruments. For the Companies’ financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:
(1)
Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.
(2)
Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs, discount or premium, and foreign currency remeasurement adjustments. At December 31, 2020 and December 31, 2019, includes the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt of $3 million and $4 million, respectively.
(3)
Includes amounts classified as held for sale, see Note 3.
(4)
Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs, discount or premium.
NOTE 7. DERIVATIVES AND HEDGE ACCOUNTING ACTIVITIES
See Note 2 for the Companies’ accounting policies, objectives, and strategies for using derivative instruments. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives.
Derivative assets and liabilities are presented gross on the Companies’ Consolidated Balance Sheets. Dominion Energy and Virginia Power’s derivative contracts include both over-the-counter transactions and those that are executed on an exchange or other trading platform (exchange contracts) and centrally cleared. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange or clearinghouse to enter, execute or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of setoff through master netting arrangements, derivative clearing agreements and contract default provisions. In addition, the contracts are subject to conditional rights of setoff through counterparty nonperformance, insolvency or other conditions.
In general, most over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral for over-the-counter and exchange contracts include cash, letters of credit, and in some cases, other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities. Certain accounts receivable and accounts payable recognized on the Companies’ Consolidated Balance Sheets, letters of credit and other forms of securities, as well as certain other long-term debt, all of which are not included in the tables below, are subject to offset under master netting or similar arrangements and would reduce the net exposure. See Note 18 for further information regarding other long-term debt, in the form of restructured derivatives, subject to offset under master netting or similar agreements. See Note 24 for further information regarding credit-related contingent features for the Companies derivative instruments.
Dominion Energy
Balance Sheet Presentation
The tables below present Dominion Energy’s derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:
(1)
Excludes $1 million and $2 million of derivative assets at December 31, 2020 and 2019, respectively, which are not subject to master netting or similar arrangements.
(1)
Excludes $1 million and $5 million of derivative liabilities at December 31, 2020 and 2019, respectively, which are not subject to master netting or similar arrangements.
Volumes
The following table presents the volume of Dominion Energy’s derivative activity as of December 31, 2020. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.
(1) Includes options.
(2)
Maturity is determined based on final settlement period.
AOCI
The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy’s Consolidated Balance Sheets at December 31, 2020:
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated purchases) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices and interest rates.
In connection with the GT&S Transaction, certain cash flow hedges of debt-related items became probable of not occurring. See Note 3 for further information.
Fair Value Hedges
For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings and presented in the same line item. Gains and losses on derivatives in fair value hedge relationships were immaterial for the years ended December 31, 2020, 2019 and 2018.
The following table presents the amounts recorded on the balance sheet related to cumulative basis adjustments for fair value hedges:
(1)
Includes $(1,153) million and $(397) million related to discontinued hedging relationships at December 31, 2020 and December 31, 2019, respectively.
(2) Includes $(3) million and $3 million of hedging adjustments on discontinued hedging relationships at December 31, 2020 and December 31, 2019, respectively.
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Dominion Energy’s derivatives and where they are presented in its Consolidated Balance Sheets:
(1)
Current derivative assets include $63 million and $61 million in other current assets in Dominion Energy’s Consolidated Balance Sheets as of December 31, 2020 and 2019, respectively. The remainder is recorded in current assets held for sale in Dominion Energy’s Consolidated Balance Sheets.
(2)
Noncurrent derivative assets include $330 million and $16 million in other deferred charges and other assets in Dominion Energy’s Consolidated Balance Sheets as of December 31, 2020 and 2019, respectively. The remainder is recorded in noncurrent assets held for sale in Dominion Energy’s Consolidated Balance Sheets.
(3)
Current derivative liabilities include $412 million and $394 million in other current liabilities in Dominion Energy’s Consolidated Balance Sheets as of December 31, 2020 and 2019, respectively. The remainder is recorded in current liabilities held for sale in Dominion Energy’s Consolidated Balance Sheets.
(4)
Noncurrent derivative liabilities include $71 million and $329 million in other deferred credits and other liabilities in Dominion Energy’s Consolidated Balance Sheets as of December 31, 2020 and 2019, respectively. The remainder is recorded in noncurrent liabilities held for sale in Dominion Energy’s Consolidated Balance Sheets.
The following tables present the gains and losses on Dominion Energy’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:
(1)
Amounts deferred into AOCI have no associated effect in Dominion Energy’s Consolidated Statements of Income.
(2)
Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion Energy’s Consolidated Statements of Income.
(3)
Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in discontinued operations.
(1)
Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion Energy’s Consolidated Statements of Income.
Virginia Power
Balance Sheet Presentation
The tables below present Virginia Power’s derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:
(1)
Excludes $3 million and $3 million of derivative assets at December 31, 2020 and 2019, respectively, which are not subject to master netting or similar arrangements.
(1)
Excludes $22 million and $44 million of derivative liabilities at December 31, 2020 and 2019, respectively, which are not subject to master netting or similar arrangements.
Volumes
The following table presents the volume of Virginia Power’s derivative activity at December 31, 2020. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.
(1)
Includes options.
(2)
Maturity is determined based on final settlement period.
AOCI
The following table presents selected information related to losses on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheets at December 31, 2020:
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest payments) in earnings, thereby achieving the realization of interest rates contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in interest rates.
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets:
(1)
Current derivative assets are presented in other current assets in Virginia Power’s Consolidated Balance Sheets.
(2)
Noncurrent derivative assets are presented in other deferred charges and other assets in Virginia Power’s Consolidated Balance Sheets.
(3)
Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheets.
The following tables present the gains and losses on Virginia Power’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:
(1)
Amounts deferred into AOCI have no associated effect in Virginia Power’s Consolidated Statements of Income.
(2)
Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.
(3)
Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in interest and related charges.
(1)
Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.
(2)
Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.
NOTE 8. EARNINGS PER SHARE
The following table presents the calculation of Dominion Energy’s basic and diluted EPS:
(1)
Dilutive securities for 2018 consist primarily of forward sale agreements, effective April 2018 to December 2018. See Note 20 for more information.
The 2019 Equity Units, the 2016 Equity Units, the Dominion Energy Midstream convertible preferred units and the Q-Pipe Transaction deposit are potentially dilutive instruments. See Notes 3, 18, 19 and 20 for additional information. The forward stock purchase contracts included within the 2019 Equity Units were excluded from the calculation of diluted EPS from continuing operations for the years ended December 31, 2020 and 2019 as the dilutive stock price threshold was not met. For the years ended December 31, 2020 and 2019, the Series A Preferred Stock included within the 2019 Equity Units is excluded from the calculation of dilutive EPS from continuing operations, but a fair value adjustment is reflected within net income from continuing operations attributable to Dominion Energy for the calculation of diluted EPS from continuing operations, based upon the expectation that the conversion will be settled in cash rather than through the issuance of Dominion Energy common stock. The impact of settling the deposit associated with the Q-Pipe Transaction in shares is excluded from the calculation for the year ended December 31, 2020 based upon the expectation Dominion Energy would settle in cash rather than through the issuance of Dominion Energy Common Stock. The 2016 Equity Units were potentially dilutive securities but were excluded from the calculation of diluted EPS from continuing operations for years ended December 31, 2019 and 2018 as the dilutive stock price threshold was not met. The Dominion Energy Midstream convertible preferred units were potentially dilutive securities but had no effect on the calculation of diluted EPS from continuing operations for the year ended December 31, 2018. In calculating diluted EPS from continuing operations in connection with the Dominion Energy Midstream convertible preferred units, Dominion Energy applied the if-converted method.
NOTE 9. INVESTMENTS
Dominion Energy
Equity and Debt Securities
Rabbi Trust Securities
Equity and fixed income securities and cash equivalents in Dominion Energy’s rabbi trusts and classified as trading totaled $134 million and $120 million at December 31, 2020 and 2019, respectively.
Decommissioning Trust Securities
Dominion Energy holds equity and fixed income securities, insurance contracts and cash equivalents in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion Energy’s decommissioning trust funds are summarized below:
(1)
Unrealized gains and losses on equity securities are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.
(2)
Unrealized gains and losses on fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2. Effective January 2020, changes in allowance for credit losses are included in other income.
(3)
Includes pending purchases of securities of $49 million and $1 million at December 31, 2020 and 2019, respectively.
(4)
The fair value of securities in an unrealized loss position was $293 million and $298 million at December 31, 2020 and 2019, respectively.
The portion of unrealized gains and losses that relates to equity securities held within Dominion Energy’s nuclear decommissioning trusts is summarized below:
(1)
Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.
The fair value of Dominion Energy’s fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2020 by contractual maturity is as follows:
Presented below is selected information regarding Dominion Energy’s equity and fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds.
(1)
Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.
Virginia Power
Virginia Power holds equity and fixed income securities and cash equivalents in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below:
(1)
Unrealized gains and losses on equity securities are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2
(2)
Unrealized gains and losses on fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2. Effective January 2020, changes in allowance for credit losses are included in other income.
(3)
Includes pending purchases of securities of $10 million at December 31, 2020.
(4)
The fair value of securities in an unrealized loss position was $142 million and $185 million at December 31, 2020 and 2019, respectively.
The portion of unrealized gains and losses that relates to equity securities held within Virginia Power’s nuclear decommissioning trusts is summarized below:
(1)
Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.
The fair value of Virginia Power’s fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2020, by contractual maturity is as follows:
Presented below is selected information regarding Virginia Power’s equity and fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds.
(1)
Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.
EQUITY METHOD INVESTMENTS
Investments that Dominion Energy accounts for under the equity method of accounting are as follows:
(1)
Dominion Energy has an $59 million unfunded commitment to be made to Align RNG by the end of 2022.
(2)
Effective November 2020, following the completion of the GT&S Transaction, Dominion Energy began accounting for its 50% noncontrolling interest in Cove Point as an equity method investment. See discussion below and Note 3 for additional information.
(3)
Dominion Energy owned 53% and 48% of Atlantic Coast Pipeline at December 31, 2020 and 2019, respectively. See discussion below for additional information.
(4)
Dominion Energy sold its 50% noncontrolling interest in Fowler Ridge in September 2020. See discussion below for additional information.
(5)
Dominion Energy’s Consolidated Balance Sheet at December 31, 2020 includes a $1.1 billion liability associated with its investment in Atlantic Coast Pipeline. See discussion below for additional information.
Dominion Energy recorded equity earnings on its investments of $40 million, $8 million and $76 million in 2020, 2019, and 2018, respectively, in other income in its Consolidated Statements of Income. In addition, Dominion Energy recorded equity earnings (losses) of $(2.3) billion, $117 million and $67 million in 2020, 2019 and 2018, respectively, in discontinued operations related to its investment in Atlantic Coast Pipeline. Dominion Energy received distributions from these investments of $102 million, $38 million and $111 million in 2020, 2019, and 2018, respectively. As of December 31, 2020 and 2019, the net difference between the carrying amount of Dominion Energy’s investments and its share of underlying equity in net assets was $213 million and $(35) million, respectively. At December 31, 2020, these differences are comprised of $27 million of equity method goodwill that is not being amortized, $227 million basis difference from Dominion Energy’s investment in Cove Point, which is being amortized over the useful lives of the underlying assets and a net $(41) million basis difference primarily attributable to an unfunded commitment made to Align RNG. At December 31, 2019 these differences are comprised of $11 million of equity method goodwill that is not being amortized and a net $(46) million basis difference from Dominion Energy’s investments in Fowler Ridge, Atlantic Coast Pipeline and an unfunded commitment made to Align RNG.
Cove Point
Prior to January 2019, Dominion Energy owned all of the common equity interest in Cove Point except for a preferred equity interest held by Dominion Energy Midstream (entitled to the first $50 million of annual cash distributions made by Cove Point), in which Dominion Energy owned a controlling financial interest and consolidated. As discussed in Note 20, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned by Dominion Energy in January 2019. In December 2019, Dominion Energy closed on an agreement to sell a 25% noncontrolling limited partnership interests in Cove Point. In November 2020, in conjunction with the GT&S Transaction, Dominion Energy sold 100% of its general partner interest and 25% of the total limited partner interest in Cove Point. Dominion Energy retained a 50% noncontrolling limited partnership interest in Cove Point which is accounted for as an equity method investment as Dominion Energy has the ability to exercise significant influence over, but not control, Cove Point. See Note 3 for further information regarding the sales of interests in Cove Point.
Income before income taxes recorded by Cove Point for 2020, 2019 and 2018 was $511 million, $471 million and $292 million, respectively. For the periods prior to closing of the GT&S Transaction, earnings attributable to Dominion Energy are presented in discontinued operations. Subsequent to the closing of the GT&S Transaction through December 31, 2020, earnings attributable to Dominion Energy of $40 million are presented within other income in its Consolidated Statements of Income.
Dominion Energy recorded distributions from Cove Point of $70 million and no contributions to Cove Point from the date of disposal through December 31, 2020.
All activity relating to Dominion Energy’s noncontrolling interest in Cove Point is recorded within Contracted Assets. See Note 3 for further information regarding the GT&S Transaction.
Atlantic Coast Pipeline
In September 2014, Dominion Energy, along with Duke Energy and Southern, announced the formation of Atlantic Coast Pipeline for the purpose of constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. Subsidiaries and affiliates of Dominion Energy, Duke Energy and Southern had planned to be customers of the pipeline under 20-year contracts.
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, subject to certain purchase price adjustments. Pivotal LNG, Inc. includes a 50% noncontrolling interest in JAX LNG. Following completion of the acquisition, Dominion Energy owns a 53% noncontrolling membership interest in Atlantic Coast Pipeline with Duke Energy owning the remaining interest.
Atlantic Coast Pipeline continues to be reflected as an equity method investment as the power to direct the activities most significant to Atlantic Coast Pipeline is shared with Duke Energy. As a result, Dominion Energy has the ability to exercise significant influence, but not control, over the investee.
The Atlantic Coast Pipeline Project had been the subject of challenges in federal courts including, among others, challenges of the Atlantic Coast Pipeline Project’s biological opinion and incidental take statement, permits providing right of way crossings of certain federal lands, the Army Corps of Engineers 404 permit, the air permit for a compressor station at Buckingham, Virginia, and the FERC order approving the CPCN. Each of these challenges alleged non-compliance on the part of federal and state permitting authorities and adverse ecological consequences if the Atlantic Coast Pipeline Project was permitted to proceed. Since December 2018, notable developments in these challenges included a stay in December 2018 issued by the U.S. Court of Appeals for the Fourth Circuit and the same court’s July 2019 vacatur of the biological opinion and incidental take statement (which stay and subsequent vacatur halted most project construction activity), the U.S. Court of Appeals for the Fourth Circuit decisions vacating the permits to cross certain federal forests and the air permit for a compressor station at Buckingham, Virginia, the U.S. Court of Appeals for the Fourth Circuit’s remand to the Army Corps of Engineers of Atlantic Coast Pipeline’s Huntington District 404 verification and the U.S. Court of Appeals for the Fourth Circuit’s remand to the National Park Service of Atlantic Coast Pipeline’s Blue Ridge Parkway right-of-way. In June 2019, the Solicitor General of the U.S. and Atlantic Coast Pipeline filed petitions requesting that the Supreme Court of the U.S. hear the case regarding the Appalachian Trail crossing and in June 2020, the Supreme Court of the U.S. ruled in favor of the Atlantic Coast Pipeline, reversing the lower court’s decision and remanding the case back to the U.S. Court of Appeals for the Fourth Circuit.
The project also faced new and serious challenges from uncertainty related to NWP 12, specifically, from the decision of the U.S. District Court for the District of Montana in April 2020 vacating an NWP 12 issued by the Army Corps of Engineers, including among other things gas pipelines, followed by a U.S. Court of Appeals for the Ninth Circuit ruling in May 2020 denying a stay of that decision. In July 2020, the Supreme Court of the U.S. issued an order allowing other new oil and gas pipeline projects to use the NWP 12 process pending appeal to the U.S. Court of Appeals for the Ninth Circuit; however, that did not decrease the uncertainty associated with an eventual ruling. The Montana district court decision was viewed as likely to prompt similar challenges in other federal circuit courts related to permits issued under NWP 12, including for the Atlantic Coast Pipeline Project.
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.
As a result of the determination of the probable abandonment of the Atlantic Coast Pipeline Project in June 2020, Dominion Energy recorded equity method earnings (losses) of $(2.3) billion ($(1.8) billion after-tax) for the year ended December 31, 2020, $117 million ($118 million after-tax) for the year ended December 31, 2019 and $67 million ($67 million after-tax) for the year ended December 31, 2018. In connection with Dominion Energy’s decision to sell substantially all of its gas transmission and storage operations, Dominion Energy has reflected the results of its equity method investment in Atlantic Coast Pipeline as discontinued operations in its Consolidated Statements of Income. As a result of its share of equity losses exceeding its investment Dominion Energy’s Consolidated Balance Sheets at December 31, 2020 includes a liability of $1.1 billion which reflects Dominion Energy’s obligations to Atlantic Coast Pipeline related to its credit facility and AROs. ‌
In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility with a stated maturity date of October 2021. Atlantic Coast Pipeline informed Dominion Energy it intends to terminate and repay the outstanding balance of the revolving credit facility in the first quarter of 2021. As of December 31, 2020, Atlantic Coast Pipeline had borrowed $1.8 billion against the revolving credit facility. In July 2020, the capacity of the revolving credit facility was reduced from $3.4 billion to $1.9 billion. Dominion Energy’s Consolidated Balance Sheets include a liability of $6 million and $14 million associated with this guarantee agreement at December 31, 2020 and 2019, respectively. The $1.1 billion liability at December 31, 2020 discussed above includes a $48 million adjustment related to this guarantee agreement that
is reflected within equity as a cumulative effect of a change in accounting principle upon adoption of the new credit loss standard in January 2020.
Dominion Energy recorded contributions of $107 million, $186 million and $414 million during 2020, 2019 and 2018, respectively, to Atlantic Coast Pipeline. At December 31, 2019, Dominion Energy had $7 million of contributions payable to Atlantic Coast Pipeline included within other current liabilities in its Consolidated Balance Sheets.
Dominion Energy expects to incur additional losses from Atlantic Coast Pipeline as it completes wind-down activities. While Dominion Energy is unable to precisely estimate the amounts to be incurred by Atlantic Coast Pipeline, the portion of such amounts attributable to Dominion Energy is not expected to be material to Dominion Energy’s results of operations, financial position or statement of cash flows.
DETI provided services to Atlantic Coast Pipeline which totaled $49 million, $103 million and $203 million in 2020 (prior to closing of the GT&S Transaction), 2019 and 2018, respectively, included in discontinued operations in Dominion Energy’s Consolidated Statements of Income. Amounts receivable related to these services were $7 million at December 31, 2019, composed entirely of accrued unbilled revenue, included in current assets held for sale in Dominion Energy’s Consolidated Balance Sheets.
All activity relating to Atlantic Coast Pipeline is recorded within the Corporate and Other segment.
Blue Racer
In December 2018, Dominion Energy sold its 50% limited partnership interest in Blue Racer for up-front cash consideration of $1.05 billion and additional consideration of $150 million, subject to increase for interest costs effective March 2019, payable upon the purchaser’s availability of cash. The additional consideration was recorded at a fair value of $150 million on the date of sale following a discounted cash flow model and is included within other receivables in the Consolidated Balance Sheets at December 31, 2018. The valuation is considered a Level 3 fair value measurement due to the use of judgment and unobservable inputs, including projected timing and amount of future cash flows and a discount rate reflecting risks inherent in the future cash flows. As a result of the sale, Dominion Energy recognized a gain of $546 million ($390 million after-tax), included in other income in its Consolidated Statements of Income for the year ended December 31, 2018. In addition, the purchaser agreed to pay additional consideration contingent upon the achievement of certain financial performance milestones of Blue Racer from 2019 through 2021. Pursuant to the purchase agreement, the aggregate will not exceed $300 million, which represents a gain contingency, and, as a result, Dominion Energy will not recognize any additional gain unless such consideration is realizable. Blue Racer did not achieve the 2019 or 2020 financial performance milestones set forth in the sale agreement. In the first quarter of 2019, Dominion Energy received $151 million of additional consideration, including applicable interest, in connection with this sale.
All activity relating to Blue Racer is recorded within the Corporate and Other segment.
Fowler Ridge
In September 2020, Dominion Energy sold its 50% noncontrolling partnership interest in Fowler Ridge to BP and terminated an affiliate’s long-term power, capacity and renewable energy credit contract with Fowler Ridge for a net payment by Dominion Energy of $150 million. The $150 million payment was allocated between the contract termination and sale based on the relative fair value of each using an income approach. The fair value determinations for the payment allocations are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including the amount of future cash flows and discount rate reflecting risks inherent in the future cash flows and market prices. Dominion Energy recognized a loss of $221 million ($165 million after-tax) on the contract termination, included in impairment of assets and other charges in its Consolidated Statements of Income for the year ended December 31, 2020, reflected in the Corporate and Other segment.
All activity relating to Fowler Ridge, unless otherwise specified, is recorded within Contracted Assets.
Wrangler
In September 2019, Dominion Energy entered into an agreement to form Wrangler, a partnership with Interstate Gas Supply, Inc. Wrangler will operate a nonregulated natural gas retail energy marketing business with Dominion Energy contributing its nonregulated retail energy marketing operations and Interstate Gas Supply, Inc. contributing cash. Dominion Energy has a 20% noncontrolling ownership interest in Wrangler which is accounted for as an equity method investment as Dominion Energy has the ability to exercise significant influence, but not control, over the investee.
The initial contribution, consisting of SEMI, closed in December 2019 for which Dominion Energy received $301 million in cash proceeds and a 20% noncontrolling ownership interest in Wrangler with an initial fair value of $75 million estimated using the market approach. This valuation is considered a Level 2 fair value measurement given that it is based on the agreed-upon sales price. In connection with the transaction, Dominion Energy recorded a gain of $147 million, net of a $73 million write-off of goodwill, presented in gains on sales of assets, and an associated tax expense of $82 million, in the Consolidated Statements of Income for the year ended December 31, 2019.
The second contribution, consisting of certain nonregulated natural gas retail energy contracts, closed in November 2020 for which Dominion Energy received $74 million in cash proceeds and retained a 20% noncontrolling ownership interest through its ownership interest in Wrangler in the contracts valued at $13 million using the market approach. This valuation is considered a Level 2 fair value measurement given that it is based on the agreed-upon sales price. In connection with the transaction, Dominion Energy recorded a gain of $64 million presented in gains on sales of assets, and an associated tax expense of $19 million, in the Consolidated Statements of Income for the year ended December 31, 2020. Dominion Energy’s Consolidated Balance Sheets at December 31, 2019 included $41 million presented in current assets held for sale.
In 2021, under the terms of the agreement, Dominion Energy expects to contribute its remaining nonregulated natural gas retail energy marketing operations to Wrangler. As a result of this contribution, Dominion Energy will receive additional cash consideration which will be based upon future financial performance. When this future contribution occurs, Dominion Energy expects to retain a 20% noncontrolling ownership interest in Wrangler.
As of December 31, 2020, $63 million of assets and $15 million of liabilities associated with the remaining nonregulated retail energy marketing operations to be contributed to Wrangler in December 2021 were classified as held for sale and were included in current assets held for sale and current liabilities held for sale on Dominion Energy’s Consolidated Balance Sheets, respectively. The related disposal group is primarily comprised of customer receivables, goodwill, inventories, and account payables.
All activity relating to Wrangler is recorded within the Corporate and Other segment.
Other- Catalyst Old River Hydroelectric Limited Partnership
In September 2018, Dominion Energy completed the sale of its 25% limited partnership interest in Catalyst Old River Hydroelectric Limited Partnership and received proceeds of $91 million. The sale resulted in a gain of $87 million ($63 million after-tax), which is included in other income in Dominion Energy’s Consolidated Statements of Income, reflected in the Corporate and Other segment.
NOTE 10. PROPERTY, PLANT AND EQUIPMENT
Major classes of property, plant and equipment and their respective balances for the Companies are as follows:
Jointly-Owned Power Stations
The Companies proportionate share of jointly-owned power stations at December 31, 2020 is as follows:
(1)
Units jointly owned by Virginia Power.
(2)
Unit jointly owned by Dominion Energy.
The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. The Companies report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes, etc.) in the Consolidated Statements of Income.
Sale of Certain Retail Energy Marketing Assets
In October 2017, Dominion Energy entered into an agreement to sell certain assets associated with its nonregulated retail energy marketing operations. The first phase of the agreement closed in December 2017. Dominion Energy closed the second phase of the agreement in October 2018 for $63 million, which resulted in the recognition of a $65 million ($49 million after-tax) benefit included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. Pursuant to the agreement, Dominion Energy entered into a commission agreement with the buyer upon the first closing in December 2017 under which the buyer will pay a commission in connection with the right to use Dominion Energy’s brand in marketing materials and other services over a ten-year term.
Sale of Certain Nonregulated Generation Facilities
In December 2018, Dominion Energy completed the sale of Fairless and Manchester for total consideration of $1.2 billion, subject to customary closing adjustments. Dominion Energy recognized a gain of $210 million ($198 million after-tax) included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. The after-tax gain reflects Dominion Energy’s assessment and more-likely-than-not conclusion that the utilization of state tax incentives will reduce the income tax expense associated with the sale of these facilities.
Acquisition of Solar Projects
The following table presents acquisitions by Virginia Power of solar projects. Virginia Power has claimed or expects to claim federal investment tax credits on the projects.
(1) Includes acquisition costs.
The following table presents acquisitions by Dominion Energy of solar projects. Dominion Energy has claimed or expects to claim federal investment tax credits on the projects.
(1) Includes acquisition costs.
(2) In December 2020 and January 2021, 97 MW and 53 MW of the project commenced commercial operations, respectively.
In addition to the facilities discussed above, Dominion Energy has also entered into various agreements to install solar facilities, primarily at schools in Virginia, with in-service dates in 2020 or 2021. Through February 2021, Dominion Energy anticipates a total projected cost of approximately $61 million under these agreements with an associated aggregate generation capacity of 30 MW. Dominion Energy has claimed or expects to claim federal investment tax credits on the projects.
Acquisition of Gathering and Processing Assets
In March 2020, Wexpro closed on an agreement with a natural gas gathering systems operator to purchase existing natural gas gathering systems including pipelines, compressors and dehydration equipment for total consideration of $38 million. These facilities gather natural gas in Colorado, Utah and Wyoming.
Non-Wholly-Owned Nonregulated Solar Facilities
In the third quarter of 2020, Dominion Energy performed a strategic review of its long-term intentions for its contracted nonregulated solar generation assets in partnerships outside of its core electric service territories in consideration of the impact of the VCEA and Dominion Energy’s decision to sell substantially all of its gas transmission and storage operations. Based on an evaluation of Dominion Energy’s interests in these long-lived assets for recoverability under a probability weighted approach, Dominion Energy determined the assets were impaired. As a result of this evaluation, Dominion Energy recorded a charge of $665 million ($293 million after-tax attributable to Dominion Energy and $267 million attributable to noncontrolling interest) in impairment of assets and other charges in its Consolidated Statements of Income (reflected in the Corporate and Other segment) for the year ended December 31, 2020 to adjust the property, plant and equipment down to its estimated fair value of $1.4 billion. The fair value was estimated using an income approach. The valuation is considered a Level 3 fair value measurement due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risks inherent in the future cash flows and market prices.
NOTE 11. GOODWILL AND INTANGIBLE ASSETS
Goodwill
In September 2020, Dominion Energy updated its operating segments following the July 2020 agreement to sell its gas transmission and storage operations to BHE. See Note 3 for information on the goodwill recast to held for sale associated with the GT&S Transaction and Q-Pipe Transaction. In addition, goodwill associated with Dominion Energy’s nonregulated retail energy marketing operations was reassigned to the Corporate and Other segment using a relative fair value allocation approach with the historical information recast herein. The changes in Dominion Energy’s carrying amount and segment allocation of goodwill are presented below:
(1) Goodwill amounts do not contain any accumulated impairment losses.
(2) See Note 3 for more information on the SCANA Combination. As a result of the December 2019 segment realignment, the acquired goodwill was reassigned using a relative fair value approach.
(3) See Note 9 for additional information including amounts reclassified to held for sale at December 31, 2020.
Other Intangible Assets
The Companies’ other intangible assets are subject to amortization over their estimated useful lives. Dominion Energy’s amortization expense for intangible assets was $69 million, $95 million and $72 million for 2020, 2019 and 2018, respectively. In 2020, Dominion Energy acquired $152 million of intangible assets, primarily representing software and right-of-use assets, with an estimated weighted-average amortization period of approximately 11 years. Amortization expense for Virginia Power’s intangible assets was $28 million, $30 million and $31 million for 2020, 2019 and 2018, respectively. In 2020, Virginia Power acquired $95 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 11 years.
The components of intangible assets are as follows:
Annual amortization expense for these intangible assets is estimated to be as follows:
NOTE 12. REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities include the following:
(1)
Reflects deferred fuel expenses for the Virginia, North Carolina and South Carolina jurisdictions of Dominion Energy’s electric generation operations.
(2)
Primarily reflects amounts expected to be collected from or owed to gas customers in Dominion Energy’s service territories associated with current and prospective rider projects, including CEP, PIR and pipeline integrity management. See Note 13 for more information.
(3)
Reflects unrecovered or overrecovered gas costs at regulated gas operations, which are recovered or refunded through filings with the applicable regulatory authority.
(4)
Reflects deferrals under Virginia Power’s electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects, net of excess deferred income taxes from the 2017 Tax Reform Act for Virginia Power. See Note 13 for more information.
(5)
As a result of actions from the Virginia Commission in the first quarter of 2019 regarding the ratemaking treatment of excess deferred taxes from the adoption of the 2017 Tax Reform Act for all existing riders, Virginia Power recorded a $29 million ($22 million after-tax) charge in operating revenue in the Consolidated Statements of Income for amounts probable of being returned to customers primarily in 2019 and 2020.
(6)
Legislation enacted in Virginia in April 2014 requires Virginia Power to defer operation and maintenance costs incurred in connection with the refueling of any nuclear-powered generating plant. These deferred costs will be amortized over the refueling cycle, not to exceed 18 months.
(7)
Reflects expenditures by DESC associated with the NND Project, which pursuant to the SCANA Merger Approval Order, will be recovered from DESC electric service customers over a 20-year period ending in 2039. See Note 3 for more information.
(8)
Reflects amounts to be recovered through retail rates in Virginia for payments Virginia Power will make to PJM over a ten-year period ending 2028 under the terms of a FERC settlement agreement in May 2018 resolving a PJM cost allocation matter.‌
(9)
Represents unrecognized pension and other postretirement employee benefit costs expected to be recovered or refunded through future rates generally over the expected remaining service period of plan participants by certain of Dominion Energy's rate-regulated subsidiaries.
(10)
During the first quarter of 2019, Virginia Power recorded a charge of $17 million ($13 million after-tax) in impairment of assets and other charges (reflected in the Corporate and Other segment) to write-off the balance of a regulatory asset for which it is no longer seeking recovery.
(11)
During the second quarter of 2020, Virginia Power recorded a charge of $16 million ($15 million after-tax) in impairment of assets and other charges (reflected in the Corporate and Other segment) to write off the balance of a regulatory asset for which it is no longer seeking recovery.
(12)
Reflects interest rate hedges recoverable from or refundable to customers. Certain of these instruments are settled and any related payments are being amortized into interest expense over the life of the related debt, which has a weighted-average useful life of approximately 27 years as of December 31, 2020.
(13)
Represents deferred depreciation and accretion expense related to legal obligations associated with the future retirement of generation, transmission and distribution properties. The AROs primarily relate to DESC’s electric generating facilities, including Summer, and are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 105 years.
(14)
Costs of the reacquisition of debt are deferred and amortized as interest expense over the would-be remaining life of the reacquired debt. The reacquired debt costs had a weighted-average life of approximately 26 years as of December 31, 2020.
(15)
Primarily reflects legislation enacted in Virginia in March 2019 which requires any CCR unit located at certain Virginia Power stations to be closed by removing the CCRs to an approved landfill or through recycling for beneficial reuse. Subject to approval by the Virginia Commission, amounts are expected to be collected over a period between 15 and 18 years commencing no earlier than 2021. Virginia Power is entitled to collect carrying costs once expenditures have been made. See Note 14 for additional information. As a result of the March 2020 planned early retirement of certain facilities, amounts recoverable through riders were reclassified from property, plant and equipment.
(16)
Rates charged to customers by Dominion Energy’s regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.
(17)
Reflects amounts previously collected from retail electric customers of DESC for the NND Project to be credited over an estimated 11-year period effective February 2019, in connection with the SCANA Merger Approval Order. See Notes 3 and 13 for more information.
(18)
Represents a reserve for benefits expected to be provided through the use of a CCRO in accordance with the GTSA to jurisdictional retail electric customers in Virginia in connection with the 2021 Triennial Review. See Note 13 for additional information.
(19)
Balance refundable to customers related to the decrease in revenue requirements for recovery of income taxes at the Companies’ regulated electric generation and electric and natural gas distribution operations. See Notes 3 and 13 for more information.
(20)
Amounts recorded to pass the effect of reduced income taxes from the 2017 Tax Reform Act to customers in future periods, which will primarily reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC equity.
(21)
Reflects amounts to be refunded to DESC electric service customers over a 20-year period ending in 2039 associated with the monetization of a bankruptcy settlement agreement. See Note 3 for more information.
(22)
Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon, as applicable) for the future decommissioning of Dominion Energy’s utility nuclear generation stations, in excess of the related AROs.
(23)
Reflects a regulatory liability for the collection of postretirement benefit costs allowed in rates in excess of expense incurred.
(1)
Reflects deferred fuel expenses for Virginia and North Carolina jurisdictions of Virginia Power’s generation operations.
(2)
Reflects deferrals under Virginia Power’s electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects, net of excess deferred income taxes from the 2017 Tax Reform Act. See Note 13 for more information.
(3)
As a result of actions from the Virginia Commission in the first quarter of 2019 regarding the ratemaking treatment of excess deferred taxes from the adoption of the 2017 Tax Reform Act for all existing riders, Virginia Power recorded a $29 million ($22 million after-tax) charge in operating revenue in the Consolidated Statements of Income for amounts probable of being returned to customers primarily in 2019 and 2020.
(4)
Legislation enacted in Virginia in April 2014 requires Virginia Power to defer operation and maintenance costs incurred in connection with the refueling of any nuclear-powered generating plant. These deferred costs will be amortized over the refueling cycle, not to exceed 18 months.
(5)
Reflects amounts to be recovered through retail rates in Virginia for payments Virginia Power will make to PJM over a ten-year period ending 2028 under the terms of a FERC settlement agreement in May 2018 resolving a PJM cost allocation matter.
(6)
During the first quarter of 2019, Virginia Power recorded a charge of $17 million ($13 million after-tax) in impairment of assets and other charges (reflected in the Corporate and Other segment) to write-off the balance of a regulatory asset for which it is no longer seeking recovery.
(7)
During the second quarter of 2020, Virginia Power recorded a charge of $16 million ($15 million after-tax) in impairment of assets and other charges (reflected in the Corporate and Other segment) to write off the balance of a regulatory asset for which it is no longer seeking recovery.
(8)
Reflects interest rate hedges recoverable from or refundable to customers. Certain of these instruments are settled and any related payments are being amortized into interest expense over the life of the related debt, which has a weighted-average useful life of approximately 25 years as of December 31, 2020.
(9)
Primarily reflects legislation enacted in Virginia in March 2019 which requires any CCR unit located at certain Virginia Power stations to be closed by removing the CCR to an approved landfill or through recycling for beneficial reuse. Subject to approval by the Virginia Commission, amounts are expected to be collected over a period between 15 and 18 years commencing no earlier than 2021. Virginia Power is entitled to collect carrying costs once expenditures have been made. See Note 14 for additional information. As a result of the March 2020 planned early retirement of certain facilities, amounts recoverable through riders were reclassified from property, plant and equipment.
(10)
Rates charged to customers by Virginia Power's regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.
(11)
Represents a reserve for benefits expected to be provided through the use of a CCRO in accordance with the GTSA to jurisdictional retail electric customers in Virginia in connection with the 2021 Triennial Review. See Note 13 for additional information.
(12)
Amounts recorded to pass the effect of reduced income taxes from the 2017 Tax Reform Act to customers in future periods, which will reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC equity.
(13)
Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of Virginia Power’s utility nuclear generation stations, in excess of the related AROs.
At December 31, 2020, Dominion Energy and Virginia Power regulatory assets include $4.5 billion and $3.2 billion, respectively, on which they do not expect to earn a return during the applicable recovery period. With the exception of certain items discussed above, the majority of these expenditures are expected to be recovered within the next two years.
NOTE 13. REGULATORY MATTERS
Regulatory Matters Involving Potential Loss Contingencies
As a result of issues generated in the ordinary course of business, the Companies are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for the Companies to estimate a range of possible loss. For regulatory matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters that the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on the Companies’ financial position, liquidity or results of operations.
FERC-ELECTRIC
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. DESC sells electricity to wholesale purchasers in its balancing authority area under its electric cost based tariff and to wholesale purchasers outside of its balancing authority area under its market based rate authority. 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, Indiana, Connecticut, Tennessee, Georgia, California, Ohio, South Carolina and Utah, under Dominion Energy’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.
FERC-GAS
In July 2017, FERC audit staff communicated to DETI that it had substantially completed an audit of DETI’s compliance with the accounting and reporting requirements of FERC’s Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report which had the potential to result in adjustments which could have been material to Dominion Energy’s results of operations. In December 2017, DETI provided its response to the audit report. In 2018, DETI recognized a charge of $129 million ($94 million after-tax) recorded within discontinued operations in Dominion Energy’s Consolidated Statements of Income for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with FERC. In November 2020, Dominion Energy completed the sale of DETI as part of the GT&S Transaction.
2017 Tax Reform Act
Subsequent to the enactment of the 2017 Tax Reform Act, the Companies’ state regulators issued orders requesting that public utilities evaluate the total tax impact on the entity’s cost of service and accrue a regulatory liability attributable to the benefits of the reduction in the corporate income tax rate. Certain of the orders requested that the public utilities submit a response to the state regulatory commissions detailing the total tax impact on the utility’s cost of service.
The Companies began to reserve the impacts of the cost-of-service reduction as regulatory liabilities in January 2018 and will continue until rates are reset pursuant to state regulators’ approvals. The Companies have recorded a reasonable estimate of net income taxes refundable through future rates in the jurisdictions in which they operate.
In September 2018, the Virginia Commission issued an order directing Virginia Power to submit a filing quantifying the impacts of the 2017 Tax Reform Act. In March 2019, the Virginia Commission issued an order approving an annual revenue reduction of approximately $183 million effective April 2019 and ordered Virginia Power to implement the one-time customer credit on or before July 1, 2019. In the second quarter of 2019, Virginia Power refunded to customers $132 million.
In August 2018, Virginia Power filed with FERC to waive protocols and begin reflecting projected tax reform benefits of approximately $100 million through the transmission formula rate prior to the normal formula rate process. FERC granted the waiver and the amounts began being reflected in customer billings in November 2018 reflecting the adjustment effective January 1, 2018.
In October 2018, the North Carolina Commission issued an order requesting companies file to reduce base rates expeditiously. In March 2019, the North Carolina Commission issued an order approving Virginia Power’s proposed annual base rate revenue decrease of approximately $14 million effective in early 2019 and one-time bill credit for its 2018 tax savings collected provisionally from customers. In the second quarter of 2019, Virginia Power refunded to customers $13 million.
In March 2019, Questar Gas filed with the Utah and Wyoming Commissions as to the impact of excess deferred income taxes resulting from the 2017 Tax Reform Act. Questar Gas proposed to return the 2018 amortization of excess deferred income taxes to customers and to incorporate the remaining excess deferred income tax impact in its next general rate cases in each jurisdiction. The Utah Commission issued an order effective March 2020 approving Questar Gas’ proposal to refund the January 2019 through February 2020 amortization of excess deferred income taxes over 12 months beginning in June 2020. Additionally, new base rates that went into effect in Utah on March 1, 2020 include the prospective impacts of sharing excess deferred income taxes with customers. In April 2020, at the request of the Wyoming Commission, this matter was considered in conjunction with the base rate case that was filed in November 2019. In June 2020, the Wyoming Commission approved a proposal to share the benefits of deferred income taxes for the period January 2018 through August 2020 with customers over a one year period beginning in September 2020. In addition, new base rates that went into effect in Wyoming in September 2020 include the prospective impacts of sharing excess deferred income taxes with customers.
In October 2018, the Ohio Commission issued an order requiring rate-regulated utilities to file an application reflecting the impact of the 2017 Tax Reform Act on current rates by January 1, 2019. In December 2018, East Ohio filed its application proposing an approach to establishing rates and charges by and through which to return tax reform benefits to its customers. In December 2019, the Ohio Commission issued an order approving customer credits of approximately $600 million that will be shared with customers primarily over the remaining book life of the property to which the excess deferred income taxes relate. In addition, East Ohio will reduce rates approximately $19 million per year to account for the 2017 Tax Reform Act’s impact on its equity return component of rates charged to customers. A tax savings credit, which passes through the reduction in the federal income tax rate under the 2017 Tax Reform Act to customers in accordance with the settlement agreement approved by the Ohio Commission, became effective with the first billing cycle in April 2020.
In connection with the SCANA Merger Approval Order, the South Carolina Commission approved DESC’s provision of approximately $100 million in bill credits related to the 2017 Tax Reform Act’s impact on retail electric customer rates for the period beginning January 2018 through January 2019. These credits have been included in bills rendered on and after the first billing cycle of February 2019. In addition, the South Carolina Commission approved a tax rider whereby the effects of the reduction in the corporate income tax rate resulting from the 2017 Tax Reform Act will benefit retail electric customers. This tax rider reduced base rates to customers by $63 million in 2019 and $66 million in 2020. Unamortized excess deferred income taxes that remained at the end of 2020 will be considered in future rate proceedings.
In October 2018, the South Carolina Commission issued an order approving adjustment to DESC’s natural gas rate schedules, under the terms of the Natural Gas Rate Stabilization Act, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. The approved natural gas rate schedules also included a tax reform rate rider to refund certain income tax amounts previously collected from customers. These lower rates, representing a $20 million decreased revenue requirement, became effective for bills rendered on and after the first billing cycle in November 2018.
In December 2018, the North Carolina Commission issued an order approving PSNC’s proposed adjustments to customer rates, representing a $13 million decreased revenue requirement, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. These lower rates became effective for service rendered on and after January 1, 2019. Amounts collected in customer rates during 2018 and amounts arising from excess deferred income taxes have been recorded in regulatory liabilities and must be considered in PSNC’s next general rate case proceeding or in three years, whichever is sooner. The reduction in the federal corporate tax rate and its impact on PSNC’s various rate riders will be addressed in future proceedings related to those riders.
Other Regulatory Matters
Virginia Regulation
Regulation Act
The Regulation Act enacted in 2007 instituted a cost-of-service rate model, ending Virginia’s planned transition to retail competition for electric supply service to most classes of customers.
The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, underground distribution lines, environmental compliance, conservation and energy efficiency programs, renewable energy programs and nuclear license renewals, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission.
If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.
In November 2019, the Virginia Commission approved a 9.2% general ROE for Virginia Power’s non-transmission rate adjustment clauses and for purposes of determining Virginia Power’s base rate earnings in the 2021 Triennial Review.
In 2020, Virginia Power recorded a charge of $130 million ($97 million after-tax) in impairment of assets and other charges in its Consolidated Statements of Income (reflected in the Corporate and Other segment) for benefits expected to be provided through the use of a CCRO in accordance with the GTSA. This charge reflects benefits expected to be provided to jurisdictional customers as a result of the 2021 Triennial Review as well as the impact on certain non-jurisdictional customers which follow Virginia Power’s jurisdictional customer rate methodology.
Grid Transformation and Security Act of 2018
In March 2018, the GTSA reinstated base rate reviews commencing with the 2021 Triennial Review which will occur one year earlier than under the Regulation Act legislation enacted in February 2015.
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 in a CCRO. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that the costs of such projects may be recovered through a rate adjustment clause if not the subject of a CCRO. Any costs that are the subject of a CCRO may not be recovered in base rates for the service life of the projects 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. In the 2021 review, any such rate reduction is limited to $50 million.
The legislation also includes provisions requiring Virginia Power to provide current customers one-time rate credits totaling $200 million and to reduce base rates to reflect reductions in income tax expense resulting from the 2017 Tax Reform Act. As a result, Virginia Power incurred a $215 million ($160 million after-tax) charge (reflected in the Corporate and Other segment during 2018) in connection with this legislation, including the impact on certain non-jurisdictional customers which follow Virginia Power’s jurisdictional customer rate methodology. In July 2018 and January 2019, Virginia Power credited $138 million and $77 million, respectively, to current customers’ bills.
In addition, Virginia Power reduced base rates on an annual basis by $125 million effective July 2018, to reflect the estimated effect of the 2017 Tax Reform Act. In March 2019, the Virginia Commission directed an annual revenue reduction of $183 million in rates for generation and distribution services pursuant to the GTSA effective April 2019.
In January 2019, the Virginia Commission issued an order approving capital spending for the first three years of Virginia Power’s ten-year plan totaling $68 million for electric distribution grid transformation projects as authorized by the GTSA on cyber and physical security and related telecommunications infrastructure (Phase IA). The Virginia Commission declined to approve certain of the proposed components for the first three years of the plan, the proposed spending for which was not found reasonable and prudent based on the record in the proceeding.
In September 2019, Virginia Power filed a revised plan which included six components: (i) smart meters; (ii) customer information platform; (iii) grid improvement projects; (iv) telecommunications infrastructure; (v) cyber security; and (vi) a smart charging electric vehicle infrastructure pilot program (Phase IB). For Phase IB, the total proposed capital investment during 2019 - 2021 is $503 million and the proposed operations and maintenance investment was $78 million. In March 2020, the Virginia Commission issued an order approving $212 million of costs related to a new customer information platform, targeted grid hardening and corridor improvements, an electric vehicle Smart Charging Infrastructure Pilot Program, cyber security, stakeholder engagement and customer education and denied the costs associated with AMI, self-healing grid and certain other grid hardening projects alleging that Virginia Power did not prove the reasonableness and prudency of these costs. In April 2020, Virginia Power filed a petition for reconsideration of the Virginia Commission’s order and requested clarification of certain matters, including the Smart Charging Infrastructure Pilot Program. Additionally, Virginia Power requested clarification of certain matters relating to an AMI time-of-use rate and the smart charging electric vehicle infrastructure pilot program. Subsequently, in April 2020, the Virginia Commission denied in full Virginia Power’s petition for reconsideration; however, it stated that its March 2020 order contained all necessary approvals for the smart charging electric vehicle infrastructure pilot program. Virginia Power intends to file a revised plan in 2021.
Utility Disconnection Moratorium Legislation
In November 2020, legislation was enacted in Virginia relating to the moratorium on utility disconnections during the COVID-19 pandemic and resulted in Virginia Power forgiving Virginia jurisdictional retail electric customer balances that were more than 30 days past due as of September 30, 2020. As a result, Virginia Power recorded a charge of $127 million ($94 million after-tax) in impairment of assets and other charges (reflected in the Corporate and Other segment). For the purposes of Virginia Power’s 2021 Triennial Review, the charge is excluded from Virginia Power’s cost of service for purposes of determining any test period earnings and determining any future rates. To the extent that the Virginia Commission determines total earnings for the test period to be above Virginia Power’s authorized earnings band, the forgiven balance amounts are offset against the excess earnings in the determination of any customer bill credits, or utilization of a CCRO, as part of the 2021 Triennial Review.
Virginia 2020 Legislation
In April 2020, the Governor of Virginia signed into law the VCEA, which along with related legislation forms a comprehensive framework affecting Virginia Power’s operations. The VCEA replaces Virginia’s voluntary renewable energy portfolio standard for Virginia Power with a mandatory program setting annual renewable energy portfolio standard requirements based on the percentage of total electric energy sold by Virginia Power, excluding existing nuclear generation and certain new carbon-free resources, reaching 100% by the end of 2045. The VCEA includes related requirements concerning deployment of wind, solar and energy storage resources, as well as provides for certain measures to increase net-metering, including an allocation for low-income customers, incentivizes energy efficiency programs and directs Virginia to participate in a carbon trading program. While the legislation affects several portions of Virginia Power’s operations, key provisions of the GTSA remain in effect, including the triennial review structure and timing, the use of the CCRO and the $50 million cap on revenue reductions in the first triennial review proceeding. Key provisions of the VCEA and related legislation passed include the following:
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Fossil Fuel Electric Generation: The legislation mandates Chesterfield Power Station Units 5 & 6 and Yorktown Power Station Unit 3 to be retired by the end of 2024, Altavista, Southampton and Hopewell to be retired by the end of 2028 and Virginia Power’s remaining fossil fuel units to be retired by the end of 2045, unless the retirement of such generating units will compromise grid reliability or security. The legislation also imposes a temporary moratorium on CPCNs for fossil fuel generation, unless the resources are needed for grid reliability. In addition, the Virginia Commission shall determine the amortization period for recovery of any appropriate costs due to the early retirement of any electric generation facilities, which could result in the reversal of previous retirement costs deemed recovered during the review period ending 2020. As discussed in Note 2, Virginia Power had recorded charges for early retirement of certain coal- and oil-fired generating units in the first quarters of 2020 and 2019. Virginia Power also revised the depreciable lives of Altavista, Southampton and Hopewell for the mandated retirement to the end of 2028, which will not have a material impact to Virginia Power’s results of operations or cash flows given the existing regulatory framework.
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Renewable Generation: The legislation provides a detailed renewable energy portfolio standard to achieve 100% zero-carbon generation by the end of 2045, excluding existing nuclear generation and certain new carbon-free resources. Components include requirements to petition the Virginia Commission for approval to construct or acquire new generating capacity to reach 16.1 GW of installed solar and onshore wind by the end of 2035, which includes specific requirements for utility-scale solar of 3.0 GW by the end of 2024, up to 15.0 GW by the end of 2035 and 1.1 GW of small-scale solar by the end of 2035. The legislation deems 2.7 GW of energy storage, including up to 800 MW for any one project which may include a pumped storage facility, by the end of 2035 to be in the public interest. The legislation also deems the construction or purchase of an offshore wind facility constructed off the Virginia coast with a capacity of up to 5.2 GW before 2035 to be in the public interest and provides certain presumptions facilitating cost recovery. The costs of such a facility constructed by the utility with a capacity between 2.5 and 3.0 GW will be presumed reasonably and prudently incurred if the Virginia Commission finds that the project meets competitive procurement requirements, the projected cost of the facility does not exceed a specified industry benchmark and the utility commences construction by the end of 2023 or has a plan for the facility to be in service by the end of 2027. Projects to meet these requirements are subject to approval by the Virginia Commission.
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Energy Efficiency: The legislation includes an energy efficiency target of 5% energy savings, as measured from a 2019 baseline, through verifiable energy efficiency programs by the end of 2025 with future targets to be set by the Virginia Commission. Virginia Power has the opportunity to offset the lost revenues with margins on program spend if certain targets are achieved and can also seek recovery of the lost revenues associated with energy efficiency programs if such reductions are found to have caused Virginia Power to earn more than 50 basis points below a fair rate of return on its rates for generation and distribution services.
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Carbon trading program: The legislation directs Virginia Power to participate in a market-based carbon trading program consistent with RGGI through 2050. All costs of the carbon trading program are recoverable through an environmental rider.
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Low-income customers: The legislation includes the establishment of a percentage of income payment program to be administered by the Virginia Department of Housing and Community Development and the Virginia Department of Social Services. To fund the program, Virginia Power will remit amounts collected from customers under a universal service fee established and set by the Virginia Commission. As such, this program will not affect Virginia Power’s results of operations, financial position or cash flows. In December 2020, the Virginia Commission issued a final order confirming a revenue requirement of $93 million related to this program. Implementation details and the effective date of the program will be established in future legislation prior to collection of fees from customers.
Virginia Power expects to incur significant costs, including capital expenditures, to comply with the legislative requirements discussed above. The legislation allows for cost recovery under the existing or modified regulatory framework through rate adjustment clauses, rates for generation and distribution services or Virginia Power’s fuel factor, as approved by the Virginia Commission. Costs allocated to the North Carolina jurisdiction will be recovered, subject to approval by the North Carolina Commission, in accordance with the existing regulatory framework.
Virginia Fuel Expenses
In February 2020, Virginia Power filed its annual fuel factor with the Virginia Commission to recover an estimated $1.2 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2020 and a projected over-recovery of approximately $81 million for the prior year balance as of June 30, 2020. Virginia Power requested that the new fuel factor rate be implemented on an interim basis two months early, beginning on May 1, 2020. In March 2020, the Virginia Commission approved interim rates. Virginia Power’s proposed fuel rate represents a fuel revenue decrease of approximately $393 million when applied to projected kilowatt-hour sales for the rate year beginning May 1, 2020. In June 2020, the Virginia Commission approved a revised fuel rate based on an updated projected over-recovery of $103 million from the prior year balance as of June 30, 2020.
Solar Facility Projects
In May 2020 and July 2020, Virginia Power entered into and closed on separate agreements to acquire Grassfield Solar, Norge Solar and Sycamore Solar. The projects are expected to cost approximately $170 million in aggregate once constructed, including the initial acquisition cost. The facilities are expected to generate 82 MW combined and be placed into service in 2021 and 2022. In October 2020, Virginia Power filed an application with the Virginia Commission for CPCNs to construct and operate these projects as part of its efforts to meet the renewable generation development requirements under VCEA. This matter is pending.
In December 2020, Virginia Power entered into and closed on separate agreements to acquire Fountain Creek Solar and Otter Creek Solar. The projects are expected to cost approximately $280 million in aggregate once constructed, including the initial acquisition cost. The facilities are expected to generate 140 MW combined and be placed into service by the end of 2023. Virginia Power expects to file with the Virginia Commission for CPCNs to construct and operate these projects as well as a rider to recover the costs associated with the recovery of certain renewable generation facilities in Virginia by the end of 2021.
Riders
Below is a discussion of significant riders associated with various Virginia Power projects:
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The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2020, Virginia Power proposed a $1 billion total revenue requirement consisting of $474 million for the transmission component of Virginia Power’s base rates and $529 million for Rider T1 for the rate year beginning September 1, 2020. This total revenue requirement represents a $73 million increase versus the revenues to be produced during the rate year under current rates. In July 2020, the Virginia Commission approved the filing.
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The Virginia Commission previously approved Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by Virginia legislation. In June 2020, Virginia Power proposed an $80 million total revenue requirement consisting of $44 million for previously approved phases and $36 million for phase five costs for Rider U for the rate year beginning April 1, 2021. This total revenue requirement represents a $28 million increase over the previous year. This matter is pending.
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The Virginia Commission previously approved Riders C1A, C2A and C3A in connection with cost recovery for DSM programs. In December 2019, Virginia Power filed a petition to approve an additional 10 new energy efficiency programs and one new demand response DSM program for five years, subject to future extension, with a $186 million cost cap, and proposed a total $60 million revenue requirement for the rate year beginning September 1, 2020. This total revenue requirement represents an $11 million increase over the previous year. In July 2020, the Virginia Commission approved the filing. In December 2020, Virginia Power filed a petition to approve an additional 10 new energy efficiency programs and one new demand response DSM program for five years, subject to future extension, with a $162 million cost cap, and proposed a total $78 million revenue requirement for the rate year beginning September 1, 2021. This total revenue requirement represents an $18 million increase over the previous year. Virginia Power also requested approval to establish a new Rider C4A in connection with cost recovery for DSM programs. This matter is pending.
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In October 2020, Virginia Power applied for approval of Rider CE associated with Grassfield Solar, Norge Solar and Sycamore Solar described above. Virginia Power proposed an $11 million revenue requirement for the rate year beginning June 1, 2021. This matter is pending.
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Pursuant to Virginia legislation, Virginia Power can recover costs associated with participating in a market-based carbon trading program consistent with RGGI. In December 2020, Virginia Power filed for approval of Rider RGGI with a proposed $167 million revenue requirement for the rate year beginning August 1, 2021. This matter is pending.
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Pursuant to the VCEA, Virginia Power can recover costs of compliance with the mandatory renewable portfolio standard program. In December 2020, Virginia Power filed for approval of Rider RPS with a proposed $13 million revenue requirement for the rate year beginning August 1, 2021. This matter is pending.
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Additional significant riders associated with various Virginia Power projects are as follows:
Electric Transmission Projects
In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry switching station in Surry County to a new Skiffes Creek switching station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County, and the City of Newport News from the proposed new Skiffes Creek switching station to Virginia Power’s existing Whealton substation in the City of Hampton. In February 2019, the transmission line project was placed into service. In March 2019, the U.S. Court of Appeals for the D.C. Circuit issued an order vacating the permit from the U.S. Army Corps of Engineers issued in July 2017 and ordered the U.S. Army Corps of Engineers to do a full environmental impact study of the project. In April 2019, Virginia Power and the U.S. Army Corps of Engineers filed petitions for rehearing with the U.S. Court of Appeals for the D.C. Circuit, asking that the permit from the U.S. Army Corps of Engineers remain in effect while an environmental impact study is performed. In May 2019, the U.S. Court of Appeals for the D.C. Circuit denied the request for rehearing and ordered the U.S. District Court for the D.C. Circuit to consider and issue a ruling on whether the permit should be vacated during the U.S. Army Corps of Engineers’ preparation of an environmental impact statement. In November 2019, the U.S. District Court for the D.C. Circuit issued an order allowing the permit to remain in effect while an environmental impact statement is prepared. In November 2020, the U.S. Army Corps of Engineers issued a draft environmental impact statement noting there is no better alternative. This matter is pending
In December 2019, Virginia Power filed an application with the Virginia Commission for a CPCN to construct a new Evergreen Mills switching station and add approximately one mile of overhead 230 kV double circuit transmission lines from both the existing Brambleton-Yardley Ridge line and Brambleton-Poland Road line in Loudoun County, Virginia, estimated to cost approximately $30 million. In May 2020, the Virginia Commission issued an order approving in part and denying in part the petition. The Virginia Commission approved Virginia Power’s request to construct the new Evergreen Mills switching station and the new 230 kV double circuit transmission line from the existing Brambleton-Yardley Ridge line with a total estimated cost of $25 million.
Additional significant Virginia Power electric transmission projects approved or applied for are as follows:
North Carolina Regulation
North Carolina Base Rate Case
In March 2019, Virginia Power filed its base rate case and schedules with the North Carolina Commission. Virginia Power proposed a non-fuel, base rate increase of $27 million effective November 1, 2019 on an interim basis subject to refund, with any permanent rates ordered by the North Carolina Commission effective January 1, 2020. The base rate increase was proposed to recover the significant investments in generation, transmission and distribution infrastructure for the benefit of North Carolina customers. Virginia Power presented an earned return of 7.52% based upon a fully-adjusted test period, compared to its authorized 9.90% return, and proposed a 10.75% ROE. In September 2019, Virginia Power revised its filing to reduce the non-fuel base rate increase to $24 million. In January 2020, the North Carolina Commission approved a 9.75% ROE and disallowed certain costs associated with coal ash remediation at Chesterfield power station. In February 2020, the North Carolina Commission issued its final order relating to base rates. In July 2020, Virginia Power filed a notice of appeal and exceptions to the Supreme Court of North Carolina, arguing that the North Carolina Commission committed reversible error on certain issues relating to the ratemaking treatment of certain coal ash remediation costs. This matter is pending.
North Carolina Fuel Filing
In August 2020, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. In January 2021, the North Carolina Commission approved a total $16 million decrease to the fuel component of its electric rates for the rate year beginning February 1, 2021.
Pipeline Integrity and Safety Program
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. In September 2020, the North Carolina Commission approved PSNC’s request to increase the integrity management annual revenue requirement to $31 million, an increase of $3 million over its previous filing, effective September 2020.
In February 2021, the North Carolina Commission approved PSNC’s request to increase the integrity management annual revenue requirement to $33 million, an increase of $2 million over its previous filing, effective March 2021.
South Carolina Regulation
South Carolina Electric Base Rate Case
In August 2020, DESC filed its retail electric base rate case and schedules with the South Carolina Commission. DESC proposed a non-fuel, base rate increase of $178 million, or 7.75%, based on an adjusted test year data, effective on or after the first billing cycle of March 2021. The base rate increase was proposed to recover the significant investment in assets and operating resources required to serve an expanding customer base, maintain the safety, reliability and efficiency of DESC’s system and meet increasingly stringent reliability, security and environmental requirements for the benefit of South Carolina customers. DESC presented an earned ROE of 5.90% based upon a fully-adjusted test period. The proposed rates would provide for an earned ROE equal to the current authorized earned ROE of 10.25% established in the previous rate case in 2012. In January 2021, the South Carolina Commission approved a proposal made by the South Carolina Office of Regulatory Staff, and agreed to by DESC and other intervenors, to stay the base rate case due to the current economic conditions and to allow the parties more time to negotiate a settlement with a final order to be issued no later than August 2021. In connection with this order, DESC, the South Carolina Office of Regulatory Staff and other parties of record are to provide monthly updates to the South Carolina Commission on the progress towards reaching a negotiated settlement. This matter is pending.
DSM Programs
DESC has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In January 2020, DESC filed an application with the South Carolina Commission seeking approval to recover $40 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. In April 2020, The South Carolina Commission approved the filing.
In January 2021, DESC filed an application with the South Carolina Commission seeking approval to recover $48 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. This matter is pending.
Natural Gas Rates
In June 2020, DESC filed with the South Carolina Commission its monitoring report for the 12-month period ended March 31, 2020 with a total revenue requirement of $409 million. This represents a $9 million overall annual increase to its natural gas rates under the terms of the Natural Gas Rate Stabilization Act effective with the first billing cycle of November 2020. In October 2020, the South Carolina Commission approved a total revenue requirement of $406 million effective with the first billing cycle of November 2020. This represents a $6 million overall annual increase to DESC’s natural gas rates. Additionally, the South Carolina Commission authorized an allowed ROE of 9.90%, a reduction from the prior ROE of 10.25%. The South Carolina Commission also approved an agreement between the South Carolina Office of Regulatory Staff and DESC that DESC will file its next retail natural gas general rate proceeding no later than April 2023.
Cost of Fuel
DESC’s retail electric rates include a cost of fuel component approved by the South Carolina Commission which may be adjusted periodically to reflect changes in the price of fuel purchased by DESC. In February 2020, DESC filed a proposal with the South Carolina Commission to decrease the total fuel cost component of retail electric rates. DESC’s proposed decrease would reduce annual base fuel component recoveries by approximately $44 million and is projected to return to customers the existing over-collected balance while recovering DESC’s current base fuel costs over the 12-month period beginning with the first billing cycle of May 2020. In addition, DESC proposed an increase to its variable environmental and distributed energy resource components. In April 2020, the South Carolina Commission approved the filing.
In February 2021, DESC filed with the South Carolina Commission a proposal to increase the total fuel cost component of retail electric rates. DESC’s proposed adjustment would increase annual base fuel component recoveries by approximately $36 million and is designed to recover DESC’s current base fuel costs, net of the existing over-collected balance, over the 12-month period beginning with the first billing cycle of May 2021. In addition, DESC proposed a decrease to its variable environmental component and an increase to its distributed energy resource component. This matter is pending.
Electric Transmission Projects
In 2020, DESC began several electric transmission projects in connection with two new nuclear plants under development by Southern. These transmission projects are required to be in place prior to these plants beginning operations to maintain reliability. DESC anticipates the projects to go into service in phases, costing approximately $75 million in aggregate. In February 2020, DESC filed an application with the South Carolina Commission requesting approval to construct and operate 28 miles of 230 kV transmission lines in Aiken County, South Carolina estimated to cost approximately $30 million. In June 2020, the South Carolina Commission approved the filing.
Ohio Regulation
PIR Program
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, calendar years 2017 through 2021, and to permit East Ohio to increase its annual capital expenditures to $200 million by 2018 and 3% per year thereafter subject to the cost recovery rate increase caps proposed by East Ohio.
In April 2020, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2019 costs. The filing reflects gross plant investment for 2019 of $209 million, cumulative gross plant investment of $1.8 billion and a revenue requirement of $218 million.
In December 2020, East Ohio filed an application with the Ohio Commission requesting approval to extend the PIR program for an additional five years upon expiration of the current authorization at the end of 2021. East Ohio proposed continued capital investment increases of 3% per year, with related increases in the annual rate-increase caps. In its application, East Ohio proposed that the new five-year period should include investment through December 31, 2026. This case is pending.
CEP Program
In 2011, East Ohio began CEP which enables East Ohio to defer depreciation expense, property tax expense and carrying costs at the debt rate of 6.5% 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 May 2019, East Ohio filed an application for an alternative rate plan to establish a CEP rider to recover existing CEP-related deferrals and to establish an ongoing recovery mechanism for future deferrals. The filing reflects cumulative gross plant investment of $723 million through 2018 and a revenue requirement of $83 million. In December 2020, the Ohio Commission approved a cumulative gross plant investment of $721 million and a revenue requirement of $83 million.
West Virginia Regulation
West Virginia Base Rate Case
In September 2020, Hope filed its base rate case and schedules with the West Virginia Commission. Hope proposed a non-fuel, base rate increase of $28 million. The base rate increase was proposed to recover the significant investment in distribution infrastructure and costs associated with the acquisition of over 2,000 miles of gathering assets, both for the benefit of West Virginia customers. The proposed rates would provide for an ROE of 10.25% compared to the authorized ROE of 9.45%. The rates are expected to go into effect in July 2021. This matter is pending.
PREP
In May 2020, Hope filed a PREP application with the West Virginia Commission requesting approval to recover PREP costs related to $39 million and $54 million of projected capital investment for 2020 and 2021, respectively. The application also includes a true-up of PREP costs related to the 2019 actual capital investment of $27 million and sets forth $13 million of annual PREP costs to be recovered in proposed rates effective November 1, 2020. In October 2020, the West Virginia Commission approved PREP rates effective November 1, 2020.
Utah Regulation
Purchased Gas
In September 2020, Questar Gas submitted a filing with the Utah Commission for a $40 million gas cost increase. In October 2020, the Utah Commission approved the application on an interim basis, with rates effective November 2020.
Rural Expansion Program
In December 2019, Questar Gas filed an application with the Utah Commission for a CPCN to construct natural gas infrastructure to extend service to Eureka, Utah. The project is expected to include 11 miles of high-pressure pipeline and up to 360 service lines and to be in service in late 2021. Questar Gas also requested approval of a rural expansion rate adjustment tracker to recover the construction costs of the project. In August 2020, the Utah Commission approved the CPCN and the rural expansion rate adjustment tracker.
Wyoming Regulation
Wyoming Base Rate Case
In November 2019, Questar Gas filed its base rate case and schedules with the Wyoming Commission. Questar Gas proposed a non-fuel, base rate increase of $4 million effective September 2020. The base rate increase was proposed to replace aging infrastructure and expand its system. Questar Gas presented an earned return of 7.46%, based upon a fully-adjusted test period, compared to its authorized 9.5% return, and proposed a 10.5% ROE. In June 2020, the Wyoming Commission approved a base rate increase of $2 million annually, with rates effective September 1, 2020. This revenue requirement increase was based on an approved ROE of 9.35%.
NOTE 14. ASSET RETIREMENT OBLIGATIONS
AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of the Companies’ long-lived assets. The Companies AROs are primarily associated with the decommissioning of their nuclear generation facilities and ash pond and landfill closures.
The Companies have also identified, but not recognized, AROs related to the retirement of Dominion Energy’s storage wells in its underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in the Companies’ generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire or dispose of any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets.
The changes to AROs during 2019 and 2020 were as follows:
(1)
Reflects future ash pond and landfill closure costs at certain utility generation facilities. See discussion below.
(2)
Reflects revisions to future ash pond and landfill closure costs at certain utility generation facilities as well as revisions for 20-year license extensions for regulated nuclear power stations in Virginia.
(3)
Includes $394 million and $179 million reported in other current liabilities at December 31, 2019 and 2020, respectively.
(4)
Reflects revisions to future ash pond and landfill closure costs at certain utility generation facilities, asbestos abatement costs associated with certain utility facilities and from the completion of a nuclear decommissioning cost study related to Summer.
(5)
Reflects revisions to future ash pond and landfill closure costs at certain utility generation facilities and asbestos abatement costs associated with certain utility facilities.
Dominion Energy’s AROs at December 31, 2020 and 2019, include $1.9 billion and $1.7 billion, respectively, with $0.9 billion and $0.8 billion recorded by Virginia Power, related to the future decommissioning of their nuclear facilities. The Companies have established trusts dedicated to funding the future decommissioning activities. At December 31, 2020 and 2019, the aggregate fair value of Dominion Energy’s trusts, consisting primarily of equity and debt securities, totaled $6.9 billion and $6.2 billion, respectively. At December 31, 2020 and 2019, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $3.2 billion and $2.9 billion, respectively.
In addition, AROs at December 31, 2020 and 2019 include $2.8 billion and $2.6 billion, respectively, related to Virginia Power’s future ash pond and landfill closure costs. Regulatory mechanisms, primarily associated with legislation described below, provide for recovery of costs to be incurred.
In April 2018, the Governor of Virginia signed legislation into law extending an existing permit moratorium on the VDEQ issuing solid waste permits for the closure of ash ponds at Virginia Power’s Bremo, Chesapeake, Chesterfield and Possum Point power stations until July 2019. The legislation also required Virginia Power to solicit and compile by November 2018, information from third parties on the suitability, cost and market demand for beneficiation or recycling of coal ash from these units. In connection with this legislation, Virginia Power recorded an $81 million ($60 million after-tax) charge recorded in other operations and maintenance expense in its Consolidated Statements of Income.
In March 2019, the Governor of Virginia signed into law legislation which requires any CCR unit located at Virginia Power’s Bremo, Chesapeake, Chesterfield or Possum Point power stations that stopped accepting CCR prior to July 2019 be closed by removing the
CCR to an approved landfill or through recycling for beneficial reuse. Costs associated with the closure of these CCR units, including costs allocated to customers outside of Virginia, are recoverable through a rider approved by the Virginia Commission. In connection with this legislation, Virginia Power recorded a $2.4 billion ARO related to the cost of landfills and beneficial reuse, with an offsetting increase to property, plant and equipment of $1.3 billion for the Chesterfield power station and an increase primarily to regulatory assets for the remaining portion related to the Bremo, Chesapeake and Possum Point power stations in 2019. In connection with the March 2020 commitment for the planned early retirement of the Chesterfield power station, these costs were reclassified from property, plant and equipment primarily to regulatory assets for amounts recoverable through riders and the remaining $185 million associated with nonjurisdictional customers was reclassified to other deferred charges and other assets. In 2020, Virginia Power recorded a $140 million increase to the landfill and beneficial use AROs from revisions to post closure monitoring costs, the execution of a coal beneficiation contract and a landfill at the Chesterfield power station. See Note 12 for additional information.
In addition, Virginia Power revised its estimated cash flows for the existing ARO related to future ash pond and landfill closure costs, which resulted in a decrease of $202 million and a corresponding $113 million ($84 million after-tax) benefit in other operations and maintenance expense in the Consolidated Statements of Income in 2019.
NOTE 15. LEASES
At December 31, 2020 and 2019, the Companies had the following lease assets and liabilities recorded in the Consolidated Balance Sheets:
(1)
Included in other deferred charges and other assets in the Companies’ Consolidated Balance Sheets.
(2)
Included in property, plant and equipment in the Companies’ Consolidated Balance Sheets, net of $50 million and $9 million of accumulated amortization at Dominion Energy and Virginia Power, respectively, at December 31, 2020 and net of $26 million and $4 million of accumulated amortization at Dominion Energy and Virginia Power, respectively, at December 31, 2019.
(3)
Included in other current liabilities in the Companies’ Consolidated Balance Sheets.
(4)
Included in securities due within one year in the Companies’ Consolidated Balance Sheets.
(5)
Included in other deferred credits and other liabilities in the Companies’ Consolidated Balance Sheets.
(6)
Included in other long-term debt in the Companies’ Consolidated Balance Sheets.
In addition to the amounts disclosed above, Dominion Energy’s Consolidated Balance Sheets at December 31, 2020 and 2019 includes property, plant and equipment of $2.2 billion and $2.8 billion, respectively, and accumulated depreciation of $68 million and $364 million, respectively, related to facilities subject to power purchase agreements under which Dominion Energy is the lessor.
For the years ended December 31, 2020 and 2019, total lease cost associated with the Companies’ leasing arrangements consisted of the following:
For the years ended December 31, 2020 and 2019, cash paid for amounts included in the measurement of the lease liabilities consisted of the following amounts, included in the Companies’ Consolidated Statements of Cash Flows:
In addition to the amounts disclosed above, Dominion Energy’s Consolidated Statements of Income for the years ended December 31, 2020 and 2019, include $175 million and $174 million, respectively, of rental revenue, included in operating revenue and $102 million and $94 million, respectively, of depreciation expense, included in depreciation, depletion and amortization, related to facilities subject to power purchase agreements under which Dominion Energy is the lessor.
At December 31, 2020 and 2019, the weighted average remaining lease term and weighted discount rate for the Companies’ finance and operating leases were as follows:
The Companies’ lease liabilities have the following maturities:
Corporate Office Leasing Arrangement
In December 2019, Dominion Energy signed an agreement with a lessor, as amended in May 2020, to construct and lease a new corporate office property in Richmond, Virginia. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $465 million, to fund the estimated project costs. If Dominion Energy ultimately proceeds with the project through completion, the project is expected to be completed by September 2024. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs, which totaled $61 million as of December 31, 2020. If the project is terminated under certain events, Dominion Energy could be required to pay up to 100% of the then funded amount.
The lease term will commence once construction is substantially complete and the facility is able to be occupied and will end in December 2027. At the end of the initial lease term, Dominion Energy can (i) extend the term of the lease for an additional five years, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property on behalf of the lessor to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the project costs, Dominion Energy may be required to make a payment to the lessor, up to 83% of project costs, for the difference between the project costs and sale proceeds.
Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.
Offshore Wind Vessel Leasing Arrangement
In December 2020, Dominion Energy signed an agreement 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 completed by the end of 2023. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs, which totaled $187 million as of December 31, 2020. If the project is terminated under certain events of default, Dominion Energy could be required to pay up to 100% of the then funded amount.
The initial lease term will commence once construction is substantially complete and the vessel is delivered and will mature in November 2027. At the end of the initial lease term, Dominion Energy can (i) extend the term of the lease for an additional term, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the outstanding project costs or, (iii) subject to certain terms and conditions, sell the property on behalf of the lessor to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the outstanding project costs, Dominion Energy may be required to make a payment
to the lessor for the difference between the outstanding project costs and sale proceeds. Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.
NOTE 16. VARIABLE INTEREST ENTITIES
The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
Dominion Energy
At December 31, 2020, Dominion Energy owns the manager and 67% of the membership interest in certain nonregulated solar facilities, as discussed in Note 2. Dominion Energy has concluded that these entities are VIEs due to the members lacking the characteristics of a controlling financial interest. In addition, in 2016 Dominion Energy created a wholly owned subsidiary, SBL Holdco, as a holding company of its interest in the VIE nonregulated solar facilities and accordingly SBL Holdco is a VIE. Dominion Energy is the primary beneficiary of SBL Holdco and the nonregulated solar facilities, as it has the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. Dominion Energy’s securities due within one year and long-term debt include $32 million and $239 million, respectively, of debt issued by SBL Holdco net of issuance costs that is nonrecourse to Dominion Energy and is secured by SBL Holdco’s interest in certain nonregulated solar facilities.
At December 31, 2020, Dominion Energy owns a 50% membership interest in Cove Point, as discussed in Notes 3 and 9. Dominion Energy concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. As a result of the GT&S Transaction, effective November 1, 2020, Dominion Energy is no longer the primary beneficiary of Cove Point as BHE retains the power to direct the activities that most significantly impact Cove Point’s economic performance. Dominion Energy’s maximum exposure to loss is limited to its current and future investment, as well as any obligations under a guarantee provided. See Note 23 for more information.
At December 31, 2020, Dominion Energy owns a 53% membership interest in Atlantic Coast Pipeline. Dominion Energy concluded that Atlantic Coast Pipeline is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion Energy has concluded that it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance, as the power to direct is shared with Duke Energy. Dominion Energy is obligated to provide capital contributions based on its ownership percentage. Dominion Energy’s maximum exposure to loss is limited to any future investment as well as any obligations under a guarantee provided. See Note 9 for more details regarding the nature of this entity.
Dominion Energy and Virginia Power
The Companies’ nuclear decommissioning trust funds and Dominion Energy’s rabbi trusts hold investments in limited partnerships or similar type entities (see Note 9 for further details). Dominion Energy and Virginia Power concluded that these partnership investments are VIEs due to the limited partners lacking the characteristics of a controlling financial interest. Dominion Energy and Virginia Power have concluded neither is the primary beneficiary as they do not have the power to direct the activities that most significantly impact these VIEs’ economic performance. Dominion Energy and Virginia Power are obligated to provide capital contributions to the partnerships as required by each partnership agreement based on their ownership percentages. Dominion Energy and Virginia Power’s maximum exposure to loss is limited to their current and future investments.
Virginia Power
Virginia Power had a long-term power and capacity contract with one non-utility generator with an aggregate summer generation capacity of approximately 218 MW. The contract contained certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considered to be variable interests and for which Virginia Power had previously concluded if the generation facility were to be a VIE that it would not be the primary beneficiary. In May 2019, Virginia Power entered into an agreement and paid $135 million to terminate the remaining contract with the non-utility generator. A $135 million ($100 million after-tax) charge was recorded in impairment of assets and other charges in Virginia Power’s Consolidated Statements of Income (reflected in the Corporate and Other segment) during the second quarter of 2019. Virginia Power paid $13 million and $50 million for
electric capacity to non-utility generators and $1 million and $18 million for electric energy to non-utility generators for the years ended December 31, 2019 and 2018, respectively.
Virginia Power purchased shared services from DES, an affiliated VIE, of $349 million, $387 million and $335 million for the years ended December 31, 2020, 2019 and 2018, respectively. Virginia Power’s Consolidated Balance Sheets included amounts due to DES of $175 million at December 31, 2020, and $102 million at December 31, 2019, respectively, recorded in payables to affiliates in the Consolidated Balance Sheets. Virginia Power determined that it is not the primary beneficiary of DES as it does not have power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it. DES provides accounting, legal, finance and certain administrative and technical services to all Dominion Energy subsidiaries, including Virginia Power. Virginia Power has no obligation to absorb more than its allocated share of DES costs.
NOTE 17. SHORT-TERM DEBT AND CREDIT AGREEMENTS
The Companies use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion Energy utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion Energy’s credit ratings and the credit quality of its counterparties.
Dominion Energy
Dominion Energy’s short-term financing is supported through its access to the joint revolving credit facility described below. Commercial paper and letters of credit outstanding, as well as capacity available under the credit facility were as follows:
(1)
The weighted-average interest rates of the outstanding commercial paper supported by Dominion Energy’s credit facility was 0.29% and 2.10% at December 31, 2020 and 2019, respectively.
(2)
This credit facility matures in March 2023 and can be used by the borrowers under the credit facility to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.
(3)
In October 2020, the joint revolving credit facility was amended to remove Dominion Energy Gas as a co-borrower.
DESC and Questar Gas’ short-term financings are supported through access as co-borrowers to the joint revolving credit facility discussed above with the Companies. At December 31, 2020, the sub-limits for DESC and Questar Gas were $500 million and $250 million, respectively.
In January 2020, DESC and GENCO applied to FERC for a two-year short-term borrowing authorization. In March 2020, FERC granted DESC authority through March 2021 to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act) in amounts not to exceed $2.2 billion outstanding with maturity dates of one year or less. In addition, in March 2020, FERC granted GENCO authority through March 2021 to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. In January 2021, DESC and GENCO applied to FERC for a two-year short-term borrowing authorization. The applications are pending.
In addition to the credit facility mentioned above, Dominion Energy also has a credit facility which had an original stated maturity date of June 2020 and allowed Dominion Energy to issue up to $21 million in letters of credit. In May 2020, the credit facility was amended to increase the facility capacity to approximately $30 million and extend the maturity date to June 2022. At December 31, 2020 and 2019, Dominion Energy had $30 million and $21 million, respectively, in letters of credit outstanding under this agreement.
In addition to the credit facilities mentioned above, SBL Holdco has $30 million of credit facilities which had an original stated maturity date of December 2017 with automatic one-year renewals through the maturity of the SBL Holdco term loan agreement in December 2023. Dominion Solar Projects III, Inc. has $25 million of credit facilities which had an original stated maturity date of May 2018 with automatic one-year renewals through the maturity of the Dominion Solar Projects III, Inc. term loan agreement in May 2024. At both December 31, 2020 and 2019, no amounts were outstanding under either of these facilities.
In March 2020, Dominion Energy entered into a $900 million 364-Day Revolving Credit Agreement. The agreement bears interest at a variable rate. At December 31, 2020, $225 million was outstanding under the agreement. The proceeds from these borrowings were used to provide for general working capital and other general corporate purposes. The maximum allowed total debt to total capital ratio under this supplemental agreement is consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility.
In March 2020, Dominion Energy borrowed $500 million under a 364-Day Term Loan Credit Agreement that bore interest at a variable rate. The proceeds were used to provide for general working capital and other general corporate purposes. In November 2020, Dominion Energy repaid the outstanding balance in full.
In April 2020, Dominion Energy borrowed $625 million under a 364-Day Term Loan Credit Agreement that bore interest at a variable rate. The proceeds were used to provide for general working capital and other general corporate purposes. In June 2020, Dominion Energy repaid the outstanding balance in full.
Dominion Energy has an effective shelf registration statement with the SEC for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability InvestmentSM. The registration limits the principal amount that may be outstanding at any one time to $1.0 billion. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Dominion Energy Reliability Investment Committee, or its designee, on a weekly basis. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Dominion Energy or at the investor’s option at any time. At December 31, 2020 and December 31, 2019, Dominion Energy’s Consolidated Balance Sheets include $268 million and $75 million, respectively, presented within short-term debt. The proceeds are used for general corporate purposes and to repay debt.
Virginia Power
Virginia Power’s short-term financing is supported through its access as co-borrower to the joint revolving credit facility. The credit facility can be used for working capital, as support for the combined commercial paper programs of the borrowers under the credit facility and for other general corporate purposes.
Virginia Power’s share of commercial paper and letters of credit outstanding under the joint revolving credit facility with Dominion Energy, Questar Gas and DESC were as follows:
(1)
The weighted-average interest rates of the outstanding commercial paper supported by the credit facility was 0.30% and 2.10% at December 31, 2020 and 2019, respectively.
(2)
The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Questar Gas and DESC. The sub-limit for Virginia Power is set within the facility limit but can be changed at the option of the borrowers under the credit facility multiple times per year. At December 31, 2020, the sub-limit for Virginia Power was $1.5 billion. If Virginia Power has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.
(3)
In October 2020, the joint revolving credit facility was amended to remove Dominion Energy Gas as a co-borrower.
NOTE 18. LONG-TERM DEBT
(1)
Represents weighted-average coupon rates for debt outstanding as of December 31, 2020.
(2)
These financings relate to certain pollution control equipment at Virginia Power’s generating facilities.
(3)
Includes debt assumed by Dominion Energy from the merger of its former CNG subsidiary.
(4)
In April 2020, Dominion Energy purchased and canceled $7 million of its 2.579% junior subordinated notes that mature in July 2020. In June 2020, Dominion Energy prepaid the remaining balance of $993 million.
(5)
In February 2020, Dominion Energy purchased and cancelled the remaining $111 million and $286 million of its June 2006 hybrids and September 2006 hybrids, respectively, both of which would have otherwise matured in 2066. As such, these borrowings are presented within securities due within one year in Dominion Energy’s Consolidated Balance Sheets at December 31, 2019.
(6)
In February 2020, SCANA provided notice to redeem the remaining principal outstanding of $183 million of its 4.75% medium-term notes and $155 million of its 4.125% medium term notes plus accrued interest and make-whole premiums in March 2020. The notes would have otherwise matured in May 2021 and February 2022, respectively. As such, these borrowings are presented within securities due within one year in Dominion Energy’s Consolidated Balance Sheets at December 31, 2019.
(7)
In January 2020, SCANA provided notice to redeem its floating rate senior notes at the remaining principal outstanding of $66 million plus accrued interest in March 2020. The notes would have otherwise matured in June 2034. As such, these borrowings are presented within securities due within one year in Dominion Energy’s Consolidated Balance Sheets at December 31, 2019.
(8)
Industrial revenue bonds totaling $68 million are secured by letters of credit that expire, subject to renewal, in the fourth quarter of 2021.
(9)
Represents debt associated with Eagle Solar, SBL Holdco and Dominion Solar Projects III, Inc. The debt is nonrecourse to Dominion Energy and is secured by Eagle Solar’s, SBL Holdco’s and Dominion Solar Projects III, Inc’s interest in certain solar facilities.
(10)
Excludes amounts classified as held for sale. See Note 3.
(11)
Represents the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt.
(12)
Includes $22 million of estimated mandatory prepayments due within one year based on estimated cash flows in excess of debt service at SBL Holdco and Dominion Solar Projects III, Inc.
Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2020, were as follows:
(1)
Excludes mandatory prepayments associated with SBL Holdco and Dominion Solar Projects III, Inc. based on cash flows in excess of debt service. At December 31, 2020, $22 million of estimated mandatory prepayments due within one year were included in securities due within one year in Dominion Energy’s Consolidated Balance Sheets.
(2)
In January 2020, SCANA provided notice to redeem its floating rate senior notes at the remaining principal outstanding of $66 million plus accrued interest in March 2020. The notes would have otherwise matured in June 2034.
(3)
In February 2020, SCANA provided notice to redeem the remaining principal outstanding of $183 million of its 4.75% medium-term notes and $155 million of its 4.125% medium-term notes plus accrued interest and make-whole premiums in March 2020. The notes would have otherwise matured in May 2021 and February 2022, respectively.
(4)
In April 2020, Dominion Energy purchased and canceled $7 million of its 2.579% junior subordinated notes that mature in July 2020. In June 2020, Dominion Energy prepaid the remaining balance of $993 million.
(5)
In February 2020, Dominion Energy purchased and cancelled the remaining $111 million and $286 million of its June 2006 hybrids and September 2006 hybrids, respectively, both of which would have otherwise matured in 2066. As such, these borrowings are presented within current liabilities in Dominion Energy’s Consolidated Balance Sheets at December 31, 2019.
The Companies’ short-term credit facility and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2020, there were no events of default under these covenants.
Senior Note Issuances
In February 2021, PSNC entered into an agreement with certain investors to issue through private placement in March 2021, $150 million 3.10% 30-year senior notes. The proceeds will be used for the repayment of existing indebtedness and for general corporate purposes.
Senior Note Redemptions
In March 2020, SCANA redeemed its floating rate senior notes at the remaining principal balance of $66 million plus accrued interest. The notes would have otherwise matured in June 2034. Expenses related to the early redemption of the senior notes were $7 million reflected within interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2020.
In March 2020, SCANA redeemed the remaining principal outstanding of $183 million of its 4.75% medium-term notes and $155 million of its 4.125% medium-term notes plus accrued interest and make-whole premiums. The notes would have otherwise matured in May 2021 and February 2022, respectively. Total expenses related to the early redemption of the medium-term notes were $14 million reflected within interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2020.
Enhanced Junior Subordinated Notes
In June 2006 and September 2006, Dominion Energy issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids and the September 2006 hybrids bore interest at the three-month LIBOR plus 2.825%, reset quarterly and at the three-month LIBOR plus 2.3%, reset quarterly, respectively. Dominion Energy executed RCCs in connection with its issuance of the June 2006 hybrids and the September 2006 hybrids. Under the terms of the RCCs, redemptions of the hybrids were subject to certain conditions. In 2019, Dominion Energy purchased and cancelled $12 million and $13 million of its June 2006 hybrids and September 2006 hybrids, respectively. In February 2020, Dominion Energy redeemed the remaining $111 million and $286 million of its June 2006 hybrids and September 2006 hybrids, respectively, both of which would have otherwise matured in 2066. All purchases were conducted in compliance with the applicable RCC, each of which was terminated in February 2020. Expenses related to the early redemption of the hybrids were $10 million reflected within interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2020.
In October 2014, Dominion Energy issued $685 million of October 2014 hybrids that will bear interest at 5.75% per year until October 1, 2024. Thereafter, they will bear interest at the three-month LIBOR plus 3.057%, reset quarterly.
In July 2016, Dominion Energy issued $800 million of 5.25% July 2016 hybrids. The July 2016 hybrids are listed on the NYSE under the symbol DRUA.
Dominion Energy may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion Energy may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments during the deferral period. Also, during the deferral period, Dominion Energy may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids.
Remarketable Subordinated Notes
In June 2019, Dominion Energy successfully remarketed the $700 million 2016 Series A-1 2.0% RSNs due 2021 and $700 million 2016 Series A-2 2.0% RSNs due 2024 pursuant to the terms of the related 2016 Equity Units. In connection with the remarketing, the interest rates on the Series A-1 and Series A-2 notes were reset to 2.715% and 3.071%, respectively, payable on a semi-annual basis, and Dominion Energy ceased to have the ability to redeem the notes at its option or defer interest payments.
Dominion Energy did not receive any proceeds from the remarketing. Remarketing proceeds belonged to the investors holding the 2016 Equity Units and were temporarily used to purchase a portfolio of treasury securities. Upon maturity of the portfolio, the proceeds were applied on behalf of the investors on the related stock purchase contract settlement date to pay the purchase price to Dominion Energy for issuance of 18.5 million shares of its common stock in August 2019.
Derivative Restructuring
In June 2020, Dominion Energy amended a portfolio of interest rate swaps with a notional value of $2.0 billion, extending the mandatory termination dates from 2020 and 2021 to December 2024. The transaction is viewed as a noncash financing activity with an embedded interest rate swap. As a result, in June 2020, Dominion Energy recorded $326 million in other long-term debt, representing the net present value of the initial fair value measurement of the new contract with an imputed interest rate of 1.19%, in its Consolidated Balance Sheets with an embedded interest rate derivative that had a fair value of zero at inception.
In August 2020, Virginia Power amended a portfolio of interest rate swaps with a notional value of $900 million, extending the mandatory termination dates from 2020 to December 2023. The transaction is viewed as a noncash financing activity with an
embedded interest rate swap. As a result, in August 2020, Virginia Power recorded $443 million in other long-term debt, representing the net present value of the initial fair value measurement of the new contract with an imputed interest rate of 0.34%, in its Consolidated Balance Sheets with an embedded interest rate derivative that had a fair value of zero at inception. The interest rate swaps were in a hedge relationship prior to the transaction. Virginia Power de-designated the hedge relationships prior to the transaction and then designated the new interest rate swap in a hedge relationship after the transaction.
NOTE 19. PREFERRED STOCK
Dominion Energy is authorized to issue up to 20 million shares of preferred stock, which may be designated into separate classes. At both December 31, 2020 and 2019, Dominion Energy had issued and outstanding 2.4 million shares preferred stock, 1.6 million and 0.8 million of which were designated as the Series A Preferred Stock and the Series B Preferred Stock, respectively.
DESC is authorized to issue up to 20 million shares of preferred stock. At both December 31, 2020 and 2019, DESC had issued and outstanding 1,000 shares of preferred stock, all of which were held by SCANA and are eliminated in consolidation.
Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference; however, none were issued and outstanding at December 31, 2020 or 2019.
2019 Corporate Units
In June 2019, Dominion Energy issued $1.6 billion of 2019 Equity Units, initially in the form of 2019 Series A Corporate Units. The Corporate Units are listed on the NYSE under the symbol DCUE. The net proceeds were used for general corporate purposes and to repay short-term debt, including commercial paper.
Each 2019 Series A Corporate Unit consists of a stock purchase contract and a 1/10, or 10%, undivided beneficial ownership interest in one share of Series A Preferred Stock. Beginning in June 2022, the Series A Preferred Stock is convertible at the option of the holder into Dominion Energy common stock under a formula based upon the average closing price of Dominion Energy common stock prior to the conversion date. The Series A Preferred Stock is redeemable in cash by Dominion Energy beginning September 2022 at the liquidation preference. Settlement of any conversion is payable in cash, common stock or a combination thereof, at Dominion Energy’s election.
The stock purchase contracts obligate the holders to purchase shares of Dominion Energy common stock in June 2022. The purchase price to be paid under the stock purchase contracts is $100 per Corporate Unit and the number of shares to be purchased will be determined under a formula based upon the average closing price of Dominion Energy common stock near the settlement date. The Series A Preferred Stock was pledged upon issuance as collateral to secure the purchase of common stock under the related stock purchase contracts.
Dominion Energy pays cumulative dividends on the Series A Preferred Stock and quarterly contract adjustment payments on the stock purchase contracts, at the rates described below. Dominion Energy may elect to pay such dividends and/or payments in cash, shares of Dominion Energy common stock or a combination of cash and shares of Dominion Energy common stock. Dominion Energy may defer the contract adjustment payments for one or more consecutive periods but generally not beyond the purchase contract settlement date. If payments are deferred, Dominion Energy may not make any distributions related to its capital stock, including dividends, redemptions, repurchases or liquidation payments. Also, during the deferral period, Dominion Energy may not make any payments on or redeem, repay or repurchase any debt securities that are equal in right of payment with, or subordinated to, the contract adjustment payments or make any payment on any guarantee of a security of a subsidiary if the guarantee ranks equal or junior to the contract adjustment payments. Unless all accumulated and unpaid dividends on the Series A Preferred Stock have been declared and paid, Dominion Energy may not make any distributions on any of its capital stock ranking equal or junior to the Series A Preferred Stock as to dividends or upon liquidation, as applicable, including dividends, redemptions, repurchases or liquidation payments. In such circumstances, Dominion Energy also may not make any contract adjustment payments or other similar types of payments, subject to certain exceptions.
Dominion Energy has recorded the present value of the stock purchase contract payments as a liability offset to common stock. Stock purchase contract payments are recorded against this liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense. In calculating diluted EPS, Dominion Energy applies the treasury stock method to the stock purchase contracts and the if-converted method to the Series A Preferred Stock. Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, the maximum number of shares of common stock Dominion Energy will issue in June 2022 is 21.8 million.
Selected information about Dominion Energy’s 2019 Equity Units is presented below:
(1) Issuance costs of $28 million were recorded as a reduction to preferred stock ($14 million) and common stock ($14 million) in the Consolidated Balance Sheets at December 31, 2019.
(2) Dominion Energy recorded dividends of $28 million ($17.50 per share) and $15 million ($9.479 per share) for the years ended December 31, 2020 and 2019, respectively.
(3) Payments of $83 million and $38 million were made in 2020 and 2019, respectively. The stock purchase contract liability was $129 million and $212 million at December 31, 2020 and 2019, respectively.
Series B Preferred Stock
In December 2019, Dominion Energy issued 800,000 shares of Series B Preferred Stock for $791 million, net of $9 million of issuance costs. The preferred stock has a liquidation preference of $1,000 per share and currently pays a 4.65% dividend per share on the liquidation preference. Dividends are paid cumulatively on a semi-annual basis, commencing June 15, 2020. Dominion Energy recorded dividends of $37 million ($46.50 per share) and $2 million ($1.9375 per share) for the years ended December 31, 2020 and 2019, respectively. The dividend rate for the Series B Preferred Stock will be reset every five years beginning on December 15, 2024 to equal the then-current five-year U.S. Treasury rate plus a spread of 2.993%. Unless all accumulated and unpaid dividends on the Series B Preferred Stock have been declared and paid, Dominion Energy may not make any distributions on any of its capital stock ranking equal or junior to the Series B Preferred Stock as to dividends or upon liquidation, including through dividends, redemptions, repurchases or otherwise.
Dominion Energy may, at its option, redeem the Series B Preferred Stock in whole or in part on December 15, 2024 or on any subsequent fifth anniversary of such date at a price equal to $1,000 per share plus any accumulated and unpaid dividends. Dominion Energy may also, at its option, redeem the Series B Preferred Stock in whole but not in part at a price equal to $1,020 per share plus any accumulated and unpaid dividends at any time within a certain period of time following any change in the criteria ratings agencies use to assign equity credit to securities such as the Series B Preferred Stock that has certain adverse effects on the equity credit actually received by the Series B Preferred Stock.
Holders of the Series B Preferred Stock have no voting rights except in the limited circumstances provided for in the terms of the Series B Preferred Stock or as otherwise required by applicable law. The Series B Preferred Stock is not subject to any sinking fund or other obligation of ours to redeem, repurchase or retire the Series B Preferred Stock. The preferred stock contains no conversion rights.
NOTE 20. EQUITY
Common Stock
Dominion Energy
During 2020, 2019, and 2018, Dominion Energy recorded, net of fees and commissions, $481 million, $11.0 billion and $2.5 billion from the issuance of approximately 7 million, 157 million and 36 million shares of common stock, respectively, for acquisitions, settlements of stock purchase contracts and litigation and through various programs including Dominion Energy Direct®, employee savings plans and an at-the-market program.
Acquisitions
During 2019, Dominion Energy issued 95.6 million shares of common stock in connection with the acquisition of SCANA. At the time of issuance, these common stock shares were valued at $6.8 billion. See Note 3 for further information on the issuance of Dominion Energy common stock in connection with the SCANA Combination.
In January 2019, Dominion Energy and Dominion Energy Midstream closed on an agreement and plan of merger pursuant to which Dominion Energy acquired each outstanding common unit representing limited partner interests in Dominion Energy Midstream not already owned by Dominion Energy through the issuance of 22.5 million shares of common stock valued at $1.6 billion. Under the terms of the agreement and plan of merger, each publicly held outstanding common unit representing limited partner interests in Dominion Energy Midstream was converted into the right to receive 0.2492 shares of Dominion Energy common stock. Immediately prior to the closing, each Series A Preferred Unit representing limited partner interests in Dominion Energy Midstream was converted into common units representing limited partner interests in Dominion Energy Midstream in accordance with the terms of Dominion Energy Midstream’s partnership agreement. The merger was accounted for by Dominion Energy following the guidance for a change
in a parent company’s ownership interest in a consolidated subsidiary. Because Dominion Energy controls Dominion Energy Midstream both before and after the merger, the changes in Dominion Energy’s ownership interest in Dominion Energy Midstream were accounted for as an equity transaction and no gain or loss was recognized. In connection with the merger, Dominion Energy recognized $40 million of income taxes in equity primarily attributable to establishing additional regulatory liabilities related to excess deferred income taxes and changes in state income taxes.
Pension Plan Contribution
In December 2019, Dominion Energy contributed 6.1 million shares of its common stock valued at $499 million to the qualified defined benefit pension plans. See Note 22 for further information regarding activity surrounding pension plan contributions.
Dominion Energy Direct® and Employee Savings Plans
Dominion Energy maintains Dominion Energy Direct® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In August 2020, Dominion Energy began purchasing its common stock on the open market for these direct stock purchase plans. During 2020, Dominion Energy received cash of $159 million from the issuance of 2.1 million of such shares through Dominion Energy Direct® and employee savings plans. In January 2021, Dominion Energy began issuing new shares of common stock for these direct stock purchase plans.
Stock Purchase Contracts
In August 2019, Dominion Energy issued 18.5 million shares under the related stock purchase contracts entered into as part of Dominion Energy’s 2016 Equity Units and received proceeds of $1.4 billion. See Note 18 for further information surrounding these stock purchase contracts.
Other Issuances
In September 2020, Dominion Energy issued 4.1 million shares of its common stock to satisfy its obligation under a settlement agreement for the Santee Cooper Ratepayer Case discussed in Note 23. These shares were immediately repurchased as discussed below.
At-the-Market Program
In June 2017, Dominion Energy entered into sales agency agreements to effect sales under an at-the-market program. In January 2018, Dominion Energy issued 6.6 million shares and received cash proceeds of $495 million, net of fees and commissions paid of $5 million, which completed the program.
In February 2018, Dominion Energy entered into sales agency agreements to effect sales under an at-the-market program. In the fourth quarter of 2018, Dominion Energy issued 2.7 million shares and received cash proceeds of $197 million, net of fees and commissions paid of $2 million. In the first quarter of 2019, Dominion Energy issued 2.1 million shares and received cash proceeds of $154 million, net of fees and commissions paid of $2 million. In the fourth quarter of 2019, Dominion Energy issued 7.8 million shares and received cash proceeds of $639 million, net of fees and commissions paid of $6 million. Following these issuances, Dominion Energy had no remaining capacity under this program.
In March 2020, Dominion Energy entered into sales agency agreements to effect sales under a $500 million at-the-market common stock program. Dominion Energy did not issue any shares under this program which expired in June 2020.
In August 2020, Dominion Energy entered into sales agency agreements to effect sales under a new at-the-market program. Under the sales agency agreements, Dominion Energy may, from time to time, offer and sell shares of its common stock through the sales agents or enter into one or more forward sale agreements with respect to shares of its common stock. Sales by Dominion Energy through the sales agents or by forward sellers pursuant to a forward sale agreement cannot exceed $1.0 billion in the aggregate. Dominion Energy has not issued any shares or entered into any forward sale agreements under this new program.
Forward Sale Agreements
In 2018, Dominion Energy entered into separate forward sale agreements with Goldman Sachs & Co. LLC and Credit Suisse Capital LLC, as forward purchasers, and an underwriting agreement with Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC, as representatives of the several underwriters named therein, relating to an aggregate of 20 million shares of Dominion Energy
common stock. The underwriting agreement granted the underwriters a 30-day option to purchase up to an additional three million shares of Dominion Energy common stock, which the underwriters exercised with respect to approximately 2.1 million shares in April 2018. Dominion Energy entered into separate forward sale agreements with the forward purchasers with respect to the additional shares. In December 2018, Dominion Energy received proceeds of $1.4 billion (after deducting underwriting discounts, but before deducting expenses, and subject to forward price adjustments under the forward sale agreements) upon the physical settlement of 22.1 million shares.
Repurchase of Common Stock
During 2020, Dominion Energy repurchased 38.9 million shares of Dominion Energy common stock for $3.1 billion through an open market agreement, a private transaction and accelerated share repurchase agreements as discussed below.
In July 2020, in contemplation of Dominion Energy entering the July 2020 agreement to sell substantially all of its gas transmission and storage operations to BHE, the Board of Directors authorized the repurchase of up to $3.0 billion of Dominion Energy’s common stock and rescinded its prior repurchase authorization approved in February 2005 and modified in June 2007. Dominion Energy completed repurchases under this authorization in December 2020. In November 2020, the Board of Directors authorized the repurchase of up to $1.0 billion of Dominion Energy’s common stock in addition to the repurchase program authorized in July 2020. 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.
In August 2020, Dominion Energy began repurchasing shares under an open market agreement with a financial institution. During the third quarter of 2020, Dominion Energy repurchased 7.2 million shares of Dominion Energy common stock for $562 million. During the fourth quarter of 2020, Dominion energy repurchased 3.7 million shares of Dominion Energy common stock for $295 million.
In September 2020, Dominion Energy repurchased 4.1 million shares of Dominion Energy common stock in a private transaction for $323 million.
In September 2020, Dominion Energy entered into two prepaid accelerated share repurchase agreements with separate financial institutions as counterparties. Dominion Energy made payments totaling $1.5 billion to the counterparties in exchange for an aggregate of 17.2 million shares of Dominion Energy common stock, which represented approximately 90% of $1.5 billion worth of Dominion Energy shares based on the closing price of such shares on the date the agreements were executed. In November 2020, Dominion Energy received an additional 1.4 million shares upon completion of the respective purchase periods under the terms of the agreements. The number of additional shares delivered under each agreement was based on the average of the daily volume-weighted average stock prices of Dominion Energy’s common stock during the term of the applicable purchase period, less a discount. As a result, Dominion Energy recorded a reduction to common stock of $1.5 billion.
In December 2020, Dominion Energy entered into a new prepaid accelerated share repurchase agreement with one financial institution as the counterparty. Dominion Energy paid $400 million to the counterparty in exchange for an aggregate of 5.0 million shares of Dominion Energy common stock, which represented all $400 million worth of Dominion Energy shares based on the closing price of such shares on the date the agreement was executed. In December 2020, Dominion Energy received an additional 0.3 million shares upon completion of the purchase period under the terms of the agreement. The number of additional shares was based on the average of the daily volume-weighted average stock prices of Dominion Energy’s common stock during the term of the purchase period, less a discount. As a result, Dominion Energy recorded a reduction to common stock of $400 million.
In addition to the repurchases described above, Dominion Energy also repurchases shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which do not count against its stock repurchase authorization. Dominion Energy did not repurchase any shares in 2019 or 2018 except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock.
Virginia Power
In 2020, 2019, and 2018, Virginia Power did not issue any shares of its common stock to Dominion Energy.
Noncontrolling Interests
GT&S Transaction Closing
In November 2020, as part of the GT&S Transaction, Dominion Energy sold a 25% controlling interest in Cove Point to BHE
resulting in Dominion Energy’s remaining 50% noncontrolling interest accounted for as an equity method investment prospectively. As a result, the $1.4 billion of noncontrolling interest related to the 25% interest in Cove Point held by Brookfield was reversed. See Notes 3 and 9 for further information on the GT&S Transaction and Dominion Energy’s equity method investment in Cove Point.
Sale of Interest in Cove Point
In December 2019, Dominion Energy completed the sale of its 25% noncontrolling limited partnership interest in Cove Point to Brookfield in exchange for cash consideration of $2.1 billion, subject to working capital adjustments. See Note 3 for further information on the sale of this interest.
Remeasurement of Dominion Energy Midstream Units
In May 2018, all of the subordinated units of Dominion Energy Midstream held by Dominion Energy were converted into common units on a 1:1 ratio following the payment of Dominion Energy Midstream’s distribution for the first quarter of 2018. In June 2018, Dominion Energy, as general partner, exercised an incentive distribution right reset as defined in Dominion Energy Midstream’s partnership agreement and received 27 million common units representing limited partner interests in Dominion Energy Midstream. As a result of the increase in its ownership interest in Dominion Energy Midstream, Dominion Energy recorded a decrease in noncontrolling interest, and a corresponding increase in shareholders’ equity, of $375 million reflecting the change in the carrying value of the interest in the net assets of Dominion Energy Midstream held by others.
Accumulated Other Comprehensive Income (Loss)
Presented in the table below is a summary of AOCI by component:
Dominion Energy
The following table presents Dominion Energy’s changes in AOCI by component, net of tax:
(1)
See table below for details about these reclassifications.
The following table presents Dominion Energy’s reclassifications out of AOCI by component:
Virginia Power
The following table presents Virginia Power’s changes in AOCI by component, net of tax:
(1)
See table below for details about these reclassifications.
The following table presents Virginia Power’s reclassifications out of AOCI by component:
Stock-Based Awards
The 2014 Incentive Compensation Plan permits stock-based awards that include restricted stock, performance grants, goal-based stock, stock options and stock appreciation rights. The Non-Employee Directors Compensation Plan permits grants of restricted stock and stock options. Under provisions of these plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are
set at the discretion of the CGN Committee of the Board of Directors or the Board of Directors itself, as provided under each plan. No options are outstanding under either plan. At December 31, 2020, approximately 20 million shares were available for future grants under these plans.
Goal-based stock awards are granted in lieu of cash-based performance grants to certain officers who have not achieved a certain targeted level of share ownership. As of December 31, 2020, unrecognized compensation cost related to nonvested goal-based stock awards was immaterial.
Dominion Energy measures and recognizes compensation expense relating to share-based payment transactions over the vesting period based on the fair value of the equity or liability instruments issued. Dominion Energy’s results for the years ended December 31, 2020, 2019, and 2018 include $64 million, $46 million and $48 million, respectively, of compensation costs and $16 million, $11 million and $12 million, respectively of income tax benefits related to Dominion Energy’s stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion Energy’s Consolidated Statements of Income. Excess Tax Benefits are classified as a financing cash flow.
Restricted Stock
Restricted stock grants are made to officers under Dominion Energy’s LTIP and may also be granted to certain key non-officer employees. The fair value of Dominion Energy’s restricted stock awards is equal to the closing price of Dominion Energy’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2020, 2019, and 2018:
As of December 31, 2020, unrecognized compensation cost related to nonvested restricted stock awards totaled $61 million and is expected to be recognized over a weighted-average period of 2.0 years. The fair value of restricted stock awards that vested was $35 million, $23 million and $23 million in 2020, 2019, and 2018, respectively. Employees may elect to have shares of restricted stock withheld upon vesting to satisfy tax withholding obligations. The number of shares withheld will vary for each employee depending on the vesting date fair market value of Dominion Energy stock and the applicable federal, state and local tax withholding rates.
Cash-Based Performance Grants
Cash-based performance grants are made to Dominion Energy’s officers under Dominion Energy’s LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.
In February 2018, a cash-based performance grant was made to officers. Payout of the performance grant occurred in January 2021 based on the achievement of two performance metrics during 2018, 2019 and 2020: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC with an additional payout based on Dominion Energy’s price-earnings ratio relative to that of the members of Dominion Energy’s peer compensation group. The total of the payout under the grant was $15 million, all of which was accrued at December 31, 2020.
In February 2019, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2022 based on the achievement of two performance metrics during 2019, 2020 and 2021: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC. There are additional opportunities to earn a portion of the award based on Dominion Energy’s absolute TSR or relative price-earnings ratio performance. At December 31, 2020, the targeted amount of the three-year grant was $15 million and a liability of $14 million had been accrued for this award.
In February 2020, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2023 based on the achievement of two performance metrics during 2020, 2021 and 2022: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC. There are additional opportunities to earn a portion of the award based on Dominion Energy’s absolute TSR or relative price-earnings ratio performance. At December 31, 2020, the targeted amount of the three-year grant was $16 million and a liability of $8 million had been accrued for this award.
NOTE 21. DIVIDEND RESTRICTIONS
The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be inconsistent with the public interest. At December 31, 2020, the Virginia Commission had not restricted the payment of dividends by Virginia Power.
The North Carolina Commission, in its order approving the SCANA Combination, limited cumulative dividends payable to Dominion Energy by Virginia Power and PSNC to (i) the amount of retained earnings the day prior to closing of the SCANA Combination plus (ii) any future earnings recorded by Virginia Power and PSNC after such closing. In addition, notice to the North Carolina Commission is required if payment of dividends causes the equity component of Virginia Power and PSNC’s capital structure to fall below 45%.
The Ohio and Utah Commissions may prohibit any public service company, including East Ohio and Questar Gas, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2020, neither the Ohio Commission nor the Utah Commission had restricted the payment of dividends by East Ohio.
There is no specific restriction from the South Carolina Commission on the payment of dividends paid by DESC. Pursuant to the SCANA Merger Approval Order, the amount of any DESC dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry.
At December 31, 2020, DESC’s retained earnings exceed the balance established by the Federal Power Act as a reserve on earnings attributable to hydroelectric generation plants. As a result, DESC is permitted to pay dividends without additional regulatory approval provided that such amounts would not bring the retained earnings balance below the threshold.
See Notes 18 and 19 for a description of potential restrictions on common stock dividend payments by Dominion Energy in connection with the deferral of interest payments on the enhanced junior subordinated notes, the deferral of contract adjustment payments on the 2019 Equity Units or a failure to pay dividends on the Series A Preferred Stock or Series B Preferred Stock.
NOTE 22. EMPLOYEE BENEFIT PLANS
Dominion Energy-Defined Benefit Plans
Dominion Energy provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Under the terms of its benefit plans, Dominion Energy reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.
Dominion Energy maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and the employee’s compensation. Dominion Energy’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension programs also provide benefits to certain retired executives under company-sponsored nonqualified employee benefit plans. The nonqualified plans are funded through contributions to grantor trusts. Dominion Energy also provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service.
Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates, mortality rates and the rate of compensation increases.
Dominion Energy uses December 31 as the measurement date for all of its employee benefit plans. Dominion Energy uses the market-related value of pension plan assets to determine the expected return on plan assets, a component of net periodic pension cost, for all pension plans. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period, which reduces year-to-year volatility. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Since the market-related value recognizes changes in fair value over a four-year period, the future market-related value of pension plan assets will be impacted as previously unrecognized changes in fair value are recognized.
Dominion Energy’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns (losses) of $1.9 billion and $2.1 billion in 2020 and 2019, respectively, versus expected returns of $933 million and $848 million, 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.
In the third quarter of 2020, Dominion Energy remeasured certain pension plans due to a curtailment resulting from entering an agreement to sell substantially all of its gas transmission and storage operations to BHE. The remeasurement resulted in an increase in the pension benefit obligation of $497 million and a decrease in the fair value of the pension plan assets of $87 million. The impact of the remeasurement on net periodic pension benefit cost (credit) was recognized prospectively from the remeasurement date. The remeasurement increased the net periodic benefit credit by approximately $4 million for the year ending December 31, 2020, excluding the impacts of curtailments. The discount rate used for the remeasurement was 3.11% - 3.16% with all other assumptions used for the remeasurement consistent with the measurement as of December 31, 2019.
In the fourth quarter of 2020, Dominion Energy remeasured certain other postretirement benefit plans due to a curtailment and settlement resulting from Dominion Energy completing the GT&S Transaction. The remeasurement resulted in an increase in the accumulated postretirement benefit obligation of $16 million and a decrease in the fair value of the other postretirement benefit plan assets of $25 million. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 3.07% - 3.11%. The initial healthcare cost trend rate used for the remeasurement was 6.25% and decreased to 5.00% by 2025-2026. All other assumptions used for the remeasurement consistent with the measurement as of December 31, 2019.
Voluntary Retirement Program
In March 2019, the Companies announced a voluntary retirement program to employees that meet certain age and service requirements. In 2019, upon the determinations made concerning the number of employees that elected to participate in the program, Dominion Energy recorded a charge of $427 million ($319 million after-tax) included within other operations and maintenance expense ($251 million), other taxes ($21 million), other income ($111 million) and discontinued operations ($44 million) and Virginia Power recorded a charge of $198 million ($146 million after-tax) included within other operations and maintenance expense ($190 million) and other taxes ($8 million) in their respective Consolidated Statements of Income.
In the second quarter of 2019, Dominion Energy remeasured its pension and other postretirement benefit plans as a result of the voluntary retirement program. The remeasurement resulted in an increase in the pension benefit obligation of $484 million and an increase in the fair value of the pension plan assets of $671 million. In addition, the remeasurement resulted in an increase in the accumulated postretirement benefit obligation of $101 million and an increase in the fair value of the other postretirement benefit plan assets of $156 million. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 4.07%-4.10% for the Dominion Energy pension plans and 4.05%-4.08% for the Dominion Energy other postretirement benefit plans. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2018.
In the third quarter of 2019, Dominion Energy remeasured a pension plan as a result of a settlement from the voluntary retirement program at SCANA. The settlement and related remeasurement resulted in an increase in the pension benefit obligation of $37 million and an increase in the fair value of the pension plan assets of $51 million for Dominion Energy. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 3.57%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2018.
Funded Status
The following table summarizes the changes in pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status for Dominion Energy:
(1)
2020 amounts include curtailments and settlements recognized as a result of the GT&S Transaction as well as settlements of qualified and nonqualified pension obligations. 2019 amounts relate primarily to a curtailment and settlement as a result of the voluntary retirement program.
(2)
2020 amounts relate primarily to settlements of qualified and nonqualified pension obligations. 2019 amounts relate primarily to a settlement as a result of the voluntary retirement program.
Actuarial losses recognized during 2020 and 2019 in Dominion Energy’s pension benefit obligations include a $1.0 billion and a $1.1 billion loss, respectively, resulting from decreases in discount rates. Actuarial losses recognized during 2020 in Dominion Energy’s other postretirement benefit obligations include a $149 million loss resulting from a decrease in discount rates, and were partially offset by a $85 million actuarial gain as a result of a completed experience study in one of Dominion Energy’s other postretirement plans and the impact of an update to healthcare claims assumptions. Actuarial losses recognized during 2019 in Dominion Energy’s other postretirement benefit obligations include a $168 million loss resulting from a decrease in discount rates and were partially offset by a $55 million actuarial gain as a result of the impact of an update to healthcare claims and other healthcare-related cost assumptions.
The ABO for all of Dominion Energy’s defined benefit pension plans was $10.6 billion and $9.7 billion at December 31, 2020 and 2019, respectively.
Under its funding policies, Dominion Energy evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, Dominion Energy determines the amount of contributions for the current year, if any, at that time. In December 2020, Dominion Energy contributed $250 million to its qualified defined benefit pension plans. During 2019, Dominion Energy made $520 million of contributions to its qualified defined benefit pension plans, including 6.1 million shares of its common stock valued at $499 million. The shares were contributed through a private placement, exempt from registration requirements, with an independent fiduciary and investment manager to a separate account within the qualified defined benefit pension plans. Dominion Energy also entered into a registration rights agreement with the independent fiduciary and investment manager pursuant to which Dominion Energy agreed to provide
registrations rights on customary terms with respect to the shares. Dominion Energy expects to make $17 million of contributions for its qualified pension plans in 2021.
Certain of Dominion Energy’s subsidiaries fund other postretirement benefit costs through VEBAs. Dominion Energy’s remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion Energy did not make any contributions to VEBAs associated with its other postretirement plans in 2020.
The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets for Dominion Energy:
The following table provides information on the ABO and fair value of plan assets for Dominion Energy’s pension plans with an ABO in excess of plan assets:
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for Dominion Energy’s plans:
Plan Assets
Dominion Energy’s overall objective for investing its pension and other postretirement plan assets is to achieve appropriate long-term rates of return commensurate with prudent levels of risk. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocations for substantially all of Dominion Energy’s pension funds are 28% U.S. equity, 18% non-U.S. equity, 35% fixed income, 3% real estate and 16% other alternative investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies located in the U.S. Non-U.S. equity includes investments in large-cap and small-cap companies located outside of the U.S. including both developed and emerging markets. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Real estate includes equity real estate investment trusts and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.
Dominion Energy also utilizes common/collective trust funds as an investment vehicle for its defined benefit plans. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. Common/collective trust funds are funds of grouped assets that follow various investment strategies.
Strategic investment policies are established for Dominion Energy’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion Energy’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities.
For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 6.
The fair values of Dominion Energy’s pension plan assets by asset category are as follows:
(1)
Includes $365 million and $508 million of Dominion Energy common stock at December 31, 2020 and 2019, respectively.
(2)
These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient are not required to be categorized in the fair value hierarchy.
(3)
Excludes net assets related to pending sales of securities and advanced subscriptions of $198 million, net accrued income of $20 million, and includes net assets related to pending purchases of securities of $71 million at December 31, 2020. Excludes net assets related to pending sales of securities of $52 million, net accrued income of $24 million, and includes net assets related to pending purchases of securities of $99 million at December 31, 2019.
The fair values of Dominion Energy’s other postretirement plan assets by asset category are as follows:
(1)
These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient are not required to be categorized in the fair value hierarchy.
(2)
Excludes net assets related to pending sales of securities of $10 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $2 million at December 31, 2020. Excludes net assets related to pending sales of securities of $2 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $5 million at December 31, 2019.
The plan assets investments are determined based on the fair values of the investments and the underlying investments, which have been determined as follows:
•
Cash and Cash Equivalents-Investments are held primarily in short-term notes and treasury bills, which are valued at cost plus accrued interest.
•
Common and Preferred Stocks-Investments are valued at the closing price reported on the active market on which the individual securities are traded.
•
Insurance Contracts-Investments in Group Annuity Contracts with John Hancock were entered into after 1992 and are stated at fair value based on the fair value of the underlying securities as provided by the managers and include investments in U.S. government securities, corporate debt instruments and state and municipal debt securities.
•
Corporate Debt Instruments-Investments are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar instruments, the instrument is valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks or a broker quote, if available.
•
Government Securities-Investments are valued using pricing models maximizing the use of observable inputs for similar securities.
•
Common/Collective Trust Funds-Common/collective trust funds invest in debt and equity securities and other instruments with characteristics similar to those of the funds’ benchmarks. The primary objectives of the funds are to seek investment returns that approximate the overall performance of their benchmark indexes. These benchmarks are major equity indices, fixed income indices and money market indices that focus on growth, income and liquidity strategies, as applicable. Investments in common/collective trust funds are stated at the NAV as determined by the issuer of the common/collective trust funds and are based on the fair value of the underlying investments held by the fund less its liabilities. The NAV is used as a practical expedient to estimate fair value. The common/collective trust funds do not have any unfunded commitments, and do not have any applicable liquidation periods or defined terms/periods to be held. The
majority of the common/collective trust funds have limited withdrawal or redemption rights during the term of the investment.
•
Alternative Investments-Investments in real estate funds, private equity funds, debt funds and hedge funds are stated at fair value based on the NAV of the plan’s proportionate share of the partnership, joint venture or other alternative investment’s fair value as determined by reference to audited financial statements or NAV statements provided by the investment manager. The NAV, which is used as a practical expedient to estimate fair value, is adjusted for contributions and distributions occurring between the investment manager’s and Dominion Energy’s measurement date. These valuations also involve assumptions and methods that are reviewed, evaluated, and adjusted, if necessary, by Dominion Energy.
Net Periodic Benefit (Credit) Cost
The service cost component of net periodic benefit (credit) cost is reflected in other operations and maintenance expense in Dominion Energy’s Consolidated Statements of Income, except for $13 million, $16 million and $18 million for the years ended December 31, 2020, 2019 and 2018, respectively, presented in discontinued operations. The non-service cost components of net periodic benefit (credit) cost are reflected in other income in Dominion Energy’s Consolidated Statements of Income. The components of the provision for net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities for Dominion Energy plans are as follows:
(1)
Assumptions used to determine net periodic cost for the following year.
The components of AOCI and regulatory assets and liabilities for Dominion Energy’s plans that have not been recognized as components of net periodic benefit (credit) cost are as follows:
(1)
As of December 31, 2020, of the $3.2 billion and $(112) million related to pension benefits and other postretirement benefits, $1.9 billion and $(40) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2019, of the $3.3 billion and $(98) million related to pension benefits and other postretirement benefits, $2.0 billion and $(65) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities.
The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality are critical assumptions in determining net periodic benefit (credit) cost. Dominion Energy develops non-investment related assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions used for Dominion Energy’s pension and other postretirement plans including discount rates, expected long-term rates of return, healthcare cost trend rates and mortality rates.
Dominion Energy determines the expected long-term rates of return on plan assets for its pension plans and other postretirement benefit plans by using a combination of:
•
Expected inflation and risk-free interest rate assumptions;
•
Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes;
•
Expected future risk premiums, asset classes’ volatilities and correlations;
•
Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and
•
Investment allocation of plan assets.
Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans.
Mortality rates are developed from actual and projected plan experience for postretirement benefit plans. Dominion Energy’s actuary conducts an experience study periodically as part of the process to select its best estimate of mortality. Dominion Energy considers both standard mortality tables and improvement factors as well as the plans’ actual experience when selecting a best estimate.
Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion Energy’s retiree healthcare plans. Dominion Energy establishes the healthcare cost trend rate assumption based on analyses of various factors including the specific provisions of its medical plans, actual cost trends experienced and projected and demographics of plan participants.
Virginia Power-Participation in Defined Benefit Plans
Virginia Power employees are covered by the Dominion Energy Pension Plan described above. As a participating employer, Virginia Power is subject to Dominion Energy’s funding policy, which is to contribute annually an amount that is in accordance with ERISA. During 2020, Virginia Power made a payment to Dominion Energy for $313 million related to its participation in the Dominion Energy Pension Plan. In addition, in December 2020, Dominion Energy notified Virginia Power of a required contribution of $151 million, recorded in payables to affiliates in Virginia Power’s Consolidated Balance Sheets at December 31, 2020. Virginia Power’s net periodic pension cost related to this plan was $118 million, $152 million and $126 million in 2020, 2019 and 2018, respectively. Net periodic benefit (credit) cost is reflected in other operations and maintenance expense in Virginia Power’s Consolidated Statements of Income The funded status of various Dominion Energy subsidiary groups and employee compensation are the basis for determining the share of total pension costs for participating Dominion Energy subsidiaries. See Note 25 for Virginia Power amounts due to/from Dominion Energy related to this plan.
Retiree healthcare and life insurance benefits, for Virginia Power employees are covered by the Dominion Energy Retiree Health and Welfare Plan described above. Virginia Power’s net periodic benefit (credit) cost related to this plan was $(58) million, $(27) million and $(51) million in 2020, 2019 and 2018, respectively. Net periodic benefit (credit) cost is reflected in other operations and maintenance expense in Virginia Power’s Consolidated Statements of Income. Employee headcount is the basis for determining the share of total other postretirement benefit costs for participating Dominion Energy subsidiaries. See Note 25 for Virginia Power amounts due to/from Dominion Energy related to this plan.
Dominion Energy holds investments in trusts to fund employee benefit payments for the pension and other postretirement benefit plans in which Virginia Power’s employees participate. Any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that Virginia Power will provide to Dominion Energy for its share of employee benefit plan contributions.
Virginia Power funds other postretirement benefit costs through VEBAs. During 2020 and 2019, Virginia Power made no contributions to the VEBAs and does not expect to contribute to the VEBAs in 2021.
Defined Contribution Plans
Dominion Energy also sponsors defined contribution employee savings plans that cover substantially all employees. During 2020, 2019 and 2018, Dominion Energy recognized $67 million, $69 million and $46 million, respectively, as employer matching contributions to these plans, excluding discontinued operations. Virginia Power also participates in these employee savings plans. During 2020, 2019 and 2018, Virginia Power recognized $19 million, $20 million and $20 million, respectively, as employer matching contributions to these plans.
NOTE 23. COMMITMENTS AND CONTINGENCIES
As a result of issues generated in the ordinary course of business, the Companies are involved in legal proceedings before various courts and are periodically subject to governmental examinations (including by regulatory authorities), inquiries and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations that the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the Companies’ financial position, liquidity or results of operations.
Environmental Matters
The Companies are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.
Air
The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, states are required to establish regulatory programs to address all 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.
MATS
In February 2019, the EPA published a proposed rule to reverse its previous finding that it is appropriate and necessary to regulate hazardous air pollutant emissions from coal- and oil-fired electric generating units. In May 2020, the EPA’s final rule became effective. The final rule is consistent with the EPA’s February 2019 proposal, and determines that it is not appropriate and necessary to regulate mercury and hazardous air pollutant emissions from coal- and oil-fired electric generating units. The final rule also states
that the MATS rule remains in place and the emissions standards for affected coal- and oil-fired electric generating units will not change. The Companies are complying with the applicable requirements of the rule and do not expect any material impacts to their operations.
Ozone Standards
The EPA published final non-attainment designations for the October 2015 ozone standard in June 2018. States have until August 2021 to develop plans to address the new standard. Until the states have developed implementation plans for the standard, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. The expenditures required to implement additional controls could have a material impact on the Companies’ results of operations and cash flows.
Oil and Gas NSPS
In August 2012, the EPA issued an NSPS impacting new and modified facilities in the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of VOC emissions for natural gas production wells, tanks, pneumatic controllers and compressors in the upstream sector. In June 2016, the EPA issued another NSPS regulation for the oil and natural gas sector, to regulate methane and VOC emissions from new and modified facilities in transmission and storage, gathering and boosting, production and processing facilities. All projects which commenced construction after September 2015 are required to comply with this regulation. In October 2018, the EPA published a proposed rule reconsidering and amending portions of the 2016 rule, including but not limited to, the fugitive emissions requirements at well sites and compressor stations. The amended portions of the 2016 rule were effective immediately upon publication. In August 2020, the EPA issued two final amendments related to the reconsideration of the NSPS for the oil and natural gas sector applicable to VOC and methane emissions. Together, the two amendments have the effect of rescinding the methane portion of the NSPS for all segments of the oil and natural gas sector, rescinding all methane and VOC NSPS for the transmission and storage segment and modifying some of the NSPS VOC requirements for facilities in the production and processing segments. The two amendments have been challenged in the U.S. Court of Appeals for the D.C. Circuit but remain in effect pending the outcome of the litigation. Dominion Energy has completed an evaluation of the potential impacts and expects that any impact would be insignificant to its results of operations, financial condition and/or cash flows.
ACE Rule
In July 2019, the EPA published the final rule informally referred to as the ACE Rule, as a replacement for the Clean Power Plan. In January 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE Rule and remanded it to the EPA. This decision will take effect upon issuance of the court’s mandate. The ACE Rule applies to existing coal-fired power plants and would require states to develop plans by July 2022 establishing unit-specific performance standards for existing coal-fired power plants. It is unknown at this time if or how the EPA will replace the ACE Rule and how that replacement will affect the Companies’ operations, financial condition and/or cash flows.
Carbon Regulations
In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and exceed a significant emissions rate of 75,000 tons per year of CO2 equivalent emissions. Until the EPA ultimately takes final action on this rulemaking, the Companies cannot predict the impact to their results of operations, financial condition and/or cash flows.
In December 2018, the EPA proposed revised Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources. The proposed rule would amend the previous determination that the best system of emission reduction for newly constructed coal-fired steam generating units is no longer partial carbon capture and storage. Instead, the proposed revised best system of emission reduction for this source category is the most efficient demonstrated steam cycle (e.g., supercritical steam conditions for large units and subcritical steam conditions for small units) in combination with the best operating practices. In January 2021, the EPA published a final rule affirming that electric generating units are included for the purposes of regulating GHG emissions from new, modified and reconstructed stationary sources. The proposed revision to the performance standards remains pending. Until the EPA ultimately takes final action on this rulemaking, the Companies cannot predict the impact to their results of operations, financial condition and/or cash flows.
State Regulations
In May 2019, VDEQ issued a final rule establishing a state carbon regulation program with a 28.0 million ton initial state-wide carbon cap in 2020. The cap was to be reduced by approximately three percent per year through 2030, resulting in an ultimate cap of 19.6 million tons. The final rule included a provision for VDEQ to delay implementation of the rule pending authorization from the General Assembly and Governor of Virginia. In April 2020, Virginia legislation was enacted authorizing VDEQ to implement the final rule. In June 2020, the VDEQ signed the CO2 Budget Trading Program rule outlining the requirements for Virginia’s direct participation in RGGI starting in 2021. As a result of joining RGGI in 2021, Virginia’s allotment of the regional cap was adjusted to approximately 27.1 million tons, although Virginia Power may purchase additional allowances from the secondary market and other states in the RGGI program. The regulatory framework in Virginia provides rate recovery mechanisms that are expected to substantially mitigate any such impact.
The legislation discussed above is considered related legislation to the VCEA as discussed in Note 13. The VCEA institutes a mandatory renewable portfolio standard, enhances renewable generation and energy storage development, requires the retirement of certain generation facilities, establishes energy efficiency targets, expands net metering and directs Virginia’s participation in a market-based carbon trading program through 2050.
Water
The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. The Companies must comply with applicable aspects of the CWA programs at their operating facilities.
Regulation 316(b)
In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Dominion Energy and Virginia Power currently have 15 and nine facilities, respectively, that are subject to the final regulations. Dominion Energy is also working with the EPA and state regulatory agencies to assess the applicability of Section 316(b) to eight hydroelectric facilities, including three Virginia Power facilities. The Companies anticipate that they may have to install impingement control technologies at certain of these stations that have once-through cooling systems. The Companies are currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and benefit studies. DESC is conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications at certain facilities to ensure compliance with this rule. While the impacts of this rule could be material to the Companies’ results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina and Virginia provide rate recovery mechanisms that could substantially mitigate any such impacts for the regulated electric utilities.
Effluent Limitations Guidelines
In September 2015, the EPA released a final rule to revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category. The final rule established updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. In April 2017, the EPA granted two separate petitions for reconsideration of the Effluent Limitations Guidelines final rule and stayed future compliance dates in the rule. Also in April 2017, the U.S. Court of Appeals for the Fifth Circuit granted the EPA’s request for a stay of the pending consolidated litigation challenging the rule while the EPA addresses the petitions for reconsideration. In September 2017, the EPA signed a rule to postpone the earliest compliance dates for certain waste streams regulations in the Effluent Limitations Guidelines final rule from November 2018 to November 2020; however, the latest date for compliance for these regulations was December 2023. In October 2020, the EPA released the final rule that extends the latest dates for compliance. Individual facilities’ compliance dates will vary based on circumstances and the determination by state regulators and may range from 2021 to 2028. While the impacts of this rule could be material to the Companies’ results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina and Virginia provide rate recovery mechanisms that could substantially mitigate any such impacts for the regulated electric utilities.
Waste Management and Remediation
The operations of the Companies are subject to a variety of state and federal laws and regulations governing the management and disposal of solid and hazardous waste, and release of hazardous substances associated with current and/or historical operations. The CERCLA, as amended, and similar state laws, may impose joint, several and strict liability for cleanup on potentially responsible parties who owned, operated or arranged for disposal at facilities affected by a release of hazardous substances. In addition, many states have created programs to incentivize voluntary remediation of sites where historical releases of hazardous substances are identified and property owners or responsible parties decide to initiate cleanups.
From time to time, the Companies may be identified as a potentially responsible party in connection with the alleged release of hazardous substances or wastes at a site. Under applicable federal and state laws, the Companies could be responsible for costs associated with the investigation or remediation of impacted sites, or subject to contribution claims by other responsible parties for their costs incurred at such sites. The Companies also may identify, evaluate and remediate other potentially impacted sites under voluntary state programs. Remediation costs may be subject to reimbursement under the Companies’ insurance policies, rate recovery mechanisms, or both. Except as described below, the Companies do not believe these matters will have a material effect on results of operations, financial condition and/or cash flows.
Dominion Energy has determined that it is associated with former manufactured gas plant sites, including certain sites associated with Virginia Power. At 12 sites associated with Dominion Energy, including certain sites acquired in the SCANA Combination, remediation work has been substantially completed under federal or state oversight. Where required, the sites are following state-approved groundwater monitoring programs. Dominion Energy has proposed or expects to propose remediation plans associated with three sites, including one at Virginia Power, and expects to conduct remediation activities primarily by the end of 2021. At December 31, 2020 and 2019, Dominion Energy had $42 million and $34 million, respectively, of reserves recorded. Dominion Energy’s reserves include charges of $14 million ($11 million after-tax) and $16 million ($12 million after-tax) recorded in 2020 and 2018, respectively, in other operations and maintenance expense in the Consolidated Statements of Income. At December 31, 2020 and 2019, Virginia Power had $26 million and $16 million, respectively, of reserves recorded. Virginia Power’s reserves include charges of $10 million ($7 million after-tax) and $16 million ($12 million after-tax) recorded in 2020 and 2018, respectively, in other operations and maintenance expense in the Consolidated Statements of Income. In addition, for one site associated with Dominion Energy, an updated work plan submitted to SCDHEC in September 2018, would increase costs by approximately $11 million if approved by federal and state agencies. In September 2020, this plan was submitted to the Army Corps of Engineers. Dominion Energy is associated with 12 additional sites, including two associated with Virginia Power, which are not under investigation by any state or federal environmental agency nor the subject of any current or proposed plans to perform remediation activities. Due to the uncertainty surrounding such sites, the Companies are unable to make an estimate of the potential financial statement impacts.
Other Legal Matters
The Companies are defendants in a number of lawsuits and claims involving unrelated incidents of property damage and personal injury. Due to the uncertainty surrounding these matters, the Companies are unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on results of operations, financial condition and/or cash flows.
SCANA Legal Proceedings
The following describes certain legal proceedings involving Dominion Energy, SCANA or DESC relating to events occurring before closing of the SCANA Combination. Dominion Energy intends to vigorously contest the lawsuits, claims and assessments which have been filed or initiated against SCANA and DESC. No reference to, or disclosure of, any proceeding, item or matter described below shall be construed as an admission or indication that such proceeding, item or matter is material. For certain of these matters, and unless otherwise noted therein, Dominion Energy is unable to estimate a reasonable range of possible loss and the related financial statement impacts, but for any such matter there could be a material impact to its results of operations, financial condition and/or cash flows. For the matters for which Dominion Energy is able to reasonably estimate a probable loss, Dominion Energy’s Consolidated Balance Sheets at December 31, 2020 and 2019 include reserves of $208 million and $696 million, respectively, and insurance receivables of $8 million and $111 million, respectively, included within other receivables. Dominion Energy’s Consolidated Statements of Income for the year ended December 31, 2020 include charges of $90 million ($68 million after-tax) included within impairment of assets and other charges (reflected in the Corporate and Other segment). In addition, Dominion Energy’s Consolidated Statements of Income for the year ended December 31, 2020 include charges of $25 million ($25 million after-tax) included within other income (expense). Dominion Energy’s Consolidated Statements of Income for the year ended December 31, 2019 includes charges of $641 million ($480 million after-tax), included within impairment of assets and other charges (reflected in the Corporate and Other segment).
Ratepayer Class Actions
In May 2018, a consolidated complaint against DESC, SCANA and the State of South Carolina was filed in the State Court of Common Pleas in Hampton County, South Carolina (the DESC Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege, among other things, that DESC was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the NND Project, and that DESC committed unfair trade practices and violated state anti-trust laws. The plaintiffs sought a declaratory judgment that DESC may not charge its customers for any past or continuing costs of the NND Project, sought to have SCANA and DESC’s assets frozen and all monies recovered from Toshiba Corporation and other sources be placed in a constructive trust for the benefit of ratepayers and sought specific performance of the alleged implied contract to construct the NND Project.
In December 2018, the State Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the DESC Ratepayer Case. The settlement agreement, contingent upon the closing of the SCANA Combination, provided that SCANA and DESC would establish an escrow account and proceeds from the escrow account would be distributed to the class members, after payment of certain taxes, attorneys' fees and other expenses and administrative costs. The escrow account would include (1) up to $2.0 billion, net of a credit of up to $2.0 billion in future electric bill relief, which would inure to the benefit of the escrow account in favor of class members over a period of time established by the South Carolina Commission in its order related to matters before the South Carolina Commission related to the NND Project, (2) a cash payment of $115 million and (3) the transfer of certain DESC-owned real estate or sales proceeds from the sale of such properties, which counsel for the DESC Ratepayer Class estimate to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA and DESC funded the cash payment portion of the escrow account. The court held a fairness hearing on the settlement in May 2019. In June 2019, the court entered an order granting final approval of the settlement, which order became effective July 2019. In July 2019, DESC transferred $117 million representing the cash payment, plus accrued interest, to the plaintiffs. Through August 2020, property, plant and equipment with a net recorded value of $27 million had been transferred to the plaintiffs in coordination with the court-appointed real estate trustee to satisfy the settlement agreement. In September 2020, the court entered an order approving a final resolution of the transfer of real estate or sales proceeds with a cash contribution of $38.5 million by DESC and the conveyance of property, plant and equipment with a net recorded value of $3 million. In October 2020, DESC completed the conveyance of property, plant and equipment and funded this cash contribution.
In September 2017, a purported class action was filed by Santee Cooper ratepayers against Santee Cooper, DESC, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the State Court of Common Pleas in Hampton County, South Carolina (the Santee Cooper Ratepayer Case). The allegations are substantially similar to those in the DESC Ratepayer Case. The plaintiffs seek a declaratory judgment that the defendants may not charge the purported class for reimbursement for past or future costs of the NND Project. In March 2018, the plaintiffs filed an amended complaint including as additional named defendants, including certain then current and former directors of Santee Cooper and SCANA. In June 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of South Carolina. In December 2018, Santee Cooper filed its answer to the plaintiffs' fourth amended complaint and filed cross claims against DESC, which was denied. In October 2019, Santee Cooper voluntarily consented to stay its cross claims against DESC pending the outcome of the trial of the underlying case. In November 2019, DESC removed the case to the U.S. District Court for the District of South Carolina. In December 2019, the plaintiffs and Santee Cooper filed a motion to remand the case to state court. In January 2020, the case was remanded to state court. In March 2020, the parties executed a settlement agreement relating to this matter as well as the Luquire Case and the Glibowski Case described below. The settlement agreement provides that Dominion Energy and Santee Cooper will establish a fund for the benefit of class members in the amount of $520 million, of which Dominion Energy’s portion is $320 million of shares of Dominion Energy common stock. Also in March 2020, the court granted preliminary approval for the settlement agreement. In July 2020, the court issued a final approval of the settlement agreement. In September 2020, Dominion Energy issued $322 million of shares of Dominion Energy common stock to satisfy its obligation under the settlement agreement, including interest charges.
In July 2019, a similar purported class action was filed by certain Santee Cooper ratepayers against DESC, SCANA, Dominion Energy and former directors and officers of SCANA in the State Court of Common Pleas in Orangeburg, South Carolina (the Luquire Case). In August 2019, DESC, SCANA and Dominion Energy were voluntarily dismissed from the case. The claims are similar to the Santee Cooper Ratepayer Case. In March 2020, the parties executed a settlement agreement as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Glibowski Case. This case was dismissed as part of the Santee Cooper Ratepayer Case settlement described above.
RICO Class Action
In January 2018, a purported class action was filed, and subsequently amended, against SCANA, DESC and certain former executive officers in the U.S. District Court for the District of South Carolina (the Glibowski Case). The plaintiff alleges, among other things, that SCANA, DESC and the individual defendants participated in an unlawful racketeering enterprise in violation of RICO and conspired to violate RICO by fraudulently inflating utility bills to generate unlawful proceeds. The DESC Ratepayer Class Action
settlement described previously contemplates dismissal of claims by DESC ratepayers in this case against DESC, SCANA and their officers. In August 2019, the individual defendants filed motions to dismiss. In March 2020, the parties executed a settlement agreement as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Luquire Case. This case was dismissed as part of the Santee Cooper Ratepayer Case settlement described above.
SCANA Shareholder Litigation
In September 2017, a purported class action was filed against SCANA and certain former executive officers and directors in the U.S. District Court for the District of South Carolina. Subsequent additional purported class actions were separately filed against all or nearly all of these defendants (collectively the SCANA Securities Class Action). In January 2018, the U.S. District Court for the District of South Carolina consolidated these suits, and the plaintiffs filed a consolidated amended complaint in March 2018. The plaintiffs allege, among other things, that the defendants violated §10(b) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated thereunder, and that the individually named defendants are liable under §20(a) of the same act. In June 2018, the defendants filed motions to dismiss. In March 2019, the U.S. District Court for the District of South Carolina granted in part and denied in part the defendants’ motions to dismiss. In December 2019, the parties executed a settlement agreement pursuant to which SCANA will pay $192.5 million, up to $32.5 million of which can be satisfied through the issuance of shares of Dominion Energy common stock, subject to approval by the U.S. District Court for the District of South Carolina. In February 2020, the U.S. District Court for the District of South Carolina granted preliminary approval of the settlement agreement, pending a fairness hearing. In March 2020, SCANA funded an escrow account with $160 million in cash and the balance of the settlement will be paid upon final approval of the settlement by the court. In July 2020, the court granted final approval of the settlement agreement. In August 2020, SCANA paid the balance of $32.5 million in cash to satisfy the settlement.
In September 2017, a shareholder derivative action was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina. In September 2018, this action was consolidated with another action in the Business Court Pilot Program in Richland County. The plaintiffs allege, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the NND Project, and that the defendants were unjustly enriched by bonuses they were paid in connection with the project. In January 2019, the defendants filed a motion to dismiss the consolidated action. In February 2019, one action was voluntarily dismissed. In March 2020, the court denied the defendants’ motion to dismiss. In April 2020, the defendants filed a notice of appeal with the South Carolina Court of Appeals and a petition with the Supreme Court of South Carolina seeking appellate review of the denial of the motion to dismiss. In June 2020, the plaintiffs filed a motion to dismiss the appeal with the South Carolina Court of Appeals, which was granted in July 2020. In August 2020, the Supreme Court of South Carolina denied the defendants’ petition seeking appellate review. Also in August 2020, the defendants filed a petition for rehearing with the South Carolina Court of Appeals relating to the July 2020 ruling by the court, which was denied in October 2020. In November 2020, SCANA filed a petition of certiorari with the Supreme Court of South Carolina seeking appellate review of the denial of SCANA’s motion to dismiss. This case is pending.
In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors of SCANA in the State Court of Common Pleas in Lexington County, South Carolina (the City of Warren Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In June 2018, the case was remanded back to the State Court of Common Pleas in Lexington County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal was consolidated with a similar appeal in the Metzler Lawsuit discussed below. In June 2019, the U.S. Court of Appeals for the Fourth Circuit reversed the order remanding the case to state court.
In February 2018, a purported class action was filed against Dominion Energy and certain former directors of SCANA and DESC in the State Court of Common Pleas in Richland County, South Carolina (the Metzler Lawsuit). The allegations made and the relief sought by the plaintiffs are substantially similar to that described for the City of Warren Lawsuit. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In August 2018, the case was remanded back to the State Court of Common Pleas in Richland County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal was consolidated with the City of Warren Lawsuit. In June 2019, the U.S. Court of Appeals for the Fourth Circuit reversed the order remanding the case to state court.
In September 2019, the U.S. District Court for the District of South Carolina granted the plaintiffs’ motion to consolidate the City of Warren Lawsuit and the Metzler Lawsuit. In October 2019, the plaintiffs filed an amended complaint against certain former directors and executive officers of SCANA and DESC, which stated substantially similar allegations to those in the City of Warren Lawsuit and the Metzler Lawsuit as well as an inseparable fraud claim. In November 2019, the defendants filed a motion to dismiss. In April 2020, the U.S. District Court for the District of South Carolina denied the motion to dismiss. In May 2020, SCANA filed a motion to
intervene, which was denied in August 2020. In September 2020, SCANA filed a notice of appeal with the U.S. Court of Appeals for the Fourth Circuit. This case is pending.
In May 2019, a case was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina. The plaintiff alleges, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the NND Project, were unjustly enriched by the bonuses they were paid in connection with the project and breached their fiduciary duties to secure and obtain the best price for the sale of SCANA. Also in May 2019, the case was removed to the U.S. District Court of South Carolina by the non-South Carolina defendants. In June 2019, the plaintiffs filed a motion to remand the case to state court. In January 2020, the case was remanded to state court. In February 2020, the defendants filed a motion to dismiss. This case is pending.
Employment Class Actions and Indemnification
In August 2017, a case was filed in the U.S. District Court for the District of South Carolina on behalf of persons who were formerly employed at the NND Project. In July 2018, the court certified this case as a class action. In February 2019, certain of these plaintiffs filed an additional case, which case has been dismissed and the plaintiffs have joined the case filed August 2017. The plaintiffs allege, among other things, that SCANA, DESC, Fluor Corporation and Fluor Enterprises, Inc. violated the Worker Adjustment and Retraining Notification Act in connection with the decision to stop construction at the NND Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment and are seeking damages, which could be as much as $100 million for 100% of the NND Project. In January 2021, the U.S. District Court for the District of South Carolina granted summary judgment in favor of SCANA, DESC, Fluor Corporation and Fluor Enterprises, Inc. In February 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fourth Circuit. This case is pending.
In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against DESC and Santee Cooper. The plaintiffs make claims for indemnification, breach of contract and promissory estoppel arising from, among other things, the defendants' alleged failure and refusal to defend and indemnify the Fluor defendants in the aforementioned case. This case is pending.
FILOT Litigation and Related Matters
In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against DESC in the State Court of Common Pleas in Fairfield County, South Carolina, making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of implied duty of good faith and fair dealing and unfair trade practices related to DESC’s termination of the FILOT agreement between DESC and Fairfield County related to the NND Project. The plaintiff sought a temporary and permanent injunction to prevent DESC from terminating the FILOT agreement. The plaintiff withdrew the motion for temporary injunction in December 2017. This case is pending.
Governmental Proceedings and Investigations
In June 2018, DESC received a notice of proposed assessment of approximately $410 million, excluding interest, from the SCDOR following its audit of DESC’s sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the NND Project, is based on the SCDOR’s position that DESC’s sales and use tax exemption for the NND Project does not apply because the facility will not become operational. In December 2020, the parties reached an agreement in principle in the amount of $165 million to resolve this matter.
In September and October 2017, SCANA was served with subpoenas issued by the U.S. Attorney’s Office for the District of South Carolina and the Staff of the SEC’s Division of Enforcement seeking documents related to the NND Project. In February 2020, the SEC filed a complaint against SCANA, two of its former executive officers and DESC in the U.S. District Court for the District of South Carolina alleging that the defendants violated federal securities laws by making false and misleading statements about the NND Project. In April 2020, SCANA and DESC reached an agreement in principle with the Staff of the SEC’s Division of Enforcement to settle, without admitting or denying the allegations in the complaint. In December 2020, the U.S. District Court for the District of South Carolina issued an order approving the settlement which required SCANA to pay a civil monetary penalty totaling $25 million, and SCANA and DESC to pay disgorgement and prejudgment interest totaling $112.5 million, which disgorgement and prejudgment interest amount were deemed satisfied by the settlements in the SCANA Securities Class Action and the DESC Ratepayer Case. SCANA paid the civil penalty in December 2020. The SEC civil action against two former executive officers of SCANA remains pending and is currently subject to a stay granted by the court in June 2020 at the request of the U.S. Attorney’s Office for the District of South Carolina.
In addition, the South Carolina Law Enforcement Division is conducting a criminal investigation into the handling of the NND Project by SCANA and DESC. Dominion Energy is cooperating fully with the investigations by the U.S. Attorney’s Office and the South
Carolina Law Enforcement Division, including responding to additional subpoenas and document requests. Dominion Energy has also entered into a cooperation agreement with the U.S. Attorney’s Office and the South Carolina Attorney General’s Office. The cooperation agreement provides that in consideration of its full cooperation with these investigations to the satisfaction of both agencies, neither such agency will criminally prosecute or bring any civil action against Dominion Energy or any of its current, previous, or future direct or indirect subsidiaries related to the NND Project. A former executive officer of SCANA entered a plea agreement with the U.S. Attorney’s Office and the South Carolina Attorney General’s Office in June 2020 and entered a guilty plea with the U.S. District Court for the District of South Carolina in July 2020. Another former executive officer of SCANA entered a plea agreement with the U.S. Attorney's Office and the South Carolina Attorney General's Office in November 2020. These matters are pending.
Other Litigation
In December 2018, arbitration proceedings commenced between DESC and Cameco Corporation related to a supply agreement signed in May 2008. This agreement provides the terms and conditions under which DESC agreed to purchase uranium hexafluoride from Cameco Corporation over a period from 2010 to 2020. Cameco Corporation alleges that DESC violated this agreement by failing to purchase the stated quantities of uranium hexafluoride for the 2017 and 2018 delivery years. DESC denies that it is in breach of the agreement and believes that it has reduced its purchase quantity within the terms of the agreement. In January 2021, the parties entered into a mutual release of claims and dismissed the arbitration.
Abandoned NND Project
DESC, for itself and as agent for Santee Cooper, entered into an engineering, construction and procurement contract with Westinghouse and WECTEC in 2008 for the design and construction of the NND Project, of which DESC’s ownership share is 55%. Various difficulties were encountered in connection with the project. The ability of Westinghouse and WECTEC to adhere to established budgets and construction schedules was affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected time frames, the availability of labor and materials at estimated costs and the efficiency of project labor. There were also contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. These matters preceded the filing for bankruptcy protection by Westinghouse and WECTEC in March 2017, and were the subject of comprehensive analyses performed by SCANA and Santee Cooper.
Based on the results of SCANA’s analysis, and in light of Santee Cooper's decision to suspend construction on the NND Project, in July 2017, SCANA determined to stop the construction of the units and to pursue recovery of costs incurred in connection with the construction under the abandonment provisions of the Base Load Review Act or through other means. This decision by SCANA became the focus of numerous legislative, regulatory and legal proceedings. Some of these proceedings remain unresolved and are described above.
In September 2017, DESC, for itself and as agent for Santee Cooper, filed with the U.S. Bankruptcy Court for the Southern District of New York Proofs of Claim for unliquidated damages against each of Westinghouse and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by Westinghouse and WECTEC of the contract, and assert against Westinghouse and WECTEC any and all claims that are based thereon or that may be related thereto.
Westinghouse’s reorganization plan was confirmed by the U.S. Bankruptcy Court for the Southern District of New York and became effective in August 2018. In connection with the effectiveness of the reorganization plan, the contract associated with the NND Project was deemed rejected. DESC is contesting approximately $285 million of filed liens in Fairfield County, South Carolina. Most of these asserted liens are claims that relate to work performed by Westinghouse subcontractors before the Westinghouse bankruptcy, although some of them are claims arising from work performed after the Westinghouse bankruptcy.
Westinghouse has indicated that some unsecured creditors have sought or may seek amounts beyond what Westinghouse allocated when it submitted its reorganization plan to the U.S. Bankruptcy Court for the Southern District of New York. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the bankruptcy reorganization plan allocated by Westinghouse, it is possible that the reorganization plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant.
DESC and Santee Cooper were responsible for amounts owed to Westinghouse for valid work performed by Westinghouse subcontractors on the NND Project after the Westinghouse bankruptcy filing until termination of the interim assessment agreement. In December 2019, DESC and Santee Cooper entered into a confidential settlement agreement with W Wind Down Co LLC resolving claims relating to the interim assessment agreement.
Further, some Westinghouse subcontractors who have made claims against Westinghouse in the bankruptcy proceeding also filed against DESC and Santee Cooper in South Carolina state court for damages. Many of these claimants have also asserted construction liens against the NND Project site. DESC also intends to oppose these claims and liens. With respect to claims of Westinghouse subcontractors, DESC believes there were sufficient amounts previously funded during the interim assessment agreement period to pay such validly asserted claims. With respect to the Westinghouse subcontractor claims which relate to other periods, DESC understands that such claims will be paid pursuant to Westinghouse’s confirmed bankruptcy reorganization plan. DESC further understands that the amounts paid under the plan may satisfy such claims in full. Therefore, DESC believes that the Westinghouse subcontractors may be paid substantially (and potentially in full) by Westinghouse. While Dominion Energy cannot be assured that it will not have any exposure on account of unpaid Westinghouse subcontractor claims, which DESC is presently disputing, Dominion Energy believes it is unlikely that it will be required to make payments on account of such claims.
Nuclear Matters
In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events resulted in significant nuclear safety reviews by the NRC and industry groups such as the Institute of Nuclear Power Operations. Like other U.S. nuclear operators, Dominion Energy has gathered supporting data and participated in industry initiatives focused on the ability to respond to and mitigate the consequences of, design-basis and beyond-design-basis events at its stations.
In July 2011, an NRC task force provided initial recommendations based on its review of the Fukushima Daiichi accident and in October 2011 the NRC staff prioritized these recommendations into Tiers 1, 2 and 3. Tier 1 recommendations consisted of actions which the NRC staff determined should be started without unnecessary delay. Tier 2 and 3 items consisted of items which could not be initiated in the near term because of resource restraints, the need for further technical assessment, or were dependent on activities related to the higher priority Tier 1 issues. In December 2011, the NRC Commissioners approved the agency staff’s prioritization and recommendations, and that same month an appropriations act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as soon as possible.
Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactor licensees, construction permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion Energy requiring implementation of safety enhancements related to mitigation strategies for responding to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation have been implemented. The information requests issued by the NRC requested each reactor licensee to reevaluate the seismic and external flooding hazards at their facility using present-day methods and information, conduct walkdowns of their facility to ensure protection against these hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. The walkdowns of each unit have been completed, audited by the NRC and found to be adequate. Reevaluation of the emergency communications systems and staffing levels was completed as part of the effort to comply with the orders. Reevaluation of the seismic hazards is complete and final with NRC acceptance received for all Dominion Energy facilities. Reevaluation of the external flooding hazards is complete for all Dominion Energy facilities. The NRC approved the external flooding hazards for Surry in May 2020 and Millstone in August 2020. The Companies do not currently expect that compliance with the NRC's information requests will materially impact their financial position, results of operations or cash flows during the implementation period. The NRC staff has resolved the Tier 2 and Tier 3 recommendations and no additional future actions on the part of Dominion Energy are anticipated with respect to these recommendations. Therefore, the Companies do not expect material financial impacts related to compliance with Tier 2 and Tier 3 recommendations.
Nuclear Operations
Nuclear Decommissioning - Minimum Financial Assurance
The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. The 2020 calculation for the NRC minimum financial assurance amount, aggregated for Dominion Energy and Virginia Power’s nuclear units, excluding joint owners’ assurance amounts and Millstone Unit 1 and Kewaunee, as those units are in a decommissioning state, was $2.8 billion and $1.8 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 2020 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2020 U.S. Bureau of Labor Statistics indices. Dominion Energy believes that the amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power also believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and
contributions are required. This reflects a positive long-term outlook for trust fund investment returns as the decommissioning of the units will not be complete for decades. The Companies will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirement, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. See Note 9 for additional information on nuclear decommissioning trust investments.
Nuclear Insurance
The Price-Anderson Amendments Act of 1988 provides the public up to $13.8 billion of liability protection on a per site, per nuclear incident basis, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. During the second quarter of 2020, the total liability protection per nuclear incident available to all participants in the Secondary Financial Protection Program decreased from $13.9 billion to $13.8 billion. This decrease does not impact Dominion Energy’s responsibility per active unit under the Price-Anderson Amendments Act of 1988. The Companies have purchased $450 million of coverage from commercial insurance pools for Millstone, Summer, Surry and North Anna with the remainder provided through the mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $138 million for each of their licensed reactors not to exceed $21 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. The NRC granted an exemption in March 2015 to remove Kewaunee from the Secondary Financial Protection program. This same exemption permitted Dominion Energy to reduce Kewaunee’s required level of liability coverage to $100 million. This reduction was implemented in January 2018, following the removal and storage of the spent nuclear fuel from the spent fuel pool. The current levels of nuclear property insurance coverage for the Companies’ nuclear units are as follows:
(1)
Surry and North Anna share a blanket property limit of $200 million.
The Companies’ nuclear property insurance coverage for Millstone, Summer, Surry and North Anna exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site. In March 2015, the NRC granted an exemption which allowed Kewaunee to reduce its property insurance limit to $50 million. This reduction was implemented in January 2018, following the removal and storage of the spent nuclear fuel from the spent fuel pool. This includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion Energy and Virginia Power's maximum retrospective premium assessment for the current policy period is $99 million and $48 million, respectively. Based on the severity of the incident, the Board of Directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. The Companies have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination. Additionally, DESC maintains an excess property insurance policy with the European Mutual Association for Nuclear Insurance. The policy provides coverage to Summer for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The European Mutual Association for Nuclear Insurance policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, DESC's share of the retrospective premium assessment would not exceed $2 million.
Millstone, Virginia Power and Summer also purchase accidental outage insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program, the Companies are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion Energy and Virginia Power's maximum retrospective premium assessment for the current policy period is $33 million and $9 million, respectively.
ODEC, a part owner of North Anna, Santee Cooper, a part owner of Summer and Massachusetts Municipal and Green Mountain, part owners of Millstone’s Unit 3, are responsible to the Companies for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.
Spent Nuclear Fuel
The Companies entered into contracts with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by the Companies’ contracts with the DOE. The Companies have previously received damages award payments and settlement payments related to these contracts.
By mutual agreement of the parties, the settlement agreements are extendable to provide for resolution of damages incurred after 2013. The settlement agreements for the Surry, North Anna and Millstone nuclear power stations have been extended to provide for periodic payments for damages incurred through December 31, 2022, and additional extensions are contemplated by the settlement agreements. A similar agreement for Summer extends until the DOE has accepted the same amount of spent fuel from the facility as if it has fully performed its contractual obligations. In June 2018, a lawsuit for Kewaunee was filed in the U.S. Court of Federal Claims for recovery of spent nuclear fuel storage costs incurred after 2013. In March 2019, Dominion Energy amended its filing for recovery of spent nuclear fuel storage to include costs incurred for the year ended December 31, 2018. This matter is pending.
In 2020, Virginia Power received payments of $24 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2018 through December 31, 2018. In addition, Dominion Energy received payments of $11 million for resolution of claims incurred at Millstone for the period of July 1, 2018 through June 30, 2019 and $4 million for resolution of its share of claims incurred at Summer for the period of January 1, 2019 through December 31, 2019.
In 2019, Virginia Power received payments of $15 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2017 through December 31, 2017. In addition, Dominion Energy received $11 million for resolution of claims incurred at Millstone for the period of July 1, 2017 through June 30, 2018 and $3 million for resolution of its share of claims incurred at Summer for the period of January 1, 2018 through December 31, 2018.
In 2018, Virginia Power received payments of $16 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2016 through December 31, 2016. In addition, Dominion Energy received payment of $13 million for resolution of claims incurred at Millstone for the period of July 1, 2016 through June 30, 2017.
The Companies continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion Energy’s receivables for spent nuclear fuel-related costs totaled $46 million and $52 million at December 31, 2020 and 2019, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $35 million at both December 31, 2020 and 2019.
The Companies will continue to manage their spent fuel until it is accepted by the DOE.
Long-Term Purchase Agreements
At December 31, 2020, Dominion Energy had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that a third party has used to secure financing for the facility that will provide the contracted goods or services:
(1)
Commitments represent estimated amounts payable for energy under power purchase contracts with qualifying facilities which expire at various dates through 2046. Energy payments are generally based on fixed dollar amounts per month and totaled $52 million and $29 million for the years ended December 31, 2020 and 2019, respectively.
Guarantees, Surety Bonds and Letters of Credit
Upon the closing of the GT&S Transaction, Dominion Energy retained its four guarantees related to Cove Point, an equity method investment, in support of terminal services, transportation and construction. Two of the Cove Point guarantees have a cumulative maximum exposure of $1.9 billion while the other two guarantees have no maximum limit. No amounts related to these guarantees have been recorded. Dominion Energy’s guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under a revolving credit facility is described in Note 9.
Dominion Energy also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion Energy would be obligated to satisfy such obligation. To the extent that a liability subject to a guarantee has been incurred by one of Dominion Energy’s consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion Energy is not required to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once obligations have been paid. Dominion Energy currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.
At December 31, 2020, Dominion Energy had issued the following subsidiary guarantees:
(1)
Guarantees related to commodity commitments of certain subsidiaries. These guarantees were provided to counterparties in order to facilitate physical and financial transaction related commodities and services.
(2)
Guarantees primarily related to certain DGI subsidiaries regarding all aspects of running a nuclear facility.
(3)
Includes guarantees to facilitate the development of solar projects. Also includes guarantees entered into by DGI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects.
(4)
Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations, construction projects and insurance programs. Also includes guarantees entered into by Dominion Energy RNG Holdings, LLC on behalf of a subsidiary to facilitate construction of renewable natural gas facilities. Due to the uncertainty of workers’ compensation claims, the parental guarantee has no stated limit.
(5)
Excludes Dominion Energy’s guarantees for the new corporate office properties and an offshore wind installation vessel discussed in Note 15.
Additionally, at December 31, 2020, Dominion Energy had purchased $157 million of surety bonds, including $88 million at Virginia Power, and authorized the issuance of letters of credit by financial institutions of $100 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.
Indemnifications
As part of commercial contract negotiations in the normal course of business, the Companies may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Companies are unable to develop an estimate of the maximum potential amount of any other future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2020, the Companies believe any other future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position.
Charitable Commitments
In 2020, Dominion Energy made unconditional promises to several charitable organizations, including to support its commitment to diversity and social justice through scholarship programs and donations to historically black colleges and universities. As a result, Dominion Energy recorded charges totaling $80 million in other income in its Consolidated Statements of Income. These commitments are to be funded at various intervals through 2028. Dominion Energy’s Consolidated Balance Sheets include $73 million in other deferred credits and other liabilities at December 31, 2020.
NOTE 24. CREDIT RISK
Dominion Energy
As a diversified energy company, Dominion Energy transacts primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic, Midwest and Rocky Mountain and Southeast regions of the U.S. Dominion Energy does not believe that this geographic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Energy is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations.
Dominion Energy’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion Energy transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include marketing of nonregulated generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of any collateral. At December 31, 2020, Dominion Energy’s credit exposure totaled $107 million. Of this amount, investment grade counterparties, including those internally rated, represented 96%, and no single counterparty, whether investment grade or non-investment grade, exceeded $41 million of exposure.
Virginia Power
Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2020, Virginia Power’s credit exposure totaled $15 million. Of this amount, investment grade counterparties, including those internally rated, represented 97%, and no single counterparty exceeded $6 million of exposure.
Credit-Related Contingent Provisions
Certain of Dominion Energy’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion Energy to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered, as of December 31, 2020 and 2019, Dominion Energy would have been required to post $14 million and $10 million, respectively, of additional collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. Dominion Energy had posted $1 million of collateral at December 31, 2020 related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash and had posted no collateral at December 31, 2019. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of December 31, 2020 and 2019 was $15 million and $10 million, respectively, which does not include the impact of any offsetting asset positions.
If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of December 31, 2020 and 2019, Virginia Power would have been required to post an additional $2 million and $8 million, respectively, of collateral to its counterparties.
See Note 7 for further information about derivative instruments.
NOTE 25. RELATED-PARTY TRANSACTIONS
Virginia Power engages in related party transactions primarily with other Dominion Energy subsidiaries (affiliates). Virginia Power’s receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power is included in Dominion Energy’s consolidated federal income tax return and, where applicable, combined income tax returns for Dominion Energy are filed in various states. See Note 2 for further information. Dominion Energy’s transactions with equity method investments are described in Note 9. A discussion of significant related party transactions follows.
Virginia Power
Transactions with Affiliates
Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of forward commodity purchases, to manage commodity price risks associated with purchases of natural gas. See Notes 7 and 20 for more information. At December 31, 2020, Virginia Power’s derivative assets and liabilities with affiliates were $3 million and $22 million, respectively. At December 31, 2019, Virginia Power’s derivative assets and liabilities with affiliates were $3 million and $53 million, respectively.
Virginia Power participates in certain Dominion Energy benefit plans as described in Note 22. At December 31, 2020 and 2019, Virginia Power’s amounts due to Dominion Energy associated with the Dominion Energy Pension Plan and reflected in noncurrent pension and other postretirement benefit liabilities in the Consolidated Balance Sheets were $436 million and $782 million, respectively. At December 31, 2020 and 2019, Virginia Power’s amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $354 million and $287 million, respectively.
DES and other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage.
The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES to Virginia Power on the basis of direct and allocated methods in accordance with Virginia Power’s services agreements with DES. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.
Presented below are Virginia Power’s significant transactions with DES and other affiliates:
(1)
Includes capitalized expenditures of $141 million, $133 million and $145 million for the year ended December 31, 2020, 2019 and 2018, respectively.
Virginia Power has borrowed funds from Dominion Energy under short-term borrowing arrangements. There were $380 million and $107 million in short-term demand note borrowings from Dominion Energy as of December 31, 2020 and 2019, respectively. The weighted-average interest rate of these borrowings was 0.30% and 3.22% at December 31, 2020 and 2019, respectively. Virginia Power had no outstanding borrowings, net of repayments under the Dominion Energy money pool for its nonregulated subsidiaries as of December 31, 2020 and 2019. Interest charges related to Virginia Power’s borrowings from Dominion Energy were immaterial for the years ended December 31, 2020, 2019 and 2018.
There were no issuances of Virginia Power’s common stock to Dominion Energy in 2020, 2019 or 2018.
NOTE 26. OPERATING SEGMENTS
The Companies are organized primarily on the basis of products and services sold in the U.S. A description of the operations included in the Companies’ primary operating segments is as follows:
(1) Includes Virginia Power’s nonjurisdictional generation operations.
(2) Includes renewable natural gas operations as well as Wexpro’s natural gas development and production operations.
In addition to the operating segments above, the Companies also report a Corporate and Other segment.
Dominion Energy
The Corporate and Other Segment of Dominion Energy includes its corporate, service companies and other functions (including unallocated debt) as well as nonregulated retail energy marketing operations, including Dominion Energy’s noncontrolling interest in Wrangler. In addition, Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources, as well as the net impact of the gas transmission and storage operations held in discontinued operations which are discussed in Note 3.
In 2020, Dominion Energy reported after-tax net expenses of $3.7 billion in the Corporate and Other segment, including $3.4 billion of after-tax net expenses for specific items with $1.2 billion of after-tax net expenses attributable to its operating segments.
The net expenses for specific items attributable to Dominion Energy’s operating segments in 2020 primarily related to the impact of the following items:
•
A $751 million ($564 million after-tax) charge primarily related to the planned early retirement of certain Virginia Power electric generation facilities, attributable to Dominion Energy Virginia;
•
A $405 million ($325 million after-tax) charge associated with certain nonregulated solar generation facilities, attributable to Contracted Assets;
•
A $221 million ($171 million after-tax) charge associated with the sale of Fowler Ridge, attributable to Contracted Assets; and
•
A $130 million ($97 million after-tax) charge for the expected CCRO to be provided to Virginia retail electric customers under the GTSA, attributable to Dominion Energy Virginia;
•
A $127 million ($94 million after-tax) charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020, attributable to Dominion Energy Virginia; and
•
A $117 million ($93 million after-tax) of charges associated with litigation acquired in the SCANA Combination, attributable to Dominion Energy South Carolina; partially offset by
•
A $335 million ($264 million after-tax) net gain related to investments in nuclear decommissioning trust funds attributable to:
•
Dominion Energy Virginia ($27 million after-tax); and
•
Contracted Assets ($237 million after-tax).
In 2019, Dominion Energy reported after-tax net expenses of $1.8 billion in the Corporate and Other segment, including $1.5 billion of after-tax net expenses for specific items with $1.9 billion of after-tax net expenses attributable to its operating segments.
The net expenses for specific items attributable to Dominion Energy’s operating segments in 2019 primarily related to the impact of the following items:
•
A $1.0 billion ($756 million after-tax) charge for refunds of amounts previously collected from retail electric customers of DESC for the NND Project, attributable to Dominion Energy South Carolina;
•
$641 million ($480 million after-tax) of charges associated with litigation acquired in the SCANA Combination, attributable to Dominion Energy South Carolina;
•
$427 million ($320 million after-tax) of charges for merger and integration-related costs associated with the SCANA Combination, including a $394 million ($295 million after-tax) charge related to a voluntary retirement program, attributable to:
•
Dominion Energy Virginia ($151 million after-tax);
•
Gas Distribution ($56 million after-tax);
•
Dominion Energy South Carolina ($75 million after-tax); and
•
Contracted Assets ($38 million after-tax).
•
A $346 million ($257 million after-tax) charge related to the early retirement of certain Virginia Power electric generation facilities, attributable to Dominion Energy Virginia;
•
A $194 million tax charge for $258 million of income tax-related regulatory assets acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery, attributable to Dominion Energy South Carolina;
•
A $160 million ($119 million after-tax) charge related to Virginia Power’s planned early retirement of certain automated meter reading infrastructure, attributable to Dominion Energy Virginia;
•
A $135 million ($100 million after-tax) charge related to Virginia Power’s contract termination with a non-utility generator, attributable to Dominion Energy Virginia;
•
A $114 million ($86 million after-tax) charge for property, plant and equipment acquired in the SCANA Combination primarily for which Dominion Energy committed to forgo recovery, attributable to Dominion Energy South Carolina; partially offset by
•
A $553 million ($411 million after-tax) net gain related to investments in nuclear decommissioning trust funds attributable to:
•
Dominion Energy Virginia ($49 million after-tax); and
•
Contracted Assets ($362 million after-tax); and
•
A $113 million ($84 million after-tax) benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019, attributable to Dominion Energy Virginia.
In 2018, Dominion Energy reported after-tax net income of $117 million in the Corporate and Other segment, including $322 million of after-tax net income for specific items with $196 million of after-tax net expenses attributable to its operating segments.
The net expenses for specific items attributable to Dominion Energy’s operating segments in 2018 primarily related to the impact of the following items:
•
A $215 million ($160 million after-tax) charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers, attributable to Dominion Energy Virginia;
•
A $170 million ($134 million after-tax) net loss related to our investments in nuclear decommissioning trust funds attributable to:
•
Dominion Energy Virginia ($14 million after-tax); and
•
Contracted Assets ($120 million after-tax);
•
An $81 million ($60 million after-tax) charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018 attributable to Dominion Energy Virginia; and
•
A $70 million ($52 million after-tax) charge associated with major storm damage and service restoration attributable to Dominion Energy Virginia; partially offset by
•
A $282 million ($229 million after-tax) benefit associated with the sale of certain nonregulated generation facilities, attributable to Contracted Assets.
The following table presents segment information pertaining to Dominion Energy’s operations:
(1)
Excludes liability to Atlantic Coast Pipeline.
Intersegment sales and transfers for Dominion Energy are based on contractual arrangements and may result in intersegment profit or loss that is eliminated in consolidation, including amounts related to entities presented within discontinued operations.
Virginia Power
The Corporate and Other Segment of Virginia Power primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources.
In 2020, Virginia Power reported after-tax net expenses of $863 million in the Corporate and Other segment, including $915 million of after-tax net expenses for specific items all of which were attributable to its operating segment.
The net expenses for specific items attributable to its operating segment in 2020 primarily related to a $751 million ($559 million after-tax) charge related to the planned early retirement of certain electric generation facilities, a $130 million ($97 million after-tax) charge for the expected CCRO to be provided to Virginia retail electric customers under the GTSA and a $127 million ($94 million after-tax) charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020.
In 2019, Virginia Power reported after-tax net expenses of $634 million in the Corporate and Other segment, including $627 million of after-tax net expenses for specific items all of which were attributable to its operating segment.
The net expenses for specific items attributable to its operating segment in 2019 primarily related to the impact of the following items:
•
A $346 million ($257 million after-tax) charge related to the early retirement of certain electric generation facilities;
•
A $198 million ($146 million after-tax) charge related to a voluntary retirement program;
•
A $160 million ($119 million after-tax) charge related to the planned early retirement of certain automated meter reading infrastructure;
•
A $135 million ($100 million after-tax) charge related to a contract termination with a non-utility generator; and
•
A $62 million ($46 million after-tax) charge related to the abandonment of a project at an electric generating facility, partially offset by
•
A $113 million ($84 million after-tax) benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019.
In 2018, Virginia Power reported after-tax net expenses of $312 million in the Corporate and Other segment, all of which was for specific items attributable to its operating segment.
The net expenses for specific items attributable to its operating segment in 2018 primarily related to the impact of the following items:
•
A $215 million ($160 million after-tax) charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers;
•
An $81 million ($60 million after-tax) charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018; and
•
A $70 million ($52 million after-tax) charge associated with major storm damage and service restoration.
The following table presents segment information pertaining to Virginia Power’s operations:
NOTE 27. QUARTERLY FINANCIAL DATA (UNAUDITED)
A summary of the Companies’ quarterly results of operations for the years ended December 31, 2020 and 2019 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors. In addition, Dominion Energy’s results have been recast reflecting the presentation of operations included in the GT&S Transaction, Q-Pipe Transaction and investment in Atlantic Coast Pipeline as discontinued operations. See Notes 3 and 9 for more information.
Dominion Energy
Dominion Energy’s 2020 results include the impact of the following significant items:
•
Fourth quarter results include a $94 million after-tax charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020.
•
Third quarter results include a $298 million after-tax charge associated with certain nonregulated solar generation facilities, a $170 million after-tax charge associated with the sale of Fowler Ridge and a $149 million after-tax charge for the expected CCRO to be provided to Virginia retail electric customers under the GTSA.
•
Second quarter results include $2.2 billion of after-tax charges presented in discontinued operations associated with the cancellation of the Atlantic Coast Pipeline Project and the related portions of the Supply Header Project.
•
First quarter results include a $566 million after-tax charge primarily related to the planned early retirement of certain Virginia Power electric generation facilities.
Dominion Energy’s 2019 results include the impact of the following significant items:
•
Fourth quarter results include a $244 million after-tax charge related to litigation acquired in the SCANA Combination, offset by a $150 million net gain related to nuclear decommissioning trust funds.
•
Second quarter results include a $283 million after-tax charge related to a voluntary retirement program, a $100 million after-tax charge related to a contract termination with a non-utility generator and a $75 million after-tax charge for litigation acquired in the SCANA Combination.
•
First quarter results include $1.3 billion of after-tax merger and integration-related costs related to the SCANA Combination (inclusive of a $756 million after-tax charge for refunds of amounts previously collected from retail electric customers of DESC for the NND Project, a $277 million after-tax charge for certain regulatory assets and property, plant and equipment acquired in the SCANA Combination for which Dominion Energy committed to forego recovery and $134 million after-tax charge for litigation acquired in the SCANA Combination) and a $409 million after-tax charge for the planned early retirement of certain Virginia Power electric generation facilities and automated metering reading infrastructure, partially offset by $197 million after-tax net gain related to nuclear decommissioning trust funds and an $84 million after-tax revision to future ash ponds and landfill closure costs.
Virginia Power
Virginia Power’s quarterly results of operations were as follows:
Virginia Power’s 2020 results include the impact of the following significant items:
•
Fourth quarter results include a $94 million after-tax charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020.
•
Third quarter results include a $149 million after-tax charge for the expected CCRO to be provided to Virginia retail electric customers under the GTSA.
•
First quarter results include a $561 million after-tax charge primarily related to the planned early retirement of certain Virginia Power electric generation facilities.
Virginia Power’s 2019 results include the impact of the following significant items:
•
Second quarter results include a $144 million after-tax charge related to a voluntary retirement program, a $100 million after-tax charge related to a contract termination with a non-utility generator and a $47 million after-tax charge for the abandonment of a project at an electric generation facility.
•
First quarter results include a $409 million after-tax charge for the planned early retirement of certain electric generation facilities and automated metering reading infrastructure, partially offset by an $84 million after-tax revision to future ash ponds and landfill closure costs.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
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 2020 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, 2020, 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, 2020. 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, 2020.
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.
February 25, 2021
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, 2020, 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, 2020, 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, 2020, of Dominion Energy and our report dated February 25, 2021, 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
February 25, 2021
Virginia Power
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 2020 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, 2020, 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, 2020. 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, 2020.
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.
February 25, 2021
Item 9B. Other Information
None.
Part III
Item 10. Directors, Executive Officers and Corporate Governance
DOMINION ENERGY
The following information for Dominion Energy is incorporated by reference from the Dominion Energy 2021 Proxy Statement, which will be filed on or around March 19, 2021:
•
Information regarding the directors required by this item is found under the heading Item 1 - Election of Directors.
•
Information regarding compliance with Section 16 of the Securities Exchange Act of 1934, as amended, required by this item is found under the heading Other Information-Delinquent Section 16(a) Reports.
•
Information regarding the Dominion Energy Audit Committee Financial expert(s) and the Dominion Energy Audit Committee required by this item is found under the heading Corporate Governance-Board and Committee Governance-The Committees of the Board-Audit Committee.
•
Information regarding Dominion Energy’s Code of Ethics and Business Conduct required by this item is found under the heading Other Information-Code of Ethics and Business Conduct.
The information concerning the executive officers of Dominion Energy required by this item is included in Part I of this Form 10-K under the caption Information about our Executive Officers. Each executive officer of Dominion Energy is elected annually.
Item 11. Executive Compensation
DOMINION ENERGY
The following information about Dominion Energy is contained in the 2021 Proxy Statement and is incorporated by reference:
•
Information regarding executive compensation and the Compensation Committee review and discussions of Compensation Discussion and Analysis contained under the heading Executive Compensation.
•
Information regarding Compensation Committee interlocks contained under the heading Corporate Governance-Compensation Committee Interlocks and Insider Participation.
•
Information regarding director compensation contained under the heading Compensation of Non-Employee Directors.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
DOMINION ENERGY
The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the heading Security Ownership of Certain Beneficial Owners and Management in the 2021 Proxy Statement is incorporated by reference.
The information regarding equity securities of Dominion Energy that are authorized for issuance under its equity compensation plans contained under the heading Executive Compensation-Executive Compensation Tables-Equity Compensation Plans in the 2021 Proxy Statement is incorporated by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
DOMINION ENERGY
The information regarding related party transactions required by this item found under the heading Corporate Governance-Certain Relationships and Related Party Transactions, and information regarding director independence found under the heading Corporate Governance-Director Independence, in the 2021 Proxy Statement is incorporated by reference.
Item 14. Principal Accountant Fees and Services
DOMINION ENERGY
The information concerning principal accountant fees and services contained under the heading Audit-Related Matters-Auditor Fees and Pre-Approval Policy in the 2021 Proxy Statement is incorporated by reference.
VIRGINIA POWER
The following table presents fees paid to Deloitte & Touche LLP for services related to Virginia Power for the fiscal years ended December 31, 2020 and 2019.
Audit fees represent fees of Deloitte & Touche LLP for the audit of Virginia Power’s annual consolidated financial statements, the review of financial statements included in Virginia Power’s quarterly Form 10-Q reports, and the services that an independent auditor would customarily provide in connection with subsidiary audits, statutory requirements, regulatory filings and similar engagements for the fiscal year, such as comfort letters, attest services, consents and assistance with review of documents filed with the SEC.
Audit-related fees consist of assurance and related services that are reasonably related to the performance of the audit or review of Virginia Power’s consolidated financial statements or internal control over financial reporting. This category may include fees related to the performance of audits and attest services not required by statute or regulations, due diligence related to mergers, acquisitions and investments, and accounting consultations about the application of GAAP to proposed transactions.
Virginia Power’s Board of Directors has adopted the Dominion Energy Audit Committee pre-approval policy for their independent auditor’s services and fees and have delegated the execution of this policy to the Dominion Energy Audit Committee. In accordance with this delegation, each year the Dominion Energy Audit Committee pre-approves a schedule that details the services to be provided for the following year and an estimated charge for such services. At its December 2020 meeting, the Dominion Energy Audit Committee approved schedules of services and fees for 2021 inclusive of Virginia Power. In accordance with the pre-approval policy, any changes to the pre-approved schedule may be pre-approved by the Dominion Energy Audit Committee or a delegated member of the Dominion Energy Audit Committee.
Part IV
Item 15. Exhibits and Financial Statement Schedules
(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.
1. Financial Statements
See Index on page 85.
2. All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes.
3. Exhibits (incorporated by reference unless otherwise noted)
Exhibit
Number
Description
Dominion
Energy
Virginia
Power
2.1.a
Purchase and Sale Agreement, dated as of July 3, 2020, by and among Dominion Energy, Inc., Dominion Energy Questar Corporation and Berkshire Hathaway Energy Company (Exhibit 2.1, Form 8-K filed July 6, 2020, File No. 1-8489).
X
2.1.b
Purchase and Sale Agreement, dated as of October 5, 2020, by and among Dominion Energy Questar Corporation, Berkshire Hathaway Energy Corporation and Dominion Energy, Inc., as guarantor (Exhibit 2.1, Form 8-K filed October 6, 2020, File No. 1-8489).
X
2.2
Agreement and Plan of Merger by and among Dominion Energy, Inc., Sedona Corp. and SCANA Corporation, dated as of January 2, 2018 (Exhibit 2.1, Form 8-K filed January 5, 2018, File No. 1-8489).
X
3.1.a
Dominion Energy, Inc. Articles of Incorporation, as restated, effective December 13, 2019 (Exhibit 3.1, Form 8-K filed December 13, 2019, File No.1-8489).
X
3.1.b
Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 2014, File No. 1-2255).
X
3.2.a
Dominion Energy, Inc. Bylaws, as amended and restated, effective July 30, 2020 (Exhibit 3.1, Form 8-K filed July 31, 2020, File No. 1-8489).
X
3.2.b
Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).
X
Dominion Energy, Inc. and Virginia Electric and Power Company agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of any of their total consolidated assets.
X
X
4.1.a
See Exhibit 3.1.a above.
X
4.1.b
See Exhibit 3.1.b above.
X
4.2
Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indenture (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255); Ninety-Second Supplemental Indenture, dated as of July 1, 2012 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2012 filed August 1, 2012, File No. 1-2255).
X
X
Exhibit
Number
Description
Dominion
Energy
Virginia
Power
4.3
Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of Thirteenth Supplemental Indenture, dated as of January 1, 2006 (Exhibit 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Seventeenth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255); Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, File No. 1-2255); Twenty-Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filed August 15, 2013, File No. 1-2255); Twenty-Seventh Supplemental Indenture, dated February 1, 2014 (Exhibit 4.3, Form 8-K filed February 7, 2014, File No. 1-2255); Twenty-Eighth Supplemental Indenture, dated February 1, 2014 (Exhibit 4.4, Form 8-K filed February 7, 2014, File No. 1-2255); Twenty-Ninth Supplemental Indenture, dated May 1, 2015 (Exhibit 4.3, Form 8-K filed May 13, 2015, File No. 1-02255); Thirtieth Supplemental Indenture, dated May 1, 2015 (Exhibit 4.4, Form 8-K filed May 13, 2015, File No. 1-02255); Thirty-First Supplemental Indenture, dated January 1, 2016 (Exhibit 4.3, Form 8-K filed January 14, 2016, File No. 000-55337); Thirty-Second Supplemental Indenture, dated November 1, 2016 (Exhibit 4.3, Form 8-K filed November 16, 2016, File No. 000-55337); Thirty-Third Supplemental Indenture, dated November 1, 2016 (Exhibit 4.4, Form 8-K filed November 16, 2016, File No. 000-55337); Thirty-Fourth Supplemental Indenture, dated March 1, 2017 (Exhibit 4.3, Form 8-K filed March 16, 2017; File No. 000-55337).
X
X
4.4
Senior Indenture, dated as of September 1, 2017, between Virginia Electric and Power Company and U.S. Bank National Association, as Trustee (Exhibit 4.1, Form 8-K filed September 13, 2017, File No.000-55337); First Supplemental Indenture, dated as of September 1, 2017 (Exhibit 4.2, Form 8-K filed September 13, 2017, File No.000-55337); Second Supplemental Indenture, dated as of March 1, 2018 (Exhibit 4.2, Form 8-K filed March 22, 2018, File No. 000-55337); Third Supplemental Indenture, dated as of November 1, 2018 (Exhibit 4.2, Form 8-K filed November 28, 2018, File No. 000-55337); Fourth Supplemental Indenture, dated as of July 1, 2019 (Exhibit 4.2, Form 8-K filed July 10, 2019, File No. 00-55337); Fifth Supplemental Indenture, dated as of December 1, 2019 (Exhibit 4.2, Form 8-K filed December 5, 2019, File No. 000-55337); Sixth Supplemental Indenture, dated as of December 1, 2020 (Exhibit 4.2, Form 8-K filed December 15, 2020, File No. 00-55337).
X
X
4.5
Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by a Form of Second Supplemental Indenture, dated January 1, 2001 (Exhibit 4.6, Form 8-K filed January 12, 2001, File No. 1-8489).
X
Exhibit
Number
Description
Dominion
Energy
Virginia
Power
4.6
Indenture, dated April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2026); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December 12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027).
X
4.7
Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187); Form of Sixteenth Supplemental Indenture, dated December 1, 2002 (Exhibit 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); Form of Twenty-First Supplemental Indenture, dated March 1, 2003 (Exhibits 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-Ninth Supplemental Indenture, dated June 1, 2005 (Exhibit 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirty-Sixth Supplemental Indentures, dated June 1, 2008 (Exhibit 4.3, Form 8-K filed June 16, 2008, File No. 1-8489); Forty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 5, 2011, File No. 1-8489); Forty-Sixth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.4, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Seventh Supplemental Indenture, dated September 1, 2012 (Exhibit 4.5, Form 8-K, filed September 13, 2012, File No. 1-8489); Fifty-First Supplemental Indenture, dated November 1, 2014 (Exhibit 4.5, Form 8-K, filed November 25, 2014, File No. 1-8489).
X
4.8
Indenture, dated as of June 1, 2015, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form 8-K filed June 15, 2015, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2015 (Exhibit 4.2, Form 8-K filed September 24, 2015, File No. 1-8489); Fifth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.3, Form 8-K filed August 9, 2016, File No. 1-8489); Sixth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.4, Form 8-K filed August 9, 2016, File No. 1-8489); Tenth Supplemental Indenture, dated as of January 1, 2017 (Exhibit 4.3, Form 8-K filed January 12, 2017, File No. 1-8489); Eleventh Supplemental Indenture, dated as of March 1, 2017 (Exhibit 4.3, Form 10-Q filed May 4, 2017, File No. 1-8489); Thirteenth Supplemental Indenture, dated December 1, 2017 (Exhibit 4.8, Form 10-K for the fiscal year ended December 31, 2017 filed February 27, 2018, File No. 1-8489); Fifteenth Supplemental Indenture, dated June 1, 2018 (Exhibit 4.2, Form 8-K, filed June 5, 2018, File No. 1-8489); Sixteenth Supplemental Indenture, dated March 1, 2019 (Exhibit 4.2, Form 8-K filed March 13, 2019, File No. 1-8489); Seventeenth Supplemental Indenture, dated as of August 1, 2019 (Exhibit 4.2, Form 10-Q filed November 1, 2019, File No. 1-8489); Eighteenth Supplemental Indenture, dated as of March 1, 2020 (Exhibit 4.2, Form 8-K, filed March 19, 2020, File No. 1-8489); Nineteenth Supplemental Indenture, dated as of March 1, 2020 (Exhibit 4.3, Form 8-K, filed March 19, 2020, File No. 1-8489); Twentieth Supplemental Indenture, dated as of April 1, 2020 (Exhibit 4.2, Form 8-K, filed April 3, 2020, File No. 1-8489); Twenty-First Supplemental Indenture, dated as of September 1, 2020 (Exhibit 4.2, Form 8-K, filed September 17, 2020, File No. 1-8489).
X
Exhibit
Number
Description
Dominion
Energy
Virginia
Power
4.9
Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Third Supplemental and Amending Indenture, dated as of June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489); Sixth Supplemental Indenture, dated as of June 1, 2014 (Exhibit 4.3, Form 8-K filed July 1, 2014, File No. 1-8489); Seventh Supplemental Indenture, dated as of September 1, 2014 (Exhibit 4.3, Form 8-K filed October 3, 2013, File No. 1-8489); Eighth Supplemental Indenture, dated March 7, 2016 (Exhibit 4.4, Form 8-K filed March 7, 2016, File No. 1-8489); Ninth Supplemental Indenture, dated May 26, 2016 (Exhibit 4.4, Form 8-K filed May 26, 2016, File No. 1-8489); Tenth Supplemental Indenture, dated July 1, 2016 (Exhibit 4.3, Form 8-K filed July 19, 2016, File No. 1-8489); Eleventh Supplemental Indenture, dated August 1, 2016 (Exhibit 4.3, Form 8-K filed August 15, 2016, File No. 1-8489); Twelfth Supplemental Indenture, dated August 1, 2016 (Exhibit 4.4, Form 8-K filed August 15, 2016, File No. 1-8489); Thirteenth Supplemental Indenture, dated May 18, 2017 (Exhibit 4.4, Form 8-K filed May 18, 2017, File No. 1-8489); Fourteenth Supplemental Indenture, dated June 27, 2019 (Exhibit 4.5, Form 8-K filed June 27, 2019, File No. 1-8489); Fifteenth Supplemental Indenture, dated June 27, 2019 (Exhibit 4.6, Form 8-K filed June 27, 2019, File No. 1-8489).
X
4.10
2019 Series A Purchase Contract and Pledge Agreement, dated June 14, 2019, among the Dominion Energy, Inc., Deutsche Bank Trust Company Americas, in its capacity as the purchase contract agent, and HSBC Bank USA, National Association, in its capacity as the collateral agent, custodial agent and securities intermediary (Exhibit 3.1, Form 8-K filed June 14, 2019, File No.1-8489).
X
4.11
Registration Rights Agreement, dated December 16, 2019, by and between Dominion Energy, Inc. and Gallagher Fiduciary Advisors, LLC on behalf of the Dominion Energy, Inc. Defined Benefit Master Trust (Exhibit 4.1, Form 8-K filed December 20, 2019, File No. 1-8489).
X
4.12
Description of Dominion Energy, Inc.’s Common Stock (Exhibit 4.16, Form 10-K for the fiscal year ended December 31, 2019 filed February 28, 2020, File No.1-8489).
X
4.13
Description of Dominion Energy, Inc.’s 2016 Series A 5.25% Enhanced Junior Subordinated Notes due 2076 (Exhibit 4.17, Form 10-K for the fiscal year ended December 31, 2019 filed February 28, 2020, File No.1-8489).
X
4.14
Description of Dominion Energy, Inc.’s 2019 Series A Corporate Units (Exhibit 4.18, Form 10-K for the fiscal year ended December 31, 2019 filed February 28, 2020, File No.1-8489).
X
4.15
Description of Virginia Electric and Power Company’s Common Stock (Exhibit 4.19, Form 10-K for the fiscal year ended December 31, 2019 filed February 28, 2020, File No.1-8489).
X
Exhibit
Number
Description
Dominion
Energy
Virginia
Power
10.1
$6,000,000,000 Fourth Amended and Restated Revolving Credit Agreement, dated March 22, 2019, among Dominion Energy, Inc., Virginia Electric and Power Company, Dominion Energy Gas Holdings, LLC, Questar Gas Company, South Carolina Electric & Gas Company, JPMorgan Chase Bank, N.A., as Administrative Agent, Mizuho Bank, Ltd., Bank of America, N.A., The Bank of Nova Scotia and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein (Exhibit 10.1, Form 8-K filed March 26, 2019, File No. 1-8489); as amended by the First Amendment, dated October 30, 2020, to the Fourth Amended and Restated Revolving Credit Agreement (Exhibit 10.1, Form 10-Q for the quarter ended September 30, 2020 filed November 6, 2020, File No. 1-8489).
X
X
10.2
DRS Services Agreement, dated January 1, 2003, between Dominion Resources, Inc. and Dominion Resources Services, Inc. (Exhibit 10.1, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489).
X
10.3
DES Services Agreement, dated January 1, 2021, between Dominion Energy Services, Inc. and Virginia Electric and Power Company (filed herewith).
X
10.4
Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No. 1-8489).
X
X
10.5
Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003 filed May 9, 2003, File No. 1-8489 and File No. 1-2255).
X
X
10.6*
Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc., amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 1-2255), as amended March 31, 2006 (Exhibit 10.1, Form 8-K filed April 4, 2006, File No. 1-8489).
X
10.7*
Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. dated January 24, 2013 (effective for certain officers elected subsequent to February 1, 2013) (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2013 filed February 28, 2014, File No. 1-8489 and File No. 1-2255).
X
10.8*
Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 31, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489).
X
10.9*
Dominion Resources, Inc. New Executive Supplemental Retirement Plan, as amended and restated effective July 1, 2013 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2013 filed August 6, 2013 File No. 1-8489), as amended September 26, 2014 (Exhibit 10.3, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014), as amended effective October 1, 2019 (Exhibit 10.1, Form 8-K filed October 2, 2019, File No. 1-8489), as amended December 11, 2020 (filed herewith).
X
10.10*
Dominion Resources, Inc. New Retirement Benefit Restoration Plan, as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489 and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-2255), as amended September 26, 2014 (Exhibit 10.4, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014).
X
Exhibit
Number
Description
Dominion
Energy
Virginia
Power
10.11*
Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489).
X
10.12*
Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489).
X
10.13*
Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005, as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489).
X
10.14*
Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated May 7, 2014 (Exhibit 10.4, Form 10-Q for the fiscal quarter ended June 30, 2014 filed July 30, 2014, File No. 1-8489 and File No. 1-2250).
X
10.15*
Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell, II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No. 1-8489).
X
X
10.16*
Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255).
X
X
10.17*
Dominion Resources, Inc. 2014 Incentive Compensation Plan, effective May 7, 2014 (Exhibit 10.1, Form 8-K filed May 7, 2014, File No. 1-8489).
X
10.18*
Dominion Energy, Inc. Deferred Compensation Plan, effective July 1, 2021 (filed herewith).
X
10.19*
2019 Performance Grant Plan under the 2019 Long-Term Incentive Program approved January 24, 2019 (Exhibit 10.42, Form 10-K for the fiscal year ended December 31, 2018, filed February 28, 2019, File No. 1-8489).
X
10.20*
2019 Goal-Based Stock Award Agreement under the 2019 Long-Term Incentive Program approved January 24, 2019 (Exhibit 10.43, Form 10-K for the fiscal year ended December 31, 2018, filed February 28, 2019, File No. 1-8489).
X
10.21*
Form of Restricted Stock Award Agreement under the 2019 Long-Term Incentive Program approved January 24, 2019 (Exhibit 10.44, Form 10-K for the fiscal year ended December 31, 2018, filed February 28, 2019, File No. 1-8489).
X
10.22*
2020 Performance Grant Plan under the 2020 Long-Term Incentive Program approved January 23, 2020 (Exhibit 10.33, Form 10-K for the fiscal year ended December 31, 2019 filed February 28, 2020, File No.1-8489).
X
10.23*
2020 Goal-Based Stock Award Agreement under the 2020 Long-Term Incentive Program approved January 23, 2020 (Exhibit 10.34, Form 10-K for the fiscal year ended December 31, 2019 filed February 28, 2020, File No.1-8489).
X
Exhibit
Number
Description
Dominion
Energy
Virginia
Power
10.24*
Form of Restricted Stock Award Agreement under the 2020 Long-Term Incentive Program approved January 23, 2020 (Exhibit 10.35, Form 10-K for the fiscal year ended December 31, 2019 filed February 28, 2020, File No.1-8489).
X
10.25*
Restricted Stock Award Agreement for Diane Leopold (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2020 filed November 6, 2020, File No. 1-8489).
X
10.26*
2021 Performance Grant Plan under the 2021 Long-Term Incentive Program approved January 21, 2021 (filed herewith).
X
10.27*
Form of 2021 Goal-Based Stock Award Agreement under the 2021 Long-Term Incentive Program approved January 21, 2021 (filed herewith).
X
10.28*
Form of Restricted Stock Agreement under the 2021 Long-Term Incentive Program approved January 21, 2021 (filed herewith).
X
10.29*
2021 Restricted Stock Award Agreement for Thomas F. Farrell, II (filed herewith).
X
10.30*
2021 Performance Grant Plan for Thomas F. Farrell, II (filed herewith).
X
Subsidiaries of Dominion Energy, Inc. (filed herewith).
X
Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm for Dominion Energy, Inc. and Virginia Electric and Power Company (filed herewith).
X
X
31.a
Certification by Chief Executive Officer of Dominion Energy, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
X
31.b
Certification by Chief Financial Officer of Dominion Energy, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
X
31.c
Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
X
31.d
Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
X
32.a
Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Energy, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
X
32.b
Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
X
Exhibit
Number
Description
Dominion
Energy
Virginia
Power
The following financial statements from Dominion Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2020, filed on February 25, 2021, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Equity, (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. The following financial statements from Virginia Electric and Power Company’s Annual Report on Form 10-K for the year ended December 31, 2020, filed on February 25, 2021, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income, (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Common Shareholder’s Equity (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements.
X
X
Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101.
X
X
*
Indicates management contract or compensatory plan or arrangement.
Item 16. Form 10-K Summary
None.
Signatures
DOMINION ENERGY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DOMINION ENERGY, INC.
By:
/s/ Robert M. Blue
(Robert M. Blue, President and
Chief Executive Officer)
Date: February 25, 2021
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 25th day of February, 2021.
Signature
Title
/s/ Thomas F. Farrell, II
Thomas F. Farrell, II
Executive Chairman of the Board of Directors
/s/ James A. Bennett
James A. Bennett
Director
/s/ Robert M. Blue
Robert M. Blue
Director, President and Chief Executive Officer
/s/ Helen E. Dragas
Helen E. Dragas
Director
/s/ James O. Ellis, Jr.
James O. Ellis, Jr.
Director
/s/ D. Maybank Hagood
Director
D. Maybank Hagood
/s/ Ronald W. Jibson
Ronald W. Jibson
Director
/s/ Mark J. Kington
Mark J. Kington
Director
/s/ Joseph M. Rigby
Joseph M. Rigby
Director
/s/ Pamela J. Royal
Pamela J. Royal
Director
/s/ Robert H. Spilman, Jr.
Robert H. Spilman, Jr.
Director
/s/ Susan N. Story
Susan N. Story
Director
/s/ Michael E. Szymanczyk
Michael E. Szymanczyk
Director
/s/ James R. Chapman
James R. Chapman
Executive Vice President, Chief Financial Officer and Treasurer
/s/ Michele L. Cardiff
Michele L. Cardiff
Senior Vice President, Controller and Chief Accounting Officer
Virginia Power
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
VIRGINIA ELECTRIC AND POWER COMPANY
By:
/s/ Robert M. Blue
(Robert M. Blue,
Chief Executive Officer)
Date: February 25, 2021
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 25th day of February, 2021.
Signature
Title
/s/ Edward H. Baine
Edward H. Baine
Director
/s/ Robert M. Blue
Robert M. Blue
Director and Chief Executive Officer
/s/ Diane Leopold
Diane Leopold
Director
/s/ James R. Chapman
James R. Chapman
Executive Vice President, Chief Financial Officer and Treasurer
/s/ Michele L. Cardiff
Michele L. Cardiff
Senior Vice President, Controller and Chief Accounting Officer