UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2021

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to

Commission File Number	Exact name of registrants as specified in their charters	I.R.S. Employer Identification Number
001-08489	DOMINION ENERGY, INC.	54-1229715
000-55337	Virginia ELECTRIC AND POWER COMPANY	54-0418825
	Virginia (State or other jurisdiction of incorporation or organization)
	120 TREDEGAR STREET RICHMOND, Virginia (Address of principal executive offices)	23219 (Zip Code)
	(804) 819-2000 (Registrants’ telephone number)

Securities registered pursuant to Section 12(b) of the Act:

Registrant	Trading Symbol	Title of Each Class	Name of Each Exchange on Which Registered
DOMINION ENERGY, INC.	D	Common Stock, no par value	New York Stock Exchange
	DCUE	2019 Series A Corporate Units	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

VIRGINIA ELECTRIC AND POWER COMPANY

Common Stock, no par value

Indicate by check mark whether the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.

Dominion Energy, Inc.    Yes  ☒    No  ☐        Virginia Electric and Power Company    Yes  ☒    No  ☐        

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Dominion Energy, Inc.    Yes  ☐    No  ☒        Virginia Electric and Power Company    Yes  ☐    No  ☒        

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Dominion Energy, Inc.    Yes  ☒    No  ☐    Virginia Electric and Power Company    Yes  ☒    No  ☐    

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Dominion Energy, Inc.    Yes  ☒    No  ☐        Virginia Electric and Power Company    Yes  ☒    No  ☐        

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Dominion Energy, Inc.

Large accelerated filer	☒	Accelerated filer	☐	Emerging growth company	☐
Non-accelerated filer	☐	Smaller reporting company	☐

Virginia Electric and Power Company

Large accelerated filer	☐	Accelerated filer	☐	Emerging growth company	☐
Non-accelerated filer	☒	Smaller reporting company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

Dominion Energy, Inc.    Yes  ☒    No ☐     Virginia Electric and Power Company    Yes ☐     No  ☒    

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act).

Dominion Energy, Inc.    Yes  ☐    No  ☒    Virginia Electric and Power Company    Yes  ☐    No  ☒    

The aggregate market value of Dominion Energy, Inc. common stock held by non-affiliates of Dominion Energy was approximately $59.3 billion based on the closing price of Dominion Energy’s common stock as reported on the New York Stock Exchange as of the last day of Dominion Energy’s most recently completed second fiscal quarter. Dominion Energy is the sole holder of Virginia Electric and Power Company common stock. At February 11, 2022, Dominion Energy had 810,463,489 shares of common stock outstanding and Virginia Power had 274,723 shares of common stock outstanding.

DOCUMENT INCORPORATED BY REFERENCE

Portions of Dominion Energy’s 2022 Proxy Statement are incorporated by reference in Part III.

This combined Form 10-K represents separate filings by Dominion Energy, Inc. and Virginia Electric and Power Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Virginia Electric and Power Company makes no representations as to the information relating to Dominion Energy, Inc.’s other operations.

VIRGINIA ELECTRIC AND POWER COMPANY MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I(1)(a) AND (b) OF FORM 10-K AND IS FILING THIS FORM 10-K UNDER THE REDUCED DISCLOSURE FORMAT.

Dominion Energy, Inc. and Virginia Electric and Power Company

Item Number		Page Number
	Glossary of Terms	3
Part I
1.	Business	10
1A.	Risk Factors	37
1B.	Unresolved Staff Comments	46
2.	Properties	47
3.	Legal Proceedings	52
4.	Mine Safety Disclosures	52
	Information about our Executive Officers	53
Part II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	54
6.	[Reserved]	54
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	55
7A.	Quantitative and Qualitative Disclosures About Market Risk	78
8.	Financial Statements and Supplementary Data	80
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	207
9A.	Controls and Procedures	207
9B.	Other Information	210
9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	210
Part III
10.	Directors, Executive Officers and Corporate Governance	211
11.	Executive Compensation	211
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	211
13.	Certain Relationships and Related Transactions, and Director Independence	211
14.	Principal Accountant Fees and Services	211
Part IV
15.	Exhibits and Financial Statement Schedules	213
16.	Form 10-K Summary	219

2

Glossary of Terms

The following abbreviations or acronyms used in this Form 10-K are defined below:

Abbreviation or Acronym	Definition
2016 Equity Units	Dominion Energy’s 2016 Series A Equity Units issued in August 2016, initially in the form of 2016 Series A Corporate Units, consisting of a stock purchase contract and a 1/40 interest in RSNs issued by Dominion Energy
2017 Tax Reform Act	An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (previously known as The Tax Cuts and Jobs Act) enacted on December 22, 2017
2019 Equity Units	Dominion Energy’s 2019 Series A Equity Units issued in June 2019, initially in the form of 2019 Series A Corporate Units, consisting of a stock purchase contract and a 1/10 interest in a share of the Series A Preferred Stock
2020 BLS Industry Average OSHA Recordable Rate	An average of the OSHA Recordable Rate for 2020 published by the Bureau of Labor Statistics for electric power generation, transmission and distribution (NAICS code 2211) and natural gas distribution (NAICS code 2212)
2021 Triennial Review	Virginia Commission review of Virginia Power’s earned return on base rate generation and distribution services for the four successive 12-month test periods beginning January 1, 2017 and ending December 31, 2020
2022 Proxy Statement	Dominion Energy 2022 Proxy Statement, File No. 001-08489
ABO	Accumulated benefit obligation
ACE Rule	Affordable Clean Energy Rule
AFUDC	Allowance for funds used during construction
Align RNG	Align RNG, LLC, a joint venture between Dominion Energy and Smithfield Foods, Inc.
Altavista	Altavista biomass power station
AMI	Advanced Metering Infrastructure
AOCI	Accumulated other comprehensive income (loss)
ARO	Asset retirement obligation
Atlantic Coast Pipeline	Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion Energy and Duke Energy
Atlantic Coast Pipeline Project	A previously proposed approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina which would have been owned by Dominion Energy and Duke Energy
bcf	Billion cubic feet
bcfe	Billion cubic feet equivalent
Bear Garden	A 622 MW combined-cycle, natural gas-fired power station in Buckingham County, Virginia
BHE	The legal entity, Berkshire Hathaway Energy Company, one or more of its consolidated subsidiaries (including Dominion Energy Gas, Dominion Energy Midstream and Cove Point effective November 1, 2020), or the entirety of Berkshire Hathaway Energy Company and its consolidated subsidiaries
Birdseye	Birdseye Renewable Energy, LLC
Blue Racer	Blue Racer Midstream, LLC, a joint venture between Caiman Energy II, LLC and FR BR Holdings, LLC effective December 2018
BP	BP Wind Energy North America Inc.
Brookfield	Brookfield Super-Core Infrastructure Partners, an infrastructure fund managed by Brookfield Asset Management Inc.
Brunswick County	A 1,376 MW combined-cycle, natural gas-fired power station in Brunswick County, Virginia
CAA	Clean Air Act
CAISO	California ISO
CAO	Chief Accounting Officer
CCR	Coal combustion residual
CCRO	Customer credit reinvestment offset
CEA	Commodity Exchange Act
CEO	Chief Executive Officer
CEP	Capital Expenditure Program, as established by House Bill 95, Ohio legislation enacted in 2011, deployed by East Ohio to recover certain costs associated with capital investment
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund
CFO	Chief Financial Officer
CH4	Methane

3

Abbreviation or Acronym	Definition
Clearway	The legal entity, Clearway Energy, Inc. (a subsidiary of Global Infrastructure Partners), one or more of its consolidated subsidiaries, or the entirety of Clearway Energy, Inc. and its consolidated subsidiaries
CNG	Consolidated Natural Gas Company
CO2	Carbon dioxide
Colonial Trail West	A 142 MW utility-scale solar power station located in Surry County, Virginia
Companies	Dominion Energy and Virginia Power, collectively
Contracted Assets	Contracted Assets operating segment
COO	Chief Operating Officer
Cooling degree days	Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, or 75 degrees Fahrenheit in DESC’s service territory, calculated as the difference between 65 or 75 degrees, as applicable, and the average temperature for that day
Cove Point	Cove Point LNG, LP (formerly known as Dominion Energy Cove Point LNG, LP)
Cove Point LNG Facility	An LNG import/export and storage facility, including the Liquefaction Facility, located on the Chesapeake Bay in Lusby, Maryland
CPCN	Certificate of Public Convenience and Necessity
CVOW Commercial Project	A proposed 2.6 GW wind generation facility 27 miles off the coast of Virginia Beach, Virginia in federal waters adjacent to the CVOW Pilot Project and associated interconnection facilities in and around Virginia Beach, Virginia
CVOW Pilot Project	A 12 MW wind generation facility 27 miles off the coast of Virginia Beach, Virginia in federal waters
CWA	Clean Water Act
DCP	The legal entity, CPMLP Holding Company, LLC (formerly known as Dominion Cove Point, LLC), one or more of its consolidated subsidiaries (including Dominion Energy Midstream), or the entirety of CPMLP Holding Company, LLC and its consolidated subsidiaries
DECGS	Carolina Gas Services, Inc. (formerly known as Dominion Energy Carolina Gas Services, Inc.)
DECP Holdings	The legal entity DECP Holdings, Inc., which holds Dominion Energy’s noncontrolling interest in Cove Point
DEQPS	Dominion Energy Questar Pipeline Services, Inc.
DES	Dominion Energy Services, Inc.
DESC	The legal entity, Dominion Energy South Carolina, Inc., one or more of its consolidated entities or operating segment, or the entirety of Dominion Energy South Carolina, Inc. and its consolidated entities
DETI	Eastern Gas Transmission and Storage, Inc. (formerly known as Dominion Energy Transmission, Inc.)
DGI	Dominion Generation, Inc.
DGP	Eastern Gathering and Processing, Inc. (formerly known as Dominion Gathering and Processing, Inc.)
DMLPHCII	Eastern MLP Holding Company II, LLC (formerly known as Dominion MLP Holding Company II, LLC)
Dodd-Frank Act	The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
DOE	U.S. Department of Energy
Dominion Energy	The legal entity, Dominion Energy, Inc., one or more of its consolidated subsidiaries (other than Virginia Power) or operating segments, or the entirety of Dominion Energy, Inc. and its consolidated subsidiaries
Dominion Energy Direct®	A dividend reinvestment and open enrollment direct stock purchase plan
Dominion Energy Gas	The legal entity, Eastern Energy Gas Holdings, LLC (formerly known as Dominion Energy Gas Holdings, LLC), one or more of its consolidated subsidiaries (consisting of DETI, DCP, DMLPHCII and Dominion Iroquois), or the entirety of Eastern Energy Gas Holdings, LLC and its consolidated subsidiaries
Dominion Energy Gas Restructuring	The acquisition of DCP and DMLPHCII from, and the disposition of East Ohio and DGP to, Dominion Energy by Dominion Energy Gas on November 6, 2019
Dominion Energy Midstream	The legal entity, Northeast Midstream Partners, LP (formerly known as Dominion Energy Midstream Partners, LP), one or more of its consolidated subsidiaries, or the entirety of Northeast Midstream Partners, LP and its consolidated subsidiaries
Dominion Energy Questar	The legal entity, Dominion Energy Questar Corporation, one or more of its consolidated subsidiaries (other than Dominion Energy Gas, effective November 2019), or the entirety of Dominion Energy Questar Corporation and its consolidated subsidiaries

4

Abbreviation or Acronym	Definition
Dominion Energy Questar Pipeline	The legal entity, Dominion Energy Questar Pipeline, LLC, one or more of its consolidated subsidiaries (including its 50% noncontrolling interest in White River Hub), or the entirety of Dominion Energy Questar Pipeline, LLC and its consolidated subsidiaries
Dominion Energy South Carolina	Dominion Energy South Carolina operating segment
Dominion Energy Virginia	Dominion Energy Virginia operating segment
Dominion Iroquois	The legal entity Iroquois Inc. (formerly known as Dominion Iroquois Inc.), one or more of its consolidated subsidiaries, or the entirety of Iroquois, Inc. and its consolidated subsidiaries, which held a 50% noncontrolling interest in Iroquois
Dominion Privatization	Dominion Utility Privatization, LLC, a partnership between Dominion Energy and Patriot
DSM	Demand-side management
DSM Riders	Rate adjustment clauses, designated Riders C1A, C2A, C3A and C4A, associated with the recovery of costs related to certain Virginia DSM programs approved in DSM cases
Dth	Dekatherm
Duke Energy	The legal entity, Duke Energy Corporation, one or more of its consolidated subsidiaries, or the entirety of Duke Energy Corporation and its consolidated subsidiaries
Eagle Solar	Eagle Solar, LLC, a wholly-owned subsidiary of DGI
East Ohio	The East Ohio Gas Company, doing business as Dominion Energy Ohio
Energy Choice	Program authorized by the Ohio Commission which provides energy customers with the ability to shop for energy options from a group of suppliers certified by the Ohio Commission
EnergySolutions	EnergySolutions, LLC
EPA	U.S. Environmental Protection Agency
EPACT	Energy Policy Act of 2005
EPS	Earnings per common share
ERISA	Employee Retirement Income Security Act of 1974
ESA Excess Tax Benefits	Endangered Species Act Benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FILOT	Fee in lieu of taxes
Fitch	Fitch Ratings Ltd.
Four Brothers	Four Brothers Solar, LLC, a limited liability company owned by Dominion Energy (through December 2021) and Four Brothers Holdings, LLC, a subsidiary of Clearway
Fowler Ridge	Fowler I Holdings LLC, a wind-turbine facility in Benton County, Indiana
FTRs	Financial transmission rights
GAAP	U.S. generally accepted accounting principles
Gas Distribution	Gas Distribution operating segment
GENCO	South Carolina Generating Company, Inc.
GHG	Greenhouse gas
Granite Mountain	Granite Mountain Holdings, LLC, a limited liability company owned by Dominion Energy (through December 2021) and Granite Mountain Renewables, LLC, a subsidiary of Clearway
Grassfield Solar	An approximate 20 MW utility-scale solar power station under development in Chesapeake, Virginia
Green Mountain	Green Mountain Power Corporation
Greensville County	A 1,629 MW combined-cycle, natural gas-fired power station in Greensville County, Virginia

5

Abbreviation or Acronym	Definition
GT&S Transaction	The sale by Dominion Energy to BHE of Dominion Energy Gas, DGP, DECGS, Eastern Energy Field Services, Inc. (formerly known as Dominion Energy Field Services, Inc.) and Modular LNG Holdings, Inc. (formerly known as Dominion Modular LNG Holdings, Inc.) (which holds a 50% noncontrolling interest in JAX LNG) pursuant to a purchase and sale agreement entered into on July 3, 2020, which was completed on November 1, 2020
GTSA	Virginia Grid Transformation and Security Act of 2018
GW	Gigawatt
Heating degree days	Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, or 60 degrees Fahrenheit in DESC’s service territory, calculated as the difference between 65 or 60 degrees, as applicable, and the average temperature for that day
Hope	Hope Gas, Inc., doing business as Dominion Energy West Virginia
Hopewell	Polyester biomass power station
Idaho Commission	Idaho Public Utilities Commission
Iron Springs	Iron Springs Holdings, LLC, a limited liability company owned by Dominion Energy (through December 2021) and Iron Springs Renewables, LLC, a subsidiary of Clearway
Iroquois	Iroquois Gas Transmission System, L.P.
IRS	Internal Revenue Service
ISO	Independent system operator
ISO-NE	ISO New England
JAX LNG	JAX LNG, LLC, an LNG supplier in Florida serving the marine and LNG markets
Jones Act	The Coastwise Merchandise Statute (commonly known as the Jones Act) 46 U.S.C. §55102 regulating U.S. maritime commerce
July 2016 hybrids	Dominion Energy’s 2016 Series A Enhanced Junior Subordinated Notes due 2076
June 2006 hybrids	Dominion Energy’s 2006 Series A Enhanced Junior Subordinated Notes due 2066
Kewaunee	Kewaunee nuclear power station
kV	Kilovolt
LIBOR	London Interbank Offered Rate
LIFO	Last-in-first-out inventory method
Liquefaction Facility	A natural gas export/liquefaction facility at the Cove Point LNG Facility
LNG	Liquefied natural gas
LTIP	Long-term incentive program
Massachusetts Municipal	Massachusetts Municipal Wholesale Electric Company
mcfe	Thousand cubic feet equivalent
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MGD	Million gallons per day
Millstone	Millstone nuclear power station
Millstone 2019 power purchase agreements	Power purchase agreements with Eversource Energy and The United Illuminating Company for Millstone to provide nine million MWh per year of electricity for ten years
Moody’s	Moody’s Investors Service
Mtpa	Million metric tons per annum
MW	Megawatt
MWh	Megawatt hour
N2O	Nitrous oxide
Natural Gas Rate Stabilization Act	Legislation effective February 2005 designed to improve and maintain natural gas service infrastructure to meet the needs of customers in South Carolina
NAV	Net asset value
NEIL	Nuclear Electric Insurance Limited
NERC	North American Electric Reliability Corporation
NGL	Natural gas liquid
NND Project	V.C. Summer Units 2 and 3 nuclear development project under which DESC and Santee Cooper undertook to construct two Westinghouse AP1000 Advanced Passive Safety nuclear units in Jenkinsville, South Carolina

6

Abbreviation or Acronym	Definition
Norge Solar	An approximate 20 MW utility-scale solar power station under development in James City County, Virginia
North Anna	North Anna nuclear power station
North Carolina Commission	North Carolina Utilities Commission
NOX	Nitrogen oxide
NRC	U.S. Nuclear Regulatory Commission
NRG	The legal entity, NRG Energy, Inc., one or more of its consolidated subsidiaries (including, effective November 2016 through August 2018, Four Brothers Holdings, LLC, Granite Mountain Renewables, LLC and Iron Springs Renewables, LLC) or operating segments, or the entirety of NRG Energy, Inc. and its consolidated subsidiaries
NWP 12	A nationwide permit from the Army Corps of Engineers authorizing activities required for the construction, maintenance, repair and removal of utility lines, including electric transmission, gas pipelines, water and communications conduit and associate facilities in waters of the U.S.
NYSE	New York Stock Exchange
October 2014 hybrids	Dominion Energy’s 2014 Series A Enhanced Junior Subordinated Notes due 2054
ODEC	Old Dominion Electric Cooperative
Ohio Commission	Public Utilities Commission of Ohio
Order 1000	Order issued by FERC adopting requirements for electric transmission planning, cost allocation and development
OSHA Recordable Rate	Number of recordable cases, as defined by the Occupational Health and Safety Administration, a division of the U.S. Department of Labor, for every 100 employees over the course of a year
Patriot	Patriot Utility Privatizations, LLC, a partnership between Foundation Infrastructure Partners, LLC and John Hancock Life Insurance Company (U.S.A.) and affiliates
PHMSA	Pipeline and Hazardous Materials Safety Administration
PIR	Pipeline Infrastructure Replacement program deployed by East Ohio
PJM	PJM Interconnection, LLC
PREP	Pipeline Replacement and Expansion Program, a program of replacing, upgrading and expanding natural gas utility infrastructure deployed by Hope
PSD	Prevention of significant deterioration
PSNC	Public Service Company of North Carolina, Incorporated, doing business as Dominion Energy North Carolina
Q-Pipe Group	Collectively, Dominion Energy Questar Pipeline, DEQPS and QPC Holding Company, LLC (including its subsidiary Questar Southern Trails Pipeline Company)
Q-Pipe Transaction	A previously proposed sale by Dominion Energy to BHE of the Q-Pipe Group pursuant to a purchase and sale agreement entered into on October 5, 2020 and terminated on July 9, 2021
Questar Gas	Questar Gas Company, doing business as Dominion Energy Utah, Dominion Energy Wyoming and Dominion Energy Idaho
RCC	Replacement Capital Covenant
Regulation Act	Legislation effective July 1, 2007, that amended the Virginia Electric Utility Restructuring Act and fuel factor statute, which legislation is also known as the Virginia Electric Utility Regulation Act, as amended in 2015 and 2018
RGGI	Regional Greenhouse Gas Initiative
RICO	Racketeer Influenced and Corrupt Organizations Act
Rider B	A rate adjustment clause associated with the recovery of costs related to the conversion of three of Virginia Power’s coal-fired power stations to biomass
Rider BW	A rate adjustment clause associated with the recovery of costs related to Brunswick County
Rider CCR	A rate adjustment clause associated with the recovery of costs related to the removal of CCR at certain power stations
Rider CE	A rate adjustment clause associated with the recovery of costs related to certain renewable generation facilities in Virginia
Rider D	A rate mechanism which allows PSNC to recover from customers all prudently incurred gas costs and certain uncollectible expenses as well as losses on negotiated gas and transportation sales
Rider E	A rate adjustment clause associated with the recovery of costs related to certain capital projects at Virginia Power’s electric generating stations to comply with federal and state environmental laws and regulations
Rider GT	A rate adjustment clause associated with the recovery of costs associated with electric distribution grid transformation projects that the Virginia Commission has approved as authorized by the GTSA
Rider GV	A rate adjustment clause associated with the recovery of costs related to Greensville County

7

Abbreviation or Acronym		Definition
Rider R		A rate adjustment clause associated with the recovery of costs related to Bear Garden
Rider OSW		A rate adjustment clause associated with costs incurred to construct, own and operate the CVOW Commercial Project
Rider RGGI		A rate adjustment clause associated with the recovery of costs related to the purchase of allowances through the RGGI market-based trading program for CO2
Rider RPS		A rate adjustment clause associated with the recovery of costs related to the mandatory renewable portfolio standard program established by the VCEA
Rider S	A rate adjustment clause associated with the recovery of costs related to the Virginia City Hybrid Energy Center
Rider SNA	A rate adjustment clause associated with costs relating to the preparation of the applications for subsequent license renewal to the NRC to extend the operating licenses of Surry and North Anna and related projects
Rider T1	A rate adjustment clause to recover the difference between revenues produced from transmission rates included in base rates, and the new total revenue requirement developed annually for the rate years effective September 1
Rider U	A rate adjustment clause associated with the recovery of costs of new underground distribution facilities
Rider US-2	A rate adjustment clause associated with the recovery of costs related to Woodland Solar, Scott Solar and Whitehouse Solar
Rider US-3	A rate adjustment clause associated with the recovery of costs related to Colonial Trail West and Spring Grove 1
Rider US-4	A rate adjustment clause associated with the recovery of costs related to Sadler Solar
Rider W	A rate adjustment clause associated with the recovery of costs related to Warren County
ROE	Return on equity
ROIC	Return on invested capital
RSN	Remarketable subordinated note
RTEP	Regional transmission expansion plan
RTO	Regional transmission organization
Sadler Solar	A 100 MW utility-scale solar power station located in Greensville County, Virginia, also referred to as Dry Bread
SAFSTOR	A method of nuclear decommissioning, as defined by the NRC, in which a nuclear facility is placed and maintained in a condition that allows the facility to be safely stored and subsequently decontaminated to levels that permit release for unrestricted use
SAIDI	System Average Interruption Duration Index, metric used to measure electric service reliability
Santee Cooper	South Carolina Public Service Authority
SBL Holdco	SBL Holdco, LLC, a wholly-owned subsidiary of DGI through December 2021
SCANA	The legal entity, SCANA Corporation, one or more of its consolidated subsidiaries, or the entirety of SCANA Corporation and its consolidated subsidiaries
SCANA Combination	Dominion Energy’s acquisition of SCANA completed on January 1, 2019 pursuant to the terms of the agreement and plan of merger entered on January 2, 2018 between Dominion Energy and SCANA
SCANA Merger Approval Order	Final order issued by the South Carolina Commission on December 21, 2018 setting forth its approval of the SCANA Combination
SCDOR	South Carolina Department of Revenue
Scope 1 emissions	Emissions that are produced directly by an entity’s own operations
Scope 2 emissions	Emissions from electricity a company consumes but does not generate from its own facilities
Scope 3 emissions	Emissions generated downstream of company operations by customers and upstream by suppliers
Scott Solar	A 17 MW utility-scale solar power station in Powhatan County, Virginia
SEC	U.S. Securities and Exchange Commission
SEMI	SCANA Energy Marketing, Inc.
September 2006 hybrids	Dominion Energy’s 2006 Series B Enhanced Junior Subordinated Notes due 2066
SERC	Southeast Electric Reliability Council
Series A Preferred Stock	Dominion Energy’s 1.75% Series A Cumulative Perpetual Convertible Preferred Stock, without par value, with a liquidation preference of $1,000 per share
Series B Preferred Stock	Dominion Energy’s 4.65% Series B Fixed-Rate Cumulative Redeemable Perpetual Preferred Stock, without par value, with a liquidation preference of $1,000 per share
Series C Preferred Stock	Dominion Energy’s 4.35% Series C Fixed-Rate Cumulative Redeemable Perpetual Preferred Stock, without par value, with a liquidation preference of $1,000 per share
SF6	Sulfur hexafluoride
SO2	Sulfur dioxide
South Carolina Commission	Public Service Commission of South Carolina

8

Abbreviation or Acronym	Definition
Southampton	Southampton biomass power station
Southern	The legal entity, The Southern Company, one or more of its consolidated subsidiaries, or the entirety of The Southern Company and its consolidated subsidiaries
Southwest Gas	The legal entity, Southwest Gas Holdings, Inc., one or more of its consolidated subsidiaries, or the entirety of Southwest Gas Holdings, Inc. and its consolidated subsidiaries
Spring Grove 1	A 98 MW utility-scale solar power station located in Surry County, Virginia
Standard & Poor’s	Standard & Poor’s Ratings Services, a division of S&P Global Inc.
Summer	V.C. Summer nuclear power station
Supply Header Project	A project previously intended for DETI to provide approximately 1,500,000 Dths of firm transportation service to various customers in connection with the Atlantic Coast Pipeline Project
Surry	Surry nuclear power station
Sycamore Solar	An approximate 42 MW utility-scale solar power station under development in Pittsylvania County, Virginia
Terra Nova Renewable Partners	The legal entity, Terra Nova Renewable Partners, LLC, a partnership comprised primarily of institutional investors advised by J.P. Morgan Asset Management-Global Real Assets, or one or more of its consolidated subsidiaries
Three Cedars	Granite Mountain and Iron Springs, collectively
TSR	Total shareholder return
UEX Rider	Uncollectible Expense Rider deployed by East Ohio
Ullico	The legal entity, Ullico Inc., one or more of its consolidated subsidiaries, or the entirety of Ullico Inc. and its consolidated subsidiaries
Utah Commission	Utah Public Service Commission
VCEA	Virginia Clean Economy Act of March 2020
VEBA	Voluntary Employees’ Beneficiary Association
VIE	Variable interest entity
Virginia City Hybrid Energy Center	A 610 MW baseload carbon-capture compatible, clean coal powered electric generation facility in Wise County, Virginia
Virginia Commission	Virginia State Corporation Commission
Virginia Facilities	Proposed electric interconnection and transmission facilities in and around Virginia Beach, Virginia, comprising transmission facilities required to interconnect the CVOW Commercial Project reliably with the existing transmission system; including 3 miles of 230 kV offshore export circuits, 4 miles of underground 230 kV onshore export circuits, a new Harpers switching station, 14 miles of three new overhead 230 kV transmission circuits between a new Harpers switching station and the Fentress substation, rebuild eight miles of two existing 230 kV overhead lines and an expansion of the Fentress substation
Virginia Power	The legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segment, or the entirety of Virginia Electric and Power Company and its consolidated subsidiaries
VOC	Volatile organic compounds
Warren County	A 1,349 MW combined-cycle, natural gas-fired power station in Warren County, Virginia
WECTEC	WECTEC Global Project Services, Inc., a wholly-owned subsidiary of Westinghouse
West Virginia Commission	Public Service Commission of West Virginia
Westinghouse	Westinghouse Electric Company LLC
Wexpro	The legal entity, Wexpro Company, one or more of its consolidated subsidiaries, or the entirety of Wexpro Company and its consolidated subsidiaries
Wexpro Agreement	An agreement which sets forth the rights of Questar Gas to receive certain benefits from Wexpro’s operations, including cost-of-service gas
Wexpro II Agreement	An agreement with the states of Utah and Wyoming modeled after the Wexpro Agreement that allows for the addition of properties under the cost-of-service methodology for the benefit of Questar Gas customers
Whitehouse Solar	A 20 MW utility-scale solar power station in Louisa County, Virginia
White River Hub	White River Hub, LLC
Wisconsin Commission	Public Services Commission of Wisconsin
Woodland Solar	A 19 MW utility-scale solar power station in Isle of Wight County, Virginia
WP&L	Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corporation
WPSC	Wisconsin Public Service Corporation, a subsidiary of WEC Energy Group
Wrangler	Wrangler Retail Gas Holdings, LLC, a partnership between Dominion Energy and Interstate Gas Supply, Inc.
Wyoming Commission	Wyoming Public Service Commission

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Part I

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 is committed to safely delivering sustainable, reliable and affordable energy and achieving net zero carbon and methane emissions by 2050. Dominion Energy’s strategy is to be a leading sustainable provider of electricity, natural gas and related services to customers primarily in the eastern and Rocky Mountain regions of the U.S. As of December 31, 2021, Dominion Energy’s portfolio of assets includes approximately 30.2 GW of electric generating capacity, 10,700 miles of electric transmission lines, 78,000 miles of electric distribution lines and 95,700 miles of gas distribution mains and related service facilities, which are supported by 6,000 miles of gas transmission, gathering and storage pipeline. As of December 31, 2021, Dominion Energy operates in 13 states and serves approximately 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 2022 through 2026 includes a focus on upgrading the electric system in Virginia through investments in additional renewable generation facilities, strategic undergrounding and energy conservation programs. Renewable generation facilities are expected to include significant investments in utility-scale solar and offshore wind projects. In addition, Dominion Energy has either received or applied for license extensions for its regulated nuclear power stations in Virginia. Other drivers for the growth capital plan include renewable natural gas initiatives 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 Combination, the completed sale of substantially all of its gas transmission and storage operations 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 SCANA and Virginia Power.

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 is an SEC registrant. However, its Form 10-K is filed separately and is not combined herein.

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

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

WHERE YOU CAN FIND MORE INFORMATION ABOUT THE COMPANIES

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

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

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ACQUISITIONS AND DISPOSITIONS

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

Gas Transmission and Storage Operations

Sales to BHE and Southwest Gas

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

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

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

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

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

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.

Hope

In February 2022, Dominion Energy entered into an agreement to sell 100% of the equity interests in Hope to Ullico for $690 million in cash consideration, subject to customary closing adjustments. This transaction is expected to close by the end of 2022, contingent on clearance or approval under the Hart-Scott-Rodino Act and from the West Virginia Commission, and other customary closing and regulatory conditions. See Note 3 to the Consolidated Financial Statements for additional information.

Electric Generation Facilities

Acquisition of Virginia Power Solar Projects

In 2019 through 2021, Virginia Power entered into and completed the acquisitions of several primarily early-stage solar development projects in Virginia, including both non-jurisdictional facilities and those expected to be recovered under Rider CE.

In 2021, Virginia Power entered into and completed the acquisitions of various solar development projects in Virginia. These projects are expected to cost a total of approximately $1.3 billion once constructed, including initial acquisition costs, and generate approximately 697 MW combined.

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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 $560 million once constructed, including initial acquisition costs, and generate approximately 282 MW combined.  

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 $760 million once constructed, including initial acquisition costs, and generate approximately 448 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 Non-Wholly-Owned Nonregulated Solar Facilities

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

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

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

Equity Method Investments

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. In December 2021, Dominion Energy completed the final contribution consisting of its remaining nonregulated natural gas retail energy marketing operations and receiving $127 million in cash.

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

Expected Acquisition of Interest in Dominion Privatization

In February 2022, Dominion Energy entered into an agreement to form Dominion Privatization, a partnership with Patriot. Dominion Energy expects to contribute its existing privatization operations, excluding contracts held by DESC, in South Carolina, Texas, Pennsylvania and Virginia for cash proceeds totaling $168 million, subject to customary closing adjustments, and a 50% noncontrolling ownership interest in Dominion Privatization following closing of the contributions expected to occur by the end of 2022, contingent on clearance or approval under the Hart-Scott-Rodino Act and other customary closing and regulatory conditions.

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, 2021, Dominion Energy had approximately 17,100 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 2021, Dominion Energy experienced an OSHA Recordable Rate of 0.46 compared to 0.41 in 2020. These rates reflect Dominion Energy’s dedication to safety when compared to a 2020 BLS Industry Average OSHA Recordable Rate of 1.5. As

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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, adapting its approach as the pandemic has evolved. Dominion Energy also facilitated telecommuting and hybrid work options for many employees and expanded paid time off and other benefits to help employees cope with disruptions caused by the pandemic.

Dominion Energy works to recruit, retain and develop the careers of talented individuals who reflect the communities it serves. To cultivate this diversified workforce, Dominion Energy focuses on workforce diversity 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 2021, Dominion Energy increased diverse representation within its workforce from 34.6% to 35.4%. For the purposes of measuring diversity, Dominion Energy includes non-minority female, minority male, minority female and undeclared female. In 2021 and 2020, the percentage of new hires that are diverse was 56% and 50%, 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.

CYBERSECURITY

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

OPERATING SEGMENTS

Dominion Energy manages its daily operations through four primary operating segments: Dominion Energy Virginia, Gas Distribution, Dominion Energy South Carolina and Contracted Assets. See Note 26 to the Consolidated Financial Statements for a summary description of operations within each of the four primary operating segments. Dominion Energy also reports a Corporate and Other segment, which includes its corporate, service companies and other functions (including unallocated debt) as well as Dominion Energy’s noncontrolling interest in 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.

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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 $27 billion from 2022 through 2026 to construct new generation capacity, including the CVOW Commercial Project, to meet its renewable generation targets and growing electricity demand within its service territory in order to maintain reliability and regulatory compliance and to upgrade or add new transmission lines, distribution lines, substations, and other facilities, as well as maintain existing generation capacity. The proposed infrastructure projects and investment commitments are intended to address both continued customer growth and increases in electricity consumption which are primarily driven by new and larger data center customers, as well as support its Subsequent License Renewal projects as it has received approval for or is seeking 20-year license extensions for the regulated nuclear fleet in Virginia. See Properties and Environmental Strategy for additional information on this and other utility projects.

Virginia Power has also created a ten-year plan through 2028 to transform its electric grid into a smarter, stronger and greener grid. This plan 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. The Virginia Commission has approved portions of this plan through 2023.

Revenue provided by electric distribution and generation operations is based primarily on rates established by the Virginia and North Carolina Commissions. Approximately 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 141 minutes for the three-year average ending 2021, down from the previous three-year average of 146 minutes. This decrease is primarily due to decreased storm activity.

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

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

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

Competition

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

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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.

In September 2019, Virginia Power filed applications with PJM for the CVOW Commercial Project and for certain approvals and rider recovery from the Virginia Commission in November 2021. The total cost of the project is estimated to be approximately $10 billion, excluding financing costs. Virginia Power’s estimate for the 2.6 GW project’s projected levelized cost of energy is approximately $80-90/MWh. Following a competitive procurement process, Virginia Power has entered into fixed price contracts for the major offshore construction and equipment components. The contracts include services denominated in currencies other than the U.S. dollar for approximately €2.6 billion and 5.1 billion kr., which have been included within the cost estimate above based on a spot price from the third quarter of 2021. In addition, certain of the fixed price contracts, approximately €0.7 billion, contain commodity indexing provisions linked to steel. As a result, any changes in applicable exchange rates or commodity indices could result in a change to the ultimate cost of the project. Virginia Power is evaluating hedging strategies, subject to approval by the Virginia Commission, to mitigate such risk. In December 2021, Virginia Power filed an application with the Virginia Commission for approval of a lease contract with an affiliated entity for the use of a Jones Act compliant offshore wind installation vessel currently under development. The proposed lease is expected to begin in August 2025 with a total cost of approximately $240 million. Virginia Power has completed the conceptual design phase for the project’s onshore electric transmission facilities and selected a recommended route with consideration given for resiliency and minimizing environmental impacts. Any changes to the onshore route necessitated by the receipt of various permitting approvals could result in upward pressure on the estimated cost of the project. Upon receiving approvals from the Virginia Commission and other permitting entities, Virginia Power anticipates commencing major construction activities in 2023 and the project is expected to be placed in service by the end of 2026. Virginia Power expects to incur approximately 80% of the project costs from 2023 through 2025. Through December 31, 2021, Virginia Power had incurred approximately $290 million of costs.  Virginia Power anticipates funding the project consistent with its approved debt to equity capitalization structure. The project is vital for Virginia Power to meet the renewable energy portfolio standard established in the VCEA and is consistent with the criteria within the VCEA for the construction of an offshore wind facility deemed to be in the public interest as well as the guidelines facilitating cost recovery. See additional discussion of the VCEA provisions concerning renewable generation projects in Note 13 to the Consolidated Financial Statements.

In addition, 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 as well as significant projects under consideration are set forth below:

• Virginia Power plans to invest approximately $6.8 billion from 2022 to 2026 to acquire or construct several solar facilities totaling approximately 3.4 GW of expected generating capacity when placed in service. Virginia Power has projects under various stages of development which, as of December 31, 2021, represent a potential generating capacity of approximately 4.8 GW. The facilities include both those to serve utility and non-jurisdictional customers. See Notes 10 and 13 to the Consolidated Financial Statements for more information.

• To support its development of solar generation facilities serving utility customers, Virginia Power plans to invest approximately $0.6 billion from 2022 to 2026 to acquire or construct multiple battery storage facilities in Virginia, totaling approximately 309 MW of expected storage capacity when placed in service. Virginia Power has projects under various stages of development which, as of December 31, 2021, represent a potential storage capacity of approximately 1.1 GW. See Note 13 to the Consolidated Financial Statements for more information.

• Virginia Power has received a 20-year extension of the operating licenses for its two units at Surry and has commenced the process to extend the operating licenses for its two nuclear units at North Anna. 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.

• Virginia Power is considering the construction of a hydroelectric pumped storage facility in Southwest Virginia.

• Virginia Power is considering the construction of simple cycle combustion turbines in Virginia for reliability purposes.

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 $1.6 billion from 2022 through 2026.

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

Virginia legislation provides for the recovery of costs, subject to approval by the Virginia Commission, for Virginia Power to move approximately 4,000 miles of electric distribution lines underground. The program is designed to reduce restoration outage time by moving Virginia Power’s most outage-prone overhead distribution lines underground, has an annual investment cap of approximately $175 million and is expected to be completed by 2028. The Virginia Commission has approved five phases of the program encompassing approximately 1,672 miles of converted lines and $728 million in capital spending (with $706 million recoverable through Rider U).

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

Investments

In February 2022, Dominion Energy entered into an agreement to form Dominion Privatization, a partnership with Patriot. Dominion Energy expects to contribute its existing privatization operations, excluding contracts held by DESC, in South Carolina, Texas, Pennsylvania and Virginia for cash proceeds totaling $168 million, subject to customary closing adjustments, and a 50% noncontrolling ownership interest in Dominion Privatization following closing of the contributions expected to occur by the end of 2022, contingent on clearance or approval under the Hart-Scott-Rodino Act and other customary closing and regulatory conditions.

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

Sources of Energy Supply

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

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

Source	2021			2020			2019
Natural gas		40	%		48	%		41	%
Nuclear(1)		29			32			29
Purchased power, net		17			7			17
Coal(2)		9			9			8
Renewable and Hydro(3)		5			4			5
Total		100	%		100	%		100	%

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

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

(3) Includes 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.

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

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

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

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

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

Seasonality

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

Nuclear Decommissioning

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

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

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

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

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

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

	NRC license expiration year	Most recent cost estimate (2021 dollars)(1)		Funds in trusts at December 31, 2021(2)
(dollars in millions)
Surry
Unit 1	2052	$	833	$	1,056
Unit 2	2053		824		1,040
North Anna
Unit 1(3)	2038		747		844
Unit 2(3)	2040		751		794
Total		$	3,155	$	3,734

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

(2) Virginia Power did not make any contributions to its nuclear decommissioning trust funds during 2021.

(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 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.

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. Gas Distribution also includes nonregulated renewable natural gas facilities in operation and under development, including Dominion Energy’s investment in Align RNG. See Investments below for additional information regarding the Align RNG investment.

Gas Distribution’s growth capital plan includes spending approximately $5 billion from 2022 through 2026 to upgrade existing or add new infrastructure to meet growing energy needs and retain reliability within its service territory as well as investments in renewable natural gas infrastructure projects. Planned capital spending is driven by infrastructure needs from a growing customer base in states with expanding economies, replacing aging assets for reliability, safety and sustainability and meeting demands for natural gas to support the transition from more carbon intensive fuels.

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, including customer growth.

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, 2021, 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.  

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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 Utah 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. Pursuant to its 2019 Utah base rate case, Questar Gas is permitted to spend up to $70 million over the three years, and up to $174 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.

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 $210 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 project noted below, for the period 2021 to 2023 is expected to be approximately $111 million.

During 2020, construction began on 11 miles of transmission pipeline in Buncombe County, NC. After an analysis was performed under the integrity management program, the new transmission line was deemed necessary to offset the capacity losses on the existing line due to lower pressure being utilized in order to meet federal safety requirements. The project is expected to cost approximately $55 million and had approximately 10 miles placed into service in December 2021 with the remaining portion anticipated to be placed into service in late 2022.

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Non-Utility Renewable Natural Gas—In December 2019, Dominion Energy announced the formation of a strategic alliance with Vanguard Renewables in collaboration with the Dairy Farmers of America to capture methane from dairy farms and convert it into pipeline quality natural gas. In August 2021, Dominion Energy announced an expansion of the partnership, increasing its commitment up to $1 billion. During 2020 and 2021 construction began on seven dairy renewable natural gas facilities located in Colorado, Nevada, Idaho, Georgia and Texas expected to be placed in service in 2022 and 2023 with an estimated total cost of approximately $345 million, excluding financing costs.

Investments

Align RNG—In November 2018, Dominion Energy announced the formation of Align RNG, an equal partnership with Smithfield Foods, Inc.  Align RNG expects to invest $500 million to develop assets to capture methane from swine farms across Virginia, North Carolina, Utah, 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. In 2021, the project produced 39,800 Dths of renewable natural gas. Currently, Align RNG has three additional projects under construction in North Carolina, Arizona and Virginia with an estimated total cost of approximately $150 million. These facilities are expected to be placed in service by the end of 2022.

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

DOMINION ENERGY SOUTH CAROLINA

The Dominion Energy South Carolina Operating Segment is comprised of DESC’s generation, transmission and distribution of electricity to approximately 772,000 customers in the central, southern and southwestern portions of South Carolina and the distribution of natural gas to approximately 419,000 residential, commercial and industrial customers in South Carolina.

DESC’s growth capital plan includes spending approximately $2 billion from 2022 through 2026 to upgrade existing or add new infrastructure to meet growing energy needs within its service territory and maintain reliability.  

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

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

Revenue provided by DESC’s electric generation operations is primarily derived from the sale of electricity generated by its utility generation assets and is based on rates established by the South Carolina Commission. Variability in earnings may arise when revenues are impacted by factors not reflected in current rates, such as the impact of weather, customer demand or the timing and nature of expenses or outages. Electric operations continue to focus on improving service and experience levels while striving to reduce costs and link investments to operational results. SAIDI performance results, excluding major events, were 82 minutes for the three-year average ending 2021, compared to the previous three-year average of 87 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.

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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. As of December 31, 2021, DESC has completed the installation of approximately 550,000 of the planned 1.1 million smart meters. This project is estimated to cost approximately $140 million and be completed in mid-2023.

DESC continues to develop electric transmission projects which commenced in 2020 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, were scheduled to be placed in service in phases through 2022. Approximately 65 miles have been completed through December 2021 with the remaining approximately 23 miles scheduled to be completed by the end of 2022.

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

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Sources of Energy Supply

DESC uses a variety of fuels to power its electric generation fleet and purchases power for utility system load requirements. Presented below is a summary of DESC’s actual system output by energy source:

Source	2021			2020			2019
Natural gas		49	%		47	%		46	%
Coal		20			22			27
Nuclear(1)		20			20			23
Renewable and Hydro(2)		11			11			4
Total		100	%		100	%		100	%

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

(2) Includes solar.

Natural gas— DESC purchases natural gas under contracts with producers and marketers on both a short-term and long-term basis at market-based prices. The gas is delivered to South Carolina through firm transportation agreements with various counterparties, which expire between 2022 and 2084.

Coal— DESC primarily obtains coal through short-term and long-term contracts with suppliers located in eastern Kentucky, Tennessee, Virginia and West Virginia that will expire at various times throughout 2022 and 2023. 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.

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

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

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

	NRC license expiration year	Most recent cost estimate (2021 dollars)(1)		Funds in trusts at December 31, 2021(2)
(dollars in millions)
Summer – Unit 1	2042	$	764	$	256

(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 2021.

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.

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, solar generation facility development operations and Dominion Energy’s 50% noncontrolling interest in Cove Point.

Contracted Assets’ growth capital plan includes spending approximately $3 billion from 2022 through 2026 to expand its renewable generation fleet.

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

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

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Competition

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

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

Regulation

Contracted Assets’ generation fleet is subject to regulation by the NRC, the EPA, the DOE, the 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 invest approximately $2.9 billion from 2022 to 2026 to acquire or construct several solar facilities in the Mid-Atlantic, Southeast and Midwest, including facilities currently under development, totaling approximately 1.6 GW of expected generating capacity when placed in service. Dominion Energy has projects under various stages of development which, as of December 31, 2021, represent a potential generating capacity of approximately 2.4 GW. 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 and, for FERC-regulated operations, changes in rates and demand for services.

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

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

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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. The initial lease term will commence once construction is substantially complete and the vessel is delivered and will mature in November 2027. See Note 15 to the Consolidated Financial Statements for more information.

Sources of Energy Supply

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

Seasonality

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

Nuclear Decommissioning

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

	NRC license expiration year	Most recent cost estimate (2021 dollars)(1)		Funds in trusts at December 31, 2021(2)
(dollars in millions)
Millstone
Unit 1(3)	N/A	$	462	$	803
Unit 2	2035		680		1,096
Unit 3(4)	2045		771		1,089
Kewaunee
Unit 1(5)	N/A		600		972
Total		$	2,513	$	3,960

(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 2021.

(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, 2021, the minority owners held $63 million of trust funds related to Millstone Unit 3 that are not reflected in the table above.

(5) Permanently ceased operations in 2013. See Note 3 for additional information.

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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 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 disposed 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 15% noncontrolling interest in Wrangler, following the sale of a 5% noncontrolling interest in December 2021. Wrangler’s operations, contributed by Dominion Energy in 2019 through 2021, consist of nonregulated natural gas retail energy marketing business serving customers in Ohio, Pennsylvania and Georgia as well as other southeastern states in the U.S.

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

See Notes 3 and 9 to the Consolidated Financial Statements for 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, energy efficiency and demand response programs and renewable energy facilities and programs through stand-alone riders, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission.

In March 2018, the GTSA reinstated base rate reviews on a triennial basis other than the 2021 Triennial Review. In the triennial review proceedings, earnings that are more than 70 basis points above the utility’s authorized ROE that might have been refunded to customers and served as the basis for a reduction in future rates, may be reduced by Virginia Commission-approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects to include as a CCRO. The legislation declares that electric distribution grid transformation projects are in the public interest and

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provides that Virginia Power may seek to recover the costs of such projects through a rider if not the subject of a CCRO. Any costs that are the subject of a CCRO are deemed recovered in base rates during the triennial period under review and may not be included in base rates in future triennial review proceedings. In any triennial review in which the Virginia Commission determines that the utility’s earnings are more than 70 basis points above its authorized ROE, base rates are subject to reduction prospectively and customer refunds would be due unless the total CCRO elected by the utility equals or exceeds the amount of earnings in excess of the 70 basis points. For the purposes of measuring any customer refunds or CCRO amounts utilized under the GTSA, associated income taxes are factored into the determination of such amounts.

In April 2020, the VCEA replaced Virginia’s voluntary renewable energy portfolio standard for Virginia Power with a mandatory program setting annual renewable energy portfolio standard requirements based on the percentage of total electric energy sold by Virginia Power, excluding existing nuclear generation and certain new carbon-free resources, reaching 100% by the end of 2045. The VCEA includes related requirements concerning deployment of wind, solar and energy storage resources, as well as provides for certain measures to increase net-metering, including an allocation for low-income customers, incentivizes energy efficiency programs and 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 also submits annual filings to the South Carolina Commission for rider recovery related to its DSM program and pension costs. The DSM rider includes recovery of any net lost revenues and for a shared savings incentive.

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

See 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.

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Gas Regulation in Utah, Wyoming and Idaho

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

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

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

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

Gas Regulation in Ohio

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

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

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

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

Gas Regulation in 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.

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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.

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

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and, under its market-based rate authority, sells electricity in the PJM wholesale market and to wholesale purchasers in Virginia and North Carolina. Dominion Energy’s nonregulated generators sell electricity in the PJM, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Ohio, Connecticut, California and South Carolina, under Dominion Energy’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. DESC may make wholesale sales at market-based rates outside its balancing authority pursuant to its market-based sales tariff authorized by FERC. In addition, 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.

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

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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 $1.4 million per day, per violation and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.

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

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

In February 2021, DESC and the other members of the 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. In October 2021, the Southeast Energy Exchange Market Agreement became effective by operation of law as a result of a split FERC vote. The members expect the Southeast Energy Exchange Market platform to be operational in the third quarter of 2022.

Nuclear Regulatory Commission

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

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

Cyber Regulations

The Companies plan and operate their facilities in compliance with approved government cyber regulatory requirements. The Companies’ employees participate on various regulatory committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. The Companies anticipate incurring additional compliance expenditures over the next several years because of the implementation of new cybersecurity programs such as the Transportation Security Administration’s gas sector cyber security directives. In addition, NERC continues to develop additional requirements specifically regarding supply chain standards and control centers that impact the bulk electric system. While the

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Companies expect to incur additional compliance costs in connection with NERC, Transportation Security Administration and other governmental agency regulations, such expenses are not expected to significantly affect results of operations.

Safety Regulations

Dominion Energy is also subject to 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, NO_X, 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

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wetlands. The authorizing agency may impose significant direct or indirect mitigation costs to compensate for such impacts to wetlands.

Waste and Chemical Management

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

Protected Species

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

Other Regulations

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

ENVIRONMENTAL STRATEGY

Dominion Energy is committed to a safe, sustainable, reliable and affordable energy future. In February 2020, Dominion Energy set a goal to achieve net zero carbon and methane Scope 1 emissions by 2050. In February 2022, Dominion Energy expanded this commitment to cover Scope 2 emissions and material categories of Scope 3 emissions: electricity purchased to power the grid, fuel for its power stations and gas distribution systems and consumption by natural gas customers. As part of the net zero commitment, Dominion Energy has specifically committed to interim targets to cut Scope 1 carbon emissions from its electric operations by 55% by 2030, relative to 2005 emissions, and cut Scope 1 methane emissions from its natural gas infrastructure operations by 65% by 2030 and by 80% by 2040, in each case relative to 2010 emissions. Dominion Energy’s commitment is highlighted by its anticipated capital investment of approximately $73 billion in projects supporting decarbonization efforts from 2022 to 2035.

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

• Clean energy diversity;

• Innovation and energy infrastructure modernization; and

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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 inclusiveness during its stakeholder engagement on decisions regarding the siting and operation of energy infrastructure and strives to include all people and communities, regardless of race, color, national origin, or income to ensure a diversity of views are considered in its public engagement process.

Transparency

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

Clean Energy Diversity

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

Over the past two decades, Dominion Energy has changed the fuel mix it uses to generate electricity, as well as improved the systems that make up its natural gas operations, to achieve a cleaner future. In addition to reducing GHG emissions, Dominion Energy’s environmental strategy has also resulted in measurable reductions of other air pollutants such as NO_X, 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 expects to invest up to $21 billion from 2022 through 2035 in solar generation to achieve its target of 13.4 GW generating capacity in-service by the end of 2035.  As of December 31, 2021, Dominion Energy had 2.0 GW of solar generation capacity in operation across five states. In addition, Dominion Energy has projects in seven states under various stages of development which, as of December 31, 2021, represent a potential generating capacity of approximately 7.2 GW. In addition, Dominion Energy expects to invest up to $21 billion from 2022 through 2035 in offshore wind generation facilities. Dominion Energy has commenced development of the CVOW Commercial Project, expected to be placed in service by the end of 2026, along with the CVOW Pilot Project which achieved commercial operation in January 2021. To support these renewable generation facilities, Dominion Energy expects to invest up to $4 billion in energy storage facilities from 2022 through 2035. Virginia Power has projects under various stages development which, as of December 31, 2021, represent a potential storage capacity of approximately 1.1 GW.

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

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

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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 2022 through 2026 includes a focus on upgrading the electric system in Virginia through investments in additional renewable generation facilities, smart meters, customer information platform, intelligent grid devices and associated control systems, physical and cyber security investments, strategic undergrounding and energy conservation programs. Dominion Energy also plans to upgrade its gas and electric transmission and distribution networks and meet environmental requirements and standards set by various regulatory bodies. These enhancements are aimed at meeting Dominion Energy’s continued goal of providing safe, reliable service while addressing increasing electricity consumption, making Dominion Energy’s system more responsive to its customers’ desire to more efficiently manage their energy consumption and transforming its grid to be more adaptive to renewable generation resources and battery technologies.

Dominion Energy has also implemented infrastructure improvements and improved operational practices to reduce the GHG emissions for its natural gas facilities. Dominion Energy is also pursuing the construction or upgrade of regulated infrastructure in its natural gas businesses. Dominion Energy has made voluntary commitments as part of the EPA’s Natural Gas STAR Methane Challenge Program to continue to reduce methane emissions as part of these improvements. Dominion Energy is also a member of the EPA’s voluntary Natural Gas STAR Program, which the entities acquired in the SCANA Combination are expected to join in 2022. In addition, Dominion Energy is a member of the One Future Coalition, an industry group with members pledging to limit methane emissions to below 1% of gas throughput across the entire natural gas value chain.

See Operating Segments for additional information.

Conservation and Energy Efficiency

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

• Energy audits and assessments;

• Incentives for customers to upgrade or install certain energy efficient measures and/or systems;

• Weatherization assistance to help income-eligible customers reduce their energy usage;

• Home energy planning, which provides homeowners with a step-by-step roadmap to efficiency improvements to reduce gas usage; and

• Rebates for installing high-efficiency equipment and qualified electric vehicle chargers.

GHG Emissions

Dominion Energy continues to make progress on achieving its net zero emissions commitment. Through 2020, Dominion Energy has reduced direct Scope 1 CO₂ equivalent carbon and methane emissions from its electric generation and natural gas operations by 42%. Through 2020, Dominion Energy has reduced carbon emissions from its electric generating units by 43% since 2005 and reduced methane emissions from its natural gas infrastructure operations by 32% since 2010. For the purposes of these calculations, Dominion Energy’s baseline data includes pro forma adjustments to include the operations acquired in the SCANA Combination as well as Questar Gas and Wexpro. In addition, both the baseline and 2020 emissions data excludes the operations sold as part of the GT&S Transaction and of the Q-Pipe Group.

Dominion Energy’s 2021 emissions data is not yet available.

Corporate GHG Inventory

Dominion Energy maintains a comprehensive Corporate GHG Inventory, which follows methodologies specified in the EPA’s Mandatory GHG Reporting Rule, 40 Code of Federal Regulations Part 98 for calculating emissions, as well as approved industry protocols. In its annual Corporate GHG Inventory, Dominion Energy voluntarily includes carbon and methane emission estimates

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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. Dominion Energy includes emissions data in its Corporate GHG Inventory based on its ownership percentage of the associated assets and for the period in which the operations are owned by Dominion Energy.

Total CO₂ equivalent emissions reported under Dominion Energy’s Corporate GHG Inventory were 37.4 million metric tons in 2020. 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. Dominion Energy’s 2020 emissions data reported under its Corporate GHG Inventory includes the results of the operations included in the GT&S Transaction through November 2020 as well as the entire year of the operations included in the Q-Pipe Group.

• For Dominion Energy’s electric generation operations, total CO₂ equivalent emissions were 33.2 million metric tons in 2020, including 8.6 million metric tons from DESC and 24.6 million metric tons from Virginia Power.

• For Dominion Energy’s electric transmission and distribution operations, direct CO₂ equivalent emissions were 0.06 million metric tons in 2020.

• For Dominion Energy’s natural gas assets, total CO₂ equivalent emissions were 3.5 million metric tons in 2020, including 1.6 million metric tons associated with operations included in the GT&S Transaction and with the Q-Pipe Group.

• For Dominion Energy’s proportional interest in Cove Point’s operations, total CO₂ equivalent emissions were 0.6 million metric tons in 2020.

EPA Mandatory GHG Reporting Program

Dominion Energy has been reporting GHG emissions, including carbon, methane, N₂O and SF₆, from its natural gas infrastructure, electric generation and power delivery operations to the EPA since 2011 under the EPA mandatory GHG Reporting Program. The EPA’s mandatory GHG Reporting Program requires annual reporting based on full equity asset ownership at the end of the calendar year. Dominion Energy’s 2020 GHG emissions reported under various subparts of the EPA’s Mandatory GHG Reporting Program as of December 31, 2020, which exclude the operations included in the GT&S Transaction and include the operations of the Q-Pipe Group, are as follows:

Natural Gas Operations – 2020 Emissions

Segment	Subpart W CH4 Emissions		Subpart C CH4 Emissions		Subparts W & C CH4 Emissions		Subparts W & C CO2 Emissions		Subparts W & C N2O Emissions		Subparts W & C as CO2 Equivalent Emissions(3)
(metric tons)
Distribution		34,116				34,116		2,355		—		855,251
Production		15,053				15,053		16,527		0.04		392,874
Transmission pipelines		496				496		14				12,412
Transmission compressor stations		843		4		847		210,737		0.40		232,036
Gathering and boosting		2,733				2,733		88,767		0.18		157,151
Storage		323		2		324		85,993		0.16		94,149
LNG storage		70		—		70		482		—		2,240
LNG import/export(1)		165		20		185		1,120,158		2.06		1,125,388
Total(2)(3)		53,799		25		53,825		1,525,034		2.84		2,871,500

(1) Includes Cove Point at 100% ownership as required by the EPA.

(2) As of December 31, 2020, Dominion Energy’s only facility classified as processing did not operate in 2020 resulting in no emissions data to report.

(3) Totals may not foot due to rounding.

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Electric Generation Operations – 2020 Emissions

Company	Subparts C & D CO2 Emissions		Subparts C & D CH4 Emissions		Subparts C & D N2O Emissions		Subparts C & D CH4 Emissions as CO2 Equivalent Emissions		Subparts C & D N2O Emissions as CO2 Equivalent Emissions		Subparts C & D as CO2 Equivalent Emissions(2)
(metric tons)
Virginia Power(1)		24,987,534		1,317		183		32,935		54,455		25,074,923
DESC		8,527,718		523		72		13,087		21,445		8,562,250
Total(2)		33,515,252		1,841		255		46,021		75,900		33,637,174

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

(2) Totals may not foot due to rounding.

Electric Transmission and Distribution Operations – 2020 Emissions

Company	Subpart DD SF6 Emissions		Subpart DD SF6 as CO2 Equivalent Emissions
(metric tons)
Virginia Power		1.36		30,974
DESC(1)		1.23		28,037
Total(2)		2.59		59,011

(1) DESC triggered EPA mandatory GHG reporting in 2020.

(2) Totals may not foot due to rounding.

ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES

Dominion Energy incurred $221 million, $238 million and $260 million of expenses (including accretion and depreciation) during 2021, 2020, and 2019 respectively, in connection with environmental protection and monitoring activities. Dominion Energy expects these expenses to be approximately $223 million and $216 million in 2022 and 2023, respectively. In addition, capital expenditures related to environmental controls were $37 million, $58 million, and $134 million for 2021, 2020, and 2019, respectively. Dominion Energy expects these expenditures to be approximately $108 million and $160 million for 2022 and 2023, respectively.

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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 September 2021, FERC issued a final order that allows distributed energy resource aggregators to compete in regional wholesale electric markets. This rule followed a previous order which mandated that distributed energy resources be allowed to participate in wholesale markets.  RTOs, including PJM, are responsible for issuing implementation rules to FERC for approval. In addition, 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.

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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.

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

Environmental Risks

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

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

There are also potential impacts on Dominion Energy’s natural gas business from its net zero emissions commitment as well as federal or state GHG regulations which may require further GHG emission reductions from the natural gas sector which, in addition to

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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 and landfills. The Companies also may face litigation concerning their coal ash facilities.

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

Construction Risks

The Companies’ infrastructure build and expansion plans often require regulatory approval, including environmental permits, before commencing construction and completing projects. The Companies may not complete the facility construction, pipeline, conversion or other infrastructure projects that they commence, or they may complete projects on materially different terms, costs or timing than initially estimated or anticipated, and they may not be able to achieve the intended benefits of any such project, if completed. A number of large and small scale projects have been announced, including 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 and other, including PJM, approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, concerns raised during stakeholder engagement, a decline in the credit strength of counterparties or vendors, inflation, or other factors beyond the Companies’ control. For example, Dominion Energy has been involved with projects which have experienced certain delays in obtaining and maintaining permits necessary for construction along with construction delays due to judicial actions which impacted the cost and schedule such as

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

The development and construction of the CVOW Commercial Project is dependent on the Companies’ ability to obtain and maintain various local, state and federal permits and other regulatory approvals, including Virginia Commission approval for rider recovery of project costs. In addition, the design and route of the project’s onshore electric transmission, network upgrades and other facilities remain subject to regulatory and PJM review and approval. Changes in the design and route of these onshore facilities, including an increase in amount of undergrounding, would likely increase project costs. Also, the CVOW Commercial Project may become the subject of litigation or other forms of intervention by third parties, including stakeholders or advocacy groups, that may impact the timing and receipt of permits or other regulatory approvals or otherwise delay or increase the cost of the project.  

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

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

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

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

The development, construction and commissioning of several large-scale infrastructure projects simultaneously involves significant execution risk.  To achieve Dominion Energy’s commitment to net zero emissions by 2050 and comply with the requirements of the VCEA, the Companies are currently simultaneously developing or constructing several electric generation projects, including Subsequent License Renewal projects at Surry and North Anna, the CVOW Commercial Project and various solar projects. Several of the Companies’ key projects are increasingly large-scale, complex and being constructed in constrained

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

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

Further, an inability to obtain financing or otherwise provide liquidity for the projects on acceptable terms could negatively affect the Companies’ financial condition, cash flows, the projects’ anticipated financial results and/or impair the Companies’ ability to execute the business plan for the projects as scheduled.

Operational Risks

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

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

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

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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. Consumer demand for our services may also be impacted by any price increases, including those driven by factors beyond our control such as inflation or increased prices in natural gas.  Further, Virginia Power’s business model is premised upon the cost efficiency of the production, transmission and distribution of large-scale centralized utility generation. However, advances in distributed generation technologies, such as solar cells, gas microturbines, battery storage and fuel cells, may make these alternative generation methods competitive with large-scale utility generation, and change how customers acquire or use our services. The widescale implementation of alternative generation methods could negatively impact the reliability of the Companies’ electric grid and/or result in significant costs to enhance the grid. Virginia Power has an exclusive franchise to serve retail electric customers in Virginia. However, Virginia’s Retail Access Statutes allow certain electric generation customers exceptions to this franchise. As market conditions change, Virginia Power’s customers may further pursue exceptions and Virginia Power’s exclusive franchise may erode.

Reduced energy demand or significantly slowed growth in demand due to customer adoption of energy efficient technology, conservation, distributed generation, regional economic conditions, or the impact of additional compliance obligations, unless substantially offset through regulatory cost allocations, could adversely impact the value of the Companies’ business activities.

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

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

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

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

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

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

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

War, acts and threats of terrorism, intentional acts and other significant events could adversely affect the Companies’ operations.  The Companies cannot predict the impact that any future terrorist attacks or retaliatory military or other action may have on the energy industry in general or on the Companies’ businesses in particular. Any such future attacks or retaliatory action may adversely affect the Companies’ operations in a variety of ways, including by disrupting the power, fuel and other markets in which

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

Nuclear Generation Risks

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

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

Financial, Economic and Market Risks

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

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

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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, interest rate and/or foreign currency exchange rate risks.

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

Future impairments of goodwill or other intangible assets or long-lived assets may have a material adverse effect on the Companies’ results.  Goodwill is evaluated for impairment annually or more frequently if an event or circumstance occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Other intangible assets and long-lived assets are evaluated for impairment on an annual basis or more frequently whenever events or circumstances indicate that an asset’s carrying value may not be recoverable. If Dominion Energy’s goodwill or the Companies’ other intangible assets or long-lived assets are in the future determined to be impaired, the applicable 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

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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.

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Item 2. Properties

As of December 31, 2021, 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, 2021; 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 6,900 miles of electric transmission lines of 69 kV or more located in North Carolina, Virginia and West Virginia. Portions of Virginia Power’s electric transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, any surplus capacity that may exist in these lines. While Virginia Power owns and maintains its electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance and exchange of capacity and energy for such facilities.

In addition, Virginia Power’s electric distribution network includes approximately 59,300 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, Virginia Power owns 468 substations and 16MW of battery storage. Dominion Energy also owns various solar facilities, primarily at schools in Virginia, with an aggregate generation capacity of 17 MW.

The following tables list Virginia Power’s generating units and capability as of December 31, 2021.

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VIRGINIA POWER UTILITY GENERATION

Plant	Location	Net Summer Capability (MW)			Percentage Net Summer Capability
Gas
Greensville County (CC)	Greensville County, VA		1,629
Brunswick County (CC)	Brunswick County, VA		1,376
Warren County (CC)	Warren County, VA		1,349
Ladysmith (CT)	Ladysmith, VA		783
Bear Garden (CC)	Buckingham County, VA		622
Remington (CT)	Remington, VA		622
Possum Point (CC)	Dumfries, VA		573
Chesterfield (CC)	Chester, VA		392
Elizabeth River (CT)	Chesapeake, VA		330
Gordonsville Energy (CC)	Gordonsville, VA		218
Gravel Neck (CT)	Surry, VA		170
Darbytown (CT)	Richmond, VA		168
Total Gas			8,232			41	%
Coal
Mt. Storm	Mt. Storm, WV		1,621
Chesterfield(1)	Chester, VA		1,014
Virginia City Hybrid Energy Center	Wise County, VA		610
Clover	Clover, VA		439	(2)
Total Coal			3,684			18
Nuclear
Surry	Surry, VA		1,676
North Anna	Mineral, VA		1,672	(3)
Total Nuclear			3,348			16
Hydro
Bath County	Warm Springs, VA		1,808	(4)
Gaston	Roanoke Rapids, NC		220
Roanoke Rapids	Roanoke Rapids, NC		95
Other			1
Total Hydro			2,124			10
Oil
Yorktown(1)	Yorktown, VA	790
Gravel Neck (CT)	Surry, VA	198
Darbytown (CT)	Richmond, VA	168
Rosemary (CC)	Roanoke Rapids, NC	160
Possum Point (CT)	Dumfries, VA	72
Low Moor (CT)	Covington, VA	48
Northern Neck (CT)	Lively, VA	47
Chesapeake (CT)	Chesapeake, VA	39
Total Oil			1,522			7
Solar(5)
Colonial Trail West	Surry County, VA		142
Dry Bread	Emporia, VA		100
Spring Grove	Surry County, VA		98
Whitehouse Solar	Louisa County, VA		20
Woodland Solar	Isle of Wight County, VA		19
Scott Solar	Powhatan, VA		17
Total Solar			396			2
Biomass
Altavista(6)	Altavista, VA		51
Polyester(6)	Hopewell, VA		51
Southampton(6)	Southampton, VA		51
Total Biomass			153			1
Wind
CVOW Pilot Project	Virginia Beach, VA		12			—
Various
Mt. Storm (CT)	Mt. Storm, WV		11			—
			19,482
Power Purchase Agreements			1,075			5
Total Utility Generation			20,577			100	%

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

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

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

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

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

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(5)  All solar facilities are alternating current.

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

VIRGINIA POWER NON-JURISDICTIONAL GENERATION

Plant	Location	Net Summer Capability (MW)
Solar(1)
Desper	Louisa, VA		88
Gutenberg	Garysburg, NC		80
Butcher Creek	Chase City, VA		80
Pecan	Pleasant Hill, NC		75
Chestnut	Halifax County, NC		75
Bedford	Chesapeake, VA		70
Gloucester	Gloucester County, VA		20
Montross	Westmoreland County, VA		20
Morgans Corner	Pasquotank County, NC		20
Remington	Fauquier County, VA		20
Rochambeau	James City County, VA		20
Oceana	Virginia Beach, VA		18
Hollyfield	Manquin, VA		17
Puller	Topping, VA		15
Total Non-Jurisdictional Generation			618

(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 76,500 miles of distribution mains and related service facilities which are supported by approximately 5,600 miles of transmission, gathering and storage pipeline. The right-of-way grants for many natural gas pipelines have been obtained from the actual owners of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many natural gas pipelines are on publicly-owned property, where company rights and actions are determined on a case-by-case basis, with results that range from reimbursed relocation to revocation of permission to operate.

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

DOMINION ENERGY SOUTH CAROLINA

DESC has approximately 3,800 miles and 18,700 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 458 substations.

DESC’s natural gas system includes approximately 19,200 miles of distribution mains and related service facilities, which are supported by approximately 400 miles of transmission pipeline.

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

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The following table lists DESC’s generating units and capability as of December 31, 2021.

Plant	Location	Net Summer Capability (MW)			Percentage Net Summer Capability
Gas
Jasper (CC) (1)	Hardeeville, SC		863
Columbia Energy Center (CC) (1)	Gaston, SC		519
Urquhart (CC) (1)	Beech Island, SC		458
McMeekin	Irmo, SC		250
Hagood (CT) (1)	Charleston, SC		126
Urquhart Unit 3	Beech Island, SC		95
Urquhart (CT) (1)	Beech Island, SC		87
Parr (CT)  (1)(2)	Jenkinsville, SC		47
Coit (CT) (1)(2)	Columbia, SC		26
Williams (CT) (1)(2)	Goose Creek, SC		16
Total Gas(3)			2,487			40	%
Coal
Williams	Goose Creek, SC		605
Cope (4)	Cope, SC		415
Wateree (5)	Eastover, SC		342
Total Coal			1,362			22
Hydro
Fairfield	Jenkinsville, SC		576
Saluda	Irmo, SC		190
Other	Various		18
Total Hydro			784			13
Nuclear
Summer	Jenkinsville, SC		651	(6)		11
			5,284
Power Purchase Agreements			898	(7)		14
Total Utility Generation			6,182			100	%

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

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

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

(3) Excludes the Hardeeville gas combustion turbine which currently does not have any net summer capability and is expected to be retired by the end of 2025.

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

(5) Excludes Wateree Unit 2 (342 MW) that is temporarily unavailable and it is expected to be returned to service in 2022.

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

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

CONTRACTED ASSETS

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

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The following table lists Contracted Assets’ generating units and capability as of December 31, 2021.

Plant	Location	Net Summer Capability (MW)			Percentage Net Summer Capability
Nuclear
Millstone	Waterford, CT		2,001	(1)
Total Nuclear			2,001			67	%
Solar(2)
Hardin I	Hardin County, OH		150
Amazon Solar Farm Virginia – Southampton	Newsoms, VA		100	(3)
Amazon Solar Farm Virginia – Accomack	Oak Hall, VA		80	(3)
Greensville	Greensville County, VA		80
Innovative Solar 37	Morven, NC		79	(3)
Wilkinson	Pantego, NC		74
Seabrook	Beaufort County, SC		73
Moffett Solar 1	Ridgeland, SC		71	(3)
Summit Farms Solar	Moyock, NC		60	(3)
Midway II	Calipatria, CA		30	(3)
Amazon Solar Farm Virginia – Buckingham	Cumberland, VA		20	(3)
Amazon Solar Farm Virginia – Correctional	Barhamsville, VA		20	(3)
Hecate Cherrydale	Cape Charles, VA		20	(3)
Amazon Solar Farm Virginia – Sussex Drive	Stoney Creek, VA		20	(3)
Amazon Solar Farm Virginia – Scott II	Powhatan, VA		20	(3)
Myrtle	Suffolk, VA		15
Trask	Beaufort County, SC		12
Hecate Energy Clarke County	White Post, VA		10	(3)
Ridgeland Solar Farm I	Ridgeland, SC		10	(3)
Yemassee	Hampton County, SC		10
Other	Various		48	(3)
Total Solar			1,002			33
Total Nonregulated Generation			3,003			100	%

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

(2) All solar facilities are alternating current.

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

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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.  

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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)
Robert M. Blue (54)	Chair of the Board of Directors from April 2021 to present; 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.
James R. Chapman (52)	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.
Diane Leopold (55)	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.
Edward H. Baine (48)	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.
P. Rodney Blevins (57)	President—Gas Distribution from January 2022 to present; President—Dominion Energy South Carolina from December 2019 to December 2021; 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.
W. Keller Kissam (55)	President—Dominion Energy South Carolina from January 2022 to present; President—Electric Operations of DESC from January 2019 to December 2021; President—Generation, Transmission and Distribution and Chief Operating Officer of DESC from January 2018 to December 2018; President—Retail Operations of DESC from December 2011 to December 2017; Senior Vice President of SCANA Corporation from 2011 to December 2018.
Daniel G. Stoddard (59)	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.
Carlos M. Brown (47)	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.
Michele L. Cardiff (54)	Senior Vice President, Controller and Chief Accounting Officer from October 2020 to present; Vice President, Controller and CAO from April 2014 to September 2020.
William L. Murray (54)	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.

(1) All positions held at Dominion Energy, unless otherwise noted. Any service listed for Virginia Power, DESC, SCANA and DES reflects service at a current or previous subsidiary of Dominion Energy.

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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 11, 2022, there were approximately 126,000 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

Period	Total Number of Shares (or Units) Purchased			Average Price Paid per Share (or Unit)(2)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs(3)
10/1/21-10/31/21		67,292	(1)	$	72.29		—	$          0.92 billion
11/1/21-11/30/21		—			—		—	0.92 billion
12/1/21-12/31/21		407	(1)		70.85		—	0.92 billion
Total		67,699		$	72.28		—	$          0.92 billion

(1) Represents shares of common stock that were tendered by employees to satisfy tax withholding obligations on vested restricted stock.  

(2) Represents the weighted-average price paid per share.

(3) In November 2020, the Dominion Energy Board of Directors authorized the repurchase of up to $1.0 billion of shares of common stock. 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 may pay cash dividends in 2022 but is neither required to nor restricted, except as described in Note 21 to the Consolidated Financial Statements, from making such payments.

Item 6. [Reserved]

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

MD&A discusses Dominion Energy’s results of operations, general financial condition and liquidity and Virginia Power’s results of operations as of and for the year ended December 31, 2021 as compared to the year ended December 31, 2020, as applicable. For a discussion of these items for the year ended December 31, 2020 as compared to the year ended December 31, 2019, please see Part II, Item 7. MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 25, 2021. 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

• Outlook

• 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 and global supply chains;

• Federal, state and local legislative and regulatory developments, including changes in or interpretations of federal and state tax laws and regulations;

• 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;

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• Risks associated with entities in which Dominion Energy shares ownership with third parties, including risks that result from lack of sole decision making authority, disputes that may arise between Dominion Energy and third party participants and difficulties in exiting these arrangements;

• Changes in future levels of domestic and international natural gas production, supply or consumption;

• Impacts to Dominion Energy’s noncontrolling interest in Cove Point from fluctuations in future volumes of LNG imports or exports from the U.S. and other countries worldwide or demand for, purchases of, and prices related to natural gas or LNG;

• Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals;

• The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement, intervention or litigation in such projects;

• Risks and uncertainties that may impact the Companies’ ability to develop and construct the CVOW Commercial Project within the currently proposed timeline, or at all, and consistent with current cost estimates along with the ability to recover such costs from customers;

• Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances;

• Cost of environmental strategy and compliance, including those costs related to climate change;

• Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities;

• Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals;

• Unplanned outages at facilities in which the Companies have an ownership interest;

• The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error and other catastrophic events;

• Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities;

• Changes in operating, maintenance and construction costs;

• Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity;

• Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s nonregulated generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers;

• Competition in the development, construction and ownership of certain electric transmission facilities in the Companies’ service territory in connection with Order 1000;

• Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;

• Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Energy’s pipeline system, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods;

• Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures;

• Impacts of acquisitions, divestitures, transfers of assets to joint ventures and retirements of assets based on asset portfolio reviews;

• The expected timing and likelihood of completing the sales of Kewaunee and Hope, 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;

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• 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;

• Fluctuations in currency exchange rates of the Euro or Danish Krone associated with the CVOW Commercial Project;

• Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;

• Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms;

• Political and economic conditions, including inflation and deflation;

• Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; and

• Changes in financial or regulatory accounting principles or policies imposed by governing bodies.

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

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

ACCOUNTING MATTERS

Critical Accounting Policies and Estimates

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

ACCOUNTING FOR REGULATED OPERATIONS

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

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

• Orders issued by regulatory commissions, legislation and judicial actions;

• Past experience;

• Discussions with applicable regulatory authorities and legal counsel;

• Forecasted earnings; and

• Considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events and other natural disasters and unplanned outages of facilities.

If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. A regulatory liability, if considered probable, will be recorded in the period such assessment is made or reversed into earnings if no longer probable. In connection with the evaluation of Virginia Power’s earnings for the 2021 Triennial Review, in 2020 Virginia Power established a regulatory liability for benefits expected to be provided to Virginia retail electric customers through the use of a CCRO in accordance with the GTSA. In 2021, Virginia Power made further adjustments to this regulatory liability prior to its ultimate resolution through a comprehensive settlement agreement. See Notes 12 and 13 to the Consolidated Financial Statements for additional information.

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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, 2021 and 2020, Dominion Energy’s nuclear decommissioning AROs totaled $2.0 billion and $1.9 billion, respectively. The following discusses critical assumptions inherent in determining the fair value of AROs associated with Dominion Energy’s nuclear decommissioning obligations.

Dominion Energy obtains from third-party specialists periodic site-specific base year cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for its nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. These cash flows include estimates on timing of decommissioning, which for regulated nuclear units factors in the probability of NRC approval for license extensions. In addition, Dominion Energy’s cost estimates include cost escalation rates that are applied to the base year costs. Dominion Energy determines cost escalation rates, which represent projected cost increases over time due to both general inflation and increases in the cost of specific decommissioning activities, for each nuclear facility. The selection of these cost escalation rates is dependent on subjective factors which are considered to be critical assumptions. At December 31, 2021, a 0.25% increase in cost escalation rates would have resulted in an approximate $360 million increase in Dominion Energy’s nuclear decommissioning AROs.

INCOME TAXES

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

Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2021 and 2020, Dominion Energy had $128 million and $167 million, respectively, of unrecognized tax benefits. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations.

Deferred income tax assets and liabilities are recorded representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion Energy evaluates quarterly the probability of realizing deferred tax assets by considering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. In addition, changes in tax laws or tax rates may require reconsideration of the realizability of existing deferred tax assets. Dominion Energy establishes a valuation allowance when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. At December 31, 2021 and 2020, Dominion Energy had established $140 million and $155 million, respectively, of valuation allowances.

ACCOUNTING FOR DERIVATIVE CONTRACTS AND FINANCIAL INSTRUMENTS AT FAIR VALUE

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

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

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

USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING

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

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

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. There were no tests performed in 2021 of long-lived assets or equity method investments which could have resulted in material impairments.

HELD FOR SALE CLASSIFICATION

Dominion Energy recognizes the assets and liabilities of a disposal group as held for sale in the period (i) it has approved and committed to a plan to sell the disposal group, (ii) the disposal group is available for immediate sale in its present condition, (iii) an active program to locate a buyer and other actions required to sell the disposal group have been initiated, (iv) the sale of the disposal group is probable, (v) the disposal group is being actively marketed for sale at a price that is reasonable in relation to its current fair value and (vi) it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn. Dominion Energy initially measures a disposal group that is classified as held for sale at the lower of its carrying value or fair value less any costs to sell.

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Any loss resulting from this measurement is recognized in the period in which the held for sale criteria are met. Conversely, gains are not recognized on the sale of a disposal group until closing. Upon designation as held for sale, Dominion Energy stops recording depreciation expense and assesses the fair value of the disposal group less any costs to sell at each reporting period and until it is no longer classified as held for sale.

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

In May 2021, Dominion Energy entered into an agreement to sell Kewaunee, subject to termination by either party if not completed by December 2022. The consideration as to whether the sale is probable includes judgments related to the ability to obtain the approvals, in a timely manner, of the NRC and the Wisconsin Commission.  Due to the uncertainty surrounding the timing of or ability to obtain approval by the Wisconsin Commission, at December 31, 2021 Dominion Energy did not conclude that the sale is probable and, as a result, the disposal group was not classified as held for sale. Dominion Energy would have recognized a loss of approximately $725 million ($570 million after-tax) if such classification had been met. This loss primarily represents the difference between the nuclear decommissioning trust and AROs at December 31, 2021.  The Wisconsin Commission requires that any excess decommissioning funds be returned to WPSC and WP&L customers following completion of all decommissioning activities.

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

EMPLOYEE BENEFIT PLANS

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

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

• Expected inflation and risk-free interest rate assumptions;

• Historical return analysis to determine long-term historic returns as well as historic risk premiums for various asset classes;

• Expected future risk premiums, asset classes’ volatilities and correlations;

• Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and

• Investment allocation of plan assets. The strategic target asset allocation for Dominion Energy’s pension funds is 27% U.S. equity, 18% non-U.S. equity, 32% fixed income, 3% real estate and 20% other alternative investments, such as private equity investments.

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

Dominion Energy develops 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 8.45% for 2021, 7.00% to 8.60% for 2020 and 7.00% to 8.65% for 2019. For 2022, the expected long-term rate of return for the pension cost assumption ranged from 7.00% to 8.35% for Dominion Energy’s plans held as of December 31, 2021. Dominion Energy calculated its other

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postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 8.45% for 2021 and 8.50% for 2020 and 2019. For 2022, the expected long-term rate of return for other postretirement benefit cost assumption is 8.35%.

Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost ranged from 2.73% to 3.29% for pension plans and 2.69% to 2.80% for other postretirement benefit plans in 2021, ranged from 2.77% to 3.63% for pension plans and 3.07% to 3.52% for other postretirement benefit plans in 2020 and ranged from 3.57% to 4.43% for pension plans and 4.05% to 4.41% for other postretirement benefit plans in 2019. Dominion Energy selected a discount rate ranging from 3.06% to 3.19% for pension plans and 3.04% to 3.11% for other postretirement benefit plans for determining its December 31, 2021 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, 2021 was 6.25% and is expected to gradually decrease to 5.00% by 2026-2027 and continue at that rate for years thereafter.

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

		Increase in 2021 Net Periodic Cost
	Change in Actuarial Assumptions	Pension Benefits		Other Postretirement Benefits
(millions, except percentages)
Dominion Energy
Discount Rate	(0.25)%	$	18	$	—
Long-term rate of return on plan assets	(0.25)%		25		5
Health care cost trend rate	1%	N/A			9

In addition to the effects on cost, a 0.25% decrease in the discount rate would increase Dominion Energy’s projected pension benefit obligation at December 31, 2021 by $376 million and its accumulated postretirement benefit obligation at December 31, 2021 by $44 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation at December 31, 2021 by $121 million.

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

New Accounting Standards

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

DOMINION ENERGY

Results of Operations

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

Year Ended December 31,	2021		$ Change		2020			$ Change			2019
(millions, except EPS)
Net income (loss) attributable to Dominion Energy	$	3,288	$	3,689	$	(401	)	$	(1,759	)	$	1,358
Diluted EPS		3.98		4.55		(0.57	)		(2.19	)		1.62

Overview

2021 VS. 2020

Net income attributable to Dominion Energy increased $3.7 billion, primarily due to the absence of: charges associated with the cancellation of the Atlantic Coast Pipeline Project and related portions of the Supply Header Project which are presented in discontinued operations, the planned early retirements of certain electric generation facilities in Virginia, an impairment of interests in certain nonregulated solar generation facilities and the termination of a contract in connection with the sale of Fowler Ridge. In addition, there was an increase in net investment earnings on nuclear decommissioning trust funds, a decrease in charges associated with Virginia Power’s 2021 Triennial Review and a gain on the sale of the Q-Pipe Group to Southwest Gas. These increases were

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partially offset by charges associated with the settlement of the South Carolina electric base rate case, increased unrealized losses on economic hedging activities and a net loss on the sales of non-wholly-owned nonregulated solar facilities.

Analysis of Consolidated Operations

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

Year Ended December 31,	2021		$ Change			2020			$ Change			2019
(millions)
Operating revenue	$	13,964	$	(208	)	$	14,172		$	(229	)	$	14,401
Electric fuel and other energy-related purchases		2,368		125			2,243			(642	)		2,885
Purchased electric capacity		70		17			53			(35	)		88
Purchased gas		1,083		194			889			(671	)		1,560
Other operations and maintenance		3,734		49			3,685			(105	)		3,790
Depreciation, depletion and amortization		2,478		146			2,332			49			2,283
Other taxes		909		38			871			(12	)		883
Impairment of assets and other charges		195		(1,910	)		2,105			585			1,520
Loss (gain) on sales of assets		108		169			(61	)		91			(152	)
Earnings from equity method investees		276		236			40			32			8
Other income		1,157		464			693			(110	)		803
Interest and related charges		1,354		(23	)		1,377			(109	)		1,486
Income tax expense		425		342			83			(126	)		209
Net income (loss) from discontinued operations including    noncontrolling interests		641		2,519			(1,878	)		(2,594	)		716
Noncontrolling interests		26		175			(149	)		(167	)		18

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

2021 VS. 2020

Operating revenue decreased 1%, primarily reflecting:

• A $402 million decrease associated with market prices affecting Millstone, including economic hedging impacts of net realized and unrealized losses on freestanding derivatives ($495 million);

• A $356 million decrease for refunds to be provided to retail electric customers in Virginia associated with the settlement of the 2021 Triennial Review;

• A $151 million decrease from an unbilled revenue reduction at Virginia Power;

• A $80 million decrease as a result of the contribution of certain nonregulated natural gas retail energy contracts to Wrangler;

• A $62 million decrease associated with settlements of economic hedges of certain Virginia Power regulated electric sales; and

• A $51 million decrease in PJM off-system sales.

These decreases were partially offset by:

• A $390 million increase in the fuel cost component included in utility rates as a result of an increase in commodity costs associated with sales to gas utility customers ($239 million) and electric utility retail customers ($151 million);

• A $117 million increase from gas utility capital cost riders;

• A $75 million increase in sales to electric utility retail customers associated with growth;

• A $62 million increase in sales to electric utility customers associated with economic and other usage factors;

• A $52 million increase from the absence of planned outages at Millstone;

• A $51 million increase in sales to electric utility retail customers from an increase in heating degree days during the heating season ($71 million) partially offset by a decrease in cooling degree days during the cooling season ($20 million);

• A $26 million increase in sales to customers from non-jurisdictional solar generation facilities; and

• A $22 million increase in sales to gas utility customers associated with growth.

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Electric fuel and other energy-related purchases increased 6%, primarily due to higher commodity costs for electric utilities ($151 million), partially offset by a decrease in PJM off-system sales ($51 million), which are offset in operating revenue and do not impact net income.

Purchased electric capacity increased 32%, primarily due to an increase in expense related to the annual PJM capacity performance market effective June 2021 ($24 million) and an increase in expense related to the annual PJM capacity performance market effective June 2020 ($17 million), partially offset by a decrease in expense associated with DESC’s electric utility operations ($24 million).

Purchased gas increased 22%, primarily due to an increase in commodity costs for gas utilities, which are offset in operating revenue and do not impact net income.

Other operations and maintenance increased 1%, primarily reflecting:

• A $117 million increase in salaries, wages and benefits, including $28 million of costs for employer-provided healthcare;

• A $44 million charge related to a revision in estimated recovery of spent nuclear fuel costs associated with the decommissioning of Kewaunee; and

• A $32 million increase in storm damage and restoration costs in Virginia Power’s service territory; partially offset by

• A $58 million decrease in merger and integration-related costs associated with the SCANA Combination;

• A $44 million decrease in certain Virginia Power expenditures which are primarily recovered through state- and FERC-regulated rates and do not impact net income; and

• A $26 million net decrease in outage costs as a result of a decrease in Millstone outage costs ($45 million) partially offset by an increase in Virginia Power outage costs ($19 million).

Depreciation, depletion and amortization increased 6%, primarily due to various projects being placed into service ($132 million) and an increase for amortization from the establishment of a regulatory asset associated with the 2021 Triennial Review ($61 million), partially offset by a decrease due to the impairment of certain nonregulated solar generation facilities in 2020 ($20 million).

Impairment of assets and other charges decreased 91%, primarily reflecting:

• The absence of a charge associated with the planned early retirements of certain electric generation facilities in Virginia ($747 million);

• The absence of a charge associated with certain nonregulated solar generation facilities ($665 million);

• A benefit from the establishment of a regulatory asset associated with the early retirements of certain coal- and oil-fired generating units associated with the settlement of the 2021 Triennial Review ($549 million);

• The absence of a contract termination charge in connection with the sale of Fowler Ridge ($221 million);

• The absence of a charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020 ($127 million); and

• The absence of dismantling costs associated with certain Virginia Power electric generation facilities ($54 million); partially offset by

• Charges associated with the settlement of the South Carolina electric base rate case ($249 million);

• A charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to Virginia’s 2021 budget process ($77 million);

• A charge for corporate office lease termination ($62 million);

• An increase in charges for CCRO benefits provided to retail electric customers in Virginia associated with Virginia Power’s 2021 Triennial Review ($58 million); and

• A charge for the write-off of nonregulated retail software development assets ($20 million).

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Loss on sales of assets increased $169 million, primarily due to a net loss on the sales of non-wholly-owned nonregulated solar facilities ($211 million) partially offset by an increase in gains on the sale of nonregulated retail energy marketing assets ($23 million).

Earnings from equity method investees increased $236 million, primarily due to accounting for Cove Point as an equity method investment for a full year following the closing of the GT&S Transaction in November 2020.

Other income increased 67%, primarily due to an increase in net investment gains on nuclear decommissioning trust funds ($237 million), the absence of a charge for social justice commitments ($80 million), an increase in non-service components of pension and other postretirement employee benefit plan credits ($77 million), the absence of charges associated with litigation acquired in the SCANA Combination ($25 million) and an increase in AFUDC associated with rate-regulated projects ($25 million), partially offset by charges associated with the settlement of the South Carolina electric base rate case ($18 million).

Interest and related charges decreased 2%, primarily due to the absence of borrowings in response to COVID-19 in 2020 ($42 million), the absence of charges associated with the early redemption of certain securities in the first quarter of 2020 ($31 million) and a benefit associated with the effective settlement of uncertain tax positions ($21 million), partially offset by decreased carrying costs associated with the recovery of CEP beginning January 2021 ($29 million), charges associated with the early redemption of certain securities in the third quarter of 2021 ($23 million) and lower unrealized gains in 2021 associated with freestanding derivatives ($13 million).

Income tax expense increased $342 million, primarily due to higher pre-tax income ($365 million), lower investment tax credits ($38 million), the absence of prior year benefits including reductions in consolidated state deferred income taxes associated with gas transmission and storage operations ($45 million) and adjustments finalizing the effects of changes in tax status of certain subsidiaries in connection with the Dominion Energy Gas Restructuring ($24 million). These increases are partially offset by a benefit associated with the effective settlement of uncertain tax positions ($38 million), the benefit of a state legislative change ($21 million) and the absence of prior year expense primarily associated with the impairment of nonregulated solar generating assets held in partnerships attributable to the noncontrolling interest ($55 million).

Net income from discontinued operations including noncontrolling interests increased $2.5 billion, primarily due to a decrease in charges associated with the Atlantic Coast Pipeline Project and related portions of the Supply Header Project ($2.1 billion) and a gain on the sale of Q-Pipe ($493 million), partially offset by the absence of operations sold in the GT&S Transaction ($56 million).

Noncontrolling interests increased $175 million, primarily due to the absence of impairments associated with certain nonregulated solar generation facilities ($267 million) partially offset by the closing of the GT&S Transaction in November 2020 ($106 million).

Outlook

Dominion Energy’s 2022 net income is expected to increase on a per share basis as compared to 2021 primarily from the following:

• The absence of charges associated with Virginia Power’s 2021 Triennial Review;

• The absence of charges associated with the settlement of the South Carolina electric base rate case;

• The absence of a net loss on the sales of certain non-wholly-owned nonregulated solar facilities;

• The absence of charges associated with litigation acquired in the SCANA Combination; and

• Construction and operation of growth projects in electric utility and gas distribution operations.

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

• The absence of operations of the Q-Pipe Group sold to Southwest Gas and associated gain on sale;

• The absence of a benefit from the establishment of a regulatory asset associated with the early retirements of certain coal- and oil-fired generating units associated with the 2021 Triennial Review and an increase from a full year of amortization of this regulatory asset; and

• Share dilution.

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SEGMENT RESULTS OF OPERATIONS

Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit or loss. Presented below is a summary of contributions by Dominion Energy’s operating segments to net income (loss) attributable to Dominion Energy:

Year Ended December 31,	2021						2020						2019
	Net income (loss) attributable to Dominion Energy			Diluted EPS			Net income (loss) attributable to Dominion Energy			Diluted EPS			Net income (loss) attributable to Dominion Energy			Diluted EPS
(millions, except EPS)
Dominion Energy Virginia	$	1,919		$	2.37		$	1,891		$	2.28		$	1,786		$	2.21
Gas Distribution		600			0.74			560			0.67			487			0.60
Dominion Energy South Carolina		437			0.54			419			0.51			430			0.53
Contracted Assets		431			0.53			402			0.48			460			0.57
Corporate and Other		(99	)		(0.20	)		(3,673	)		(4.51	)		(1,805	)		(2.29	)
Consolidated	$	3,288		$	3.98		$	(401	)	$	(0.57	)	$	1,358		$	1.62

Dominion Energy Virginia

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

Year Ended December 31,	2021		% Change				2020		% Change				2019
Electricity delivered (million MWh)		85.2		2		%		83.3		(5	)	%		87.7
Electricity supplied (million MWh):
Utility		85.7		(1	)			87.0		(1	)			88.2
Non-Jurisdictional		1.0		43				0.7		75				0.4
Degree days (electric distribution and utility service area):
Cooling		1,783		1				1,759		(13	)			2,031
Heating		3,210		8				2,970		(9	)			3,259
Average electric distribution customer accounts    (thousands)		2,697		1				2,661		1				2,626

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

2021 VS. 2020

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	44		$	0.05
Other		20			0.02
Rider equity return		41			0.05
Electric capacity		(28	)		(0.03	)
Outages		(14	)		(0.02	)
Depreciation and amortization		(18	)		(0.02	)
Renewable energy investment tax credits		7			0.01
Salaries, wages and benefits & administrative costs		(22	)		(0.03	)
Other		(2	)		—
Share accretion		—			0.06
Change in net income contribution	$	28		$	0.09

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Gas Distribution

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

Year Ended December 31,	2021		% Change				2020		% Change				2019
Gas distribution throughput (bcf):
Sales		183		2		%		180		(6	)	%		192
Transportation		975		12				868		7				811
Heating degree days (gas distribution service area):
North Carolina		2,947		8				2,734		(7	)			2,942
Ohio and West Virginia		5,121		(1	)			5,148		(4	)			5,355
Utah, Wyoming, and Idaho		4,874		(2	)			4,973		(10	)			5,501
Average gas distribution customer accounts    (thousands):
Sales		1,935		2				1,897		2				1,857
Transportation		1,131		1				1,123		1				1,108

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

2021 VS. 2020

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Regulated gas sales:
Weather	$	—		$	—
Other		31			0.04
Rider equity return		40			0.05
Salaries, wages and benefits & administrative costs		(8	)		(0.01	)
Interest expense, net		12			0.01
Other		(35	)		(0.04	)
Share accretion		—			0.02
Change in net income contribution	$	40		$	0.07

Dominion Energy South Carolina

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

Year Ended December 31,	2021		% Change			2020		% Change				2019
Electricity delivered (million MWh)		22.4		1	%		22.1		(4	)	%		23.0
Electricity supplied (million MWh)		23.5		2			23.0		(5	)			24.1
Degree days (electric and gas distribution service areas):
Cooling		859		8			794		(17	)			951
Heating		1,280		19			1,074		(9	)			1,179
Average electric distribution customer accounts    (thousands)		766		2			753		2				739
Gas distribution throughput (bcf):
Sales		72		9			66		2				65
Average gas distribution customer accounts    (thousands)		412		3			399		3				386

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

2021 VS. 2020

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	(6	)	$	(0.01	)
Other		48			0.06
Regulated gas sales		9			0.01
Capital cost rider		(6	)		(0.01	)
Depreciation and amortization		(9	)		(0.01	)
Interest expense, net		7			0.01
Salaries, wages and benefits & administrative costs		(46	)		(0.06	)
Other		21			0.02
Share accretion		—			0.02
Change in net income contribution	$	18		$	0.03

Contracted Assets

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

Year Ended December 31,	2021		% Change			2020		% Change				2019
Electricity supplied (million MWh)		20.8		8	%		19.3		(4	)	%		20.2

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

2021 VS. 2020

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Margin(1)	$	28		$	0.03
Planned outage costs		33			0.04
Renewable energy investment tax credits		(43	)		(0.05	)
Absence of contract associated with Fowler Ridge		14			0.02
Other		(3	)		(0.00	)
Share accretion		—			0.01
Change in net income contribution	$	29		$	0.05

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

Corporate and Other

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

Year Ended December 31,	2021			2020			2019
(millions, except EPS)
Specific items attributable to operating segments	$	(493	)	$	(1,241	)	$	(1,901	)
Specific items attributable to Corporate and Other segment		590			(2,166	)		384
Total specific items		97			(3,407	)		(1,517	)
Other corporate operations:
Interest expense, net		(410	)		(384	)		(383	)
Other		214			118			95
Total other corporate operations		(196	)		(266	)		(288	)
Total net expense		(99	)		(3,673	)		(1,805	)
EPS impact	$	(0.20	)	$	(4.51	)	$	(2.29	)

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

VIRGINIA POWER

Results of Operations

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

Year Ended December 31,	2021		$ Change		2020		$ Change			2019
(millions)
Net income	$	1,712	$	691	$	1,021	$	(128	)	$	1,149

Overview

2021 VS. 2020

Net income increased 68%, primarily due to the absence of charges related to the planned early retirements of certain electric generation facilities and a decrease in charges associated with the 2021 Triennial Review.

Analysis of Consolidated Operations

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

Year Ended December 31,	2021			$ Change			2020			$ Change			2019
(millions)
Operating revenue	$	7,470		$	(293	)	$	7,763		$	(345	)	$	8,108
Electric fuel and other energy-related purchases		1,735			99			1,636			(542	)		2,178
Purchased (excess) electric capacity		24			41			(17	)		(57	)		40
Other operations and maintenance		1,793			7			1,786			43			1,743
Depreciation and amortization		1,364			112			1,252			29			1,223
Other taxes		326			(1	)		327			(1	)		328
Impairment of assets and other charges (benefits)		(269	)		(1,362	)		1,093			336			757
Other income		146			66			80			(18	)		98
Interest and related charges		534			18			516			(8	)		524
Income tax expense		397			168			229			(35	)		264

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

2021 VS. 2020

Operating revenue decreased 4%, primarily reflecting:

• A $356 million decrease for refunds to be provided to retail electric customers in Virginia associated with the settlement of the 2021 Triennial Review;

• A $151 million decrease from an unbilled revenue reduction;

• A $62 million decrease associated with settlements of economic hedges of certain regulated electric sales; and

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• A $51 million decrease in PJM off-system sales;

These decreases were partially offset by:

• A $125 million increase in the fuel cost component included in utility rates as a result of a net increase in commodity costs associated with sales to electric utility retail customers

• A $59 million increase in sales to retail customers from an increase in heating degree days during the heating season ($65 million) partially offset by a decrease in cooling degree days during the cooling season ($6 million);

• A $49 million increase in sales to electric utility retail customers associated with growth;

• A $35 million increase in sales to electric utility retail customers associated with economic and other usage factors; and

• A $26 million increase in sales to customers from non-jurisdictional solar generation facilities.

Electric fuel and other energy-related purchases increased 6%, primarily due to higher commodity costs for electric utilities ($125 million), partially offset by a decrease in PJM off-system sales ($51 million), which are offset in operating revenue and do not impact net income.

Purchased electric capacity increased $41 million, primarily due to an increase in expense related to the annual PJM capacity performance market effective June 2021 ($24 million) and an increase in expense related to the annual PJM capacity performance market effective June 2020 ($17 million).

Other operations and maintenance increased $7 million, primarily reflecting:

• A $57 million increase in outside services;

• A $32 million increase in storm damage and service restoration costs;

• A $20 million increase in materials and supplies; and

• A $19 million increase in planned outage costs; partially offset by

• A $44 million decrease in certain expenses which are primarily recovered through state- and FERC-regulated rates and do not impact net income;

• A $12 million gain on the sale of corporate office real estate;

• The absence of a $11 million charge associated with ash pond and landfill closure costs;

• The absence of a $11 million charge associated with credit risk on customer accounts related to COVID-19;

• A $10 million reduction in bad debt expense due to the forgiveness of Virginia retail electric customer accounts in arrears pursuant to Virginia’s 2021 budget process; and

• A $10 million decrease in environmental remediation costs.

Depreciation and amortization increased 9%, primarily due to an increase for amortization from the establishment of a regulatory asset associated with the 2021 Triennial Review ($61 million), various projects being placed into service ($57 million), partially offset by the absence of depreciation from certain electric generation facilities that were retired early ($11 million).

Impairment of assets and other charges (benefits) decreased $1.4 billion, primarily reflecting:

• The absence of charges associated with the planned early retirements of certain electric generation facilities ($747 million);

• A benefit from the establishment of a regulatory asset associated with the early retirements of certain coal- and oil-fired generating units associated with the settlement of the 2021 Triennial Review ($549 million);

• The absence of a charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020 ($127 million); and

• The absence of charges for dismantling costs associated with certain electric generation facilities ($54 million); partially offset by

• A charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to Virginia’s 2021 budget process ($77 million); and

• An increase in charges for CCRO benefits provided to retail electric customers in Virginia associated with the 2021 Triennial Review ($58 million).

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Other income increased 83%, primarily due to an increase in net investment gains on nuclear decommissioning trust funds ($38 million) and an increase in AFUDC associated with rate-regulated projects ($24 million).

Income tax expense increased 73%, primarily due to higher pre-tax income ($192 million) partially offset by the benefit of a state legislative change ($16 million).

LIQUIDITY AND CAPITAL RESOURCES

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

Analysis of Cash Flows

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

Year Ended December 31,	2021			2020			2019
(millions)
Cash, restricted cash and equivalents at beginning of year	$	247		$	269		$	391
Cash flows provided by (used in):
Operating activities		4,037			5,227			5,204
Investing activities		(6,247	)		(2,916	)		(4,622	)
Financing activities		2,371			(2,333	)		(704	)
Net increase (decrease) in cash, restricted cash and equivalents		161			(22	)		(122	)
Cash, restricted cash and equivalents at end of year	$	408		$	247		$	269

Operating Cash Flows

Net cash provided by Dominion Energy's operating activities decreased $1.2 billion, including a $1.4 billion decrease from discontinued operations largely due to the absence of operations sold in the GT&S Transaction. Net cash provided by continuing operations increased $200 million, primarily as the result of higher operating cash flows from electric utility and gas distribution operations driven by weather, customer growth and riders ($737 million), the absence of a cash pension plan contribution ($250 million), increased distributions from Cove Point ($230 million), absence of a contract termination payment in connection with the sale of Fowler Ridge ($221 million), decreases in severance payments primarily related to a voluntary retirement program ($174 million) and a decrease in payments associated with litigation acquired in the SCANA Combination ($143 million), lower income tax payments ($132 million) and changes in working capital ($161 million). These increases were partially offset by lower deferred fuel cost recoveries ($1.2 billion) and increased margin deposits ($690 million).

Investing Cash Flows

Net cash used in Dominion Energy’s investing activities increased $3.3 billion, primarily due to a net decrease in proceeds from the sale of the Q-Pipe Group compared to the GT&S Transaction ($2.2 billion), the repayment of the Q-Pipe Transaction deposit ($1.3 billion), an increase in contributions to equity method affiliates including Atlantic Coast Pipeline ($873 million), partially offset by the proceeds from the sale of non-wholly-owned nonregulated solar facilities ($495 million), the absence of acquisitions of equity method investments ($178 million) and a decrease in acquisitions of solar development projects ($210 million).

Financing Cash Flows

Net cash provided by Dominion Energy’s financing activities was $2.4 billion for the year ended December 31, 2021, compared to net cash used by financing activities of $2.3 billion for the year ended December 31, 2020. This change is primarily due to the absence of common stock repurchases ($3.1 billion), higher net issuances of short-term debt ($1.4 billion), lower common stock dividend payments ($837 million) and the issuance of Series C Preferred Stock ($742 million), partially offset by increased repayments and redemptions of long-term debt ($871 million).

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Credit Facilities and Short-Term Debt

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

Joint Revolving Credit Facility

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

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

	Facility Limit		Outstanding Commercial Paper(1)		Outstanding Letters of Credit		Facility Capacity Available
(millions)
At December 31, 2021
Joint revolving credit facility(2)	$	6,000	$	1,883	$	131	$	3,986

(1) The weighted-average interest rate of the outstanding commercial paper supported by Dominion Energy’s credit facility was 0.31% at December 31, 2021.

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

Dominion Energy Reliability Investment^SM Program

Dominion Energy has an effective registration statement with the SEC for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability Investment^SM. The registration 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, 2021, Dominion Energy’s Consolidated Balance Sheets include $431 million presented within short-term debt.  The proceeds are used for general corporate purposes and to repay debt.

Other Facilities

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

Long-Term Debt

Issuances and Borrowings of Long-Term Debt

During 2021, Dominion Energy issued or borrowed the following long-term debt. Unless otherwise noted, the proceeds were used for the repayment of existing long-term indebtedness and for general corporate purposes.  

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Month of Issuance	Type	Public / Private	Issuer / Borrowing Entity	Principal		Rate			Stated Maturity
				(millions)
March	Senior notes	Private	PSNC	$	150		3.100	%	2051
April	Senior notes	Public	Dominion Energy		600		1.450	%	2026
April	Senior notes	Public	Dominion Energy		500		3.300	%	2041
June	Sustainability Revolving Credit Agreement(1)	Private	Dominion Energy		250	variable			2024
August	Sustainability Revolving Credit Agreement(1)	Private	Dominion Energy		650	variable			2024
August	Senior notes(2)	Public	Dominion Energy		1,000		2.250	%	2031
August	Senior notes	Private	Questar Gas		125		2.210	%	2031
August	Senior notes	Private	Questar Gas		125		3.150	%	2051
November	Senior notes	Public	Virginia Power		500		2.300	%	2031
November	Senior notes	Public	Virginia Power		500		2.950	%	2051
November	First mortgage bonds	Public	DESC		400		2.300	%	2031
December	Term loan(3)	Private	DECP Holdings		2,500	variable			2024
Total issuances and borrowings				$	7,300

(1) This supplemental credit facility offers a reduced interest rate margin with respect to borrowed amounts allocated to certain environmental sustainability or social investment initiatives. Proceeds of the supplemental credit facility may also be used for general corporate purposes, but such proceeds are not eligible for a reduced interest rate margin. The proceeds from these borrowings were used to support environmental sustainability and social investment initiatives ($250 million) and for general corporate purposes ($650 million). At December 31, 2021, no amounts were outstanding under this arrangement.

(2) The proceeds from this offering will be used to finance and/or refinance, in whole or in part, existing and future capital expenditures associated with the development, construction, acquisition and operation of certain solar projects.

(3) The maturity date for this term loan has the potential to be extended to December 2026.

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

Dominion Energy anticipates, excluding potential opportunistic financings, issuing between approximately $3.2 billion and $4.4 billion of long-term debt during 2022, inclusive of $1.0 billion issued at Virginia Power in January 2022. The raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.

Repayment, Repurchases and Redemptions of Long-Term Debt

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

The following long-term debt was repaid, repurchased or redeemed in 2021:

Month of Redemption	Type		Entity	Principal		(1)	Rate			Stated Maturity
				(millions)
Debt scheduled to mature in 2021				$	2,109	(2)	various
Early redemptions
August	July 2016 hybrids(3)	Dominion Energy			800			5.250	%	2076
November	Senior notes	Virginia Power			450			2.950	%	2022
November	Sustainability Revolving Credit Agreement	Dominion Energy			650		variable			2024
December	Sustainability Revolving Credit Agreement	Dominion Energy			250		variable			2024
December	Senior notes	Dominion Energy			400			2.750	%	2022
December	Term loan	Dominion Solar Projects III, Inc.			177		variable			2024
Total repayments, repurchases and redemptions(4)				$	4,836

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

(2) Includes repayment of $225 million associated with supplemental 364-Day revolving credit facility borrowings.

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(3) The July 2016 hybrids were listed on the NYSE under the symbol DRUA. Expenses related to the early redemption were $23 million reflected within interest and related charges in Dominion Energy’s Consolidated Statements of Income for the year ended December 31, 2021.

(4) Amounts exclude $265 million of long-term debt assumed by Terra Nova Renewable Partners in connection with the sale of SBL Holdco in December 2021.

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

Remarketing of Long-Term Debt

In 2021, Dominion Energy was not required to and did not complete the remarketing of any of its long-term debt. In 2022, Dominion Energy expects to remarket approximately $165 million of its senior notes and tax-exempt bonds.

Credit Ratings

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

Credit ratings and outlooks as of February 21, 2022 are as follows:

	Fitch	Moody's	Standard & Poor's
Dominion Energy
Issuer	BBB+	Baa2	BBB+
Senior unsecured debt securities	BBB+	Baa2	BBB
Junior subordinated notes	BBB	Baa3	BBB
Enhanced junior subordinated notes	BBB-	Baa3	BBB-
Preferred Stock	BBB-	Ba1	BBB-
Commercial paper	F2	P-2	A-2
Outlook	Stable	Stable	Positive

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

Financial Covenants

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

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

As of December 31, 2021, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows:

Company	Maximum Allowed Ratio			Actual Ratio(1)
Dominion Energy		67.5	%		56.0	%

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

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

Dominion Energy monitors compliance with these covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2021, there have been no events of default under Dominion Energy’s covenants.

Common Stock, Preferred Stock and Other Equity Securities

Issuances of Equity Securities

Dominion Energy maintains Dominion Energy Direct® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January 2021, Dominion Energy began issuing new shares of common stock for these direct stock purchase plans. During 2021, Dominion Energy issued 2.6 million of such shares and received proceeds of $192 million.

Dominion Energy also maintains sales agency agreements to effect sales under an at-the-market program. Under the sales agency agreements, Dominion Energy may, from time to time, offer and sell shares of its common stock through the sales agents or enter into one or more forward sale agreements with respect to shares of its common stock. Sales by Dominion Energy through the sales agents or by forward sellers pursuant to a forward sale agreement cannot exceed $1.0 billion in the aggregate. In November 2021, Dominion Energy entered forward sale agreements for approximately 1.1 million shares of its common stock to be settled by November 2022 at an average initial forward price of $74.66 per share. See Note 20 to the Consolidated Financial Statements for additional information.

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

• In 2021, Dominion Energy issued 2.0 million shares of its common stock, valued at $149 million, to satisfy obligations under settlement agreements associated with litigation acquired in the SCANA Combination.

• In December 2021, Dominion Energy issued 750,000 shares of Series C Preferred Stock and received cash proceeds of $742 million, net of issuance costs. Also in December 2021, Dominion Energy issued 250,000 shares of Series C Preferred Stock, valued at $250 million, to the qualified pension plans.

Between Dominion Energy Direct® and its at-the-market program (including any related forward-sale agreements), and excluding potential opportunistic financings, Dominion Energy anticipates raising between $300 million and $500 million of capital through the issuance of common stock in 2022. In addition, Dominion Energy may issue up to $150 million of stock under settlement agreements associated with litigation acquired in the SCANA Combination as discussed in Note 23 to the Consolidated Financial Statements. As discussed in Note 19 to the Consolidated Financial Statements, in 2022, Dominion Energy will settle the stock purchase contract component of the 2019 Equity Units expected to result in proceeds of $1.6 billion and the issuance of up to 21.8 million shares, subject to a formula based on the average closing price of Dominion Energy common stock upon settlement.

Repurchases of Equity Securities

In November 2020, the Board of Directors authorized the repurchase of up to $1.0 billion of Dominion Energy’s common stock. This repurchase program does not include a specific timetable or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors. No purchases have been made under this authorization as of December 31, 2021.

Dominion Energy does not plan to repurchase shares of common stock in 2022, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which does not impact the available capacity under its stock repurchase authorization.

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Capital Expenditures

See Note 26 to the Consolidated Financial Statements for Dominion Energy’s historical capital expenditures by segment. Dominion Energy’s total planned capital expenditures for each segment over the next five years are presented in the table below:

	2022		2023		2024		2025		2026		Total(1)
(billions)
Dominion Energy Virginia	$	5.8	$	7.2	$	7.5	$	7.5	$	5.3	$	33.2
Gas Distribution		1.4		1.4		1.2		1.5		1.1		6.5
Dominion Energy South Carolina		0.8		0.9		0.9		0.8		0.7		4.2
Contracted Assets		0.6		0.9		0.9		0.9		0.5		3.8
Corporate and Other segment		0.1		0.1		0.1		0.1		0.1		0.4
Total(1)	$	8.6	$	10.3	$	10.7	$	10.6	$	7.7	$	47.9

(1) Totals may not foot due to rounding.

Dominion Energy’s planned growth expenditures are subject to approval by the Board of Directors as well as potentially by regulatory bodies based on the individual project and are expected to include significant investments in support of its clean energy profile. See Dominion Energy Virginia, Gas Distribution, Dominion Energy South Carolina and Contracted Assets in Item 1. Business for additional discussion of various significant capital projects currently under development. The above estimates are based on a capital expenditures plan reviewed and endorsed by Dominion Energy’s Board of Directors in December 2021 and are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. Dominion Energy may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.

Dividends

Dominion Energy believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In December 2021, Dominion Energy’s Board of Directors established an annual dividend rate for 2022 of $2.67 per share of common stock, a 6% increase over the 2021 rate. Dividends are subject to declaration by the Board of Directors. In January 2022, Dominion Energy’s Board of Directors declared dividends payable in March 2022 of 66.75 cents per share of common stock.

See Note 19 for a discussion of Dominion Energy’s outstanding preferred stock and associated dividend rates.

Subsidiary Dividend Restrictions

Certain of Dominion Energy’s subsidiaries may, from time to time, be subject to certain restrictions imposed by regulators or financing arrangements on their ability to pay dividends, or to advance or repay funds, to Dominion Energy. At December 31, 2021, these restrictions did not have a significant impact on Dominion Energy’s ability to pay dividends on its common or preferred stock or meet its other cash obligations.

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

Collateral and Credit Risk

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

Dominion Energy’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion Energy’s credit exposure as of December 31, 2021 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.

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	Gross Credit Exposure		Credit Collateral		Net Credit Exposure
(millions)
Investment grade(1)	$	32	$	—	$	32
Non-Investment grade(2)		6		—		6
No external ratings:
Internally rated—investment grade(3)		98		—		98
Internally rated—non-investment grade(4)		39		28		16
Total	$	175	$	28	$	152

(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 17% of the total net credit exposure.

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

(3) The five largest counterparty exposures, combined, for this category represented approximately 64% of the total net credit exposure.

(4) The five largest counterparty exposures, combined, for this category represented approximately 5% of the total net credit exposure.

Fuel and Other Purchase Commitments

Dominion Energy is party to various contracts for fuel and purchased power commitments related to both its regulated and nonregulated operations. Total estimated costs for such commitments at December 31, 2021 are presented in the table below. These costs represent estimated minimum obligations for various purchased power and capacity agreements and actual costs may differ from amounts presented below depending on actual quantities purchased and prices paid.

	2022		2023		2024		2025		2026		Total
(millions)
Purchased electric capacity for utility operations	$	66	$	66	$	66	$	65	$	68	$	331
Fuel commitments for utility operations		1,169		685		371		178		166		2,569
Fuel commitments for nonregulated operations		104		134		88		68		59		453
Pipeline transportation and storage		523		462		365		303		291		1,944
Total	$	1,862	$	1,347	$	890	$	614	$	584	$	5,297

Other Material Cash Requirements

In addition to the financing arrangements discussed above, Dominion Energy is party to numerous contracts and arrangements obligating it to make cash payments in future years. Dominion Energy expects current liabilities to be paid within the next twelve months. In addition to the items already discussed, the following represent material expected cash requirements recorded on Dominion Energy’s Consolidated Balance Sheets at December 31, 2021. Such obligations include:

• Operating and financing lease obligations – See Note 15 to the Consolidated Financial Statements;

• Regulatory liabilities – See Note 12 to the Consolidated Financial Statements;

• AROs – See Note 14 to the Consolidated Financial Statements;

• Employee benefit plan obligations – See Note 22 to the Consolidated Financial Statements; and

• Charitable commitments – See Note 23 to the Consolidated Financial Statements.

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

• Off-balance sheet leasing arrangements – See Note 15 to the Consolidated Financial Statements

• Guarantees – See notes 9 and 23 to the Consolidated Financial Statements

FUTURE ISSUES AND OTHER MATTERS

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

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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 NO_X 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.

PHMSA Regulation

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

Dodd-Frank Act

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

North Anna

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

Federal Income Tax Laws

Under existing law, the Companies utilize a financial reporting method that classifies and recognizes investment tax credits on nonregulated operations as immediate reductions to income tax expense and, therefore, immediate increases in earnings. This immediate earnings benefit provides a significant incentive for renewable energy development.  Provisions in recently proposed federal legislation would allow taxpayers to elect direct payment for investment tax credits.  While effective from a cash flow perspective, this option may not provide the same level of incentive due to the financial reporting potentially applicable to the proposed direct pay benefits and “refundable” tax credits, regardless of whether such an option is selected by the taxpayer.

Because the investment tax credit could be received as a direct payment under this proposed legislation, Dominion Energy may be required to either report the benefit ratably over the life of the qualifying facility or over the five-year recapture period. Either of these alternatives may be required instead of maintaining our historical financial reporting method regardless of whether we elect the direct pay option.  If this legislation is enacted into law, the application of these alternative accounting methodologies could have a material impact on the Companies’ future results of operations, financial condition and/or cash flows.

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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 Companies’ exposure to foreign currency exchange rate risk is related to certain fixed price contracts entered into in 2021 in connection with the CVOW Commercial Project. The contracts include services denominated in currencies other than the U.S. dollar for approximately €2.6 billion and 5.1 billion kr. In addition, certain of the fixed price contracts, approximately €0.7 billion, contain commodity indexing provisions linked to steel. As a result, any changes in applicable exchange rates or commodity indices could result in a change to the ultimate cost of the project. Virginia Power is evaluating hedging strategies, subject to approval by the Virginia Commission, to mitigate such risk.

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

Commodity Price Risk

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

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

A hypothetical 10% increase in commodity prices would have resulted in a decrease of $16 million and $3 million in the fair value of Dominion Energy’s commodity-based derivative instruments as of December 31, 2021 and 2020, respectively.

A hypothetical 10% increase in commodity prices would have resulted in a decrease of $6 million in the fair value of Virginia Power’s commodity-based derivative instruments as of December 31, 2021. A hypothetical 10% decrease in commodity prices would have resulted in a decrease of $35 million in the fair value of Virginia Power’s commodity-based derivative instruments as of December 31, 2020.

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, 2021 or 2020.

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

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Energy and Virginia Power’s interest rate derivatives at December 31, 2021. 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’s interest rate derivatives at December 31, 2020.

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 $1.1 billion and $0.7 billion for the years ended December 31, 2021 and 2020, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion Energy recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on debt investments of $64 million and a net increase in unrealized gains on debt investments of $57 million for the years ended December 31, 2021 and 2020, respectively.

Virginia Power recognized net investment gains (including investment income) on nuclear decommissioning trust investments of $568 million and $287 million for the years ended December 31, 2021 and 2020, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on debt investments of $31 million and a net increase in unrealized gains on debt investments of $29 million for the years ended December 31, 2021 and 2020, 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 $1.5 billion and $1.9 billion in 2021 and 2020, respectively, versus expected returns of $1.0 billion and $933 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 $27 million and $25 million as of December 31, 2021 and 2020, respectively, for pension benefits and $6 million and $5 million as of December 31, 2021 and 2020, respectively, for other postretirement benefits.

Risk Management Policies

The Companies have established operating procedures with corporate management to ensure that proper internal controls are maintained. In addition, Dominion Energy has established an independent function at the corporate level to monitor compliance with the credit and commodity risk management policies of all subsidiaries, including Virginia Power. Dominion Energy maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion Energy also monitors the financial condition of existing counterparties on an ongoing basis. Based on these credit policies and the Companies’ December 31, 2021 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.

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Item 8. Financial Statements and Supplementary Data

	Page Number
Dominion Energy, Inc.
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)	81
Consolidated Statements of Income for the years ended December 31, 2021, 2020 and 2019	83
Consolidated Statements of Comprehensive Income for the years ended December 31, 2021, 2020 and 2019	84
Consolidated Balance Sheets at December 31, 2021 and 2020	85
Consolidated Statements of Equity at December 31, 2021, 2020 and 2019 and for the years then ended	87
Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019	88
Virginia Electric and Power Company
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)	89
Consolidated Statements of Income for the years ended December 31, 2021, 2020 and 2019	91
Consolidated Statements of Comprehensive Income for the years ended December 31, 2021, 2020 and 2019	92
Consolidated Balance Sheets at December 31, 2021 and 2020	93
Consolidated Statements of Common Shareholder’s Equity at December 31, 2021, 2020 and 2019 and for the years then ended	95
Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019	96
Combined Notes to Consolidated Financial Statements	97

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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, 2021 and 2020, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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, 2021, 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 24, 2022, 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 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 audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our 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

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 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 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

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authorized ROE prospectively. Under certain circumstances, Virginia Power may be required to credit a portion of its earnings to customers.

When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds or other benefits through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Dominion Energy evaluates whether 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 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.

/s/ Deloitte & Touche LLP

Richmond, Virginia  

February 24, 2022

We have served as Dominion Energy’s auditor since 1988.

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Dominion Energy, Inc.

Consolidated Statements of Income

Year Ended December 31,	2021		2020			2019
(millions, except per share amounts)
Operating Revenue	$	13,964	$	14,172		$	14,401
Operating Expenses
Electric fuel and other energy-related purchases		2,368		2,243			2,885
Purchased electric capacity		70		53			88
Purchased gas		1,083		889			1,560
Other operations and maintenance		3,734		3,685			3,790
Depreciation, depletion and amortization		2,478		2,332			2,283
Other taxes		909		871			883
Impairment of assets and other charges		195		2,105			1,520
Losses (gains) on sales of assets		108		(61	)		(152	)
Total operating expenses		10,945		12,117			12,857
Income from operations		3,019		2,055			1,544
Earnings from equity method investees		276		40			8
Other income		1,157		693			803
Interest and related charges		1,354		1,377			1,486
Income from continuing operations including noncontrolling interests before income      tax expense		3,098		1,411			869
Income tax expense		425		83			209
Net Income From Continuing Operations Including Noncontrolling Interests		2,673		1,328			660
Net Income (Loss) From Discontinued Operations Including Noncontrolling      Interests(1)(2)		641		(1,878	)		716
Net Income (Loss) Including Noncontrolling Interests		3,314		(550	)		1,376
Noncontrolling Interests		26		(149	)		18
Net Income (Loss) Attributable to Dominion Energy	$	3,288	$	(401	)	$	1,358
Amounts attributable to Dominion Energy
Net income from continuing operations	$	2,647	$	1,583		$	653
Net income (loss) from discontinued operations		641		(1,984	)		705
Net income (loss) attributable to Dominion Energy	$	3,288	$	(401	)	$	1,358
EPS - Basic
Net income from continuing operations	$	3.19	$	1.83		$	0.79
Net income (loss) discontinued operations		0.79		(2.39	)		0.87
Net income (loss) attributable to Dominion Energy	$	3.98	$	(0.56	)	$	1.66
EPS - Diluted
Net income from continuing operations	$	3.19	$	1.82		$	0.75
Net income (loss) discontinued operations		0.79		(2.39	)		0.87
Net income (loss) attributable to Dominion Energy	$	3.98	$	(0.57	)	$	1.62

(1) See Note 9 for amounts attributable to related parties.

(2) Includes income tax expense (benefit) of $188 million, $(204) million and $142 million for the years ended December 31, 2021, 2020 and 2019, respectively.

The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.

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Dominion Energy, Inc.

Consolidated Statements of Comprehensive Income

Year Ended December 31,	2021			2020			2019
(millions)
Net income (loss) including noncontrolling interests	$	3,314		$	(550	)	$	1,376
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of $(6),      $81 and $35 tax		15			(239	)		(110	)
Changes in unrealized net gains (losses) on investment securities, net of      $7, $(14) and $(14) tax		(7	)		43			39
Changes in net unrecognized pension and other postretirement benefit      costs, net of $(54), $(2) and $(4) tax		144			25			(22	)
Amounts reclassified to net income (loss):
Net derivative (gains) losses-hedging activities, net of $(15), $(75) and      $21 tax		46			227			(62	)
Net realized (gains) losses on investment securities, net of $5, $6 and      $1 tax		(18	)		(18	)		(4	)
Net pension and other postretirement benefit costs, net of $(29), $(13)      and $(23) tax		82			37			66
Changes in other comprehensive income from equity method investees,      net of $1, $(1) and $— tax		(3	)		1			—
Total other comprehensive income (loss)		259			76			(93	)
Comprehensive income (loss) including noncontrolling interests		3,573			(474	)		1,283
Comprehensive income (loss) attributable to noncontrolling interests		26			(149	)		18
Comprehensive income (loss) attributable to Dominion Energy	$	3,547		$	(325	)	$	1,265

The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.

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Dominion Energy, Inc.

Consolidated Balance Sheets

At December 31,	2021			2020
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	283		$	172
Customer receivables (less allowance for doubtful accounts of $40 and $42)		2,219			2,295
Other receivables (less allowance for doubtful accounts of $4 and $3)		349			212
Inventories:
Materials and supplies		1,167			1,105
Fossil fuel		320			349
Gas stored		144			96
Margin deposit assets		678			19
Prepayments		328			309
Regulatory assets		1,492			699
Other		264			148
Current assets held for sale(1)		25			1,482
Total current assets		7,269			6,886
Investments
Nuclear decommissioning trust funds		7,950			6,900
Investment in equity method affiliates		2,932			2,934
Other		394			404
Total investments		11,276			10,238
Property, Plant and Equipment
Property, plant and equipment		86,503			82,959
Accumulated depreciation, depletion and amortization		(26,729	)		(25,111	)
Total property, plant and equipment, net		59,774			57,848
Deferred Charges and Other Assets
Goodwill		7,405			7,381
Pension and other postretirement benefit assets		2,310			1,704
Intangible assets, net		784			765
Regulatory assets		8,643			9,133
Other		2,129			1,950
Total deferred charges and other assets		21,271			20,933
Total assets	$	99,590		$	95,905

(1) See Note 9 for amounts attributable to related parties.

The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.  

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At December 31,	2021			2020
(millions)
LIABILITIES, MEZZANINE EQUITY AND SHAREHOLDERS' EQUITY
Current Liabilities
Securities due within one year	$	841		$	1,937
Supplemental 364-Day credit facility borrowings		—			225
Short-term debt		2,314			895
Accounts payable		1,197			944
Accrued interest, payroll and taxes		1,169			1,133
Regulatory liabilities		986			809
Liability to Atlantic Coast Pipeline		113			1,052
Q-Pipe Transaction deposit		—			1,290
Other(1)		2,053			1,933
Current liabilities held for sale		—			625
Total current liabilities		8,673			10,843
Long-Term Debt
Long-term debt		35,190			30,915
Junior subordinated notes		1,386			2,161
Other		850			881
Total long-term debt		37,426			33,957
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		6,658			5,953
Regulatory liabilities		10,713			10,187
Asset retirement obligations		5,275			5,404
Pension and other postretirement benefit liability		442			1,706
Other(1)		1,485			1,394
Total deferred credits and other liabilities		24,573			24,644
Total liabilities		70,672			69,444
Commitments and Contingencies (see Note 23)
Mezzanine Equity
Preferred stock (See Note 19)		1,610			—
Shareholders' Equity
Preferred stock (See Note 19)		1,783			2,387
Common stock – no par(2)		21,610			21,258
Retained earnings		5,373			4,189
Accumulated other comprehensive loss		(1,458	)		(1,717	)
Shareholders' equity		27,308			26,117
Noncontrolling interests		—			344
Total shareholders' equity		27,308			26,461
Total liabilities, mezzanine equity and shareholders' equity	$	99,590		$	95,905

(1)     See Note 9 for amounts attributable to related parties.

(2)    1.8 billion shares authorized; 810 million shares and 806 million shares outstanding at December 31, 2021 and 2020, respectively.

The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.

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Dominion Energy, Inc.

Consolidated Statements of Equity

	Preferred Stock						Common Stock						Dominion Energy Shareholders
	Shares			Amount			Shares			Amount			Retained Earnings			AOCI			Total Shareholders' Equity			Noncontrolling Interests			Total Equity
(millions except per share amounts)
December 31, 2018								681		$	12,588		$	9,219		$	(1,700	)	$	20,107		$	1,941		$	22,048
Net income including noncontrolling interests														1,358						1,358			18			1,376
Issuance of stock		2			2,387			39			3,014									5,401						5,401
Stock purchase contract component of 2019      Equity Units											(264	)								(264	)					(264	)
Acquisition of SCANA								96			6,818									6,818						6,818
Acquisition of public interest in Dominion      Energy Midstream								22			1,181									1,181			(1,221	)		(40	)
Sale of interest in Cove Point											476									476			1,386			1,862
Stock awards (net of change in unearned      compensation)											24									24						24
Preferred stock dividends (See Note 19)														(17	)					(17	)					(17	)
Common dividends ($3.67 per common share)     and distributions														(2,983	)					(2,983	)		(85	)		(3,068	)
Other comprehensive loss, net of tax																	(93	)		(93	)					(93	)
Other											(13	)		(1	)					(14	)					(14	)
December 31, 2019		2		$	2,387			838		$	23,824		$	7,576		$	(1,793	)	$	31,994		$	2,039		$	34,033
Cumulative-effect of changes in accounting     principles														(48	)					(48	)					(48	)
Net loss including noncontrolling interests														(401	)					(401	)		(149	)		(550	)
Issuance of stock								7			481									481						481
Stock repurchases								(39	)		(3,080	)								(3,080	)					(3,080	)
Stock awards (net of change in unearned      compensation)											29									29						29
Preferred stock dividends (See Note 19)														(65	)					(65	)					(65	)
Common dividends ($3.45 per common share)      and distributions														(2,873	)					(2,873	)		(164	)		(3,037	)
Other comprehensive income, net of tax																	76			76						76
GT&S Transaction closing											17									17			(1,384	)		(1,367	)
Other											(13	)								(13	)		2			(11	)
December 31, 2020		2		$	2,387			806		$	21,258		$	4,189		$	(1,717	)	$	26,117		$	344		$	26,461
Net income including noncontrolling interests														3,288						3,288			26			3,314
Issuance of stock		1			992			4			340									1,332						1,332
Stock awards (net of change in unearned      compensation)											28									28						28
Preferred stock dividends (See Note 19)														(68	)					(68	)					(68	)
Common dividends ($2.52 per common share)      and distributions														(2,036	)					(2,036	)		(47	)		(2,083	)
Other comprehensive income, net of tax																	259			259						259
Reclassification of Series A Preferred Stock to     Mezzanine Equity		(1	)		(1,596	)					(14	)								(1,610	)					(1,610	)
Sale of non-wholly-owned nonregulated solar     facilities																				—			(323	)		(323	)
Other											(2	)								(2	)					(2	)
December 31, 2021		2		$	1,783			810		$	21,610		$	5,373		$	(1,458	)	$	27,308		$	—		$	27,308

The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.  

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Dominion Energy, Inc.

Consolidated Statements of Cash Flows

Year Ended December 31,	2021			2020			2019
(millions)
Operating Activities
Net income (loss) including noncontrolling interests	$	3,314		$	(550	)	$	1,376
Adjustments to reconcile net income (loss) including noncontrolling interests to net cash provided by operating activities:
Depreciation, depletion and amortization (including nuclear fuel)		2,768			2,836			2,977
Deferred income taxes and investment tax credits		487			(324	)		216
Gain from sale of Q-Pipe Group and GT&S Transaction		(685	)		(134	)		—
Contribution to pension plan		—			(250	)		(21	)
Net loss on sale of interest in renewable generation facilities		211			—			—
Provision for refunds and rate credits to electric utility customers		356			—			800
Impairment of assets and other charges		182			2,345			1,333
Loss from investment in Atlantic Coast Pipeline		20			2,405			—
Charges related to a voluntary retirement program		—			—			320
Gains on sales of assets and equity method investments		(97	)		(63	)		(167	)
Net (gains) losses on nuclear decommissioning trusts funds and other investments		(639	)		(412	)		(626	)
Charge (revision) for future ash pond and landfill closure costs		—			11			(113	)
Other adjustments		294			213			29
Changes in:
Accounts receivable		(183	)		(292	)		(105	)
Inventories		(74	)		39			(90	)
Deferred fuel and purchased gas costs, net		(939	)		212			195
Prepayments		(20	)		7			(225	)
Accounts payable		156			35			(225	)
Accrued interest, payroll and taxes		41			(53	)		(78	)
Customer deposits		(24	)		(13	)		(101	)
Margin deposit assets and liabilities		(664	)		26			60
Net realized and unrealized changes related to derivative activities		435			(36	)		43
Pension and other postretirement benefits		(314	)		(319	)		(148	)
Other operating assets and liabilities		(588	)		(456	)		(246	)
Net cash provided by operating activities		4,037			5,227			5,204
Investing Activities
Plant construction and other property additions (including nuclear fuel)		(5,960	)		(6,020	)		(4,980	)
Cash and restricted cash acquired in the SCANA Combination		—			—			389
Acquisition of solar development projects		(101	)		(311	)		(341	)
Proceeds from GT&S Transaction and sale of Q-Pipe Group		1,522			3,687			—
Repayment of Q-Pipe Transaction deposit		(1,265	)		—			—
Proceeds from sale of non-wholly-owned nonregulated solar facilities		495			—			—
Proceeds from sales of securities		3,985			4,278			1,712
Purchases of securities		(3,939	)		(4,379	)		(1,749	)
Proceeds from sales of assets and equity method investments		159			143			447
Contributions to equity method affiliates		(1,021	)		(148	)		(209	)
Acquisition of equity method investments		—			(178	)		—
Other		(122	)		12			109
Net cash used in investing activities		(6,247	)		(2,916	)		(4,622	)
Financing Activities
Issuance (repayment) of short-term debt, net		1,419			(16	)		404
Issuance of short-term notes		1,265			1,125			3,000
Repayment and repurchase of short-term notes		(1,265	)		(1,125	)		(3,000	)
Supplemental 364-day credit facility borrowings		—			225			—
Supplemental 364-day credit facility repayments		(225	)		—			—
Credit facility borrowings (repayments)		—			—			(113	)
Issuance and remarketing of long-term debt		6,400			6,577			4,374
Repayment and repurchase of long-term debt (including redemption premiums)		(3,750	)		(2,879	)		(9,116	)
Proceeds from sale of interest in Cove Point		—			—			2,078
Issuance of 2019 Equity Units		—			—			1,582
Supplemental credit facility borrowings		900			—			—
Supplemental credit facility repayments		(900	)		—			—
Issuance of preferred stock		742			—			791
Issuance of common stock		192			159			2,515
Repurchase of common stock		—			(3,080	)		—
Common dividend payments		(2,036	)		(2,873	)		(2,983	)
Other		(371	)		(446	)		(236	)
Net cash provided by (used in) financing activities		2,371			(2,333	)		(704	)
Increase (decrease) in cash, restricted cash and equivalents		161			(22	)		(122	)
Cash, restricted cash and equivalents at beginning of period		247			269			391
Cash, restricted cash and equivalents at end of period	$	408		$	247		$	269

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, 2021 and 2020, 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, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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 our 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

89

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 credit a portion of its earnings to customers.

When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds or other benefits through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. 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) 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 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 24, 2022

We have served as Virginia Power's auditor since 1988.

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Virginia Electric and Power Company

Consolidated Statements of Income

Year Ended December 31,	2021			2020			2019
(millions)
Operating Revenue(1)	$	7,470		$	7,763		$	8,108
Operating Expenses
Electric fuel and other energy-related purchases(1)		1,735			1,636			2,178
Purchased (excess) capacity		24			(17	)		40
Other operations and maintenance:
Affiliated suppliers		333			314			367
Other		1,460			1,472			1,376
Depreciation and amortization		1,364			1,252			1,223
Other taxes		326			327			328
Impairment of assets and other charges (benefits)		(269	)		1,093			757
Total operating expenses		4,973			6,077			6,269
Income from operations		2,497			1,686			1,839
Other income		146			80			98
Interest and related charges(1)		534			516			524
Income before income tax expense		2,109			1,250			1,413
Income tax expense		397			229			264
Net Income	$	1,712		$	1,021		$	1,149

(1) See Note 25 for amounts attributable to affiliates.

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

91

Virginia Electric and Power Company

Consolidated Statements of Comprehensive Income

Year Ended December 31,	2021			2020			2019
(millions)
Net income	$	1,712		$	1,021		$	1,149
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of $(4), $9 and $8 tax		13			(28	)		(22	)
Changes in unrealized net gains (losses) on nuclear decommissioning trust funds, net of      $—, $(3) and $(2) tax		(2	)		6			5
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities, net of $(1), $—  and $— tax		2			2			1
Net realized (gains) losses on nuclear decommissioning trust funds, net of $1, $1      and $1 tax		(2	)		(3	)		(1	)
Other comprehensive income (loss)		11			(23	)		(17	)
Comprehensive income	$	1,723		$	998		$	1,132

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

92

Virginia Electric and Power Company

Consolidated Balance Sheets

	2021			2020
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	26		$	35
Customer receivables (less allowance for doubtful accounts of $28 and $23)		1,172			1,315
Other receivables (less allowance for doubtful accounts of $2 at both dates)		112			91
Affiliated receivables		37			5
Inventories (average cost method):
Materials and supplies		610			581
Fossil fuel		261			281
Margin deposit assets		167			1
Prepayments		37			32
Regulatory assets		850			295
Other(1)		78			26
Total current assets		3,350			2,662
Investments
Nuclear decommissioning trust funds		3,734			3,197
Other		3			3
Total investments		3,737			3,200
Property, Plant and Equipment
Property, plant and equipment		49,890			46,736
Accumulated depreciation and amortization		(15,234	)		(14,167	)
Total property, plant and equipment, net		34,656			32,569
Deferred Charges and Other Assets
Pension and other postretirement benefit assets(1)		431			354
Intangible assets, net		395			334
Regulatory assets		4,130			3,509
Other(1)		1,233			1,026
Total deferred charges and other assets		6,189			5,223
Total assets	$	47,932		$	43,654

(1) See Note 25 for amounts attributable to affiliates.

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

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	2021			2020
(millions)
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	313		$	8
Short-term debt		745			45
Accounts payable		402			332
Payables to affiliates		121			266
Affiliated current borrowings		699			380
Accrued interest, payroll and taxes		274			253
Asset retirement obligations		191			166
Regulatory liabilities		647			425
Derivative liabilities (1)		134			390
Other current liabilities		567			562
Total current liabilities		4,093			2,827
Long-Term Debt
Long-term debt		13,453			13,207
Other		503			480
Total long-term debt		13,956			13,687
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		3,183			2,779
Asset retirement obligations		3,732			3,654
Regulatory liabilities		5,740			5,338
Other (1)		1,248			812
Total deferred credits and other liabilities		13,903			12,583
Total liabilities		31,952			29,097
Commitments and Contingencies (see Note 23)
Common Shareholder’s Equity
Common stock – no par(2)		5,738			5,738
Other paid-in capital		1,113			1,113
Retained earnings		9,170			7,758
Accumulated other comprehensive loss		(41	)		(52	)
Total common shareholder’s equity		15,980			14,557
Total liabilities and shareholder’s equity	$	47,932		$	43,654

(1) See Note 25 for amounts attributable to affiliates.

(2) 500,000 shares authorized; 274,723 shares outstanding at December 31, 2021 and 2020.

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

94

Virginia Electric and Power Company

Consolidated Statements of Common Shareholder’s Equity

	Common Stock
	Shares		Amount		Other Paid-In Capital		Retained Earnings			AOCI			Total
(millions, except for shares)	(thousands)
December 31, 2018		275	$	5,738	$	1,113	$	6,208		$	(12	)	$	13,047
Net income								1,149						1,149
Dividends								(190	)					(190	)
Other comprehensive loss, net of tax											(17	)		(17	)
December 31, 2019		275		5,738		1,113		7,167			(29	)		13,989
Net income								1,021						1,021
Dividends								(430	)					(430	)
Other comprehensive loss, net of tax											(23	)		(23	)
December 31, 2020		275		5,738		1,113		7,758			(52	)		14,557
Net income								1,712						1,712
Dividends								(300	)					(300	)
Other comprehensive income, net of tax											11			11
December 31, 2021		275	$	5,738	$	1,113	$	9,170		$	(41	)	$	15,980

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

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Virginia Electric and Power Company

Consolidated Statements of Cash Flows

Year Ended December 31,	2021			2020			2019
(millions)
Operating Activities
Net income	$	1,712		$	1,021		$	1,149
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		1,521			1,421			1,392
Deferred income taxes and investment tax credits		343			(206	)		(80	)
Charge (revision) for future ash pond and landfill closure costs		—			11			(113	)
Impairment of assets and other charges		(269	)		1,079			624
Charges related to a voluntary retirement program		—			—			116
Provision for refunds to customers		356			—			—
Other adjustments		19			(61	)		(63	)
Changes in:
Accounts receivable		(112	)		(266	)		(219	)
Affiliated receivables and payables		(175	)		78			75
Inventories		(10	)		10			(56	)
Prepayments		(4	)		(5	)		1
Deferred fuel expenses, net		(652	)		131			243
Accounts payable		19			6			(31	)
Accrued interest, payroll and taxes		21			(4	)		5
Margin deposit assets and liabilities		(166	)		(1	)		—
Net realized and unrealized changes related to derivative activities		—			(6	)		21
Other operating assets and liabilities		(106	)		(308	)		(280	)
Net cash provided by operating activities		2,497			2,900			2,784
Investing Activities
Plant construction and other property additions		(3,521	)		(3,138	)		(2,642	)
Purchases of nuclear fuel		(160	)		(199	)		(157	)
Acquisition of solar development projects		(75	)		(35	)		(182	)
Proceeds from sales of securities		1,791			884			858
Purchases of securities		(1,789	)		(936	)		(905	)
Other		—			21			(37	)
Net cash used in investing activities		(3,754	)		(3,403	)		(3,065	)
Financing Activities
Issuance (repayment) of short-term debt, net		700			(198	)		(71	)
Issuance (repayment) of affiliated current borrowings, net		319			273			(117	)
Issuance and remarketing of long-term debt		1,000			1,327			1,248
Repayment and repurchase of long-term debt		(450	)		(427	)		(591	)
Common dividend payments to parent		(300	)		(430	)		(190	)
Other		(21	)		(31	)		(12	)
Net cash provided by financing activities		1,248			514			267
Increase (decrease) in cash, restricted cash and equivalents		(9	)		11			(14	)
Cash, restricted cash and equivalents at beginning of year		35			24			38
Cash, restricted cash and equivalents at end of year	$	26		$	35		$	24

See Note 2 for disclosure of supplemental cash flow information.

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

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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 through the GT&S Transaction completed in November 2020 and the sale of the Q-Pipe Group completed in December 2021.

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 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. Clearway’s ownership interest in Four Brothers and Three Cedars (through December 2021), Terra Nova Renewable Partners’ 33% interest in certain Dominion Energy nonregulated solar projects (through December 2021), 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.

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’ 2020 and 2019 Consolidated Financial Statements and Notes have been reclassified to conform to the 2021 presentation for comparative purposes; however, such reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows. Effective in the second quarter of 2021, the Companies updated their Statements of Cash Flows to present net charges for allowance for credit risk and write-offs of accounts receivables within other adjustments to reconcile net income to net cash provided by operating activities from the previous presentation within changes in accounts receivable. All prior period information has been conformed to this presentation, which does not result in a change to net cash provided by operating activities.

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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, 2021 and 2020 included $779 million and $1.1 billion, 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, 2021 and 2020 included $398 million and $740 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

• Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

• Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates and associated hedging activity and sales to Virginia Power customers from non-jurisdictional solar generation facilities;

• Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services;

• 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;

• 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;

• 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

• 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 (through December 2021), service concession arrangements and revenue associated with services provided to entities presented in discontinued operations under transition services agreements.

Other Revenue

• 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

• Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services;

• Nonregulated electric sales consists of sales to customers from non-jurisdictional solar generation facilities;

• 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 revenue from renting space on certain electric transmission poles and distribution towers and service concession arrangements.

Other Revenue

• Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.

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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 to BHE as part of the GT&S Transaction and sold to Southwest Gas as part of the Q-Pipe Group sale primarily consisted 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 to BHE as part of the GT&S Transaction and sold to Southwest Gas as part of the Q-Pipe Group sale were 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 continued 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, 2021, approximately 86% 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, 2021, 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.

99

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.

In 2021, Dominion Energy reflected a $21 million benefit from the reversal of interest expense and a $7 million benefit from the reversal of penalty expense on uncertain tax positions that were effectively settled.

At December 31, 2021, Virginia Power had an income tax-related affiliated receivable of $35 million, comprised of $33 million of federal income taxes and $2 million of state income taxes receivable from Dominion Energy. These affiliated balances are expected to be received from Dominion Energy.  

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. 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.

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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:

At December 31,	2021		2020
(millions)
Dominion Energy	$	70	$	50
Virginia Power		15		30

Restricted Cash and Equivalents

The Companies hold restricted cash and equivalent balances that primarily consist of amounts held for litigation settlements, customer deposits, federal assistance funds and future debt payments on SBL Holdco and Dominion Solar Projects III, Inc.’s term loan agreements (through December 2021), on DECP Holdings’ term loan agreement 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, 2021, 2020 and 2019:

	Cash, Restricted Cash and Equivalents at End/Beginning of Year
	December 31, 2021		December 31, 2020		December 31, 2019		December 31, 2018
(millions)
Dominion Energy
Cash and cash equivalents(1)	$	283	$	179	$	166	$	268
Restricted cash and equivalents(2)(3)		125		68		103		123
Cash, restricted cash and equivalents shown in the    Consolidated Statements of Cash Flows	$	408	$	247	$	269	$	391
Virginia Power
Cash and cash equivalents	$	26	$	35	$	17	$	29
Restricted cash and equivalents(3)		—		—		7		9
Cash, restricted cash and equivalents shown in the    Consolidated Statements of Cash Flows	$	26	$	35	$	24	$	38

(1) At December 31, 2020, December 31, 2019 and December 31, 2018, Dominion Energy had $7 million, $31 million and $110 million of cash and cash equivalents included in current assets held for sale, respectively. No amounts were included in current assets held for sale at December 31, 2021.

(2) At December 31, 2020, December 31, 2019 and December 31, 2018, Dominion Energy had $3 million, $12 million and $89 million of restricted cash included in current assets held for sale, respectively. No amounts were included in current assets held for sale at December 31, 2021.

(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:

Year Ended December 31,	2021		2020		2019
Cash paid during the year for:
Interest and related charges, excluding capitalized amounts	$	1,340	$	1,519	$	1,643
Income taxes		160		292		106
Significant noncash investing and financing activities:(1)(2)(3)(4)(5)
Accrued capital expenditures		637		485		555
Leases(6)		96		173		157

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(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 $47 million of finance leases and $49 million of operating leases entered in 2021, $46 million of finance leases and $127 million of operating leases entered in 2020 and $113 million of finance leases and $44 million of operating leases entered in 2019.

The following table provides supplemental disclosure of cash flow information related to Virginia Power:

Year Ended December 31,	2021		2020		2019
Cash paid during the year for:
Interest and related charges, excluding capitalized amounts	$	501	$	491	$	495
Income taxes		109		452		272
Significant noncash investing activities:(1)(2)
Accrued capital expenditures		363		262		292
Leases (3)		79		32		55

(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 $37 million of finance leases and $42 million of operating leases entered in 2021, $32 million of finance leases entered in, 2020 and $20 million of finance leases and $35 million of operating leases entered in 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 and foreign currency exchange rate risks in their business operations. The Companies use derivative instruments such as physical and financial forwards, futures, swaps, options, foreign currency transactions and FTRs to manage the commodity, interest rate and/or foreign currency exchange 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 $678 million and $19 million associated with cash collateral at December 31, 2021 and 2020, respectively. Dominion Energy had margin liabilities of $5 million associated with cash collateral at December 31, 2020 and no amounts outstanding at December 31, 2021. Virginia Power had margin assets of $167 million and $1 million associated with cash collateral at December 31, 2021 and 2020, respectively. Virginia Power had no margin liabilities associated with cash collateral at December 31, 2021 and 2020. See Note 7 for further information about derivatives.

To manage price and interest rate 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

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represent economic hedges that mitigate their exposure to fluctuations in commodity prices or interest rates. 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 use of 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, or as appropriate to regulatory assets or regulatory liabilities. 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 2021, 2020 and 2019, Dominion Energy capitalized interest costs and AFUDC to property, plant and equipment of $117 million, $103 million and $78 million, respectively. In 2021, 2020 and 2019, Virginia Power capitalized AFUDC to property, plant and equipment of $78 million, $60 million and $34 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 2021, 2020 and 2019, Virginia Power recorded $35 million, $11 million and $11 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:

• 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

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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. In addition, see Note 13 for information on the settlement of the 2021 Triennial Review. Also in 2020, Virginia Power recorded charges of $54 million ($40 million after-tax) associated with dismantling certain of these electric generation facilities.     

• 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.

• 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. In addition, see Note 13 for information on the settlement of the 2021 Triennial Review.

• 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).

• 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:

Year Ended December 31,	2021		2020		2019
(percent)
Dominion Energy(1)
Generation		2.63		2.51		2.84
Transmission		2.47		2.48		2.50
Distribution		2.76		2.76		2.80
Storage		1.79		1.59		1.49
General and other		3.85		4.35		3.99
Virginia Power
Generation		2.69		2.52		2.94
Transmission		2.51		2.52		2.54
Distribution		3.18		3.19		3.14
General and other		5.08		5.09		4.40

(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 January 2022, Dominion Energy revised the estimated useful life of its non-jurisdictional and certain nonregulated solar generation facilities to 35 years.  This revision is expected to result in an annual decrease of depreciation expense of approximately $20 million ($15 million after-tax), including approximately $8 million ($6 million after-tax) at Virginia Power, and increase Dominion Energy’s EPS by approximately $0.02.

Virginia Power’s non-jurisdictional property, plant and equipment is depreciated using the straight-line method over an estimated useful life of 35 years, effective January 2022.

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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 $1.92 and $1.97 per mcfe in 2021 and 2020, respectively.

Dominion Energy’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:

Asset	Estimated Useful Lives
Nonregulated generation-nuclear	44 years
Nonregulated generation-solar	15-35  years
General and other	5-59  years

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 or other benefits 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:

• 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.

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.

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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 or, subject to regulatory framework, is deferred within regulatory assets in the Consolidated Balance Sheets and amortized into the 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 35 years, effective January 2022.

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 of its distribution business 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 and other electric generation and distribution facilities 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.

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Investments

Debt Securities

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.

Credit Impairment

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

Equity Securities with Readily Determinable Fair Values

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. 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

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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.

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 $26 million and $2 million at December 31, 2021 and December 31, 2020, respectively. Based on the average price of gas purchased during 2021 and 2020, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by $74 million and $52 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 guidance became effective for Dominion Energy’s interim and annual reporting periods beginning January 1, 2022. Upon adoption, Dominion Energy will apply the guidance using a modified retrospective approach and will continue to 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. 

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. The Companies applied the 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. Upon entering an agreement to sell substantially all of Dominion Energy’s gas transmission and storage operations in 2020, $43 million of the initially recorded right-of-use assets and liabilities for operating leases were considered activity associated with discontinued operations. See Note 15 for additional information.

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NOTE 3. ACQUISITIONS AND DISPOSITIONS

Dominion Energy

Disposition of Gas Transmission & Storage Operations

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 the Q-Pipe Group 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 would sell the Q-Pipe Group 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 was 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, subsequently extended through June 2023 for certain services. In addition, BHE will provide certain administrative services to Dominion Energy.  Dominion Energy recorded revenue of $21 million and $4 million associated with the transition service agreement in operating revenue in the Consolidated Statements of Income for the years ended December 31, 2021 and 2020, respectively.

Also in November 2020, BHE provided a $1.3 billion deposit to Dominion Energy on the Q-Pipe Transaction.  In July 2021, Dominion Energy and BHE mutually agreed to terminate the Q-Pipe Transaction as a result of uncertainty associated with receiving approval under the Hart-Scott-Rodino Act. Also in July 2021, Dominion Energy entered into an approximately $1.3 billion term loan credit agreement and borrowed the full amount available thereunder. The agreement matured in December 2021 and bore interest at a variable rate. The proceeds were utilized to repay the deposit received from BHE on the Q-Pipe Transaction. Upon completion of a sale of the Q-Pipe Group, Dominion Energy was required to utilize the net proceeds to repay any outstanding balances under the term loan agreement.

In October 2021, Dominion Energy entered into an agreement with Southwest Gas to sell the Q-Pipe Group. The total value of this transaction is approximately $2 billion, comprised of approximately $1.5 billion of cash consideration (subject to customary closing adjustments) plus the assumption of long-term debt. 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 December 2021, Dominion Energy completed the sale of the Q-Pipe Group and received cash proceeds of $1.5 billion. This transaction is structured as an asset sale for tax purposes. Upon closing, Dominion Energy recognized a gain of $666 million (net of a $191 million write-off of goodwill) and an associated tax expense of $173 million, presented in net income (loss) from discontinued operations including noncontrolling interest in Dominion Energy’s Consolidated Statements of Income. Also in December 2021, Dominion Energy used the net proceeds from the sale to repay all outstanding balances under the July 2021 term loan agreement and terminated the term loan agreement.

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In connection with the closing of the sale of the Q-Pipe Group, Dominion Energy and Southwest Gas entered into a transition services agreement under which Dominion Energy will continue to provide specified administrative services to support the operations of the disposed businesses for up to 12 months after closing, subject to extension.

The operations included in both the GT&S Transaction and the Q-Pipe Group 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:

	Year Ended December 31, 2021		Year Ended December 31, 2020						Year Ended December 31, 2019
	Q-Pipe Group(1)		GT&S Transaction(1)			Q-Pipe Group			GT&S Transaction		Q-Pipe Group
(millions)
Operating revenue	$	254	$	1,710		$	246		$	2,213	$	251
Operating expense(2)		76		1,289			96			1,367		131
Other income (loss)(3)		28		88			1			58		4
Interest and related charges(4)		25		372			20			267		20
Income before income taxes		181		137			131			637		104
Income tax expense (benefit)(5)		36		334			(9	)		120		23
Net income (loss) including    noncontrolling interests		145		(197	)		140			517		81
Noncontrolling interests		—		106			—			11		—
Net income (loss) attributable to    Dominion Energy	$	145	$	(303	)	$	140		$	506	$	81

(1) Operations associated with the Q-Pipe Group are through the December 31, 2021 closing date. Operations associated with the GT&S Transaction are through the November 1, 2020 closing 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.

(3) Q-Pipe Group includes a $25 million benefit associated with the termination of the Q-Pipe Transaction in the third quarter of 2021.

(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.

(5) Excludes $17 million income tax benefit recorded in 2021 associated with the GT&S Transaction.

The carrying amounts of major classes of assets and liabilities relating to the Q-Pipe Group, all of which was classified as current and reported as held for sale in Dominion Energy’s Consolidated Balance Sheets at December 31, 2020, were as follows:

(millions)
Current assets(1)	$	47
Equity method investments(2)		35
Property, plant and equipment, net		1,113
Other deferred charges and other assets, including goodwill(3) and intangible assets		224
Current liabilities		30
Long-term debt		426
Other deferred credits and liabilities		154

(1) Includes cash and cash equivalents of $7 million.

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(2) Comprised of equity method investment in White River Hub.

(3) Includes goodwill of $191 million.

Capital expenditures and significant noncash items relating to the disposal groups included the following:

	Year Ended December 31, 2021		Year Ended December 31, 2020				Year Ended December 31, 2019
	Q-Pipe Group(1)		GT&S Transaction(1)		Q-Pipe Group		GT&S Transaction		Q-Pipe Group
(millions)
Capital expenditures	$	34	$	292	$	38	$	386	$	42
Significant noncash items
Impairment of assets and other    charges		—		469		—		13		1
Charge related to a voluntary    retirement program		—		—		—		19		3
Depreciation, depletion and    amortization		—		177		27		322		51
Accrued capital expenditures		—		—		1		25		2

(1) Operations associated with the Q-Pipe Group are through the December 31, 2021 closing date. Operations associated with the GT&S Transaction are through the November 1, 2020 closing 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.

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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. 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

• 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 base rate case;

• PSNC agreed not to file an application for a general rate case with the North Carolina Commission any earlier than April 2021. See Note 13 for information on the status of PSNC’s general rate case;

• 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;

• Dominion Energy will maintain DESC and PSNC’s headquarters in Cayce, South Carolina and Gastonia, North Carolina, respectively; and

• 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 Dominion Energy South Carolina and Gas Distribution. 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.

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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.

	Amount
(millions)
Total current assets(1)		$	1,782
Investments(2)			224
Property, plant and equipment(3)(4)			11,006
Goodwill			2,609
Regulatory assets(5)			3,940
Other deferred charges and other assets, including intangible assets(6)			430
Total Assets			19,991
Total current liabilities(7)			1,556
Long-term debt			6,707
Deferred income taxes			1,068
Regulatory liabilities			2,706
Other deferred credits and other liabilities(8)			1,115
Total Liabilities			13,152
Total purchase price(9)		$	6,839

(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 $3.6 billion, $3.3 billion and $3.1 billion for the years ended December 31, 2021, 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 $287 million and $277 million for the years ended December 31, 2021 and 2020, respectively, and a decrease of $1.1 billion for the year ended December 31, 2019 in the Consolidated Statements of Income.

Dominion Energy incurred merger and integration-related costs of $31 million and $97 million for the years ended December 31, 2021 and 2020, respectively, 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. These costs consist of professional fees, the charitable contribution commitment described above, employee-related expenses, certain financing costs and other miscellaneous costs.

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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.

	Twelve Months Ended
	December 31, 2019(1)
(millions, except EPS)
Operating revenue	$	15,408
Net income attributable to Dominion Energy		3,266
Earnings Per Common Share – Basic	$	4.04
Earnings Per Common Share – Diluted	$	4.00

(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 change in Dominion Energy’s ownership interest in Cove Point was accounted for as an equity transaction and no gain or loss was recognized.  

Sale of Hope

In February 2022, Dominion Energy entered into an agreement to sell 100% of the equity interests in Hope to Ullico for $690 million of cash consideration, subject to customary closing adjustments. The sale will be treated as a stock sale for tax purposes and is expected to close by the end of 2022, contingent on clearance or approval under the Hart-Scott-Rodino Act and from the West Virginia Commission, and other customary closing and regulatory conditions. While Dominion Energy is still completing its evaluation, it does not expect to record a significant gain or loss associated with the sale. Dominion Energy will reclassify the assets and liabilities to be disposed of, currently reflected in Gas Distribution, as held for sale starting in the first quarter of 2022.

Sale of Kewaunee

In May 2021, Dominion Energy entered into an agreement to sell 100% of the equity interests in Dominion Energy Kewaunee, Inc. to EnergySolutions, including the transfer of all decommissioning obligations associated with Kewaunee, which ceased operations in 2013. The agreement provides that Dominion Energy retains the assets and obligations of the pension and other postretirement employee benefit plans.  In addition, Dominion Energy may continue to withdraw funds prior to closing from the nuclear decommissioning trust to recover certain spent nuclear fuel and other permitted costs, subject to certain conditions. The sale will be treated as an asset sale for tax purposes and is subject to termination by either party if not completed by December 2022. Closing is contingent on approval from the Wisconsin Commission as well as the NRC for the transfer of control of applicable licenses.  The purchase agreement requires that EnergySolutions be subject to the Wisconsin regulatory conditions agreed to by Dominion Energy upon its acquisition of Kewaunee, including the return of any excess decommissioning funds to WPSC and WP&L customers following completion of all decommissioning activities.

In May 2021, Dominion Energy and EnergySolutions submitted a license transfer application to the NRC. Also in May 2021, Dominion Energy submitted an application to the Wisconsin Commission for approval. In July 2021, WPSC and WP&L submitted a joint request to the Wisconsin Commission for the waiver of both of their rights of first refusal to purchase Kewaunee, such rights having been granted as the former owners of Kewaunee. At December 31, 2021, Dominion Energy determined that the assets and liabilities associated with the Kewaunee sale, included in Contracted Assets, did not meet the criteria to be classified as held for sale due to the significant uncertainty surrounding the timing of or ability to obtain necessary regulatory approvals.

Dominion Energy expects to record a loss if and when it determines that criteria for the classification as held for sale have been met. If such classification had been made at December 31, 2021, Dominion Energy would have recognized a loss of approximately $725 million ($570 million after-tax). If the sale is ultimately completed, the final net loss will primarily depend on the value of the nuclear decommissioning trust and AROs at closing.

Acquisition of Birdseye

In May 2021, Dominion Energy acquired 100% of the ownership interest in Birdseye from BRE Holdings, LLC for total consideration of $46 million, consisting of $28 million in cash and $18 million, measured at fair value at closing, of consideration contingent on the achievement of certain revenue targets and future development project sales. Birdseye is primarily engaged in the development of solar energy projects in southeastern states in the U.S. with 2.5 GW of solar generation projects under development. The allocation of

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the purchase price resulted in $25 million of development project assets, primarily reflected in other deferred charges and other assets in Dominion Energy’s Consolidated Balance Sheets, and $24 million of goodwill, which is not deductible for tax purposes. The goodwill reflects the value associated with enhancing Dominion Energy's development of regulated and long-term contracted solar generating and electric storage projects. The fair value measurements, including of the assets acquired, were determined using the income approach and 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. Birdseye is included in Contracted Assets.

NOTE 4. OPERATING REVENUE

The Companies’ operating revenue consists of the following:

Year Ended December 31,	2021			2020		2019
(millions)
Dominion Energy
Regulated electric sales:
Residential	$	4,509		$	4,833	$	4,325
Commercial		3,194			3,102		3,219
Industrial		748			730		683
Government and other retail		921			868		873
Wholesale		175			128		176
Nonregulated electric sales		1,005			823		941
Regulated gas sales:
Residential		1,455			1,283		1,343
Commercial		527			457		457
Other		135			88		109
Nonregulated gas sales		96			174		495
Regulated gas transportation and storage		945			801		742
Other regulated revenues		265			327		252
Other nonregulated revenues(1)(2)		195			138		130
Total operating revenue from contracts with customers		14,170			13,752		13,745
Other revenues(3)(4)		(206	)		420		656
Total operating revenue	$	13,964		$	14,172	$	14,401
Virginia Power
Regulated electric sales:
Residential	$	3,366		$	3,677	$	3,657
Commercial		2,417			2,342		2,712
Industrial		367			380		455
Government and other retail		862			804		823
Wholesale		107			90		128
Nonregulated electric sales		44			19		15
Other regulated revenues		234			299		190
Other nonregulated revenues(1)(2)		73			50		56
Total operating revenue from contracts with customers		7,470			7,661		8,036
Other revenues(1)(3)		—			102		72
Total operating revenue	$	7,470		$	7,763	$	8,108

(1) See Notes 9 and 25 for amounts attributable to related parties and affiliates.

(2) Includes sales which are considered to be goods transferred at a point in time of $34 million, $22 million and $37 million for the years ended December 31, 2021, 2020 and 2019, respectively, at Dominion Energy, primarily consisting of sales of commodities related to nonregulated extraction activities and other miscellaneous products. Additionally, sales of renewable energy credits were $33 million, $20 million and $24 million for the years ended December 31, 2021, 2020 and 2019, respectively, at Dominion Energy and $21 million, $11 million and $17 million for the years ended December 31, 2021, 2020 and 2019, respectively, at Virginia Power.

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(3) Includes alternative revenue of $56 million, $119 million and $66 million at Dominion Energy and $44 million, $82 million and $52 million at Virginia Power for years ended December 31, 2021, 2020 and 2019, respectively.

(4) Includes revenue associated with services provided to discontinued operations of $5 million, $4 million and $6 million for the years ended December 31, 2021, 2020 and 2019, respectively.

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.

Revenue expected to be recognized on multi-year    contracts in place at December 31, 2021	2022		2023		2024		2025		2026		Thereafter		Total
(millions)
Dominion Energy(1)	$	68	$	66	$	59	$	51	$	45	$	448	$	737

(1) Includes no amounts for Virginia Power.

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, 2021 and 2020, Dominion Energy’s contract liability balances were $124 million and $130 million, respectively. At December 31, 2021 and 2020, Virginia Power’s contract liability balances were $33 million and $36 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, 2021 and 2020, Dominion Energy recognized revenue of $124 million and $97 million from the beginning contract liability balance. During the years ended December 31, 2021 and 2020, Virginia Power recognized revenue of $36 million and $24 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 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. Under the 2017 Tax Reform Act, deductions for net interest expense are limited to 30% of adjusted taxable income, which has, until this point, been defined similarly to EBITDA (earnings before interest, taxes, depreciation and amortization). For tax years beginning after December 31, 2021, the calculation of adjusted taxable income is defined similarly to EBIT (earnings before interest and taxes). 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.

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Continuing Operations

Details of income tax expense for continuing operations including noncontrolling interests were as follows:

	Dominion Energy									Virginia Power
Year Ended December 31,	2021			2020			2019			2021			2020			2019
(millions)
Current:
Federal	$	(162	)	$	(314	)	$	(94	)	$	67		$	364		$	286
State		45			(81	)		58			(13	)		71			58
Total current expense (benefit)		(117	)		(395	)		(36	)		54			435			344
Deferred:
Federal
Taxes before operating loss carryforwards, investment tax credits and tax reform		151			12			168			145			(226	)		(128	)
Tax utilization expense of operating loss carryforwards		43			44			119			—			—			—
Investment tax credits		250			311			(51	)		(39	)		(27	)		(34	)
State		(19	)		72			(50	)		118			7			22
Total deferred expense (benefit)		425			439			186			224			(246	)		(140	)
Investment tax credit-gross deferral		121			42			62			121			42			62
Investment tax credit-amortization		(4	)		(3	)		(3	)		(2	)		(2	)		(2	)
Total income tax expense	$	425		$	83		$	209		$	397		$	229		$	264

In 2021, Dominion Energy’s current income taxes reflect a benefit from continuing operations as the income tax expense associated with the QPipe Group’s 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 2020, Dominion Energy’s current income taxes reflect a benefit from continuing operations as the 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 $188 million, $(204) million and $142 million for the years ended December 31, 2021, 2020 and 2019, respectively. 2021 income taxes include a $14 million benefit related to finalizing income tax returns on the GT&S Transaction and the absence of a $36 million benefit on non-deductible goodwill written off in connection with the sale of the Q-Pipe Group. 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.

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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:

	Dominion Energy												Virginia Power
Year Ended December 31,	2021				2020				2019				2021				2020				2019
U.S. statutory rate		21.0		%		21.0		%		21.0		%		21.0		%		21.0		%		21.0		%
Increases (reductions) resulting from:
State taxes, net of federal benefit		2.6				2.0				1.5				4.6				4.8				4.5
Investment tax credits		(3.2	)			(9.6	)			(11.4	)			(3.0	)			(4.5	)			(2.9	)
Production tax credits		(0.4	)			(0.7	)			(2.1	)			(0.6	)			(0.7	)			(0.7	)
Valuation allowances		0.1				0.9				0.5				—				—				—
Reversal of excess deferred income     taxes		(3.2	)			(5.4	)			(3.2	)			(2.1	)			(2.2	)			(3.1	)
State legislative change		(0.7	)			—				—				(0.7	)			—				—
Write-off of regulatory assets		—				—				21.7				—				—				—
Change in tax status		—				(1.7	)			(5.5	)			—				—				—
AFUDC—equity		(0.4	)			(0.2	)			(0.2	)			(0.5	)			—				—
Changes in state deferred taxes     associated with assets held for sale		(0.3	)			(3.2	)			—				—				—				—
Absence of tax on noncontrolling     interest		(0.1	)			3.8				(0.2	)			—				—				—
Settlements of uncertain tax positions		(1.2	)			—				—				—				—				—
Employee stock ownership plan     deduction		(0.3	)			(0.9	)			(1.4	)			—				—				—
Nondeductible goodwill		—				—				1.8				—				—				—
Other, net		(0.2	)			(0.1	)			1.5				0.1				(0.1	)			(0.2	)
Effective tax rate		13.7		%		5.9		%		24.0		%		18.8		%		18.3		%		18.6		%

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 2021, 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.

In December 2021, unrecognized tax benefits related to several state uncertain tax positions acquired in the SCANA Combination were effectively settled through negotiations with the taxing authority.  Management believed it was reasonably possible these unrecognized tax benefits could decrease through settlement negotiations or payments during 2021, however no income tax benefits could be recognized unless or until the positions were effectively settled.  Resolution of these uncertain tax positions decreased income tax expense by $38 million. In addition, the Companies’ effective tax rates reflect the benefit of a state legislative change enacted in April 2021 for tax years beginning January 1, 2022. Dominion Energy’s effective tax rate reflects a $21 million deferred tax benefit, inclusive of a $16 million deferred tax benefit at Virginia Power.

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.

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The Companies’ deferred income taxes consist of the following:

	Dominion Energy						Virginia Power
At December 31,	2021			2020			2021			2020
(millions)
Deferred income taxes:
Total deferred income tax assets	$	3,025		$	3,285		$	1,373		$	1,204
Total deferred income tax liabilities		9,397			9,069			4,286			3,832
Total net deferred income tax liabilities	$	6,372		$	5,784		$	2,913		$	2,628
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	$	6,017		$	5,824		$	3,327		$	3,227
Excess deferred income taxes		(1,107	)		(1,142	)		(629	)		(656	)
Unrecovered NND Project costs		508			529			—			—
DESC rate refund		(113	)		(140	)		—			—
Toshiba Settlement		(189	)		(204	)		—			—
Nuclear decommissioning		1,114			991			324			303
Deferred state income taxes		857			702			420			305
Federal benefit of deferred state income taxes		(179	)		(147	)		(88	)		(64	)
Deferred fuel, purchased energy and gas costs		189			(28	)		126			(34	)
Pension benefits		362			239			(119	)		(105	)
Other postretirement benefits		73			(14	)		93			76
Loss and credit carryforwards		(1,571	)		(1,534	)		(537	)		(354	)
Valuation allowances		140			155			6			6
Partnership basis differences		398			593			—			—
Other		(127	)		(40	)		(10	)		(76	)
Total net deferred income tax liabilities	$	6,372		$	5,784		$	2,913		$	2,628
Deferred Investment Tax Credits – Regulated Operations		286			169			270			151
Total Deferred Taxes and Deferred Investment Tax Credits	$	6,658		$	5,953		$	3,183		$	2,779

At December 31, 2021, Dominion Energy had the following deductible loss and credit carryforwards:

	Deductible		Deferred		Valuation			Expiration
	Amount		Tax Asset		Allowance			Period
(millions)
Federal losses	$	965	$	203	$	—		2037
Federal investment credits	—			752	—			2036-2041
Federal production and other credits	—			63	—			2036-2041
State losses		4,583		243		(50	)	2022-2041
State minimum tax credits	—			214	—			No expiration
State investment and other credits	—			129		(90	)	2022-2031
Total	$	5,548	$	1,604	$	(140	)

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At December 31, 2021, Virginia Power had the following deductible loss and credit carryforwards:

	Deductible		Deferred		Valuation			Expiration
	Amount		Tax Asset		Allowance			Period
(millions)
Federal losses	$	—	$	—	$	—
Federal investment credits	—			467	—			2036-2041
Federal production and other credits	—			62	—			2036-2041
State investment and other credits	—			8		(6	)	2024
Total	$	—	$	537	$	(6	)

A reconciliation of changes in the Companies’ unrecognized tax benefits follows:

	Dominion Energy											Virginia Power
	2021			2020			2019					2021		2020		2019
(millions)
Balance at January 1	$	167		$	175		$	44				$	—	$	—	$	2
Acquired unrecognized tax benefits		—			—			129		(1	)		—		—		—
Increases-prior period positions		48			18			—					—		—		—
Decreases-prior period positions		(59	)		(19	)		—					—		—		—
Increases-current period positions		2			1			9					—		—		—
Settlements with tax authorities		(26	)		—			(7	)				—		—		(2	)
Expiration of statutes of limitations		(4	)		(8	)		—					—		—		—
Balance at December 31	$	128		$	167		$	175				$	-	$	—	$	-

(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 $72 million, $140 million and $141 million at December 31, 2021, 2020 and 2019, respectively. In discontinued operations, these unrecognized tax benefits were $33 million at December 31, 2021. For Dominion Energy, the change in these unrecognized tax benefits decreased income tax expense by $34 million and $6 million in 2021 and 2020, respectively, and increased income tax expense by $3 million in 2019. 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 2019. For Virginia Power, these unrecognized tax benefits were less than $1 million at December 31, 2019. For Virginia Power, the change in these unrecognized tax benefits decreased income tax expense by $2 million in 2019.

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. The IRS has completed its audit of tax years through 2019. The statute of limitations has not yet expired for years after 2017. Although Dominion Energy has not received a final letter indicating no changes to its taxable income for tax year 2020, no material adjustments are expected. The IRS examination of tax year 2021 is ongoing.

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It is reasonably possible that settlement negotiations and expiration of statutes of limitations could result in a decrease in unrecognized tax benefits in 2022 by up to $23 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 $9 million for Dominion Energy. Otherwise, with regard to 2021 and prior years, the Companies cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2022.

For each of the major states in which Dominion Energy operates, the earliest tax year remaining open for examination is as follows:

	Earliest
	Open Tax
State	Year
Pennsylvania(1)	2012
Connecticut	2018
Virginia(2)	2018
Utah	2018
South Carolina	2018

(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/or foreign currency exchange rate derivative instruments, and other investments including those held in nuclear decommissioning, 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, interest rate and/or foreign currency exchange 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.

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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 exchange rate derivative contracts:

• Foreign currency forward exchange rates

• Interest rates

• Credit quality of counterparties and the Companies

• Notional value

• Time value

For investments:

• Quoted securities prices and indices

• Securities trading information including volume and restrictions

• Maturity

• Interest rates

• Credit quality of counterparties and the Companies

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.

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• 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, foreign currency exchange rate instruments 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 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, 2021. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range	Weighted Average(1)
Assets
Physical and financial forwards:
Natural gas(2)	$	54	Discounted cash flow	Market price (per Dth)	(3)	(2)-8		(1	)
FTRs		51	Discounted cash flow	Market price (per MWh)	(3)	(2)-11		2
Electricity		120	Discounted cash flow	Market price (per MWh)	(3)	28-72		43
Physical options:
Natural gas		5	Option model	Market price (per Dth)	(3)	3-9		6
				Price volatility	(4)	19% - 27%		24	%
Total assets	$	230
Liabilities
Physical and financial forwards:
Natural gas(2)	$	3	Discounted cash flow	Market price (per Dth)	(3)	(2)-4		(1	)
FTRs		5	Discounted cash flow	Market price (per MWh)	(3)	(3)-7		1
Total liabilities	$	8

(1) Averages weighted by volume.

(2) Includes basis.  

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(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:

Significant Unobservable Inputs	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)
Price volatility	Buy	Increase (decrease)	Gain (loss)
Price volatility	Sell	Increase (decrease)	Loss (gain)

Nonrecurring Fair Value Measurements

Dominion Energy

See Note 3 for information on the nonrecurring fair value measurement associated with the acquisition of Birdseye. 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 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.

In 2021, Dominion Energy recorded a charge of $20 million ($15 million after-tax) in impairment of assets and other charges in its Consolidated Statements of Income (reflected in the Corporate and Other segment) to write off substantially all of the long-lived assets of its nonregulated retail software development operations to their estimated fair value, using a market approach, of less than $1 million. The valuation is considered a Level 2 fair value measurement given that it is based on bids received.  

In 2021, Dominion Energy recorded a charge of $16 million ($12 million after-tax) in impairment of assets and other charges in its Consolidated Statements of Income to adjust a corporate office building down to its estimated fair value, using both an income and market approach, of $26 million. The valuation is considered a Level 3 measurement due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates inherent in the future cash flows and market prices. The corporate office building is reflected in the Corporate and Other segment and presented as held for sale in Dominion Energy’s Consolidated Balance Sheets at December 31, 2021.

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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:

	Level 1			Level 2		Level 3		Total
(millions)
December 31, 2021
Assets
Derivatives:
Commodity	$	—		$	52	$	230	$	282
Interest rate		—			323		—		323
Foreign currency exchange rate		—			8		—		8
Investments(1):
Equity securities:
U.S.		5,241			—		—		5,241
Fixed income:
Corporate debt instruments		—			881		—		881
Government securities		199			1,256		—		1,455
Cash equivalents and other		(29	)		—		—		(29	)
Total assets	$	5,411		$	2,520	$	230	$	8,161
Liabilities
Derivatives:
Commodity	$	—		$	461	$	8	$	469
Interest rate		—			399		—		399
Total liabilities	$	—		$	860	$	8	$	868
December 31, 2020
Assets
Derivatives:
Commodity	$	—		$	57	$	110	$	167
Interest rate		—			230		—		230
Investments(1):
Equity securities:
U.S.		4,648			—		—		4,648
Fixed income:
Corporate debt instruments		—			629		—		629
Government securities		508			730		—		1,238
Cash equivalents and other		32			15		—		47
Total assets	$	5,188		$	1,661	$	110	$	6,959
Liabilities
Derivatives:
Commodity	$	—		$	48	$	7	$	55
Interest rate		—			431		—		431
Total liabilities	$	—		$	479	$	7	$	486

(1) Includes investments held in the nuclear decommissioning trusts and rabbi trusts. Excludes $366 million and $340 million of assets at December 31, 2021 and 2020, 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.

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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:

	2021			2020			2019
(millions)
Balance at January 1,	$	103		$	(37	)	$	64
Total realized and unrealized gains (losses):
Included in earnings:
Operating Revenue		(9	)		—			(1	)
Electric fuel and other energy-related purchases		10			(33	)		(22	)
Purchased gas		—			—			2
Discontinued operations		—			1			—
Included in regulatory assets/liabilities		119			140			(90	)
Settlements		(10	)		33			17
Purchases		—			—			(10	)
Sales		—			(1	)		6
Transfers out of Level 3		9			—			(3	)
Balance at December 31,	$	222		$	103		$	(37	)

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, 2021, 2020 and 2019.

Virginia Power

The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at December 31, 2021. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range	Weighted Average(1)
Assets
Physical and financial forwards:
Natural gas(2)	$	54	Discounted cash flow	Market price (per Dth)	(3)	(2)-6		(1	)
FTRs		51	Discounted cash flow	Market price (per MWh)	(3)	(2)-11		2
Physical options:
Natural gas		5	Option model	Market price (per Dth)	(3)	3-9		6
				Price volatility	(4)	19% - 27%		24	%
Total assets	$	110
Liabilities
Physical and financial forwards:
Natural gas(2)	$	3	Discounted cash flow	Market price (per Dth)	(3)	(2)-4		(1	)
FTRs		5	Discounted cash flow	Market price (per MWh)	(3)	(3)-7		1
Total liabilities	$	8

(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.

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Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

Significant Unobservable Inputs	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)
Price volatility	Buy	Increase (decrease)	Gain (loss)
Price volatility	Sell	Increase (decrease)	Loss (gain)

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:

	Level 1			Level 2		Level 3		Total
(millions)
December 31, 2021
Assets
Derivatives:
Commodity	$	—		$	36	$	110	$	146
Interest rate		—			146		—		146
Foreign currency exchange rate		—			8		—		8
Investments(1):
Equity securities:
U.S.		2,420			—		—		2,420
Fixed income:
Corporate debt instruments		—			531		—		531
Government securities		93			506		—		599
Cash equivalents and other		(3	)		—		—		(3	)
Total assets	$	2,510		$	1,227	$	110	$	3,847
Liabilities
Derivatives:
Commodity	$	—		$	125	$	8	$	133
Interest rate		—			337		—		337
Total liabilities	$	—		$	462	$	8	$	470
December 31, 2020
Assets
Derivatives:
Commodity	$	—		$	5	$	110	$	115
Interest rate		—			66		—		66
Investments(1):
Equity securities:
U.S.		2,171			—		—		2,171
Fixed income:
Corporate debt instruments		—			348		—		348
Government securities		201			309		—		510
Cash equivalents and other		13			—		—		13
Total assets	$	2,385		$	728	$	110	$	3,223
Liabilities
Derivatives:
Commodity	$	—		$	22	$	7	$	29
Interest rate		—			376		—		376
Total liabilities	$	—		$	398	$	7	$	405

(1) Includes investments held in the nuclear decommissioning trusts. Excludes $185 million and $167 million of assets at December 31, 2021 and 2020, 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.

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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:

	2021			2020			2019
(millions)
Balance at January 1,	$	103		$	(37	)	$	60
Total realized and unrealized gains (losses):
Included in earnings:
Electric fuel and other energy-related purchases		4			(33	)		(22	)
Included in regulatory assets/liabilities		(1	)		140			(88	)
Settlements		(4	)		33			13
Balance at December 31,	$	102		$	103		$	(37	)

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, 2021, 2020 and 2019.

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:

December 31,	2021				2020
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair  Value(1)
(millions)
Dominion Energy
Long-term debt(2)(3)	$	35,996	$	40,947	$	31,996	$	38,773
Supplemental 364-Day credit facility borrowings		—		—		225		225
Junior subordinated notes(4)		1,386		1,470		3,411		3,633
Virginia Power
Long-term debt(4)	$	13,753	$	16,021	$	13,207	$	16,455

(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 and discount or premium. At December 31, 2021 and December 31, 2020, the carrying amount includes the valuation of certain fair value hedges associated with fixed rate debt of $2 million and $3 million, respectively.

(3) Includes amounts classified as held for sale at December 31, 2020, 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. In February 2022, Dominion Energy entered into contracts representing offsetting positions to certain existing exchange contracts with collateral requirements as

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well as new over-the-counter transactions that are not subject to collateral requirements. These contracts resulted in positions which limit the risk of increased cash collateral requirements. 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:

	December 31, 2021								December 31, 2020
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	153	$	13	$	—	$	140	$	117	$	9	$	—	$	108
Exchange		9		7		—		2		49		24		—		25
Interest rate contracts:
Over-the-counter		323		49		—		274		230		13		—		217
Foreign currency exchange rate contracts:
Over-the-counter		8		—		—		8		—		—		—		—
Total derivatives, subject to a    master netting or similar    arrangement	$	493	$	69	$	—	$	424	$	396	$	46	$	—	$	350

(1) Excludes $120 million and $1 million of derivative assets at December 31, 2021 and 2020, respectively, which are not subject to master netting or similar arrangements.

	December 31, 2021								December 31, 2020
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	95	$	13	$	54	$	28	$	30	$	9	$	—	$	21
Exchange		374		7		367		—		24		24		—		—
Interest rate contracts:
Over-the-counter		399		49		11		339		431		13		17		401
Total derivatives, subject to a    master netting or similar    arrangement	$	868	$	69	$	432	$	367	$	485	$	46	$	17	$	422

(1) Excludes $1 million of derivative liabilities at December 31, 2020 which are not subject to master netting or similar arrangements.

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Volumes

The following table presents the volume of Dominion Energy’s derivative activity as of December 31, 2021. 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.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price(1)		34		5
Basis		156		446
Electricity (MWh in millions):
Fixed price		15		31
FTRs		44		—
Interest rate(2) (in millions)	$	1,537	$	9,859
Foreign currency exchange rate(2) (in millions)	501 kr.		4,581 kr.

(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 Dominion Energy’s Consolidated Balance Sheets at December 31, 2021:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Interest rate	$	(358	)	$	(40	)	396 months
Total	$	(358	)	$	(40	)

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest rate payments) 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 interest rates.

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. There were no derivative instruments designated as fair value hedges during the twelve months ended December 31, 2021 and 2020. Gains and losses on derivative fair value hedge relationships were immaterial for the year ended December 31, 2019.

The following table presents the amounts recorded on the Consolidated Balance Sheets related to cumulative basis adjustments for fair value hedges all of which related to discontinued hedging relationships at both December 31, 2021 and 2020, respectively:

	Carrying Amount of the Hedged Asset (Liability)						Cumulative Amount of Fair Value Hedging Adjustments Included in the Carrying Amount of the Hedged Assets (Liabilities)
	December 31, 2021			December 31, 2020			December 31, 2021			December 31, 2020
(millions)
Long-term debt	$	(352	)	$	(1,153	)	$	(2	)	$	(3	)

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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:

	Fair Value – Derivatives under Hedge  Accounting		Fair Value – Derivatives not under Hedge  Accounting		Total Fair Value
(millions)
At December 31, 2021
ASSETS
Current Assets
Commodity	$	—	$	103	$	103
Interest rate		1		17		18
Foreign currency exchange rate		—		1		1
Total current derivative assets(1)		1		121		122
Noncurrent Assets
Commodity		—		179		179
Interest rate		145		160		305
Foreign currency exchange rate		—		7		7
Total noncurrent derivative assets(2)		145		346		491
Total derivative assets	$	146	$	467	$	613
LIABILITIES
Current Liabilities
Commodity	$	—	$	304	$	304
Interest rate		42		13		55
Total current derivative liabilities(3)		42		317		359
Noncurrent Liabilities
Commodity		—		165		165
Interest rate		295		49		344
Total noncurrent derivative liabilities(4)		295		214		509
Total derivative liabilities	$	337	$	531	$	868
At December 31, 2020
ASSETS
Current Assets
Commodity	$	—	$	58	$	58
Interest rate		—		9		9
Total current derivative assets(1)		—		67		67
Noncurrent Assets
Commodity		—		109		109
Interest rate		66		155		221
Total noncurrent derivative assets(2)		66		264		330
Total derivative assets	$	66	$	331	$	397
LIABILITIES
Current Liabilities
Commodity	$	—	$	42	$	42
Interest rate		363		10		373
Total current derivative liabilities(3)		363		52		415
Noncurrent Liabilities
Commodity		—		13		13
Interest rate		19		39		58
Total noncurrent derivative liabilities(4)		19		52		71
Total derivative liabilities	$	382	$	104	$	486

(1) At December 31, 2021, all current derivative assets are presented in other current assets in Dominion Energy’s Consolidated Balance Sheets. At December 31, 2020, $63 million is included in other current assets and the remainder is recorded in current assets held for sale.

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(2) At December 31, 2021, all noncurrent derivative assets are presented in other deferred charges and other assets in Dominion Energy’s Consolidated Balance Sheets. At December 31, 2020, $330 million is included in other deferred charges and other assets and the remainder is recorded in noncurrent assets held for sale.

(3) At December 31, 2021, all current derivative liabilities are presented in other current liabilities in Dominion Energy’s Consolidated Balance Sheets. At December 31, 2020, $412 million is included in other current liabilities and the remainder is recorded in current liabilities held for sale.

(4) At December 31, 2021, all noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Energy’s Consolidated Balance Sheets. At December 31, 2020, $71 million is included in other deferred credits and other liabilities and the remainder is recorded in noncurrent liabilities held for sale.

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:

Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives(1)			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Year Ended December 31, 2021
Derivative type and location of gains (losses):
Commodity(3):				$	(1	)
Interest rate(4)	$	21			(60	)	$	135
Total	$	21		$	(61	)	$	135
Year Ended December 31, 2020
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	25
Purchased gas					(4	)
Discontinued operations					2
Total commodity	$	—		$	23		$	—
Interest rate:
Interest and related charges				$	(83	)
Discontinued operations					(236	)
Total interest rate	$	(309	)	$	(319	)	$	(332	)
Foreign currency exchange rate(5)		(11	)		(6	)		—
Total	$	(320	)	$	(302	)	$	(332	)
Year Ended December 31, 2019
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	142
Purchased gas					(3	)
Discontinued operations					4
Total commodity	$	125		$	143		$	—
Interest rate:
Interest and related charges				$	(49	)
Discontinued operations					(5	)
Total interest rate	$	(252	)	$	(54	)	$	(255	)
Foreign currency exchange rate(5)		(18	)		(6	)		—
Total	$	(145	)	$	83		$	(255	)

(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 purchased gas.

(4) Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in interest and related charges.

(5) Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in discontinued operations.

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Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2021			2020			2019
(millions)
Derivative type and location of gains (losses):
Commodity:
Operating revenue	$	(487	)	$	73		$	41
Purchased gas		(1	)		(20	)		(22	)
Electric fuel and other energy-related purchases		16			(104	)		(46	)
Discontinued operations		—			(11	)		(2	)
Interest rate:
Interest and related charges		97			87			3
Discontinued operations		—			5			—
Foreign currency exchange rate:
Discontinued operations		—			12			—
Total	$	(375	)	$	42		$	(26	)

(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:

	December 31, 2021								December 31, 2020
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	110	$	8	$	—	$	102	$	111	$	6	$	—	$	105
Exchange		7		7		—		—		1		1		—		—
Interest rate contracts:
Over-the-counter		146		20		—		126		66		7		—		59
Foreign currency exchange rate contracts:
Over-the-counter		8		—		—		8		—		—		—		—
Total derivatives, subject to a    master netting or similar    arrangement	$	271	$	35	$	—	$	236	$	178	$	14	$	—	$	164

(1) Excludes $29 million and $3 million of derivative assets at December 31, 2021 and 2020, respectively, which are not subject to master netting or similar arrangements.

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	December 31, 2021								December 31, 2020
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	84	$	8	$	54	$	22	$	6	$	6	$	—	$	—
Exchange		43		7		36		—		1		1		—		—
Interest rate contracts:
Over-the-counter		337		20		—		317		376		7		—		369
Total derivatives, subject to a    master netting or similar    arrangement	$	464	$	35	$	90	$	339	$	383	$	14	$	—	$	369

(1) Excludes $6 million and $22 million of derivative liabilities at December 31, 2021 and 2020, 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, 2021. 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.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price(1)		24		5
Basis		139		440
Electricity (MWh in millions):
Fixed price		6		7
FTRs		44		—
Interest rate(2) (in millions)	$	1,000	$	1,750
Foreign currency exchange rate(2) (in millions)	501 kr.		4,581 kr.

(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, 2021:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Interest rate	$	(45	)	$	(2	)	396 months
Total	$	(45	)	$	(2	)

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.

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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:

	Fair Value – Derivatives under Hedge  Accounting		Fair Value – Derivatives not under Hedge  Accounting		Total Fair Value
(millions)
At December 31, 2021
ASSETS
Current Assets
Commodity	$	—	$	74	$	74
Interest rate		1		—		1
Foreign currency exchange rate		—		1		1
Total current derivative assets(1)		1		75		76
Noncurrent Assets
Commodity		—		72		72
Interest rate		145		—		145
Foreign currency exchange rate		—		7		7
Total noncurrent derivative assets(2)		145		79		224
Total derivative assets	$	146	$	154	$	300
LIABILITIES
Current Liabilities
Commodity	$	—	$	92	$	92
Interest rate		42		—		42
Total current derivative liabilities		42		92		134
Noncurrent Liabilities
Commodity		—		41		41
Interest rate		295		—		295
Total noncurrent derivatives liabilities(3)		295		41		336
Total derivative liabilities	$	337	$	133	$	470
At December 31, 2020
ASSETS
Current Assets
Commodity	$	—	$	22	$	22
Total current derivative assets(1)		—		22		22
Noncurrent Assets
Commodity		—		93		93
Interest rate		66		—		66
Total noncurrent derivative assets(2)		66		93		159
Total derivative assets	$	66	$	115	$	181
LIABILITIES
Current Liabilities
Commodity	$	—	$	28	$	28
Interest rate		362		—		362
Total current derivative liabilities		362		28		390
Noncurrent Liabilities
Commodity		—		1		1
Interest rate		14		—		14
Total noncurrent derivatives liabilities(3)		14		1		15
Total derivative liabilities	$	376	$	29	$	405

(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.

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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:

Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives(1)			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Year Ended December 31, 2021
Derivative type and location of gains (losses):
Interest rate(3)	$	17		$	(3	)	$	130
Total	$	17		$	(3	)	$	130
Year Ended December 31, 2020
Derivative type and location of gains (losses):
Interest rate(3)	$	(37	)	$	(2	)	$	(338	)
Total	$	(37	)	$	(2	)	$	(338	)
Year Ended December 31, 2019
Derivative type and location of gains (losses):
Interest rate(3)	$	(30	)	$	(1	)	$	(259	)
Total	$	(30	)	$	(1	)	$	(259	)

(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.

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2021			2020			2019
(millions)
Derivative type and location of gains (losses):
Commodity:
Operating revenue	$	(62	)	$	(104	)	$	(45	)
Electric fuel and other energy-related purchases		9			—			—
Total	$	(53	)	$	(104	)	$	(45	)

(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.

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NOTE 8. EARNINGS PER SHARE

The following table presents the calculation of Dominion Energy’s basic and diluted EPS:

	2021			2020			2019
(millions, except EPS)
Net income attributable to Dominion Energy from continuing operations	$	2,647		$	1,583		$	653
Preferred stock dividends (see Note 19)		(68	)		(65	)		(17	)
Net income attributable to Dominion Energy from continuing operations - Basic		2,579			1,518			636
Dilutive effect of Series A Preferred Stock		—			(11	)		(28	)
Net income attributable to Dominion Energy from continuing operations - Diluted		2,579		$	1,507		$	608
Net income (loss) attributable to Dominion Energy from discontinued operations -     Basic & Diluted		641		$	(1,984	)	$	705
Average shares of common stock outstanding – Basic		807.8			831.0			808.8
Net effect of dilutive securities(1)		0.7			—			0.1
Average shares of common stock outstanding – Diluted		808.5			831.0			808.9
EPS from continuing operations - Basic	$	3.19		$	1.83		$	0.79
EPS from discontinued operations - Basic		0.79			(2.39	)		0.87
EPS attributable to Dominion Energy - Basic	$	3.98		$	(0.56	)	$	1.66
EPS from continuing operations - Diluted		3.19		$	1.82		$	0.75
EPS from discontinued operations - Diluted		0.79			(2.39	)		0.87
EPS attributable to Dominion Energy - Diluted	$	3.98		$	(0.57	)	$	1.62

(1) Dilutive securities for 2021 consist primarily of stock expected to be issued to satisfy the obligation under a settlement agreement with the SCDOR (applying the if converted method) as well as forward sales agreements entered into in November 2021 (applying the treasury stock method). See Notes 20 and 23 for additional information.

The 2019 Equity Units, the Q-Pipe Transaction deposit, prior to being settled in cash in July 2021 and the 2016 Equity Units, prior to being settled via stock issuances in August 2019, are potentially dilutive instruments. See Notes 3, 18 and 19 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, 2021, 2020 and 2019 as the dilutive stock price threshold was not met. The Series A Preferred Stock included within the 2019 Equity Units is excluded from the effect of dilutive securities within diluted EPS from continuing operations, but a fair value adjustment is reflected within net income attributable to Dominion Energy from continuing operations for the calculation of diluted EPS from continuing operations for the years ended December 31, 2020 and 2019, based upon the expectation that the conversion will be settled in cash rather than through the issuance of Dominion Energy common stock. As described in Note 19, effective November 2021 any settlement of the conversion up to $1,000 per share is payable in cash, and any amount in excess of $1,000 per share may be settled in cash, common stock or a combination thereof. For the year ended December 31, 2021, a fair value adjustment related to the Series A Preferred Stock included within the 2019 Equity Units is excluded from the calculation of diluted EPS from continuing operations, as such fair value adjustment was not dilutive during the period.

The impact of settling the deposit associated with the Q-Pipe Transaction in shares is excluded from the calculation for the years ending December 31, 2021 and 2020 based upon the expectation Dominion Energy would settle in cash, which occurred in July 2021, rather than through the issuance of shares 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 year ended December 31, 2019 as the dilutive stock price threshold was not met.

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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 $122 million and $134 million at December 31, 2021 and 2020, 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:

	Amortized Cost			Total Unrealized Gains		Total Unrealized Losses				Allowance for Credit Losses		Fair Value
(millions)
December 31, 2021
Equity securities:(1)
U.S.	$	1,567		$	3,734	$	(13	)				$	5,288
Fixed income securities:(2)
Corporate debt instruments		854			32		(5	)		$	—		881
Government securities		1,382			43		(7	)			—		1,418
Common/collective trust funds		168			4		—				—		172
Insurance contracts		255			—		—						255
Cash equivalents and other(3)		9			2		(75	)			—		(64	)
Total	$	4,235		$	3,815	$	(100	)	(4)	$	—	$	7,950
December 31, 2020
Equity securities:(1)
U.S.	$	1,756		$	2,948	$	(24	)				$	4,680
Fixed income securities:(2)
Corporate debt instruments		572			58		(1	)		$	—		629
Government securities		1,119			66		(1	)			—		1,184
Common/collective trust funds		170			5		—				—		175
Insurance contracts		237			—		—						237
Cash equivalents and other(3)		(8	)		4		(1	)			—		(5	)
Total	$	3,846		$	3,081	$	(27	)	(4)	$	—	$	6,900

(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. Changes in allowance for credit losses are included in other income.

(3) Includes pending purchases of securities of $35 million and $49 million at December 31, 2021 and 2020, respectively.

(4) The fair value of securities in an unrealized loss position was $883 million and $293 million at December 31, 2021 and 2020, respectively.

The portion of unrealized gains and losses that relates to equity securities held within Dominion Energy’s nuclear decommissioning trusts is summarized below:

Year Ended December 31,	2021			2020			2019
(millions)
Net gains (losses) recognized during the period	$	1,072		$	512		$	919
Less: Net gains recognized during the period    on securities sold during the period		(346	)		(16	)		(80	)
Unrealized gains (losses) recognized during the period    on securities still held at period end(1)	$	726		$	496		$	839

(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, 2021 by contractual maturity is as follows:

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	Amount
(millions)
Due in one year or less	$	331
Due after one year through five years		642
Due after five years through ten years		630
Due after ten years		868
Total	$	2,471

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.

Year Ended December 31,	2021		2020		2019
(millions)
Proceeds from sales	$	3,985	$	4,278	$	1,712
Realized gains(1)		441		340		195
Realized losses(1)		91		297		96

(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:

	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses				Allowance for Credit Losses		Fair Value
(millions)
December 31, 2021
Equity securities:(1)
U.S.	$	841	$	1,720	$	(11	)				$	2,550
Fixed income securities:(2)
Corporate debt instruments		517		17		(3	)		$	—		531
Government securities		584		16		(2	)			—		598
Common/collective trust funds		53		—		—				—		53
Cash equivalents and other(3)		2		—		—				—		2
Total	$	1,997	$	1,753	$	(16	)	(4)	$	—	$	3,734
December 31, 2020
Equity securities:(1)
U.S.	$	929	$	1,371	$	(21	)				$	2,279
Fixed income securities:(2)
Corporate debt instruments		315		33		—			$	—		348
Government securities		484		25		—				—		509
Common/collective trust funds		58		—		—				—		58
Cash equivalents and other(3)		3		—		—				—		3
Total	$	1,789	$	1,429	$	(21	)	(4)	$	—	$	3,197

(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. Changes in allowance for credit losses are included in other income.

(3) Includes pending sales of securities of $5 million at December 31, 2021, and pending purchases of securities of $10 million at December 31, 2020.

(4) The fair value of securities in an unrealized loss position was $425 million and $142 million at December 31, 2021 and 2020, respectively.

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The portion of unrealized gains and losses that relates to equity securities held within Virginia Power’s nuclear decommissioning trusts is summarized below:

Year Ended December 31,	2021			2020			2019
(millions)
Net gains (losses) recognized during the period	$	552		$	224		$	423
Less: Net gains recognized during the period    on securities sold during the period		(190	)		(6	)		(20	)
Unrealized gains (losses) recognized during the period    on securities still held at end of period (1)	$	362		$	218		$	403

(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, 2021, by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	78
Due after one year through five years		335
Due after five years through ten years		361
Due after ten years		408
Total	$	1,182

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.

Year Ended December 31,	2021		2020		2019
(millions)
Proceeds from sales	$	1,791	$	884	$	858
Realized gains(1)		228		88		58
Realized losses(1)		35		68		22

(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:

					Investment
Company	Ownership%				Balance						Description
As of  December 31,					2021			2020
(millions)
Cove Point		50	%		$	2,738		$	2,784		LNG import/export and storage facility
Atlantic Coast Pipeline		53	%			—	(3)		—	(3)	Gas transmission system
Wrangler		15	%	(2)		68			74		Nonregulated retail energy marketing
Align RNG(1)		50	%			74			25		Renewable natural gas
Other	various					52			51
Total					$	2,932		$	2,934

(1) Dominion Energy’s unfunded commitment to be made to Align RNG by the end of 2022 was $8 million and $59 million at December 31, 2021 and 2020, respectively. The commitment was fully paid in January 2022.

(2) Dominion Energy’s ownership interest became 15% in December 2021, following the sale of 5% of its ownership interest. See discussion below.

(3) Dominion Energy’s Consolidated Balance Sheets include a liability associated with its investment in Atlantic Coast Pipeline of $113 million and $1.1 billion at December 31, 2021 and 2020, respectively. See discussion below for additional information.

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Dominion Energy recorded equity earnings on its investments of $276 million, $40 million and $8 million in 2021, 2020 and 2019, respectively, in its Consolidated Statements of Income. In addition, Dominion Energy recorded equity earnings (losses) of $(20) million, $(2.3) billion and $117 million in 2021, 2020 and 2019, respectively, in discontinued operations related to its investment in Atlantic Coast Pipeline.  Dominion Energy received distributions from these investments of $328 million, $102 million and $38 million in 2021, 2020 and 2019, respectively. As of December 31, 2021 and 2020, the net difference between the carrying amount of Dominion Energy’s investments and its share of underlying equity in net assets was $244 million and $213 million, respectively.  At December 31, 2021, these differences are comprised of $27 million of equity method goodwill that is not being amortized, $221 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 $(4) million basis difference primarily attributable to an unfunded commitment made to Align RNG. 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.

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 by Cove Point), in which Dominion Energy owned a controlling financial interest and consolidated. As discussed in Note 20, Dominion Energy acquired all of the 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 interest 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 2021, 2020 and 2019 was $528 million, $511 million and $471 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, earnings attributable to Dominion Energy are presented within earnings from equity method investees in its Consolidated Statements of Income. In 2020, earnings attributable to Dominion Energy of $40 million are presented within earnings from equity method investees in its Consolidated Statements of Income.

Dominion Energy recorded distributions from Cove Point of $300 million and $70 million in 2021 and 2020 (after the date of disposal), respectively. Dominion Energy made no contributions to Cove Point in 2021 or 2020 (after the date of disposal).

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 accounted for 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.

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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 ongoing 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 recorded equity method earnings (losses) of $(2.3) billion ($(1.8) billion after-tax) for the year ended December 31, 2020, as a result of the determination of the probable abandonment of the Atlantic Coast Pipeline Project in June 2020, and $(20) million ($(14) million after-tax) and $117 million ($118 million after-tax) for the year ended December 31, 2021 and 2019, respectively. 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, 2021 and 2020 includes a liability of $113 million and $1.1 billion, respectively, which reflects Dominion Energy’s obligations to Atlantic Coast Pipeline related to its credit facility, through February 2021, 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. In July 2020, the capacity of the revolving credit facility was reduced from $3.4 billion to $1.9 billion.  In February 2021, Atlantic Coast Pipeline repaid the outstanding borrowed amounts and terminated its revolving credit facility.  Concurrently, Dominion Energy’s related guarantee agreement to support its portion of the Atlantic Coast Pipeline’s borrowings was also terminated.  As of December 31, 2020, Atlantic Coast Pipeline had borrowed $1.8 billion against the revolving credit facility. Dominion Energy’s Consolidated Balance Sheets include a liability of $6 million associated with this guarantee agreement at December 31, 2020. 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 $965 million, $107 million and $186 million during 2021, 2020 and 2019, respectively, to Atlantic Coast Pipeline.

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 and $103 million in 2020 (prior to closing of the GT&S Transaction) and 2019, respectively, included in discontinued operations in Dominion Energy’s Consolidated Statements of Income.

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. In the first quarter of 2019, Dominion Energy received $151 million of additional consideration, including applicable interest, in connection with this sale. 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. Blue Racer did not achieve the 2019, 2020 or 2021 financial performance milestones set forth in the sale agreement.

All activity relating to Blue Racer is recorded within the Corporate and Other segment.  

Fowler Ridge

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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.  At December 31, 2021 Dominion Energy has a 15% 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 losses (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 losses (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.

The final contribution, consisting of Dominion Energy’s remaining nonregulated natural gas retail energy marketing operations, closed in December 2021 for which Dominion Energy received $127 million in cash proceeds and retained a 20% noncontrolling ownership interest in Wrangler with an initial fair value of $23 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 $87 million, net of a $14 million write-off of goodwill, presented in losses (gains) on sales of assets, and an associated tax expense of $32 million, in the Consolidated Statements of Income for the year ended December 31, 2021.

Subsequently in December 2021, Dominion Energy sold 5% of its noncontrolling ownership interest in Wrangler to Interstate Gas Supply, Inc. for $33 million and recorded a gain of $10 million, presented in other income, and an associated tax expense of $3 million, in the Consolidated Statements of Income for the year ended December 31, 2021.

At December 31, 2020, $63 million of assets and $15 million of liabilities associated with the remaining nonregulated retail energy marketing operations 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.

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Dominion Privatization

In February 2022, Dominion Energy entered into an agreement to form Dominion Privatization, a partnership with Patriot. Dominion Privatization, through its wholly-owned subsidiaries, will maintain and operate electric and gas distribution infrastructure under service concession arrangements with certain U.S. military installations. Under the agreement, Dominion Energy will contribute its existing privatization operations, excluding contracts held by DESC, in South Carolina, Texas, Pennsylvania and Virginia and Patriot will contribute cash. The contribution of the service concession arrangements currently held by Virginia Power requires approval from the Virginia and North Carolina Commissions. Dominion Energy expects to receive cash proceeds totaling $168 million, subject to customary closing adjustments, and a 50% noncontrolling ownership interest in Dominion Privatization following closing of the contributions expected to occur by the end of 2022, contingent on clearance or approval under the Hart-Scott-Rodino Act and other customary closing and regulatory conditions. Dominion Energy expects to recognize gains totaling approximately $150 million ($110 million after-tax) upon closing of the contributions. Dominion Energy’s 50% noncontrolling ownership interest in Dominion Privatization will be accounted for as an equity method investment as Dominion Energy has the ability to exercise significant influence, but not control, over the investee.

All activity relating to Dominion Privatization will be recorded within Dominion Energy Virginia.

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NOTE 10. PROPERTY, PLANT AND EQUIPMENT

Major classes of property, plant and equipment and their respective balances for the Companies are as follows:

At December 31,	2021		2020
(millions)
Dominion Energy
Utility:
Generation	$	23,378	$	22,697
Transmission		15,430		14,351
Distribution		28,953		27,311
Storage		455		436
Nuclear fuel		2,306		2,283
General and other		4,373		4,130
Plant under construction		3,898		3,350
Total utility		78,793		74,558
Non-jurisdictional - including plant under construction		1,694		1,225
Nonutility:
Nonregulated generation-nuclear		1,773		1,736
Nonregulated generation-solar		2,026		3,268
Nuclear fuel		1,056		1,012
Other-including plant under construction		1,161		1,160
Total nonutility		6,016		7,176
Total property, plant and equipment	$	86,503	$	82,959
Virginia Power
Utility:
Generation	$	17,325	$	16,769
Transmission		11,760		11,000
Distribution		13,621		12,839
Nuclear fuel		1,702		1,709
General and other		912		845
Plant under construction		2,865		2,338
Total utility		48,185		45,500
Non-jurisdictional - including plant under construction		1,694		1,225
Other		11		11
Total property, plant and equipment	$	49,890	$	46,736

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Jointly-Owned Power Stations

The Companies proportionate share of jointly-owned power stations at December 31, 2021 is as follows:

	Bath County Pumped Storage Station(1)			North Anna Units 1 and 2(1)			Clover Power Station(1)			Millstone Unit 3(2)			Summer Unit 1 (2)
(millions, except percentages)
Ownership interest		60	%		88.4	%		50	%		93.5	%		66.7	%
Plant in service		1,063			2,532			610			1,353			1,522
Accumulated depreciation		(714	)		(1,381	)		(273	)		(522	)		(699	)
Nuclear fuel		—			730			—			549			603
Accumulated amortization of nuclear fuel		—			(576	)		—			(406	)		(387	)
Plant under construction		6			178			1			127			76

(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.

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.

Project Name	Date Agreement Entered	Date Agreement Closed	Project Location	Project Cost (millions(1)]		Date of Commercial Operations	MW Capacity
Gutenberg	September 2017	June 2019	North Carolina		142	September 2019		80
Gloucester	June 2018	February 2019	Virginia		37	April 2019		20
Grasshopper(2)	August 2018	May 2019	Virginia		128	October 2020		80
Chestnut	August 2018	May 2019	North Carolina		127	January 2020		75
Ft. Powhatan	June 2019	June 2019	Virginia		267	January 2022		150
Belcher(3)	June 2019	August 2019	Virginia		164	June 2021		88
Bedford	August 2019	November 2019	Virginia		106	November 2021		70
Maplewood	October 2019	October 2019	Virginia		185	Expected 2022		120
Rochambeau	December 2019	January 2020	Virginia		35	December 2021		20
Pumpkinseed	May 2020	May 2020	Virginia		130	Expected 2022		60
Bookers Mill	February 2021	June 2021	Virginia		200	Expected 2023		127

(1) Includes acquisition costs.

(2) Referred to as Butcher Creek once placed in service.

(3) Referred to as Desper once placed in service.

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The following table presents acquisitions by Dominion Energy of solar projects in addition to the Virginia Power solar projects presented above. Dominion Energy has claimed or expects to claim federal investment tax credits on the projects.

Project Name	Date Agreement Entered	Date Agreement Closed	Project Location	Project Cost (millions)(1)		Date of Commercial Operations	MW Capacity
Greensville	August 2019	August 2019	Virginia	$	127	December 2020		80
Myrtle	August 2019	August 2019	Virginia		32	June 2020		15
Seabrook	September 2019	September 2019	South Carolina		103	December 2019		72
Wilkinson	November 2019	November 2019	North Carolina		153	December 2019		74
Blackville	May 2020	May 2020	South Carolina		12	December 2020		7
Denmark	May 2020	May 2020	South Carolina		14	December 2020		6
Yemassee	May 2020	August 2020	South Carolina		17	January 2021		10
Trask	May 2020	October 2020	South Carolina		22	March 2021		12
Hardin I	June 2020	June 2020	Ohio		240	Split(2)		150
Madison	July 2020	July 2020	Virginia		125	Expected 2023		62
Hardin II	August 2020	Expected 2022	Ohio		295	Expected 2023		150

(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. As of December 31, 2021, Dominion Energy had placed in service solar facilities with an aggregate generation capacity of 17 MW at a cost of $34 million and anticipates placing additional facilities in service by the end of 2022 with an estimated total projected cost of approximately $30 million and an aggregate generation capacity of 15 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.

In November 2021, Wexpro closed on an agreement with a natural gas gathering systems operator to purchase an existing natural gas gathering system in Wyoming including pipelines, compressors and dehydration equipment for total consideration of $41 million.

Non-Wholly-Owned Nonregulated Solar Facilities

Sale to Terra Nova Renewable Partners

In August 2021, Dominion Energy entered into an agreement with Terra Nova Renewable Partners to sell SBL Holdco, which held Dominion Energy’s 67% controlling interest in certain nonregulated solar projects for consideration of $456 million, subject to customary closing adjustments, with the amount of cash reduced by the amount of SBL Holdco’s debt outstanding at closing. The sale was contingent on clearance or approval under the Hart-Scott-Rodino Act and by FERC as well as other customary closing and regulatory conditions. In September 2021, the waiting period under the Hart-Scott-Rodino Act expired and in October 2021, FERC approved the proposed sale. In December 2021, the transaction closed and Dominion Energy recorded a gain of $19 million ($15 million after-tax) in losses (gains) on sales of assets in its Consolidated Statements of Income (reflected in the Corporate and Other segment). Except as specifically identified, all activity related to SBL Holdco is recorded within Contracted Assets.

Sale to Clearway

In August 2021, Dominion Energy entered an agreement with Clearway to sell its 50% controlling interest in Four Brothers and Three Cedars for $335 million in cash, subject to customary closing adjustments. The transaction was contingent on clearance or approval under the Hart-Scott-Rodino Act and by FERC as well as other customary closing and regulatory conditions. In October 2021, the waiting period under the Hart-Scott-Rodino Act expired. In December 2021, the transaction closed and Dominion Energy recorded a loss of $229 million ($176 million after-tax) in losses (gains) on sales of assets in its Consolidated Statements of Income (reflected in the Corporate and Other segment), primarily associated with the derecognition of noncontrolling interest. Except as specifically identified, all activity related to Four Brothers and Three Cedars is recorded within Contracted Assets.

Impairment

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

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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.

Virginia Power CCRO Utilization

In 2021, Virginia Power wrote off $318 million, primarily to accumulated depreciation, representing the utilization of a CCRO in accordance with the GTSA in connection with the settlement of the 2021 Triennial Review.  See Note 13 for additional information.

NOTE 11. GOODWILL AND INTANGIBLE ASSETS

Goodwill

The changes in Dominion Energy’s carrying amount and segment allocation of goodwill are presented below:

	Dominion Energy Virginia		Gas Distribution		Dominion Energy South Carolina		Contracted Assets		Corporate and Other			Total
(millions)
Dominion Energy
Balance at December 31, 2019(1)	$	2,106	$	3,512	$	1,521	$	242	$	14		$	7,395
Contribution to Wrangler(2)		—		—		—		—		(14	)		(14	)
Balance at December 31, 2020(1)	$	2,106	$	3,512	$	1,521	$	242	$	—		$	7,381
Acquisition of Birdseye (3)		—		—		—		24		—			24
Balance at December 31, 2021(1)	$	2,106	$	3,512	$	1,521	$	266	$	—		$	7,405

(1) Goodwill amounts do not contain any accumulated impairment losses. 

(2) See Note 9 for additional information including amounts reclassified to held for sale at December 31, 2020.

(3) See Note 3 for more information.

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 $79 million, $69 million and $95 million for 2021, 2020 and 2019, respectively. In 2021, Dominion Energy acquired $311 million of intangible assets, primarily representing RGGI allowances and software, with an estimated weighted-average amortization period of approximately 7 years. Amortization expense for Virginia Power’s intangible assets was $31 million, $28 million and $30 million for 2021, 2020 and 2019, respectively. In 2021, Virginia Power acquired $276 million of intangible assets, primarily representing RGGI allowances and software, with an estimated weighted-average amortization period of 7 years.

The components of intangible assets are as follows:

	2021				2020
At December 31,	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Dominion Energy
Software, licenses and other(1)	$	1,459	$	675	$	1,295	$	530
Virginia Power
Software, licenses and other(1)	$	685	$	290	$	482	$	148

(1) Includes $158M of RGGI allowances purchased and consumed in 2021, with deferral to a regulatory asset.

Annual amortization expense for these intangible assets is estimated to be as follows:

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	2022		2023		2024		2025		2026
(millions)
Dominion Energy	$	72	$	58	$	50	$	42	$	28
Virginia Power	$	29	$	23	$	20	$	16	$	9

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NOTE 12. REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities include the following:

At December 31,	2021		2020
(millions)
Dominion Energy
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	251	$	—
Deferred project costs and DSM programs for gas utilities(2)		53		35
Unrecovered gas costs(3)		191		78
Deferred rider costs for Virginia electric utility(4)		72		98
Ashpond and landfill closure costs(5)		193		—
Deferred nuclear refueling outage costs(6)		79		53
NND Project costs(7)		138		138
PJM transmission rates(8)		7		71
Deferred early plant retirement charges(9)		226		—
Derivatives(10)		112		33
Other		170		193
Regulatory assets-current		1,492		699
Unrecognized pension and other postretirement benefit costs(11)		548		1,363
Deferred rider costs for Virginia electric utility(4)		489		311
Deferred project costs for gas utilities(2)		675		632
Interest rate hedges(12)		899		1,042
AROs and related funding(13)		329		331
Cost of reacquired debt(14)		10		245
NND Project costs(7)		2,226		2,364
Ash pond and landfill closure costs(5)		2,223		2,301
Deferred cost of fuel used in electric generation(1)		409		—
Deferred early plant retirement charges(9)		226		—
Other		609		544
Regulatory assets-noncurrent		8,643		9,133
Total regulatory assets	$	10,135	$	9,832
Regulatory liabilities:
Deferred cost of fuel used in electric generation(1)	$	—	$	58
Provision for future cost of removal and AROs(15)		181		183
Reserve for refunds and rate credits to electric utility customers(16)		420		128
Reserve for future credits to Virginia electric customers(17)		—		120
Income taxes refundable through future rates(18)		153		124
Monetization of guarantee settlement(19)		67		67
Commodity derivatives(10)		55		9
Other		110		120
Regulatory liabilities-current		986		809
Income taxes refundable through future rates(18)		4,260		4,376
Provision for future cost of removal and AROs(15)		2,331		2,150
Nuclear decommissioning trust(20)		2,158		1,719
Monetization of guarantee settlement(19)		831		903
Reserve for refunds and rate credits to electric utility customers(16)		448		540
Unrecognized pension and other postretirement benefit costs(11)		200		66
Overrecovered other postretirement benefit costs(21)		105		111
Other		380		322
Regulatory liabilities-noncurrent		10,713		10,187
Total regulatory liabilities	$	11,699	$	10,996

(1) Reflects deferred fuel expenses for the Virginia, North Carolina and South Carolina jurisdictions of Dominion Energy’s electric generation operations.

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(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 gas costs at regulated gas operations, which are recovered 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. See Note 13 for more information.  

(5) Primarily reflects legislation enacted in Virginia in 2019 which requires any CCR asset located at certain Virginia Power stations to be closed by removing the CCR to an approved landfill or through beneficial reuse. These deferred costs are expected to be collected over a period between 15 and 18 years commencing December 2021 through Rider CCR. Virginia Power is entitled to collect carrying costs on uncollected expenditures once expenditures have been made. See Note 13 for additional information.

(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 current portion of amounts to be recovered through retail rates in Virginia for payments Virginia Power expects to make to PJM through 2026 under the terms of a FERC settlement agreement in May 2018 resolving a PJM cost allocation matter.‌

(9) Reflects amounts from the early retirements of certain coal- and oil-fired generating units to be amortized through 2023 in accordance with the settlement of the 2021 Triennial Review. See Note 13 for additional information. 

(10) For jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

(11) 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.      

(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, 2021.

(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) In 2021, DESC recorded a charge of $237 million ($178 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 that is no longer probable of recovery under the settlement agreement approved in DESC’s retail electric base rate case.  See Note 13 for more information.    

(15) 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. Reflects an increase of $66 million associated with the revision of certain gas distribution pipeline AROs in the third quarter of 2021. See Note 14 for more information.

(16) 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. Also reflects amounts to be refunded to jurisdictional retail electric customers in Virginia associated with the settlement of the 2021 Triennial Review. See Note 13 for additional information.

(17) Represents a reserve related to the expected use of a CCRO in accordance with the GTSA associated with the 2021 Triennial Review. See Note 13 for additional information. 

(18) 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.

(19) 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.

(20) 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.

(21) Reflects a regulatory liability for the collection of postretirement benefit costs allowed in rates in excess of expense incurred.

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At December 31,	2021		2020
(millions)
Virginia Power
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	131	$	—
Deferred rider costs(2)		72		98
Ash pond and landfill closure costs(3)		193		—
Deferred nuclear refueling outage costs(4)		79		53
PJM transmission rates(5)		7		71
Deferred early plant retirement charges(6)		226		—
Derivatives(7)		105		40
Other		37		33
Regulatory assets-current		850		295
Deferred rider costs(2)		489		311
Interest rate hedges(8)		604		733
Ash pond and landfill closure costs(3)		2,223		2,301
Deferred cost of fuel used in electric generation(1)		409		—
Deferred early plant retirement charges(6)		226		—
Other		179		164
Regulatory assets-noncurrent		4,130		3,509
Total regulatory assets	$	4,980	$	3,804
Regulatory liabilities:
Deferred cost of fuel used in electric generation(1)	$	—	$	58
Provision for future cost of removal(9)		154		152
Reserve for refunds to Virginia electric customers(10)		306		—
Reserve for future credits to Virginia electric customers(11)		—		120
Income taxes refundable through future rates(12)		63		54
Derivatives(7)		51		8
Other		73		33
Regulatory liabilities-current		647		425
Income taxes refundable through future rates(12)		2,335		2,404
Nuclear decommissioning trust(13)		2,158		1,719
Provision for future cost of removal(9)		1,043		980
Deferred cost of fuel used in electric generation(1)		—		54
Reserve for refunds to Virginia electric customers(10)		25		—
Other		179		181
Regulatory liabilities-noncurrent		5,740		5,338
Total regulatory liabilities	$	6,387	$	5,763

(1) Reflects deferred fuel expenses for the 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. See Note 13 for more information.  

(3) Primarily reflects legislation enacted in Virginia in 2019 which requires any CCR asset located at certain Virginia Power stations to be closed by removing the CCR to an approved landfill or through beneficial reuse. These deferred costs are expected to be collected over a period between 15 and 18 years commencing December 2021 through Rider CCR. Virginia Power is entitled to collect carrying costs on uncollected expenditures once expenditures have been made. See Note 13 for additional information.

(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 current portion of amounts to be recovered through retail rates in Virginia for payments Virginia Power expects to make to PJM through 2026 under the terms of a FERC settlement agreement in May 2018 resolving a PJM cost allocation matter.  

(6) Reflects amounts from the early retirement of certain coal- and oil-fired generating units to be amortized through 2023 in accordance with the settlement of the 2021 Triennial Review. See Note 13 for more information.  

(7) For jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

(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, 2021.

(9) 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.

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(10) Reflects amounts to be refunded to jurisdictional retail electric customers in Virginia associated with the settlement of the 2021 Triennial Review. See Note 13 for additional information.

(11) Represents a reserve related to the expected use of a CCRO in accordance with the GTSA associated 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, 2021, Dominion Energy and Virginia Power regulatory assets include $4.4 billion and $3.0 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.

Other Regulatory Matters

Virginia Regulation

Regulation Act and Grid Transformation and Security Act of 2018

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.

The GTSA reinstated base rate reviews commencing with 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 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 are deemed recovered in base rates during the triennial period under review and may not be included in base rates in future triennial review proceedings. In any triennial review in which the Virginia Commission determines that the utility’s earnings are more than 70 basis points above its authorized ROE, base rates are subject to reduction prospectively and customer refunds would be due unless the total CCRO elected by the utility equals or exceeds the amount of earnings in excess of the 70 basis points. For the purposes of measuring any customer refunds or CCRO amounts utilized under the GTSA, associated income taxes are factored into the determination of such amounts. In the 2021 Triennial Review, any such rate reduction was limited to $50 million.

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

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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:

• 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 imposed a temporary moratorium on CPCNs for fossil fuel generation, unless the resources are needed for grid reliability. This temporary moratorium concluded in January 2022. 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.

• 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.

• 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.

• Carbon trading program:  The legislation directs Virginia to participate in a market-based carbon trading program consistent with RGGI through 2050. In January 2022, the Governor of Virginia issued an executive order which puts directives in place to start the withdrawal of Virginia from RGGI. All costs of the carbon trading program are recoverable through an environmental rider.

• 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 is incurring and 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.

2021 Triennial Review

In March 2021, Virginia Power filed its base rate case and accompanying schedules in support of the 2021 Triennial Review. In its filing, Virginia Power did not request an increase in base rates for generation and distribution services and proposed that base rates remain at their existing level. Virginia Power’s earnings test analysis, as filed, demonstrated it earned a combined ROE of 10.85% on

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its generation and distribution services for the test period, before accounting for forgiven customer balances. Pursuant to Virginia legislation, forgiven customer balances were excluded from the cost of service in determining test period revenues as part of the 2021 Triennial Review. To the extent that the Virginia Commission determined total earnings for the test period to be above Virginia Power’s authorized earnings band, the forgiven balance amounts are offset against the available revenues in the determination of any customer bill credits, or utilization of a CCRO. Test period earnings may be further 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 under the GTSA. In its filing, Virginia Power elected to utilize $26 million of the CVOW Pilot Project investment as a CCRO to offset available revenues. Virginia Power had contingently elected to offset additional available revenues, if any, determined by the Virginia Commission for earnings sharing with additional Virginia Commission approved qualifying CCRO investments. The Virginia Commission also authorized an ROE for Virginia Power that is applied to Virginia Power’s riders prospectively and that was also utilized to measure base rate earnings as of January 1, 2021. Virginia Power had requested authorization of an ROE of 10.8% based on Virginia Power’s current cost of equity. Pursuant to the Regulation Act, Virginia Power’s authorized ROE shall not be set lower than the average of either (i) the returns reported for the three previous years by not less than a majority of comparable utilities in the Southeastern U.S., with certain limitations as described in the Regulation Act, or (ii) the authorized returns that are set by the applicable regulatory commissions for the same select peer group. In May 2021, Virginia Power filed supplemental testimony to reflect updated test period earnings, including an earned ROE of 10.42%, before accounting for forgiven customer balances, and that no amount of eligible CCRO is necessary to be elected to be utilized.

In 2020, Virginia Power recorded a net charge of $130 million related to the use of a CCRO in accordance with the GTSA, included in impairment of assets and other charges (benefits) in its Consolidated Statements of Income (reflected in the Corporate and Other segment) for 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. In 2021, Virginia Power recorded a benefit of $130 million ($97 million after-tax) in impairment of assets and other charges (benefits) in its Consolidated Statements of Income (reflected in the Corporate and Other segment) to adjust its reserve related to the use of a CCRO in accordance with the GTSA.

Subsequently, in October 2021, Virginia Power, the Virginia Commission staff and other parties filed a comprehensive settlement agreement with the Virginia Commission for approval. The comprehensive settlement agreement provides for $330 million in one-time refunds to customers made up of $255 million over a 6-month period and $75 million over three years, a $50 million going-forward base rate reduction and an authorized ROE of 9.35%. Additionally, Virginia Power has agreed to utilize $309 million of qualifying CCRO investments in the CVOW Pilot Project, deployment of AMI and a Customer Information Platform to offset available earnings and to amortize through 2023 the early retirement charges for coal- and oil-fired generation units recorded in 2019 and 2020. In November 2021, the Virginia Commission approved the comprehensive settlement agreement.

In connection with the settlement agreement, Virginia Power recorded a $356 million ($265 million after-tax) charge for refunds to be provided to customers in operating revenues in its Consolidated Statements of Income as well as a $549 million ($409 million after-tax) benefit primarily from the establishment of a regulatory asset associated with the early retirements of certain coal- and oil-fired generating units and a $318 million ($237 million after-tax) charge for CCRO benefits provided to customers in impairment of assets and other charges (benefits) in its Consolidated Statements of Income (reflected in the Corporate and Other segment). The amounts recorded reflect the impact related 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.

Utility Disconnection Moratorium

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 in its Consolidated Statements of Income (reflected in the Corporate and Other segment) in 2020. In connection with the Virginia 2021 budget process, in the first quarter of 2021 Virginia Power recorded a charge of $76 million ($56 million after-tax) in impairment of assets and other charges (benefits) in its Consolidated Statements of Income for Virginia jurisdictional retail electric customer balances that were more than 30 days past due as of December 31, 2020 that Virginia Power is required to forgive. For the purposes of Virginia Power’s 2021 Triennial Review, these charges were 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 determined total earnings for the test period were above Virginia Power’s authorized earnings band, the forgiven balance amounts were 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 discussed above.

Virginia Fuel Expenses

In May 2021, Virginia Power filed its annual fuel factor with the Virginia Commission to recover an estimated $1.4 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2021 and $72 million of estimated net under-recovered balances through June 30, 2021.  In June 2021, the Virginia Commission approved the annual fuel factor.

GTSA Filing

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In June 2021, Virginia Power filed a petition with the Virginia Commission for approval of a revised plan for electric distribution grid transformation projects as authorized by the GTSA.  The plan includes 14 projects covering six components: (i) smart meters; (ii) customer information platform; (iii) grid improvement projects; (iv) physical and cyber security; (v) telecommunications infrastructure and (vi) customer education (Phase II). For Phase II, the total proposed capital investment during 2022 – 2023 is $667 million and the proposed operations and maintenance investment is $110 million.  In January 2022, the Virginia Commission approved the petition.

Renewable Generation 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 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.  In April 2021, the Virginia Commission approved the application.

In September 2021, Virginia Power filed a petition with the Virginia Commission for CPCNs to construct and operate 13 utility-scale projects totaling approximately 661 MW of solar generation and 70 MW of energy storage as part of its efforts to meet the renewable generation development requirements under the VCEA. The projects are expected to cost approximately $1.4 billion in the aggregate, excluding financing costs, and be placed into service between 2022 and 2023. This matter is pending.

In November 2021, Virginia Power filed an application with the Virginia Commission requesting approval and certification of the Virginia Facilities component of the CVOW Commercial Project.  The onshore Virginia Facilities have an estimated cost of approximately $1.1 billion, excluding financing costs, which is included within the overall cost of the CVOW Commercial Project.  In addition, Virginia Power requested approval from the Virginia Commission to enter into financial hedges with U.S. financial institutions to mitigate the foreign currency exchange risk associated with certain supplier contracts associated with the CVOW Commercial Project.  This matter is pending.

Nuclear Life Extension Program

In October 2021, Virginia Power filed a petition with the Virginia Commission requesting a determination that it is reasonable and prudent for Virginia Power to pursue a nuclear life extension program to extend the operating licenses of Surry and North Anna and to carry out projects to upgrade or replace systems and equipment necessary to continue to safely and reliably operate these nuclear power stations.  The nuclear life extension program is expected to cost approximately $3.9 billion, excluding financing costs. This matter is pending.

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Riders

The significant riders associated with various Virginia Power projects are as follows:

Rider Name	Application Date	Approval Date	Rate Year Beginning	Total Revenue Requirement (millions)	Increase (Decrease) Over Previous Year (millions)
Rider B	June 2020	February 2021	April 2021	24		(8	)
Rider B	June 2021	February 2022	April 2022	16		(8	)
Rider BW	October 2020	July 2021	September 2021	113		14
Rider BW	October 2021	Pending	September 2022	145		32
Rider BW	October 2021	Pending	September 2023	120		(25	)
Rider CCR	February 2021	October 2021	December 2021	216	N/A
Rider CE(1)	October 2020	April 2021	June 2021	10	N/A
Rider CE(2)	September 2021	Pending	May 2022	71		61
Rider E	January 2021	September 2021	November 2021	67		(18	)
Rider E	January 2022	Pending	November 2022	101		34
Rider GT	August 2021	Pending	June 2022	56	N/A
Rider GV	June 2020	February 2021	April 2021	153		21
Rider GV	June 2021	December 2021	April 2022	142		(11	)
Rider GV	June 2021	December 2021	April 2023	127		(15	)
Rider OSW	November 2021	Pending	September 2022	79	N/A
Rider R	June 2020	February 2021	April 2021	58		14
Rider R	June 2021	Pending	April 2022	59		1
Rider R	June 2021	Pending	April 2023	55		(4	)
Rider RGGI(3)	December 2020	August 2021	September 2021	168	N/A
Rider RGGI(4)	December 2021	Withdrawal pending
Rider RPS	December 2020	July 2021	August 2021	13	N/A
Rider RPS	December 2021	Pending	September 2022	140		127
Rider S	June 2020	February 2021	April 2021	194		(1	)
Rider S	June 2021	February 2022	April 2022	192		(2	)
Rider S	June 2021	February 2022	April 2023	191		(1	)
Rider SNA(5)	October 2021	Pending	September 2022	109	N/A
Rider T1(6)	May 2021	August 2021	September 2021	874		(190	)
Rider U(7)	June 2020	February 2021	April 2021	80		28
Rider U(8)	June 2021	Pending	April 2022	96		16
Rider US-2	October 2020	July 2021	September 2021	9		—
Rider US-2	October 2021	Pending	September 2022	11		2
Rider US-3	July 2020	March 2021	June 2021	38		10
Rider US-3	August 2021	Pending	June 2022	50		12
Rider US-4	July 2020	March 2021	June 2021	10		3
Rider US-4	August 2021	Pending	June 2022	15		5
Rider W	June 2020	February 2021	April 2021	120		14
Rider W	June 2021	February 2022	April 2022	121		1
DSM Riders(9)	December 2020	September 2021	October 2021	74		14
DSM Riders(10)	December 2021	Pending	September 2022	91		17

(1) Associated with Grassfield Solar, Norge Solar and Sycamore Solar.

(2) Associated with solar generation and energy storage projects requested for approval in September 2021, solar generation projects approved in April 2021 and certain small-scale solar projects.

(3) In August 2021, the Virginia Commission issued an order granting reconsideration and suspended its order approving the revenue requirement.  In November 2021, the Virginia Commission lifted the suspension of the order. In February 2022, a party filed an appeal to the Supreme Court of Virginia challenging the Virginia Commission’s order.

(4) In January 2022, Virginia Power filed a motion to withdraw its application as a result of the announcement by the Governor of Virginia that he intends to withdraw Virginia from RGGI.  Virginia Power expects to file an updated application to recover its actual and projected RGGI compliance costs informed by these developments at the appropriate time.

(5) Virginia Power also requested approval of cost recovery of approximately $1.2 billion through Rider SNA for the first phase of nuclear life extension program which includes investments through 2024.

(6) Consists of $493 million for the transmission component of Virginia Power’s base rates and $381 million for Rider T1.

(7) Consists of $44 million for previously approved phases and $36 million for phase five costs for Rider U.

(8) Consists of $61 million for previously approved phases and $35 million for phase six costs for Rider U.

(9) Associated with 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.

(10) Associated with an additional nine new energy efficiency programs with a $140 million cost cap, with the ability to exceed the cost cap by no more than 15%.

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Electric Transmission Projects

Significant Virginia Power electric transmission projects approved or applied for are as follows:

Description and Location of Project	Application Date	Approval Date	Type of Line	Miles of Lines	Cost Estimate (millions)
Bristers-Ladysmith Rebuild Project in the Counties of Fauquier, Stafford, Spotsylvania and Caroline, Virginia	May 2020	February 2021	500 kV	37	110
Relocate and replace a transmission line underground between the Tysons substation and the future Spring Hill substation	September 2020	June 2021	230 kV	< 1	30
Rebuild an existing transmission line and install new line adjacent thereto in the Counties of New Kent, King William, King and Queen, Essex and Richmond, Virginia	October 2020	December 2021	230 kV	41	100
Rebuild Clubhouse-Dry Bread Line and Dry Bread-Lakeview Line in Greensville County, Virginia	November 2020	July 2021	230 kV	13	20
Rebuild transmission lines and related projects in the Counties of York and James City and the City of Williamsburg, Virginia	January 2021	September 2021	230 kV	11	30
Elmont-Ladysmith rebuild and related projects in the Counties of Hanover and Caroline, Virginia	April 2021	Pending	500 kV	26	95
Beaumeade-Belmont reconductor and rebuild projects in the County of Loudoun, Virginia	May 2021	February 2022	230 kV	7	15
Extension to Cloud Switching Station and Easters Switching Station in the County of Mecklenburg, Virginia	June 2021	February 2022	230 kV	15	105
Rebuild transmission lines and related projects in the City of Staunton and County of Augusta, Virginia	November 2021	Pending	230 kV	21	45
Build new DTC substation and line loop in the County of Loudoun, Virginia	December 2021	Pending	230 kV	1	105
Build new Aviator substation and line loop in the County of Loudoun, Virginia	February 2022	Pending	230 kV	1	80

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. 

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North Carolina Regulation

Virginia Power 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.

Virginia Power North Carolina Fuel Filing

In August 2021, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power updated its filing in October 2021 to reflect the increased commodity cost of fuel and proposed a total $26 million increase to the fuel component of its electric rates for the rate year beginning February 1, 2022. In January 2022, the North Carolina Commission approved the filing.

PSNC Base Rate Case

In April 2021, PSNC filed its general rate case application and schedules with the North Carolina Commission.  PSNC proposed a non-fuel, base rate increase of $53 million to be effective November 1, 2021. After considering the benefits of the 2017 Tax Reform Act, the net revenue increase to customers would be approximately $42 million.  The base rate increase was proposed to recover the significant investment in infrastructure to serve a growing customer base, improve safety and reliability of the transmission and distribution system and enhance energy efficiency and sustainability.  The proposed rates would provide for an ROE of 10.25% compared to the currently authorized ROE of 9.7%.

In October 2021, PSNC, the North Carolina Commission public staff and certain other parties of record filed a stipulation of settlement with the North Carolina Commission for approval. The stipulation of settlement provides for a non-fuel, base rate increase of $29 million effective November 1, 2021, based on an ROE of 9.60%. The net revenue increase to customers, after considering the amortization of the previously deferred benefits of the 2017 Tax Reform Act, would be $4 million in the initial rate year, $23 million for the following rate year and then $26 million beginning for the third through fifth rate years. In addition, the stipulation of settlement provides for the recovery, over four years, of $106 million of operation and maintenance costs which PSNC has incurred and deferred through June 2021 to comply with federal standards for pipeline integrity and safety. In November 2021, PSNC implemented temporary rates consistent with the stipulation of settlement. In December 2021, a revised stipulation of settlement was filed with the North Carolina Commission adjusting the net revenue increase to customers, after considering the amortization of the previously deferred benefits of the 2017 Tax Reform Act, to $6 million in the initial rate year, $25 million for the following rate year and $27 million beginning for the third through fifth rate years. In January 2022, the North Carolina Commission approved the revised stipulation of settlement without modification and issued its final order.

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 August 2021, the North Carolina Commission approved PSNC’s request to increase the integrity management annual revenue requirement to $34 million, an increase of $1 million over its previous filing, effective September 2021.

Rider D

Rider D allows PSNC to recover from customers all prudently incurred gas costs and certain related uncollectible expenses as well as losses on negotiated gas and transportation sales. In September 2021, PSNC submitted a filing with the North Carolina Commission for a $61 million gas cost increase. The North Carolina Commission approved the filing in September 2021 with rates effective October 2021.  In November 2021, PSNC submitted a filing with the North Carolina Commission for a $49 million gas cost increase and a $15 million increase in the customers deferred account. The North Carolina Commission approved the filing in December 2021 with rates effective December 2021.

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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 July 2021, DESC, the South Carolina Office of Regulatory Staff and other parties of record filed a comprehensive settlement agreement with the South Carolina Commission for approval. The comprehensive settlement agreement provides for a non-fuel, base rate increase of $62 million (resulting in a net increase of $36 million after considering an accelerated amortization of certain excess deferred income taxes) commencing with bills issued on September 1, 2021 and an authorized earned ROE of 9.50%. Additionally, DESC has agreed to commit up to $15 million to forgive retail electric customer balances that were more than 60 days past due as of May 31, 2021 and provide $15 million for energy efficiency upgrades and critical health and safety repairs to customer homes. Pursuant to the comprehensive settlement agreement, DESC would not file a retail electric base rate case prior to July 1, 2023, such that new rates would not be effective prior to January 1, 2024, absent unforeseen extraordinary economic or financial conditions that may include changes in corporate tax rates. In July 2021, the South Carolina Commission approved the comprehensive settlement agreement and issued its final order in August 2021.

In connection with this matter, Dominion Energy recorded charges of $249 million ($187 million after-tax) reflected within impairment of assets and other charges (benefits) (reflected in the Corporate and Other segment), including $237 million of regulatory assets associated with DESC’s purchases of its first mortgage bonds during 2019 that are no longer probable of recovery under the settlement agreement, and $18 million ($14 million after-tax) reflected within other income in its Consolidated Statements of Income for the year ended December 31, 2021.

DSM Programs

DESC has approval for a DSM rider through which it recovers expenditures related to its DSM programs

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. In April 2021, the South Carolina Commission approved the filing. In connection with the approval of the comprehensive settlement agreement in the South Carolina base rate case discussed above, the net lost revenue component of the DSM rider was adjusted resulting in a recovery of $43 million commencing with bills issued on September 1, 2021.

In January 2022, DESC filed an application with the South Carolina Commission seeking approval to recover $60 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 2021, DESC filed with the South Carolina Commission its monitoring report for the 12-month period ended March 31, 2021 with a total revenue requirement of $426 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 2021. In October 2021, the South Carolina Commission issued an order approving a total revenue requirement of $424 million effective with the first billing cycle of November 2021. This represents a $7 million overall annual increase to DESC’s natural gas rates.

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 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. In April 2021, the South Carolina Commission approved the filing.

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In February 2022, DESC filed with the South Carolina Commission a proposal to increase the total fuel cost component of retail electric rates. DESC’s proposed adjustment is designed to recover DESC’s current base fuel costs, including its existing under-collected balance, over the 12-month period beginning with the first billing cycle of May 2022. DESC also proposed to apply approximately $66 million representing the net balance of funds associated with the monetization of the bankruptcy settlement with Toshiba Corporation following the satisfaction of liens against NND Project property recorded in regulatory liabilities, as a reduction to its under-collected base fuel cost balance. In addition, DESC proposed an increase to its variable environmental and avoided capacity cost component. The net effect is a proposed annual increase of $143 million. This matter is pending.

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 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.

In April 2021, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2020 costs. The filing reflects gross plant investment for 2020 of $178 million, cumulative gross plant investment of $2.0 billion and a revenue requirement of $243 million.

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 infrastructure and information technology systems as well as investments necessary to comply with the Ohio Commission or other government regulation.

In April 2021, East Ohio filed an application requesting approval to adjust the CEP cost recovery rates for 2019 and 2020 costs.  The filing reflects gross plant investment for 2019 of $137 million, gross plant investment for 2020 of $99 million, cumulative gross plant investment of $957 million and a revenue requirement of $119 million. This matter is pending.

UEX Rider

East Ohio has approval for a UEX Rider through which it recovers the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar for dollar recovery of East Ohio’s actual write-offs of uncollectible amounts. In July 2021, the Ohio Commission approved East Ohio’s application to adjust its UEX Rider to reflect an increased annual revenue requirement of $20 million to provide for an under-recovered accumulated bad debt expense of $7 million as of March 31, 2021, and recovery of net bad debt expense projected to total $13 million for the twelve-month period ending March 2022.

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%. In July 2021, the West Virginia Commission approved a non-fuel, base rate increase of $13 million for rates effective July 2021 with an ROE of 9.54%. In August 2021, Hope filed a petition for reconsideration with the West Virginia Commission regarding certain return calculations included in the July 2021 approval order. This matter is pending.

PREP

In October 2021, the West Virginia Commission approved Hope’s request to recover PREP costs related to $54 million and $56 million of projected capital investment for 2021 and 2022, respectively. The request also includes a true-up of PREP costs related to the 2020 actual capital investment of $34 million and sets forth $9 million of annual PREP costs to be recovered in proposed rates effective November 1, 2021.

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Utah Regulation

Purchased Gas

In May 2021, the Utah Commission approved Questar Gas’ request for a $43 million gas cost increase with rates effective June 2021.

In October 2021, the Utah Commission approved Questar Gas’ request for an $83 million gas cost increase with rates effective November 2021.

In December 2021, the Utah Commission approved Questar Gas’ request for a $29 million gas cost increase on an interim basis, with rates effective January 2022.

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 2020 and 2021 were as follows:

	Amount
(millions)
Dominion Energy
AROs at December 31, 2019	$	5,184
Obligations incurred during the period		67
Obligations settled during the period		(114	)
Revisions in estimated cash flows(1)		228
Accretion		218
AROs at December 31, 2020(2)	$	5,583
Obligations incurred during the period		31
Obligations settled during the period		(165	)
Revisions in estimated cash flows(3)		(151	)
Accretion		224
Sale of non-wholly-owned nonregulated solar facilities		(49	)
AROs at December 31, 2021(2)	$	5,473
Virginia Power
AROs at December 31, 2019	$	3,581
Obligations incurred during the period		48
Obligations settled during the period		(85	)
Revisions in estimated cash flows(4)		139
Accretion		137
AROs at December 31, 2020	$	3,820
Obligations incurred during the period		26
Obligations settled during the period		(131	)
Revisions in estimated cash flows(5)		67
Accretion		141
AROs at December 31, 2021	$	3,923

(1) 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.

(2) Includes $179 million and $198 million reported in other current liabilities at December 31, 2020 and 2021, respectively.

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(3) Reflects revisions to future ash pond and landfill closure costs at certain utility generation facilities, estimated cash flow projections associated with the recovery of spent nuclear fuel costs for its AROs associated with the decommissioning of Kewaunee and estimated cash flow projections associated with certain gas distribution pipelines.  These revisions in 2021 resulted in a charge of $44 million ($35 million after-tax) within other operations and maintenance expense in the Consolidated Statements of Income as well as a $173 million decrease to property, plant and equipment, net.

(4) Reflects revisions to future ash pond and landfill closure costs at certain utility generation facilities and asbestos abatement costs associated with certain utility facilities.

(5) Reflects revisions to future ash pond and landfill closure costs at certain utility generation facilities.

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 $113 million ($84 million after-tax) benefit in other operations and maintenance expense in the Consolidated Statements of Income in 2019.

Dominion Energy’s AROs at December 31, 2021 and 2020, include $2.0 billion and $1.9 billion, respectively, with $0.9 billion and $0.9 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, 2021 and 2020, the aggregate fair value of Dominion Energy’s trusts, consisting primarily of equity and debt securities, totaled $8.0 billion and $6.9 billion, respectively. At December 31, 2021 and 2020, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $3.7 billion and $3.2 billion, respectively.

In addition, AROs at December 31, 2021 and 2020 include $2.9 billion and $2.8 billion, respectively, related to Virginia Power’s future ash pond and landfill closure costs. Regulatory mechanisms, primarily associated with legislation enacted in Virginia in March 2019, provide for recovery of costs to be incurred. See Note 12 for additional information.   

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NOTE 15. LEASES

At December 31, 2021 and 2020, the Companies had the following lease assets and liabilities recorded in the Consolidated Balance Sheets:

	December 31, 2021		December 31, 2020
(millions)
Dominion Energy
Lease assets:
Operating lease assets(1)	$	506	$	564
Finance lease assets(2)		144		148
Total lease assets	$	650	$	712
Lease liabilities:
Operating lease liabilities(3)	$	44	$	54
Finance lease liabilities(4)		36		32
Total lease liabilities - current		80		86
Operating lease liabilities (5)		464		516
Finance lease liabilities(6)		112		108
Total lease liabilities - noncurrent		576		624
Total lease liabilities	$	656	$	710
Virginia Power
Operating lease assets(1)	$	256	$	185
Finance lease assets(2)		71		45
Total lease assets	$	327	$	230
Lease liabilities:
Operating lease liabilities(3)	$	25	$	28
Finance lease liabilities(4)		13		8
Total lease liabilities - current		38		36
Operating lease liabilities (5)		227		155
Finance lease liabilities(6)		57		36
Total lease liabilities - noncurrent		284		191
Total lease liabilities	$	322	$	227

(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 $81 million and $18 million of accumulated amortization at Dominion Energy and Virginia Power, respectively, at December 31, 2021 and net of $50 million and $9 million of accumulated amortization at Dominion Energy and Virginia Power, respectively, at December 31, 2020.

(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.

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In addition to the amounts disclosed above, Dominion Energy’s Consolidated Balance Sheets at December 31, 2021 and 2020 includes property, plant and equipment of $1.2 billion and $2.2 billion, respectively, and accumulated depreciation of $106 million and $68 million, respectively, related to facilities subject to power purchase agreements under which Dominion Energy is the lessor.

For the years ended December 31, 2021, 2020 and 2019, total lease cost associated with the Companies’ leasing arrangements consisted of the following:

	Year Ended December 31, 2021			Year Ended December 31, 2020		Year Ended December 31, 2019
(millions)
Dominion Energy
Finance lease cost:
Amortization	$	40		$	33	$	20
Interest		(3	)		—		4
Operating lease cost		66			68		79
Short-term lease cost		32			20		26
Variable lease cost		5			8		5
Total lease cost	$	140		$	129	$	134
Virginia Power
Finance lease cost:
Amortization	$	12		$	7	$	3
Interest		1			1		—
Operating lease cost	$	30		$	36	$	41
Short-term lease cost		19			12		13
Variable lease cost		1			4		2
Total lease cost	$	63		$	60	$	59

For the years ended December 31, 2021, 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:

	Year Ended December 31, 2021			Year Ended December 31, 2020		Year Ended December 31, 2019
(millions)
Dominion Energy
Operating cash flows for finance leases	$	(3	)	$	—	$	4
Operating cash flows for operating leases		103			96		111
Financing cash flows for finance leases		40			33		20
Virginia Power
Operating cash flows for finance leases	$	1		$	1	$	—
Operating cash flows for operating leases		53			52		56
Financing cash flows for finance leases		12			7		3

In addition to the amounts disclosed above, Dominion Energy’s Consolidated Statements of Income for the years ended December 31, 2021, 2020 and 2019, include $168 million, $175 million and $174 million, respectively, of rental revenue, included in operating revenue and $110 million, $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, 2021 and 2020, the weighted average remaining lease term and weighted discount rate for the Companies’ finance and operating leases were as follows:

	December 31, 2021			December 31, 2020
Dominion Energy
Weighted average remaining lease term - finance leases	5 years			5 years
Weighted average remaining lease term - operating leases	27 years			26 years
Weighted average discount rate - finance leases		2.77	%		3.17	%
Weighted average discount rate - operating leases		3.96	%		4.07	%
Virginia Power
Weighted average remaining lease term - finance leases	6 years			6 years
Weighted average remaining lease term - operating leases	25 years			21 years
Weighted average discount rate - finance leases		2.27	%		2.51	%
Weighted average discount rate - operating leases		4.00	%		4.26	%

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The Companies’ lease liabilities have the following maturities:

Maturity of Lease Liabilities	Dominion Energy						Virginia Power
(millions)	Operating			Finance			Operating			Finance
2022	$	50		$	32		$	27		$	8
2023		41			39			21			14
2024		33			33			17			14
2025		27			18			13			13
2026		24			15			10			10
After 2026		577			22			240			17
Total undiscounted lease payments		752			159			328			76
Present value adjustment		(244	)		(11	)		(76	)		(6	)
Present value of lease liabilities	$	508		$	148		$	252		$	70

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 provided equity and had obtained financing commitments from debt investors, totaling $465 million, to fund the estimated project costs. In March 2021, Dominion Energy notified the lessor of its intention to terminate the leasing arrangement effective April 2021. As a result, Dominion Energy recorded a charge of $62 million ($46 million after-tax) in 2021, included in impairments of assets and other charges in its Consolidated Statements of Income, primarily for amounts required to be repaid to the lessor.   

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 $293 million as of December 31, 2021. 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

Through December 2021, Dominion Energy owned the manager and 67% of the membership interest in certain nonregulated solar facilities, as discussed in Note 2. Dominion Energy concluded that these entities were 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 was a VIE. Prior to

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its disposition in December 2021, Dominion Energy was the primary beneficiary of SBL Holdco and the nonregulated solar facilities, as it had 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. At December 31, 2020, 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 was nonrecourse to Dominion Energy and was secured by SBL Holdco’s interest in certain nonregulated solar facilities.

At December 31, 2021, 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 guarantees provided.  See Note 23 for more information.

At December 31, 2021, 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. 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 for electric capacity to non-utility generators and $1 million and million for electric energy to non-utility generators for the year ended December 31, 2019.

Virginia Power purchased shared services from DES, an affiliated VIE, of $380 million, $349 million and $387 million for the years ended December 31, 2021, 2020, and 2019, respectively. Virginia Power’s Consolidated Balance Sheets included amounts due to DES of $20 million at December 31, 2021, and $175 million at December 31, 2020, 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.

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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

In June 2021, Dominion Energy amended its $6.0 billion joint revolving credit facility to provide for a discount in the pricing of certain annual fees and amounts borrowed by Dominion Energy under the facility if Dominion Energy achieves certain annual renewable electric generation and diversity and inclusion objectives. In addition, the amended facility incorporates certain administrative changes with respect to the anticipated transition from LIBOR to an alternative benchmark rate. The key financial covenants are unchanged from the previous facility.

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:

	Facility Limit		Outstanding Commercial Paper(1)		Outstanding Letters of Credit		Facility Capacity Available
(millions)
At December 31, 2021
Joint revolving credit facility(2)	$	6,000	$	1,883	$	131	$	3,986
At December 31, 2020
Joint revolving credit facility(2)	$	6,000	$	627	$	100	$	5,273

(1) The weighted-average interest rates of the outstanding commercial paper supported by Dominion Energy’s credit facility was 0.31% and 0.29% at December 31, 2021 and 2020, respectively.

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

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, 2021, the sub-limits for DESC and Questar Gas were $500 million and $250 million, respectively.

In January 2021, DESC and GENCO applied to FERC for a two-year short-term borrowing authorization. In March 2021, FERC granted DESC authority through March 2023 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 2021, FERC granted GENCO authority through March 2023 to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less.

In addition to the joint revolving credit facility mentioned above, Dominion Energy also has a credit facility which allows Dominion Energy to issue up to $30 million in letters of credit and matures in June 2022.  At December 31, 2021 and 2020, Dominion Energy had $29 million and $30 million, respectively, in letters of credit outstanding under this agreement.

In December 2021, in connection with the sale of certain non-wholly owned nonregulated solar facilities, as discussed in Note 10, SBL Holdco terminated $30 million of credit facilities and Dominion Solar Projects III, Inc. terminated $25 million of credit facilities. At December 31, 2020, no amounts were outstanding under either of these facilities.

In March 2020, Dominion Energy entered into a $900 million 364-Day Revolving Credit Agreement that bore interest at a variable rate. At December 31, 2020, $225 million was outstanding under the agreement. In March 2021, the agreement reached maturity and Dominion Energy repaid the outstanding borrowed amount in full.

In July 2021, Dominion Energy entered into an approximately $1.3 billion term loan credit agreement following the termination of the Q-Pipe Transaction as discussed in Note 3 and borrowed the full amount available thereunder.  The term loan was scheduled to mature in December 2021, with the ability to extend maturity at Dominion Energy’s option to June 2022 and bore interest at a variable rate.  The proceeds were utilized to repay the deposit received from BHE on the Q-Pipe Transaction.  In December 2021, Dominion Energy used the net proceeds from the completion of the sale of the Q-Pipe Group to Southwest Gas to repay the principal outstanding under the term loan plus accrued interest.

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In December 2021, DECP Holdings entered into a credit facility, which allows it to issue up to $110 million in letters of credit with automatic one-year renewals through the maturity of the facility in December 2024. At December 31, 2021, $110 million in letters of credit were outstanding under this agreement with no amounts drawn under the letters of credit.

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 Investment^SM. 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, 2021 and December 31, 2020, Dominion Energy’s Consolidated Balance Sheets include $431 million and $268 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 Dominion Energy’s $6.0 billion joint revolving credit facility, as amended in June 2021. 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:

	Facility Limit		Outstanding Commercial Paper(1)		Outstanding Letters of Credit
(millions)
At December 31, 2021
Joint revolving credit facility(2)	$	6,000	$	745	$	40
At December 31, 2020
Joint revolving credit facility(2)	$	6,000	$	45	$	12

(1) The weighted-average interest rates of the outstanding commercial paper supported by the credit facility was 0.26% and 0.30% at December 31, 2021 and 2020, 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, 2021, the sub-limit for Virginia Power was $1.75 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 June 2026, with the potential to be extended by the borrowers to June 2028. The credit facility 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.

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NOTE 18. LONG-TERM DEBT

At December 31,	2021 Weighted- average Coupon(1)			2021			2020
(millions, except percentages)
Virginia Electric and Power Company:
Unsecured Senior Notes:
2.30% to 8.875%, due 2022 to 2051		4.07	%	$	13,238		$	12,689
Tax-Exempt Financings(2):
0.45% to 1.90%, due 2032 to 2041		1.14	%		625			625
Virginia Electric and Power Company total principal				$	13,863		$	13,314
Securities due within one year		3.45	%		(300	)		—
Unamortized discount, premium and debt issuances costs, net					(110	)		(107	)
Derivative restructuring					446			444
Finance leases					57			36
Virginia Electric and Power Company total long-term debt				$	13,956		$	13,687
Dominion Energy, Inc.:
Supplemental 364-Day credit facility, variable rate, due 2021				$	—		$	225
Sustainability Revolving Credit Agreement, variable rate, due 2024(3)					—			—
Unsecured Senior Notes:
Variable rate, due 2023		0.73	%		1,000			1,000
1.45% to 7.0%, due 2021 to 2049(4)		3.78	%		11,238			9,938
Unsecured Junior Subordinated Notes:
2.715% to 4.104%, due 2021 and 2024		3.07	%		700			1,950
Payable to Affiliated Trust, 8.4%, due 2031		8.40	%		10			10
Enhanced Junior Subordinated Notes:
5.25% and 5.75%, due 2054 and 2076(5)		5.75	%		685			1,485
DECP Holdings, Term Loan, variable rate, due 2024(6)		1.50	%		2,500			—
Questar Gas, Unsecured Senior Notes, 2.21% to 7.20%, due 2024 to 2051		3.85	%		1,000			750
East Ohio, Unsecured Senior Notes, 1.30% to 3.00%, due 2025 to 2050		2.25	%		1,800			1,800
PSNC, Senior Debentures and Notes, 3.10% to 7.45%, due 2021 to 2051		4.34	%		800			800
DESC:
First Mortgage Bonds, 2.30% to 6.625%, due 2021 to 2065		5.09	%		3,634			3,267
Tax-Exempt Financings(7):
Variable rate due 2038		0.14	%		35			35
3.625% and 4.00%, due 2028 and 2033		3.90	%		54			54
GENCO, variable rate due 2038		0.14	%		33			33
Other		3.65	%		1			1
Secured Senior Notes, 4.82%, due 2042(8)		4.82	%		314			331
Term Loans, variable rates, due 2023 and 2024(9)					—			476
Tax-Exempt Financing, 1.7% due 2033		1.70	%		27			27
Virginia Electric and Power Company total principal (from above)					13,863			13,314
Dominion Energy, Inc. total principal(10)				$	37,694		$	35,496
Fair value hedge valuation(11)					2			3
Securities due within one year(12)		2.79	%		(805	)		(1,905	)
Supplemental 364-Day credit facility borrowings					—			(225	)
Unamortized discount, premium and debt issuance costs, net					(315	)		(293	)
Derivative restructuring					738			773
Finance leases					112			108
Dominion Energy, Inc. total long-term debt				$	37,426		$	33,957

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2021.

(2) These financings relate to certain pollution control equipment at Virginia Power’s generating facilities.

(3) This $900 million supplemental credit facility, entered in June 2021, offers a reduced interest rate margin with respect to borrowed amounts allocated to certain environmental sustainability or social investment initiatives. Proceeds of the supplemental credit facility also may be used for general corporate purposes, but such proceeds are not eligible for a reduced interest rate margin. In June 2021 and August 2021, Dominion Energy borrowed $250 million and $650 million respectively. The proceeds from these borrowings were used to support environmental sustainability and social investment initiatives ($250 million) and for general corporate purposes ($650 million). In November 2021 and December 2021, Dominion Energy repaid $650 million and $250 million, respectively, borrowed under this arrangement.

(4) Includes debt assumed by Dominion Energy from the merger of its former CNG subsidiary.

(5) In August 2021, Dominion Energy redeemed the remaining principal outstanding of $800 million of its July 2016 hybrids, which would have otherwise matured in 2076.

(6) The term loan amortizes over a 17-year period and matures in December 2024 with the potential to be extended to December 2026. The debt is secured by DECP Holdings’ noncontrolling interest in Cove Point.

(7) Industrial revenue bonds totaling $68 million are secured by letters of credit that expire, subject to renewal, in the fourth quarter of 2022.

(

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8) Represents debt associated with Eagle Solar. The debt is nonrecourse to Dominion Energy and is secured by Eagle Solar’s interest in certain solar facilities.

(9) Represents debt associated with SBL Holdco and Dominion Solar Projects III, Inc. The debt was nonrecourse to Dominion Energy and was secured by SBL Holdco’s and Dominion Solar Projects III, Inc’s interest in certain solar facilities. In connection with the sales of certain non-wholly owned nonregulated solar facilities discussed in Note 10, the outstanding debt of SBL Holdco was assumed by Terra Nova Renewable Partners and Dominion Energy utilized proceeds from Clearway to repay the outstanding balance of the Dominion Solar Projects III, Inc. term loan.

(10) Excludes amounts classified as held for sale at December 31, 2020. See Note 3.

(11) Represents the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt.

(12) At December 31, 2020, 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, 2021, were as follows:

	2022			2023			2024			2025			2026			Thereafter			Total
(millions, except percentages)
Virginia Power
Unsecured Senior Notes	$	300		$	700		$	350		$	350		$	1,150		$	10,388		$	13,238
Tax-Exempt Financings		—			—			—			—			—			625			625
Total	$	300		$	700		$	350		$	350		$	1,150		$	11,013		$	13,863
Weighted-average Coupon		3.45	%		2.75	%		3.45	%		3.10	%		3.08	%		4.16	%
Dominion Energy
Term Loans	$	151		$	134		$	2,215		$	—		$	—		$	—		$	2,500
First Mortgage Bonds		—			—			—			—			—			3,634			3,634
Unsecured Senior Notes		650			2,700			690			2,000			2,257			20,779			29,076
Secured Senior Notes		6			17			31			19			20			221			314
Tax-Exempt Financings		—			—			—			—			—			775			775
Unsecured Junior Subordinated Notes Payable    to Affiliated Trusts		—			—			—			—			—			10			10
Unsecured Junior Subordinated Notes		—			—			700			—			—			—			700
Enhanced Junior Subordinated Notes		—			—			—			—			—			685			685
Total	$	807		$	2,851		$	3,636		$	2,019		$	2,277		$	26,104		$	37,694
Weighted-average Coupon		2.79	%		1.89	%		2.20	%		3.01	%		2.82	%		4.26	%

The Companies’ short-term credit facility and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2021, there were no events of default under these covenants.

Senior Note Issuances

In January 2022, Virginia Power issued $600 million of 2.40% senior notes and $400 million of 2.95% senior notes that mature in 2032 and 2051, respectively. The proceeds were used for general corporate purposes and/or to repay short-term debt.

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. If the three-month LIBOR is terminated while the October 2014 hybrids are outstanding, they will thereafter bear interest at the last interest rate determined prior to the termination.

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In July 2016, Dominion Energy issued $800 million of 5.25% July 2016 hybrids. In August 2021, Dominion Energy redeemed the remaining principal outstanding of $800 million of its July 2016 hybrids, which would have otherwise matured in 2076 and were listed on the NYSE under the symbol DRUA. Expenses related to the early redemption of the hybrids were $23 million reflected within interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2021.

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. As a result of this noncash financing activity with an embedded interest rate swap, 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 2021, Dominion Energy settled certain of the outstanding interest rate swaps which would have otherwise matured in December 2024, resulting in a $39 million reduction in other long-term debt.

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. As a result of this noncash financing activity with an embedded interest rate swap, 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 December 31, 2021, Dominion Energy had issued and outstanding 3.4 million shares of preferred stock, 1.6 million, 0.8 million and 1.0 million of which were designated as the Series A Preferred Stock, the Series B Preferred Stock and the Series C Preferred Stock, respectively. At December 31, 2020, 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, 2021 and 2020, 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, 2021 or 2020.

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.

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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. In November 2021, Dominion Energy’s Articles of Incorporation were amended to require that any conversion of its Series A Preferred Stock be settled, at Dominion Energy’s election, either entirely in cash or in cash up to the first $1,000 per share and in shares of Dominion Energy common stock, cash or any combination thereof for any amounts in excess of $1,000 per share. As a result of establishing a minimum amount to be settled in cash if the holders elect to convert the Series A Preferred Stock, $1.6 billion was reclassified from equity to mezzanine equity in 2021.

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.

Pursuant to the terms of the 2019 Equity Units, Dominion Energy expects to remarket shares of Series A Preferred Stock during the first or second quarter of 2022. Following a successful remarketing, the dividend rate on the preferred stock will be reset and the conversion rate on the preferred stock may increase depending on the closing price of Dominion Energy’s common stock on the date of the remarketing. Dominion Energy will not directly receive any proceeds from the remarketing as the remarketing will be conducted on behalf of investors that, as of the remarketing, continue to hold corporate units or otherwise elect to participate in the remarketing. Proceeds from the remarketing attributable to investors that continue to hold corporate units will be used to purchase a treasury portfolio that upon maturity will be used in June 2022 to pay the purchase price to Dominion Energy for issuance of its common stock under the stock purchase contracts that are a component of such corporate units. 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 for consideration of $1.6 billion.

Selected information about Dominion Energy’s 2019 Equity Units is presented below:

Issuance Date	Units Issued	Total Net Proceeds(1)		Total Preferred Stock(2)		Cumulative Dividend Rate			Stock Purchase Contract Annual Rate			Stock Purchase Contract Liability(3)		Stock Purchase Contract Settlement Date
(millions except interest rates)
6/14/2019	16	$	1,582	$	1,610		1.75	%		5.5	%	$	250	6/1/2022

(1) Issuance costs of $28 million were recorded as a reduction to preferred stock ($14 million) and common stock ($14 million). In connection with the reclassification of the Series A Preferred Stock to mezzanine equity in 2021, the issuance costs originally recognized as a reduction to preferred stock were reclassified to common stock.

(2) Dominion Energy recorded dividends of $28 million ($17.50 per share), $28 million ($17.50 per share) and $15 million ($9.479 per share) for the years ended December 31, 2021, 2020 and 2019, respectively.

(3) Payments of $85 million, $83 million and $38 million were made in 2021, 2020 and 2019, respectively. The stock purchase contract liability was $44 million and $129 million at December 31, 2021 and 2020, 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

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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) for the years ended December 31, 2021 and 2020. 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.

Series C Preferred Stock

In December 2021, Dominion Energy issued 750,000 shares of Series C Preferred Stock for $742 million, net of $8 million of issuance costs. Also in December 2021, Dominion Energy issued 250,000 shares of Series C Preferred Stock valued at $250 million to the qualified benefit pension plans. See Note 22 for further information regarding activity surrounding pension plan contributions. The preferred stock has a liquidation preference of $1,000 per share and currently pays a 4.35% dividend per share on the liquidation preference. Dividends are paid cumulatively on a semi-annual basis, commencing April 15, 2022. Dominion Energy recorded dividends of $3 million ($2.6583 per share) for the year ended December 31, 2021. The dividend rate for the Series C Preferred Stock will be reset every five years beginning on April 15, 2027 to equal the then-current five-year U.S. Treasury rate plus a spread of 3.195%. Unless all accumulated and unpaid dividends on the Series C 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 C Preferred Stock as to dividends or upon liquidation, including through dividends, redemptions, repurchases or otherwise.

Dominion Energy may, at its option, redeem the Series C Preferred Stock in whole or in part anytime from and including January 15, 2027 through and including April 15, 2027 or during any subsequent fifth anniversary of such period 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 C 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 C Preferred Stock that has certain adverse effects on the equity credit actually received by the Series C Preferred Stock.

Holders of the Series C Preferred Stock have no voting rights except in the limited circumstances provided for in the terms of the Series C Preferred Stock or as otherwise required by applicable law. The Series C Preferred Stock is not subject to any sinking fund or other obligation of ours to redeem, repurchase or retire the Series C Preferred Stock. The preferred stock contains no conversion rights.

NOTE 20. EQUITY

Common Stock

Dominion Energy

During 2021, 2020 and 2019, Dominion Energy recorded, net of fees and commissions, $340 million, $481 million and $11.0 billion from the issuance of approximately 4 million, 7 million and 157 million shares of common stock, respectively, for acquisitions, pension plan contributions, 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.

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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. During 2021, Dominion Energy issued 2.6 million of such shares and received proceeds of $192 million.

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 July 2021, Dominion Energy issued 1.4 million shares of its common stock, valued at $104 million, to satisfy DESC’s obligation under a settlement agreement for the FILOT litigation discussed in Note 23.

In August 2021, Dominion Energy issued 0.6 million shares of its common stock, valued at $45 million, to satisfy DESC’s obligation for the initial payment under a settlement agreement with the SCDOR discussed in Note 23.

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 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

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or enter into one or more forward sale agreements with respect to shares of its common stock. Sales by Dominion Energy through the sales agents or by forward sellers pursuant to a forward sale agreement cannot exceed $1.0 billion in the aggregate. In November 2021, Dominion Energy entered forward sale agreements for approximately 1.1 million shares of its common stock to be settled by November 2022 at an initial forward price of $74.66 per share. Except in certain specified circumstances that would require physical share settlement, Dominion Energy may elect physical, cash or net share settlement of the forward sale agreements. A net share settlement could require us to deliver a number of shares significantly lower than would be issued in connection with a full physical settlement.

Repurchase of Common Stock

Dominion Energy did not repurchase any shares in 2021 or 2019, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which do not count against its stock repurchase authorization. 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.

Virginia Power

In 2021, 2020 and 2019, 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.  

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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.   

Non-Wholly-Owned Nonregulated Solar Facilities

In December 2021, Dominion Energy completed the sale of SBL Holdco, which held Dominion Energy’s 67% controlling interest in certain nonregulated solar projects, and the sale of its 50% controlling interest in Four Brothers and Three Cedars.  As a result of these sales, all balances recorded as noncontrolling interests associated with these entities were written off.  See Note 10 for more information.

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Accumulated Other Comprehensive Income (Loss)

Dominion Energy

The following table presents Dominion Energy’s changes in AOCI (net of tax) and reclassifications out of AOCI by component:

	Commodity			Interest Rate			Foreign Currency			Total Derivative-Hedging Activities(1)			Investment Securities(2)			Pension and other postretirement benefit costs(3)			Equity Method Investees(4)			Total
(millions)
Year Ended December 31, 2021
Beginning balance	$	(1	)	$	(418	)	$	—		$	(419	)	$	62		$	(1,359	)	$	(1	)	$	(1,717	)
Other comprehensive income     before reclassifications:     gains (losses)		—			15			—			15			(7	)		144			(3	)		149
Amounts reclassified from     AOCI: (gains) losses
Purchased gas		1			—			—			1			—			—			—			1
Interest and related     charges		—			60			—			60			—			—			—			60
Other income		—			—			—			—			(23	)		111			—			88
Total		1			60			—			61			(23	)		111			—			149
Income tax expense		—			(15	)		—			(15	)		5			(29	)		—			(39	)
Total, net of tax		1			45			—			46			(18	)		82			—			110
Net current period other comprehensive income (loss)		1			60			—			61			(25	)		226			(3	)		259
Ending balance	$	—		$	(358	)	$	—		$	(358	)	$	37		$	(1,133	)	$	(4	)	$	(1,458	)
Year Ended December 31, 2020
Beginning balance	$	16		$	(426	)	$	3		$	(407	)	$	37		$	(1,421	)	$	(2	)	$	(1,793	)
Other comprehensive income     before reclassifications:     gains (losses)		—			(231	)		(8	)		(239	)		43			25			1			(170	)
Amounts reclassified from     AOCI: (gains) losses
Operating revenue		(25	)		—			—			(25	)		—			—			—			(25	)
Purchased gas		4			—			—			4			—			—			—			4
Discontinued operations		(2	)		236			6			240			—			—			—			240
Interest and related     charges		—			83			—			83			—			—			—			83
Other income		—			—			—			—			(24	)		50			—			26
Total		(23	)		319			6			302			(24	)		50			—			328
Income tax expense		6			(80	)		(1	)		(75	)		6			(13	)		—			(82	)
Total, net of tax		(17	)		239			5			227			(18	)		37			—			246
Net current period other comprehensive income (loss)		(17	)		8			(3	)		(12	)		25			62			1			76
Ending balance	$	(1	)	$	(418	)	$	—		$	(419	)	$	62		$	(1,359	)	$	(1	)	$	(1,717	)

(1) Net of $119 million and $141 million tax at December 31, 2021 and 2020, respectively.

(2) Net of $(10) million and $(21) million tax at December 31, 2021 and 2020, respectively.

(3) Net of $396 million and $478 million tax at December 31, 2021 and 2020, respectively.

(4) Net of $1 million and $— million tax at December 31, 2021 and 2020, respectively.

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Virginia Power

The following table presents Virginia Power’s changes in AOCI (net of tax) and reclassification out of AOCI by component:

	Interest Rate			Total Derivative-Hedging Activities(1)			Investment Securities(2)			Total
(millions)
Year Ended December 31, 2021
Beginning balance	$	(60	)	$	(60	)	$	8		$	(52	)
Other comprehensive income before     reclassifications: gains (losses)		13			13			(2	)		11
Amounts reclassified from AOCI: (gains) losses
Interest and related charges		3			3			—			3
Other income		—			—			(3	)		(3	)
Total		3			3			(3	)		—
Income tax expense		(1	)		(1	)		1			—
Total, net of tax		2			2			(2	)		—
Net current period other comprehensive income (loss)		15			15			(4	)		11
Ending balance	$	(45	)	$	(45	)	$	4		$	(41	)
Year Ended December 31, 2020
Beginning balance	$	(34	)	$	(34	)	$	5		$	(29	)
Other comprehensive income before     reclassifications: gains (losses)		(28	)		(28	)		6			(22	)
Amounts reclassified from AOCI: (gains) losses
Interest and related charges		2			2			—			2
Other income		—			—			(4	)		(4	)
Total		2			2			(4	)		(2	)
Income tax expense		—			—			1			1
Total, net of tax		2			2			(3	)		(1	)
Net current period other comprehensive income (loss)		(26	)		(26	)		3			(23	)
Ending balance	$	(60	)	$	(60	)	$	8		$	(52	)

(1)  Net of $16 million and $21 million tax at December 31, 2021 and 2020, respectively.

(2) Net of $(2) million and $(3) million tax at December 31, 2021 and 2020, respectively.

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 Compensation and Talent Development 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, 2021, approximately 19 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, 2021, 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, 2021, 2020 and 2019 include $42 million, $64 million and $46 million, respectively, of compensation costs and $9 million, $16 million and $11 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.

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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, 2021, 2020 and 2019:

	Shares			Weighted - average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2018		1,208		$	73.03
Granted		614			76.49
Vested		(324	)		71.75
Cancelled and forfeited		(96	)		77.16
Nonvested at December 31, 2019		1,402		$	74.77
Granted		531			81.74
Vested		(424	)		74.39
Cancelled and forfeited		(99	)		81.59
Nonvested at December 31, 2020		1,410		$	77.41
Granted		518			71.78
Vested		(505	)		73.54
Cancelled and forfeited		(113	)		75.57
Nonvested at December 31, 2021		1,310		$	76.65

As of December 31, 2021, unrecognized compensation cost related to nonvested restricted stock awards totaled $55 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 $37 million, $35 million and $23 million in 2021, 2020 and 2019, 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 2019, a cash-based performance grant was made to officers. Payout of the performance grant occurred in January 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 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 payout under the grant was $5.7 million, all of which was accrued at December 31, 2021.

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, 2021, the targeted amount of the three-year grant was $10 million and a liability of $6 million had been accrued for this award.

In February 2021, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2024 based on the achievement of two performance metrics during 2021, 2022 and 2023: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC. There is an additional opportunity to earn a portion of the award based on Dominion Energy’s relative price-earnings ratio performance. At December 31, 2021, the targeted amount of the three-year grant was $13 million and a liability of $4 million had been accrued for this award.

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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, 2021, 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, 2021, neither the Ohio Commission nor the Utah Commission had restricted the payment of dividends by East Ohio or Questar Gas, respectively.

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, 2021, 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, Series B Preferred Stock or Series C 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 who commenced employment prior to July 2021. 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 $1.5 billion and $1.9 billion in 2021 and 2020, respectively, versus expected returns of $1.0 billion and $933 million, respectively. Differences between

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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 fourth quarter of 2021, Dominion Energy recognized the effects of a curtailment for certain pension plans resulting from an option that will provide certain active employees a one-time choice to transition to an enhanced defined contribution plan in lieu of accruing pension benefits for future services. The curtailment resulted in a decrease in the pension benefit obligation of $26 million and an increase to net periodic pension cost of $2 million. The effects of the curtailment are included in the measurement of Dominion Energy’s pension plans as of December 31, 2021.

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 were 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.  

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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:

	Pension Benefits						Other Postretirement Benefits
Year Ended December 31,	2021			2020			2021			2020
(millions, except percentages)
Dominion Energy
Changes in benefit obligation:
Benefit obligation at beginning of year	$	11,363		$	10,446		$	1,746		$	1,769
Service cost		170			173			25			28
Interest cost		317			351			46			58
Benefits paid		(488	)		(461	)		(105	)		(120	)
Actuarial (gains) losses during the year		(413	)		992			(161	)		33
Plan amendments		—			—			(14	)		(6	)
Settlements and curtailments(1)		(59	)		(138	)		—			(16	)
Benefit obligation at end of year	$	10,890		$	11,363		$	1,537		$	1,746
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	10,979		$	9,631		$	2,100		$	1,880
Actual return (loss) on plan assets		1,202			1,602			294			300
Employer contributions		284			278			—			13
Benefits paid		(488	)		(461	)		(71	)		(93	)
Settlements(2)		(32	)		(71	)		—			—
Fair value of plan assets at end of year	$	11,945		$	10,979		$	2,323		$	2,100
Funded status at end of year	$	1,055		$	(384	)	$	786		$	354
Amounts recognized in the Consolidated Balance Sheets    at December 31:
Noncurrent pension and other postretirement benefit assets	$	1,246		$	1,054		$	1,064		$	650
Other current liabilities		(12	)		(14	)		(15	)		(15	)
Noncurrent pension and other postretirement benefit liabilities		(179	)		(1,424	)		(263	)		(281	)
Net amount recognized	$	1,055		$	(384	)	$	786		$	354
Significant assumptions used to determine benefit    obligations as of December 31:
Discount rate	3.06%-3.19%			2.73%–2.95%			3.04%-3.11%			2.69%–2.80%
Weighted average rate of increase for compensation	4.51%			4.53%			n/a			n/a
Crediting interest rate for cash balance and similar plans	1.81%-1.94%			1.93% - 2.15%			n/a			n/a

(1) 2021 amounts include curtailments and settlements recognized primarily as a result of the employee choice program and settlements of nonqualified pension obligations. 2020 amounts include curtailment and settlements recognized as a result of the GT&S Transaction as well as settlements of qualified and nonqualified pension obligations.  

(2) 2021 amounts relate to settlements of nonqualified pension obligations and 2020 amounts relate primarily to settlements of qualified and nonqualified pension obligations.

Actuarial gains recognized during 2021 in Dominion Energy’s pension benefit obligations were $413 million primarily driven by an increase in discount rates. Actuarial losses recognized during 2020 in Dominion Energy’s pension benefit obligations include a $1.0 billion loss resulting primarily from a decrease in discount rate. Actuarial gains recognized during 2021 in Dominion Energy’s other postretirement benefit obligations were $161 million resulting from an increase in discount rates, better than expected per capita claims experience and changes in demographic and economic assumptions based on an experience study completed in 2021. 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 an $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.

The ABO for all of Dominion Energy’s defined benefit pension plans was $10.2 billion and $10.6 billion at December 31, 2021 and 2020, 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 2021, Dominion Energy issued 250,000 shares of its Series C Preferred Stock to its qualified defined benefit pension plans, valued at $250 million. 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 of common and preferred stock were contributed though private placements 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 registration rights on customary terms with respect to the shares of

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common and preferred stock. Dominion Energy is not required to make any contributions to its qualified defined benefit pension plans in 2022. Dominion Energy considers voluntary contributions from time to time, either in the form of cash or equity securities.

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 2021 and 2020. Dominion Energy’s contributions to VEBAs, all of which pertained to employees of operations sold to BHE, totaled $12 million for 2019. Dominion Energy is not required to make any contributions to its VEBAs associated with its other postretirement plans in 2022. Dominion Energy considers voluntary contributions from time to time, either in the form of cash or equity securities.

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:

	Pension Benefits				Other Postretirement Benefits
As of  December 31,	2021		2020		2021		2020
(millions)
Dominion Energy
Benefit obligation	$	9,420	$	10,697	$	261	$	305
Fair value of plan assets		9,229		9,259		7		9

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:

As of  December 31,	2021		2020
(millions)
Accumulated benefit obligation	$	127	$	9,970
Fair value of plan assets		53		9,259

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for Dominion Energy’s plans:

	Estimated Future Benefit Payments
	Pension Benefits		Other Postretirement Benefits
(millions)
Dominion Energy
2022	$	513	$	101
2023		516		100
2024		529		99
2025		541		97
2026		548		96
2027-2031		2,833		450

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 27% U.S. equity, 18% non-U.S. equity, 32% fixed income, 3% real estate and 20% 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.

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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:

At December 31,	2021								2020
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Dominion Energy
Cash and cash equivalents	$	25	$	5	$	—	$	30	$	20	$	1	$	—	$	21
Common and preferred stocks:
U.S.(1)		2,592		244		—		2,836		2,405		—		—		2,405
International		1,773		19		—		1,792		1,727		—		—		1,727
Insurance contracts		—		279		—		279		—		409		—		409
Corporate debt instruments		81		1,439		—		1,520		32		1,385		—		1,417
Government securities		39		914		—		953		30		772		—		802
Total recorded at fair value	$	4,510	$	2,900	$	—	$	7,410	$	4,214	$	2,567	$	—	$	6,781
Assets recorded at NAV(2):
Common/collective trust funds								3,010								2,905
Alternative investments:
Real estate funds								116								108
Private equity funds								1,233								856
Debt funds								162								168
Hedge funds								14								13
Total recorded at NAV							$	4,535							$	4,050
Total investments(3)							$	11,945							$	10,831

(1) Includes $258 million of Dominion Energy preferred stock and no Dominion Energy common stock at December 31, 2021 and $365 million of Dominion Energy common stock at December 31, 2020.

(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 of $35 million, net accrued income of $27 million, and includes net assets related to pending purchases of securities of $62 million at December 31, 2021. 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.

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The fair values of Dominion Energy’s other postretirement plan assets by asset category are as follows:  

At December 31,	2021								2020
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Dominion Energy
Cash and cash equivalents	$	3	$	1	$	—	$	4	$	—	$	2	$	—	$	2
Common and preferred stocks:
U.S.		898		14		—		912		817		—		—		817
International		256		1		—		257		240		—		—		240
Insurance contracts		—		16		—		16		—		23		—		23
Corporate debt instruments		5		61		—		66		2		60		—		62
Government securities		2		47		—		49		2		42		—		44
Total recorded at fair value	$	1,164	$	140	$	—	$	1,304	$	1,061	$	127	$	—	$	1,188
Assets recorded at NAV(1):
Common/collective trust funds								840								765
Alternative investments:
Real estate funds								13								10
Private equity funds								152								117
Debt funds								9								10
Hedge funds								1								1
Total recorded at NAV							$	1,015							$	903
Total investments(2)							$	2,319							$	2,091

(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 $5 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $3 million at December 31, 2021. 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.

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.

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• 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 $1 million, $13 million and $16 million for the years ended December 31, 2021, 2020 and 2019, 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:  

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2021			2020			2019			2021			2020			2019
(millions, except percentages)
Dominion Energy
Service cost	$	170		$	173		$	162		$	25		$	28		$	26
Interest cost		317			351			394			46			58			68
Expected return on plan assets		(834	)		(777	)		(708	)		(173	)		(156	)		(140	)
Amortization of prior service (credit) cost		—			1			1			(42	)		(49	)		(52	)
Amortization of net actuarial loss		193			206			172			4			6			10
Settlements, curtailments and special termination benefits		10			14			72			—			(59	)		42
Net periodic benefit (credit) cost	$	(144	)	$	(32	)	$	93		$	(140	)	$	(172	)	$	(46	)
Changes in plan assets and benefit obligations    recognized in other comprehensive income    and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	(782	)	$	166		$	16		$	(282	)	$	(110	)	$	(98	)
Prior service (credit) cost		—			—			—			(13	)		(6	)		2
Settlements and curtailments		(36	)		(81	)		6			—			59			—
Less amounts included in net periodic benefit    cost:
Amortization of net actuarial loss		(193	)		(206	)		(172	)		(4	)		(6	)		(10	)
Amortization of prior service credit (cost)		—			(1	)		(1	)		42			49			52
Total recognized in other comprehensive    income and regulatory assets and liabilities	$	(1,011	)	$	(122	)	$	(151	)	$	(257	)	$	(14	)	$	(54	)
Significant assumptions used to determine    periodic cost:
Discount rate	2.73%-3.29%			2.77%-3.63%			3.57%-4.43%			2.69%-2.80%			3.07%-3.52%			4.05% to 4.41%
Expected long-term rate of return on plan assets	7.00%-8.45%			7.00%-8.60%			7.00% -8.65%			8.45%			8.50%			8.50%
Weighted average rate of increase for    compensation	4.53%			4.23%			4.20%			n/a			n/a			n/a
Crediting interest rate for cash balance and similar plans	1.93%-2.15%			2.31-2.83%			2.77-3.63%			n/a			n/a			n/a
Healthcare cost trend rate(1)										6.25%			6.25%			6.50% to 6.60%
Rate to which the cost trend rate is assumed to    decline (the ultimate trend rate)(1)										5.00%			5.00%			5.00%
Year that the rate reaches the ultimate trend rate(1)										2026-2027			2025-2026			2023-2025

(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:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2021		2020		2021			2020
(millions)
Dominion Energy
Net actuarial loss	$	2,198	$	3,207	$	(166	)	$	120
Prior service (credit) cost		2		4		(203	)		(232	)
Total(1)	$	2,200	$	3,211	$	(369	)	$	(112	)

(1) As of December 31, 2021, of the $2.2 billion and $(369) million related to pension benefits and other postretirement benefits, $1.7 billion and $(155) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2020,

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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.

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 2019, Virginia Power made no contributions to the Dominion Energy Pension Plan. 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, which was paid in 2021. While Virginia Power has not been notified by Dominion Energy of any required contributions to be made in 2022, it anticipates that it may have to contribute approximately $175 million as a result of Dominion Energy’s contribution made in December 2021. Virginia Power’s net periodic pension cost related to this plan was $86 million, $118 million and $152 million in 2021, 2020 and 2019, 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 $(72) million, $(58) million and $(27) million in 2021, 2020 and 2019, 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.

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Virginia Power funds other postretirement benefit costs through VEBAs. During 2021, 2020 and 2019, Virginia Power made no contributions to the VEBAs and does not expect to contribute to the VEBAs in 2022.

Defined Contribution Plans

Dominion Energy also sponsors defined contribution employee savings plans that cover substantially all employees. During 2021, 2020 and 2019, Dominion Energy recognized $65 million, $67 million and $69 million, respectively, as employer matching contributions to these plans, excluding discontinued operations. Virginia Power also participates in these employee savings plans. During 2021, 2020 and 2019, Virginia Power recognized $20 million, $19 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. The Companies maintain various insurance programs, including general liability insurance coverage which provides coverage for personal injury or wrongful death cases. 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 meet applicable requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of the Companies’ facilities are subject to the CAA’s permitting and other requirements.

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Ozone Standards

The EPA published final non-attainment designations for the October 2015 ozone standard in June 2018 with states required to develop plans to address the new standard. Certain states in which the Companies operate have developed plans, and had such plans approved or partially approved by the EPA, which are not expected to have a material impact on the Companies’ results of operations or cash flows. However, until implementation plans for the standard are developed and approved for all states in which the Companies operate, 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.

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. The ACE Rule regulated GHG emissions from existing coal-fired power plants pursuant to Section 111(d) of the CAA and required states to develop plans by July 2022 establishing unit-specific performance standards for existing coal-fired power plants. 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 would take effect upon issuance of the court’s mandate. In March 2021, the court issued a partial mandate vacating and remanding all parts of the ACE Rule except for the portion of the ACE Rule that repealed the Clean Power Plan. In October 2021, the U.S. Supreme Court agreed to hear a challenge of the U.S. Court of Appeals for the D.C. Circuit’s decision on the ACE Rule. While the EPA has stated its intention to replace the ACE Rule, it is unknown at this time if or how the EPA will issue a replacement for 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 best operating practices. In January 2021, the EPA published a final rule affirming that fossil fuel-fired electric generating units meet the requirement that a source category “significantly contribute” to endangering air pollution for the purposes of regulating GHG emissions from new, modified and reconstructed stationary sources. The January 2021 rule also established a threshold for the “significant contribution” threshold that would have meant that no other source category, such as oil and gas facilities, petroleum refineries, and boilers, would meet that requirement at this time. In April 2021, the U.S. Court of Appeals for the D.C. Circuit granted an unopposed motion by the EPA to vacate and remand the January 2021 rule. The proposed revision to the performance standards for coal-fired steam generating units 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.

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

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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, technological, and cost 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 13 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 remediation plans associated with two sites, including one at Virginia Power, and expects to commence remediation activities in 2022 depending on receipt of final permits and approvals. For one site associated with Dominion Energy, final approval of an updated work plan was received from the Army Corps of Engineers in December 2021, resulting in an additional $11 million of reserves and corresponding regulatory assets. At December 31, 2021 and 2020, Dominion Energy had $45 million and $42 million, respectively, of reserves recorded. Dominion Energy’s reserves include charges of $14 million ($11 million after-tax) recorded in 2020, in other operations and maintenance expense in the Consolidated Statements of Income. At December 31, 2021 and 2020, Virginia Power had $25 million and $26 million, respectively, of reserves recorded. Virginia Power’s reserves include charges of $10 million ($7 million after-tax) recorded in 2020, in other operations and maintenance expense in the Consolidated Statements of Income. 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.

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SCANA Legal Proceedings

The following describes certain legal proceedings involving Dominion Energy, SCANA or DESC relating primarily to events occurring before closing of the SCANA Combination. 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, 2021 and 2020 include reserves of $274 million and $208 million, respectively, included in other current liabilities, and insurance receivables of $118 million and $8 million, respectively, included within other receivables. These balances at December 31, 2021 and 2020 include $85 million and $8 million, respectively, of offsetting reserves and insurance receivables related to personal injury or wrongful death cases which are currently pending. Dominion Energy’s Consolidated Statements of Income for the years ended December 31, 2021, 2020 and 2019 include charges of $100 million ($75 million after-tax), $90 million ($68 million after-tax) and $641 million ($480 million after-tax), respectively, 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) within other income (expense) (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). The plaintiffs alleged, 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. In December 2018, the State Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement. The court entered an order granting final approval of the settlement in June 2019, which became effective in July 2019. The settlement agreement, contingent upon the closing of the SCANA Combination, provided that SCANA and DESC establish an escrow account and proceeds from the escrow account would be distributed to the plaintiffs, 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 plaintiffs estimated 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. 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, which was completed by DESC in October 2020. In December 2021, the court approved a motion for and DESC completed the repurchase of $8 million of property, plant and equipment previously transferred to the plaintiffs.

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 were substantially similar to those in the DESC Ratepayer Case. 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 provided that Dominion Energy and Santee Cooper establish a fund for the benefit of class members in the amount of $520 million, of which Dominion Energy’s portion was $320 million of shares of Dominion Energy common stock. 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 were 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

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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 alleged, 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. 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 alleged, 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 December 2019, the parties executed a settlement agreement pursuant to which SCANA would pay $192.5 million, up to $32.5 million of which could be satisfied through the issuance of shares of Dominion Energy common stock, subject to court approval. 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, and granted final approval in July 2020. In March 2020, SCANA funded an escrow account with $160 million in cash and paid the balance of $32.5 million in cash in August 2020 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 (the State Court Derivative Case). 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 petition was denied in June 2021. Also in June 2021, the parties reached an agreement in principle in the amount of $33 million to resolve this matter, subject to court approval. This settlement was reached in contemplation of and will be utilized to satisfy a portion of the Federal Court Merger Case and the State Court Merger Case discussed below. In November 2021, the parties executed a settlement agreement and filed with the State Court of Common Pleas in Richland County, South Carolina for approval.

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, 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 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 (the Federal Court Merger Case). 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. In June 2021, the parties reached an agreement in principle in the amount of $63 million to resolve this matter as well as the State Court Merger Case described below, subject to court approval. This settlement was reached in contemplation of and will be partially satisfied by the State Court Derivative Case settlement described above. In November 2021, the parties executed a settlement agreement, as described above relating to this matter as well as the State Court Derivative Case and the State Court Merger Case, and filed with the State Court of Common Pleas in Richland County, South Carolina for approval.

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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 State Court Merger Case). 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. In June 2021, the parties reached an agreement in principle as described above relating to this matter as well as the Federal Court Merger Case and the State Court Derivative Case. In November 2021, the parties executed a settlement agreement, as described above relating to this matter as well as the State Court Derivative Case and the Federal Court Merger Case, and filed with the State Court of Common Pleas in Richland County, South Carolina for approval.

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. In November 2021, the U.S Court of Appeals for the Fourth Circuit affirmed the lower court ruling.

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. In July 2021, the parties executed a settlement agreement requiring DESC to pay $99 million, which could be satisfied in either cash or shares of Dominion Energy common stock. Also in July 2021, the State Court of Common Pleas in Fairfield County, South Carolina approved the settlement. In July 2021, Dominion Energy issued 1.4 million shares of Dominion Energy common stock to satisfy DESC’s obligation under the settlement agreement.

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 June 2021, the parties executed a settlement agreement which allows DESC to fund the settlement amount through a combination of cash, shares of Dominion Energy common stock or real estate with an initial payment of at least $43 million in shares of Dominion Energy common stock. In August 2021, Dominion Energy issued 0.6 million shares of its common stock to satisfy DESC’s obligation for the initial payment under the settlement agreement.

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.

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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 and entered guilty pleas in the U.S. District Court for the District of South Carolina and in South Carolina state court in February 2021. As a result of the pleas, Dominion Energy has terminated indemnity for these former executive officers related to these two cases.

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 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 contested approximately $285 million of filed liens in Fairfield County, South Carolina. Most of these asserted liens were claims that relate to work performed by Westinghouse subcontractors before the Westinghouse bankruptcy, although some of them were claims arising from work performed after the Westinghouse bankruptcy.

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.

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Further, some Westinghouse subcontractors that made claims against Westinghouse in the bankruptcy proceeding also filed claims against DESC and Santee Cooper in South Carolina state court for damages. Many of these claimants asserted construction liens against the NND Project site. In December 2021, settlements were reached to resolve all remaining claims made by Westinghouse subcontractors. All amounts for which Dominion Energy was ultimately responsible were funded utilizing, and did not exceed, the portion of the Toshiba Settlement allocated for such balances within the SCANA Merger Approval Order recorded in regulatory liabilities on Dominion Energy’s Consolidated Balance Sheets.

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 2021 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 $3.2 billion and $1.9 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 2021 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2021 U.S. Bureau of Labor Statistics indices. Dominion Energy believes that decommissioning funds and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. In addition, Dominion Energy believes that the decommissioning funds and their expected earnings will be sufficient to cover expected decommissioning costs for the Summer unit, particularly when combined with future ratepayer collections and contributions. The Companies believe 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 $13.5 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 first quarter of 2021, the total liability protection per nuclear incident available to all participants in the Secondary Financial Protection Program decreased from $13.8 billion to $13.7 billion. During the second quarter of 2021, the total liability protection per nuclear incident available to all participants in the Secondary Financial Protection Program decreased from $13.7 billion to $13.5 billion. These decreases do 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:

	Coverage
(billions)
Dominion Energy
Millstone	$	1.06
Kewaunee		0.05
Summer		2.75
Virginia Power
Surry	$	1.06
North Anna		1.06

The Companies’ nuclear property insurance coverage for Millstone, Summer, Surry and North Anna meets or 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

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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 $76 million and $35 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. In January 2022, a settlement agreement was entered into for $48 million. Dominion Energy received the settlement funds in February 2022.

In 2021, Virginia Power received payments of $25 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2019 through December 31, 2019. In addition, Dominion Energy received payments of $9 million for resolution of claims incurred at Millstone for the period of July 1, 2019 through June 30, 2020 and $1 million for resolution of its share of claims incurred at Summer for the period of January 1, 2020 through December 31, 2020.

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.

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 $52 million and $46 million at

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December 31, 2021 and 2020, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $39 million and $35 million at December 31, 2021 and 2020, respectively.

The Companies will continue to manage their spent fuel until it is accepted by the DOE.

Long-Term Purchase Agreements

At December 31, 2021, 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:

	2022		2023		2024		2025		2026		Thereafter		Total
(millions)
Purchased electric capacity(1)	$	66	$	66	$	66	$	65	$	68	$	681	$	1,012

(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 $59 million and $52 million for the years ended December 31, 2021 and 2020, 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. In addition, at December 31, 2021, Dominion Energy had issued an additional $20 million of guarantees, primarily to support third parties. No amounts related to these guarantees have been recorded.

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, 2021, Dominion Energy had issued the following subsidiary guarantees:

	Maximum Exposure
(millions)
Commodity transactions(1)	$	2,077
Nuclear obligations(2)		243
Solar(3)		321
Other(4)		1,282
Total(5)	$	3,923

(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, II, Inc. 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 property and an offshore wind installation vessel discussed in Note 15.

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Additionally, at December 31, 2021, Dominion Energy had purchased $217 million of surety bonds, including $154 million at Virginia Power, and authorized the issuance of letters of credit by financial institutions of $131 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, 2021, 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 for the year ended December 31, 2020. These commitments are to be funded at various intervals through 2028. Dominion Energy’s Consolidated Balance Sheets include $43 million and $73 million in other deferred credits and other liabilities at December 31, 2021 and 2020, respectively and $26 million in other current liabilities at December 31, 2021.

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, 2021, Dominion Energy’s credit exposure totaled $152 million. Of this amount, investment grade counterparties, including those internally rated, represented 85%, and no single counterparty, whether investment grade or non-investment grade, exceeded $45 million of exposure.

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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, 2021, Virginia Power’s credit exposure totaled $16 million. Of this amount, investment grade counterparties, including those internally rated, represented 47%, and no single counterparty exceeded $4 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, 2021 and 2020 Dominion Energy would have been required to post $31 million and $14 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 $66 million and $1 million of collateral at December 31, 2021 and 2020, respectively, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. 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, 2021 and 2020 was $97 million and $15 million, respectively, which does not include the impact of any offsetting asset positions.

Certain of Virginia Power’s derivative instruments contain credit-related contingent provisions. These provisions require Virginia Power 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, 2021 and 2020, Virginia Power would have been required to post an additional $22 million and $2 million, respectively, of additional collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset position and any amounts already posted for derivatives and non-derivative contracts, per contractual terms. Virginia Power had posted $54 million of collateral at December 31, 2021 related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. No such amounts were posted at December 31, 2020. 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 was $76 million and $2 million at December 31, 2021 and December 31, 2020, respectively, which does not include the impact of any offsetting asset positions.

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, 2021, Virginia Power’s derivative assets and liabilities with affiliates were $29 million and $6 million, respectively. At December 31, 2020, Virginia Power’s derivative assets and liabilities with affiliates were $3 million and $22 million, respectively.

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Virginia Power participates in certain Dominion Energy benefit plans as described in Note 22. At December 31, 2021 and 2020, 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 $522 million and $436 million, respectively. At December 31, 2021 and 2020, 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 $431 million and $354 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:

Year Ended December 31,	2021		2020		2019
(millions)
Commodity purchases from affiliates	$	742	$	569	$	690
Services provided by affiliates(1)		494		455		503
Services provided to affiliates		18		18		24

(1) Includes capitalized expenditures of $161 million, $141 million and $133 million for the year ended December 31, 2021, 2020 and 2019, respectively.

Virginia Power has borrowed funds from Dominion Energy under short-term borrowing arrangements. There were $699 million and $380 million in short-term demand note borrowings from Dominion Energy as of December 31, 2021 and 2020, respectively. The weighted-average interest rate of these borrowings was 0.26% and 0.30% at December 31, 2021 and 2020, respectively. Virginia Power had no outstanding borrowings, net of repayments under the Dominion Energy money pool for its nonregulated subsidiaries as of December 31, 2021 and 2020. Interest charges related to Virginia Power’s borrowings from Dominion Energy were immaterial for the years ended December 31, 2021, 2020 and 2019.

There were no issuances of Virginia Power’s common stock to Dominion Energy in 2021, 2020 or 2019.

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:

Primary Operating Segment	Description of Operations	Dominion Energy	Virginia Power
Dominion Energy Virginia	Regulated electric distribution	X	X
	Regulated electric transmission	X	X
	Regulated electric generation fleet(1)	X	X
Gas Distribution	Regulated gas distribution and storage(2)	X
Dominion Energy South Carolina	Regulated electric distribution	X
	Regulated electric transmission	X
	Regulated electric generation fleet	X
	Regulated gas distribution and storage	X
Contracted Assets	Nonregulated electric generation fleet(3)	X
	Noncontrolling interest in Cove Point	X

(1)    Includes Virginia Power’s non-jurisdictional generation operations.

(2)   Includes renewable natural gas operations as well as Wexpro’s natural gas development and production operations.

(3)    Includes solar generation facility development operations.

In addition to the operating segments above, the Companies also report a Corporate and Other segment.

Dominion Energy

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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 (prior to December 1, 2021), 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 2021, Dominion Energy reported after-tax net expenses of $99 million in the Corporate and Other segment, including $97 million of after-tax net benefit for specific items with $493 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 2021 primarily related to the impact of the following items:

• A $347 million ($261 million after-tax) loss related to economic hedging activities, attributable to Contracted Assets;

• $266 million ($199 million after-tax) of charges associated with the settlement of the South Carolina electric base rate case, attributable to Dominion Energy South Carolina;

• A $211 million ($161 million after-tax) net loss on the sale of non-wholly-owned nonregulated solar facilities, attributable to Contracted Assets;

• A $151 million ($112 million after-tax) loss from an unbilled revenue reduction at Virginia Power, attributable to Dominion Energy Virginia;

• A $125 million ($93 million after-tax) net charge associated with the settlement of the 2021 Triennial Review, attributable to Dominion Energy Virginia;

• A $77 million ($57 million after-tax) charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to Virginia’s 2021 budget process, attributable to Dominion Energy Virginia;

• A $70 million ($53 million after-tax) charge associated with litigation acquired in the SCANA Combination, attributable to Dominion Energy South Carolina;

• A $68 million ($50 million after-tax) charge associated with storm damage and service restoration in Virginia Power’s service territory, attributable to Dominion Energy Virginia;

• A $61 million ($45 million after-tax) charge for amortization of a regulatory asset established in connection with the settlement of the 2021 Triennial Review, attributable to Dominion Energy Virginia; and

• A $44 million ($35 million after-tax) charge related to a revision in estimated recovery of spent nuclear fuel costs associated with the decommissioning of Kewaunee, attributable to Contracted Assets; partially offset by

• A $568 million ($445 million after-tax) gain related to investments in nuclear decommissioning trust funds, attributable to:

• Contracted Assets ($390 million after-tax); and

• Dominion Energy Virginia ($55 million after-tax); and

• A $130 million ($97 million after-tax) benefit for a change in the expected CCRO to be provided to Virginia retail electric customers under the GTSA, attributable to Dominion Energy Virginia.

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

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• 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.

203

The following table presents segment information pertaining to Dominion Energy’s operations:

Year Ended December 31,	Dominion Energy Virginia			Gas Distribution		Dominion Energy South Carolina			Contracted Assets			Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2021
Total revenue from external customers	$	8,012		$	2,660	$	2,968		$	1,018		$	(759	)	$	60		$	13,959
Intersegment revenue		(13	)		5		7			67			943			(1,004	)		5
Total operating revenue		7,999			2,665		2,975			1,085			184			(944	)		13,964
Depreciation, depletion and amortization		1,299			380		486			162			151			—			2,478
Equity in earnings of equity method investees		—			—		(3	)		259			20			—			276
Interest income		13			6		10			81			17			(26	)		101
Interest and related charges		537			86		206			52			499			(26	)		1,354
Income tax expense (benefit)		462			116		125			112			(390	)		—			425
Net income from discontinued operations		—			—		—			—			641			—			641
Net income (loss) attributable to Dominion    Energy		1,919			600		437			431			(99	)		—			3,288
Investment in equity method investees(1)		—			106		—			2,738			88			—			2,932
Capital expenditures		3,762			1,252		694			277			76			—			6,061
Total assets (billions)		50.3			18.5		16.4			12.3			7.1			(5.0	)		99.6
2020
Total revenue from external customers	$	7,802		$	2,345	$	2,782		$	1,020		$	200		$	48		$	14,197
Intersegment revenue		(15	)		10		5			51			963			(1,039	)		(25	)
Total operating revenue		7,787			2,355		2,787			1,071			1,163			(991	)		14,172
Depreciation, depletion and amortization		1,247			344		474			182			85			—			2,332
Equity in earnings of equity method investees		—			—		(1	)		35			6			—			40
Interest income		13			6		12			91			73			(88	)		107
Interest and related charges		527			76		219			75			568			(88	)		1,377
Income tax expense (benefit)		496			121		107			(16	)		(625	)		—			83
Net income (loss) from discontinued    operations		—			—		—			167			(2,045	)		—			(1,878	)
Net income (loss) attributable to Dominion    Energy		1,891			560		419			402			(3,673	)		—			(401	)
Investment in equity method investees(1)		—			55		—			2,784			95			—			2,934
Capital expenditures		3,406			1,151		700			649			425			—			6,331
Total assets (billions)		46.0			17.1		16.0			13.1			8.6			(4.9	)		95.9
2019
Total revenue from external customers	$	8,170		$	2,367	$	2,948		$	1,083		$	(239	)	$	79		$	14,408
Intersegment revenue		(13	)		18		4			73			1,071			(1,160	)		(7	)
Total operating revenue		8,157			2,385		2,952			1,156			832			(1,081	)		14,401
Depreciation, depletion and amortization		1,216			335		452			180			100			—			2,283
Equity in earnings of equity method investees		—			2		(4	)		(1	)		11			—			8
Interest income		11			4		9			97			112			(136	)		97
Interest and related charges		530			116		242			98			636			(136	)		1,486
Income tax expense (benefit)		482			114		163			20			(570	)		—			209
Net income from discontinued operations		—			—		—			183			533			—			716
Net income (loss) attributable to Dominion    Energy		1,786			487		430			460			(1,805	)		—			1,358
Capital expenditures		3,002			853		562			367			537			—			5,321

(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.

204

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 2021, Virginia Power reported after-tax net expenses of $202 million in the Corporate and Other segment, including $202 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 2021 primarily related to the impact of the following items:

• A $151 million ($112 million after-tax) loss from an unbilled revenue reduction;

• A $125 million ($93 million after-tax) net charge associated with the settlement of the 2021 Triennial Review;

• A $77 million ($57 million after-tax) charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to Virginia’s 2021 budget process;

• A $68 million ($50 million after-tax) charge associated with storm damage and service restoration in its service territory; and

• A $61 million ($45 million after-tax) charge for amortization of a regulatory asset established in connection with the settlement of the 2021 Triennial Review; partially offset by

• A $130 million ($97 million after-tax) benefit for a change in the expected CCRO to be provided to Virginia retail electric customers under the GTSA.

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.

205

The following table presents segment information pertaining to Virginia Power’s operations:

Year Ended December 31,	Dominion Energy Virginia		Corporate and Other			Consolidated Total
(millions)
2021
Operating revenue	$	7,976	$	(506	)	$	7,470
Depreciation and amortization		1,296		68			1,364
Interest income		11		—			11
Interest expense (benefit) and related charges		535		(1	)		534
Income tax expense (benefit)		467		(70	)		397
Net income (loss)		1,914		(202	)		1,712
Capital expenditures		3,756		—			3,756
Total assets (billions)		47.9		—			47.9
2020
Operating revenue	$	7,763	$	—		$	7,763
Depreciation and amortization		1,245		7			1,252
Interest income		11		—			11
Interest expense (benefit) and related charges		524		(8	)		516
Income tax expense (benefit)		500		(271	)		229
Net income (loss)		1,884		(863	)		1,021
Capital expenditures		3,372		—			3,372
Total assets (billions)		43.7		—			43.7
2019
Operating revenue	$	8,137	$	(29	)	$	8,108
Depreciation and amortization		1,215		8			1,223
Interest income		11		—			11
Interest expense (benefit) and related charges		529		(5	)		524
Income tax expense (benefit)		481		(217	)		264
Net income (loss)		1,783		(634	)		1,149
Capital expenditures		2,981		—			2,981

206

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 2021 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, 2021, 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, 2021. 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, 2021.

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 24, 2022

207

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, 2021, 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, 2021, 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, 2021, of Dominion Energy and our report dated February 24, 2022, 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 24, 2022

208

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 2021 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, 2021, 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, 2021. 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, 2021.

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 24, 2022

209

Item 9B. Other Information

None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

210

Part III

Item 10. Directors, Executive Officers and Corporate Governance

DOMINION ENERGY

The information required by this item is incorporated by reference to the sections entitled Item 1—Election of Directors, Corporate Governance—The Committees of the Board and Corporate Governance—Other Governance Policies and Practices—Code of Ethics and Business Conduct in the Dominion Energy 2022 Proxy Statement.

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 information required by this item is incorporated by reference to the sections entitled Executive Compensation, Compensation of Non-Employee Directors and Corporate Governance—The Committees of the Board—Compensation Committee Interlocks and Insider Participation in the 2022 Proxy Statement.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

DOMINION ENERGY

The information required by this item is incorporated by reference to the sections entitled Security Ownership of Certain Beneficial Owners and Management and Executive Compensation—Equity Compensation Plans in the 2022 Proxy Statement.

Item 13. Certain Relationships and Related Transactions, and Director Independence

DOMINION ENERGY

The information required by this item is incorporated by reference to the sections entitled Corporate Governance—Other Governance Policies and Practices —Certain Relationships and Related Party Transactions and Corporate Governance —Director Independence in the 2022 Proxy Statement.

Item 14. Principal Accountant Fees and Services

DOMINION ENERGY

The information required by this item is incorporated by reference to the section entitled Audit-Related Matters—Auditor Fees and Pre-Approval Policy in the 2022 Proxy Statement.

211

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, 2021 and 2020.

Type of Fees	2021		2020
(millions)
Virginia Power
Audit fees	$	2.37	$	2.30
Audit-related fees		—	—
Tax fees		0.04	—
All other fees		—	—
Total Fees	$	2.41	$	2.30

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 2021 meeting, the Dominion Energy Audit Committee approved schedules of services and fees for 2022 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.

212

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 80.

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
3.1.a	Dominion Energy, Inc. Articles of Incorporation, as amended, effective December 9, 2021 (Exhibit 3.1, Form 8-K filed December 9, 2021, 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 May 5, 2021 (Exhibit 3.1, Form 8-K filed May 6, 2021, 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
4	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

213

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); Seventh Supplemental Indenture, dated as of November 1, 2021 (Exhibit 4.2, Form 8-K filed November 22, 2021, File No.000-55337); Eighth Supplemental Indenture, dated as of November 1, 2021 (Exhibit 4.3, Form 8-K filed November 22, 2021, File No.000-55337); Ninth Supplemental Indenture, dated as of January 1, 2022 (Exhibit 4.3, Form 8-K filed January 13, 2022, File No.000-55337).	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

214

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); Twenty-Second Supplemental Indenture, dated as of April 1, 2021 (Exhibit 4.2, Form 8-K, filed April 5, 2021, File No. 1-8489); Twenty-Third Supplemental Indenture, dated as of April 1, 2021 (Exhibit 4.3, Form 8-K, filed April 5, 2021, File No. 1-8489); Twenty-Fourth Supplemental Indenture, dated as of August 1, 2021 (Exhibit 4.2, Form 8-K filed August 12, 2021, File No. 1-8489).	X

215

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); 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); Tenth Supplemental Indenture, dated July 1, 2016 (Exhibit 4.3, Form 8-K filed July 19, 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 4.1, Form 8-K filed June 14, 2019, File No.1-8489).	X
4.11	Registration Rights Agreement, dated August 6, 2021, by and between Dominion Energy, Inc. and South Carolina Department of Revenue (Exhibit 4.1, Form 10-Q filed August 6, 2021, File No. 1-8489).	X
4.12	Registration Rights Agreement, date December 1, 2021, by and between Dominion Energy, Inc. and Gallagher Fiduciary Advisors, LLC on behalf of the Dominion Energy, Inc. Defined Benefit Master Trust (Exhibit 4.2, Form 8-K filed December 9, 2021, File No. 1-8489).	X
4.13	Description of Dominion Energy, Inc.’s Common Stock (filed herewith).	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
10.1	$6,000,000,000 Fifth Amended and Restated Revolving Credit Agreement, dated June 9, 2021, among Dominion Energy, Inc., Virginia Electric and Power Company, Questar Gas Company, Dominion Energy South Carolina, Inc., 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, J.P. Morgan Securities LLC and Mizuho Bank, Ltd., as Co-Sustainability Structuring Agent, and other lenders named therein (Exhibit 10.1, Form 8-K filed June 10, 2021, File No. 1-8489).	X	X
10.2	$900,000,000 Sustainability Revolving Credit Agreement, dated as of June 9, 2021, among Dominion Energy, Inc., Sumitomo Mitsui Banking Corporation, as Administrative Agent and Sustainability Coordinator, Sumitomo Mitsui Banking Corporation, The Bank of Nova Scotia and The Toronto- Dominion Bank, New York Branch, as Joint Lead Arrangers and Joint Bookrunners, and the other lenders named therein (Exhibit 10.2, Form 8-K filed June 10, 2021, File No. 1-8489).	X

216

Exhibit Number	Description	Dominion Energy	Virginia Power
10.3	$1,265,341,250 364-Day Term Loan Credit Agreement, dated as of July 14, 2021, by and Dominion Energy, Inc., as Borrower, Barclays Bank PLC, as Administrative Agent, Barclays Bank PLC, as Sole Leader Arranger and Sole Bookrunner, and the other lenders from time to time parties thereto (Exhibit 10.1, Form 8-K filed July 14, 2021, File No. 1-8489).	X
10.4	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
10.5	DES Services Agreement, dated January 1, 2021, between Dominion Energy Services, Inc. and Virginia Electric and Power Company (Exhibit 10.3, Form 10-K for the fiscal year ended December 31, 2020 filed February 25, 2021, File No.1-8489).		X
10.6	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
10.7	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
10.8*	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), as amended, March 31, 2006 (Exhibit 10.1, Form 8-K filed April 4, 2006, File No. 1-8489).	X
10.9*	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
10.10*	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
10.11*	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 (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2020 filed February 25, 2021, File No.1-8489).	X
10.12*	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, as amended September 26, 2014 (Exhibit 10.4, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014), 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 15, 2021 (filed herewith).	X

217

Exhibit Number	Description	Dominion Energy	Virginia Power
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).	X
10.15*	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).	X
10.16*	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
10.17*	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
10.18*	2021 Restricted Stock Award Agreement for Thomas F. Farrell, II (Exhibit 10.29, Form 10-K for the fiscal year ended December 31, 2020 filed February 25, 2021, File No.1-8489).	X
10.19*	2021 Performance Grant Plan for Thomas F. Farrell, II (Exhibit 10.30, Form 10-K for the fiscal year ended December 31, 2020 filed February 25, 2021, File No.1-8489).	X
10.20*	Dominion Energy, Inc. Deferred Compensation Plan, effective July 1, 2021 (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2020, filed February 25, 2021, File No. 1-8489), as amended September 23, 2021 (Exhibit 10.1, Form 10-Q filed November 5, 2021, File No. 1-8489).	X
10.21*	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
10.22*	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
10.23*	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
10.24*	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
10.25*	2021 Performance Grant Plan under the 2021 Long-Term Incentive Program approved January 21, 2021 (Exhibit 10.26, Form 10-K for the fiscal year ended December 31, 2020 filed February 25, 2021, File No.1-8489).	X
10.26*	Form of 2021 Goal-Based Stock Award Agreement under the 2021 Long-Term Incentive Program approved January 21, 2021 (Exhibit 10.27, Form 10-K for the fiscal year ended December 31, 2020 filed February 25, 2021, File No.1-8489).	X
10.27*	Form of Restricted Stock Agreement under the 2021 Long-Term Incentive Program approved January 21, 2021 (Exhibit 10.28, Form 10-K for the fiscal year ended December 31, 2020 filed February 25, 2021, File No.1-8489).	X
10.28*	2022 Performance Grant Plan under the 2022 Long-Term Incentive Program approved January 27, 2022 (filed herewith).	X

218

Exhibit Number	Description	Dominion Energy	Virginia Power
10.29*	Form of 2022 Goal-Based Stock Award Agreement under the 2022 Long-Term Incentive Program approved January 27, 2022 (filed herewith).	X
10.30*	Form of Restricted Stock Agreement under the 2022 Long-Term Incentive Program approved January 27, 2022 (filed herewith).	X
21	Subsidiaries of Dominion Energy, Inc. (filed herewith).	X
23	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
101	The following financial statements from Dominion Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2021, filed on February 24, 2022, 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, 2021, filed on February 24, 2022, 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
104	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.

219

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 24, 2022

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 24th day of February, 2022.

Signature		Title
/s/ Robert M. Blue Robert M. Blue	Chair of the Board of Directors, President and Chief Executive Officer
/s/ James A. Bennett James A. Bennett	Director
/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

220

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 24, 2022

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 24th day of February, 2022.

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

221