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
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For the fiscal year ended December 31, 20202022
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☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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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) | |
(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 |
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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 No ☒ Virginia Electric and Power Company Yes ☐ ☐No 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 ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
Dominion Energy, Inc. ☐ Virginia Electric and Power Company ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).
Dominion Energy, Inc. ☐ Virginia Electric and Power Company ☐
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 $68.0$66.3 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 12, 2021,15, 2023, Dominion Energy had 805,648,140835,193,617 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 20212023 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.
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Dominion Energy, Inc. and Virginia Electric and Power Company
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1B. |
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7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
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9B. |
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9C. | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections |
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10. |
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12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
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13. | Certain Relationships and Related Transactions, and Director Independence |
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Glossary of Terms
The following abbreviations or acronyms used in this Form 10-K are defined below:
Abbreviation or Acronym | Definition | |
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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 | |
| Dominion | |
2021 BLS Industry Average OSHA Recordable Rate | An average of the OSHA Recordable Rate for 2021 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 | |
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| 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 | |
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| Billion cubic feet equivalent | |
Bear Garden | A | |
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 | |
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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 | |
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| Customer credit reinvestment offset | |
CEA | Commodity Exchange Act | |
CEO | Chief Executive Officer | |
CEP | Capital Expenditure Program, | |
CERCLA | Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund |
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Abbreviation or Acronym | Definition | |
CFO | Chief Financial Officer | |
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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 | |
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| 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.) | |
| The legal entity DECP Holdings, Inc., which holds Dominion Energy’s noncontrolling interest in Cove Point | |
DEQPS | MountainWest Pipeline Services, Inc. (formerly known as 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 | |
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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 |
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Abbreviation or Acronym | Definition | |
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Dominion Energy Questar Pipeline | The legal entity, MountainWest Pipeline, LLC (formerly known as Dominion Energy Questar Pipeline, | |
Dominion Energy South Carolina | Dominion Energy South Carolina operating segment |
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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 | |
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| Rate adjustment clauses, designated Riders C1A, C2A, C3A and C4A, associated with the recovery of costs related to certain Virginia DSM programs in approved 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 | |
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| 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, 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 | |
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| Financial Accounting Standards Board | |
FERC | Federal Energy Regulatory Commission | |
FILOT | Fee in lieu of taxes | |
Fitch | Fitch Ratings Ltd. | |
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| Four Brothers Solar, LLC, a limited liability company owned by Dominion Energy (through December 2021) and Four Brothers Holdings, LLC, a subsidiary of | |
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 | |
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| Gas Distribution operating segment | |
GENCO | South Carolina Generating Company, Inc. | |
GHG | Greenhouse gas | |
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| Granite Mountain Holdings, LLC, a limited liability company owned by Dominion Energy (through December 2021) and Granite Mountain Renewables, LLC, a subsidiary of | |
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| Green Mountain Power Corporation | |
Greensville County | A | |
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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 through August 2022 | |
Hopewell | Polyester biomass power station |
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Idaho Commission | Idaho Public Utilities Commission | |
| An Act to Provide for Reconciliation Pursuant to Title II of Senate Concurrent Resolution 14 of the 117th Congress (also known as the Inflation Reduction Act of 2022) enacted on August 16, 2022 | |
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 | |
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 | |
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| 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 | |
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| Massachusetts Municipal Wholesale Electric Company | |
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| Thousand cubic feet equivalent | |
MD&A | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
MGD | Million gallons | |
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 | |
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| North Anna nuclear power station |
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Abbreviation or Acronym | Definition | |
North Carolina Commission | North Carolina Utilities Commission | |
NOX | Nitrogen oxide | |
NRC | U.S. Nuclear Regulatory Commission | |
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| A nationwide permit from the U.S. 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. |
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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 | ||
| The period May 1st through October 31st for waters off the coast of the Mid-Atlantic and Northeast | ||
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 | ||
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PHMSA | Pipeline and Hazardous Materials Safety Administration | ||
| Percentage of Income Payment Plan deployed by East Ohio | ||
PIR | Pipeline Infrastructure Replacement program deployed by East Ohio | ||
PJM | PJM Interconnection, | ||
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| Prevention of significant deterioration | ||
PSNC | Public Service Company of North Carolina, Incorporated, doing business as Dominion Energy North Carolina | ||
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Q-Pipe Transaction |
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Questar Gas | Questar Gas Company, doing business as Dominion Energy Utah, Dominion Energy Wyoming and Dominion Energy Idaho | ||
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| 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 | 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, energy storage and related transmission facilities in Virginia as well as certain small-scale distributed generation projects and related transmission facilities | ||
Rider | A rate mechanism which allows PSNC to recover from customers all prudently incurred gas costs and the related portion of 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 | 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 |
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Abbreviation or Acronym | Definition | ||
Rider GV | A rate adjustment clause associated with the recovery of costs related to Greensville County | ||
Rider | A rate adjustment clause associated with costs incurred to construct, own and operate the CVOW Commercial Project | ||
Rider PPA | A rate adjustment clause associated with the recovery of costs associated with power purchase agreements for the energy, capacity, ancillary services and renewable energy credits owned by third parties | ||
Rider R | A rate adjustment clause associated with the recovery of costs related to Bear Garden | ||
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 | 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 |
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Rider W | A rate adjustment clause associated with the recovery of costs related to Warren County | ||
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| Return on invested capital | ||
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| Regional transmission expansion plan | ||
RTO | Regional transmission organization | ||
Sadler Solar |
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| 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 | ||
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| South Carolina Department of Revenue | ||
| 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 | ||
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| Southeast Electric Reliability Council | ||
Series A Preferred Stock | Dominion Energy’s | ||
Series B Preferred Stock | Dominion Energy’s 4.65% Series B Fixed-Rate |
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Abbreviation or Acronym | Definition | ||
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| Sulfur | ||
SO2 | Sulfur dioxide | ||
SOFR | Secured Overnight Financing Rate | ||
South Carolina Commission | Public Service Commission of South Carolina | ||
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 | ||
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 | ||
Surry | Surry nuclear power station | ||
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Terra Nova Renewable Partners |
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Three Cedars | Granite Mountain and Iron Springs, collectively | ||
TSR | Total shareholder return | ||
| 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 | ||
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| Voluntary Employees’ Beneficiary Association |
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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 | 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 | ||
WECTEC | WECTEC Global Project Services, Inc. | ||
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 | ||
| Collectively, the Wexpro Agreement, Wexpro II Agreement and two stipulation agreements approved by the Utah Commission allowing for the inclusion of certain property at Canyon Creek and the Trail Unit under the Wexpro II Agreement | ||
Whitehouse Solar | A 20 MW utility-scale solar power station in Louisa County, Virginia | ||
White River Hub | MountainWest White River Hub, LLC (formerly known as White River Hub, LLC) |
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Abbreviation or Acronym | Definition | ||
Wisconsin Commission | Public Service Commission of Wisconsin | ||
Woodland Solar | A 19 MW utility-scale solar power station in Isle of Wight County, Virginia | ||
| 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 (through March 2022) 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, 2020,2022, Dominion Energy’s portfolio of assets includes approximately 30.231.0 GW of electric generating capacity, 10,50010,600 miles of electric transmission lines, 85,60078,500 miles of electric distribution lines and 94,20093,500 miles of gas distribution mains and related service facilities, which are supported by 6,2004,000 miles of gas transmission, gathering and storage pipeline. In addition, Dominion Energy owns approximately 2,400 miles of gas transmission, gathering and storage pipeline through entities under agreement to be sold to BHE. As of December 31, 2020,2022, Dominion Energy operates in 1615 states and serves more thanapproximately 7 million customers.
Dominion Energy has commenced a comprehensive business review as discussed in Future Issues and Other Matters in Item 7. MD&A. Pending the results of the business review, Dominion Energy continues to focus on expanding and improving its regulated and long-term contracted electric and natural gas utility businesses while transitioning to a cleaner energy future. Its previously announced growth capital expenditure plan for 20212022 through 20252026 includes a focus on upgrading the electric system in Virginia through investments in additional renewable generation facilities, strategic undergrounding and energy conservation programs. Renewable generation facilities are expected to include significant investments in utility-scale solar and offshore wind projects. In addition, Dominion Energy is currently seekinghas 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 planspipeline and continued upgrades to continue upgrading its gas and electric transmission and distribution networks while also meeting environmental requirements and standards set by various regulatory bodies.
Dominion Energy has continued its transition to a more state-regulated earnings mix as evidenced by its capital investments in regulated infrastructure, the SCANA and Dominion Energy Questar Combinations, the partially completed sale of substantially all of its gas transmission and storage operations to BHE and the divestiture of interests in certain nonregulated generating facilities and natural gas gathering and processing investments. Dominion Energycurrently expects approximately 90% of earnings from its primary operating segments to come from state-regulated electric and natural gas utility businesses. Dominion Energy’s nonregulated operations consist primarily of primarily long-term contracted electric generation operations and its investment in Cove Point. Dominion Energy’s operations are conducted through various subsidiaries, including DESC and Virginia Power.
In January 2019, Dominion Energy completed the SCANA Combination in a stock-for-stock merger valued at $13.4 billion. SCANA, which operates as a wholly-owned subsidiary of Dominion Energy, DESC is primarily engaged in the generation, transmission and distribution of electricity in the central, southern and southwestern portions of South Carolina and in the distribution of natural gas in North Carolina and South Carolina. DESC, a wholly-owned subsidiary of SCANA, is consolidated by Dominion Energy and remains an SEC registrant. However,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 October 2020,December 2021, Dominion Energy entered into an agreement forcompleted the sale of the Q-Pipe Transaction with BHEGroup to Southwest Gas for $1.3approximately $1.5 billion in cash considerationproceeds and the assumption by BHESouthwest Gas of approximately $430 million of related long-term debt. This transaction is expected to close in early 2021, contingent on clearance or approval under the Hart-Scott-Rodino Act and other customary closing and regulatory conditions.
See Note 3 to the Consolidated Financial Statements for additional information.
Acquisition of Interest in Atlantic Coast Pipeline and Pivotal LNG, Inc.
In March 2020, Dominion Energy completed the acquisition from Southern to acquireof 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 UnitsHope
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 PointIn December 2019,August 2022, Dominion Energy completed the sale of a 25% noncontrolling interest100% of the equity interests in Cove PointHope to BrookfieldUllico for $690 million in exchange for cash consideration, of $2.1 billion, subject to working capitalcustomary closing adjustments. See Note 3 to the Consolidated Financial Statements for additional information.
In addition, a 25% controlling interest in Cove Point was included within the GT&S Transaction and sold to BHE in November 2020.
SCANA
In January 2019, Dominion Energy and SCANA completed a stock-for-stock merger valued at $13.4 billion, inclusive of SCANA’s outstanding debt, which totaled $6.9 billion at closing. SCANA operates as a wholly-owned subsidiary of Dominion Energy. See Note 3 to the Consolidated Financial Statements for additional information.
Electric Generation Facilities
Acquisition of Virginia Power Solar Projects
In 2020 through 2022, Virginia Power entered into and completed the acquisitions of several primarily early-stage solar development projects in Virginia, including both non-jurisdictional facilities and those expected to be recovered under Rider CE.
In 2022, Virginia Power entered into and completed the acquisitions of various solar development projects in Virginia. These projects are expected to cost a total of approximately $1.1 billion once constructed, including initial acquisition costs, and generate approximately 537 MW combined.
In 2021, Virginia Power entered into and completed the acquisitions of various solar development projects in Virginia. These projects are expected to cost a total of approximately $1.4 billion once constructed, including initial acquisition costs, and generate approximately 697 MW combined.
In 2020, Virginia Power entered into and completed the acquisition of various solar development projects in Virginia. These projects are expected to cost a total of approximately $580$595 million once constructed, including initial acquisition costs, and generate approximately 282 MW.
In 2019, Virginia Power entered into agreements to acquire various solar development projects in Virginia, with the acquisitions completed in 2019 and 2020. These projects are expected to cost a total of approximately $765 million once constructed, including initial acquisition costs, and generate approximately 448 MW combined.
In 2018, Virginia Power entered into agreements to acquire various solar development projects in North Carolina and Virginia. These projects closed in 2019 with a total cost of $297 million, including initial acquisition costs, and generate 175 MW combined.
See Notes 10 and 13 to the Consolidated Financial Statements for additional information.
Acquisition of Nonregulated Solar Projects
In 2022, Dominion Energy entered into an agreement and completed the acquisition of a nonregulated solar project in Ohio. The project is expected to cost a total of $390 million once constructed, including the initial acquisition cost, and generate approximately 200 MW.
In 2020, Dominion Energy entered into agreements and completed the acquisition of various nonregulated solar projects in Ohio, South Carolina and Virginia with one project expected to close in 2022.Virginia. These projects are expected to cost a total of approximately $730$470 million once constructed, including the initial acquisition cost,costs, and generate approximately 398248 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.
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Sale of CertainNon-Wholly-Owned Nonregulated GenerationSolar Facilities
In December 2018,2021, Dominion Energy completed the sale of FairlessSBL 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 Manchesterthe 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 total considerationcash proceeds of $1.2 billion, subject to customary closing adjustments. $331 million.
See Note 10 to the Consolidated Financial Statements for additional information.
Equity Method Investments
AcquisitionContributions to and Disposition of Interest in Wrangler
In DecemberAfter an initial contribution to Wrangler in 2019, Dominion Energy acquiredcompleted a 20% noncontrolling interestsecond contribution 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 a final contribution in December 2021 of its remaining nonregulated natural gas retail energy marketing operations receiving $127 million in cash, while maintaining its 20% noncontrolling interest in Wrangler. Subsequently in December 2021 and March 2022, Dominion Energy sold 5% and the remaining 15% of its noncontrolling ownership interest in Wrangler to Interstate Gas Supply, Inc. for cash consideration of $33 million and $85 million, respectively.
See Note 9 to the Consolidated Financial Statements for additional information.
SaleAcquisition of Interest in Blue RacerDominion Privatization
In December 2018,February 2022, Dominion Energy completedentered into an agreement to form Dominion Privatization, a joint venture with Patriot. Under the sale ofagreement, during 2022 Dominion Energy contributed its 50% limited partner interestexisting privatization operations in Blue Racer forVirginia, Texas, Pennsylvania and South Carolina, excluding contracts held by DESC, and Patriot contributed cash. Dominion Energy received total consideration of $1.2 billion. In addition, the purchaser agreed to pay additional consideration contingent upon the achievement$335 million, comprised of certain financial performance milestones$168 million in cash proceeds and a 50% noncontrolling ownership interest in Dominion Privatization with an initial fair value of Blue Racer from 2019 through 2021. $167 million.
See Note 9 to the Consolidated Financial Statements for additional information.
HUMAN CAPITAL
One of Dominion Energy's greatest strengths is its employees and Dominion Energy is committed to providing them with a safe, diverse and inclusive workplace. The ability to attract, develop and retain a diverse workforce is integral to the long-term success of Dominion Energy. At December 31, 2020,2022, Dominion Energy had approximately 17,30017,200 full-time employees, of which approximately 4,7004,500 are subject to collective bargaining agreements, including approximately 6,0006,100 full-time employees at Virginia Power, of which approximately 2,500 are subject to collective bargaining agreements.
Safety is the highest priority of Dominion Energy’s five core values with the fundamental goal to send every employee home safe and sound every day. In 2020,2022, Dominion Energy experienced an OSHA Recordable Rate of 0.410.52 compared to 0.620.46 in 2019.2021 and 0.41 in 2020. These rates reflect Dominion Energy’s dedication to safety when compared to a 20192021 BLS Industry Average OSHA Recordable Rate of 2.05.1.7 and a 2020 BLS Industry Average OSHA Recordable Rate of 1.5. As evidence of Dominion Energy’s commitment to safety, annual incentive plans for all employees, except as restricted by any collective bargaining agreements, include a safety performance measure. Furthermore, Dominion Energy has been proactive in protecting its workforce during the global COVID-19 pandemic by establishing safety protocols including requirements to wear face coverings and maintain physical distancingadapting its approach as well as new procedures for enhanced cleaning and temperature screening.the pandemic has evolved. Dominion Energy also facilitated telecommuting and hybrid work options for many employees and expanded paid time off and other benefits to help employees cope with disruptions caused by the pandemic.
Dominion Energy works to recruit, retain and develop the careers of talented individuals who reflect the communities it serves. To cultivate this diversified workforce, Dominion Energy focuses on workforce diversity, equity and inclusion while fostering an environment where employees can utilize their unique strengths, skills, personalities and life experiences. In October 2020, Dominion Energy announcedis committed to increasing its commitmentdiverse workforce representation to increase workforce diversity40% by 1% annually until it achieves at least 40% diverse representation.year-end 2026; to be adjusted as necessary based on position and market availability. During 2020,2022, Dominion Energy increased diverse representation within its workforce from 33.2%35.5% to 34.6%37.0%, following an increase during 2021 from 34.7% to 35.5%. For the purposes of measuring diversity, Dominion Energy includes non-minorityemployees who identify their gender as female minority male, minority femaleand/or their race/ethnicity as American Indian or Alaskan Native, Asian, Black or African American, Hispanic or Latino, Native Hawaiian or Other Pacific Islander or Two or More Races. In 2022, 2021 and undeclared female. In 2020, and 2019, the percentage of new hires that are diverse was 50%48.9%, 57.5% and 45%50.7%, respectively. Dominion Energy sponsors eight employee
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resource groups to support and reinforce its culture of inclusiveness by enabling employees with shared interests and backgrounds to work together to create community, provide networking opportunities and encourage professional development. The employee resource groups are aligned to support various forms of diversity, equity and inclusion, including gender, sexual orientation, gender identity and expression, race, veteran status, age, ability and cultural heritage. To further advance these initiatives, annual incentive plans for all employees, except as restricted by any collective bargaining agreements, include a performance measure for participation in diversity, equity and inclusion training.
Dominion Energy attracts and retains its employees by offering competitive compensation and benefits packages, including healthcare, retirement, paid time off, parental leave and other benefits. Dominion Energy also offers a variety of training and development opportunities for all employees with the goal to provide a consistent and progressive approach to training that engages the workforce and fosters a culture of learning. To this end, Dominion Energy offers continuous learning opportunities including tuition assistance programs, professional development resources, access to a career center and a self-guided training program for independent learning as well as leadership development programs. These resources and programs are designed not only to engage and retain talented employees but also to allow Dominion Energy to meet the needs of its customers in an ever-changing industry with a skilled workforce.
CYBERSECURITY
In an effort to reduce the likelihood and severity of cyber intrusions, the Companies have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of data and systems, including oversight by the Board of Directors as well as the finance and risk oversight board committee. The Companies are subject to mandatory cybersecurity regulatory requirements, interface regularly with a wide range of external organizations and participate in classified briefings to maintain an awareness of current cybersecurity threats and vulnerabilities. The Companies’ current security posture and regulatory compliance efforts are intended to address the evolving and changing cyber threats. See Item 1A. Risk Factors for discussion of related risks.
OPERATING SEGMENTS
Beginning in September 2020, Dominion Energy manages its daily operations through four primary operating segments: Dominion Energy Virginia, Gas Distribution, Dominion Energy South Carolina and Contracted Assets. See Note 26 to the Consolidated Financial Statements for a summary description of operations within each of the four primary operating segments. Dominion Energy also reports a Corporate and Other segment, which includes its corporate, service companies and other functions (including unallocated debt) as well as nonregulated retail energy marketing operations, including Dominion Energy’s noncontrolling interest in Wrangler.Dominion Privatization. Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the operating segments’ performance or in allocating resources. In addition, Corporate and Other includes the net impact of discontinued operations consisting primarily of Dominion Energy’s 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
Dominion Energy Virginia’s previously announced growth capital plan includes spending approximately $24$27 billion from 20212022 through 20252026 to upgrade or add new transmission lines, distribution lines, substations, and other facilities, as well as maintain existing and 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.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 Renewalsubsequent license renewal projects as it has received approval for or is seeking 20-year license extensions for the regulated nuclear fleet in Virginia. See Properties and Environmental Strategy for additional information on this and other utility projects. Data centers, which currently represent approximately 20% of Virginia Power’s electricity sales, have been a source of significant increase in demand which is expected to continue over the next decade. The concentration of data centers primarily in Loudon County, Virginia represents a unique challenge and requires significant investments in electric transmission facilities to meet the growing demand. While an updated growth capital plan is dependent upon completion of the comprehensive business review discussed in Future Issues and Other Matters in Item 7. MD&A, it is expected to reflect an acceleration of certain electric transmission projects to serve the rapidly growing data center customer demand.
Virginia Power has also created a ten-year plan through 2028 to transform its electric grid into a smarter, stronger and greener grid. This plan will addressaddresses the structural limitations of Virginia Power’s distribution grid in a systematic manner in order to recognize and accommodate fundamental changes and requirements in the energy industry. The objective is to address both customer and system needs by (i) achieving even higher levels of reliability and resiliency against natural and man-made threats, (ii) leveraging technology to enhance the customer experience and improve the operation of the system and (iii) safely and effectively integrating new utility-scale renewable generation and storage as well as customer–level distributed energy resources such as rooftop solar and battery storage. In 2019 and 2020, theThe Virginia Commission has approved portions of this plan.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%81% of revenue comes from serving Virginia jurisdictional customers. Base rates for the Virginia jurisdiction are set using a modified cost-of-service rate model, and are generally designed to allow an opportunity to recover the cost of providing utility service and earn a reasonable return on investments used to provide that service. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures. Electric operations continue to focus on improving service and experience levels while striving to reduce costs and link investments to operational results. SAIDI performance results, excluding major events, were 146136 minutes for the three-year average ending 2020, up2022, down from the previous three-year average of 138141 minutes. This increasedecrease is primarily due to increaseddecreased 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
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Competition
There is no competition for electric distribution service within Virginia Power’s service territory in Virginia and North Carolina and no such competition is currently permitted. Historically, since its electric transmission facilities are integrated into PJM and electric transmission services are administered by PJM, there was no competition in relation to transmission service provided to customers within the PJM region. However, competition from non-incumbent PJM transmission owners for development, construction and ownership of certain transmission facilities in Virginia Power’s service territory is permitted pursuant to Order 1000, subject to state and local siting and permitting approvals. This could result in additional competition to build and own transmission infrastructure in Virginia Power’s service area in the future and could allow Dominion Energy to seek opportunities to build and own facilities in other service territories. Additionally, there is some competition for Virginia Power’s generation operations for Virginia jurisdictional electric utility customers that meet certain size requirements or that currently are purchasing energy from competitive suppliers deemed to be 100% renewable by the Virginia Commission. See Electric under State Regulations in Regulation for more information. Currently, North Carolina does not offer retail choice to electric customers.
Virginia Power’s non-jurisdictional solar operations are not currently subject to significant competition as the output from these facilities is primarily sold under long-term power purchase agreements with terms generally ranging from 16 to 25 years. However, in the future, such operations may compete with other power generation facilities to serve certain large-scale customers after the power purchase agreements expire.
Regulation
Virginia Power’s electric distribution and generation operations, including the rates it may charge to jurisdictional customers, as well as wholesale electric transmission rates, tariffs and terms of service, are subject to regulation by the Virginia and North Carolina Commissions as well as FERC,FERC, the NRC, the EPA, the DOE and the U.S. Army Corps of Engineers.Engineers. See State Regulations and Federal Regulations in Regulation, Future Issues and Other Matters in Item 7. MD&A and Notes 13 and 23 to the Consolidated Financial Statements for additional information.
Properties
For a description of existing facilities see Item 2. Properties.
CVOW Commercial Project
In September 2019, Virginia Power filed applications with PJM for the CVOW Commercial Project and for certain approvals and rider recovery from the Virginia Commission in November 2021. The total cost of the project is estimated to be approximately $10 billion, excluding financing costs. Virginia Power’s estimate for the 2.6 GW project’s projected levelized cost of energy is approximately $80-90/MWh. Following a competitive procurement process, Virginia Power has entered into fixed price contracts for the major offshore construction and equipment components. The contracts include services denominated in currencies other than the U.S. dollar for approximately €2.6 billion and 5.1 billion kr., which have been included within the cost estimate above. In addition, certain of the fixed price contracts, approximately €0.7 billion, contain commodity indexing provisions linked to steel. As a result, any changes in applicable exchange rates or commodity indices, if not mitigated, could result in a change to the ultimate cost of the project. In May 2022, Virginia Power entered into forward purchase agreements with a notional amount of approximately €3.2 billion to hedge its foreign currency rate risk exposure from certain fixed price contracts for the major offshore construction and equipment components of the CVOW Commercial Project.
In March 2022, the Virginia Commission approved Virginia Power’s application filed in December 2021 for approval of a lease contract with an affiliated entity for the use of a Jones Act compliant offshore wind installation vessel currently under development. In April 2022, Virginia Power filed an application with the North Carolina Commission for approval of the same lease contract and received approval in January 2023. In January 2023, Virginia Power entered into the lease contract with commencement of the 20-month lease term in August 2025 at a total cost of approximately $240 million plus ancillary services.
Virginia Power has completed the conceptual design phase for the project’s onshore electric transmission facilities and selected a recommended route with consideration given for resiliency and minimizing environmental impacts. Any changes to the onshore route necessitated by the receipt of various permitting approvals could result in upward pressure on the estimated cost of the project. In August 2022, the Virginia Commission approved the application for certification of the Virginia Facilities component of the CVOW Commercial Project, the revenue requirement for the initial rate year of Rider OSW and noted that no further action was required with respect to Virginia Power’s foreign currency risk mitigation plan. The Virginia Commission also included a performance standard for operation of the CVOW Commercial Project, which would require that customers be held harmless for any shortfall in energy production below an annual net capacity factor of 42%, as determined on a three-year rolling average, with details on the implementation of such standard to be determined in a future proceeding. Also in August 2022, Virginia Power filed a petition for
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limited reconsideration relating to the performance standard for operation of the CVOW Commercial Project included in the Virginia Commission’s August order. The Virginia Commission granted reconsideration and suspended in part the August order pending its reconsideration with Rider OSW approved on an interim basis. In October 2022, Virginia Power, Office of the Attorney General of Virginia and other parties filed a settlement agreement with the Virginia Commission for approval. The settlement agreement provides for a voluntary cost sharing mechanism resulting from unforeseen construction cost increases; specifically, that Virginia Power will be eligible to recover 50% of such incremental costs which fall between $10.3 billion and $11.3 billion with no recovery of such incremental costs which fall between $11.3 billion and $13.7 billion. There is no voluntary cost sharing mechanism for any total construction costs in excess of $13.7 billion, the recovery of which would be determined in a future Virginia Commission preceding. The settlement agreement also provides for customers to receive the maximum benefits available under the IRA including that to the extent the IRA reduces the total construction costs, such reductions will also be applied to the cost sharing bands discussed above. In addition, the settlement agreement includes enhanced performance reporting provisions, in lieu of a performance guarantee, for the operation of the CVOW Commercial Project. To the extent the annual net capacity factor is below 42%, as determined on a three-year rolling average, Virginia Power is required to provide detailed explanation of the factors contributing to any shortfall to the Virginia Commission which could determine in a future proceeding a remedy for incremental costs incurred associated with any deemed unreasonable or imprudent actions of Virginia Power. In December 2022, the Virginia Commission approved the settlement agreement and reinstated its August 2022 order granting approval of Rider OSW.
Upon receiving remaining approvals from other permitting entities, Virginia Power anticipates commencing major construction activities in 2023 and the project is expected to be placed in service by the end of 2026. Virginia Power expects to incur approximately 80% of the project costs from 2023 through 2025. Through December 31, 2022, Virginia Power had incurred approximately $1.1 billion of costs. Virginia Power anticipates funding the project consistent with its approved debt to equity capitalization structure. The project is vital for Virginia Power to meet the renewable energy portfolio standard established in the VCEA and is consistent with the criteria within the VCEA for the construction of an offshore wind facility deemed to be in the public interest as well as the guidelines facilitating cost recovery. See additional discussion of the VCEA provisions concerning renewable generation projects in Note 13 to the Consolidated Financial Statements.
Electric Generation and Storage Projects
In addition, Virginia Power is developing, financing and constructing new generation capacity as well as seeking license extensions on zero carbon nuclear generation facilities to meet its renewable generation targets and growing electricity demand within its service territory. Significant projects under construction or development as well as significant projects under consideration are set forth below:
• Virginia Power plans to invest approximately $6.8 billion from 2022 to 2026 to acquire or construct several solar facilities totaling approximately 3.4 GW of expected generating capacity when placed in service. Virginia Power has projects under various stages of development which, as of December 31, 2022, represent a potential generating capacity of approximately 6.3 GW. The facilities include both those to serve utility and non-jurisdictional customers. See Notes 10 and 13 to the Consolidated Financial Statements for additional information. • To support its development of solar generation facilities serving utility customers, Virginia Power plans to invest approximately $0.6 billion from 2022 to 2026 to acquire or construct multiple battery storage facilities in Virginia, totaling approximately 309 MW of expected storage capacity when placed in service. Virginia Power has projects under various stages of development which, as of December 31, 2022, represent a potential storage capacity of approximately 1.2 GW. See Note 13 to the Consolidated Financial Statements for additional information. • Virginia Power has received a 20-year extension of the operating licenses for its two units at Surry and has commenced the process to extend the operating licenses for its two units at North Anna. See Nuclear Decommissioning below for additional information on these facilities. • Virginia Power continues to consider the construction of a third nuclear unit at a site located at North Anna. See Future Issues and Other Matters in Item 7. MD&A for more information on this project. • Virginia Power is considering the construction of a hydroelectric pumped storage facility in Southwest Virginia. • Virginia Power is considering the construction of simple cycle combustion turbines in Virginia for reliability purposes. Electric Transmission and Distribution Projects
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Virginia Power continues to invest in transmission projects that are a part of PJM’s RTEP process which focus on reliability improvements and replacement of aging infrastructure. The projects that have been authorized by PJM are expected to result in future capital expenditures of approximately $1.5$3.0 billion from 2021 through 2025.2026.
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Virginia Power is investing in transmission substation physical security and expects to invest an additional $110$100 million to $160$150 million through 20252026 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 2028.2029. The Virginia Commission has approved foursix phases of the program encompassing approximately 1,3501,866 miles of converted lines and $545 million$1.1 billion in capital spending (with $523 million$1.1 billion recoverable through Rider U).
See Note 13 to the Consolidated Financial Statements for moreadditional information.
Sources of Energy Supply
Virginia Power uses a variety of fuels to power its electric generation fleet and purchases power for utility system load requirements and to satisfy physical forward sale requirements. Some of these agreements have fixed commitments and are included as contractual obligationsdetailed further in Future Cash Payments for Contractual ObligationsFuel and Planned Capital Expenditures Other Purchase Commitments in Item 7. MD&A.
Presented below is a summary of Virginia Power’s actual system output by energy source:
Source |
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| 2021 |
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| 2020 |
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Natural gas |
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| 36 |
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| 40 |
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| 48 |
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Nuclear(1) |
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| 28 |
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| 29 |
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| 32 |
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Purchased power, net |
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| 23 |
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| 17 |
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| 7 |
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Coal(2) |
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| 8 |
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| 9 |
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| 9 |
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Renewable and Hydro(3) |
|
| 5 |
|
|
| 5 |
|
|
| 4 |
|
|
Total |
|
| 100 |
| % |
| 100 |
| % |
| 100 |
| % |
Source |
| 2020 |
|
| 2019 |
|
| 2018 |
|
| |||
Natural gas |
|
| 48 |
| % |
| 41 |
| % |
| 33 |
| % |
Nuclear(1) |
|
| 32 |
|
|
| 29 |
|
|
| 29 |
|
|
Purchased power, net |
|
| 7 |
|
|
| 17 |
|
|
| 19 |
|
|
Coal(2) |
|
| 9 |
|
|
| 8 |
|
|
| 13 |
|
|
Renewable and Hydro(3) |
|
| 4 |
|
|
| 5 |
|
|
| 5 |
|
|
Other |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
Total |
|
| 100 |
| % |
| 100 |
| % |
| 100 |
| % |
|
|
|
|
|
|
Nuclear Fuel—Fuel—Virginia Power primarily utilizes long-term contracts to support its nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent on the market environment. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal cost and inventory levels.
Fossil Fuel—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—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
18
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 arehave 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 20322038 to 2078.2112. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. In 2018,2021, Virginia Power applied for renewal of its operating licenses forwas granted an additional 20 years for its operating licenses for the two nuclear units at Surry. Under these renewal applications,license extensions, the two nuclear units will be allowed to generate electricity through 2052 and 2053, if approved.2053. In 2020, Virginia Power also submitted a license renewal application for the two units at North Anna in 2020.Anna. Under thesethis renewal applications,application, the two nuclear units will be allowed to generate electricity through 2058 and 2060, if approved. Between the four units, Virginia Power estimates that it could spend approximately $3 billion to $4 billion over the next several yearsthrough 2035 on capital improvements. The existing regulatory framework in Virginia provides rate recovery mechanisms for such costs.
The estimated decommissioning costs, funds in trust and current license expiration dates for Surry and North Anna are shown in the following table:
|
| NRC license expiration year |
| Most recent cost estimate (2022 dollars)(1) |
|
| Funds in trusts at December 31, 2022(2) |
| ||
(dollars in millions) |
|
|
|
|
|
|
|
| ||
Surry |
|
|
|
|
|
|
|
| ||
Unit 1 |
| 2052 |
| $ | 849 |
|
| $ | 905 |
|
Unit 2 |
| 2053 |
|
| 839 |
|
|
| 892 |
|
North Anna |
|
|
|
|
|
|
|
| ||
Unit 1(3) |
| 2038 |
|
| 760 |
|
|
| 724 |
|
Unit 2(3) |
| 2040 |
|
| 765 |
|
|
| 681 |
|
Total |
|
|
| $ | 3,213 |
|
| $ | 3,202 |
|
|
| NRC license expiration year |
| Most recent cost estimate (2020 dollars)(1) |
|
| Funds in trusts at December 31, 2020(2) |
| ||
(dollars in millions) |
|
|
|
|
|
|
|
|
|
|
Surry |
|
|
|
|
|
|
|
|
|
|
Unit 1 |
| 2032 |
| $ | 818 |
|
| $ | 905 |
|
Unit 2 |
| 2033 |
|
| 809 |
|
|
| 892 |
|
North Anna |
|
|
|
|
|
|
|
|
|
|
Unit 1(3) |
| 2038 |
|
| 733 |
|
|
| 722 |
|
Unit 2(3) |
| 2040 |
|
| 737 |
|
|
| 678 |
|
Total |
|
|
| $ | 3,097 |
|
| $ | 3,197 |
|
(2) Virginia Power did not make any contributions to its nuclear decommissioning trust funds during 2022. (3) North Anna is jointly owned by Virginia Power (88.4%) and ODEC (11.6%). However, Virginia Power is responsible for 89.26% of the decommissioning obligation. Amounts reflect 89.26% of the decommissioning cost for both of North Anna’s units.
|
|
|
|
|
|
Also see Notes 9, 14 and 23 to the Consolidated Financial Statements for furtheradditional information about nuclear decommissioning trust investments, AROs and other aspects of nuclear decommissioning, respectively.
19
GAS DISTRIBUTION
The Gas Distribution Operating Segment of Dominion Energyincludes 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 3.13.0 million residential, commercial and industrial customers. The Gas Distribution Operating Segment also includes nonregulated renewable natural gas facilities in operation and under development, including Dominion Energy’s investment in Align RNG. See Investments below for additional information regarding the Align RNG investment.
Gas Distribution’s previously announced growth capital plan includes spending approximately $5 billion from 20212022 through 2025 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 outside its service territory.projects. Planned capital spending is driven by infrastructure needs from a growing customer base in states with expanding economies, replacing aging assets for reliability, safety and sustainability and meeting demands for natural gas to support the transition from more carbon intensive fuels. An updated growth capital plan is dependent upon completion of the comprehensive business review discussed in Future Issues and Other Matters in Item 7. MD&A.
Earnings for the Gas Distribution Operating Segment of Dominion Energyprimarily 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.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, 2020,2022, approximately 1.1 million of East Ohio’s 1.2 million Ohio customers were participating in the Energy Choice program.
Competition in PSNC’s natural gas distribution operations is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and the ability to retain large commercial and industrial customers.
Questar Gas does not currently face direct competition from other distributors of natural gas for residential and commercial customers in its service territories as state regulations in Utah, Wyoming and Idaho do not allow customers to choose their provider at this time. See State Regulations in Regulation for additional information.
In all of Dominion Energy’s gas service territories, electric utilities offer electricity as a rival energy source and compete for the space heating, water heating and cooking markets. The principal means to compete against alternative fuels is lower prices, and natural gas historically has maintained its price advantage in the residential and commercial markets. Competition for heating as well as general household and small commercial energy needs generally occurs at the initial installation phase when the customer or builder makes the decision as to which types of equipment to install, asinstall. 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, the EPA and the U.S. Department of Transportation. See Federal Regulations and State Regulations in RegulationRegulations, Future Issues and Other Matters in Item 7. MD&A and Notes 13 and 23 to the Consolidated Financial Statements for moreadditional information.
Properties
For a description of existing facilities see Item 2. Properties.
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
20
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 withApril 2022, the Ohio Commission to extend theapproved an extension of East Ohio’s PIR program for an additional five yearscapital investments through 2026 with continuation of 3% increases of annual capital expenditures per year. See Note 13 to the Consolidated Financial Statements for furtheradditional information.
In 2011, East Ohio began CEP which enables East Ohio to defer depreciation expense, property tax expense and carrying costs on capital investments not covered by its PIR program to expand, upgrade or replace its pipeline system and information technology systems as well as investments necessary to comply with the Ohio Commission or other government regulation. In 2022, the Ohio Commission approved recovery of costs incurred in 2019, 2020 and 2021 under an associated rider. See Note 13 to the Consolidated Financial Statements for further information.
Questar Gas— In 2010, Questar Gas began replacing aging high pressure infrastructure under a cost-tracking mechanism that allows it to place into rate base and earn a return on capital expenditures associated with a multi-year natural gas infrastructure-replacement program upon the completion of each project. As part of the 2019 base rate case, the Utah Commission approved an annual spending budget of $72 million for the replacement program, to be adjusted annually for inflation.
In 2018, legislation became effective in Utah which is designed to spur economic growth in rural communities without natural gas service. The legislation allows Questar Gas to spend up to $50 million over three years, and up to $125 million over five years, for
expansion of distribution facilities to bring natural gas to residential and commercial customers in rural parts of Utah, as approved by the Utah Commission. See Note 13 to Consolidated Financial Statements for moreadditional information.
The Utah Commission has provided approval for Questar Gas to construct an LNG storage facility with a liquefaction rate of 8.2 million cubic feet per day. The project is expected to cost approximately $200 million, excluding financing costs, and is anticipated to be placed into service in late 2022.
PSNC—PSNC—The North Carolina Commission has authorized PSNC to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. Projected integrity management plan investment, excluding the costs associated with the 2020 project noted below, for the period 20212023 to 20232025 is expected to be approximately $111$144 million.
During 2019, construction began on 38 miles of transmission pipeline between Franklinton, North Carolina and Clayton, North Carolina, which will provide the capacity necessary to support the growing natural gas demand in PSNC’s service territory. The project is expected to cost approximately $155 million, excluding financing costs, and is anticipated to be placed into service in 2021.
During 2020, construction began on 11 miles of transmission pipeline in Buncombe County, NC. After an analysis was performed under the integrity management program, the new transmission line was deemed necessary to offset the capacity losses on the existing line due to lower pressure being utilized in order to meet federal safety requirements. The project is expected to cost approximately $55$65 million and ishad approximately 10 miles placed into service in December 2021 with the remaining portion anticipated to be placed into service in late 2021.2023.
Questar Gas— In 2010, Questar Gas began replacing aging high pressure infrastructure under a cost-tracking mechanism that allows it to place into rate base and earn a return on capital expenditures associated with a multi-year natural gas infrastructure-replacement program upon the completion of each project. As part of the 2022 Utah base rate case, the Utah Commission approved the continuation of the infrastructure-replacement program with an annual spending budget of approximately $85 million, to be adjusted annually for inflation.
In 2018, legislation became effective in Utah which is designed to spur economic growth in rural communities without natural gas service. Pursuant to its 2022 Utah base rate case, Questar Gas is permitted to spend approximately $85 million over the three years, and approximately $215 million in the aggregate, for expansion of distribution facilities to bring natural gas to residential and commercial customers in rural parts of Utah, as approved by the Utah Commission. Additionally, as part of the 2022 Utah base rate case, the Utah Commission also approved the inclusion of $24 million of rural expansion capital investment in rate base, with costs above this amount to be included for future rural expansion cost consideration.
Non-Utility Renewable Natural Gas—Gas—In December 2019, Dominion Energy announced the formation of a nationwide partnershipstrategic 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 expectsannounced an expansion of the partnership, increasing its commitment up to invest $200 million to develop the related assets. During 2020, construction began$1 billion. As of aDecember 31, 2022, 16 dairy renewable natural gas facilityfacilities were under construction in Greeley, Colorado, Nevada, Idaho, Georgia, Kansas, Texas and New Mexico. These facilities are expected to cost approximately $70 million, excluding financing costs, and to be placed in service in late 2022.2023 through 2025 with an estimated total cost of approximately $1.0 billion, excluding financing costs.
Investments
Align RNG—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 CaliforniaArizona and convert it into pipeline quality natural gas. In July 2020, Align RNG placed its first project, located in Milford, UT, in service and the project has produced 11,200over 160,000 Dths of renewable natural gas throughgas. As of December 31, 2020.2022, Align RNG had four additional projects under construction in North Carolina, Arizona and Virginia with an estimated total cost of approximately $200 million. These facilities are expected to be placed in service in 2023 and 2024.
Sources of Energy Supply
Dominion Energy’s natural gas supply is obtained from various sources including purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, local producers in the Appalachian area, gas marketers and, for Questar Gas specifically, from Wexpro and other producers in the Rocky Mountain region. Wexpro’s gas development and production operations serve over half of Questar Gas’ gas supply requirements in accordance with the Wexpro Agreement and the Wexpro II Agreement,Agreements, comprehensive agreements with the states
21
of Utah and Wyoming. In addition, these agreements provide for potential cost saving sharing incentives to the extent that the cost of gas supplied to Questar Gas is a certain amount lower than third-party rates.
Seasonality
Gas Distribution’s business earnings varycustomer 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. Historically, the majority of these earnings have been generatedAccordingly, 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 have reducedmitigate the earnings impact of weather-related fluctuations.
DOMINION ENERGY SOUTH CAROLINA
The Dominion Energy South Carolina Operating Segment is comprised of DESC’s generation, transmission and distribution of electricity to approximately 758,000782,000 customers in the central, southern and southwestern portions of South Carolina and the distribution of natural gas to approximately 405,000435,000 residential, commercial and industrial customers in South Carolina.
DESC’s
Dominion Energy South Carolina’s previously announced growth capital plan includes spending approximately $2 billion from 20212022 through 2025 2026 to upgrade existing or add new infrastructure to meet growing energy needs within its service territory and maintain reliability. An updated growth capital plan is dependent upon completion of the comprehensive business review discussed in Future Issues and Other Matters in Item 7. MD&A.
Revenue provided by DESC’s electric distribution operations is based primarily on rates established by the South Carolina Commission. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures.
DESC’s electric transmission operations serve its electric distribution operations as well as certain wholesale customers. Revenue provided by such electric transmission operations is based on a FERC-approved formula rate mechanism under DESC’s open access transmission tariff or based on retail rates established by the South Carolina Commission.
Revenue provided by DESC’s electric generation operations is primarily derived from the sale of electricity generated by its utility generation assets and is based on rates established by the South Carolina Commission. Variability in earnings may arise when revenues are impacted by factors not reflected in current rates, such as the impact of weather, customer demand or the timing and nature of expenses or outages.
Electric operations continue to focus on improving service and experience levels while striving to reduce costs and link investments to operational results. SAIDI performance results, excluding major events, were 8782 minutes for the three-year average ending 2020, compared to2022, consistent with the previous three-year average of 8582 minutes.
Revenue provided by DESC’s natural gas distribution operations primarily results from rates established by the South Carolina Commission. Variability in earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, the availability and prices of alternative fuels and the economy.
DESC is a member of the Virginia-Carolinas ReliabilityCarolinas Reserve Sharing Group, one of several geographic divisions within the SERC. The SERC is one of seven regional entities with delegated authority from NERC for the purpose of proposing and enforcing reliability standards approved by NERC. In addition, DESC also participates in the SEEM platform, which became operational in November 2022.
Competition
There is no competition for electric distribution or generation service within DESC’s retail electric service territory in South Carolina and no such competition is currently permitted. However, competition from third-party owners for development, construction and ownership of certain transmission facilities in DESC’s service territory is permitted pursuant to Order 1000, subject to state and local siting and permitting approvals. This could result in additional competition to build and own transmission infrastructure in DESC’s service area in the future.
Competition in DESC’s natural gas distribution operations is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and the ability to retain large commercial and industrial customers.
Regulation
22
Regulation
DESC’s electric distribution service, including the rates it may charge to jurisdictional customers, is subject to regulation by the South Carolina Commission. DESC’s electric generation operations are subject to regulation by the South Carolina Commission, FERC, the NRC, the EPA, the DOE, the U.S. Army Corps of Engineers and various other federal, state and local authorities. DESC’s electric transmission service is primarily regulated by FERC and the DOE. DESC’s gas distribution operations are subject to regulation by the South Carolina Commission, as well as PHMSA, the U.S. Department of Transportation and the South Carolina Office of Regulatory Staff for enforcement of federal and state pipeline safety requirements. See State Regulations and Federal Regulations in Regulation, Future Issues and Other Matters in Item 7. MD&A and Notes 13 and 23 to the Consolidated Financial Statements for moreadditional information.
Properties
For a description of existing facilities see Item 2. Properties.
DESC has the following significant projects under construction or development to better serve customers or expand its service offerings within its service territory:
In 2020, DESC began the upgrade of its electric and gas systems to an AMI whereby smart meters will be installed throughout its service area. As of December 31, 2022, DESC has completed the installation of over 132,000approximately 765,000 of the planned 1.1 million smart meters. This project is estimated to cost approximately $140 million and will be completed in March 2023.mid-2024.
In 2020,January 2022, DESC continued several electric transmission projects in connectioncommitted 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 two new nuclear plants under development by Southern. These transmission projectsgas combustion turbine units at the Williams and Parr facilities to increase reliability and reduce emissions. The replacement facilities are requiredexpected to be placed in place prior to these plants beginning operations to maintain reliability.
These projects, costing approximately $75 million in aggregate, will go into service in phases through 2022. The first phaseby the end of 2025 at an estimated cost of approximately six miles was completed in November 2020 with another phase$310 million, excluding financing costs, and have a total winter generating capacity of approximately 13 miles scheduled171 MW.
To maintain reliability, DESC expects to commence development in 2023 of a wastewater treatment facility at its Williams facility. The project will allow DESC to comply with the effluent limitation guidelines and is expected to be completedplaced in early 2021.service by the end of 2025 at an estimated cost of approximately $165 million, excluding financing costs.
Sources of Energy Supply
DESC uses a variety of fuels to power its electric generation fleet and purchases power for utility system load requirements.
Presented below is a summary of DESC’s actual system output by energy source:
Source |
| 2022 |
|
| 2021 |
|
| 2020 |
|
| |||
Natural gas |
|
| 48 |
| % |
| 49 |
| % |
| 47 |
| % |
Nuclear(1) |
|
| 23 |
|
|
| 20 |
|
|
| 20 |
|
|
Coal |
|
| 18 |
|
|
| 20 |
|
|
| 22 |
|
|
Renewable and Hydro(2) |
|
| 11 |
|
|
| 11 |
|
|
| 11 |
|
|
Total |
|
| 100 |
| % |
| 100 |
| % |
| 100 |
| % |
Source |
| 2020 |
|
| 2019 |
|
| 2018(1) |
|
| |||
Natural gas |
|
| 47 |
| % |
| 46 |
| % |
| 37 |
| % |
Coal |
|
| 22 |
|
|
| 27 |
|
|
| 35 |
|
|
Nuclear(2) |
|
| 20 |
|
|
| 23 |
|
|
| 20 |
|
|
Renewable and Hydro(3) |
|
| 11 |
|
|
| 4 |
|
|
| 8 |
|
|
Total |
|
| 100 |
| % |
| 100 |
| % |
| 100 |
| % |
|
|
|
|
|
|
Natural gas—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 CarolinaDESC through firm transportation agreements with various counterparties, which expire between 20212023 and 2084.
Coal—
Coal— DESC primarily obtains coal through short-term and long-term contracts with suppliers located in eastern Kentucky, Tennessee, Virginia and West Virginia. These contracts provide for approximately 2.1 million tons annually. These contractsVirginia that will expire at various times throughout 20212023 and 2022.2024. Spot market purchases may occur when needed or when prices are believed to be favorable.
Nuclear—
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.
23
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
Seasonality
DESC’s electric distribution and transmission business earnings vary seasonally as a result of the impact of changes in temperature, the impact of storms and other catastrophic weather events and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs, respectively. An increase in heating degree days does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials and because alternative heating sources are more readily available.
DESC’s gas distribution and storage business earnings vary seasonally as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. The majority of these earnings are generated during the heating season, which is generally from November to March; however, South Carolina has certain rate mechanisms designed to reduce the impact of weather-related fluctuations.
Nuclear Decommissioning
DESC has a two-thirds interest in one licensed, operating nuclear reactor at Summer in South Carolina.
Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. Amounts collected from ratepayers are placed into trusts and are invested to fund the expected future costs of decommissioning Summer.
DESC believes that the decommissioning funds and their expected earnings will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to this trust. DESC will continue to monitor this trust to ensure that it meets the NRC minimum financial assurance requirements, which may include, if needed, the use of Dominion Energy guarantees, surety bonding or other financial instruments recognized by the NRC.
The estimated cost to DESC to decommission its 66.7% ownership in Summer is reflected in the table below and is primarily based upon site-specific studies completed in 2020. These cost studies are generally completed every four to five years. Santee Cooper is responsible for the remaining decommissioning costs, proportionate with its 33.3% ownership in Summer. The cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating license expires. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. DESC is consideringexpects 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 (2022 dollars)(1) |
|
| Funds in trusts at December 31, 2022(2) |
| ||
(dollars in millions) |
|
|
|
|
|
|
|
| ||
Summer – Unit 1 |
| 2042 |
| $ | 788 |
|
| $ | 221 |
|
|
| NRC license expiration year |
| Most recent cost estimate (2020 dollars)(1) |
|
| Funds in trusts at December 31, 2020(2) |
| ||
(dollars in millions) |
|
|
|
|
|
|
|
|
|
|
Summer – Unit 1 |
| 2042 |
| $ | 744 |
|
| $ | 238 |
|
Also see Notes 9, 14 and 23 to the Consolidated Financial Statements for additional information about nuclear decommissioning trust investments, AROs and other aspects of nuclear decommissioning, respectively. 24
|
|
|
|
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 Asset’sAssets’ previously announced growth capital plan includes spending $2approximately $3 billion from 20212022 through 20252026 to expand its renewable generation fleet. While an updated growth capital plan is dependent upon completion of the comprehensive business review discussed in Future Issues and Other Matters in Item 7. MD&A, it is expected to reflect a decreased investment in new nonregulated solar generation facilities.
The Contracted
Contracted Assets Operating Segment derives its earnings primarily from Dominion Energy’s nonregulated generation assets, including associated capacity and ancillary services, and from its noncontrolling interest in Cove Point. Variability in earnings provided by Millstone relates to changes in market-based prices received for electricity and capacity as well as the timing, duration and costs of scheduled and unscheduled outages. Approximately half of Millstone’s output is sold under the Millstone 2019 power purchase agreements, which commenced in October 2019. Market-based prices for electricity are largely dependent on commodity prices and the demand for electricity. Capacity prices are dependent upon resource requirements in relation to the supply available (both existing and new) in the forward capacity auctions, which are held approximately three years in advance of the associated delivery year. Dominion Energy manages the electric price volatility of Millstone by hedging a substantial portion of its expected near-term energy sales not subject to the Millstone 2019 power purchase agreements with derivative instruments.
Dominion Energy’s nonregulated generation fleet includes numerous renewablesolar generation facilities including solar generation in operation or development in tennine states, including Virginia. The output of these facilities is sold under long-term power purchase agreements with terms generally ranging from 15 to 25 years. Variability in earnings provided by these assets relates to changes in
irradiance levels due to changes in weather. See Notes 3 and 10 to the Consolidated Financial Statements for additional information regarding certain solar projects.
Competition
Contracted Asset’s renewable generation projects are not currently subject to significant competition as the output from these facilities is primarily sold under long-term power purchase agreements with terms generally ranging from 15 to 25 years. However, in the future, such operations may compete with other power generation facilities to serve certain large-scale customers after the power purchase agreements expire. Competition for the nonregulated fleet is impacted by electricity and fuel prices, new market entrants, construction by others of generating assets and transmission capacity, technological advances in power generation, the actions of environmental and other regulatory authorities and other factors. These competitive factors may negatively impact the nonregulated fleet’s ability to profit from the sale of electricity and related products and services.
Millstone is dependent on its ability to operate in a competitive environment and does not have a predetermined rate structure that provides for an ROIC. Millstone operates within a functioning RTO and primarily competecompetes on the basis of price. Competitors include other generating assets bidding to operate within the RTO. Millstone competes in the wholesale market with other generators to sell a variety of products including energy, capacity and ancillary services. It is difficult to compare various types of generation given the wide range of fuels used by generation facilities, fuel procurement strategies, efficiencies and operating characteristics of the fleet within any given RTO. However, Dominion Energy applies its expertise in operations, dispatch and risk management to maximize the degree to which Millstone is competitive compared to similar assets within the region.
Regulation
Contracted Assets’ generation fleet is subject to regulation by the NRC, the EPA, the DOE, the U.S. Army Corps of Engineers and other federal, state and local authorities. See Federal Regulations in Regulation, Future Issues and Other Matters in Item 7,7. MD&A and Notes 13 andNote 23 to the Consolidated Financial Statements for moreadditional information.
Properties
For a listing of facilities, see Item 2. Properties.
Dominion Energy currently plans to invest approximately $0.5 billion through 2024 to acquire or construct certainthree solar facilities currently under development in the Mid-AtlanticVirginia and Midwest.Ohio totaling approximately 345 MW of expected generating capacity when placed in service. See Note 10 to the Consolidated Financial Statements for moreadditional information.
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Investments
Contracted Assets includes Dominion Energy’s 50% noncontrolling interest in Cove Point. Cove Point’s gas transportation, LNG import and storage operations, as well as the Liquefaction Facility’s capacity, are contracted primarily under long-term fixed reservation fee agreements. The Liquefaction Facility has a firm contracted capacity for LNG loading onto ships of approximately 4.6 Mtpa (0.66 bcfe/day) under normal operating conditions and after accounting for maintenance downtime. In addition to the operations of the Liquefaction Facility, Cove Point receives revenue from firm fee-based contractual arrangements, including negotiated rates, for its pipeline operations and certain LNG storage and terminalling services as provided for in FERC-approved tariffs. Variability in earnings results from changes in operating and maintenance expenditures as well asand, for its FERC-regulated operations, any changes in rates and the demand for services.
See Item 2. Properties for a description of Cove Point’s physical assets.
See Note 9 to the Consolidated Financial Statements for further information about Dominion Energy’s equity method investment in Cove Point.
Leasing Arrangement
In December 2020, Dominion Energy signed an agreement (subsequently amended in December 2022) with a lessor to complete construction of and lease a Jones Act compliant offshore wind installation vessel. This vessel is designed to handle current turbine technologies as well as next generation turbines. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $550 million, to fund the estimated project costs. The project is expected to be ready for the 2024 offshore wind turbine installation season. The initial lease term will commence once construction is substantially complete and the vessel is delivered and will mature in November 2027. See Note 15 to the Consolidated Financial Statements for additional information.
Sources of Energy Supply
Contracted Asset’s renewable fleet utilizes solar energy to power its electric generation while Millstone utilizes nuclear fuel, which is acquired primarily through a series of 5-year contracts, to power its electric generation. In addition, Dominion Energy occasionally purchases electricity from the ISO-NE spot market to satisfy physical forward sale requirements, as described below. Some of these agreements have fixed commitments and are included as contractual obligationsdetailed further in Future Cash Payments for Contractual ObligationsFuel and Planned Capital Expenditures 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 amounts currently available in the decommissioning trustsfunds 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 studiesstudy completed for Millstone and for Kewaunee werewas performed in 2019 and 2018, respectively.2019.
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 (2022 dollars)(1) |
|
| Funds in trusts at December 31, 2022(2) |
| ||
(dollars in millions) |
|
|
|
|
|
|
|
| ||
Millstone |
|
|
|
|
|
|
|
| ||
Unit 1(3) |
| N/A |
| $ | 464 |
|
| $ | 685 |
|
Unit 2 |
| 2035 |
|
| 694 |
|
|
| 929 |
|
Unit 3(4) |
| 2045 |
|
| 787 |
|
|
| 920 |
|
Total |
|
|
| $ | 1,945 |
|
| $ | 2,534 |
|
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|
| NRC license expiration year |
| Most recent cost estimate (2020 dollars)(1) |
|
| Funds in trusts at December 31, 2020(2) |
| ||
(dollars in millions) |
|
|
|
|
|
|
|
|
|
|
Millstone |
|
|
|
|
|
|
|
|
|
|
Unit 1(3) |
| N/A |
| $ | 459 |
|
| $ | 698 |
|
Unit 2 |
| 2035 |
|
| 666 |
|
|
| 940 |
|
Unit 3(4) |
| 2045 |
|
| 756 |
|
|
| 917 |
|
Kewaunee |
|
|
|
|
|
|
|
|
|
|
Unit 1(5) |
| N/A |
|
| 584 |
|
|
| 910 |
|
Total |
|
|
| $ | 2,465 |
|
| $ | 3,465 |
|
(2) Dominion Energy did not make any contributions to its nuclear decommissioning trust funds related to Millstone during 2022. (3) Unit 1 permanently ceased operations in 1998, before Dominion Energy’s acquisition of Millstone. (4) Millstone Unit 3 is jointly owned by Dominion Energy Nuclear Connecticut, Inc., with a 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain. Decommissioning cost is shown at Dominion Energy’s ownership percentage. At December 31, 2022, the minority owners held $53 million of trust funds related to Millstone Unit 3 that are not reflected in the table above. |
|
|
|
|
|
|
|
|
|
|
Also see Notes 9, 14 and 23 to the Consolidated Financial Statements for further information about AROs and nuclear decommissioning, respectively, and Note 9 to the Consolidated Financial Statements foradditional information about nuclear decommissioning trust investments.investments, AROs and other aspects of nuclear decommissioning, respectively.
CORPORATE AND OTHER
Corporate and Other Segment-Virginia Power
Virginia Power’s Corporate and Other segment primarily includes certain specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources.
Corporate and Other Segment-Dominion Energy
Dominion Energy’s Corporate and Other segment includes its corporate, service company and other functions (including unallocated debt) as well as nonregulated retail energy marketing operations, including Dominion Energy’sits noncontrolling interest in Wrangler.Dominion Privatization. Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. In addition, Corporate and Other includes the net impact of discontinued operations consisting primarily of Dominion Energy’s gas transmission and storage operations as discussed in Note 3 to the Consolidated Financial Statements and its equity investment in Atlantic Coast Pipeline as discussed in Note 9 to the Consolidated Financial Statements.
Dominion Energy owns a 20%50% noncontrolling interest in Wrangler,Dominion Privatization, a partnership with Patriot, which was formed in September 2019. Wrangler’s operations, contributed by Dominion Energy in 2020will maintain and 2019, consist of nonregulated naturaloperate electric and gas retail energy marketing business serving customers in Ohio and Georgia as well as other southeastern states in thedistribution infrastructure under service concession arrangements with certain U.S. Dominion Energy expects to contribute its remaining retail energy marketing operations, primarily serving customersmilitary installations in Pennsylvania, to Wrangler by the end of 2021.South Carolina, Texas and Virginia.
Dominion Energy owns a 53% noncontrolling interest in Atlantic Coast Pipeline. In July 2020, as a result of the continued permitting delays, growing legal uncertainties and the need to incur significant capital expenditures to maintain project timing before such uncertainties could be resolved, Dominion Energy and Duke Energy announced the cancellation of the Atlantic Coast Pipeline Project.
Dominion Energy Questar Pipeline provides gas transportation and storage services in the Rocky Mountain region of the U.S. These operations are currently presented in held-for-sale and discontinued operations effective July 2020 until closing of the Q-Pipe Transaction with BHE, which is expected in early 2021.
See Notes 3 andNote 9 to the Consolidated Financial Statements for moreadditional 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, U.S. Army Corps of Engineers and the U.S. Department of Transportation.
State Regulations
Electric
Virginia Power and DESC’s electric utility retail services are subject to regulation by the Virginia and North Carolina Commissions and the South Carolina Commission, respectively.
Virginia Power and DESC hold CPCNs which authorize them to maintain and operate their electric facilities already in operation and to sell electricity to customers. However, Virginia Power and DESC may not construct generating facilities or large capacity transmission lines without the prior approval of various state and federal government agencies. In addition, the Virginia Commission and the North Carolina Commission regulate Virginia Power’s and the South Carolina Commission regulates DESC’s transactions with affiliates and transfers of certain facilities. The Virginia, North Carolina and South Carolina Commissions also regulate the issuance of certain securities.
Electric Regulation in Virginia
The Regulation Act provides for a cost-of-service rate model and permits Virginia Power to seek recovery of costs for new generation projects, including pumped hydroelectricity generation and storage facilities as well as extensions of operating licenses of nuclear
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power generation facilities, FERC-approved transmission costs, underground distribution lines, certain environmental compliance, conservation, and energy efficiency and demand response programs and renewable energy facilities and programs through stand-alone riders, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission.
In March 2018, the GTSA reinstated base rate reviews on a triennial basis other than the 2021 Triennial Review. In the triennial review proceedings, earnings that are more than 70 basis points above the utility’s authorized ROE that might have been refunded to customers and served as the basis for a reduction in future rates, may be reduced by Virginia Commission-approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects
to include as a CCRO. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that Virginia Power may seek to recover the costs of such projects through a rider if not the subject of a CCRO. Any costs that are the subject of a CCRO may not beare deemed recovered in base rates forduring the service life of the projectstriennial 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. InFor the 2021 Triennial Review,purposes of measuring any customer refunds or CCRO amounts utilized under the GTSA, associated income taxes are factored into the determination of such rate reduction is limited to $50 million.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 Virginiaprovides for cost recovery related to participateparticipation in a carbon trading program.
See Note 13 to the Consolidated Financial Statements for additional information.
Electric Regulation in North Carolina
Virginia Power’s retail electric base rates in North Carolina are regulated on a cost-of-service/rate-of-return basis subject to North Carolina statutes and the rules and procedures of the North Carolina Commission. North Carolina base rates are set by a process that allows Virginia Power to recover its operating costs and an ROIC. If retail electric earnings exceed the authorized ROE established by the North Carolina Commission, retail electric rates may be subject to review and possible reduction by the North Carolina Commission, which may decrease Virginia Power’s future earnings. Additionally, if the North Carolina Commission does not allow recovery of costs incurred in providing service on a timely basis, Virginia Power’s future earnings could be negatively impacted. Fuel rates are subject to revision under annual fuel cost adjustment proceedings. Recent North Carolina legislation provides Virginia Power the option to apply for a multi-year rate plan to establish base rates under a performance-based rate plan rather than a general rate case. Under this optional structure, rates would be set for a multi-year period and be subject to revenue decoupling for residential customers, an annual earnings sharing mechanism and performance-based requirements.
Virginia Power’s transmission service rates in North Carolina are regulated by the North Carolina Commission as part of Virginia Power’s bundled retail service to North Carolina customers.
See Note 13 to the Consolidated Financial Statements for additional information.
Electric Regulation in South Carolina
DESC’s retail electric base rates in South Carolina are regulated on a cost-of-service/rate-of-return basis subject to South Carolina statutes and the rules and procedures of the South Carolina Commission. South Carolina base rates are set by a process that allows DESC to recover its operating costs and an ROIC. If retail electric earnings exceed the authorized ROE established by the South Carolina Commission, retail electric rates may be subject to review and possible reduction, which may decrease DESC’s future earnings. Additionally, if the South Carolina Commission does not allow recovery of costs incurred in providing service on a timely basis, DESC’s future earnings could be negatively impacted. Fuel costs are reviewed annually by the South Carolina Commission, as required by statute, and fuel rates are subject to revision in these annual fuel proceedings.
DESC offers to its retail electric customers several DSM programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. DESCalso submits annual filings to the South Carolina Commission for rider recovery related to these programs. As actualits DSM program costs are incurred, they are deferred as regulatory assetsprograms and recovered through apension costs. The DSM rider approved by the South Carolina Commission. The rider also provides forincludes 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
28
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 andNote 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’sOhio, PSNC and DESC’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 state commissions of Ohio, North Carolina and South Carolina, Commission and North Carolina Commission, respectively.
Gas Regulation in Utah, Wyoming and Idaho
Questar Gas is subject to regulation of rates and other aspects of its business by the Utah, Wyoming and Idaho Commissions. The Idaho Commission has contracted with the Utah Commission for rate oversight of Questar Gas’ operations in a small area of southeastern Idaho. When necessary, Questar Gas seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. Base rates for Questar Gas are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges. The volumetric charges for the residential and small commercial customers in Utah and Wyoming are subject to revenue decoupling and adjusted for changes in usage per customer.
Questar Gas makes routine separate filings with the Utah and Wyoming Commissions to reflect changes in the costs of purchased gas. 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.
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
29
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 customercustomer..
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 certainthe related portion of uncollectible expenses. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas recovery filings are made periodically to reflect prospective costs and recovery. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.
The North Carolina Commission has also approved a stand-alone cost recovery mechanism to recover specified capital costs and a return for pipeline integrity management infrastructure projects between general base rate cases.
In connection with the SCANA Combination, PSNC agreed not to file an application for a general rate case with the North Carolina Commission before April 2021 other than for rate adjustments as described above.
See Note 13 to the Consolidated Financial Statements for additional information.
Gas Regulation in South Carolina
DESC is subject to regulation of rates and other aspects of its natural gas distribution service by the South Carolina Commission. DESC provides retail natural gas service to customers in areas in which it has received authorization from the South Carolina Commission and in municipalities in which it holds a franchise. DESC’s base rates can be adjusted annually, pursuant to the Natural Gas Rate Stabilization Act, for recovery of costs related to natural gas infrastructure. Base rates are set based on the cost-of-service by rate class approved by the South Carolina Commission in the latest general rate case. Base rates for DESC are based primarily on a rate design methodology in which the majority of operating costs are recovered through volumetric charges. DESC also utilizes a weather normalization adjustment to adjust its base rates during the winter billing months for residential and commercial customers to mitigate the effects of unusually cold or warm weather.
DESC’s natural gas tariffs include a purchased gas adjustment that provides for the recovery of prudently incurred gas costs, including transportation costs. DESC is authorized to adjust its purchased gas rates monthly and makes routine filings with the South Carolina Commission to provide notification of changes in these rates. Costs that are under or over recovered are deferred as regulatory assets or liabilities, respectively, and considered in subsequent purchased gas adjustments. The purchased gas adjustment filings generally cover a prospective twelve-month period. Increases or decreases in purchased gas costs can result in corresponding changes in purchased gas adjustment rates and the revenue generated by those rates. The South Carolina Commission reviews DESC’s gas purchasing policies and practices, including its administration of the purchased gas adjustment, annually. DESC has also received approval from the South Carolina Commission to create DSM programs for its residential and commercial natural gas customers and a rider to retail gas rates for the recovery of the associated program costs and for a shared savings incentive. DESC has also notified the South Carolina Commission that DESC would seek to recover the net lost revenues resulting from the DSM programs through its annual Natural Gas Rate Stabilization Act proceeding.
See Note 13 to the Consolidated Financial Statements for additional information.
Federal Regulations
Federal Energy Regulatory Commission
Electric
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and, under its market-based rate authority, sells electricity in the PJM wholesale market and sells electricity to wholesale purchasers in Virginia and North Carolina. Dominion Energy’s nonregulated generators sell electricity in the PJM, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Ohio, Connecticut, Tennessee, Georgia, California and South Carolina, and Utah, under Dominion Energy’s market-based sales tariffs
authorized by FERC or pursuant to FERC authority to sell as a qualified facility. DESC may make wholesale sales at market-based rates outside its balancing authority pursuant to its market-based sales tariff authorized by FERC. In addition, Virginia Power and DESC havehas FERC approved tariffs to sell wholesale power at capped rates based on their respectiveits 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.territory. Any such sales are voluntary. FERC also regulates the issuance of certain securities by DESC.
In January 2021, Virginia Power notified PJM that it was electing to satisfy its capacity requirements by becoming a Fixed Resource Requirement Entity that self-supplies the capacity needed to serve load rather than satisfying this requirement by purchasing capacity in PJM’s Reliability Pricing Model capacity market. This change became effective for the delivery year beginning June 2022. This decision does not affect day-to-day operations.
The Companies are subject to FERC’s Standards of Conduct that govern conduct between transmission function employees of interstate gas and electricity transmission providers and the marketing function employees of their affiliates. The rule defines the
30
scope of transmission and marketing-related functions that are covered by the standards and is designed to prevent transmission providers from giving their affiliates undue preferences.
The Companies are also subject to FERC’s affiliate restrictions that (1) prohibit power sales between nonregulated plants and utility plants without first receiving FERC authorization, (2) require the nonregulated and utility plants to conduct their wholesale power sales operations separately, and (3) prohibit utilities from sharing market information with nonregulated plant operating personnel. The rules are designed to prohibit utilities from giving the nonregulated plants a competitive advantage.
EPACT included provisions to create an Electric Reliability Organization, which is required to promulgate mandatory reliability standards governing the operation of the bulk power system in the U.S. FERC has certified NERC as the Electric Reliability Organization and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards will be subject to fines of up to $1.3$1.5 million per day, per violation and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.
The Companies plan and operate their facilities in compliance with approved NERC reliability requirements. The Companies’ employees participate on various NERC committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. The Companies anticipate incurring additional compliance expenditures over the next several years because of the implementation of new cybersecurity programs. In addition, NERC has redefined critical assets which expanded the number of assets subject to NERC reliability standards, including cybersecurity assets. NERC continues to develop additional requirements specifically regarding supply chain standards and control centers that impact the bulk electric system. While the Companies expect to incur additional compliance costs in connection with NERC requirements and initiatives, such expenses are not expected to significantly affect results of operations.
In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.
In October 2011, FERC issued an order approving the settlement of DESC’s formula rate that updates transmission rates on an annual basis, including its ROE. The formula rate is designed to recover the expected revenue requirement for the calendar year and is updated annually based on actual costs. This FERC accepted formula rate enables DESC to earn a return on its investment in electric transmission infrastructure.
Gas
FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938In February 2021, DESC and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion Energy Questar Pipeline.
Dominion Energy’s remaining interstate gas transmission and storage activities, which are currently classified as held for sale, are conducted on an open access basis, in accordance with certificates, tariffs and service agreements on file with FERC and FERC regulations.
Dominion Energy operates in compliance with FERC standards of conduct, which prohibit the sharing of certain non-public transmission information or customer specific data by its interstate gas transmission and storage companies with non-transmission function employees. Pursuant to these standards of conduct, Dominion Energy also makes certain informational postings available on Dominion Energy’s website.
See Note 3 to the Consolidated Financial Statements for a discussionother members of the Q-Pipe Transaction.SEEM submitted the Southeast Energy Exchange Market Agreement to FERC for authorization. This agreement sets forth the framework and rules for establishing and maintaining a new voluntary electronic trading platform designed to enhance the existing bilateral market in the Southeast utilizing zero-charge transmission service. That transmission service, in turn, will be voluntarily provided by participating transmission service providers, including DESC. In October 2021, the Southeast Energy Exchange Market Agreement became effective by operation of law as a result of a split FERC vote. The SEEM platform became operational in November 2022.
Nuclear Regulatory Commission
All aspects of the operation and maintenance of the Companies’ nuclear power stations are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.
From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining the Companies’ nuclear generating units. See Note 23 to the Consolidated Financial Statements for furtheradditional information.
The NRC also requires the Companies to decontaminate their nuclear facilities once operations cease. This process is referred to as decommissioning, and the Companies are required by the NRC to be financially prepared. For information on decommissioning trusts, see Dominion Energy Virginia-Nuclear Decommissioning,, Dominion Energy South Carolina-Nuclear Decommissioning, and Contracted Assets-Nuclear Decommissioning above and Notes 3 and 9 to the Consolidated Financial Statements. See Note 23 to the Consolidated Financial Statements for additional information on spent nuclear fuel.
Safety Regulations
Cyber Regulations
The Companies plan and operate their facilities in compliance with approved government cyber regulatory requirements. The Companies’ employees participate on various regulatory committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. The Companies anticipate incurring additional compliance expenditures over the next several years because of the implementation of new cybersecurity programs such as the Transportation Security Administration’s gas sector cyber security directives. In addition, NERC continues to develop additional requirements specifically regarding supply chain standards and control centers that impact the bulk electric system. While the Companies expect to incur additional compliance costs in connection with NERC, Transportation Security Administration and other governmental agency regulations, such expenses are not expected to significantly affect results of operations.
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Safety Regulations
Dominion Energy is also subject to federal and state pipeline safety laws and regulations which set forth numerous operation, maintenance and inspection and repair regulations designed to ensure the Pipeline Safety Improvement Actsafety and integrity of 2002 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, which mandate inspections of interstate and intrastate natural gas transmissionDominion Energy’s pipeline 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.infrastructure.
The Companies are subject to a number of federal and state laws and regulations, including Occupational Safety and Health Administration, and comparable state statutes, whose purpose is to protect the health and safety of workers. The Companies have an internal safety, health and security program designed to monitor and enforce compliance with worker safety requirements, which is routinely reviewed and considered for improvement. The Companies believe that they are in material compliance with all applicable laws and regulations related to worker health and safety. Notwithstanding these preventive measures, incidents may occur that are outside of the Companies’ control.
Environmental Regulations
Each of the Companies’ operating segments is subject to substantial laws, regulations and compliance costs with respect to environmental matters. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of significant penalties for noncompliance, including fines, injunctive relief and other sanctions. The cost of complying with applicable environmental laws, regulations and rules is material to the Companies. If compliance expenditures and associated operating costs are not recoverable from customers through regulated rates (in regulated businesses) or market prices (in unregulated businesses), those costs could adversely affect future results of operations and cash flows. The Companies have applied for or obtained the necessary environmental permits for the construction and operation of their facilities. Many of these permits are subject to reissuance and continuing review. For a discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance required to be discussed in this Item, see Environmental Matters in Future Issues and Other Matters in Item 7. MD&A. Additional information can also be found in Note 23 to the Consolidated Financial Statements.
Global Climate Change
The Companies support a federal climate change program that would provide a consistent, economy-wide approach to addressing this issue. Regardless of federal action, the Companies are reducing their GHG emissions while meeting the growing needs of their customers. In 2020, Virginia enacted the VCEA which addresses climate change matters such as the reduction of GHG emissions and renewable energy portfolio standards. Dominion Energy’s CEO and executive operational leadership within each operating segment are responsible for compliance with the laws and regulations governing environmental matters, including GHG emissions, and Dominion Energy’s Board of Directors receives periodic updates on these matters. See State Regulations—Electric—Electric Regulation in Virginia above, Environmental Strategy below,, Environmental Matters in Future Issues and Other Matters in Item 7. MD&A and Note 23 to the Consolidated Financial Statements for additional information on climate change legislation and regulation.
Air
The CAA is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. Regulated emissions include, but are not limited to, carbon, methane, VOC, NOX, other GHGs, mercury, other toxic metals, hydrogen chloride, SO2 and particulate matter. At a minimum, delegated states are required to establish regulatory programs to address allmeet applicable requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of the Companies’ facilities are subject to the CAA’s permitting and other requirements.
Water
The CWA is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. The CWA and analogous state laws impose restrictions and strict controls regarding discharges of effluent into surface waters and require permits to be obtained from the EPA or the analogous state agency for those discharges. Containment berms and similar structures may be required to help prevent accidental releases. Dominion EnergyThe Companies must comply with applicable CWA requirements at itstheir 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’sthe Companies' projects and operations may impact tidal and non-tidal wetlands. In these instances, Dominion Energythe Companies must obtain authorization from the appropriate federal, state and local agencies prior to impacting wetlands. The authorizing agency may impose significant direct or indirect mitigation costs to compensate for such impacts to wetlands.
Waste and Chemical Management
Dominion Energy is subject to various federal and state laws and implementing regulations governing the management, storage, treatment, reuse and disposal of waste materials and hazardous substances, including the Resource Conservation and Recovery Act of 1976, CERCLA, the Emergency Planning and Community Right-to-Know Act of 1986 and the Toxic Substances Control Act of 1976.
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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.
ENVIRONMENTALSTRATEGY
Dominion Energy hasis 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. This goal covers carbonIn February 2022, Dominion Energy expanded this commitment to cover Scope 2 emissions and methane emissions from both electric generationmaterial categories of Scope 3 emissions: electricity purchased to power the grid, fuel purchased for its power stations and gas distribution systems and consumption of sales gas by natural gas operations.customers. As part of the net zero commitment, Dominion Energy has specifically committed to interim targets to cut Scope 1 carbon emissions from its electric operations by 55% by 2030, relative to 2005 emissions, and cut Scope 1 methane emissions from its natural gas infrastructure operations by 65% by 2030 and by 80% by 2040, in each case relative to 2010 emissions. As previously announced, Dominion Energy’s commitment is highlighted by its up to $73 billion potential capital investment in projects supporting decarbonization efforts from 2022 to 2035. While the completion of the comprehensive business review discussed in Future Issues and Other Matters in Item 7. MD&A could result in a material adjustment to Dominion Energy’s capital expenditure plans, Dominion Energy has announced its commitment to an industry-leading regulated investment opportunity focused on decarbonization. Dominion Energy’s future capital expenditure plan is expected to reflect a decreased investment in new nonregulated solar generation facilities.
To meet its customers’ needs for safe, reliable, and affordable energy and to reach net zero emissions, in the near term Dominion Energy is seeking extension of the licenses of its zero-carbon nuclear fleet in Virginia,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.grid and requesting offers for responsibly sourced gas or from those suppliers who are committed to net zero. The strategy to meet these objectives consists of three major elements which will significantly reduce GHG emissions:
• Clean energy diversity; • Innovation and energy infrastructure modernization; and • Conservation and energy efficiency.
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Over the long term, Dominion Energy’s ability to meet its customers’ needs for safe, reliable and affordable energy and achieve net zero emissions will require supportive legislative and regulatory policies, advancements in technology and broader investments across the economy. Dominion Energy will pursue solutions, including pilot programs, of technologies such as large-scale battery storage, carbon capture and storage, small modular reactors and hydrogen if and when they become technologically and economically feasible.
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Environmental Justice
Dominion Energy seeks to build partnerships and engage with local communities, stakeholders and customers on environmental issues important to them, including environmental justice considerations such as fair treatment, inclusive involvement and effective communication. Dominion Energy commits to increase inclusiveness ofduring its stakeholder engagement on decisions regarding the siting and operation of energy infrastructure. Dominion Energyinfrastructure and strives to include to all people and communities, regardless of race, color, national origin or income to ensure a diversity of views are considered in ourits public engagement process.
Transparency
As part of its broader commitment to transparency, Dominion Energy increased its disclosures around carbon and methane emissions. Dominion Energy discloses its environmental commitments, policies and initiatives in a Sustainability and Corporate Responsibility Report as well as a Climate Report in addition to other reports included on Dominion Energy’s dedicated Environmental, Social and Governance website.
Clean Energy Diversity
To achieve its net zero commitment, Dominion Energy is pursuing a diverse mix of cleaner, more efficient and lower-emitting methods of generating and delivering energy, while advancing aggressive voluntary measures to continue dramatically reducing emissions from traditional generation and delivery. Diversifying the energy portfolio enables Dominion Energy to provide customers with cleaner options while protecting the power supply from potential disruption.
Over the past two decades, Dominion Energy has changed the fuel mix it uses to generate electricity, as well as improved the systems that make up its natural gas operations, to achieve a cleaner future. In addition to reducing GHG emissions, Dominion Energy’s environmental strategy has also resulted in measurable reductions of other air pollutants such as NOX, SO2 and mercury and reduced the amount of coal ash generated and the amount of water withdrawn. Dominion Energy achieved GHG and other air pollutant reductions by implementing an integrated environmental strategy that addresses electric energy production and delivery and energy management. As part of this strategy, Dominion Energy has retired, or committed to retire, several of its fossil fuel electric generating facilities, including those powered by coal, oil and gas with the replacement of this capacity coming from the development of renewable energy facilities.
Renewable energy is an important component of a diverse energy mix designed to meet Dominion Energy’s customers’ needs for safe, reliable and reliable energy mix.affordable energy. Dominion Energy continues to add utility-scale solar capacity and currently has the third largest utility-owned solar fleet in the U.S. with 2.2 GW in operations across 10 states as of December 31, 2020. Dominion Energy also has approximately 2.5 GW of solar generating capacity under development, including agreements for acquisitions of projects, for facilities expected to commence commercial operations in 2021 through 2025 in Virginia, South Carolina and Ohio, representing approximately $4.7 billion of investment. Dominion Energypreviously announced it expects to continueinvest up to make
significant investments$21 billion from 2022 through 2035 in solar generation to achieve its target of 13.4 GW generating capacity in-service by the end of 2035. While an updated investment plan is dependent upon completion of the comprehensive business review discussed in Future Issues and Other Matters in Item 7. MD&A, it is expected to reflect a decreased investment in new nonregulated solar generation facilities. As of December 31, 2022, Dominion Energy had 2.4 GW of solar generation capacity in operation across five states and several projects under various stages of development which represented a potential generating capacity of approximately 7.8 GW. In addition, Dominion Energy is pursuingpreviously announced it expects to invest up to $21 billion from 2022 through 2035 in offshore wind withgeneration facilities. Dominion Energy has commenced development of the 2.6 GW Coastal Virginia Offshore WindCVOW Commercial project,Project, expected to be placed in service by the end of 2026, along with the Coastal Virginia Offshore WindCVOW Pilot projectProject which achieved commercial operation in January 2021. To support these renewable generation facilities, Dominion Energy previously announced it expects to invest up to $4 billion in energy storage facilities from 2022 through 2035. As of December 31, 2022, Virginia Power had projects under various stages of development which represented a potential storage capacity of approximately 1.2 GW.
Preservation of Dominion Energy’s existing carbon-free baseload nuclear generation is also an important component of Dominion Energy’s GHG emissions reduction strategy. Dominion Energy previously announced it expects to invest from 2022 through 2035 approximately $4 billion supporting 20-year life extensions of its units at Surry and North Anna. Virginia Power has received a 20-year extension of the operating licenses for its two units at Surry and has commenced the process to extend the operating licenses for its two units at North Anna.
Dominion Energy is pursuing renewable natural gas through its investment in Align RNG, which is developing projects to capture and convert methane emissions from swine farms, and its strategic alliance with Vanguard Renewables in collaboration with the Dairy Farmers of America to develop projects to capture and convert methane emissions from dairy farms across the U.S. Preservation of Dominion Energy’s existing carbon-free baseload nuclear generation is also an important component of Dominion Energy’s GHG emissions reduction strategy. Accordingly, Virginia Power has commenced the processEnergy previously announced it expects to extend the operating licenses for its four nuclear units at Surry and North Anna. invest approximately $2 billion in renewable natural gas facilities from 2022 through 2035.
See Operating Segments and Item 2. Properties for additional information.
The IRA provides many incentives designed to encourage production of clean energy, reduce carbon emissions, and promote domestic manufacturing. The IRA significantly extends the investment and production tax credits for renewable technologies including wind and solar, and expands the qualifying technologies to include stand-alone storage, hydrogen, renewable natural gas, nuclear and, after
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2024, other zero-emissions facilities. The IRA supersedes certain prior renewable energy legislation and contains a two-tiered credit system applicable to both the production and investment tax credits with a lower base credit amount that can be increased up to five times if the taxpayer can satisfy certain labor requirements. See Note 5 to the Consolidated Financial Statements and Future Issues and Other Matters in Item 7. MD&A for additional information on the IRA.
Innovation and Energy Infrastructure Modernization
One of the pillars of Dominion Energy’s net zero strategy is a focus on innovation as way to advance technology and sustainability. This includes investing in and building upon previously proven technology, including large-scale battery storage, hydrogen, advanced nuclear technology and carbon capture technology. Further, Dominion Energy’s previously announced growth capital plan from 20212022 through 20252026 includes a focus on upgrading the electric system in Virginia through investments in additional renewable generation facilities, smart meters, customer information platform, intelligent grid devices and associated control systems, physical and cyber security investments, strategic undergrounding and energy conservation programs. Dominion Energy also plans to upgrade its gas and electric transmission and distribution networks and meet environmental requirements and standards set by various regulatory bodies. These enhancements are aimed at meeting Dominion Energy’s continued goal of providing safe, reliable service while addressing increasing electricity consumption, and making Dominion Energy’s system more responsive to its customers’ desire to more efficiently manage their energy consumption as well asand 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 2021.Program. In addition, Dominion Energy is a member of the One Future Coalition, an industry group with members pledging to limit methane emissions to below 1% of gas throughput across the entire natural gas value chain.
See Operating Segments for additional information.
Conservation and Energy Efficiency
Conservation and load management play a significant role in meeting the growing demand for electricity and natural gas, while also helping to reduce the environmental footprint of Dominion Energy’s customers.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. |
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GHG Emissions
Dominion Energy’s integrated environmental strategy supports a reduction in GHG emissions.Energy continues to make progress on achieving its net zero emissions commitment. Through 2019,2021, Dominion Energy has reduced direct Scope 1 CO2 equivalent carbon and methane emissions from its electric generation and natural gas operations by 44%. Through 2021, Dominion Energy has reduced carbon emissions from its electric generating units (based on ownership percentage)generation by 57%46% since 2005 and reduced methane
emissions from its natural gas infrastructure operations by 25%38% since 2010. For the purposes of these calculations and consistent with GHG protocol requirements for reporting GHG emission reductions over time, both the baseline and 2021 emissions data excludes the operations sold as part of the Q-Pipe Group and Hope.
Dominion Energy’s 20202022 emissions data is not yet available. Emissions for fiscal year 2019 include the assets acquired as a part of the SCANA Combination, such as DESC’s electric generation operations and DESC and PSNC’s natural gas operations. Dominion Energy’s 2019 emissions data presented below also includes the operations of gas transmission and distribution operations sold or to be sold to BHE as part of the GT&S Transaction and the Q-Pipe Transaction.
Corporate GHG Inventory
Dominion Energy has been reporting GHG emissions, including carbon, methane, N2O and SF6, from its natural gas infrastructure, electric generation and power delivery operations to the EPA since 2011 under the EPA mandatory GHG Reporting Program. Dominion Energy’smaintains a comprehensive Corporate GHG Inventory, used for reporting purposeswhich follows methodologies specified in the EPA’s Mandatory GHG Reporting Rule, 40 Code of Federal Regulations Part 98 for calculating emissions, as well as approved industry protocols. In its annual Corporate GHG Inventory, Dominion Energy also voluntarily includes carbon and methane emission estimates
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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 Energyit voluntarily reports to various programs in which it participates in.participates. As a result, Dominion Energy’s reported methane emissions in its Corporate GHG Inventory are higher than what is reported to the EPA. Dominion Energy includes emissions data in its Corporate GHG Inventory based on its ownership percentage of the associated assets and for the period in which the operations are owned by Dominion Energy.
Total direct Scope 1 CO2 equivalent emissions reported under Dominion Energy’s Corporate GHG Inventory were 36.934.9 million metric tons in 2019.2021. Reported CO2 equivalent emissions include CO2, CH4, N2O and SF6 emissions from Dominion Energy’s electric generation operations, electric transmission and distribution operations and natural gas operations.
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Consistent with its ownership percentage, Dominion Energy’s 20192021 emissions data reported under its Corporate GHG Inventory includes emissions from the Q-Pipe Group (through December 2021) as well as the entire year of operations for Hope.
EPA Mandatory GHG Reporting Program
Dominion Energy has been reporting GHG emissions, asincluding carbon, methane, N2O and SF6, from its natural gas infrastructure, electric generation and power delivery operations to the EPA since 2011 under the EPA mandatory GHG Reporting Program. The EPA’s mandatory GHG Reporting Program requires annual reporting based on full equity asset ownership at the end of the calendar year. Dominion Energy’s 2021 GHG emissions reported under various subparts of the EPA’s Mandatory GHG Reporting Program as of December 31, 2020,2021, which include the operations of Hope, are as follows:
Natural Gas Operations – 20192021 Emissions
Segment |
| Subpart W |
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| Subpart C |
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| Subparts |
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| Subparts |
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| Subparts |
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| Subparts |
| ||||||
(metric tons) |
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|
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|
|
|
|
|
|
|
|
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| ||||||
Distribution |
|
| 33,482 |
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|
|
|
|
| 33,482 |
|
|
| 2,168 |
|
|
| — |
|
|
| 839,208 |
| |
Production(1) |
|
| 13,731 |
|
|
|
|
|
| 13,731 |
|
|
| 10,028 |
|
|
| 0.02 |
|
|
| 353,311 |
| |
Transmission pipelines(1) |
|
| 573 |
|
|
|
|
|
| 573 |
|
|
| 17 |
|
|
|
|
|
| 14,340 |
| ||
Transmission compressor stations(1) |
|
| 636 |
|
|
| 4.7 |
|
|
| 641 |
|
|
| 249,628 |
|
|
| 0.47 |
|
|
| 265,788 |
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Gathering and boosting |
|
| 3,555 |
|
|
|
|
|
| 3,555 |
|
|
| 79,542 |
|
|
| 0.16 |
|
|
| 168,472 |
| |
Storage(1) |
|
| 422 |
|
|
| 1.5 |
|
|
| 423 |
|
|
| 79,128 |
|
|
| 0.15 |
|
|
| 89,749 |
|
LNG storage |
|
| 172 |
|
|
| — |
|
|
| 172 |
|
|
| 630 |
|
|
| — |
|
|
| 4,940 |
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Total(2)(3) |
|
| 52,571 |
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|
| 6.2 |
|
|
| 52,577 |
|
|
| 421,141 |
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|
| 0.80 |
|
|
| 1,735,808 |
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Segment |
| Subpart W CH4 Emissions |
|
| Subpart C CH4 Emissions |
|
| Subparts W & C CH4 Emissions |
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| Subparts W & C CO2 Emissions |
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| Subparts W & C N2O Emissions |
| |||||
(metric tons) |
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Distribution |
|
| 34,735 |
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|
|
|
|
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| 34,735 |
|
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| 2,123 |
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|
Production |
|
| 17,168 |
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|
|
|
|
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| 17,168 |
|
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| 10,951 |
|
|
| 0.02 |
|
Transmission pipelines |
|
| 4,576 |
|
|
|
|
|
|
| 4,576 |
|
|
| 73 |
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|
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Transmission compressor stations |
|
| 2,722 |
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| 12 |
|
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| 2,734 |
|
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| 650,859 |
|
|
| 1.22 |
|
Gathering and boosting |
|
| 3,083 |
|
|
|
|
|
|
| 3,083 |
|
|
| 93,352 |
|
|
| 0.19 |
|
Storage |
|
| 1,542 |
|
|
| 5 |
|
|
| 1,547 |
|
|
| 261,741 |
|
|
| 0.49 |
|
LNG import/export |
|
| 111 |
|
|
| 21 |
|
|
| 132 |
|
|
| 1,166,479 |
|
|
| 2.14 |
|
Processing |
|
| 91 |
|
|
|
|
|
|
| 91 |
|
|
| 2,168 |
|
|
| 0.01 |
|
Total |
|
| 64,028 |
|
|
| 38 |
|
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| 64,066 |
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| 2,187,746 |
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| 4.07 |
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Electric Generation Operations – 20192021 Emissions
Company |
| Subparts C & D |
|
| Subparts C & D |
|
| Subparts C & D |
|
| Subparts C & D |
|
| Subparts C & D |
|
| Subparts C & D as |
| ||||||
(metric tons) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Virginia Power(1) |
|
| 22,426,491 |
|
|
| 1,258 |
|
|
| 175 |
|
|
| 31,447 |
|
|
| 52,031 |
|
|
| 22,509,968 |
|
DESC |
|
| 9,429,039 |
|
|
| 601 |
|
|
| 83 |
|
|
| 15,030 |
|
|
| 24,815 |
|
|
| 9,468,883 |
|
Total(2) |
|
| 31,855,530 |
|
|
| 1,859 |
|
|
| 258 |
|
|
| 46,476 |
|
|
| 76,845 |
|
|
| 31,978,852 |
|
Company |
| Subparts C & D CO2 Emissions |
|
| Subparts C & D CH4 Emissions |
|
| Subparts C & D N2O Emissions |
| |||
(metric tons) |
|
|
|
|
|
|
|
|
|
|
|
|
Virginia Power(1) |
|
| 19,051,753 |
|
|
| 17,096 |
|
|
| 27,863 |
|
DESC |
|
| 9,855,332 |
|
|
| 10,239 |
|
|
| 16,239 |
|
Total |
|
| 28,907,085 |
|
|
| 27,335 |
|
|
| 44,102 |
|
(2) Totals may not foot due to rounding.
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Electric Transmission and Distribution Operations – 20192021 Emissions
Company |
| Subpart DD |
|
| Subpart DD |
| ||
(metric tons) |
|
|
|
|
|
| ||
Virginia Power |
|
| 0.85 |
|
|
| 19,332 |
|
DESC |
|
| 0.96 |
|
|
| 21,910 |
|
Total(1) |
|
| 1.81 |
|
|
| 41,242 |
|
Company(1) |
| Subpart DD SF6 Emissions |
|
| Subpart DD SF6 as CO2 Equivalent Emissions |
| ||
(metric tons) |
|
|
|
|
|
|
|
|
Virginia Power |
|
| 2 |
|
|
| 38,338 |
|
|
|
CYBERSECURITYENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES
Dominion Energy incurred $251 million, $221 million and $238 million of expenses (including accretion and depreciation) during 2022, 2021 and 2020 respectively, in connection with environmental protection and monitoring activities. Dominion Energy expects these expenses to be approximately $254 million and $235 million in 2023 and 2024, respectively. In an effortaddition, capital expenditures related to reduce the likelihoodenvironmental controls were $91 million, $37 million, and severity of cyber intrusions, the Companies have a comprehensive cybersecurity program designed$58 million for 2022, 2021 and 2020, respectively. Dominion Energy expects these expenditures to protectbe approximately $153 million and preserve the confidentiality, integrity$173 million for 2023 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 additional information. 2024, 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. As discussed in Future Issues in Item 7. MD&A, Dominion Energy has commenced a comprehensive business review. The outcomes of the business review and the implementation of the resulting recommendations may be subject to various risks and uncertainties (some of which may include the risks and uncertainties discussed below or other risks and uncertainties that cannot yet be determined) that could have a material impact on the Companies’ future results of operations, cash flows and/or financial condition.
Regulatory, Legislative and Legal Risks
The rates of the Companies’ principal electric transmission, distribution and generation operations and gas distribution operations are subject to regulatory review. Revenue provided by the Companies’ electric transmission, distribution and generation operations and by gas distribution operations is based primarily on rates approved by state and federal regulatory agencies. The profitability of the Companies’ businesses is dependent on their ability, through the rates that they are permitted to charge, to recover costs and earn a reasonable rate of return on their capital investment.
At the federal level, the Companies’ wholesale rates for electric transmission service are regulated by FERC. Rates for electric transmission services are updated annually according to a FERC-approved formula rate mechanism, and may be subject to additional prospective adjustments and retroactive corrections. A failure by the Companies to support these rates could result in rate decreases from current rate levels, which could adversely affect the Companies’ results of operations, cash flows and financial condition.
At the state level, Virginia Power’s retail base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia Commission in a proceeding that involves the determination of Virginia Power’s actual earned ROE during a historic test period, and the determination of Virginia Power’s authorized ROE prospectively. The GTSA reinstated triennial reviews commencing with the 2021 Triennial Review. Under certain circumstances described in the Regulation Act, Virginia Power may be required to refund a portion of its earnings to customers through a refund process and to reduce its rates. Additionally, Virginia Power’s ability to utilize CCROs for certain qualifying projects as provided for in the GTSA may be limited if the Virginia Commission does not approve such projects. Virginia Power makes assessments throughout the review period and will record a regulatory liability for refunds and/or CCRO benefits to customers in any period it is determined probable, which could be material to the Companies’ results of operations in the period recognized and to cash flows on completion of any triennial review. Several proposed legislative bills have been introduced in the Virginia General Assembly which, if ultimately enacted into law, could have a material impact on Virginia Power’s retail base rates and other cost-recovery mechanisms. Items under consideration include frequency of base rate reviews, eliminating CCROs, shifting the recovery of certain costs currently recovered through riders into base rates and adjusting the parameters for determining an acceptable ROE and revenue sharing.
In states other than Virginia, the Companies’ retail electric base rates for generation and distribution services to customers are regulated on a cost-of-service/rate-of-return basis subject to the statutes, rules and procedures of such states. Dominion Energy’s rates for gas distribution to retail customers are similarly regulated at the state level. If retail electric or gas earnings exceed the returns established by state utility commissions, retail electric rates or gas rates may be subject to review and possible reduction, which may decrease the Companies’ future earnings. Additionally, if any state utility commission does not allow recovery through base rates, on a timely basis, of costs incurred in providing service, the Company’s future earnings could be negatively impacted.
Under certain circumstances, state utility regulators may impose a moratorium on increases to retail base rates for a specified period of time, which could delay recovery of costs incurred in providing service. Additionally, governmental officials, stakeholders and advocacy groups may challenge any of thesethe regulatory reviews.reviews or proceedings referred to above. Such challenges may lengthen the time, complexity and costs associated with such regulatory reviews.reviews or proceedings.
The Companies’ generation business may be negatively affected by possible FERC actions that could change market design in the wholesale markets or affect pricing rules or revenue calculations in the RTO markets. The Companies’ generation stations operating in RTO markets sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these generation stations to take advantage of market price opportunities, but also expose them to market risk. Properly functioning competitive wholesale markets depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize RTOs to make changes in market design. FERC also periodically reviews the Companies’ authority to sell at market-based rates. Material changes by FERC to the design of the wholesale markets or its interpretation of market rules, the Companies’ authority to sell power at market-based rates, or changes to pricing rules or rules involving revenue calculations, could adversely impact the future results of the Companies’ generation business. For example, in December 2019,September 2021, FERC issued ana final order on PJM’s Minimum Offer Price Rule proposals finding thethat allows distributed energy resource aggregators to compete in regional wholesale
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electric markets. This rule followed a previous order which mandated that distributed energy resources be allowed to participate in wholesale markets. RTOs, including PJM, tariff unjust and unreasonable and directed PJMare responsible for issuing implementation rules 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.for approval. In addition, changes to the interpretation and application of FERC’s market manipulation rules may occur from time to time. A failure to comply with these market manipulation rules could lead to civil and criminal penalties.
The Companies are subject to complex governmental regulation, including tax regulation, that could adversely affect their results of operations and subject the Companies to monetary penalties. The Companies’ operations are subject to extensive federal, state and local regulationlaws and regulations and require numerous permits, approvals and certificates from various governmental agencies. Such laws and regulations govern the terms and conditions of the services we offer, our relationships with affiliates, protection of our critical electric infrastructure assets and pipeline safety, among other matters. These operationsThe Companies are also subject to legislation and associated regulation governing taxation at the federal, state and local level. They must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for existing operations and that the businesses are conducted in accordance with applicable laws. The Companies’ businesses are subject to regulatory regimes which could result in substantial monetary penalties if anyeither of the Companies is found not to be in compliance, including mandatory reliability standards and interaction in the wholesale markets. New laws or regulations, the revision or reinterpretation of existing laws or regulations, changes in enforcement practices of regulators, or penalties imposed for non-compliance with existing laws or regulations may result in substantial additional expense. Recent legislative and regulatory changes that are impacting the Companies include the IRA, the VCEA, the 2017 Tax Reform Act and tariffs imposed on imported solar panels by the U.S. government in 2018.
Through the SCANA Combination, Dominion Energy acquired SCANA and DESC whichThe Companies have been and may continue to be or become subject to numerous legal proceedings and ongoing governmental investigations and examinations. While a significant portion ofThe Companies may from time to time be subject to various legal proceedings and governmental investigations and examinations. For example, Dominion Energy, following the SCANA Combination, has been subject to numerous federal and state legal proceedings and governmental investigations have been settled, SCANA and DESC remain defendants in multiple lawsuits and investigations relating to the decision of SCANA and DESC to abandon construction at the NND Project. Among other things, theDominion Energy has spent substantial amounts of time and money defending these lawsuits and investigations allege misrepresentation, failureproceedings and on related investigations. In addition, juries have demonstrated a willingness to properly manage the NND Project, unfair trade practicesgrant large awards in certain cases, including personal injury claims. Accordingly, actual costs incurred may differ materially from insured or reserved amounts and violation of anti-trust laws. Additionally, pursuant to the SCANA Merger Agreement and applicable indemnification agreements, SCANA is indemnifying former directors and officers of SCANA and DESC who are defendantsmay not be recoverable, in federal and state legal proceedings relating to the decision to abandon construction at the NND Project and the subsequent SCANA Combination. Among other things, the lawsuits allege breaches of various fiduciary duties.
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, is uncertain and may adversely affect Dominion Energy’sthe 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 16,100 MW16.1 GW of solar or onshore wind capacity by the end of 2035, 5,200 MWwhich 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 2,700 MW2.7 GW of energy storage by the end of 2035.2035 to be in the public interest. The VCEA and related legislation also directsauthorizes Virginia Power to participate in a program consistent with RGGI, requiring the purchase of carbon credits to offset emissions from Virginia Power’s generating fleet within the state. In January 2022, the Governor of Virginia issued an executive order which puts directives in place to start the withdrawal of Virginia from RGGI. Cost recovery for these initiatives will require approval by the Virginia Commission which may be denied or materially altered to the detriment of the Companies. For example, the Companies recorded charges in 2022 associated with the Virginia Commission's approval in June 2022 of Virginia Power's petition that RGGI compliance costs incurred and unrecovered through July 2022 be recovered through existing base rates in effect during the period incurred. In addition, permitting and other project execution challenges may hinder Virginia Power’s ability to meet the requirements of the VCEA. The Companies could face similar risks if there is further legislation at the federal and/or state level mandating additional limitations on GHG emissions or requiring additional efficiency improvements.
In February 2020, Dominion Energy announced its commitment to achieve net zero carbon and methane Scope 1 emissions by 2050. In February 2022, Dominion Energy expanded this commitment to cover Scope 2 emissions and material categories of Scope 3 emissions. To meet this commitment, the Companies expect to construct new electric generation facilities, including renewable facilities such as wind and solar, and to seek the extension of operating licenses for the Companies’ nuclear generation facilities. The Companies also need to depend on technological improvements not currently in commercial development. Additionally, actions taken in furtherance of Dominion Energy’s net zero commitment may impact existing generation facilities, including as a result of fuel switching and/or the retirement of high-emitting generation facilities and their potential replacement with lower-emitting generation facilities. Further, the ability to realize this commitment will require the Companies to be able to obtain significant financing. These
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efforts will require approvals from various regulatory bodies for the siting and construction of such new facilities and a determination by the applicable state commissions that costs related to the construction are prudent. Given these and other uncertainties associated with the implementation of Dominion Energy’s net zero commitment, the Companies cannot estimate the aggregate effect of future actions taken in furtherance of this commitment on their results of operations or financial condition or on their customers. However, such actions could render additional existing generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect the Companies’ results of operations, financial performance or liquidity.
There are also potential impacts on Dominion Energy’s natural gas business from its net zero emissions commitment as well as federal or state GHG regulations which may require further GHG emission reductions from the natural gas sector which, in addition to
resulting in increased costs, could affect demand for natural gas. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products, which could impact the natural gas business.Dominion Energy’s renewable natural gas projects, expected to be a key component of Dominion Energy’s environmental strategy, require approvals from various regulatory bodies for the siting and construction of such facilities.
The Companies’ operations and construction activities are subject to a number of environmental laws and regulations which impose significant compliance costs on the Companies. The Companies’ operations and construction activities are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources, and health and safety. Compliance with these legal requirements requires the Companies to commit significant capital toward permitting, emission fees, environmental monitoring, installation and operation of environmental control equipment and purchase of allowances and/or offsets. Additionally, the Companies could be responsible for expenses relating to remediation and containment obligations, including at sites where they have been identified by a regulatory agency as a potentially responsible party. Expenditures relating to environmental compliance have been significant in the past, and the Companies expect that they will remain significant in the future. Certain facilities have become uneconomical to operate and have been shut down, converted to new fuel types or sold. These types of events could occur again in the future.
We expect that existing environmental laws and regulations may be revised and/or new laws may be adopted including regulation of GHG emissions which could have an impact on the Companies’ business (risks relating to regulation of GHG emissions from existing fossil fuel-fired electric generating units are discussed in more detail above and below). In addition, further regulation of air quality and GHG emissions under the CAA may be imposed on the natural gas sector. The Companies are also subject to federal water and waste regulations, including regulations concerning cooling water intake structures, coal combustion by-product handling and disposal practices, wastewater discharges from steam electric generating stations, management and disposal of hydraulic fracturing fluids and the potential further regulation of polychlorinated biphenyls.
Compliance costs cannot be estimated with certainty due to the inability to predict the requirements and timing of implementation of any new environmental rules or regulations. Other factors which affect the ability to predict future environmental expenditures with certainty include the difficulty in estimating clean-up costs and quantifying liabilities under environmental laws that impose joint and several liabilities on all responsible parties. However, such expenditures, if material, could make the Companies’ facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect the Companies’ results of operations, financial performance or liquidity.
The Companies are subject to risks associated with the disposal and storage of coal ash. The Companies historically produced and continue to produce coal ash, or CCRs, as a by-product of their coal-fired generation operations. The ash is stored and managed in impoundments (ash ponds) and landfills located at 11 different facilities, eight of which are at Virginia Power.
The EPA has issued regulations concerning the management and storage of CCRs, which Virginia has adopted. These CCR regulations require the Companies to make additional capital expenditures and increase operating and maintenance expenses. In addition, the Companies will incur expenses and other costs associated with closing, corrective action and ongoing monitoring of certain ash ponds.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
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transmission lines, pipeline replacements, facility expansions or renewed licensing, conversions and other infrastructure developments or construction. Additional projects may be considered in the future. The Companies compete for projects with companies of varying size and financial capabilities, including some that may have competitive advantages. Commencing construction on announced and future projects may require approvals from applicable state and federal agencies, and such approvals could include mitigation costs which may be material to the Companies. Projects may not be able to be completed on time or in accordance with our estimated costs as a result of weather conditions, delays in obtaining or failure to obtain regulatory and other, including PJM, approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, concerns raised during stakeholder engagement, a decline in the credit strength of counterparties or vendors, inflation, or other factors beyond the Companies’ control. For example, Dominion Energy has been involved with projects which have experienced certain
delays in obtaining and maintaining permits necessary for construction along with construction delays due to judicial actions which impacted the cost and schedule such as the Atlantic Coast Pipeline Project and ultimately led to its cancellation.cancellation in July 2020. Even if facility construction, pipeline, expansion, electric transmission line, conversion and other infrastructure projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of the Companies following completion of the projects may not meet expectations.
Start-up and operational issues can arise in connection with the commencement of commercial operations at our facilities. Such issues may include failure to meet specific operating parameters, which may require adjustments to meet or amend these operating parameters. Additionally, the Companies may not be able to timely and effectively integrate the projects into their operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Any of these or other factors could adversely affect the Companies’ ability to realize the anticipated benefits from the facility construction, pipeline, electric transmission line, expansion, conversion and other infrastructure projects.
The development and construction of the CVOW Commercial Project involves significant risks. The CVOW Commercial Project is a large-scale, complex project that will take several years to complete. Significant delays or cost increases, or an inability to recover certain project costs, could have an adverse effect on the Companies’ financial condition, cash flows and results of operations. If the Companies are unable to complete the development and construction of the CVOW Commercial Project or decide in the future to delay or cancel the project, the Companies may not be able to recover all or a portion of their investment in the project and may incur substantial cancellation payments under existing contracts or other substantial costs associated with any such delay or cancellation. The Companies’ ability to complete the CVOW Commercial Project within the currently proposed timeline, or at all, and consistent with current cost estimates is subject to various risks and uncertainties, certain of which are beyond the Companies’ control.
The development and construction of the CVOW Commercial Project is dependent on the Companies’ ability to obtain and maintain various local, state and federal permits and other regulatory approvals, including Virginia Commission approval for rider recovery of project costs. In addition, the design and route of the project’s onshore electric transmission, network upgrades and other facilities remain subject to regulatory and PJM review and approval. Changes in the design and route of these onshore facilities, including an increase in amount of undergrounding, would likely increase project costs. Also, the CVOW Commercial Project may become the subject of litigation or other forms of intervention by third parties, including stakeholders or advocacy groups, that may impact the timing and receipt of permits or other regulatory approvals or otherwise delay or increase the cost of the project. The Companies’ ability to recover unforeseen cost increases associated with construction of the CVOW Commercial Project is potentially limited which could negatively impact the Companies’ future financial condition, results of operations and/or cash flows. In accordance with the Virginia Commission’s order in December 2022, the Companies are subject to a cost sharing mechanism in which Virginia Power will be eligible to recover 50% of such incremental costs which fall between $10.3 billion and $11.3 billion with no recovery of such incremental costs which fall between $11.3 billion and $13.7 billion. There is no cost sharing mechanism for any total construction costs in excess of $13.7 billion, the recovery of which would be determined in a future Virginia Commission preceding. In addition, the order includes enhanced performance reporting provisions for the operation of the CVOW Commercial Project. To the extent the net annual net capacity factor is below 42%, as determined on a three-year rolling average, Virginia Power is required to provide detailed explanation of the factors contributing to any shortfall to the Virginia Commission which could determine in a future proceeding a remedy for incremental costs incurred associated with any deemed unreasonable or imprudent actions of Virginia Power. Any such action by the Virginia Commission could adversely impact the Companies’ future financial condition, results of operations and/or cash flows.
The Companies’ ability to invest the significant financial resources necessary for the CVOW Commercial Project is dependent on the Companies’ access to the financial markets in a timely and cost-effective manner. A decline in the Companies’ credit worthiness, an unfavorable market reputation of either the Companies or their industry or general market disruptions could adversely impact financing costs and increase the overall cost of the project.
The development and construction of the CVOW Commercial Project is also dependent on the ability of certain key suppliers and contractors to timely satisfy their obligations under contracts entered into or expected to be entered into. Given the unique equipment and expertise required for this project, the Companies may not be able to remedy in a timely and cost-effective manner, if at all, any
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failure by one or more of these suppliers or contractors to timely satisfy their contractual obligations. Certain of the fixed price contracts for major offshore construction and equipment components are denominated in Euros and Danish kroner, including those which contain commodity indexing provisions linked to steel. In May 2022, Virginia Power entered into forward purchase agreements with a notional amount of approximately €3.2 billion. Accordingly, to the extent the instruments do not effectively hedge the Companies’ exposure to these currencies, including by default of the counterparty, adverse fluctuations in the applicable exchange rates would likely adversely affect the cost of the CVOW Commercial Project. Similarly, adverse fluctuations in the price of certain raw materials, including steel, would likely, to the extent not hedged by the Companies, adversely affect the overall costs incurred to develop and construct the project.
The development and construction of the CVOW Commercial Project involves the use of new turbine technology and will take place in a marine environment, which presents unique challenges and will require the use of a specialized workforce and specialized equipment. In addition, the timely installation of the turbines is dependent on the completion and availability of a Jones Act compliant vessel currently under construction.
The timeline for development and construction of the CVOW Commercial Project may also be negatively impacted by severe weather events or marine wildlife, including migration patterns of endangered and protected species, both of which are outside of the control of the Companies and their contractors. Any significant delays in the project timeline, including from any of the factors discussed above, resulting in both the delay of commencement of construction to 2024 or later combined with a delay to the in-service date to 2028 or later may impact the ability of the Companies to recover the costs of the CVOW Commercial Project.
The development, construction and commissioning of several large-scale infrastructure projects simultaneously involves significant execution risk. To achieve Dominion Energy’s commitment to net zero emissions by 2050 and comply with the requirements of the VCEA, the Companies are currently simultaneously developing or constructing several electric generation projects, including Subsequent License Renewalsubsequent license renewal projects at Surry and North Anna, the Coastal Virginia Offshore Wind projectsCVOW Commercial Project and various solar projects. Several of the Companies’ key projects are increasingly large-scale, complex and being constructed in constrained geographic areas or in unfamiliar environments such as the marine environment for the Coastal Virginia Offshore Wind projects. The advancement of the Companies’ ventures is also affected by the interventions, litigation or other activities of stakeholder and advocacy groups, some of which oppose natural gas-related and energy infrastructure projects. For example, certain stakeholder groups oppose solar farms due to the increasing quantities of land tracts required for these facilities. Given that these projects provide the foundation for the Companies’ strategic growth plan, if the Companies are unable to obtain or maintain the required regulatory and other, including PJM, approvals, develop the necessary technical expertise, allocate and coordinate sufficient resources, adhere to budgets and timelines, effectively handle public outreach efforts, including its commitment to environmental justice, or otherwise fail to successfully execute the projects, there could be an adverse impact to the Companies’ financial position, results of operations and cash flows. Failure to comply with regulatory approval conditions or an adverse ruling in any future litigation could adversely affect the Companies’ ability to execute their business plan.
The Companies are dependent on their contractors for the successful and timely completion of large-scale infrastructure projects. The construction of such projects is expected to take several years, is typically confined within a limited geographic area or difficult environments and could be subject to delays, supply chain disruption, cost overruns, inflation, labor disputes or shortages and other factors that could cause the total cost of the project to exceed the anticipated amount and adversely affect the Companies’ financial performance and/or impair the Companies’ ability to execute the business plan for the project as scheduled.
Further, an inability to obtain financing or otherwise provide liquidity for the projects on acceptable terms, including any potential adverse conditions arising from or in connection with the comprehensive business review announced in November 2022, could negatively affect the Companies’ financial condition, cash flows, the projects’ anticipated financial results and/or impair the Companies’ ability to execute the business plan for the projects as scheduled.
Operational Risks
The Companies’ financial performance and condition can be affected by changes in the weather, including the effects of global climate change. Fluctuations in weather can affect demand for the Companies’ services. For example, milder than normal weather can reduce demand for electricity and gas distribution services. In addition, severe weather or acts of nature, including hurricanes, winter storms, earthquakes, floods and other natural disasters can stress systems, disrupt operation of the Companies’ facilities and cause service outages, production delays and property damage that require incurring additional expenses. Changes in weather conditions can result in reduced water levels or changes in water temperatures that could adversely affect operations at some of the Companies’ power stations. Furthermore, the Companies’ operations could be adversely affected and their physical plant placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and, for operations located on or near coastlines, a change in sea level or sea temperatures. Due to the location of the Companies’ electric utility service territories and a number of its other facilities in the eastern portions of the states of South Carolina, North Carolina and
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Virginia which are frequently in the path of hurricanes, we experience the consequences of these weather events to a greater degree than many of our industry peers.
Hostile cyber intrusions could severely impair the Companies’ operations, lead to the disclosure of confidential information, damage the reputation of the Companies and otherwise have an adverse effect on the Companies’ business. The Companies own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run the Companies’ facilities are not completely isolated from external networks. There appears to be an increasing level of activity, sophistication and maturity of threat actors, in particular nation state actors, that wish to disrupt the U.S. bulk power system and the U.S. gas transmission or distribution system. Such parties could view the Companies’ computer systems, software or networks as attractive targets for cyber attack. For example, malware has been designed to target software that runs the nation’s critical infrastructure such as power transmission grids and gas pipelines. In addition, the Companies’ businesses require that they and their vendors collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.
A successful cyber attack through third-party or insider action on the systems that control the Companies’ electric generation, electric transmission or distribution assets could severely disrupt business operations, preventing the Companies from serving customers or collecting revenues. The breach of certain business systems could affect the Companies’ ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to the Companies’ reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data at the Companies or one of their vendors could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. If a significant breach were to occur, the reputation of the Companies also could be adversely affected. While the Companies maintain property and casualty insurance, along with other contractual provisions, that may cover certain damage caused by potential cyber incidents, all damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a significant cyber incident could materially and adversely affect the Companies’ business, financial condition and results of operations.
The Companies’ operations are subject to operational hazards, equipment failures, supply chain disruptions and personnel issues which could negatively affect the Companies. Operation of the Companies’ facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply, pipeline integrity or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost
overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, changes to the environment and performance below expected levels. The Companies’ businesses are dependent upon sophisticated information technology systems and network infrastructure, the failure of which could prevent them from accomplishing critical business functions. Because the Companies’ transmission facilities, pipelines and other facilities are interconnected with those of third parties, the operation of their facilities and pipelines could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.
Operation of the Companies’ facilities below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of the Companies’ facilities and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the Companies’ business. Unplanned outages typically increase the Companies’ operation and maintenance expenses and may reduce their revenues as a result of selling less output or may require the Companies to incur significant costs as a result of operating higher cost units or obtaining replacement output from third parties in the open market to satisfy forward energy and capacity or other contractual obligations. Moreover, if the Companies are unable to perform their contractual obligations, penalties or liability for damages could result.
In addition, there are many risks associated with the Companies’ principal operations and the transportation and storage of natural gas including nuclear accidents, fires, explosions, uncontrolled release of natural gas and other environmental hazards, pole strikes, electric contact cases, the collision of third party equipment with pipelines and avian and other wildlife impacts. Such incidents could result in loss of human life or injuries among employees, customers or the public in general, environmental pollution, damage or destruction of facilities or business interruptions and associated public or employee safety impacts, loss of revenues, increased liabilities, heightened regulatory scrutiny and reputational risk. Further, the location of natural gas pipelines and associated distribution facilities, or electric generation, transmission, substations and distribution facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks.
The Companies’ financial results can be adversely affected by various factors driving supply and demand for electricity and gas and related services. Technological advances required by federal laws mandate new levels of energy efficiency in end-use devices, including lighting, furnaces and electric heat pumps and could lead to declines in per capita energy consumption. Additionally, certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Likewise, certain regulatory and legislative bodies have introduced or are considering actions
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which could limit the use or installation of new natural gas appliances. Consumer demand for our services may also be impacted by any price increases, including those driven by factors beyond our control such as inflation or increased prices in natural gas. Further, Virginia Power’s business model is premised upon the cost efficiency of the production, transmission and distribution of large-scale centralized utility generation. However, advances in distributed generation technologies, such as solar cells, gas microturbines, battery storage and fuel cells, may make these alternative generation methods competitive with large-scale utility generation, and change how customers acquire or use ourthe Companies’ services. The widescale implementation of alternative generation methods could negatively impact the reliability of the Companies’ electric grid and/or result in significant costs to enhance the grid. Virginia Power has an exclusive franchise to serve retail electric customers in Virginia. However, Virginia’s Retail Access Statutes allow certain electric generation customers exceptions to this franchise. As market conditions change, Virginia Power’s customers may further pursue exceptions and Virginia Power’s exclusive franchise may erode.
Reduced energy demand or significantly slowed growth in demand due to customer adoption of energy efficient technology, conservation, distributed generation, regional economic conditions, or the impact of additional compliance obligations, unless substantially offset through regulatory cost allocations, could adversely impact the value of the Companies’ business activities.
The Companies may be materially adversely affected by negative publicity. publicity or the inability of Dominion Energy to meet its stated commitments. From time to time, political and public sentiment in connection with significant transactions and infrastructure projects, such as the SCANA Merger and the abandonment of the NND Project, may result in a significant amount of adverse press coverage and other adverse public statements affecting the Companies. WhileAny 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 projectProject was cancelled in July 2020 and several of the legal proceedings and governmental investigations relating to the abandonment of the NND Project have been resolved, there is a risk that lingering negative publicity may continue. Additionally, any failure by the Companies to realize voluntary targets set with respect to the reduction of GHG emissions or other long-term goals could lead to adverse press coverage and other adverse public statements affecting the Companies. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims.claims as well as adverse outcomes.
Addressing any adverse publicity, governmental scrutiny or enforcement or other legal proceedings is time consuming and expensive and, regardless of the factual basis for the assertions being made, can have a negative impact on the reputation of the Companies, on the morale and performance of their employees and on their relationships with their respective regulators, customers and commercial counterparties. It may also have a negative impact on the Companies’ ability to take timely advantage of various business and market opportunities. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have a material adverse effect on the Companies’ business, financial condition and results of operations.
Dominion Energy’s nonregulated generation business operates in a challenging market, which could adversely affect its results of operations and future growth. The success of Dominion Energy’s contracted generation business depends upon favorable market
conditions including the ability to sell power at prices sufficient to cover its operating costs. Dominion Energy operates in active wholesale markets that expose it to price volatility for electricity and nuclear fuel as well as the credit risk of counterparties. Dominion Energy attempts to manage its price risk by entering into long-term power purchase agreements with customers as well as hedging transactions, including short-term and long-term fixed price sales and purchase contracts. The failure of Dominion Energy to maintain, renew or replace its existing long-term contracts on similar terms or with counterparties with similar credit profiles could result in a loss of revenue and/or decreased earnings and cash flows for Dominion Energy.
In these wholesale markets, the spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. In many cases, the next unit of electricity supplied would be provided by generating stations that consume fossil fuels, primarily natural gas. Consequently, the open market wholesale price for electricity generally reflects the cost of natural gas plus the cost to convert the fuel to electricity. Therefore, changes in the price of natural gas generally affect the open market wholesale price of electricity. To the extent Dominion Energy does not enter into long-term power purchase agreements or otherwise effectively hedge its output, these changes in market prices could adversely affect its financial results.
Dominion Energy purchases nuclear fuel primarily under long-term contracts. Dominion Energy is exposed to nuclear fuel cost volatility for the portion of its nuclear fuel obtained through short-term contracts or on the spot market, including as a result of market supply shortages. Nuclear fuel prices can be volatile and the price that can be obtained for power produced may not change at the same rate as nuclear fuel costs, thus adversely impacting Dominion Energy’s financial results. In addition, in the event that any of the contracted generation facilities experience a forced outage, Dominion Energy may not receive the level of revenue it anticipated.
Dominion Energy conducts certain operations through partnership arrangements involving third-party investors which may limit Dominion Energy’s operational flexibility or result in an adverse impact on its financial results. Certain of Dominion
44
Energy’s operations are conducted through entities subject to partnership arrangements under which Dominion Energy has significant influence but does not control the operations of such entities or in which Dominion Energy’s control over such entities may be subject to certain rights of third-party investors. Accordingly, while Dominion Energy may have a certain level of control or influence over these entities, it may not have unilateral, or any, control over the day-to-day operations of these entities or over decisions that may have a material financial impact on the partnership participants, including Dominion Energy. In each case such partnership arrangements operate in accordance with their respective governance documents, and Dominion Energy is dependent upon third parties satisfying their respective obligations, including, as applicable, funding of their required share of capital expenditures. Such third-party investors have their own interests and objectives which may differ from those of Dominion Energy and, accordingly, disputes may arise amongst the owners of such partnership arrangements that may result in delays, litigation or operational impasses.
For example, Dominion Energy has a noncontrolling 50% interest in Cove Point following the sale of a 25% controlling interest to BHE in November 2020. This controlling interest allows BHE to make decisions affecting Cove Point’s ability to retain its long-term contracts. Cove Point is a party to certain contracts that allow a regulated service provider and a customer to mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated, cost-based recourse rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue as a result of these “negotiated rate” contracts could decrease Cove Point’s earnings and cash flows. The inability to maintain or renew such contracts on favorable terms may have a material impact to Dominion Energy’s results of operations, financial position or cash flows. Dominion Energy is also dependent upon BHE for managing counterparty credit risk relating to Cove Point’s terminal services agreements for its liquefied natural gas export/liquefaction facility. While the counterparties’ obligations are supported by parental guarantees and letters of credit, there is no assurance that such credit support would be sufficient to satisfy the obligations in the event of a counterparty default. In addition, if a controversy arises under either terminal services agreement resulting in a judgment in Cove Point’s favor, Cove Point may need to seek to enforce a final U.S. court judgment in a foreign tribunal, which could involve a lengthy process. Accordingly, there is no assurance that BHE may pursue remedies in the event of default in the same manner as Dominion Energy would if it had unilateral control over such decisions.
In addition, for certain contracted generation solar facilities in which Dominion Energy maintains a controlling interest, third-party investors hold certain protective rights. These rights may impact the ability of Dominion Energy to make certain decisions, such as the retention or distribution of available cash, significant acquisitions or dispositions of assets by those entities or the ability to sell or transfer its ownership interests.
Hostile cyber intrusions could severely impair the Companies’ operations, lead to the disclosure of confidential information, damage the reputation of the Companies and otherwise have an adverse effect on the Companies’ business. The Companies own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run the Companies’ facilities are not completely isolated from external networks. There appears to be an increasing level of activity, sophistication and maturity of threat actors, in particular nation state actors, that wish to disrupt the U.S. bulk power system and the U.S. gas transmission or distribution system. Such parties could view the Companies’ computer systems,
software or networks as attractive targets for cyber attack. For example, malware has been designed to target software that runs the nation’s critical infrastructure such as power transmission grids and gas pipelines. In addition, the Companies’ businesses require that they and their vendors collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.
A successful cyber attack on the systems that control the Companies’ electric generation, electric transmission or distribution assets could severely disrupt business operations, preventing the Companies from serving customers or collecting revenues. The breach of certain business systems could affect the Companies’ ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to the Companies’ reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data at the Companies or one of their vendors could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. If a significant breach were to occur, the reputation of the Companies also could be adversely affected. While the Companies maintain property and casualty insurance, along with other contractual provisions, that may cover certain damage caused by potential cyber incidents, all damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a significant cyber incident could materially and adversely affect the Companies’ business, financial condition and results of operations.
War, acts and threats of terrorism, intentional acts and other significant events could adversely affect the Companies’ operations. The Companies cannot predict the impact that any future terrorist attacks or retaliatory military or other action may have on the energy industry in general or on the Companies’ businesses in particular. Any such future attacks or retaliatory action may adversely affect the Companies’ operations in a variety of ways, including by disrupting the power, fuel and other markets in which the Companies operate or requiring the implementation of additional, more costly security guidelines and measures. The Companies’ infrastructure facilities, including nuclear facilities and projects under construction, could be direct targets or indirect casualties of an act of terror or other physical attack. Any physical compromise of the Companies’ facilities could adversely affect the Companies’ ability to generate, purchase, transmit or distribute electricity, distribute natural gas or otherwise operate their respective facilities in the most efficient manner or at all. For example, in December 2022 electric utilities in North Carolina and Washington experienced physical attacks on substations with the damage causing power outages. In addition, the amount and scope of insurance coverage maintained against losses resulting from any such attack may not be sufficient to cover such losses or otherwise adequately compensate for any business disruptions that could result.
Instability in financial markets as a result of terrorism, war, intentional acts, pandemic, credit crises, recession or other factors could result in a significant decline in the U.S. economy and/or increase the cost or limit the availability of insurance or adversely impact the Companies’ ability to access capital on acceptable terms.
Failure to attract and retain key executive officers and an appropriately qualified workforce could have an adverse effect on the Companies’ operations. The Companies’ business strategy is dependent on their ability to recruit, retain and motivate employees. The Companies’ key executive officers are the Executive Chairman, CEO, CFO, COO and presidents and those responsible for financial, operational, legal, regulatory, accounting, tax, information technology and accountingcybersecurity 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.
45
Nuclear Generation Risks
The Companies have substantial ownership interests in and operate nuclear generating units; as a result, each may incur substantial costs and liabilities. The Companies’ nuclear facilities are subject to operational, environmental, health and financial risks such as the on-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, limitations on the amounts and types of insurance available, potential operational liabilities and extended outages, the costs of replacement power, the costs of maintenance and the costs of securing the facilities against possible terrorist attacks. The Companies maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that future decommissioning costs could exceed amounts in the decommissioning trusts and/or damages could exceed the amount of insurance coverage. If the Companies’ decommissioning trust funds are insufficient, and they are
not allowed to recover the additional costs incurred through insurance or regulatory mechanisms, their results of operations could be negatively impacted.
The Companies’ nuclear facilities are also subject to complex government regulation which could negatively impact their results of operations. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit, or take some combination of these actions, depending on its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could require the Companies to make substantial expenditures at their nuclear plants. In addition, although the Companies have no reason to anticipate a serious nuclear incident at their plants, if an incident did occur, it could materially and adversely affect their results of operations and/or financial condition. A major incident at a nuclear facility anywhere in the world, such as the nuclear events in Japan in 2011, could cause the NRC to adopt increased safety regulations or otherwise limit or restrict the operation or licensing of domestic nuclear units.
Financial, Economic and Market Risks
Changing rating agency requirements could negatively affect the Companies’ growth and business strategy. In order to maintain appropriate credit ratings to obtain needed credit at a reasonable cost in light of existing or future rating agency requirements, the Companies may find it necessary to take steps or change their business plans in ways that may adversely affect their growth and earnings. A reduction in the Companies’ credit ratings could result in an increase in borrowing costs, loss of access to certain markets, or both, thus adversely affecting operating results and could require the Companies to post additional collateral in connection with some of its price risk management activities.
An inability to access financial markets and, in the case of Dominion Energy, obtain cash from subsidiaries could adversely affect the execution of the Companies’ business plans. The Companies rely on access to short-term money markets and longer-term capital markets as significant sources of funding and liquidity for business plans with increasing capital expenditure needs, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities. Deterioration in the Companies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or declines in market reputation either for the Companies or their industry in general, or general financial market disruptions outside of the Companies’ control could increase their cost of borrowing or restrict their ability to access one or more financial markets. In addition, any potential adverse conditions arising from or in connection with the comprehensive business review announced in November 2022 could affect the availability and/or cost of capital. Market disruptions could stem from general market disruption due to general credit market or political events, the planned phase out of LIBOR by the end of 2023 or the reform or replacement of other benchmark rates, the failure of financial institutions on which the Companies rely or the bankruptcy of an unrelated company. Increased costs and restrictions on the Companies’ ability to access financial markets may be severe enough to affect their ability to execute their business plans as scheduled.
Dominion Energy is a holding company that conducts all of its operations through its subsidiaries. Accordingly, Dominion Energy’s ability to execute its business plan is further subject to the earnings and cash flows of its subsidiaries and the ability of its subsidiaries to pay dividends or advance or repay funds to it, which may, from time to time, be subject to certain contractual restrictions or restrictions imposed by regulators.
Market performance, interest rates and other changes may decrease the value of the Companies’ decommissioning trust funds and Dominion Energy’s benefit plan assets or increase Dominion Energy’s liabilities, which could then require significant additional funding. The performance of the capital markets affects the value of the assets that are held in trusts to satisfy future obligations to decommission the Companies’ nuclear plants and under Dominion Energy’s pension and other postretirement benefit plans. The Companies have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuation and will yield uncertain returns, which may fall below expected return rates.
With respect to decommissioning trust funds, a decline in the market value of these assets may increase the funding requirements of the obligations to decommission the Companies’ nuclear plants or require additional NRC-approved funding assurance.
46
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 and financial marketexchange rate risks. In addition, Dominion Energy purchases and sells commodity-based contracts for hedging purposes.
The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The CEA, as amended by Title VII of the Dodd-Frank Act, requires certain over-the-counter derivatives, or swaps, to be cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, may elect the end-user exception to the CEA’s clearing requirements. The Companies have elected to exempt their swaps from the CEA’s clearing requirements. If, as a result of changes to the rulemaking process, the Companies’ derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs due to decreased market liquidity or increased margin payments. In addition, the Companies’ swap dealer counterparties may attempt to pass-through additional trading costs in connection with changes to or the elimination of rulemaking that implements Title VII of the Dodd-Frank Act.
Future impairments of goodwill or other intangible assets or long-lived assets may have a material adverse effect on the Companies’ results. results of operations. Goodwill is evaluated for impairment annually or more frequently if an event or circumstance occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Other intangible assets and long-lived assets are evaluated for impairment on an annual basis or more frequently whenever events or circumstances indicate that an asset’s carrying value may not be recoverable. If Dominion Energy’s goodwill including the goodwill recorded in connection with the SCANA Combination, or the Companies’ other intangible assets or long-lived assets are in the future determined to be impaired, the applicable Companyregistrant 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.registrant's results of operations. For example, in the fourth quarter of 2022, Dominion Energy determined that its nonregulated solar generation assets within Contracted Assets were impaired, resulting in a $1.1 billion after-tax charge.
Exposure to counterparty performance may adversely affect the Companies’ financial results of operations. The Companies are exposed to credit risks of their counterparties and the risk that one or more counterparties may fail or delay the performance of their contractual obligations, including but not limited to payment for services. Some of Dominion Energy’s operations are conducted through partnership arrangements, as noted above. Counterparties could fail or delay the performance of their contractual obligations for a number of reasons, including the effect of regulations on their operations. Defaults or failure to perform by customers, suppliers, contractors, joint venture partners, financial institutions or other third parties may adversely affect the Companies’ financial results.
Public health crises and epidemics or pandemics, such as COVID-19, could adversely affect the Companies’ business, results of operations, financial condition, liquidity and/or cash flows. The effects of the continued outbreak of the COVID-19 pandemic and related government responses could include extended disruptions to supply chains and capital markets, reduced labor availability and productivity and a prolonged reduction in economic activity. The effects could also have a variety of adverse impacts on the Companies, including reduced demand for energy, particularly from commercial and industrial customers, impairment of goodwill or long-lived assets and diminished ability of the Companies to access funds from financial institutions and capital markets. There remains uncertainty regarding the extent and duration of measures to try to contain the virus, such as travel bans and restrictions, quarantines, shelter-in-place orders and shutdowns. Such restrictions may cause operational interruptions and delays in construction projects, which, in the case of renewable energy projects, could delay the expected in-service dates of these projects and financial statement impact of the investment tax credits associated with these projects. For the duration of the outbreak of COVID-19, voluntary suspension, or potential legislative or government action, such as legislation enacted in Virginia in November 2020, may limit the Companies’ ability to collect on overdue accounts or disconnect services for non-payment, which may cause a decrease in the Companies’ results of operations and cash flows.
47
Item 1B. Unresolved Staff Comments
None.
48
Item 2. Properties
As of December 31, 2020,2022, Dominion Energy owned its principal executive office in Richmond, Virginia and five other corporate offices. Dominion Energy also leases corporate offices in Richmond, Virginia and other cities in which its subsidiaries operate. Virginia Power shares Dominion Energy’s principal executive office in Richmond, Virginia. In addition, Virginia Power leases certain buildings and equipment.
Dominion Energy’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described below by operating segment.
Certain of Virginia Power’s properties are subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. There were no bonds outstanding as of December 31, 2020;2022; however, by leaving the indenture open, Virginia Power retains the flexibility to issue mortgage bonds in the future. Certain of Dominion Energy’s nonregulated generation facilities are also subject to liens. Additionally, DESC’s bond indenture, which secures its First Mortgage Bonds, constitutes a direct mortgage lien on substantially all of its electric utility property.
DOMINION ENERGY VIRGINIA
Virginia Power has approximately 6,700 miles of electric transmission lines of 69 kV or more located in North Carolina, Virginia and West Virginia. Portions of Virginia Power’s electric transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, any surplus capacity that may exist in these lines. While Virginia Power owns and maintains its electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance and exchange of capacity and energy for such facilities.
In addition, Virginia Power’s electric distribution network includes approximately 58,90059,700 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, Virginia Power owns 473 substations.482 substations and 16 MW of battery storage. Dominion Energy also owns various solar facilities, primarily at schools in Virginia, with an aggregate generation capacity of 921 MW.
49
The following tables list Virginia Power’s generating units and capability as of December 31, 2020.2022.
VIRGINIA POWER UTILITY GENERATION
Plant |
| Location |
| Net Summer Capability (MW) |
|
| Percentage Net Summer Capability |
|
|
| Location |
| Net Summer |
|
| Percentage |
|
| ||||
Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Greensville County (CC) |
| Greensville County, VA |
|
| 1,629 |
|
|
|
|
|
|
| Greensville County, VA |
|
| 1,629 |
|
|
|
|
| |
Brunswick County (CC) |
| Brunswick County, VA |
|
| 1,376 |
|
|
|
|
|
|
| Brunswick County, VA |
|
| 1,376 |
|
|
|
|
| |
Warren County (CC) |
| Warren County, VA |
|
| 1,370 |
|
|
|
|
|
|
| Warren County, VA |
|
| 1,349 |
|
|
|
|
| |
Ladysmith (CT) |
| Ladysmith, VA |
|
| 783 |
|
|
|
|
|
|
| Ladysmith, VA |
|
| 783 |
|
|
|
|
| |
Bear Garden (CC) |
| Buckingham County, VA |
|
| 622 |
|
|
|
|
|
|
| Buckingham County, VA |
|
| 622 |
|
|
|
|
| |
Remington (CT) |
| Remington, VA |
|
| 622 |
|
|
|
|
|
|
| Remington, VA |
|
| 622 |
|
|
|
|
| |
Possum Point (CC) |
| Dumfries, VA |
|
| 573 |
|
|
|
|
|
|
| Dumfries, VA |
|
| 573 |
|
|
|
|
| |
Chesterfield (CC) |
| Chester, VA |
|
| 392 |
|
|
|
|
|
|
| Chester, VA |
|
| 392 |
|
|
|
|
| |
Elizabeth River (CT) |
| Chesapeake, VA |
|
| 330 |
|
|
|
|
|
|
| Chesapeake, VA |
|
| 330 |
|
|
|
| ||
Gordonsville Energy (CC) |
| Gordonsville, VA |
|
| 218 |
|
|
|
|
|
|
| Gordonsville, VA |
|
| 218 |
|
|
|
| ||
Gravel Neck (CT) |
| Surry, VA |
|
| 170 |
|
|
|
|
|
|
| Surry, VA |
|
| 170 |
|
|
|
| ||
Darbytown (CT) |
| Richmond, VA |
|
| 168 |
|
|
|
|
|
|
| Richmond, VA |
|
| 168 |
|
|
|
|
| |
Total Gas |
|
|
|
| 8,253 |
|
|
| 41 |
| % |
|
| 8,232 |
|
|
| 41 |
| % | ||
Coal |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Mt. Storm |
| Mt. Storm, WV |
|
| 1,621 |
|
|
|
|
|
|
| Mt. Storm, WV |
|
| 1,617 |
|
|
|
| ||
Chesterfield(1) |
| Chester, VA |
|
| 1,014 |
|
|
|
|
|
|
| Chester, VA |
|
| 1,014 |
|
|
|
| ||
Virginia City Hybrid Energy Center |
| Wise County, VA |
|
| 610 |
|
|
|
|
|
|
| Wise County, VA |
|
| 610 |
|
|
|
| ||
Clover |
| Clover, VA |
|
| 439 |
| (2) |
|
|
|
|
| Clover, VA |
|
| 439 |
| (2) |
|
|
| |
Total Coal |
|
|
|
| 3,684 |
|
|
| 18 |
|
|
|
| 3,680 |
|
|
| 18 |
|
| ||
Nuclear |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Surry |
| Surry, VA |
|
| 1,676 |
|
|
|
|
|
|
| Surry, VA |
|
| 1,676 |
|
|
|
| ||
North Anna |
| Mineral, VA |
|
| 1,672 |
| (3) |
|
|
|
|
| Mineral, VA |
|
| 1,672 |
| (3) |
|
|
| |
Total Nuclear |
|
|
|
| 3,348 |
|
|
| 17 |
|
|
|
| 3,348 |
|
|
| 16 |
|
| ||
Hydro |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Bath County |
| Warm Springs, VA |
|
| 1,808 |
| (4) |
|
|
|
|
| Warm Springs, VA |
|
| 1,808 |
| (4) |
|
|
| |
Gaston |
| Roanoke Rapids, NC |
|
| 220 |
|
|
|
|
|
|
| Roanoke Rapids, NC |
|
| 220 |
|
|
|
|
| |
Roanoke Rapids |
| Roanoke Rapids, NC |
|
| 95 |
|
|
|
|
|
|
| Roanoke Rapids, NC |
|
| 95 |
|
|
|
|
| |
Other |
|
|
|
| 1 |
|
|
|
|
|
|
|
|
|
| 1 |
|
|
|
|
| |
Total Hydro |
|
|
|
| 2,124 |
|
|
| 10 |
|
|
|
| 2,124 |
|
|
| 10 |
|
| ||
Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Yorktown(1) |
| Yorktown, VA |
| 790 |
|
|
|
|
|
|
| Yorktown, VA |
|
| 790 |
|
|
|
| |||
Gravel Neck (CT) |
| Surry, VA |
| 198 |
|
|
|
|
|
|
| Surry, VA |
|
| 198 |
|
|
|
| |||
Darbytown (CT) |
| Richmond, VA |
| 168 |
|
|
|
|
|
|
| Richmond, VA |
|
| 168 |
|
|
|
| |||
Rosemary (CC) |
| Roanoke Rapids, NC |
| 160 |
|
|
|
|
|
|
| Roanoke Rapids, NC |
|
| 160 |
|
|
|
| |||
Possum Point (CT) |
| Dumfries, VA |
| 72 |
|
|
|
|
|
|
| Dumfries, VA |
|
| 72 |
|
|
|
| |||
Low Moor (CT) |
| Covington, VA |
| 48 |
|
|
|
|
|
|
| Covington, VA |
|
| 48 |
|
|
|
| |||
Northern Neck (CT) |
| Lively, VA |
| 47 |
|
|
|
|
|
|
| Lively, VA |
|
| 47 |
|
|
|
| |||
Chesapeake (CT) |
| Chesapeake, VA |
| 39 |
|
|
|
|
|
|
| Chesapeake, VA |
|
| 39 |
|
|
|
|
| ||
Total Oil |
|
|
|
| 1,522 |
|
|
| 7 |
|
|
|
| 1,522 |
|
|
| 7 |
|
| ||
Solar(5) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Colonial Trail West |
| Surry County, VA |
|
| 142 |
|
|
|
|
|
|
| Surry County, VA |
|
| 142 |
|
|
|
|
| |
Sadler Solar |
| Emporia, VA |
|
| 100 |
|
|
|
|
| ||||||||||||
Spring Grove |
| Surry County, VA |
|
| 98 |
|
|
|
|
|
|
| Surry County, VA |
|
| 98 |
|
|
|
|
| |
Grassfield |
| Chesapeake, VA |
|
| 20 |
|
|
|
|
| ||||||||||||
Whitehouse Solar |
| Louisa County, VA |
|
| 20 |
|
|
|
|
|
|
| Louisa County, VA |
|
| 20 |
|
|
|
|
| |
Woodland Solar |
| Isle of Wight County, VA |
|
| 19 |
|
|
|
|
|
|
| Isle of Wight County, VA |
|
| 19 |
|
|
|
|
| |
Scott Solar |
| Powhatan, VA |
|
| 17 |
|
|
|
|
|
|
| Powhatan, VA |
|
| 17 |
|
|
|
|
| |
Total Solar |
|
|
|
| 296 |
|
|
| 1 |
|
|
|
| 416 |
|
|
| 2 |
|
| ||
Biomass |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Altavista(6) |
| Altavista, VA |
|
| 51 |
|
|
|
|
|
|
| Altavista, VA |
|
| 51 |
|
|
|
|
| |
Polyester(6) |
| Hopewell, VA |
|
| 51 |
|
|
|
|
|
|
| Hopewell, VA |
|
| 51 |
|
|
|
|
| |
Southampton(6) |
| Southampton, VA |
|
| 51 |
|
|
|
|
|
|
| Southampton, VA |
|
| 51 |
|
|
|
|
| |
Total Biomass |
|
|
|
| 153 |
|
|
| 1 |
|
|
|
| 153 |
|
|
| 1 |
|
| ||
Wind |
|
|
|
|
|
|
| |||||||||||||||
CVOW Pilot Project |
| Virginia Beach, VA |
|
| 12 |
|
|
| — |
|
| |||||||||||
Various |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Mt. Storm (CT) |
| Mt. Storm, WV |
|
| 11 |
|
|
| — |
|
|
| Mt. Storm, WV |
|
| 11 |
|
|
| — |
|
|
|
|
|
|
| 19,391 |
|
|
|
|
|
|
|
| 19,498 |
|
|
|
|
| |||
Power Purchase Agreements |
|
|
|
| 917 |
|
|
| 5 |
|
|
|
| 1,106 |
|
|
| 5 |
|
| ||
Total Utility Generation |
|
|
|
| 20,308 |
|
|
| 100 |
| % |
|
| 20,604 |
|
|
| 100 |
| % |
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
50
VIRGINIA POWER NON-JURISDICTIONAL GENERATION
Plant | Location | Net Summer | |||||||
Solar(1) | |||||||||
Fort Powhatan | Disputanta, VA |
|
|
|
| ||||
| Chatham, VA |
| 120 |
| |||||
| Louisa, VA |
|
|
|
| ||||
| Garysburg, NC |
|
| 80 |
| ||||
| Chase City, VA |
|
|
|
| ||||
| Pleasant Hill, NC |
|
| 75 |
| ||||
| Halifax County, NC |
|
|
|
| ||||
| Chesapeake, VA |
|
|
|
| ||||
| Emporia, VA |
|
|
|
| ||||
| Gloucester County, VA |
|
| 20 |
| ||||
| Westmoreland County, VA |
|
|
|
| ||||
| Pasquotank County, NC |
|
|
|
| ||||
| Fauquier County, VA |
|
|
|
| ||||
| James City County, VA |
| 20 | ||||||
Oceana | Virginia Beach, VA |
| 18 |
| |||||
Hollyfield | Manquin, VA | 17 | |||||||
Puller | Topping, VA | 15 | |||||||
Total Non-Jurisdictional Generation | 948 |
|
|
|
GAS DISTRIBUTION
Gas Distribution’s network is located in Ohio, West Virginia, North Carolina, Utah, southwestern Wyoming and southeastern Idaho. This network includes approximately 75,50074,400 miles of distribution mains and related service facilities which are supported by approximately 5,7003,600 miles of transmission, gathering and storage pipeline. The right-of-way grants for many natural gas pipelines have been obtained from the actual owners of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many natural gas pipelines are on publicly-owned property, where company rights and actions are determined on a case-by-case basis, with results that range from reimbursed relocation to revocation of permission to operate.
East Ohio’s integrated underground storage facilities have more than 60 bcf of working gas capacity to serve base and peak demand. PSNC owns one LNG facility that stores the liquefied equivalent of 1.0 bcf of natural gas, can regasify approximately 10% of its storage capacity per day and can liquefy less than 1% of its storage capacity per day. Questar Gas also owns one LNG facility that stores the liquified equivalent of 1.2 bcf of natural gas, can regasify approximately 12% of its storage capacity per day and can liquefy less than 1% of its storage capacity per day.
DOMINION ENERGY SOUTH CAROLINA
DESC has approximately 3,8003,900 miles and 26,70018,800 miles of electric transmission and distribution lines, respectively, exclusive of service level lines, in South Carolina. The grants for most of DESC’s electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying property titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked. In addition, DESC owns 442459 substations.
DESC’s natural gas system includes approximately 18,70019,100 miles of distribution mains and related service facilities, which are supported by approximately 500400 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.
51
The following table lists DESC’s generating units and capability as of December 31, 2020.2022.
Plant |
| Location |
| Net Summer Capability (MW) |
|
| Percentage Net Summer Capability |
|
|
| Location |
| Net Summer |
|
| Percentage |
|
| ||||
Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Jasper (CC) (1) |
| Hardeeville, SC |
|
| 852 |
|
|
|
|
|
|
| Hardeeville, SC |
|
| 903 |
|
|
|
|
| |
Columbia Energy Center (CC) (1) |
| Gaston, SC |
|
| 519 |
|
|
|
|
|
|
| Gaston, SC |
|
| 519 |
|
|
|
|
| |
Urquhart (CC) (1) |
| Beech Island, SC |
|
| 458 |
|
|
|
|
|
|
| Beech Island, SC |
|
| 458 |
|
|
|
|
| |
McMeekin |
| Irmo, SC |
|
| 250 |
|
|
|
|
|
|
| Irmo, SC |
|
| 250 |
|
|
|
|
| |
Hagood (CT) (1) |
| Charleston, SC |
|
| 126 |
|
|
|
|
|
|
| Charleston, SC |
|
| 126 |
|
|
|
|
| |
Urquhart Unit 3 |
| Beech Island, SC |
|
| 95 |
|
|
|
|
|
|
| Beech Island, SC |
|
| 95 |
|
|
|
| ||
Urquhart (CT) |
| Beech Island, SC |
|
| 87 |
|
|
|
|
|
| |||||||||||
Parr (CT) (1) |
| Jenkinsville, SC |
|
| 60 |
|
|
|
|
|
| |||||||||||
Coit (CT) (1) |
| Columbia, SC |
|
| 26 |
|
|
|
|
|
| |||||||||||
Williams (CT) (1) |
| Goose Creek, SC |
|
| 20 |
|
|
|
|
|
| |||||||||||
Urquhart (CT) (1) |
| Beech Island, SC |
|
| 87 |
|
|
|
| |||||||||||||
Parr (CT) (1)(2) |
| Jenkinsville, SC |
|
| 47 |
|
|
|
| |||||||||||||
Coit (CT) (1)(2) |
| Columbia, SC |
|
| 26 |
|
|
|
|
| ||||||||||||
Total Gas |
|
|
|
| 2,493 |
|
|
| 41 |
| % |
|
| 2,511 |
|
|
| 38 |
| % | ||
Coal |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Wateree |
| Eastover, SC |
|
| 684 |
|
|
|
| |||||||||||||
Williams |
| Goose Creek, SC |
|
| 605 |
|
|
|
|
|
|
| Goose Creek, SC |
|
| 605 |
|
|
|
| ||
Cope (3) |
| Cope, SC |
|
| 415 |
|
|
|
|
|
|
| Cope, SC |
|
| 415 |
|
|
|
|
| |
Wateree |
| Eastover, SC |
|
| 342 |
|
|
|
|
|
| |||||||||||
Total Coal |
|
|
|
| 1,362 |
|
|
| 22 |
|
|
|
| 1,704 |
|
|
| 26 |
|
| ||
Hydro |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Fairfield |
| Jenkinsville, SC |
|
| 576 |
|
|
|
|
|
|
| Jenkinsville, SC |
|
| 576 |
|
|
|
| ||
Saluda |
| Irmo, SC |
|
| 190 |
|
|
|
|
|
|
| Irmo, SC |
|
| 198 |
|
|
|
| ||
Other |
| Various |
|
| 18 |
|
|
|
|
|
|
| Various |
|
| 18 |
|
|
|
|
| |
Total Hydro |
|
|
|
| 784 |
|
|
| 13 |
|
|
|
| 792 |
|
|
| 12 |
|
| ||
Nuclear |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Summer |
| Jenkinsville, SC |
|
| 652 |
| (4) |
| 10 |
|
|
| Jenkinsville, SC |
|
| 651 |
| (4) |
| 10 |
|
|
|
|
|
|
| 5,291 |
|
|
|
|
|
|
|
| 5,658 |
|
|
|
|
| |||
Power Purchase Agreements |
|
|
|
| 846 |
| (5) |
| 14 |
|
|
|
| 973 |
| (5) |
| 14 |
|
| ||
Total Utility Generation |
|
|
|
| 6,137 |
|
|
| 100 |
| % |
|
| 6,631 |
|
|
| 100 |
| % |
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1) Capable of burning fuel oil as a secondary source. (2) Expected to be retired by the end of 2025. (3) Capable of burning natural gas as a secondary source. (4) Excludes 33.3% undivided interest owned by Santee Cooper. (5) Includes 189 MW from agreements with certain solar facilities within Contracted Assets.
|
|
|
|
|
|
|
|
|
|
CONTRACTED ASSETS
Contracted Assets includes Dominion Energy’s 50% noncontrolling interest in Cove Point. The Cove Point LNG Facility has an operational peak regasification daily send-out capacity of approximately 1.8 million Dths and an aggregate LNG storage capacity of approximately 14.6 bcfe. In addition, Cove Point has a small liquefier that has the potential to create approximately 15,000 Dths/day. The Liquefaction Facility consists of one LNG train with a nameplate outlet capacity of 5.25 Mtpa. Cove Point has authorization from the DOE to export up to 0.77 bcfe/day (approximately 5.75 Mtpa) should the Liquefaction Facility perform better than expected. In addition, Cove Point operates a 136-mile natural gas pipeline that connects the Cove Point LNG Facility to interstate natural gas pipelines.
52
The following table lists Contracted Assets’ generating units and capability as of December 31, 2020.2022.
Plant |
| Location |
| Net Summer |
|
| Percentage |
|
| ||
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 |
|
|
|
|
| |
Blackville |
| Blackville, SC |
|
| 7 |
|
|
|
|
| |
Denmark |
| Denmark, SC |
|
| 6 |
|
|
|
|
| |
Other |
| Various |
|
| 35 |
| (3) |
|
|
| |
Total Solar |
|
|
|
| 1,002 |
|
|
| 33 |
|
|
Total Nonregulated Generation |
|
|
|
| 3,003 |
|
|
| 100 |
| % |
Plant |
| Location |
| Net Summer Capability (MW) |
|
| Percentage Net Summer Capability |
|
| ||
Nuclear |
|
|
|
|
|
|
|
|
|
|
|
Millstone |
| Waterford, CT |
|
| 2,001 |
| (1) |
|
|
|
|
Total Nuclear |
|
|
|
| 2,001 |
|
|
| 58 |
| % |
Solar(2) |
|
|
|
|
|
|
|
|
|
|
|
Escalante I, II and III |
| Beaver County, UT |
|
| 120 |
| (3) |
|
|
|
|
Amazon Solar Farm Virginia – Southampton |
| Newsoms, VA |
|
| 100 |
| (4) |
|
|
|
|
Hardin I |
| Hardin County, OH |
|
| 97 |
|
|
|
|
|
|
Amazon Solar Farm Virginia – Accomack |
| Oak Hall, VA |
|
| 80 |
| (4) |
|
|
|
|
Greensville |
| Greensville County, VA |
|
| 80 |
|
|
|
|
|
|
Innovative Solar 37 |
| Morven, NC |
|
| 79 |
| (4) |
|
|
|
|
Wilkinson |
| Pantego, NC |
|
| 74 |
|
|
|
|
|
|
Seabrook |
| Beaufort County, SC |
|
| 73 |
|
|
|
|
|
|
Moffett Solar 1 |
| Ridgeland, SC |
|
| 71 |
| (4) |
|
|
|
|
Granite Mountain East and West |
| Iron County, UT |
|
| 65 |
| (3) |
|
|
|
|
Summit Farms Solar |
| Moyock, NC |
|
| 60 |
| (4) |
|
|
|
|
Enterprise |
| Iron County, UT |
|
| 40 |
| (3) |
|
|
|
|
Iron Springs |
| Iron County, UT |
|
| 40 |
| (3) |
|
|
|
|
Pavant Solar |
| Holden, UT |
|
| 34 |
| (5) |
|
|
|
|
Camelot Solar |
| Mojave, CA |
|
| 30 |
| (5) |
|
|
|
|
Midway II |
| Calipatria, CA |
|
| 30 |
| (4) |
|
|
|
|
Indy I, II and III |
| Indianapolis, IN |
|
| 20 |
| (5) |
|
|
|
|
Amazon Solar Farm Virginia – Buckingham |
| Cumberland, VA |
|
| 20 |
| (4) |
|
|
|
|
Amazon Solar Farm Virginia – Correctional |
| Barhamsville, VA |
|
| 20 |
| (4) |
|
|
|
|
Hecate Cherrydale |
| Cape Charles, VA |
|
| 20 |
| (4) |
|
|
|
|
Amazon Solar Farm Virginia – Sussex Drive |
| Stoney Creek, VA |
|
| 20 |
| (4) |
|
|
|
|
Amazon Solar Farm Virginia – Scott II |
| Powhatan, VA |
|
| 20 |
| (4) |
|
|
|
|
Cottonwood Solar |
| Kings and Kern Counties, CA |
|
| 16 |
| (5) |
|
|
|
|
Myrtle |
| Suffolk, VA |
|
| 15 |
|
|
|
|
|
|
Adams East Solar |
| Tranquility, CA |
|
| 13 |
| (5) |
|
|
|
|
Alamo Solar |
| San Bernardino, CA |
|
| 13 |
| (5) |
|
|
|
|
CID Solar |
| Corcoran, CA |
|
| 13 |
| (5) |
|
|
|
|
Imperial Valley Solar |
| Imperial County, CA |
|
| 13 |
| (5) |
|
|
|
|
Kansas Solar |
| Lenmore, CA |
|
| 13 |
| (5) |
|
|
|
|
Kent South Solar |
| Lenmore, CA |
|
| 13 |
| (5) |
|
|
|
|
Maricopa West Solar |
| Kern County, CA |
|
| 13 |
| (5) |
|
|
|
|
Old River One Solar |
| Bakersfield, CA |
|
| 13 |
| (5) |
|
|
|
|
Richland Solar |
| Jeffersonville, GA |
|
| 13 |
| (5) |
|
|
|
|
West Antelope Solar |
| Lancaster, CA |
|
| 13 |
| (5) |
|
|
|
|
Catalina 2 Solar |
| Kern County, CA |
|
| 12 |
| (5) |
|
|
|
|
Mulberry Solar |
| Selmer, TN |
|
| 11 |
| (5) |
|
|
|
|
Selmer Solar |
| Selmer, TN |
|
| 11 |
| (5) |
|
|
|
|
Columbia 2 Solar |
| Mojave, CA |
|
| 10 |
| (5) |
|
|
|
|
Hecate Energy Clarke County |
| White Post, VA |
|
| 10 |
| (4) |
|
|
|
|
Ridgeland Solar Farm I |
| Ridgeland, SC |
|
| 10 |
| (4) |
|
|
|
|
Other |
| Various |
|
| 56 |
| (4) (5) |
|
|
|
|
Total Solar |
|
|
|
| 1,474 |
|
|
| 42 |
|
|
Total Nonregulated Generation |
|
|
|
| 3,475 |
|
|
| 100 |
| % |
|
|
|
|
|
|
|
|
|
|
53
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.
54
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) | |
|
| |
| 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. | |
Edward H. Baine (49) | 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 (58) | 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 | |
|
| |
Michele L. Cardiff (55) | Senior Vice President, Controller and Chief Accounting Officer from October 2020 to present; Vice President, Controller and CAO from April 2014 to September 2020. | |
W. Keller Kissam (56) | 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 COO of DESC from January 2018 to December | |
Diane Leopold (56) | ||
| 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 | |
Steven D. Ridge (42) | Senior Vice President and | |
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| |
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2019. | |
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Daniel G. Stoddard | 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. |
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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 12, 2021,15, 2023, there were approximately 130,000122,016 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 |
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| Average |
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| Total Number |
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| Maximum Number (or | |||
10/1/22-10/31/22 |
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| 74,869 |
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| $ | 69.11 |
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| — |
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| $ 0.92 billion |
11/1/22-11/30/22 |
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| 1,014 |
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| 69.72 |
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| — |
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| 0.92 billion |
12/1/22-12/31/22 |
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| 556 |
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| 60.37 |
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| — |
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| 0.92 billion |
Total |
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| 76,439 |
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| $ | 69.05 |
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| — |
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| $ 0.92 billion |
Period |
| Total Number of Shares (or Units) Purchased |
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| Average Price Paid per Share (or Unit)(4) |
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| Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs |
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| Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs(5) | ||||||||||||
10/1/20-10/31/20 |
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| 52,079 |
| (1) | $ | 78.59 |
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| — |
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| $ 0.62 billion | |||||||||
11/1/20-11/30/20 |
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| 3,049,613 |
| (2) |
| 80.36 |
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| 3,029,827 |
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| 1.48 billion | |||||||||
12/1/20-12/31/20 |
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| 7,387,403 |
| (3) |
| 76.22 |
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| 7,387,403 |
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| 0.92 billion | |||||||||
Total |
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| 10,489,095 |
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| $ | 77.44 |
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| 10,417,230 |
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| $ 0.92 billion |
(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.
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VIRGINIA POWER
There is no established public trading market for Virginia Power’s common stock, all of which is owned by Dominion Energy. Virginia Power intends tomay pay quarterly cash dividends in 20212023 but is neither required to nor restricted, except as described in Note 21 to the Consolidated Financial Statements, from making such payments.
Item 6. Selected Financial Data[Reserved]
The following table should be read in conjunction with the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data.
Dominion Energy’s Consolidated Financial Statements include the results of operations acquired in the SCANA Combination effective January 2019.56
DOMINION ENERGY
Year Ended December 31,(1) |
| 2020(2) |
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| 2019(3) |
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| 2018(4) |
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| 2017(5) |
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| 2016(6) |
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(millions, except per share amounts) |
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Operating revenue |
| $ | 14,172 |
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| $ | 14,401 |
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| $ | 11,199 |
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| $ | 11,004 |
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| $ | 10,320 |
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Net income from continuing operations attributable |
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to Dominion Energy |
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| 1,583 |
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| 653 |
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| 2,087 |
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| 2,707 |
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| 1,809 |
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Net income from continuing operations attributable |
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to Dominion Energy per common share-basic |
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| 1.83 |
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| 0.79 |
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| 3.19 |
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| 4.26 |
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| 2.93 |
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Net income from continuing operations attributable |
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to Dominion Energy per common share-diluted |
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| 1.82 |
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| 0.75 |
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| 3.19 |
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| 4.26 |
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| 2.93 |
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Dividends declared per common share |
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| 3.45 |
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| 3.67 |
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| 3.34 |
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| 3.035 |
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| 2.80 |
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Total assets |
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| 95,905 |
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| 103,823 |
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| 77,914 |
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| 76,585 |
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| 71,610 |
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Long-term debt(7) |
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| 33,957 |
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| 28,998 |
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| 27,075 |
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| 26,951 |
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| 26,271 |
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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, and general financial condition and liquidity and Virginia Power’s results of operations.operations as of and for the year ended December 31, 2022 as compared to the year ended December 31, 2021, as applicable. For a discussion of these items for the year ended December 31, 2021 as compared to the year ended December 31, 2020, please see Part II, Item 7. MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 24, 2022. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data. Virginia Power meets the conditions to file under the reduced disclosure format, and therefore has omitted certain sections of MD&A.
CONTENTS OF MD&A
MD&A consists of the following information:
• Forward-Looking Statements—Dominion Energy and Virginia Power • Accounting Matters—Dominion Energy • Results of Operations—Dominion Energy and Virginia Power • Segment Results of Operations—Dominion Energy • Outlook—Dominion Energy • Liquidity and Capital Resources—Dominion Energy • Future Issues and Other Matters—Dominion Energy
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FORWARD-LOOKING STATEMENTS
This report contains statements concerning the Companies’ expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may,” “continue,” “target” or other similar words.
The Companies make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:
• Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; • Extreme weather events and other natural disasters, including, but not limited to, hurricanes, high winds, severe storms, earthquakes, flooding, climate changes and changes in water temperatures and availability that can cause outages and property damage to facilities; • The impact of extraordinary external events, such as the current pandemic health event resulting from COVID-19, and their collateral consequences, including extended disruption of economic activity in our markets and global supply chains; • Federal, state and local legislative and regulatory developments, including changes in or interpretations of federal and state tax laws and regulations; • The direct and indirect impacts of implementing recommendations resulting from the business review announced in November 2022; • Risks of operating businesses in regulated industries that are subject to changing regulatory structures; • Changes to regulated electric rates collected by the Companies and regulated gas distribution, transportation and storage rates collected by Dominion Energy; • Changes in rules for RTOs and ISOs in which the Companies join and/or participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models; • Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; 57 • Risks associated with entities in which Dominion Energy shares ownership with third parties, including risks that result from lack of sole decision making authority, disputes that may arise between Dominion Energy and third party participants and difficulties in exiting these arrangements; • Changes in future levels of domestic and international natural gas production, supply or consumption; • Impacts to Dominion Energy’s noncontrolling interest in Cove Point from fluctuations in future volumes of LNG imports or exports from the U.S. and other countries worldwide or demand for, purchases of, and prices related to natural gas or LNG; • • Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals; • The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement, intervention or litigation in such projects; • Risks and uncertainties that may impact the Companies’ ability to develop and construct the CVOW Commercial Project within the currently proposed timeline, or at all, and consistent with current cost estimates along with the ability to recover such costs from customers; • Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances; • Cost of environmental strategy and compliance, including those costs related to climate change; • Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities; • Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals; • Unplanned outages at facilities in which the Companies have an ownership interest; • The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error and other catastrophic events; • Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; • Changes in operating, maintenance and construction costs; • Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity; • Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s nonregulated generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers; • Competition in the development, construction and ownership of certain electric transmission facilities in the Companies’ service territory in connection with Order 1000; • Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; • Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Energy’s pipeline system, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods; • Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures; • Impacts of acquisitions, divestitures, transfers of assets to joint ventures and retirements of assets based on asset portfolio reviews; • Adverse outcomes in litigation matters or regulatory proceedings, including matters acquired in the SCANA Combination; • Counterparty credit and performance risk; 58 • Fluctuations in the value of investments held in nuclear decommissioning trusts by the Companies and in benefit plan trusts by Dominion Energy; • Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy’s earnings and the Companies’ liquidity position and the underlying value of their assets; • Fluctuations in interest rates; • The effectiveness to which existing economic hedging instruments mitigate fluctuations in currency exchange rates of the Euro and Danish Krone associated with certain fixed price contracts for the major offshore construction and equipment components of the CVOW Commercial Project; • Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; • Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; • Political and economic conditions, including inflation and deflation; • Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; and • Changes in financial or regulatory accounting principles or policies imposed by governing bodies.
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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 OPERATIONSAccounting 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.
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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
59
CCRO in accordance with the GTSA. In 2021, Virginia Power made further adjustments to this regulatory liability prior to its ultimate resolution through a comprehensive settlement agreement. See Notes 12 and 13 to the Consolidated Financial Statements for additional information.
ASSET RETIREMENT OBLIGATIONSAsset Retirement Obligations
Dominion Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists and the ARO can be reasonably estimated. These AROs are recognized at fair value as incurred or when sufficient information becomes available to determine fair value and are generally capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Dominion Energy estimates the fair value of its AROs using present value techniques, in which it makes various assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. The impact on measurements of new AROs or remeasurements of existing AROs, using different cost escalation or credit-adjusted risk free rates in the future, may be significant. When Dominion Energy
revises any assumptions used to calculate the fair value of existing AROs, it adjusts the carrying amount of both the ARO liability and the related long-lived asset for assets that are in service; for assets that have ceased or are expected to cease operations, Dominion Energy adjusts the carrying amount of the ARO liability with such changes either recognized in income or as a regulatory asset.
Dominion Energy’s AROs include a significant balance related to the future decommissioning of its nonregulated and utility nuclear facilities. These nuclear decommissioning AROs are reported in Dominion Energy Virginia, Dominion Energy South Carolina and Contracted Assets. At December 31, 2020,2022 and 2021, Dominion Energy’s nuclear decommissioning AROs totaled $1.9 billion.billion and $2.0 billion, respectively. The following discusses critical assumptions inherent in determining the fair value of AROs associated with Dominion Energy’s nuclear decommissioning obligations.
Dominion Energy obtains from third-party specialists periodic site-specific base year cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for its nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. These cash flows include estimates on timing of decommissioning, which for regulated nuclear units factors in the probability of NRC approval for license extensions. In addition, Dominion Energy’s cost estimates include cost escalation rates that are applied to the base year costs. Dominion Energy determines cost escalation rates, which represent projected cost increases over time due to both general inflation and increases in the cost of specific decommissioning activities, for each nuclear facility. The selection of these cost escalation rates is dependent on subjective factors which are considered to be critical assumptions. At December 31, 2022, a 0.25% increase in cost escalation rates would have resulted in an approximate $370 million increase in Dominion Energy’s nuclear decommissioning AROs.
INCOME TAXESIncome 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, 20202022 and 2021, Dominion Energy had $167$117 million and $128 million, respectively, of unrecognized tax benefits. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations.
Deferred income tax assets and liabilities are recorded representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion Energy evaluates quarterly the probability of realizing deferred tax assets by considering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. In addition, changes in tax laws or tax rates may require reconsideration of the realizability of existing deferred tax assets. Dominion Energy establishes a valuation allowance when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. At December 31, 2020,2022 and 2021, Dominion Energy had established $155$138 million and $140 million, respectively, of valuation allowances.
ACCOUNTING FOR DERIVATIVE CONTRACTS AND FINANCIAL INSTRUMENTS AT FAIR VALUE
60
Accounting for Derivative Contracts and Financial Instruments at Fair Value
Dominion Energy uses derivative contracts such as physical and financial forwards, futures, swaps, options and FTRs to manage commodity, and interest rate and/or foreign currency exchange rate risks of its business operations. Derivative contracts, with certain exceptions, are reported in the Consolidated Balance Sheets at fair value. The majority of investments held in Dominion Energy’s nuclear decommissioning and rabbi trusts and pension and other postretirement funds are also subject to fair value accounting. See Notes 6 and 22 to the Consolidated Financial Statements for further information on these fair value measurements.
Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, management seeks indicative price information from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, Dominion Energy considers whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if Dominion Energy believes that observable pricing information is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases, Dominion Energy must estimate prices based on available historical and near-term future price information and use of statistical methods, including regression analysis, that reflect its market assumptions.
Dominion Energy maximizes the use of observable inputs and minimizes the use of unobservable inputs when measuring fair value.
USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING
As of December 31, 2020, Dominion Energy’s Consolidated Balance Sheets include $7.4 billion presented within goodwill. The majority of the balance relates to the SCANA Combination, as discussed in See Note 36 to the Consolidated Financial Statements thefor quantitative information on unobservable inputs utilized in Dominion Energy Questar CombinationEnergy’s fair value measurements of certain derivative contracts.
Use of Estimates in 2016 and the acquisition of the former CNG in 2000. In connection with Dominion Energy entering agreements for the sale of substantially all of its gas transmission and storage business to BHE, associated goodwill of $1.6 billion was reclassified to assets held for sale in the Consolidated Balance Sheets. During 2020, $1.4 billion of this amount was written off at the completion of the GT&S Transaction.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. In addition, in the third quarter of 2020, Dominion Energy performed impairment tests immediately beforeThe 2022, 2021 and after the realignment of its operating segments. The 2020 annual test and any interim tests did not result in the recognition of any goodwill impairment.
In general, Dominion Energy estimates the fair value of its reporting units by using a combination of discounted cash flows and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. Fair value estimates are dependent on subjective factors such as Dominion Energy’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in Dominion Energy’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion Energy has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent teststest 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 TESTINGUse 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
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fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions. In 2020,2022, Dominion Energy determined that it had an impairment of its contracted nonregulated solar generation assets within Contracted Assets were impaired. The estimates of future cash flows and selection of a discount rate are considered to be critical assumptions. A 10% decrease in partnerships outside of its core electric service territories.projected future pre-tax cash flows would have resulted in a $69 million increase to the impairment charge recorded. A 0.25% increase in the discount rate would have resulted in a $13 million increase to the impairment charge recorded. See Notes 6 andNote 10 to the Consolidated Financial Statements for a discussion offurther information concerning the impairment related to certain of Dominion Energy’s non-wholly-owned nonregulated solar facilities.generation assets. There were no other tests performed in 2022 of long-lived assets or equity method investments which could have resulted in material impairments.
EMPLOYEE BENEFIT PLANSHeld for Sale Classification
Dominion Energy recognizes the assets and liabilities of a disposal group as held for sale in the period (i) it has approved and committed to a plan to sell the disposal group, (ii) the disposal group is available for immediate sale in its present condition, (iii) an active program to locate a buyer and other actions required to sell the disposal group have been initiated, (iv) the sale of the disposal group is probable, (v) the disposal group is being actively marketed for sale at a price that is reasonable in relation to its current fair value and (vi) it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn. Dominion Energy initially measures a disposal group that is classified as held for sale at the lower of its carrying value or fair value less any costs to sell. Any loss resulting from this measurement is recognized in the period in which the held for sale criteria are met. Conversely, gains are not recognized on the sale of a disposal group until closing. Upon designation as held for sale, Dominion Energy stops recording depreciation expense and assesses the fair value of the disposal group less any costs to sell at each reporting period and until it is no longer classified as held for sale.
The determination as to whether the sale of the disposal group is probable may include significant judgments from management related to the expectation of obtaining approvals from applicable regulatory agencies such as state utility regulatory commissions, FERC or the U.S. Federal Trade Commission. This analysis is generally based on orders issued by regulatory commissions, past experience and discussions with applicable regulatory authorities and legal counsel.
In 2022, Dominion Energy completed the sale of Kewaunee following the receipt of approval for sale from the Wisconsin Commission; which prior to its receipt there had been uncertainty as to the timing of or ability to obtain such approval. Dominion Energy recorded a loss of $649 million primarily related to the difference between the nuclear decommissioning trust and AROs.
See Note 3 to the Consolidated Financial Statements for additional information.
Employee Benefit Plans
Dominion Energy sponsors noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The projected costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected long-term rate of return on plan assets, discount rates applied to benefit obligations, mortality rates and the anticipated rate of increase in healthcare costs and participant compensation, also have a significant impact on employee benefit costs. The impact of changes in these factors, as well as differences between Dominion Energy’s
assumptions and actual experience, is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants, rather than immediately.
The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality rates are critical assumptions. Dominion Energy determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:
• Expected inflation and risk-free interest rate assumptions; • Historical return analysis to determine long-term historic returns as well as historic risk premiums for various asset classes; • Expected future risk premiums, asset classes’ volatilities and correlations; • Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and • Investment allocation of plan assets. The long-term strategic target asset allocation for Dominion Energy’s pension funds is 26% U.S. equity, 19% non-U.S. equity, 32% fixed income, 3% real assets and 20% other alternative investments, such as private equity investments. 62
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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 relatedits critical assumptions, which are then compared to the forecasts of an independent investment advisor or an independent actuary, as applicable, to ensure reasonableness. An internal committee selects the final assumptions. Dominion Energy calculated its pension cost using an expected long-term rate of return on plan assets assumption that ranged from 7.00% to 8.35% for 2022, 7.00% to 8.45% for 2021 and 7.00% to 8.60% for 2020, 7.00% to 8.65% for 2019 and 8.75% for 2018.2020. For 2021,2023, the expected long-term rate of return for the pension cost assumption ranged from 7.00% to 8.45%8.35% for Dominion Energy’s plans held as of December 31, 2020.2022. Dominion Energy calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 8.35% for 2022, 8.45% for 2021 and 8.50% for 2020, 2019 and 2018.2020. For 2021,2023, the expected long-term rate of return for other postretirement benefit cost assumption is 8.45%8.35%. The rate used in calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets.
Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost ranged from 3.06% to 3.19% for pension plans and 3.04% to 5.03% for other postretirement benefit plans in 2022, ranged from 2.73% to 3.29% for pension plans and 2.69% to 2.80% for other postretirement benefit plans in 2021 and ranged from 2.77% to 3.63% for pension plans and 3.07% to 3.52% for other postretirement benefit plans in 2020, ranged from 3.57% to 4.43% for pension plans and 4.05% to 4.41% for other postretirement benefit plans in 2019 and ranged from 3.80% to 3.81% for pension plans and 3.76% for other postretirement benefit plans in 2018.2020. Dominion Energy selected a discount rate ranging from 2.73%5.65% to 2.95%5.75% for pension plans and 2.69%5.69% to 2.80%5.70% for other postretirement benefit plans for determining its December 31, 20202022 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, 20202022 was 6.25% and is expected to gradually decrease to 5.00% by 2025-20262026-2027 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 2022 Net Periodic Cost |
| |||||
| Change in Actuarial Assumptions |
| Pension Benefits |
|
| Other Postretirement Benefits |
| ||
(millions, except percentages) |
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| ||
Discount rate | (0.25)% |
| $ | 17 |
|
| $ | — |
|
Long-term rate of return on plan assets | (0.25)% |
|
| 27 |
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|
| 6 |
|
Health care cost trend rate | 1% |
| N/A |
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|
| 9 |
|
In addition to the effects on cost, a 0.25% decrease in the discount rate would increase Dominion Energy’s projected pension benefit obligation at December 31, 2022 by $215 million and its accumulated postretirement benefit obligation at December 31, 2022 by $26 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation at December 31, 2022 by $75 million.
See Note 22 to the Consolidated Financial Statements for additional information on Dominion Energy’s employee benefit plans.
NEW ACCOUNTING STANDARDSNew Accounting Standards
See Note 2 to the Consolidated Financial Statements for a discussion of new accounting standards.
DOMINION ENERGY
Results of Operations
63
RESULTS OF OPERATIONS
Dominion Energy
Presented below is a summary of Dominion Energy’s consolidated results:
Year Ended December 31, |
| 2020 |
|
| $ Change |
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| 2019 |
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| $ Change |
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| 2018 |
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| 2022 |
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| $ Change |
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| 2021 |
|
| $ Change |
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| 2020 |
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(millions, except EPS) |
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Net Income (loss) attributable to Dominion Energy |
| $ | (401 | ) |
| $ | (1,759 | ) |
| $ | 1,358 |
|
| $ | (1,089 | ) |
| $ | 2,447 |
| ||||||||||||||||||||
Net income (loss) attributable to Dominion Energy |
| $ | 994 |
|
| $ | (2,294 | ) |
| $ | 3,288 |
|
| $ | 3,689 |
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| $ | (401 | ) | ||||||||||||||||||||
Diluted EPS |
|
| (0.57 | ) |
|
| (2.19 | ) |
|
| 1.62 |
|
|
| (2.12 | ) |
|
| 3.74 |
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|
| 1.09 |
|
|
| (2.89 | ) |
|
| 3.98 |
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|
| 4.55 |
|
|
| (0.57 | ) |
Overview
20202022 VS. 20192021
Net income attributable to Dominion Energy decreased $1.8 billion,70%, primarily due to charges presented in discontinued operationsa charge associated with the cancellationimpairment of certain nonregulated solar generation facilities, a loss associated with the Atlantic Coast Pipeline Project and related portionssale of the Supply Header Project,Kewaunee, a decrease in net investment earnings on nuclear decommissioning trust funds, an increase in chargesa net decrease associated with the plannedimpacts of Virginia Power’s 2021 Triennial Review, a charge for RGGI compliance costs deemed recovered through base rates, a charge in connection with a comprehensive settlement agreement for Virginia fuel expenses and dismantling costs associated with the early retirementsretirement of certain electric generation facilities inat Virginia an impairment charge associated with interests in certain nonregulated solar generation facilities, a contract termination charge in connection with the sale of Fowler Ridge, a charge for benefits expected to be provided to retail electric customers in Virginia through the use of a CCRO in accordance with the GTSA and a charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020.Power. These decreases in net income were partially offset by the absence of charges for refunds of amounts previously collected from retail electric customers of DESC for the NND Project and for certain regulatory assets and property, plant and equipment acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery, the planned early retirement of certain Virginia Power automated meter reading infrastructure and a voluntary retirement program and a decrease in charges associated with litigation acquired in the SCANA Combination.
2019 VS. 2018
Net income attributable to Dominion Energy decreased 45%, primarily due to charges for refundssettlement of amounts previously collected from retailthe South Carolina electric customers of DESC for the NND Project, litigation acquired in the SCANA Combination, a voluntary retirement program, the planned early retirement of certain Virginia Power electric generation facilities base rate case, increased unrealized gains on economic hedging activities and the absence of gainsa net loss on the sales of certain equity method investments. These decreases were partially offset by an increase in net investment earnings on nuclear decommissioning trust funds and the operations acquired in the SCANA Combination.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, |
| 2020 |
|
| $ Change |
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| 2019 |
|
| $ Change |
|
| 2018 |
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| 2022 |
|
| $ Change |
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| 2021 |
|
| $ Change |
|
| 2020 |
| ||||||||||
(millions) |
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Operating revenue |
| $ | 14,172 |
|
| $ | (229 | ) |
| $ | 14,401 |
|
| $ | 3,202 |
|
| $ | 11,199 |
|
| $ | 17,174 |
|
| $ | 3,210 |
|
| $ | 13,964 |
|
| $ | (208 | ) |
| $ | 14,172 |
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Electric fuel and other energy-related purchases |
|
| 2,243 |
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|
| (642 | ) |
|
| 2,885 |
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| 198 |
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| 2,687 |
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| 3,711 |
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| 1,343 |
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| 2,368 |
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| 125 |
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| 2,243 |
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Purchased electric capacity |
|
| 53 |
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| (35 | ) |
|
| 88 |
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| (34 | ) |
|
| 122 |
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|
| 59 |
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|
| (11 | ) |
|
| 70 |
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| 17 |
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| 53 |
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Purchased gas |
|
| 889 |
|
|
| (671 | ) |
|
| 1,560 |
|
|
| 956 |
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|
| 604 |
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|
| 1,582 |
|
|
| 499 |
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|
| 1,083 |
|
|
| 194 |
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|
| 889 |
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Other operations and maintenance |
|
| 3,685 |
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|
| (105 | ) |
|
| 3,790 |
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|
| 1,004 |
|
|
| 2,786 |
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|
| 3,984 |
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|
| 250 |
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|
| 3,734 |
|
|
| 49 |
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|
| 3,685 |
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Depreciation, depletion and amortization |
|
| 2,332 |
|
|
| 49 |
|
|
| 2,283 |
|
|
| 623 |
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|
| 1,660 |
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| 2,830 |
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|
| 352 |
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|
| 2,478 |
|
|
| 146 |
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| 2,332 |
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Other taxes |
|
| 871 |
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|
| (12 | ) |
|
| 883 |
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|
| 303 |
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|
| 580 |
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|
| 923 |
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| 14 |
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| 909 |
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|
| 38 |
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|
| 871 |
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Impairment of assets and other charges |
|
| 2,105 |
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|
| 585 |
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| 1,520 |
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| 1,508 |
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| 12 |
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| 2,063 |
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| 1,868 |
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|
| 195 |
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|
| (1,910 | ) |
|
| 2,105 |
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Gains on sales of assets |
|
| (61 | ) |
|
| 91 |
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| (152 | ) |
|
| 113 |
|
|
| (265 | ) | ||||||||||||||||||||
Losses (gains) on sales of assets |
|
| 426 |
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|
| 318 |
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|
| 108 |
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|
| 169 |
|
|
| (61 | ) | ||||||||||||||||||||
Earnings from equity method investees |
|
| 299 |
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|
| 23 |
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| 276 |
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| 236 |
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|
| 40 |
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Other income |
|
| 733 |
|
|
| (78 | ) |
|
| 811 |
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|
| (74 | ) |
|
| 885 |
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|
| 124 |
|
|
| (1,033 | ) |
|
| 1,157 |
|
|
| 464 |
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|
| 693 |
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Interest and related charges |
|
| 1,377 |
|
|
| (109 | ) |
|
| 1,486 |
|
|
| 207 |
|
|
| 1,279 |
|
|
| 966 |
|
|
| (388 | ) |
|
| 1,354 |
|
|
| (23 | ) |
|
| 1,377 |
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Income tax expense |
|
| 83 |
|
|
| (126 | ) |
|
| 209 |
|
|
| (313 | ) |
|
| 522 |
|
|
| 68 |
|
|
| (357 | ) |
|
| 425 |
|
|
| 342 |
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|
| 83 |
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Net income (loss) from discontinued operations including noncontrolling interests |
|
| (1,878 | ) |
|
| (2,594 | ) |
|
| 716 |
|
|
| 264 |
|
|
| 452 |
|
|
| 9 |
|
|
| (632 | ) |
|
| 641 |
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|
| 2,519 |
|
|
| (1,878 | ) |
Noncontrolling interests |
|
| (149 | ) |
|
| (167 | ) |
|
| 18 |
|
|
| (84 | ) |
|
| 102 |
|
|
| — |
|
|
| (26 | ) |
|
| 26 |
|
|
| 175 |
|
|
| (149 | ) |
An analysis of Dominion Energy’s results of operations follows:
20202022 VS. 20192021
Operating revenue decreased 2% increased 23%, primarily reflecting:
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64
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|
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These decreasesincreases were partially offset by:
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Electric fuel and other energy-related purchases decreased 22%increased 57%, primarily due to decreased fuelhigher commodity costs associated withfor electric utility retail customersutilities ($6811.2 billion) and an increase in the use of purchased renewable energy credits at Virginia Power ($58 million), which are offset in operating revenue and do not impact net income.
Purchased gas increased 46%, primarily due to an increase in commodity costs for gas utilities ($586 million), which are offset in operating revenue and do not impact net income, partially offset by PJM off-system salescost saving incentives earned under the Wexpro Agreements ($64 million) and the absence of various contracts at Virginia Power ($3427 million).
Purchased electric capacity
decreased 40%Other operations and maintenance increased 7%, primarily reflecting:
These increases were partially offset by:
65
Depreciation, depletion and amortization increased 14%, primarily due to various projects being placed into service ($205 million), an increase for amortization of a decreaseregulatory asset established in expense related to the annual PJM capacity performance market effective June 2019settlement of the 2021 Triennial Review ($51183 million), and a Virginia Power contract termination with a non-utility generator ($13 million) partially offset by an increase in expense associated with sales to DESC electric utility retail customersRGGI-related amortization ($30128 million), which except for the suspended period of Rider RGGI is offset in operating revenue and does not impact net income, partially offset by depreciation rates revised in the first quarter of 2022 at Virginia Power ($82 million) and a decrease from the sale of non-wholly-owned nonregulated solar facilities ($45 million).
Impairment of assets and other charges increased $1.9 billion, primarily reflecting:
Losses on sales of assets increased $318 million, primarily due to a loss associated with the sale of Kewaunee ($649 million) and the absence of gains on the sale of nonregulated retail energy marketing assets ($87 million), partially offset by the absence of a net loss on the sales of non-wholly-owned nonregulated solar facilities ($211 million), a gain on the contribution of certain privatization operations to Dominion Privatization ($155 million), a gain on the transfer of certain non-utility and utility property in South Carolina ($20 million) and a gain on the sale of certain utility property in South Carolina ($20 million).
Other income decreased 89%, primarily due to net investment losses in 2022 compared to net investment gains in 2021 on nuclear decommissioning trust funds ($1.1 billion), partially offset by an increase in non-service components of pension and other postretirement employee benefit plan credits ($109 million) and the absence of charges associated with the settlement of the South Carolina electric base rate case ($18 million).
Interest and related charges decreased 29%, primarily due to higher unrealized gains associated with freestanding derivatives ($511 million), higher premiums received on interest rate derivatives ($60 million), a decrease due to junior subordinated note repayments in 2021 ($52 million), benefits associated with the early redemption of certain securities in the third and fourth quarters of 2022 ($35 million) and the absence of charges associated with the early redemption of certain securities in the third quarter of 2021 ($23 million), partially offset by an increase from net debt issuances ($179 million), higher interest rates on commercial paper borrowings ($51 million), higher interest rates on variable rate debt and cash flow interest rate swaps ($29 million) and the absence of a benefit associated with the effective settlement of uncertain tax positions ($21 million).
Income tax expense decreased 84%, primarily due to lower pre-tax income including lower state income tax benefits on pre-tax losses from nuclear decommissioning trusts and economic hedges ($455 million) and higher investment tax credits ($36 million), partially offset by tax expense on the sale of Hope’s stock ($90 million) and the absence of benefits from the effective settlement of uncertain tax positions ($38 million) and a state legislative change ($21 million).
Net income from discontinued operations including noncontrolling interests decreased 99%, primarily due to the completion of the sale of the Q-Pipe Group in December 2021.
66
Noncontrolling interests decreased $26 million, primarily due to the absence of operations in connection with the sale of certain nonregulated solar generating projects held in partnerships.
Virginia Power
Presented below is a summary of Virginia Power’s consolidated results:
Year Ended December 31, |
| 2022 |
|
| $ Change |
|
| 2021 |
|
| $ Change |
|
| 2020 |
| |||||
(millions) |
|
|
|
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|
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|
|
|
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| |||||
Net income |
| $ | 1,215 |
|
| $ | (497 | ) |
| $ | 1,712 |
|
| $ | 691 |
|
| $ | 1,021 |
|
Overview
2022 VS. 2021
Net income decreased 29%, primarily due to a decrease in net investment earnings on nuclear decommissioning trust funds, a net decrease associated with the impacts of the 2021 Triennial Review, a charge for RGGI compliance costs deemed recovered through base rates, a charge in connection with a comprehensive settlement agreement for Virginia fuel expenses and dismantling costs associated with the early retirement of certain electric generation facilities.
Analysis of Consolidated Operations
Presented below are selected amounts related to Virginia Power’s results of operations:
Year Ended December 31, |
| 2022 |
|
| $ Change |
|
| 2021 |
|
| $ Change |
|
| 2020 |
| |||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Operating revenue |
| $ | 9,654 |
|
| $ | 2,184 |
|
| $ | 7,470 |
|
| $ | (293 | ) |
| $ | 7,763 |
|
Electric fuel and other energy-related purchases |
|
| 2,913 |
|
|
| 1,178 |
|
|
| 1,735 |
|
|
| 99 |
|
|
| 1,636 |
|
Purchased (excess) electric capacity |
|
| 46 |
|
|
| 22 |
|
|
| 24 |
|
|
| 41 |
|
|
| (17 | ) |
Other operations and maintenance |
|
| 2,051 |
|
|
| 258 |
|
|
| 1,793 |
|
|
| 7 |
|
|
| 1,786 |
|
Depreciation and amortization |
|
| 1,736 |
|
|
| 372 |
|
|
| 1,364 |
|
|
| 112 |
|
|
| 1,252 |
|
Other taxes |
|
| 303 |
|
|
| (23 | ) |
|
| 326 |
|
|
| (1 | ) |
|
| 327 |
|
Impairment of assets and other charges (benefits) |
|
| 557 |
|
|
| 826 |
|
|
| (269 | ) |
|
| (1,362 | ) |
|
| 1,093 |
|
Other income |
|
| — |
|
|
| (146 | ) |
|
| 146 |
|
|
| 66 |
|
|
| 80 |
|
Interest and related charges |
|
| 642 |
|
|
| 108 |
|
|
| 534 |
|
|
| 18 |
|
|
| 516 |
|
Income tax expense |
|
| 191 |
|
|
| (206 | ) |
|
| 397 |
|
|
| 168 |
|
|
| 229 |
|
An analysis of Virginia Power’s results of operations follows:
2022 VS. 2021
Operating revenue increased 29%, primarily reflecting:
67
These increases were partially offset by:
Electric fuel and other energy-related purchases increased 68%, primarily due to higher commodity costs for electric utilities ($1.1 billion) and an increase in the use of purchased renewable energy credits ($58 million), which are offset in operating revenue and do not impact net income.
Purchased electric capacity increased 92%, primarily due to an increase in expense related to the annual PJM capacity performance market effective June 2020 ($15 million).2021.
Purchased gas decreased 43%Other operations and maintenance increased 14%, primarily due to the contribution of SEMI to Wranglerreflecting:
Other operations and maintenance decreased 3%, primarily reflecting:
|
|
|
|
|
|
These decreases were partially offset by:
|
|
|
|
|
|
|
|
Depreciation depletion and amortization increased 2%27%, primarily due to an increase for amortization of a regulatory asset established in the settlement of the 2021 Triennial Review ($183 million), an increase due to various projects being placed into service ($102144 million) and an increase in RGGI-related amortization ($128 million), which except for the suspended period of Rider RGGI is offset in operating revenue and does not impact net income, partially offset by depreciation rates revised in the absencefirst quarter of depreciation from certain electric generation facilities that were, or have been, committed to be retired early2022 ($58 million) and a decrease reflecting the expected approval of the nuclear plant life extensions from the NRC ($3182 million).
Impairment of assets and other charges (benefits) increased 38%,$826 million, primarily reflecting:
Other income decreased $146 million, primarily due to:to net investment losses in 2022 compared to net investment gains in 2021 on nuclear decommissioning trust funds.
|
|
|
|
|
|
|
|
|
|
|
|
These increases were partially offset by:
|
|
|
|
|
|
|
|
|
|
|
|
Gains on sales of assets decreased 60%Interest and related charges increased 20%, primarily due to a decrease in gains on the sale of nonregulated retail energy marketing assets.
Other income decreased 10%, primarily reflecting a decrease in net investment earnings on nuclear decommissioning trust funds ($217 million), an increase in charitable commitments ($65 million), primarily for social justice, and charges associated with litigation acquired in the SCANA Combination ($25 million), partially offset by the absence of a charge related to a voluntary retirement program ($111 million), an increase from equity method earnings from Cove Point following closing of the GT&S Transactionnet debt issuances in 2022 and 2021 ($4060 million), higher interest rates on commercial paper borrowings ($17 million) and an increase in non-service components of pensionprincipal and other postretirement employee benefit plan creditsinterest rates on intercompany borrowings with Dominion Energy ($3314 million).
Interest and related charges decreased 7%, primarily reflecting unrealized gains associated with freestanding derivatives ($84 million), lower interest expense from early redemptions of certain securities in 2019 and 2020 ($41 million), reductions in commercial paper borrowings ($34 million) and increases in AFUDC on regulated construction projects ($28 million), partially offset by increased borrowings in response to COVID-19 ($42 million) and charges associated with the early redemption of certain securities in the first quarter of 2020 ($25 million).
Income tax expense decreased 60%, primarily due to a reduction in consolidated state deferred income taxes associated with gas transmission and storage operations ($45 million) and the absence of a charge for certain income tax-related regulatory assets acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery ($194 million), partially offset by income tax expense primarily associated with the impairment of nonregulated solar generating assets held in partnerships attributable to the noncontrolling interest ($55 million) and a lower current year benefit from finalizing changes in tax status of certain subsidiaries in connection with the Dominion Energy Gas Restructuring ($24 million).
Net income from discontinued operations including noncontrolling interests decreased $2.6 billion, primarily due to charges associated with the cancellation of the Atlantic Coast Pipeline Project and related portions of the Supply Header Project.
Noncontrolling interests decreased $167 million, primarily due to impairments associated with certain nonregulated solar generation facilities ($267 million), partially offset by the sale of a 25% noncontrolling limited partnership interest in Cove Point to Brookfield in December 2019 ($97 million).
2019 VS. 2018
Operating revenue increased 29%, primarily reflecting:
|
|
|
|
|
|
|
|
These increases were partially offset by:
|
|
|
|
|
|
Electric fuel and other energy-related purchases increased 7%, primarily due to a $576 million increase from operations acquired in the SCANA Combination, partially offset by a decrease in fuel costs due to the absence of certain nonregulated generation facilities in 2018 ($245 million), decreased fuel costs associated with Virginia Power utility customers ($83 million), which are offset in operating revenue and do not impact net income, and a decrease in Virginia Power fuel costs due to the expiration of an energy supply contract ($40 million).
Purchased electric capacity decreased 28%, primarily due to a decrease in expense related to the annual PJM capacity performance market effective June 2019 ($63 million) and a Virginia Power contract termination with a non-utility generator ($37 million), partially offset by an increase in expense from operations acquired in the SCANA Combination ($49 million) and the annual PJM capacity performance market effective June 2018 ($26 million).
Purchased gas increased $956 million, primarily due an increase from operations acquired in the SCANA Combination.
Other operations and maintenance increased 36%, primarily reflecting:
|
|
|
|
|
|
These increases were partially offset by:
|
|
|
|
|
|
Depreciation, depletion and amortization increased 38%, primarily due to property, plant and equipment acquired in the SCANA Combination ($559 million), including amortization of NND Project costs ($127 million), an increase from various growth projects being placed into service ($140 million) and the absence of a benefit for the retroactive application of depreciation rates for regulated
nuclear plants to comply with Virginia Commission requirements ($31 million), partially offset by the planned early retirement of certain Virginia Power electric generation facilities and automated meter reading infrastructure ($40 million) and the sale of certain nonregulated electric generation facilities in 2018 ($37 million).
Other taxes increased 52%, primarily due to the SCANA Combination ($258 million), an increase in property tax charges for growth projects placed into service ($56 million) and a charge related to a voluntary retirement program ($21 million).
Impairment of assets and other charges increased $1.5 billion, primarily due to:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains on sales of assets decreased 43%, primarily due to the absence of the sale of Fairless and Manchester ($210 million) partially offset by an increase in gains on sales of nonregulated retail energy marketing assets ($82 million).
Other income decreased 8%, primarily reflecting the absence of equity method earnings and gain from the sale of Dominion Energy’s 50% limited partnership interest in Blue Racer ($603 million), a charge related to a voluntary retirement program ($111 million) and the absence of a gain on the sale of Dominion Energy’s 25% limited partnership interest in Catalyst Old River Hydroelectric Limited Partnership ($87 million). These decreases were partially offset by an increase in net investment earnings on nuclear decommissioning trust funds ($720 million).
Interest and related charges increased 16%, primarily due to debt acquired in the SCANA Combination net of debt redeemed in 2019 ($314 million), partially offset by the absence of charges associated with the early redemption of certain debt securities in 2018 ($69 million) and reduced interest on long-term debt due to net debt repayments in 2018 and 2019 ($57 million).
Income tax expense decreased 60%, primarily due to lower pre-tax income ($383182 million), the impacts of changes in tax status of certain subsidiaries in connection with the Dominion Energy Gas Restructuring ($48 million), and higher investment tax credits ($3966 million), partially offset by the recognition of an intercompany gain related to the transfer and subsequent contribution of existing
68
privatization operations in Virginia to Dominion Privatization ($34 million) and the absence of 2017 Tax Reform Act impacts ($46 million), partially offset by a charge for certain income tax-related regulatory assets acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery ($194 million) and the absence ofbenefit from a state legislative change ($2016 million).
Net income from discontinued operations including noncontrolling interests increased 58%, primarily due to the operations of the Liquefaction Facility for the entire year and the absence of charges for impairment of certain gathering and processing assets and disallowance of FERC-regulated plant.
Noncontrolling interests decreased 82%, primarily due to the acquisition of the public interest in Dominion Energy Midstream in January 2019.
Outlook
Dominion Energy’s 2021 net income is expected to increase on a per share basis as compared to 2020 primarily from the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
These increases are expected to be partially offset by the following:
|
|
|
|
|
|
SEGMENT RESULTS OF OPERATIONS
Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit or loss. In September 2020, Dominion Energy updated its operating segments following the July 2020 agreement to sell substantially all of its gas transmission and storage operations to BHE. The historical information presented herein has been recast to reflect the current segment presentation. Presented below is a summary of contributions by Dominion Energy’s operating segments to net income (loss) attributable to Dominion Energy:
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||||||||||||||
|
| Net income |
|
| EPS(1) |
|
| Net income |
|
| EPS(1) |
|
| Net income |
|
| EPS(1) |
| ||||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Dominion Energy Virginia |
| $ | 2,008 |
|
| $ | 2.44 |
|
| $ | 1,919 |
|
| $ | 2.37 |
|
| $ | 1,891 |
|
| $ | 2.28 |
|
Gas Distribution |
|
| 697 |
|
|
| 0.85 |
|
|
| 600 |
|
|
| 0.74 |
|
|
| 560 |
|
|
| 0.67 |
|
Dominion Energy South Carolina |
|
| 505 |
|
|
| 0.61 |
|
|
| 437 |
|
|
| 0.54 |
|
|
| 419 |
|
|
| 0.51 |
|
Contracted Assets |
|
| 335 |
|
|
| 0.41 |
|
|
| 431 |
|
|
| 0.53 |
|
|
| 402 |
|
|
| 0.48 |
|
Corporate and Other |
|
| (2,551 | ) |
|
| (3.22 | ) |
|
| (99 | ) |
|
| (0.20 | ) |
|
| (3,673 | ) |
|
| (4.51 | ) |
Consolidated |
| $ | 994 |
|
| $ | 1.09 |
|
| $ | 3,288 |
|
| $ | 3.98 |
|
| $ | (401 | ) |
| $ | (0.57 | ) |
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
| |||||||||||||||
|
| Net income (loss) attributable to Dominion Energy |
|
| Diluted EPS |
|
| Net income (loss) attributable to Dominion Energy |
|
| Diluted EPS |
|
| Net income attributable to Dominion Energy |
|
| Diluted EPS |
| ||||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy Virginia |
| $ | 1,891 |
|
| $ | 2.28 |
|
| $ | 1,786 |
|
| $ | 2.21 |
|
| $ | 1,596 |
|
| $ | 2.44 |
|
Gas Distribution |
|
| 560 |
|
|
| 0.67 |
|
|
| 487 |
|
|
| 0.60 |
|
|
| 373 |
|
|
| 0.57 |
|
Dominion Energy South Carolina |
|
| 419 |
|
|
| 0.51 |
|
|
| 430 |
|
|
| 0.53 |
|
|
| — |
|
|
| — |
|
Contracted Assets |
|
| 402 |
|
|
| 0.48 |
|
|
| 460 |
|
|
| 0.57 |
|
|
| 361 |
|
|
| 0.55 |
|
Corporate and Other |
|
| (3,673 | ) |
|
| (4.51 | ) |
|
| (1,805 | ) |
|
| (2.29 | ) |
|
| 117 |
|
|
| 0.18 |
|
Consolidated |
| $ | (401 | ) |
| $ | (0.57 | ) |
| $ | 1,358 |
|
| $ | 1.62 |
|
| $ | 2,447 |
|
| $ | 3.74 |
|
Dominion Energy Virginia
Presented below are operating statistics related to Dominion Energy Virginia’s operations:
Year Ended December 31, |
| 2020 |
|
| % Change |
|
| 2019 |
|
| % Change |
|
| 2018 |
|
| 2022 |
|
| % Change |
|
| 2021 |
|
| % Change |
|
| 2020 |
| ||||||||||
Electricity delivered (million MWh) |
|
| 83.3 |
|
|
| (5 | ) | % |
| 87.7 |
|
|
| — |
| % | 87.8 |
|
|
| 90.0 |
|
|
| 6 |
| % |
| 85.2 |
|
|
| 2 |
| % |
| 83.3 |
| |
Electricity supplied (million MWh): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Utility |
|
| 87.0 |
|
|
| (1 | ) |
|
| 88.2 |
|
|
| — |
|
|
| 88.0 |
|
|
| 90.2 |
|
|
| 5 |
|
|
| 85.7 |
|
|
| (1 | ) |
|
| 87.0 |
|
Non-Jurisdictional |
|
| 0.7 |
|
|
| 75 |
|
|
| 0.4 |
|
|
| 300 |
|
|
| 0.1 |
|
|
| 1.5 |
|
|
| 50 |
|
|
| 1.0 |
|
|
| 43 |
|
|
| 0.7 |
|
Degree days (electric distribution and utility service area): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Cooling |
|
| 1,759 |
|
|
| (13 | ) |
|
| 2,031 |
|
|
| 1 |
|
|
| 2,019 |
|
|
| 1,765 |
|
|
| (1 | ) |
|
| 1,783 |
|
|
| 1 |
|
|
| 1,759 |
|
Heating |
|
| 2,970 |
|
|
| (9 | ) |
|
| 3,259 |
|
|
| (10 | ) |
|
| 3,608 |
|
|
| 3,555 |
|
|
| 11 |
|
|
| 3,210 |
|
|
| 8 |
|
|
| 2,970 |
|
Average electric distribution customer accounts (thousands) |
|
| 2,661 |
|
|
| 1 |
|
|
| 2,626 |
|
|
| 1 |
|
|
| 2,600 |
|
|
| 2,724 |
|
|
| 1 |
|
|
| 2,697 |
|
|
| 1 |
|
|
| 2,661 |
|
69
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy Virginia’s net income contribution:
20202022 VS. 20192021
|
| Increase (Decrease) |
|
| Increase (Decrease) |
| ||||||||||
|
| Amount |
|
| EPS |
|
| Amount |
|
| EPS |
| ||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Regulated electric sales: |
|
|
|
|
|
|
|
| ||||||||
Weather |
| $ | (74 | ) |
| $ | (0.09 | ) |
| $ | 21 |
|
| $ | 0.03 |
|
Other |
|
| (20 | ) |
|
| (0.02 | ) | ||||||||
Customer usage and other factors |
|
| 25 |
|
|
| 0.03 |
| ||||||||
Customer-elected rate impacts |
|
| 13 |
|
|
| 0.02 |
| ||||||||
Base rate case impacts |
|
| (41 | ) |
|
| (0.05 | ) | ||||||||
Rider equity return |
|
| 87 |
|
|
| 0.10 |
|
|
| 64 |
|
|
| 0.08 |
|
Electric capacity |
|
| 22 |
|
|
| 0.03 |
| ||||||||
Outages |
|
| 29 |
|
|
| 0.04 |
| ||||||||
Salaries, wages and benefits |
|
| 32 |
|
|
| 0.04 |
| ||||||||
Storm damage and service restoration |
|
| (17 | ) |
|
| (0.02 | ) | ||||||||
Planned outage costs |
|
| (12 | ) |
|
| (0.01 | ) | ||||||||
Depreciation and amortization |
|
| 42 |
|
|
| 0.05 |
|
|
| 19 |
|
|
| 0.02 |
|
Renewable energy investment tax credits |
|
| 19 |
|
|
| 0.02 |
|
|
| 65 |
|
|
| 0.08 |
|
Salaries, wages and benefits & administrative costs |
|
| 26 |
|
|
| 0.03 |
| ||||||||
Interest expense, net |
|
| (13 | ) |
|
| (0.02 | ) | ||||||||
Other |
|
| (32 | ) |
|
| (0.04 | ) |
|
| (61 | ) |
|
| (0.07 | ) |
Share dilution |
|
| — |
|
|
| (0.06 | ) |
|
| — |
|
|
| (0.05 | ) |
Change in net income contribution |
| $ | 105 |
|
| $ | 0.07 |
|
| $ | 89 |
|
| $ | 0.07 |
|
20192021 VS. 20182020
|
| Increase (Decrease) |
|
| Increase (Decrease) |
| ||||||||||
|
| Amount |
|
| EPS |
|
| Amount |
|
| EPS |
| ||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Regulated electric sales: |
|
|
|
|
|
|
|
| ||||||||
Weather |
| $ | (14 | ) |
| $ | (0.02 | ) |
| $ | 44 |
|
| $ | 0.05 |
|
Other |
|
| 9 |
|
|
| 0.01 |
| ||||||||
Customer usage and other factors |
|
| (26 | ) |
|
| (0.03 | ) | ||||||||
Customer-elected rate impacts |
|
| 46 |
|
|
| 0.06 |
| ||||||||
Rider equity return |
|
| 84 |
|
|
| 0.13 |
|
|
| 41 |
|
|
| 0.05 |
|
Electric capacity |
|
| 54 |
|
|
| 0.08 |
|
|
| (28 | ) |
|
| (0.03 | ) |
Expiration of energy supply contract |
|
| 30 |
|
|
| 0.05 |
| ||||||||
Outages |
|
| (14 | ) |
|
| (0.02 | ) | ||||||||
Depreciation and amortization |
|
| (18 | ) |
|
| (0.02 | ) | ||||||||
Renewable energy investment tax credits |
|
| (14 | ) |
|
| (0.02 | ) |
|
| 7 |
|
|
| 0.01 |
|
Salaries, wages and benefits & administrative costs |
|
| (22 | ) |
|
| (0.03 | ) | ||||||||
Other |
|
| 41 |
|
|
| 0.06 |
|
|
| (2 | ) |
|
| (0.01 | ) |
Share dilution |
|
| — |
|
|
| (0.52 | ) | ||||||||
Share accretion |
|
| — |
|
|
| 0.06 |
| ||||||||
Change in net income contribution |
| $ | 190 |
|
| $ | (0.23 | ) |
| $ | 28 |
|
| $ | 0.09 |
|
Gas Distribution
Presented below are selected operating statistics related to Gas Distribution’s operations:
Year Ended December 31, |
| 2022(1) |
|
| % Change |
|
| 2021 |
|
| % Change |
|
| 2020 |
| |||||
Gas distribution throughput (bcf): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Sales |
|
| 194 |
|
|
| 6 |
| % |
| 183 |
|
|
| 2 |
| % |
| 180 |
|
Transportation |
|
| 1,020 |
|
|
| 5 |
|
|
| 975 |
|
|
| 12 |
|
|
| 868 |
|
Heating degree days (gas distribution service area): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
North Carolina |
|
| 3,009 |
|
|
| 2 |
|
|
| 2,947 |
|
|
| 8 |
|
|
| 2,734 |
|
Ohio and West Virginia |
|
| 5,514 |
|
|
| 8 |
|
|
| 5,121 |
|
|
| (1 | ) |
|
| 5,148 |
|
Utah, Wyoming, and Idaho |
|
| 5,170 |
|
|
| 6 |
|
|
| 4,874 |
|
|
| (2 | ) |
|
| 4,973 |
|
Average gas distribution customer accounts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Sales |
|
| 1,944 |
|
|
| — |
|
|
| 1,935 |
|
|
| 2 |
|
|
| 1,897 |
|
Transportation |
|
| 1,131 |
|
|
| — |
|
|
| 1,131 |
|
|
| 1 |
|
|
| 1,123 |
|
Year Ended December 31, |
| 2020 |
|
| % Change |
|
| 2019(1) |
|
| % Change |
|
| 2018 |
| |||||
Gas distribution throughput (bcf): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
| 180 |
|
|
| (6 | ) | % |
| 192 |
|
|
| 47 |
| % |
| 131 |
|
Transportation |
|
| 868 |
|
|
| 7 |
|
|
| 811 |
|
|
| 12 |
|
|
| 725 |
|
Heating degree days (gas distribution service area): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North Carolina |
|
| 2,734 |
|
|
| (7 | ) |
|
| 2,942 |
|
|
|
|
|
|
|
|
|
Ohio and West Virginia |
|
| 5,148 |
|
|
| (4 | ) |
|
| 5,355 |
|
|
| (6 | ) |
|
| 5,693 |
|
Utah, Wyoming, and Idaho |
|
| 4,973 |
|
|
| (10 | ) |
|
| 5,501 |
|
|
| 18 |
|
|
| 4,672 |
|
Average gas distribution customer accounts (thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
| 1,897 |
|
|
| 2 |
|
|
| 1,857 |
|
|
| 48 |
|
|
| 1,258 |
|
Transportation |
|
| 1,123 |
|
|
| 1 |
|
|
| 1,108 |
|
|
| 1 |
|
|
| 1,096 |
|
(1) Includes PSNC effective January 2019.
70
Presented below, on an after-tax basis, are the key factors impacting Gas Distribution’s net income contribution:
20202022 VS. 20192021
|
| Increase (Decrease) |
|
| Increase (Decrease) |
| ||||||||||
|
| Amount |
|
| EPS |
|
| Amount |
|
| EPS |
| ||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Regulated gas sales: |
|
|
|
|
|
|
|
| ||||||||
Weather |
| $ | (2 | ) |
| $ | — |
|
| $ | 4 |
|
| $ | — |
|
Other |
|
| 11 |
|
|
| 0.01 |
| ||||||||
Salaries, wages and benefits |
|
| 14 |
|
|
| 0.02 |
| ||||||||
Customer usage and other factors |
|
| 36 |
|
|
| 0.04 |
| ||||||||
Base rate case impacts |
|
| 29 |
|
|
| 0.04 |
| ||||||||
Rider equity return |
|
| 25 |
|
|
| 0.03 |
| ||||||||
Wexpro cost saving sharing incentives |
|
| 21 |
|
|
| 0.03 |
| ||||||||
Sale of Hope |
|
| (11 | ) |
|
| (0.01 | ) | ||||||||
Interest expense, net |
|
| 36 |
|
|
| 0.04 |
|
|
| (16 | ) |
|
| (0.02 | ) |
Other |
|
| 14 |
|
|
| 0.02 |
|
|
| 9 |
|
|
| 0.01 |
|
Share dilution |
|
| — |
|
|
| (0.02 | ) |
|
| — |
|
|
| (0.01 | ) |
Change in net income contribution |
| $ | 73 |
|
| $ | 0.07 |
|
| $ | 97 |
|
| $ | 0.11 |
|
20192021 VS. 20182020
|
| Increase (Decrease) |
|
| Increase (Decrease) |
| ||||||||||
|
| Amount |
|
| EPS |
|
| Amount |
|
| EPS |
| ||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Regulated gas sales: |
|
|
|
|
|
|
|
| ||||||||
Weather |
| $ | (3 | ) |
| $ | — |
|
| $ | — |
|
| $ | — |
|
Customer usage and other factors |
|
| 24 |
|
|
| 0.03 |
| ||||||||
Base rate case impacts |
|
| 7 |
|
|
| 0.01 |
| ||||||||
Rider equity return |
|
| 40 |
|
|
| 0.05 |
| ||||||||
Salaries, wages and benefits & administrative costs |
|
| (8 | ) |
|
| (0.01 | ) | ||||||||
Interest expense, net |
|
| 12 |
|
|
| 0.01 |
| ||||||||
Other |
|
| (2 | ) |
|
| — |
|
|
| (35 | ) |
|
| (0.04 | ) |
Rider equity return |
|
| 16 |
|
|
| 0.02 |
| ||||||||
SCANA Combination |
|
| 87 |
|
|
| 0.13 |
| ||||||||
Other |
|
| 16 |
|
|
| 0.02 |
| ||||||||
Share dilution |
|
| — |
|
|
| (0.14 | ) | ||||||||
Share accretion |
|
| — |
|
|
| 0.02 |
| ||||||||
Change in net income contribution |
| $ | 114 |
|
| $ | 0.03 |
|
| $ | 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, |
| 2020 |
|
| % Change |
|
| 2019 |
|
| 2022 |
|
| % Change |
|
| 2021 |
|
| % Change |
|
| 2020 |
| ||||||||
Electricity delivered (million MWh) |
|
| 22.1 |
|
|
| (4 | ) | % |
| 23.0 |
|
|
| 23.0 |
|
|
| 3 |
| % |
| 22.4 |
|
|
| 1 |
| % |
| 22.1 |
|
Electricity supplied (million MWh) |
|
| 23.0 |
|
|
| (5 | ) |
|
| 24.1 |
|
|
| 24.1 |
|
|
| 3 |
|
|
| 23.5 |
|
|
| 2 |
|
|
| 23.0 |
|
Degree days (electric and gas distribution service areas): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Cooling |
|
| 794 |
|
|
| (17 | ) |
|
| 951 |
|
|
| 767 |
|
|
| (11 | ) |
|
| 859 |
|
|
| 8 |
|
|
| 794 |
|
Heating |
|
| 1,074 |
|
|
| (9 | ) |
|
| 1,179 |
|
|
| 1,294 |
|
|
| 1 |
|
|
| 1,280 |
|
|
| 19 |
|
|
| 1,074 |
|
Average electric distribution customer accounts (thousands) |
|
| 753 |
|
|
| 2 |
|
|
| 739 |
|
|
| 777 |
|
|
| 1 |
|
|
| 766 |
|
|
| 2 |
|
|
| 753 |
|
Gas distribution throughput (bcf): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Sales |
|
| 66 |
|
|
| 2 |
|
|
| 65 |
|
|
| 68 |
|
|
| (6 | ) |
|
| 72 |
|
|
| 9 |
|
|
| 66 |
|
Average gas distribution customer accounts (thousands) |
|
| 399 |
|
|
| 3 |
|
|
| 386 |
|
|
| 427 |
|
|
| 4 |
|
|
| 412 |
|
|
| 3 |
|
|
| 399 |
|
71
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy South Carolina’s net income contribution:
20202022 VS. 20192021
|
| Increase (Decrease) |
|
| Increase (Decrease) |
| ||||||||||
|
| Amount |
|
| EPS |
|
| Amount |
|
| EPS |
| ||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Regulated electric sales: |
|
|
|
|
|
|
|
| ||||||||
Weather |
| $ | (15 | ) |
| $ | (0.02 | ) |
| $ | 21 |
|
| $ | 0.03 |
|
Other |
|
| 2 |
|
|
| — |
| ||||||||
Regulated gas sales |
|
| 12 |
|
|
| 0.02 |
| ||||||||
Customer usage and other factors |
|
| 38 |
|
|
| 0.05 |
| ||||||||
Customer-elected rate impacts |
|
| 14 |
|
|
| 0.02 |
| ||||||||
Base rate case & Natural Gas Rate Stabilization Act impacts |
|
| 22 |
|
|
| 0.03 |
| ||||||||
Capital cost rider |
|
| (10 | ) |
|
| (0.01 | ) |
|
| (8 | ) |
|
| (0.01 | ) |
Gains on sales of property |
|
| 17 |
|
|
| 0.02 |
| ||||||||
Depreciation and amortization |
|
| (15 | ) |
|
| (0.02 | ) | ||||||||
Interest expense, net |
|
| 17 |
|
|
| 0.02 |
|
|
| (16 | ) |
|
| (0.02 | ) |
Other |
|
| (17 | ) |
|
| (0.02 | ) |
|
| (5 | ) |
|
| (0.02 | ) |
Share dilution |
|
| — |
|
|
| (0.01 | ) |
|
| — |
|
|
| (0.01 | ) |
Change in net income contribution |
| $ | (11 | ) |
| $ | (0.02 | ) |
| $ | 68 |
|
| $ | 0.07 |
|
20192021 VS. 20182020
|
| Increase (Decrease) |
|
| Increase (Decrease) |
| ||||||||||
|
| Amount |
|
| EPS |
|
| Amount |
|
| EPS |
| ||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
SCANA Combination |
| $ | 430 |
|
| $ | 0.53 |
| ||||||||
|
|
|
|
|
|
|
|
| ||||||||
Weather |
| $ | (6 | ) |
| $ | (0.01 | ) | ||||||||
Customer usage and other factors |
|
| 34 |
|
|
| 0.04 |
| ||||||||
Customer-elected rate impacts |
|
| 10 |
|
|
| 0.01 |
| ||||||||
Base rate case & Natural Gas Rate Stabilization Act impacts |
|
| 13 |
|
|
| 0.02 |
| ||||||||
Capital cost rider |
|
| (6 | ) |
|
| (0.01 | ) | ||||||||
Depreciation and amortization |
|
| (9 | ) |
|
| (0.01 | ) | ||||||||
Interest expense, net |
|
| 7 |
|
|
| 0.01 |
| ||||||||
Salaries, wages and benefits & administrative costs |
|
| (46 | ) |
|
| (0.06 | ) | ||||||||
Other |
|
| 21 |
|
|
| 0.02 |
| ||||||||
Share accretion |
|
| — |
|
|
| 0.02 |
| ||||||||
Change in net income contribution |
| $ | 18 |
|
| $ | 0.03 |
|
Contracted Assets
Presented below are selected operating statistics related to Contracted Asset’s operations:
Year Ended December 31, |
| 2020 |
|
| % Change |
|
| 2019 |
|
| % Change |
|
| 2018 |
|
| 2022 |
|
| % Change |
|
| 2021 |
|
| % Change |
|
| 2020 |
| ||||||||||
Electricity supplied (million MWh) |
|
| 19.3 |
|
|
| (4 | ) | % |
| 20.2 |
|
|
| (30 | ) | % |
| 28.8 |
|
|
| 17.8 |
|
|
| (14 | ) | % |
| 20.8 |
|
|
| 8 |
| % |
| 19.3 |
|
Presented below, on an after-tax basis, are the key factors impacting Contracted Asset’s net income contribution:
20202022 VS. 20192021
|
| Increase (Decrease) |
| |||||
|
| Amount |
|
| EPS |
| ||
(millions, except EPS) |
|
|
|
|
|
| ||
Margin(1) |
| $ | 11 |
|
| $ | 0.01 |
|
Sale of non-wholly-owned nonregulated solar facilities |
|
| (20 | ) |
|
| (0.02 | ) |
Planned outage costs |
|
| (19 | ) |
|
| (0.02 | ) |
Renewable energy investment tax credits |
|
| (29 | ) |
|
| (0.04 | ) |
Interest expense, net |
|
| (50 | ) |
|
| (0.06 | ) |
Other |
|
| 11 |
|
|
| 0.02 |
|
Share dilution |
|
| — |
|
|
| (0.01 | ) |
Change in net income contribution |
| $ | (96 | ) |
| $ | (0.12 | ) |
|
| Increase (Decrease) |
| |||||
|
| Amount |
|
| EPS |
| ||
(millions, except EPS) |
|
|
|
|
|
|
|
|
Margin(1) |
| $ | (46 | ) |
| $ | (0.06 | ) |
Planned outage costs |
|
| (29 | ) |
|
| (0.04 | ) |
Renewable energy investment tax credits |
|
| 17 |
|
|
| 0.02 |
|
Interest expense, net |
|
| 13 |
|
|
| 0.02 |
|
Other |
|
| (13 | ) |
|
| (0.02 | ) |
Share dilution |
|
| — |
|
|
| (0.01 | ) |
Change in net income contribution |
| $ | (58 | ) |
| $ | (0.09 | ) |
72
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 | ) |
|
| — |
|
Share accretion |
|
| — |
|
|
| 0.01 |
|
Change in net income contribution |
| $ | 29 |
|
| $ | 0.05 |
|
(1) Includes earnings associated with a 50% noncontrolling interest in Cove Point.
|
|
2019 VS. 2018
|
| Increase (Decrease) |
| |||||
|
| Amount |
|
| EPS |
| ||
(millions, except EPS) |
|
|
|
|
|
|
|
|
Margin(1) |
| $ | 109 |
|
| $ | 0.17 |
|
Renewable energy investment tax credits |
|
| 50 |
|
|
| 0.08 |
|
Sale of certain electric generation facilities |
|
| (95 | ) |
|
| (0.15 | ) |
Interest expense |
|
| 26 |
|
|
| 0.04 |
|
Other |
|
| 9 |
|
|
| 0.01 |
|
Share dilution |
|
| — |
|
|
| (0.13 | ) |
Change in net income contribution |
| $ | 99 |
|
| $ | 0.02 |
|
|
|
Corporate and Other
Presented below are the Corporate and Other segment’s after-tax results:
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Specific items attributable to operating segments |
| $ | (1,241 | ) |
| $ | (1,901 | ) |
| $ | (196 | ) |
| $ | (2,777 | ) |
| $ | (493 | ) |
| $ | (1,241 | ) |
Specific items attributable to Corporate and Other segment |
|
| (2,166 | ) |
|
| 384 |
|
|
| 518 |
|
|
| 266 |
|
|
| 590 |
|
|
| (2,166 | ) |
Total specific items |
|
| (3,407 | ) |
|
| (1,517 | ) |
|
| 322 |
|
|
| (2,511 | ) |
|
| 97 |
|
|
| (3,407 | ) |
Other corporate operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Interest expense, net |
|
| (384 | ) |
|
| (383 | ) |
|
| (375 | ) |
|
| (329 | ) |
|
| (410 | ) |
|
| (384 | ) |
Other |
|
| 118 |
|
|
| 95 |
|
|
| 170 |
|
|
| 289 |
|
|
| 214 |
|
|
| 118 |
|
Total other corporate operations |
|
| (266 | ) |
|
| (288 | ) |
|
| (205 | ) |
|
| (40 | ) |
|
| (196 | ) |
|
| (266 | ) |
Total net income (expense) |
|
| (3,673 | ) |
|
| (1,805 | ) |
|
| 117 |
| ||||||||||||
Total net expense |
|
| (2,551 | ) |
|
| (99 | ) |
|
| (3,673 | ) | ||||||||||||
EPS impact |
| $ | (4.51 | ) |
| $ | (2.29 | ) |
| $ | 0.18 |
|
| $ | (3.22 | ) |
| $ | (0.20 | ) |
| $ | (4.51 | ) |
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 2022, this primarily included a $255 million after-tax benefit for derivative mark-to-market changes. In 2021, this primarily included $641 million of net income from discontinued operations, primarily associated with the Q-Pipe Group, a $64 million after-tax benefit for derivative mark-to-market changes, $62 million of after-tax charges for workplace realignment, primarily related to a corporate office lease termination, and $32 million of after-tax charges for merger and integration-related costs associated with the SCANA Combination. In 2020, this primarily included $2.2 billion of after-tax loss associated with discontinued operations, including the results of operations of the entities included in the GT&S and Q-Pipe Transactions as well as charges associated with the cancellation of the Atlantic Coast Pipeline Project, $82 million of after-tax charges for merger and integration-related costs associated with the SCANA Combination, a $78 million after-tax benefit of derivative mark-to-market changes and a $69 million tax benefit associated with the GT&S Transaction. In 2019, this
OUTLOOK
Dominion Energy’s 2023 net income is expected to increase on a per share basis as compared to 2022 primarily included $521 millionfrom the following:
VIRGINIA POWER
Results of Operations
Presented below is a summary of Virginia Power’s consolidated results:
Year Ended December 31, |
| 2020 |
|
| $ Change |
|
| 2019 |
|
| $ Change |
|
| 2018 |
| |||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
| $ | 1,021 |
|
| $ | (128 | ) |
| $ | 1,149 |
|
| $ | (133 | ) |
| $ | 1,282 |
|
Overview
2020 VS. 2019
Net income decreased 11%, primarily due to an increase in charges related to the planned early retirements of certain electric generation facilities, a charge for benefits expected to be provided to retail electric customers in Virginiadeemed recovered through the use of a CCRO in accordance with the GTSA, a charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020 and thebase rates;
These decreases wereincreases are expected to be partially offset by the absence of charges related to the planned early retirement of certain automated meter reading infrastructure, a voluntary retirement program and a contract termination with a non-utility generator.
2019 VS. 2018
Net income decreased 10%, primarily due to charges associated with the planned early retirement of certain electric generation facilities and automated meter reading infrastructure, a voluntary retirement program and a contract termination with a non-utility generator. These decreases were partially offset by increases related to higher rider equity returns, the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019 and the absence of charges associated with Virginia legislation enacted in March 2018 and April 2018.
Analysis of Consolidated Operations
Presented below are selected amounts related to Virginia Power’s results of operations:
Year Ended December 31, |
| 2020 |
|
| $ Change |
|
| 2019 |
|
| $ Change |
|
| 2018 |
| |||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 7,763 |
|
| $ | (345 | ) |
| $ | 8,108 |
|
| $ | 489 |
|
| $ | 7,619 |
|
Electric fuel and other energy-related purchases |
|
| 1,636 |
|
|
| (542 | ) |
|
| 2,178 |
|
|
| (140 | ) |
|
| 2,318 |
|
Purchased (excess) electric capacity |
|
| (17 | ) |
|
| (57 | ) |
|
| 40 |
|
|
| (82 | ) |
|
| 122 |
|
Other operations and maintenance |
|
| 1,786 |
|
|
| 43 |
|
|
| 1,743 |
|
|
| 67 |
|
|
| 1,676 |
|
Depreciation and amortization |
|
| 1,252 |
|
|
| 29 |
|
|
| 1,223 |
|
|
| 91 |
|
|
| 1,132 |
|
Other taxes |
|
| 327 |
|
|
| (1 | ) |
|
| 328 |
|
|
| 28 |
|
|
| 300 |
|
Impairment of assets and other charges |
|
| 1,093 |
|
|
| 336 |
|
|
| 757 |
|
|
| 757 |
|
|
| — |
|
Other income |
|
| 80 |
|
|
| (18 | ) |
|
| 98 |
|
|
| 76 |
|
|
| 22 |
|
Interest and related charges |
|
| 516 |
|
|
| (8 | ) |
|
| 524 |
|
|
| 13 |
|
|
| 511 |
|
Income tax expense |
|
| 229 |
|
|
| (35 | ) |
|
| 264 |
|
|
| (36 | ) |
|
| 300 |
|
An analysis of Virginia Power’s results of operations follows:
2020 VS. 2019
Operating revenue decreased 4%, primarily reflecting:following:
| • A |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric fuel and other energy-related purchases decreased 25%, primarily due to decreased fuel costs associated with electric utility retail customers ($561 million), which are offset in operating revenue and do not impact net income, partially offset by PJM off-system sales ($64 million) and the absence of various contracts ($34 million).
Purchased electric capacity decreased $57 million, primarily due to a decrease in expense related to the annual PJM capacity performance market effective June 2019 ($51 million) and a contract termination with a non-utility generator ($13 million) partially offset by an increase in expense related to the annual PJM capacity performance market effective June 2020 ($15 million).
Other operations and maintenance increased 2%, primarily reflecting:
|
|
|
|
|
|
|
|
These increases were partially offset by:
|
|
|
|
|
|
|
|
Depreciation and amortization increased 2%, primarily due to various projects being placed into service ($114 million), partially offset by the absence of depreciation from certain electric generation facilities that were, or have committed to be, retired early ($58 million) and a decrease reflecting the expected approval of the nuclear plant life extensions from the NRC ($31 million).
Impairment of assets and other charges increased 44%, primarily due to:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income decreased 18%, primarily reflecting a decrease in net investment earnings on nuclear decommissioning trust funds.
Income tax expense decreased 13%, primarily due to lower pre-tax income.
2019 VS. 2018
Operating revenue increased 6%, primarily reflecting:
|
|
|
|
|
|
|
|
Electric fuel and other energy-related purchases decreased 6% primarily due to decreased fuel costs associated with electric utility retail customers ($83 million), which are offset in operating revenue and do not impact net income, and a decrease in Virginia Power fuel costs due to the expiration of an energy supply contract ($40 million).
Purchased electric capacity decreased 67%, primarily due to a decrease in expense related to the annual PJM capacity performance market effective June 2019 ($63 million) and a contract termination with a non-utility generator ($37 million), partially offset by the annual PJM capacity performance market effective June 2018 ($26 million).
Other operations and maintenance increased 4%, primarily reflecting:
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization increased 8%, primarily due to various projects being placed into service ($92 million) and the absence of a benefit for the retroactive application of depreciation rates for regulated nuclear plants to comply with Virginia Commission requirements ($31 million), partially offset by the absence of depreciation from certain electric generation facilities and automated meter reading infrastructure that were retired early ($40 million).
Impairment of assets and other charges increased $757 million, primarily reflecting:
|
|
|
|
|
|
|
|
Other income increased $76 million, primarily reflecting an increase in net investment earnings on nuclear decommissioning trust funds.
Income tax expense decreased 12%, primarily due to lower pretax income ($29 million) and the absence of 2017 Tax Reform Act impacts ($23 million), partially offset by lower investment tax credits ($14 million).associated with nonregulated solar generation facilities;
73
LIQUIDITY AND CAPITAL RESOURCES
Dominion Energy depends on both internalcash generated from operations and external sources of liquidity to provide working capital and as a bridge to long-term debt financings. Short-termDominion Energy’s material cash requirements not met by cash provided by operationsinclude 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 generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.
At December 31, 2020, Dominion Energy had $5.3 billion of unused capacity under its credit facility. See additional discussion below under Credit Facilities and Short-Term Debt.
A summary ofselected amounts related to Dominion Energy’s cash flows is presented below:flows:
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Cash, restricted cash and equivalents at beginning of year |
| $ | 269 |
|
| $ | 391 |
|
| $ | 185 |
|
| $ | 408 |
|
| $ | 247 |
|
| $ | 269 |
|
Cash flows provided by (used in): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Operating activities |
|
| 5,227 |
|
|
| 5,204 |
|
|
| 4,773 |
|
|
| 3,700 |
|
|
| 4,037 |
|
|
| 5,227 |
|
Investing activities |
|
| (2,916 | ) |
|
| (4,622 | ) |
|
| (2,358 | ) |
|
| (6,746 | ) |
|
| (6,247 | ) |
|
| (2,916 | ) |
Financing activities |
|
| (2,333 | ) |
|
| (704 | ) |
|
| (2,209 | ) |
|
| 2,979 |
|
|
| 2,371 |
|
|
| (2,333 | ) |
Net increase (decrease) in cash, restricted cash and equivalents |
|
| (22 | ) |
|
| (122 | ) |
|
| 206 |
|
|
| (67 | ) |
|
| 161 |
|
|
| (22 | ) |
Cash, restricted cash and equivalents at end of year |
| $ | 247 |
|
| $ | 269 |
|
| $ | 391 |
|
| $ | 341 |
|
| $ | 408 |
|
| $ | 247 |
|
Operating Cash Flows
Net cash provided by Dominion Energy's operating activities increased $23decreased $337 million, including approximately $707inclusive of a $201 million decrease from discontinued operations. Net cash provided by continuing operations decreased $136 million, primarily due to litigation settlements relatedlower deferred fuel cost recoveries ($1.1 billion), current year refund payments to the SCANA Combination, higher contributions to Dominion Energy’s qualified pension plan, payments related to a voluntary retirement plan, and a contract termination in connectionVirginia electric customers associated with the salesettlement of Fowler Ridge,the 2021 Triennial Review ($319 million) and changes in working capital ($628 million), partially offset by lower margin deposits ($862 million) and an increase of $1.0 billion primarily as the absenceresult of a contract termination payment to a non-utility generator and net changes in other working capital items.
Dominion Energy believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In December 2020, Dominion Energy’s Board of Directors established an annual dividend rate for 2021 of $2.52 per share of common stock, a 33% decrease over the 2020 rate. This reduction in the annual dividend rate reflects the absence of income from operations sold to BHE as part of the GT&S Transaction and Q-Pipe Transaction as well as a revision to Dominion Energy’s target payout ratio to align with industry peers. Dividends are subject to declaration by the Board of Directors. In January 2021, Dominion Energy’s Board of Directors declared dividends payable in March 2021 of 63 cents per share of common stock.
Dominion Energy’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts ofhigher operating cash flows from electric utility and which are discussed in Item 1A. Risk Factors.gas distribution operations driven by riders, customer usage and other factors.
Credit Risk
Dominion Energy’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion Energy’s credit exposure as of December 31, 2020 for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.
|
| Gross Credit Exposure |
|
| Credit Collateral |
|
| Net Credit Exposure |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Investment grade(1) |
| $ | 68 |
|
| $ | — |
|
| $ | 68 |
|
Non-Investment grade(2) |
|
| 1 |
|
|
|
|
|
|
| 1 |
|
No external ratings: |
|
|
|
|
|
|
|
|
|
|
|
|
Internally rated—investment grade(3) |
|
| 35 |
|
|
| — |
|
|
| 35 |
|
Internally rated—non-investment grade(4) |
|
| 3 |
|
|
| — |
|
|
| 3 |
|
Total |
| $ | 107 |
|
| $ | — |
|
| $ | 107 |
|
|
|
|
|
|
|
|
|
Investing Cash Flows
Net cash used in Dominion Energy’s investing activities decreased $1.7 billion,increased $499 million, primarily due to proceeds from the GT&S and Q-Pipe Transactions, partially offset by an increase in plant construction and other property additions ($1.6 billion) and the absence of cash acquired in the SCANA Combination, the acquisition of an investment in Pivotal LNG, Inc. and an additional 5% investment in Atlantic Coast Pipeline and a decrease in the proceeds from the sale of assetsQ-Pipe Group ($1.5 billion) and the sale of non-wholly-owned nonregulated solar facilities ($495 million), partially offset by the absence of the repayment of the Q-Pipe Transaction deposit ($1.3 billion), a decrease in contributions to equity method investments.affiliates including Atlantic Coast Pipeline ($978 million) and net proceeds from the sale of Hope ($727 million).
Financing Cash Flows
Net cash provided by Dominion Energy's financing activities increased $608 million primarily due to settlement of the stock purchase contract component of the 2019 Equity Units ($1.6 billion), higher net issuances of long-term debt ($927 million) and Liquidityhigher net supplemental credit facility borrowings ($450 million), partially offset by the redemption of the Series A Preferred Stock ($1.6 billion) in 2022 and the absence of the issuance of Series C Preferred Stock ($742 million) in 2021.
Credit Facilities and Short-Term Debt
Dominion Energy reliesgenerally 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 capital markets as significant sourcesthe timing and amount of funding for capitalcash requirements not satisfied by cash provided by itsfrom operations. As discussed in Credit Ratings,A description of Dominion Energy’s abilityprimary available sources of short-term liquidity follows.
74
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, 2022 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Joint revolving credit facility(2) |
| $ | 6,000 |
|
| $ | 3,076 |
|
| $ | 202 |
|
| $ | 2,722 |
|
Dominion Energy Reliability InvestmentSM Program
Dominion Energy has an effective registration statement with the SEC for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability InvestmentSM. The registration limits the principal amount that may be outstanding at any one time to $1.0 billion. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Dominion Energy Reliability Investment Committee, or its designee, on a weekly basis. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Dominion Energy or at the investor’s option at any time. At December 31, 2022, Dominion Energy’s Consolidated Balance Sheets include $347 million presented within short-term debt, with a weighted-average interest rate of 4.24%. The proceeds are used for general corporate purposes and to repay debt.
Other Facilities
In addition to the primary sources of short-term liquidity discussed above, from time to time Dominion Energy enters into separate supplementary credit facilities or term loans as discussed in Note 17 to the Consolidated Financial Statements.
In January 2023, Dominion Energy entered into a $2.5 billion 364-Day term loan facility which bears interest at a variable rate and will mature in January 2024 with the proceeds to be used to repay existing long-term debt and short-term debt upon maturity and for other general corporate purposes. Concurrently, Dominion Energy borrowed an initial $1.0 billion with the proceeds used to repay long-term debt. Dominion Energy may make up to two additional borrowings under this agreement through March 31, 2023, at which point any unused capacity will cease to be available to Dominion Energy.
Long-Term Debt
Sustainability Revolving Credit Facility
Dominion Energy maintains a $900 million Sustainability Revolving Credit Facility which matures in 2024 and bears interest at a variable rate. The facility offers a reduced interest rate margin with respect to borrowed amounts allocated to certain issuances.environmental sustainability or social investment initiatives. In May 2022, Dominion Energy borrowed $900 million with the proceeds used to support environmental sustainability and social investment initiatives ($450 million) and for general corporate purposes ($450 million). In June 2022, Dominion Energy repaid $450 million borrowed for general corporate purposes. At December 31, 2022, Dominion Energy had $450 million outstanding under this supplemental credit facility.
Issuances and Borrowings of Long-Term Debt
During 2022, Dominion Energy issued or borrowed the following long-term debt. Unless otherwise noted, the proceeds were used for the repayment of existing long-term indebtedness and for general corporate purposes.
75
Month |
| Type |
| Public / Private |
| Entity |
| Principal |
|
| Rate |
|
| Stated Maturity | ||
|
|
|
|
|
|
|
| (millions) |
|
|
|
|
|
| ||
January |
| Senior notes |
| Public |
| Virginia Power |
| $ | 600 |
|
|
| 2.400 | % |
| 2032 |
January |
| Senior notes |
| Public |
| Virginia Power |
|
| 400 |
|
|
| 2.950 | % |
| 2051 |
May |
| Senior notes |
| Public |
| Virginia Power |
|
| 600 |
|
|
| 3.750 | % |
| 2027 |
May |
| Senior notes |
| Public |
| Virginia Power |
|
| 600 |
|
|
| 4.625 | % |
| 2052 |
August |
| Senior notes |
| Public |
| Dominion Energy |
|
| 400 |
|
|
| 4.350 | % |
| 2032 |
August |
| Senior notes |
| Public |
| Dominion Energy |
|
| 600 |
|
|
| 4.850 | % |
| 2052 |
August |
| Senior notes |
| Private |
| Questar Gas |
|
| 125 |
|
|
| 4.390 | % |
| 2032 |
August |
| Senior notes |
| Private |
| Questar Gas |
|
| 125 |
|
|
| 4.700 | % |
| 2052 |
November |
| Senior notes |
| Public |
| Dominion Energy |
|
| 850 |
|
|
| 5.375 | % |
| 2032 |
December |
| Senior notes |
| Private |
| East Ohio |
|
| 250 |
|
|
| 6.190 | % |
| 2032 |
December |
| Senior notes |
| Private |
| East Ohio |
|
| 250 |
|
|
| 6.380 | % |
| 2052 |
Total issuances and borrowings |
|
|
|
|
| $ | 4,800 |
|
|
|
|
|
|
Dominion Energy currently meets the definition of a well-known seasoned issuer under SEC rules governing the registration, communications and offering processes under the Securities Act of 1933, as amended. The rules provide for a streamlined shelf registration process to provide registrants with timely access to capital. This allows Dominion Energy to use automatic shelf registration statements to register any offering of securities, other than those for exchange offers or business combination transactions.
FromAs the comprehensive business review announced in November 2022 is still in progress, Dominion Energy is uncertain as to the amount of long-term debt it anticipates issuing in 2023. Dominion Energy expects to issue long-term debt to satisfy cash needs for capital expenditures and maturing long-term debt to the extent such amounts are not satisfied from cash available from operations following the payment of dividends and any borrowings made from unused capacity of Dominion Energy’s credit facilities discussed above. The raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.
Repayments, Repurchases and Redemptions of Long-Term Debt
Dominion Energy may from time to time Dominion Energy may reduce its outstanding debt and level of interest expense through redemption of debt securities prior to maturity andor repurchases of debt securities in the open market, in privately negotiated transactions, through tender offers or otherwise.
NetThe following long-term debt was repaid, repurchased or redeemed in 2022:
Month |
| Type |
| Entity |
| Principal |
| (1) | Rate |
|
| Stated Maturity | ||
|
|
|
|
|
| (millions) |
|
|
|
|
|
| ||
Debt scheduled to mature in 2022 |
|
|
| $ | 806 |
|
| various |
|
|
| |||
Early repurchases & redemptions |
|
|
|
|
|
|
|
|
|
| ||||
July |
| Senior notes |
| Dominion Energy |
|
| 5 |
|
|
| 4.250 | % |
| 2028 |
Multiple |
| Senior notes |
| Dominion Energy |
|
| 147 |
|
|
| 2.250 | % |
| 2031 |
Multiple |
| Senior notes |
| Dominion Energy |
|
| 35 |
|
|
| 3.300 | % |
| 2041 |
Multiple |
| Senior notes |
| Dominion Energy |
|
| 37 |
|
|
| 1.450 | % |
| 2026 |
Multiple |
| Senior notes |
| Dominion Energy |
|
| 9 |
|
|
| 4.700 | % |
| 2044 |
Multiple |
| Senior notes |
| Dominion Energy |
|
| 30 |
|
|
| 4.600 | % |
| 2049 |
Total repayments, repurchases and redemptions |
|
|
| $ | 1,069 |
|
|
|
|
|
|
See Note 18 to the Consolidated Financial Statements for additional information regarding scheduled maturities and other cancellations of Dominion Energy’s long-term debt, including related average interest rates.
Remarketing of Long-Term Debt
In April 2022, Virginia Power remarketed two series of tax-exempt bonds, with an aggregate outstanding principal of approximately $138 million to new investors. Both bonds will bear interest at a coupon of 1.65% until May 2024, after which they will bear interest at a market rate to be determined at that time.
76
In October 2022, Dominion Energy remarketed its $27 million Peninsula Ports Authority of Virginia Coal Terminal Revenue Refunding Bonds, Series 2003 due in 2033 to new investors. The bonds will bear interest at a coupon rate of 3.80% until October 2024, after which they will bear interest at a market rate to be determined at that time.
In 2023, Dominion Energy expects to remarket approximately $160 million of its tax-exempt bonds.
Credit Ratings
Dominion Energy’s credit ratings affect its liquidity, cost of borrowing under credit facilities and collateral posting requirements under commodity contracts, as well as the rates at which it is able to offer its debt securities. The credit ratings for Dominion Energy are affected by its financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and event risk, if applicable, such as major acquisitions or dispositions.
Credit ratings and outlooks as of February 17, 2023 are as follows:
Fitch | Moody's | Standard & Poor's | ||||
Dominion Energy | ||||||
Issuer | BBB+ | Baa2 | BBB+ | |||
Senior unsecured debt securities | BBB+ | Baa2 | BBB | |||
Junior subordinated notes | BBB | Baa3 | BBB | |||
Enhanced junior subordinated notes | BBB- | Baa3 | BBB- | |||
Preferred stock | BBB- | Ba1 | BBB- | |||
Commercial paper | F2 | P-2 | A-2 | |||
Outlook | Stable | Stable | Stable |
A credit rating is not a recommendation to buy, sell or hold securities and should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the applicable rating organization.
Financial Covenants
As part of borrowing funds and issuing both short-term and long-term debt or preferred securities, Dominion Energy must enter into enabling agreements. These agreements contain customary covenants that, in the event of default, could result in the acceleration of principal and interest payments; restrictions on distributions related to capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to Dominion Energy.
Dominion Energy is required to pay annual commitment fees to maintain its joint revolving credit facility. In addition, the credit agreement contains various terms and conditions that could affect Dominion Energy’s ability to borrow under the facility. They include a maximum debt to total capital ratio, which is also included in Dominion Energy's financing activities increased $1.6 billion primarily dueEnergy’s Sustainability Revolving Credit Agreement entered into in 2021 and 364-Day term loan facility entered into in January 2023, and cross-default provisions.
As of December 31, 2022, the calculated total debt to repurchasestotal capital ratio, pursuant to the terms of the agreements, was as follows:
Company |
| Maximum Allowed Ratio |
|
| Actual Ratio(1) |
| ||
Dominion Energy |
|
| 67.5 | % |
|
| 59.7 | % |
If Dominion Energy or any of its material subsidiaries fails to make payment on various debt obligations in excess of $100 million, the lenders could require the defaulting company, if it is a borrower under Dominion Energy’s joint revolving credit facility, to accelerate its repayment of any outstanding borrowings and the lenders could terminate their commitments, if any, to lend funds to that company under the credit facility. In addition, if the defaulting company is Virginia Power, Dominion Energy’s obligations to repay any outstanding borrowing under the credit facility could also be accelerated and the lenders’ commitments to Dominion Energy could terminate.
Dominion Energy monitors compliance with these covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2022, there have been no events of default under Dominion Energy’s covenants.
77
Common Stock, Preferred Stock and Other Equity Securities
Issuances of Equity Securities
Dominion Energy maintains Dominion Energy Direct® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In 2021, Dominion Energy began issuing new shares of common stock in 2020, lower issuancesfor these direct stock purchase plans. During 2022, Dominion Energy issued 2.4 million of such shares and received proceeds of $179 million.
Dominion Energy also maintains sales agency agreements to effect sales under an at-the-market program. Under the sales agency agreements, Dominion Energy may, from time to time, offer and sell shares of its common stock through the absencesales agents or enter into one or more forward sale agreements with respect to shares of its common stock. Sales by Dominion Energy through the sales agents or by forward sellers pursuant to a forward sale agreement cannot exceed $1.0 billion in the aggregate. In November 2021, Dominion Energy entered forward sale agreements for approximately 1.1 million shares of its common stock to be settled by November 2022 at an initial forward price of $74.66 per share. Except in certain circumstances, Dominion Energy could have elected physical, cash or net settlement of the forward sale agreements. In November 2022, Dominion Energy provided notice to elect physical settlement of the forward sale agreements and in December 2022 received total proceeds of $78 million.
In addition, Dominion Energy issued shares of its common and preferred stock, as discussed in Notes 19 and 20 to the Consolidated Financial Statements, respectively, as follows:
As the comprehensive business review announced in November 2022 is still in progress, Dominion Energy is uncertain as to the amount of common stock that it anticipates issuing in 2023, including through its at-the-market program. However, Dominion Energy anticipates raising similar amounts of capital through Dominion Energy Direct® in 2023 compared to 2022 and 2021. The raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.
Repurchases of Equity Securities
In November 2020, the Board of Directors authorized the repurchase of up to $1.0 billion of Dominion Energy’s common stock. This repurchase program does not include a specific timetable or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors. At December 31, 2022, Dominion Energy had $920 million of available capacity under this authorization.
Dominion Energy does not plan to repurchase shares of common stock in 2023, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which does not impact the available capacity under its stock repurchase authorization.
In September 2022, Dominion Energy redeemed all outstanding shares of Series BA Preferred Stock issuances andfor $1.6 billion.
Capital Expenditures
See Note 26 to the absence of proceeds from the sale of a 25% noncontrolling interest in Cove Point, partially offsetConsolidated Financial Statements for Dominion Energy’s historical capital expenditures by higher issuances and lower repayments of long-term debt.
Credit Facilities and Short-Term Debt
segment. Dominion Energy uses short-term debtincluded its total annual planned capital expenditures by each segment for 2022 through 2026 in Item 7. MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 24, 2022. As disclosed therein, Dominion Energy’s total planned capital expenditures were $10.3 billion for 2023, $10.7 billion for 2024, $10.6 billion for 2025 and $7.7 billion for 2026 based on a capital expenditures plan reviewed and endorsed by Dominion Energy’s Board of Directors in December 2021. As a result of the comprehensive business review announced in November 2022, Dominion Energy has not completed an update to fund working capital requirementsits previous plan and, as a bridge to long-term debt financings. The levels of borrowing may vary significantly duringdiscussed in Future Issues and Other Matters, the courseimplementation of the year, depending upon
78
recommendations could result in a material adjustment to capital allocations. Currently, Dominion Energy expects the timing and amount of cash requirements not satisfied by cash from operations.total planned capital expenditures for 2023 to be substantially consistent with the previously disclosed amount. In addition, Dominion Energy utilizesexpects its next capital expenditures plan to reflect an acceleration of electric transmission projects within Dominion Energy Virginia to serve the rapidly growing data center customer demand and a decreased investment in new nonregulated solar generation facilities within Contracted Assets.
Dominion Energy’s planned growth expenditures are subject to approval by the Board of Directors as well as potentially by regulatory bodies based on the individual project and are expected to include significant investments in support of its clean energy profile. See Dominion Energy Virginia, Gas Distribution, Dominion Energy South Carolina and Contracted Assets in Item 1. Business for additional discussion of various significant capital projects currently under development. The estimates disclosed above are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. Dominion Energy may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.
Dividends
Dominion Energy believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and lettersmaintain or grow the dividend on common shares. In December 2022, Dominion Energy’s Board of creditDirectors established an annual dividend rate for 2023 of $2.67 per share of common stock, consistent with the 2022 rate. Dividends are subject to fund collateral requirements. declaration by the Board of Directors. In February 2023, Dominion Energy’s Board of Directors declared dividends payable in March 2023 of 66.75 cents per share of common stock.
See Note 19 to the Consolidated Financial Statements for a discussion of Dominion Energy’s outstanding preferred stock and associated dividend rates.
Subsidiary Dividend Restrictions
Certain of Dominion Energy’s subsidiaries may, from time to time, be subject to certain restrictions imposed by regulators or financing arrangements on their ability to pay dividends, or to advance or repay funds, to Dominion Energy. At December 31, 2022, these restrictions did not have a significant impact on Dominion Energy’s ability to pay dividends on its common or preferred stock or meet its other cash obligations.
See Note 21 to the Consolidated Financial Statements for a description of such restrictions and any other restrictions on Dominion Energy’s ability to pay dividends.
Collateral and Credit Risk
Collateral requirements are impacted by commodity prices, hedging levels, Dominion Energy’s credit ratings and the credit quality of its counterparties.
In connection with commodity hedging activities, Dominion Energy is required to provide collateral to counterparties under some circumstances. Under certain collateral arrangements, Dominion Energy may satisfy these requirements by electing to either deposit cash, post letters of credit or, in some cases, utilize other forms of security. From time to time, Dominion Energy may vary the form of collateral provided to counterparties after weighing the costs and benefits of various factors associated with the different forms of collateral. These factors include short-term borrowing and short-term investment rates, the spread over these short-term rates at which Dominion Energy can issue commercial paper, balance sheet impacts, the costs and fees of alternative collateral postings with these and other counterparties and overall liquidity management objectives.
Dominion Energy’s commercial paper and lettersexposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion Energy’s credit exposure as of December 31, 2022 for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.
|
| Gross Credit |
|
| Credit |
|
| Net Credit |
| |||
(millions) |
|
|
|
|
|
|
|
|
| |||
Investment grade(1) |
| $ | 191 |
|
| $ | — |
|
| $ | 191 |
|
Non-Investment grade(2) |
|
| 37 |
|
|
| 20 |
|
|
| 17 |
|
No external ratings: |
|
|
|
|
|
|
|
|
| |||
Internally rated—investment grade(3) |
|
| 58 |
|
|
| — |
|
|
| 58 |
|
Internally rated—non-investment grade(4) |
|
| 28 |
|
|
| 13 |
|
|
| 15 |
|
Total |
| $ | 314 |
|
| $ | 33 |
|
| $ | 281 |
|
79
|
| Facility Limit |
|
| Outstanding Commercial Paper(1) |
|
| Outstanding Letters of Credit |
|
| Facility Capacity Available |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility(2) |
| $ | 6,000 |
|
| $ | 627 |
|
| $ | 100 |
|
| $ | 5,273 |
|
Fuel and Other Purchase Commitments
|
|
|
|
Dominion Energy has an effective registration statement with the SECis party to various contracts for the sale of upfuel and purchased power commitments related to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability InvestmentSM. The registration limits the principal amount that may be outstandingboth its regulated and nonregulated operations. Total estimated costs for such commitments at any one time to $1.0 billion. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Dominion Energy Reliability Investment Committee, or its designee, on a weekly basis. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Dominion Energy or at the investor’s option at any time. At December 31, 2020, Dominion Energy’s Consolidated Balance Sheets include $268 million2022 are presented within short-term debt. The proceeds are usedin the table below. These costs represent estimated minimum obligations for general corporate purposesvarious purchased power and to repay debt.capacity agreements and actual costs may differ from amounts presented below depending on actual quantities purchased and prices paid.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
|
| 2023 |
|
| 2024 |
|
| 2025 |
|
| 2026 |
|
| 2027 |
|
| Total |
| |||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Purchased electric capacity for utility operations |
| $ | 71 |
|
| $ | 70 |
|
| $ | 70 |
|
| $ | 72 |
|
| $ | 73 |
|
| $ | 356 |
|
Fuel commitments for utility operations |
|
| 1,669 |
|
|
| 995 |
|
|
| 599 |
|
|
| 185 |
|
|
| 184 |
|
|
| 3,632 |
|
Fuel commitments for nonregulated operations |
|
| 198 |
|
|
| 133 |
|
|
| 46 |
|
|
| 37 |
|
|
| 50 |
|
|
| 464 |
|
Pipeline transportation and storage |
|
| 668 |
|
|
| 587 |
|
|
| 489 |
|
|
| 427 |
|
|
| 376 |
|
|
| 2,547 |
|
Total |
| $ | 2,606 |
|
| $ | 1,785 |
|
| $ | 1,204 |
|
| $ | 721 |
|
| $ | 683 |
|
| $ | 6,999 |
|
In March 2020, Dominion Energy entered into a $900 million 364-Day Revolving Credit Agreement. The agreement bears interest at a variable rate. At December 31, 2020, $225 million was outstanding under the agreement. The proceeds from these borrowings were used to provide for general working capital and other general corporate purposes. The maximum allowed total debt to total capital ratio under this agreement is consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility.
Other Material Cash Requirements
In March 2020, Dominion Energy borrowed $500 million under a 364-Day Term Loan Credit Agreement that bore interest at a variable rate. The proceeds were used to provide for general working capital and other general corporate purposes. In November 2020, Dominion Energy repaid the outstanding balance in full.
In April 2020, Dominion Energy borrowed $625 million under a 364-Day Term Loan Credit Agreement that bore interest at a variable rate. The proceeds were used to provide for general working capital and other general corporate purposes. In June 2020, Dominion Energy repaid the outstanding balance in full.
Long-Term Debt
During 2020, Dominion Energy issued the following long-term public debt:
Type |
| Issuer |
| Principal |
|
| Rate |
|
| Maturity | ||
|
|
|
| (millions) |
|
|
|
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Senior notes |
| Dominion Energy |
| $ | 1,000 |
|
| variable |
|
| 2023 | |
Senior notes |
| Dominion Energy |
|
| 400 |
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|
| 3.300 | % |
| 2025 |
Senior notes |
| Dominion Energy |
|
| 350 |
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|
| 3.600 | % |
| 2027 |
Senior notes |
| Dominion Energy |
|
| 1,500 |
|
|
| 3.375 | % |
| 2030 |
Senior notes |
| Virginia Power |
| 900 |
|
|
| 2.450 | % |
| 2050 | |
Total notes issued |
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| $ 4,150 |
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During 2020, Dominion Energy also issued the following long-term private debt:
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During 2020, Dominion Energy also remarketed the following long-term debt:
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During 2020, Dominion Energy repaid, repurchased or redeemed $2.9 billion of long-term debt, including redemption premiums. The following long-term debt was repaid, repurchased or redeemed before its stated maturity:
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In addition, in 2020 both Dominion Energy and Virginia Power amended portfolios of interest rate swaps extending the mandatory termination dates resulting in an increase in long-term debt. See Note 18 to the Consolidated Financial Statements for more information.
In February 2021, PSNC entered into an agreement with certain investors to issue through private placement in March 2021, $150 million 3.10% 30-year senior notes. The proceeds will be used for the repayment of existing indebtedness and for general corporate purposes.
Issuance of Common Stock
During 2020, Dominion Energy issued approximately 6.7 million shares of common stock, valued at $520 million, for a litigation settlement and through various programs including Dominion Energy Direct®.
Dominion Energy maintains Dominion Energy Direct® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In August 2020, Dominion Energy began purchasing its common stock on the open market for these direct stock purchase plans. In January 2021, Dominion Energy began issuing new shares of common stock for these direct stock purchase plans. During 2020, Dominion Energy received cash of $159 million from the issuance of 2.1 million of such shares through Dominion Energy Direct® and employee savings plans.
In September 2020, Dominion Energy issued 4.1 million shares of its common stock to satisfy its obligation under a settlement agreement for the Santee Cooper Ratepayer Case discussed in Note 20 to the Consolidated Financial Statements. These shares were immediately repurchased as discussed below.
In August 2020, Dominion Energy entered into sales agency agreements to effect sales under a new at-the-market program. Under the sales agency agreements, Dominion Energy may, from time to time, offer and sell shares of its common stock through the sales agents or enter into one or more forward sale agreements with respect to shares of its common stock. Sales by Dominion Energy through the sales agents or by forward sellers pursuant to a forward sale agreement cannot exceed $1.0 billion in the aggregate. Dominion Energy has not issued any shares or entered into any forward sale agreements under this new program.
Repurchase of Common Stock
During 2020, Dominion Energy repurchased 38.9 million shares of Dominion Energy common stock for $3.1 billion through an open market agreement, accelerated share repurchase agreements and a private transaction as discussed below.
In July 2020, in contemplation of Dominion Energy entering the July 2020 agreement to sell substantially all of its gas transmission and storage operations to BHE, the Board of Directors authorized the repurchase of up to $3.0 billion of Dominion Energy’s common stock and rescinded its prior repurchase authorization approved in February 2005 and modified in June 2007. Dominion Energy completed repurchases under this authorization in December 2020. In November 2020, the Board of Directors authorized the repurchase of up to $1.0 billion of Dominion Energy’s common stock in addition to the repurchase program authorized in July 2020. This repurchase program does not include a specific timetable or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors.
In August 2020, Dominion Energy began repurchasing shares under an open market agreement with a financial institution. Through the end of 2020, Dominion Energy repurchased 10.9 million shares of Dominion Energy common stock for $857 million.
In September 2020, Dominion Energy entered into two prepaid accelerated share repurchase agreements and made payments totaling $1.5 billion for the ultimate receipt of 18.6 million shares of Dominion Energy common stock. In December 2020, Dominion Energy entered into another prepaid accelerated share repurchase agreement and paid $400 million for the ultimate receipt of 5.3 million shares of Dominion Energy common stock.
In September 2020, Dominion Energy repurchased 4.1 million shares of Dominion Energy common stock in a private transaction for $323 million.
See Note 20 to the Consolidated Financial Statements for more information.
Credit Ratings
Dominion Energy’s credit ratings affect its liquidity, cost of borrowing under credit facilities and collateral posting requirements under commodity contracts, as well as the rates at which it is able to offer its debt securities. The credit ratings for Dominion Energy are affected by its financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and event risk, if applicable, such as major acquisitions or dispositions.
Credit ratings and outlooks as of February 22, 2021 follow:
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A credit rating is not a recommendation to buy, sell or hold securities and should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the applicable rating organization.
Debt Covenants
As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, Dominion Energy must enter into enabling agreements. These agreements containcustomary covenants that, in the event of default, could result in the acceleration of principal and interest payments; restrictions on distributions related to capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to Dominion Energy.
Dominion Energy is required to pay annual commitment fees to maintain its joint revolving credit facility. In addition, the credit agreement contains various terms and conditions that could affect Dominion Energy’s ability to borrow under the facility. They include a maximum debt to total capital ratio and cross-default provisions.
As of December 31, 2020, the calculated total debt to total capital ratio, pursuant to the terms of the agreement, was as follows:
Company |
| Maximum Allowed Ratio |
|
| Actual Ratio(1) |
| ||
Dominion Energy |
|
| 67.5 | % |
|
| 55.2 | % |
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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 credit facility, to accelerate its repayment of any outstanding borrowings and the lenders could terminate their commitments, if any, to lend funds to that company under the credit facility. In addition, if the defaulting company is Virginia Power, Dominion Energy’s obligations to repay any outstanding borrowing under the credit facility could also be accelerated and the lenders’ commitments to Dominion Energy could terminate.
The term loan and revolving credit agreements Dominion Energy entered into in the first quarter of 2020 have a maximum allowed total debt to total capital ratio consistent with the ratio under the credit facility discussed above.
Dominion Energy monitors compliance with these debt covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2020, there have been no events of default under Dominion Energy’s debt covenants.
Subsidiary Dividend Restrictions
Certain of Dominion Energy’s subsidiaries may, from time to time, be subject to certain restrictions imposed by regulators or financing arrangements on their ability to pay dividends, or to advance or repay funds, to Dominion Energy. At December 31, 2020, these restrictions did not have a significant impact on Dominion Energy’s ability to pay dividends on its common stock or meet its other cash obligations.
See Note 21 to the Consolidated Financial Statements for a description of such restrictions and any other restrictions on Dominion Energy’s ability to pay dividends.
Future Cash Payments for Contractual Obligations and Planned Capital Expenditures
Contractual Obligations
discussed above, Dominion Energy is party to numerous contracts and arrangements obligating it to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services and financial derivatives. Presented below is a table summarizing cash payments that may result from contracts to which Dominion Energy is a party as of December 31, 2020. For purchase obligations and otherexpects current liabilities amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actualpaid within the next twelve months. In addition to the items already discussed, the following represent material expected cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts presented below. The table excludes all amounts classified as current liabilities in therequirements recorded on Dominion Energy’s Consolidated Balance Sheets other than current maturities of long-term debt, interest payable and certain derivative instruments. The majority of Dominion Energy’s current liabilities will be paid in cash in 2021.
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| 2022- |
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| 2024- |
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| 2026 and |
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| |||
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| 2021 |
|
| 2023 |
|
| 2025 |
|
| thereafter |
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| Total |
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(millions) |
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|
Long-term debt(1) |
| $ | 2,110 |
|
| $ | 4,519 |
|
| $ | 3,583 |
|
| $ | 25,284 |
|
| $ | 35,496 |
|
Interest payments(2) |
|
| 1,472 |
|
|
| 2,642 |
|
|
| 2,430 |
|
|
| 17,837 |
|
|
| 24,381 |
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Leases |
|
|
|
|
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|
|
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|
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Operating Leases |
|
| 64 |
|
|
| 103 |
|
|
| 74 |
|
|
| 756 |
|
|
| 997 |
|
Finance Leases |
|
| 36 |
|
|
| 66 |
|
|
| 50 |
|
|
| 14 |
|
|
| 166 |
|
Purchase obligations(3): |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased electric capacity for utility operations |
|
| 67 |
|
|
| 133 |
|
|
| 132 |
|
|
| 753 |
|
|
| 1,085 |
|
Fuel commitments for utility operations |
|
| 1,056 |
|
|
| 726 |
|
|
| 327 |
|
|
| 799 |
|
|
| 2,908 |
|
Fuel commitments for nonregulated operations |
|
| 223 |
|
|
| 214 |
|
|
| 174 |
|
|
| 279 |
|
|
| 890 |
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Pipeline transportation and storage |
|
| 567 |
|
|
| 908 |
|
|
| 677 |
|
|
| 2,913 |
|
|
| 5,065 |
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Other(4) |
|
| 604 |
|
|
| 34 |
|
|
| 9 |
|
|
| 26 |
|
|
| 673 |
|
Other long-term liabilities(5): |
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Other contractual obligations(6) |
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| 7 |
|
|
| 28 |
|
|
| 1 |
|
|
| 3 |
|
|
| 39 |
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Total cash payments |
| $ | 6,206 |
|
| $ | 9,373 |
|
| $ | 7,457 |
|
| $ | 48,664 |
|
| $ | 71,700 |
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Planned Capital Expenditures
Dominion Energy’s planned capital expenditures, including contributions for equity method investments, are expected to total approximately $8.1 billion, $7.4 billion and $8.7 billion in 2021, 2022 and 2023, respectively. Dominion Energy’s planned expenditures are expected to include construction and expansion of electric generation, including renewable energy, and natural gas distribution, construction improvements and expansion of electric transmission and distribution assets, purchases of nuclear fuel and maintenance.
Dominion Energy expects to fund its capital expenditures with cash from operations and a combination of securities issuances and short-term borrowings. Planned capital expenditures include capital projects that are subject to approval by regulators and the Board of Directors.
See Dominion Energy Virginia, Gas Distribution, Dominion Energy South Carolina and Contracted Assets -Properties in Item 1. Business for a discussion of Dominion Energy’s expansion plans.
The above estimates are based on a capital expenditures plan reviewed and endorsed by Dominion Energy’s Board of Directors in late 2020 and are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. Dominion Energy may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.
Use of Off-Balance Sheet Arrangements
Corporate Office Leasing Arrangement
In December 2019, Dominion Energy signed an agreement with a lessor, as amended in May 2020, to construct and lease a new corporate office property in Richmond, Virginia. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $465 million, to fund the estimated project costs. If Dominion Energy ultimately proceeds with the project through completion, the project is expected to be completed by September 2024. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs, which totaled $61 million as of December 31, 2020. If the project is terminated under certain events, Dominion Energy could be required to pay up to 100% of the then funded amount.2022. Such obligations include:
The
Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.
Offshore Wind Vessel Leasing Arrangement
In December 2020, Dominion Energy signed an agreement with a lessor to complete construction of and lease a Jones Act compliant offshore wind installation vessel. This vessel is designed to handle current turbine technologies as well as next generation turbines. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $550 million, to fund the estimated project costs. The project is expected to be completed by the end of 2023. Dominion Energy has been appointed to act as the
construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs, which totaled $187 million as of December 31, 2020. If the project is terminated under certain events of default, Dominion Energy could be required to pay up to 100% of the then funded amount.•
The initial lease term will commence once construction is substantially complete and the vessel is delivered and will mature in November 2027. At the end of the initial lease term, Dominion Energy can (i) extend the term of the lease for an additional term, subject
Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.
Guarantees
Dominion Energy primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the provisions of FASB guidance that dictate a guarantor’s accounting and disclosure requirements for guarantees, including indirect guarantees of indebtedness of others
In addition, Dominion Energy 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:
FUTURE ISSUES AND OTHER MATTERS
See Item 1. Business and Notes 13 and 23 to the Consolidated Financial Statements for additional information on various environmental, regulatory, legal and other matters that may impact future results of operations, financial condition and/or cash flows.
Environmental MattersBusiness Review
In November 2022, Dominion Energy announced the commencement of a business review of value-maximizing strategic business actions, alternatives to its current business mix and capital allocation and regulatory options which may assist customers to manage costs and provide greater predictability to its long-term, state-regulated utility value proposition. While the ultimate impacts cannot be estimated until the review is completed, which is expected in 2023, implementation of recommendations resulting from the business review could have a material impact on Dominion Energy's future results of operations, financial condition and/or cash flows.
Potential Virginia Legislation
The 2023 General Assembly session in Virginia has included several proposals which, if ultimately enacted into law, could have a material impact on Virginia Power’s retail base rates and other cost-recovery mechanisms. Items under consideration include the frequency of base rate reviews, eliminating CCROs, shifting recovery of certain costs currently recovered through riders into base
80
rates and adjusting the parameters for determining an acceptable ROE and revenue sharing. Other topics include securitization of deferred fuel costs, offshore wind financing and small modular reactors. As the legislative process remains underway, Dominion Energy is subjectunable to costs resulting from a number of federal, state and local laws and regulations designed to protect human health andestimate the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.
Environmental Protection and Monitoring Expenditures
Dominion Energy incurred $238 million, $260 million and $198 million of expenses (including accretion and depreciation) during 2020, 2019, and 2018 respectively, in connection with environmental protection and monitoring activities. Dominion Energy expects these expenses to be approximately $234 million and $231 million in 2021 and 2022, respectively. In addition, capital expenditurespotential financial statement impacts related to environmental controls were $58 million, $134 million, and $104 million for 2020, 2019, and 2018, respectively. Dominion Energy expects these expendituresmatters currently under consideration by the Virginia General Assembly, but there could be a material impact to be approximately $63 million and $81 million for 2021 and 2022, respectively.its results of operations, financial condition and/or cash flows.
Future Environmental Regulations
Climate Change
The federal government and several states in which Dominion Energy operates have announced a commitment to achieving carbon reduction goals. In February 2021, the U.S. rejoined the Paris Agreement, which establishes a universal framework for addressing GHG emissions. States may also enact legislation relating to climate change matters such as the reduction of GHG emissions and renewable energy portfolio standards, similar to the VCEA. To the extent legislation is enacted at the federal or state level that is more restrictive than the VCEA and/or Dominion Energy’s commitment to achieving net zero emissions by 2050, compliance with such legislation could have a material impact to Dominion Energy’s financial condition and/or cash flows.
State Actions Related to Air and GHG Emissions
In August 2017, the Ozone Transport Commission released a draft model rule for control of NOX emissions from natural gas pipeline compressor fuel-fire prime movers. States within the ozone transport region, including states in which Dominion Energy has natural gas operations, are expected to develop reasonably achievable control technology rules for existing sources based on the Ozone Transport Commission model rule. States outside of the Ozone Transport Commission may also consider the model rules in setting new reasonably achievable control technology standards. Several states in which Dominion Energy operates, including Virginia and Ohio, are developing or have announced plans to develop state-specific regulations to control GHG emissions, including methane. Dominion Energy cannot currently estimate the potential financial statement impacts related to these matters, but there could be a material impact to its financial condition and/or cash flows.
In October 2020,
Inflation Reduction Act
The IRA includes provisions which impose an annual fee for waste methane emissions from the EPA published a proposal to revise the 2016 Cross State Air Pollution Rule Update to address interstate air quality impacts for the 2008 ozone National Ambient Air Quality Standards. The EPA’s proposed rule will affect 12 states including Virginiaoil and West Virginia and proposes to either issue new or amend existing NOX Ozone Season emission budgets. The EPA is proposing to require implementation of the revised emission budgetsnatural gas industry beginning with emissions reported in calendar year 2024 to the 2021 ozone season (May 1 through September 30, 2021). Such revisions could necessitateextent that an entity’s emissions exceed a stated threshold, with implementation to be addressed by future rulemaking by the Companies install additional control technology at certain facilities and/or limitEPA. Pending the abilitycompletion of facilities to run at certain times or at all.such rulemaking, Dominion Energy cannot currently estimate the potential financial statement impacts relateddoes not expect these provisions to these matters, but there could be a material impact tomaterially affect its future results of operations, financial condition and/or cash flows.
PHMSA Regulation
The most recent reauthorization of PHMSA included new provisions on historical records research, maximum-allowed operating pressure validation, use of automated or remote-controlled valves on new or replaced lines, increased civil penalties and evaluation of expanding integrity management beyond high-consequence areas. PHMSA has not yet issued new rulemaking on most of these items.
Dodd-Frank Act
The CEA, as amended by Title VII of the Dodd-Frank Act, requires certain over-the counter derivatives, or swaps, to be cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk may elect the end-user exception to the CEA’s clearing requirements. Dominion Energy utilizes the end-user exception with respect to its swaps. If, as a result of changes to the rulemaking process, Dominion Energy can no longer utilize the end-user exception or otherwise becomes subject to mandatory clearing, exchange trading or margin requirements, it could be subject to higher costs due to decreased market liquidity or increased margin payments. In addition, Dominion Energy’s swap dealer counterparties may attempt to pass-through additional trading costs in connection with changes to the rulemaking process. Due to the evolving rulemaking process, Dominion Energy is currently unable to assess the potential impact of the Dodd-Frank Act’s derivative-related provisions on its financial condition, results of operations or cash flows.
81
North Anna
Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. If Virginia Power decides to build a new unit, it would require a Combined Construction Permit and Operating License from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. In June 2017, the NRC issued the Combined Construction Permit and Operating License. Virginia Power has not yet committed to building a new nuclear unit at North Anna.
Southeast Energy Exchange MarketFederal Income Tax Laws
In February 2021, DESCInflation Reduction Act
The IRA imposes a 15% alternative minimum tax on GAAP net income, as adjusted for certain items, of corporations in excess of $1 billion, for tax years beginning after December 31, 2022. Entities that are subject to the alternative minimum tax may use tax credits to reduce the liability by up to 75% and will receive a tax credit carryforward with an indefinite life that can be claimed against the other membersregular tax in future years. Pending additional guidance, the alternative minimum tax is not expected to have an effect on the assessment of the Southeast Energy Exchange Market submitted the Southeast Energy Exchange Market Agreement to FERC for authorization. This agreement sets forth the framework and rules for establishing and maintaining a new voluntary electronic trading platform designed to enhance the existing bilateral market in the Southeast utilizing zero-charge transmission service. That transmission service, in turn, will be voluntarily provided by participating transmission service providers, including DESC. This matter is pending.
COVID-19
realizability of Dominion Energy continues to monitor the global outbreak of COVID-19 and developments affecting its workforce, suppliers and other aspects of its business, such as construction projects, and will take additional precautions as Dominion Energy believes are warranted. In addition, Dominion Energy continues to review both customer demand and its ability to collect customer receivables. As a result of the COVID-19 pandemic, Virginia legislation was enacted in November 2020 related to a moratorium on utility disconnections resulting in the forgiveness of certain past due accounts. Other state legislaturesEnergy’s deferred tax assets or utility commissions could impose similar measures which could have a material impact toon Dominion Energy’s future results of operations financial position 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 associated with the CVOW Commercial Project which it manages through foreign currency exchange rate derivatives. The contracts include services denominated in currencies other than the U.S. dollar for approximately €2.6 billion and 5.1 billion kr. In addition, certain of the fixed price contracts, approximately €0.7 billion, contain commodity indexing provisions linked to steel.
The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% change in commodity prices or interest rates.
Commodity Price Risk
To manage price risk, Thethe 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% decreaseincrease in commodity prices would have resulted in an increase of $2 million and a decrease of $50$52 million and $16 million in the fair value of Dominion Energy’s commodity-based derivative instruments as of December 31, 20202022 and December 31, 2019,2021, respectively.
A hypothetical 10% decreaseincrease in commodity prices would have resulted in a decrease of $35$25 million and $54$6 million in the fair value of Virginia Power’s commodity-based derivative instruments as of December 31, 20202022 and December 31, 2019,2021, respectively.
The impact of a change in energy commodity prices on the Companies’ commodity-based derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net losses from commodity-based financial derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity.
Interest Rate Risk
The Companies manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For variable rate debt outstanding for Dominion Energy, a hypothetical 10% increase in market interest rates would result in a $37 million and $6 million decrease in earnings at December 31, 2022 and 2021, respectively. For variable rate debt outstanding for Virginia Power, a hypothetical 10% increase in market interest rates would not have resultedresult in a material change$14 million and less than $1 million decrease in earnings at December 31, 2020 or2022 and 2021, respectively. 2019.
The Companies also use interest rate derivatives, including forward-starting swaps, interest rate swaps and interest rate lock agreements to manage interest rate risk. As of December 31, 2020,2022, Dominion Energy and Virginia Power had $6.9$12.7 billion and $2.1$3.6 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $124$274 million and $75$156 million, respectively, in the fair value of Dominion Energy and Virginia PowerPower’s interest rate derivatives at December 31, 2020.2022. As of December 31, 2019,2021, Dominion Energy and
83
Virginia Power had $6.4$11.4 billion and $1.9$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 $135$191 million and $88$111 million, respectively, in the fair value of Dominion Energy and Virginia PowerPower’s interest rate derivatives at December 31, 2019.
Prior to completing the GT&S Transaction, Dominion Energy held foreign currency swaps for the purpose of hedging the foreign currency exchange risk associated with Euro denominated debt. As of2021.December 31, 2019, Dominion Energy had €250 million in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would not have resulted in a material decrease in fair value of Dominion Energy’s foreign currency swaps at December 31, 2019.
The impact of a change in interest rates on the Companies’ interest rate-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.
Foreign Currency Exchange Rate Risk
The Companies utilize foreign currency exchange rate swaps to economically hedge the foreign currency exchange risk associated with fixed price contracts related to the CVOW Commercial Project denominated in foreign currencies. As of December 31, 2022, Dominion Energy had €2.9 billion in aggregate notional amounts of these foreign currency forward purchase agreements outstanding. A hypothetical 10% increase in exchange rates would have resulted in a decrease of $284 million in the fair value of Dominion Energy’s foreign currency swaps at December 31, 2022.
The impact of a change in exchange rates on the Companies’ foreign currency-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net gains and/or losses from foreign exchange derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.
Investment Price Risk
The Companies are subject to investment price risk due to securities held as investments in nuclear decommissioning and rabbi trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in the Consolidated Balance Sheets at fair value.
Dominion Energy recognized net investment losses (including investment income) on nuclear decommissioning and rabbi trust investments of $888 million and net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $0.7 billion and $1.0$1.1 billion for the years ended December 31, 20202022 and 2019,2021, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion Energy recorded, in AOCI and regulatory liabilities, a net increasedecrease in unrealized gains on debt investments of $57$196 million and $74$64 million for the years ended December 31, 20202022 and 2019,2021, respectively.
Virginia Power recognized net investment losses (including investment income) on nuclear decommissioning and rabbi trust investments of $426 million and net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $287 million and $481$568 million for the years ended December 31, 20202022 and 2019,2021, respectively.Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net increasedecrease in unrealized gains on debt investments of $29$106 million and $30$31 million for the years ended December 31, 20202022 and 2019,2021, respectively.
Dominion Energy sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power employees participate in these plans. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns (losses) of $1.9$(3.0) billion and $2.1$1.5 billion in 20202022 and 2019,2021, respectively, versus expected returns of $933 million$1.1 billion and $848 million,$1.0 billion, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. A hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion Energy’s plan assets would result in an increase in the following year's net periodic cost of $25$26 million and $23$27 million as of December 31, 20202022 and 2019,2021, respectively, for pension benefits and $5 million and $6 million as of both December 31, 20202022 and 20192021, respectively, for other postretirement benefits.
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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, 20202022 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 StatementsStatements and Supplementary Data
Page Number | ||
Dominion Energy, Inc. | ||
Report of Independent Registered Public Accounting Firm(PCAOB ID No. 34) |
| |
Consolidated Statements of Income for the years ended December 31, 2022, 2021 and 2020 |
| |
| ||
Consolidated Balance Sheets at December 31, |
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| ||
| ||
Virginia Electric and Power Company | ||
Report of Independent Registered Public Accounting Firm(PCAOB ID No. 34) |
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| ||
Consolidated Balance Sheets at December 31, |
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| ||
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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, 20202022 and 2019,2021, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2020,2022, 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, 20202022 and 2019,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020,2022, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), Dominion Energy's internal control over financial reporting at December 31, 2020,2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2021,21, 2023, 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 MattersMatter
The critical audit mattersmatter communicated below are mattersis a matter arising from the current-period audit of the financial statements that werewas communicated or required to be communicated to the audit committee and that (1) relaterelates 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 mattersmatter below, providing a separate opinionsopinion on the critical audit mattersmatter or on the accounts or disclosures to which they relate.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 and transmission companies. Management has determined its rate-regulated subsidiaries meet the requirements under accounting principles generally accepted in the United States of America to apply the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment, net; regulatory assets; regulatory liabilities; operating revenues; electric fuel and other energy-related purchases; purchased gas; other operations and maintenance expense; depreciation, depletion and amortization expense; and impairment of assets and other charges, collectively, the “financial statement impacts of rate regulation.”
Revenue provided by Dominion Energy’s electric transmission, distribution and generation operations and its gas transmission and distribution operations is based primarily on rates approved by the relevant commissions. Further, Virginia Electric and Power Company’s (“Virginia Power”) retail base rates, terms and conditions for generation and distribution services to customers in Virginia are
87
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 refundcredit a portion of its earnings to customers.
In connection with the evaluation of Virginia Power’s earnings for the four-year test period ended December 31, 2020, Virginia Power recorded a charge of $130 million for the year ended December 31, 2020 for benefits it expects to provide to its customers through the use of a customer credit reinvestment offset in accordance with the Virginia Grid Transformation and Security Act of 2018 (“GTSA”). This evaluation included consideration of the regulatory treatment of a charge of $754 million ($561 million after-tax) recorded in the first quarter of 2020, associated with Virginia Power’s commitment to retire certain coal- and oil-fired generating units before the end of their useful lives. Virginia Power determined it was appropriate to consider this charge to be recovered as a component of Virginia Power’s base rates under the GTSA. This determination required management judgment.
When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds 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 |
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Impairment of Non-Wholly-Owned Nonregulated Solar Facilities— Refer to Note 10 to the Consolidated Financial Statements
Critical Audit Matter Description
Dominion Energy performs an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets with finite lives may not be recoverable. A long-lived asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount.
In the third quarter of 2020, Dominion Energy performed a strategic review of its long-term intentions for its contracted nonregulated solar generation assets in partnerships outside of its core electric service territories in consideration of the impact of the Virginia Clean Economy Act and Dominion Energy’s decision to sell substantially all of its gas transmission and storage operations. Based on an evaluation of Dominion Energy’s interests in these long-lived assets for recoverability under a probability weighted approach, Dominion Energy determined the assets were impaired. As a result, Dominion Energy recorded a charge of $665 million ($293 million after-tax attributable to Dominion Energy and $267 million attributable to noncontrolling interest) in impairment of assets and other charges in its Consolidated Statements of Income for year ended December 31, 2020 to adjust the property, plant and equipment down to its estimated fair value of $1.4 billion. The fair value was estimated using an income approach. The valuation is considered a Level 3 fair value measurement due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risks inherent in the future cash flows and market prices.
We identified the impairment of the contracted nonregulated solar generation assets held in partnerships as a critical audit matter due to the high degree of auditor judgment and an increased level of effort, including the need to involve our fair value specialists, when performing audit procedures to evaluate (1) the timing of management’s identification of the triggering event requiring the recoverability test, (2) the reasonableness of the probabilities assigned by management to the scenarios utilized within the recoverability model (3) the estimates underlying the future cash flows in scenarios utilized and, (4) the selection of a discount rate in deriving the fair value of the assets.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the impairment of the solar generation assets held in partnerships included the following, among others:
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Earnings (loss) from equity method investees– Presentation of Loss from Atlantic Coast Pipeline in Discontinued Operations — Refer to Note 9 to the Consolidated Financial Statements
Critical Audit Matter Description
Dominion Energy holds a 53% noncontrolling interest in Atlantic Coast Pipeline, LLC (“Atlantic Coast Pipeline”) which since its formation in September 2014 had been focused on the construction of an approximately 600-mile natural gas pipeline.
Atlantic Coast Pipeline determined that the pipeline was probable of abandonment in June 2020, and it fully impaired the related asset under construction which resulted in an equity method loss to Dominion Energy of $2.3 billion. In connection with Dominion Energy’s decision to sell substantially all of its gas transmission and storage operations, which it determined to be a strategic shift, Dominion Energy has reflected the results of its equity method investment in Atlantic Coast Pipeline as discontinued operations in its Consolidated Statements of Income.
Auditing the conclusion that the equity method earnings (loss) associated with Dominion Energy’s investment in Atlantic Coast Pipeline was appropriately presented in discontinued operations involved significant judgment in applying the accounting standards as to when an equity method investee can be considered abandoned.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the assessment of whether the equity method loss associated withrecovery of regulatory assets through future rates or a regulatory liability due to customers is probable.
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/s/ Deloitte & Touche LLP
Richmond, Virginia
February 25, 202121, 2023
We have served as Dominion Energy’s auditor since 1988.
88
Dominion Energy, Inc.
Consolidated StatementsStatements of Income
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
(millions, except per share amounts) |
|
|
|
|
|
|
|
|
| |||
Operating Revenue |
| $ | 17,174 |
|
| $ | 13,964 |
|
| $ | 14,172 |
|
Operating Expenses |
|
|
|
|
|
|
|
|
| |||
Electric fuel and other energy-related purchases |
|
| 3,711 |
|
|
| 2,368 |
|
|
| 2,243 |
|
Purchased electric capacity |
|
| 59 |
|
|
| 70 |
|
|
| 53 |
|
Purchased gas |
|
| 1,582 |
|
|
| 1,083 |
|
|
| 889 |
|
Other operations and maintenance |
|
| 3,984 |
|
|
| 3,734 |
|
|
| 3,685 |
|
Depreciation, depletion and amortization |
|
| 2,830 |
|
|
| 2,478 |
|
|
| 2,332 |
|
Other taxes |
|
| 923 |
|
|
| 909 |
|
|
| 871 |
|
Impairment of assets and other charges |
|
| 2,063 |
|
|
| 195 |
|
|
| 2,105 |
|
Losses (gains) on sales of assets |
|
| 426 |
|
|
| 108 |
|
|
| (61 | ) |
Total operating expenses |
|
| 15,578 |
|
|
| 10,945 |
|
|
| 12,117 |
|
Income from operations |
|
| 1,596 |
|
|
| 3,019 |
|
|
| 2,055 |
|
Earnings from equity method investees |
|
| 299 |
|
|
| 276 |
|
|
| 40 |
|
Other income |
|
| 124 |
|
|
| 1,157 |
|
|
| 693 |
|
Interest and related charges |
|
| 966 |
|
|
| 1,354 |
|
|
| 1,377 |
|
Income from continuing operations including noncontrolling interests before income |
|
| 1,053 |
|
|
| 3,098 |
|
|
| 1,411 |
|
Income tax expense |
|
| 68 |
|
|
| 425 |
|
|
| 83 |
|
Net Income From Continuing Operations Including Noncontrolling Interests |
|
| 985 |
|
|
| 2,673 |
|
|
| 1,328 |
|
Net Income (Loss) From Discontinued Operations Including Noncontrolling |
|
| 9 |
|
|
| 641 |
|
|
| (1,878 | ) |
Net Income (Loss) Including Noncontrolling Interests |
|
| 994 |
|
|
| 3,314 |
|
|
| (550 | ) |
Noncontrolling Interests |
|
| — |
|
|
| 26 |
|
|
| (149 | ) |
Net Income (Loss) Attributable to Dominion Energy |
| $ | 994 |
|
| $ | 3,288 |
|
| $ | (401 | ) |
Amounts attributable to Dominion Energy |
|
|
|
|
|
|
|
|
| |||
Net income from continuing operations |
| $ | 985 |
|
| $ | 2,647 |
|
| $ | 1,583 |
|
Net income (loss) from discontinued operations |
|
| 9 |
|
|
| 641 |
|
|
| (1,984 | ) |
Net income (loss) attributable to Dominion Energy |
| $ | 994 |
|
| $ | 3,288 |
|
| $ | (401 | ) |
EPS - Basic |
|
|
|
|
|
|
|
|
| |||
Net income from continuing operations |
| $ | 1.08 |
|
| $ | 3.19 |
|
| $ | 1.83 |
|
Net income (loss) discontinued operations |
|
| 0.01 |
|
|
| 0.79 |
|
|
| (2.39 | ) |
Net income (loss) attributable to Dominion Energy |
| $ | 1.09 |
|
| $ | 3.98 |
|
| $ | (0.56 | ) |
EPS - Diluted |
|
|
|
|
|
|
|
|
| |||
Net income from continuing operations |
| $ | 1.08 |
|
| $ | 3.19 |
|
| $ | 1.82 |
|
Net income (loss) discontinued operations |
|
| 0.01 |
|
|
| 0.79 |
|
|
| (2.39 | ) |
Net income (loss) attributable to Dominion Energy |
| $ | 1.09 |
|
| $ | 3.98 |
|
| $ | (0.57 | ) |
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
| |||
(millions, except per share amounts) |
|
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|
|
|
|
|
|
|
|
Operating Revenue |
| $ | 14,172 |
|
| $ | 14,401 |
|
| $ | 11,199 |
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Electric fuel and other energy-related purchases |
|
| 2,243 |
|
|
| 2,885 |
|
|
| 2,687 |
|
Purchased electric capacity |
|
| 53 |
|
|
| 88 |
|
|
| 122 |
|
Purchased gas |
|
| 889 |
|
|
| 1,560 |
|
|
| 604 |
|
Other operations and maintenance |
|
| 3,685 |
|
|
| 3,790 |
|
|
| 2,786 |
|
Depreciation, depletion and amortization |
|
| 2,332 |
|
|
| 2,283 |
|
|
| 1,660 |
|
Other taxes |
|
| 871 |
|
|
| 883 |
|
|
| 580 |
|
Impairment of assets and other charges |
|
| 2,105 |
|
|
| 1,520 |
|
|
| 12 |
|
Gains on sales of assets |
|
| (61 | ) |
|
| (152 | ) |
|
| (265 | ) |
Total operating expenses |
|
| 12,117 |
|
|
| 12,857 |
|
|
| 8,186 |
|
Income from operations |
|
| 2,055 |
|
|
| 1,544 |
|
|
| 3,013 |
|
Other income |
|
| 733 |
|
|
| 811 |
|
|
| 885 |
|
Interest and related charges |
|
| 1,377 |
|
|
| 1,486 |
|
|
| 1,279 |
|
Income from continuing operations including noncontrolling interests before income tax expense |
|
| 1,411 |
|
|
| 869 |
|
|
| 2,619 |
|
Income tax expense |
|
| 83 |
|
|
| 209 |
|
|
| 522 |
|
Net Income From Continuing Operations Including Noncontrolling Interests |
|
| 1,328 |
|
|
| 660 |
|
|
| 2,097 |
|
Net Income (Loss) From Discontinued Operations Including Noncontrolling Interests(1)(2) |
|
| (1,878 | ) |
|
| 716 |
|
|
| 452 |
|
Net Income (Loss) Including Noncontrolling Interests |
|
| (550 | ) |
|
| 1,376 |
|
|
| 2,549 |
|
Noncontrolling Interests |
|
| (149 | ) |
|
| 18 |
|
|
| 102 |
|
Net Income (Loss) Attributable to Dominion Energy |
| $ | (401 | ) |
| $ | 1,358 |
|
| $ | 2,447 |
|
Amounts attributable to Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
Net Income from continuing operations |
| $ | 1,583 |
|
| $ | 653 |
|
| $ | 2,087 |
|
Net Income (Loss) from discontinued operations |
|
| (1,984 | ) |
|
| 705 |
|
|
| 360 |
|
Net Income (Loss) attributable to Dominion Energy |
| $ | (401 | ) |
| $ | 1,358 |
|
| $ | 2,447 |
|
EPS - Basic |
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations |
| $ | 1.83 |
|
| $ | 0.79 |
|
| $ | 3.19 |
|
Net income (loss) discontinued operations |
|
| (2.39 | ) |
|
| 0.87 |
|
|
| 0.55 |
|
Net income (loss) attributable to Dominion Energy |
| $ | (0.56 | ) |
| $ | 1.66 |
|
| $ | 3.74 |
|
EPS - Diluted |
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations |
| $ | 1.82 |
|
| $ | 0.75 |
|
| $ | 3.19 |
|
Net income (loss) discontinued operations |
|
| (2.39 | ) |
|
| 0.87 |
|
|
| 0.55 |
|
Net income (loss) attributable to Dominion Energy |
| $ | (0.57 | ) |
| $ | 1.62 |
|
| $ | 3.74 |
|
|
|
|
|
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
89
Dominion Energy, Inc.
Consolidated Statements of Comprehensive Income
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Net income including noncontrolling interests |
| $ | (550 | ) |
| $ | 1,376 |
|
| $ | 2,549 |
|
Other comprehensive loss, net of taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred gains (losses) on derivatives-hedging activities, net of $81, $35 and $(10) tax |
|
| (239 | ) |
|
| (110 | ) |
|
| 30 |
|
Changes in unrealized net gains (losses) on investment securities, net of $(14), $(14) and $5 tax |
|
| 43 |
|
|
| 39 |
|
|
| (18 | ) |
Changes in net unrecognized pension and other postretirement benefit costs, net of $(2), $(4) and $75 tax |
|
| 25 |
|
|
| (22 | ) |
|
| (215 | ) |
Amounts reclassified to net income: |
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative (gains) losses-hedging activities, net of $(75), $21 and $(35) tax |
|
| 227 |
|
|
| (62 | ) |
|
| 102 |
|
Net realized (gains) losses on investment securities, net of $6, $1 and $(2) tax |
|
| (18 | ) |
|
| (4 | ) |
|
| 5 |
|
Net pension and other postretirement benefit costs, net of $(13), $(23) and $(21) tax |
|
| 37 |
|
|
| 66 |
|
|
| 78 |
|
Changes in other comprehensive income from equity method investees, net of $(1), $— and $(1) tax |
|
| 1 |
|
|
| — |
|
|
| 1 |
|
Total other comprehensive loss |
|
| 76 |
|
|
| (93 | ) |
|
| (17 | ) |
Comprehensive income (loss) including noncontrolling interests |
|
| (474 | ) |
|
| 1,283 |
|
|
| 2,532 |
|
Comprehensive income (loss) attributable to noncontrolling interests |
|
| (149 | ) |
|
| 18 |
|
|
| 103 |
|
Comprehensive income (loss) attributable to Dominion Energy |
| $ | (325 | ) |
| $ | 1,265 |
|
| $ | 2,429 |
|
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
(millions) |
|
|
|
|
|
|
|
|
| |||
Net income (loss) including noncontrolling interests |
| $ | 994 |
|
| $ | 3,314 |
|
| $ | (550 | ) |
Other comprehensive income (loss), net of taxes: |
|
|
|
|
|
|
|
|
| |||
Net deferred gains (losses) on derivatives-hedging activities, net of $(22), |
|
| 67 |
|
|
| 15 |
|
|
| (239 | ) |
Changes in unrealized net gains (losses) on investment securities, net of |
|
| (100 | ) |
|
| (7 | ) |
|
| 43 |
|
Changes in net unrecognized pension and other postretirement benefit |
|
| (218 | ) |
|
| 144 |
|
|
| 25 |
|
Amounts reclassified to net income (loss): |
|
|
|
|
|
|
|
|
| |||
Net derivative (gains) losses-hedging activities, net of $(15), $(15) and |
|
| 42 |
|
|
| 46 |
|
|
| 227 |
|
Net realized (gains) losses on investment securities, net of $(6), $5 and |
|
| 19 |
|
|
| (18 | ) |
|
| (18 | ) |
Net pension and other postretirement benefit costs, net of $(27), $(29) |
|
| 75 |
|
|
| 82 |
|
|
| 37 |
|
Changes in other comprehensive income from equity method investees, |
|
| 1 |
|
|
| (3 | ) |
|
| 1 |
|
Total other comprehensive income (loss) |
|
| (114 | ) |
|
| 259 |
|
|
| 76 |
|
Comprehensive income (loss) including noncontrolling interests |
|
| 880 |
|
|
| 3,573 |
|
|
| (474 | ) |
Comprehensive income (loss) attributable to noncontrolling interests |
|
| — |
|
|
| 26 |
|
|
| (149 | ) |
Comprehensive income (loss) attributable to Dominion Energy |
| $ | 880 |
|
| $ | 3,547 |
|
| $ | (325 | ) |
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
90
Dominion Energy, Inc.
Consolidated Balance Sheets
At December 31, |
| 2020 |
|
| 2019 |
|
| 2022 |
|
| 2021 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 172 |
|
| $ | 135 |
|
| $ | 153 |
|
| $ | 283 |
|
Customer receivables (less allowance for doubtful accounts of $42 and $18) |
|
| 2,295 |
|
|
| 2,085 |
| ||||||||
Other receivables (less allowance for doubtful accounts of $3 at both dates) |
|
| 212 |
|
|
| 340 |
| ||||||||
Customer receivables (less allowance for doubtful accounts of $31 and $40) |
|
| 2,952 |
|
|
| 2,219 |
| ||||||||
Other receivables (less allowance for doubtful accounts of $3 and $4) |
|
| 405 |
|
|
| 349 |
| ||||||||
Inventories: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Materials and supplies |
|
| 1,105 |
|
|
| 1,071 |
|
|
| 1,206 |
|
|
| 1,167 |
|
Fossil fuel |
|
| 349 |
|
|
| 411 |
|
|
| 358 |
|
|
| 320 |
|
Gas stored |
|
| 96 |
|
|
| 134 |
|
|
| 165 |
|
|
| 144 |
|
Derivative assets |
|
| 1,137 |
|
|
| 122 |
| ||||||||
Margin deposit assets |
|
| 480 |
|
|
| 678 |
| ||||||||
Prepayments |
|
| 309 |
|
|
| 296 |
|
|
| 392 |
|
|
| 328 |
|
Regulatory assets |
|
| 699 |
|
|
| 871 |
|
|
| 2,340 |
|
|
| 1,492 |
|
Other |
|
| 167 |
|
|
| 218 |
|
|
| 215 |
|
|
| 142 |
|
Current assets held for sale(1) |
|
| 1,482 |
|
|
| 535 |
| ||||||||
Current assets held for sale |
|
| 47 |
|
|
| 25 |
| ||||||||
Total current assets |
|
| 6,886 |
|
|
| 6,096 |
|
|
| 9,850 |
|
|
| 7,269 |
|
Investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Nuclear decommissioning trust funds |
|
| 6,900 |
|
|
| 6,192 |
|
|
| 5,957 |
|
|
| 7,950 |
|
Investment in equity method affiliates |
|
| 2,934 |
|
|
| 1,334 |
|
|
| 3,012 |
|
|
| 2,932 |
|
Other |
|
| 404 |
|
|
| 379 |
|
|
| 390 |
|
|
| 394 |
|
Total investments |
|
| 10,238 |
|
|
| 7,905 |
|
|
| 9,359 |
|
|
| 11,276 |
|
Property, Plant and Equipment |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Property, plant and equipment |
|
| 82,959 |
|
|
| 82,043 |
|
|
| 91,202 |
|
|
| 86,503 |
|
Accumulated depreciation, depletion and amortization |
|
| (25,111 | ) |
|
| (24,843 | ) |
|
| (27,742 | ) |
|
| (26,729 | ) |
Total property, plant and equipment, net |
|
| 57,848 |
|
|
| 57,200 |
|
|
| 63,460 |
|
|
| 59,774 |
|
Deferred Charges and Other Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Goodwill |
|
| 7,381 |
|
|
| 7,395 |
|
|
| 7,295 |
|
|
| 7,405 |
|
Pension and other postretirement benefit assets |
|
| 1,704 |
|
|
| 1,707 |
|
|
| 1,785 |
|
|
| 2,310 |
|
Intangible assets, net |
|
| 765 |
|
|
| 685 |
|
|
| 868 |
|
|
| 784 |
|
Derivative assets |
|
| 1,039 |
|
|
| 491 |
| ||||||||
Regulatory assets |
|
| 9,133 |
|
|
| 7,652 |
|
|
| 9,087 |
|
|
| 8,643 |
|
Other |
|
| 1,950 |
|
|
| 1,226 |
|
|
| 1,500 |
|
|
| 1,638 |
|
Total deferred charges and other assets |
|
| 20,933 |
|
|
| 18,665 |
|
|
| 21,574 |
|
|
| 21,271 |
|
Noncurrent assets held for sale |
|
| — |
|
|
| 13,957 |
| ||||||||
Total assets |
| $ | 95,905 |
|
| $ | 103,823 |
|
| $ | 104,243 |
|
| $ | 99,590 |
|
|
|
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
At December 31, |
| 2020 |
|
| 2019 |
| ||
(millions) |
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Securities due within one year |
| $ | 1,937 |
|
| $ | 2,462 |
|
Supplemental 364-Day credit facility borrowings |
|
| 225 |
|
|
| — |
|
Short-term debt |
|
| 895 |
|
|
| 849 |
|
Accounts payable |
|
| 944 |
|
|
| 1,023 |
|
Accrued interest, payroll and taxes |
|
| 1,133 |
|
|
| 1,284 |
|
Regulatory liabilities |
|
| 809 |
|
|
| 455 |
|
Reserves for SCANA legal proceedings |
|
| 208 |
|
|
| 696 |
|
Liability to Atlantic Coast Pipeline |
|
| 1,052 |
|
|
| — |
|
Q-Pipe Transaction deposit |
|
| 1,290 |
|
|
| — |
|
Other(1) |
|
| 1,725 |
|
|
| 2,132 |
|
Current liabilities held for sale |
|
| 625 |
|
|
| 1,039 |
|
Total current liabilities |
|
| 10,843 |
|
|
| 9,940 |
|
Long-Term Debt |
|
|
|
|
|
|
|
|
Long-term debt |
|
| 30,915 |
|
|
| 25,492 |
|
Junior subordinated notes |
|
| 2,161 |
|
|
| 3,406 |
|
Other |
|
| 881 |
|
|
| 100 |
|
Total long-term debt |
|
| 33,957 |
|
|
| 28,998 |
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
|
|
|
Deferred income taxes and investment tax credits |
|
| 5,953 |
|
|
| 6,277 |
|
Regulatory liabilities |
|
| 10,187 |
|
|
| 10,204 |
|
Asset retirement obligations |
|
| 5,404 |
|
|
| 4,790 |
|
Pension and other postretirement benefit liability |
|
| 1,706 |
|
|
| 2,364 |
|
Other(1) |
|
| 1,394 |
|
|
| 1,463 |
|
Total deferred credits and other liabilities |
|
| 24,644 |
|
|
| 25,098 |
|
Noncurrent liabilities held for sale |
|
| — |
|
|
| 5,754 |
|
Total liabilities |
|
| 69,444 |
|
|
| 69,790 |
|
Commitments and Contingencies (see Note 23) |
|
|
|
|
|
|
|
|
Equity |
|
|
|
|
|
|
|
|
Preferred stock (See Note 19) |
|
| 2,387 |
|
|
| 2,387 |
|
Common stock – no par(2) |
|
| 21,258 |
|
|
| 23,824 |
|
Retained earnings |
|
| 4,189 |
|
|
| 7,576 |
|
Accumulated other comprehensive loss |
|
| (1,717 | ) |
|
| (1,793 | ) |
Total shareholders' equity |
|
| 26,117 |
|
|
| 31,994 |
|
Noncontrolling interests |
|
| 344 |
|
|
| 2,039 |
|
Total equity |
|
| 26,461 |
|
|
| 34,033 |
|
Total liabilities and equity |
| $ | 95,905 |
|
| $ | 103,823 |
|
91
At December 31, |
| 2022 |
|
| 2021 |
| ||
(millions) |
|
|
|
|
|
| ||
LIABILITIES, MEZZANINE EQUITY AND SHAREHOLDERS' EQUITY |
|
|
|
|
|
| ||
Current Liabilities |
|
|
|
|
|
| ||
Securities due within one year |
| $ | 3,341 |
|
| $ | 841 |
|
Short-term debt |
|
| 3,423 |
|
|
| 2,314 |
|
Accounts payable |
|
| 1,825 |
|
|
| 1,197 |
|
Accrued interest, payroll and taxes |
|
| 1,199 |
|
|
| 1,169 |
|
Derivative liabilities |
|
| 778 |
|
|
| 359 |
|
Regulatory liabilities |
|
| 946 |
|
|
| 986 |
|
Other(1) |
|
| 1,938 |
|
|
| 1,807 |
|
Total current liabilities |
|
| 13,450 |
|
|
| 8,673 |
|
Long-Term Debt |
|
|
|
|
|
| ||
Long-term debt |
|
| 36,832 |
|
|
| 35,190 |
|
Junior subordinated notes |
|
| 1,387 |
|
|
| 1,386 |
|
Supplemental credit facility borrowings |
|
| 450 |
|
|
| — |
|
Other |
|
| 245 |
|
|
| 850 |
|
Total long-term debt |
|
| 38,914 |
|
|
| 37,426 |
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
| ||
Deferred income taxes and investment tax credits |
|
| 6,698 |
|
|
| 6,658 |
|
Regulatory liabilities |
|
| 10,107 |
|
|
| 10,713 |
|
Asset retirement obligations |
|
| 5,208 |
|
|
| 5,275 |
|
Derivative liabilities |
|
| 626 |
|
|
| 509 |
|
Other |
|
| 1,359 |
|
|
| 1,418 |
|
Total deferred credits and other liabilities |
|
| 23,998 |
|
|
| 24,573 |
|
Total liabilities |
|
| 76,362 |
|
|
| 70,672 |
|
Commitments and Contingencies (see Note 23) |
|
|
|
|
|
| ||
Mezzanine Equity |
|
|
|
|
|
| ||
Preferred stock (See Note 19) |
|
| — |
|
|
| 1,610 |
|
Shareholders' Equity |
|
|
|
|
|
| ||
Preferred stock (See Note 19) |
|
| 1,783 |
|
|
| 1,783 |
|
Common stock – no par(2) |
|
| 23,605 |
|
|
| 21,610 |
|
Retained earnings |
|
| 4,065 |
|
|
| 5,373 |
|
Accumulated other comprehensive loss |
|
| (1,572 | ) |
|
| (1,458 | ) |
Shareholders' equity |
|
| 27,881 |
|
|
| 27,308 |
|
Noncontrolling interests |
|
| — |
|
|
| — |
|
Total shareholders' equity |
|
| 27,881 |
|
|
| 27,308 |
|
Total liabilities, mezzanine equity and shareholders' equity |
| $ | 104,243 |
|
| $ | 99,590 |
|
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
92
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, 2017 |
|
|
|
|
|
|
|
|
|
| 645 |
|
| $ | 9,865 |
|
| $ | 7,936 |
|
| $ | (659 | ) |
| $ | 17,142 |
|
| $ | 2,228 |
|
| $ | 19,370 |
|
Cumulative-effect of changes in accounting principles |
|
|
|
|
|
|
|
|
|
|
|
|
|
| (127 | ) |
|
| 1,029 |
|
|
| (1,023 | ) |
|
| (121 | ) |
|
| 127 |
|
|
| 6 |
|
Net income including noncontrolling interests |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2,447 |
|
|
|
|
|
|
| 2,447 |
|
|
| 102 |
|
|
| 2,549 |
|
Issuance of common stock |
|
|
|
|
|
|
|
|
|
| 36 |
|
|
| 2,461 |
|
|
|
|
|
|
|
|
|
|
| 2,461 |
|
|
|
|
|
|
| 2,461 |
|
Sale of Dominion Energy Midstream common units—net of offering costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| — |
|
|
| 4 |
|
|
| 4 |
|
Remeasurement of noncontrolling interest in Dominion Energy Midstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 375 |
|
|
|
|
|
|
|
|
|
|
| 375 |
|
|
| (375 | ) |
|
| — |
|
Stock awards (net of change in unearned compensation) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 22 |
|
|
|
|
|
|
|
|
|
|
| 22 |
|
|
|
|
|
|
| 22 |
|
Dividends ($3.34 per common share) and distributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (2,185 | ) |
|
|
|
|
|
| (2,185 | ) |
|
| (146 | ) |
|
| (2,331 | ) |
Other comprehensive income (loss), net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (18 | ) |
|
| (18 | ) |
|
| 1 |
|
|
| (17 | ) |
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
| (8 | ) |
|
| (8 | ) |
|
|
|
|
|
| (16 | ) |
|
|
|
|
|
| (16 | ) |
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 loss, 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 |
|
| Preferred Stock |
| Common Stock |
| Dominion Energy Shareholders |
|
|
|
|
|
|
| |||||||||||||||
| Shares |
| Amount |
| Shares |
| Amount |
| Retained Earnings |
| AOCI |
| Total Shareholders' Equity |
| Noncontrolling |
| Total |
| |||||||||
(millions except per share amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
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 |
|
|
|
|
|
|
|
|
| (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 |
|
|
|
|
|
|
| 29 |
|
|
|
|
|
| 29 |
|
|
|
| 29 |
| ||||||
Preferred stock dividends (See Note 19) |
|
|
|
|
|
|
|
|
| (65 | ) |
|
|
| (65 | ) |
|
|
| (65 | ) | ||||||
Common dividends ($3.45 per common share) |
|
|
|
|
|
|
|
|
| (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 |
|
|
|
|
|
|
| 28 |
|
|
|
|
|
| 28 |
|
|
|
| 28 |
| ||||||
Preferred stock dividends (See Note 19) |
|
|
|
|
|
|
|
|
| (68 | ) |
|
|
| (68 | ) |
|
|
| (68 | ) | ||||||
Common dividends ($2.52 per common share) |
|
|
|
|
|
|
|
|
| (2,036 | ) |
|
|
| (2,036 | ) |
| (47 | ) |
| (2,083 | ) | |||||
Other comprehensive income, net of tax |
|
|
|
|
|
|
|
|
|
|
| 259 |
|
| 259 |
|
|
|
| 259 |
| ||||||
Reclassification of Series A Preferred Stock to |
| (1 | ) |
| (1,596 | ) |
|
|
| (14 | ) |
|
|
|
|
| (1,610 | ) |
|
|
| (1,610 | ) | ||||
Sale of non-wholly-owned nonregulated solar |
|
|
|
|
|
|
|
|
|
|
|
|
| — |
|
| (323 | ) |
| (323 | ) | ||||||
Other |
|
|
|
|
|
|
| (2 | ) |
|
|
|
|
| (2 | ) |
|
|
| (2 | ) | ||||||
December 31, 2021 |
| 2 |
| $ | 1,783 |
|
| 810 |
| $ | 21,610 |
| $ | 5,373 |
| $ | (1,458 | ) | $ | 27,308 |
| $ | — |
| $ | 27,308 |
|
Net income including noncontrolling interests |
|
|
|
|
|
|
|
|
| 994 |
|
|
|
| 994 |
|
|
|
| 994 |
| ||||||
Issuance of stock |
|
|
|
|
| 25 |
|
| 1,969 |
|
|
|
|
|
| 1,969 |
|
|
|
| 1,969 |
| |||||
Stock awards (net of change in unearned |
|
|
|
|
|
|
| 26 |
|
|
|
|
|
| 26 |
|
|
|
| 26 |
| ||||||
Preferred stock dividends (See Note 19) |
|
|
|
|
|
|
|
|
| (93 | ) |
|
|
| (93 | ) |
|
|
| (93 | ) | ||||||
Common dividends ($2.67 per common share) |
|
|
|
|
|
|
|
|
| (2,209 | ) |
|
|
| (2,209 | ) |
|
|
| (2,209 | ) | ||||||
Other comprehensive loss, net of tax |
|
|
|
|
|
|
|
|
|
|
| (114 | ) |
| (114 | ) |
|
|
| (114 | ) | ||||||
December 31, 2022 |
| 2 |
| $ | 1,783 |
|
| 835 |
| $ | 23,605 |
| $ | 4,065 |
| $ | (1,572 | ) | $ | 27,881 |
| $ | — |
| $ | 27,881 |
|
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
93
Dominion Energy, Inc.
Consolidated Statements of Cash Flows
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
(millions) |
|
|
|
|
|
|
|
|
| |||
Operating Activities |
|
|
|
|
|
|
|
|
| |||
Net income (loss) including noncontrolling interests |
| $ | 994 |
|
| $ | 3,314 |
|
| $ | (550 | ) |
Adjustments to reconcile net income (loss) including noncontrolling interests to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
| |||
Depreciation, depletion and amortization (including nuclear fuel) |
|
| 3,113 |
|
|
| 2,768 |
|
|
| 2,836 |
|
Deferred income taxes and investment tax credits |
|
| 9 |
|
|
| 487 |
|
|
| (324 | ) |
Gain from sale of Q-Pipe Group and GT&S Transaction |
|
| (27 | ) |
|
| (685 | ) |
|
| (134 | ) |
Contribution to pension plan |
|
| — |
|
|
| — |
|
|
| (250 | ) |
Net loss on sale of interest in renewable generation facilities |
|
| — |
|
|
| 211 |
|
|
| — |
|
Provision for refunds and rate credits to electric utility customers |
|
| — |
|
|
| 356 |
|
|
| — |
|
Impairment of assets and other charges |
|
| 1,996 |
|
|
| 182 |
|
|
| 2,345 |
|
Loss from investment in Atlantic Coast Pipeline |
|
| 7 |
|
|
| 20 |
|
|
| 2,405 |
|
Losses (gains) on sales of assets and equity method investments |
|
| 467 |
|
|
| (97 | ) |
|
| (63 | ) |
Net (gains) losses on nuclear decommissioning trusts funds and other investments |
|
| 505 |
|
|
| (639 | ) |
|
| (412 | ) |
Other adjustments |
|
| (28 | ) |
|
| 294 |
|
|
| 224 |
|
Changes in: |
|
|
|
|
|
|
|
|
| |||
Accounts receivable |
|
| (985 | ) |
|
| (183 | ) |
|
| (292 | ) |
Inventories |
|
| (216 | ) |
|
| (74 | ) |
|
| 39 |
|
Deferred fuel and purchased gas costs, net |
|
| (2,021 | ) |
|
| (939 | ) |
|
| 212 |
|
Prepayments |
|
| (68 | ) |
|
| (20 | ) |
|
| 7 |
|
Accounts payable |
|
| 556 |
|
|
| 156 |
|
|
| 35 |
|
Accrued interest, payroll and taxes |
|
| 41 |
|
|
| 41 |
|
|
| (53 | ) |
Margin deposit assets and liabilities |
|
| 198 |
|
|
| (664 | ) |
|
| 26 |
|
Net realized and unrealized changes related to derivative activities |
|
| (47 | ) |
|
| 435 |
|
|
| (36 | ) |
Pension and other postretirement benefits |
|
| (461 | ) |
|
| (314 | ) |
|
| (319 | ) |
Other operating assets and liabilities |
|
| (333 | ) |
|
| (612 | ) |
|
| (469 | ) |
Net cash provided by operating activities |
|
| 3,700 |
|
|
| 4,037 |
|
|
| 5,227 |
|
Investing Activities |
|
|
|
|
|
|
|
|
| |||
Plant construction and other property additions (including nuclear fuel) |
|
| (7,591 | ) |
|
| (5,960 | ) |
|
| (6,020 | ) |
Acquisition of solar development projects |
|
| (167 | ) |
|
| (101 | ) |
|
| (311 | ) |
Proceeds from sale of Hope |
|
| 727 |
|
|
| — |
|
|
| — |
|
Proceeds from GT&S Transaction and sale of Q-Pipe Group |
|
| 19 |
|
|
| 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 |
|
| 3,282 |
|
|
| 3,985 |
|
|
| 4,278 |
|
Purchases of securities |
|
| (3,067 | ) |
|
| (3,939 | ) |
|
| (4,379 | ) |
Proceeds from sales of assets and equity method investments |
|
| 252 |
|
|
| 159 |
|
|
| 143 |
|
Contributions to equity method affiliates |
|
| (43 | ) |
|
| (1,021 | ) |
|
| (148 | ) |
Acquisition of equity method investments |
|
| — |
|
|
| — |
|
|
| (178 | ) |
Short-term deposit |
|
| (2,000 | ) |
|
| — |
|
|
| — |
|
Return of short-term deposit |
|
| 2,000 |
|
|
| — |
|
|
| — |
|
Other |
|
| (158 | ) |
|
| (122 | ) |
|
| 12 |
|
Net cash used in investing activities |
|
| (6,746 | ) |
|
| (6,247 | ) |
|
| (2,916 | ) |
Financing Activities |
|
|
|
|
|
|
|
|
| |||
Issuance (repayment) of short-term debt, net |
|
| 1,109 |
|
|
| 1,419 |
|
|
| (16 | ) |
Issuance of short-term notes |
|
| — |
|
|
| 1,265 |
|
|
| 1,125 |
|
Repayment and repurchase of short-term notes |
|
| — |
|
|
| (1,265 | ) |
|
| (1,125 | ) |
Issuance of supplemental 364-day credit facility borrowings |
|
| — |
|
|
| — |
|
|
| 225 |
|
Repayment of supplemental 364-day credit facility borrowings |
|
| — |
|
|
| (225 | ) |
|
| — |
|
Issuance and remarketing of long-term debt |
|
| 4,965 |
|
|
| 6,400 |
|
|
| 6,577 |
|
Repayment and repurchase of long-term debt (including redemption premiums) |
|
| (1,388 | ) |
|
| (3,750 | ) |
|
| (2,879 | ) |
Supplemental credit facility borrowings |
|
| 900 |
|
|
| 900 |
|
|
| — |
|
Supplemental credit facility repayments |
|
| (450 | ) |
|
| (900 | ) |
|
| — |
|
Issuance of preferred stock |
|
| — |
|
|
| 742 |
|
|
| — |
|
Series A Preferred Stock redemption |
|
| (1,610 | ) |
|
| — |
|
|
| — |
|
Issuance of common stock |
|
| 1,866 |
|
|
| 192 |
|
|
| 159 |
|
Repurchase of common stock |
|
| — |
|
|
| — |
|
|
| (3,080 | ) |
Common dividend payments |
|
| (2,209 | ) |
|
| (2,036 | ) |
|
| (2,873 | ) |
Other |
|
| (204 | ) |
|
| (371 | ) |
|
| (446 | ) |
Net cash provided by (used in) financing activities |
|
| 2,979 |
|
|
| 2,371 |
|
|
| (2,333 | ) |
Increase (decrease) in cash, restricted cash and equivalents |
|
| (67 | ) |
|
| 161 |
|
|
| (22 | ) |
Cash, restricted cash and equivalents at beginning of period |
|
| 408 |
|
|
| 247 |
|
|
| 269 |
|
Cash, restricted cash and equivalents at end of period |
| $ | 341 |
|
| $ | 408 |
|
| $ | 247 |
|
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) including noncontrolling interests |
| $ | (550 | ) |
| $ | 1,376 |
|
| $ | 2,549 |
|
Adjustments to reconcile net income (loss) including noncontrolling interests to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization (including nuclear fuel) |
|
| 2,836 |
|
|
| 2,977 |
|
|
| 2,280 |
|
Deferred income taxes and investment tax credits |
|
| (324 | ) |
|
| 216 |
|
|
| 517 |
|
Gain from GT&S Transaction |
|
| (134 | ) |
|
| — |
|
|
| — |
|
Contribution to pension plan |
|
| (250 | ) |
|
| (21 | ) |
|
| — |
|
Provision for refunds and rate credits to electric utility customers |
|
| — |
|
|
| 800 |
|
|
| 77 |
|
Impairment of assets and other charges |
|
| 2,345 |
|
|
| 1,333 |
|
|
| 395 |
|
Loss for equity method investee |
|
| 2,405 |
|
|
| — |
|
|
| — |
|
Charges related to a voluntary retirement program |
|
| — |
|
|
| 320 |
|
|
| — |
|
Gains on sales of assets and equity method investments |
|
| (63 | ) |
|
| (167 | ) |
|
| (1,006 | ) |
Net (gains) losses on nuclear decommissioning trusts funds and other investments |
|
| (412 | ) |
|
| (626 | ) |
|
| 102 |
|
Charge (revision) for future ash pond and landfill closure costs |
|
| 11 |
|
|
| (113 | ) |
|
| 81 |
|
Other adjustments |
|
| 159 |
|
|
| (5 | ) |
|
| 19 |
|
Changes in: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
| (238 | ) |
|
| (71 | ) |
|
| (110 | ) |
Inventories |
|
| 39 |
|
|
| (90 | ) |
|
| (29 | ) |
Deferred fuel and purchased gas costs, net |
|
| 212 |
|
|
| 195 |
|
|
| (247 | ) |
Prepayments |
|
| 7 |
|
|
| (225 | ) |
|
| (51 | ) |
Accounts payable |
|
| 35 |
|
|
| (225 | ) |
|
| 67 |
|
Accrued interest, payroll and taxes |
|
| (53 | ) |
|
| (78 | ) |
|
| (12 | ) |
Customer deposits |
|
| (13 | ) |
|
| (101 | ) |
|
| 54 |
|
Margin deposit assets and liabilities |
|
| 26 |
|
|
| 60 |
|
|
| — |
|
Net realized and unrealized changes related to derivative activities |
|
| (36 | ) |
|
| 43 |
|
|
| 181 |
|
Pension and other postretirement benefits |
|
| (319 | ) |
|
| (148 | ) |
|
| (114 | ) |
Other operating assets and liabilities |
|
| (456 | ) |
|
| (246 | ) |
|
| 20 |
|
Net cash provided by operating activities |
|
| 5,227 |
|
|
| 5,204 |
|
|
| 4,773 |
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Plant construction and other property additions (including nuclear fuel) |
|
| (6,020 | ) |
|
| (4,980 | ) |
|
| (4,254 | ) |
Cash and restricted cash acquired in the SCANA Combination |
|
| — |
|
|
| 389 |
|
|
| — |
|
Acquisition of solar development projects |
|
| (311 | ) |
|
| (341 | ) |
|
| (151 | ) |
Proceeds from GT&S Transaction and Q-Pipe Transaction |
|
| 3,687 |
|
|
| — |
|
|
| — |
|
Proceeds from sales of securities |
|
| 4,278 |
|
|
| 1,712 |
|
|
| 1,804 |
|
Purchases of securities |
|
| (4,379 | ) |
|
| (1,749 | ) |
|
| (1,894 | ) |
Proceeds from sales of assets and equity method investments |
|
| 143 |
|
|
| 447 |
|
|
| 2,542 |
|
Contributions to equity method affiliates |
|
| (148 | ) |
|
| (209 | ) |
|
| (428 | ) |
Acquisition of equity method investments |
|
| (178 | ) |
|
| — |
|
|
| — |
|
Other |
|
| 12 |
|
|
| 109 |
|
|
| 23 |
|
Net cash used in investing activities |
|
| (2,916 | ) |
|
| (4,622 | ) |
|
| (2,358 | ) |
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Issuance (repayment) of short-term debt, net |
|
| (16 | ) |
|
| 404 |
|
|
| (2,964 | ) |
Issuance of short-term notes |
|
| 1,125 |
|
|
| 3,000 |
|
|
| 1,450 |
|
Repayment and repurchase of short-term notes |
|
| (1,125 | ) |
|
| (3,000 | ) |
|
| (1,450 | ) |
Supplemental 364-day credit facility borrowings |
|
| 225 |
|
|
| — |
|
|
| — |
|
Credit facility borrowings (repayments) |
|
| — |
|
|
| (113 | ) |
|
| 73 |
|
Issuance and remarketing of long-term debt |
|
| 6,577 |
|
|
| 4,374 |
|
|
| 6,362 |
|
Repayment and repurchase of long-term debt (including redemption premiums) |
|
| (2,879 | ) |
|
| (9,116 | ) |
|
| (5,682 | ) |
Proceeds from sale of interest in Cove Point |
|
| — |
|
|
| 2,078 |
|
|
| — |
|
Issuance of 2019 Equity Units |
|
| — |
|
|
| 1,582 |
|
|
| — |
|
Issuance of Series B Preferred Stock |
|
| — |
|
|
| 791 |
|
|
| — |
|
Repurchase of common stock |
|
| (3,080 | ) |
|
| — |
|
|
| — |
|
Issuance of common stock |
|
| 159 |
|
|
| 2,515 |
|
|
| 2,461 |
|
Common dividend payments |
|
| (2,873 | ) |
|
| (2,983 | ) |
|
| (2,185 | ) |
Other |
|
| (446 | ) |
|
| (236 | ) |
|
| (274 | ) |
Net cash used in financing activities |
|
| (2,333 | ) |
|
| (704 | ) |
|
| (2,209 | ) |
Increase (decrease) in cash, restricted cash and equivalents |
|
| (22 | ) |
|
| (122 | ) |
|
| 206 |
|
Cash, restricted cash and equivalents at beginning of period |
|
| 269 |
|
|
| 391 |
|
|
| 185 |
|
Cash, restricted cash and equivalents at end of period |
| $ | 247 |
|
| $ | 269 |
|
| $ | 391 |
|
See Note 2 for disclosure of supplemental cash flow information.
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
94
[THIS PAGE INTENTIONALLY LEFT BLANK]
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, 20202022 and 2019,2021, the related consolidated statements of income, comprehensive income, common shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2020,2022, 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, 20202022 and 2019,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020,2022, 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 Directorsaudit 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
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; electric fuel and other energy-related purchases; 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
95
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 refundcredit a portion of its earnings to customers.
In connection with the evaluation of Virginia Power’s earnings for the four-year test period ended December 31, 2020, Virginia Power recorded a charge of $130 million for the year ended December 31, 2020 for benefits it expects to provide to its customers through the use of a customer credit reinvestment offset in accordance with the Virginia Grid Transformation and Security Act of 2018 (“GTSA”). This evaluation included consideration of the regulatory treatment of a charge of $754 million ($561 million after-tax) recorded in the first quarter of 2020, associated with Virginia Power’s commitment to retire certain coal- and oil-fired generating units before the end of their useful lives. Virginia Power determined it was appropriate to consider this charge to be recovered as a component of Virginia Power’s base rates under the GTSA. This determination required management judgment.
When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds 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,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 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.
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|
|
|
|
|
|
|
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/s/ Deloitte & Touche LLP
Richmond, Virginia
February 25, 202121, 2023
We have served as Virginia Power's auditor since 1988.
96
Virginia Electric and Power Company
Consolidated Statements of Income
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
(millions) |
|
|
|
|
|
|
|
|
| |||
Operating Revenue(1) |
| $ | 9,654 |
|
| $ | 7,470 |
|
| $ | 7,763 |
|
Operating Expenses |
|
|
|
|
|
|
|
|
| |||
Electric fuel and other energy-related purchases(1) |
|
| 2,913 |
|
|
| 1,735 |
|
|
| 1,636 |
|
Purchased (excess) capacity |
|
| 46 |
|
|
| 24 |
|
|
| (17 | ) |
Other operations and maintenance: |
|
|
|
|
|
|
|
|
| |||
Affiliated suppliers |
|
| 342 |
|
|
| 333 |
|
|
| 314 |
|
Other |
|
| 1,709 |
|
|
| 1,460 |
|
|
| 1,472 |
|
Depreciation and amortization |
|
| 1,736 |
|
|
| 1,364 |
|
|
| 1,252 |
|
Other taxes |
|
| 303 |
|
|
| 326 |
|
|
| 327 |
|
Impairment of assets and other charges (benefits) |
|
| 557 |
|
|
| (269 | ) |
|
| 1,093 |
|
Total operating expenses |
|
| 7,606 |
|
|
| 4,973 |
|
|
| 6,077 |
|
Income from operations |
|
| 2,048 |
|
|
| 2,497 |
|
|
| 1,686 |
|
Other income |
|
| — |
|
|
| 146 |
|
|
| 80 |
|
Interest and related charges(1) |
|
| 642 |
|
|
| 534 |
|
|
| 516 |
|
Income before income tax expense |
|
| 1,406 |
|
|
| 2,109 |
|
|
| 1,250 |
|
Income tax expense |
|
| 191 |
|
|
| 397 |
|
|
| 229 |
|
Net Income |
| $ | 1,215 |
|
| $ | 1,712 |
|
| $ | 1,021 |
|
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue(1) |
| $ | 7,763 |
|
| $ | 8,108 |
|
| $ | 7,619 |
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Electric fuel and other energy-related purchases(1) |
|
| 1,636 |
|
|
| 2,178 |
|
|
| 2,318 |
|
Purchased (excess) capacity |
|
| (17 | ) |
|
| 40 |
|
|
| 122 |
|
Other operations and maintenance: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliated suppliers |
|
| 314 |
|
|
| 367 |
|
|
| 305 |
|
Other |
|
| 1,472 |
|
|
| 1,376 |
|
|
| 1,371 |
|
Depreciation and amortization |
|
| 1,252 |
|
|
| 1,223 |
|
|
| 1,132 |
|
Other taxes |
|
| 327 |
|
|
| 328 |
|
|
| 300 |
|
Impairment of assets and other charges |
|
| 1,093 |
|
|
| 757 |
|
|
| — |
|
Total operating expenses |
|
| 6,077 |
|
|
| 6,269 |
|
|
| 5,548 |
|
Income from operations |
|
| 1,686 |
|
|
| 1,839 |
|
|
| 2,071 |
|
Other income |
|
| 80 |
|
|
| 98 |
|
|
| 22 |
|
Interest and related charges(1) |
|
| 516 |
|
|
| 524 |
|
|
| 511 |
|
Income from operations before income tax expense |
|
| 1,250 |
|
|
| 1,413 |
|
|
| 1,582 |
|
Income tax expense |
|
| 229 |
|
|
| 264 |
|
|
| 300 |
|
Net Income |
| $ | 1,021 |
|
| $ | 1,149 |
|
| $ | 1,282 |
|
|
|
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
97
Virginia Electric and Power Company
Consolidated Statements of Comprehensive Income
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Net income |
| $ | 1,021 |
|
| $ | 1,149 |
|
| $ | 1,282 |
|
| $ | 1,215 |
|
| $ | 1,712 |
|
| $ | 1,021 |
|
Other comprehensive income (loss), net of taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Net deferred gains (losses) on derivatives-hedging activities, net of $9, $8 and $(1) tax |
|
| (28 | ) |
|
| (22 | ) |
|
| 1 |
| ||||||||||||
Changes in unrealized net gains (losses) on nuclear decommissioning trust funds, net of $(3), $(2) and $— tax |
|
| 6 |
|
|
| 5 |
|
|
| — |
| ||||||||||||
Net deferred gains (losses) on derivatives-hedging activities, net of $(20), $(4) and $9 tax |
|
| 60 |
|
|
| 13 |
|
|
| (28 | ) | ||||||||||||
Changes in unrealized net gains (losses) on nuclear decommissioning trust funds, net of |
|
| (11 | ) |
|
| (2 | ) |
|
| 6 |
| ||||||||||||
Amounts reclassified to net income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Net derivative (gains) losses-hedging activities, net of $—, $— and $— tax |
|
| 2 |
|
|
| 1 |
|
|
| 1 |
| ||||||||||||
Net realized (gains) losses on nuclear decommissioning trust funds, net of $1, $1 and $— tax |
|
| (3 | ) |
|
| (1 | ) |
|
| — |
| ||||||||||||
Net derivative (gains) losses-hedging activities, net of $(1), $(1) and $— tax |
|
| 1 |
|
|
| 2 |
|
|
| 2 |
| ||||||||||||
Net realized (gains) losses on nuclear decommissioning trust funds, net of $—, $1 |
|
| — |
|
|
| (2 | ) |
|
| (3 | ) | ||||||||||||
Other comprehensive income (loss) |
|
| (23 | ) |
|
| (17 | ) |
|
| 2 |
|
|
| 50 |
|
|
| 11 |
|
|
| (23 | ) |
Comprehensive income |
| $ | 998 |
|
| $ | 1,132 |
|
| $ | 1,284 |
|
| $ | 1,265 |
|
| $ | 1,723 |
|
| $ | 998 |
|
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
98
Virginia Electric and Power Company
Consolidated Balance Sheets
|
| 2022 |
|
| 2021 |
| ||
(millions) |
|
|
|
|
|
| ||
ASSETS |
|
|
|
|
|
| ||
Current Assets |
|
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 22 |
|
| $ | 26 |
|
Customer receivables (less allowance for doubtful accounts of $21 and $28) |
|
| 1,578 |
|
|
| 1,172 |
|
Other receivables (less allowance for doubtful accounts of $2 at both dates) |
|
| 204 |
|
|
| 112 |
|
Affiliated receivables |
|
| 7 |
|
|
| 37 |
|
Inventories (average cost method): |
|
|
|
|
|
| ||
Materials and supplies |
|
| 663 |
|
|
| 610 |
|
Fossil fuel |
|
| 261 |
|
|
| 261 |
|
Derivative assets(1) |
|
| 765 |
|
|
| 76 |
|
Margin deposit assets |
|
| 310 |
|
|
| 167 |
|
Prepayments |
|
| 43 |
|
|
| 37 |
|
Regulatory assets |
|
| 1,140 |
|
|
| 850 |
|
Other |
|
| 9 |
|
|
| 2 |
|
Total current assets |
|
| 5,002 |
|
|
| 3,350 |
|
Investments |
|
|
|
|
|
| ||
Nuclear decommissioning trust funds |
|
| 3,202 |
|
|
| 3,734 |
|
Other |
|
| 3 |
|
|
| 3 |
|
Total investments |
|
| 3,205 |
|
|
| 3,737 |
|
Property, Plant and Equipment |
|
|
|
|
|
| ||
Property, plant and equipment |
|
| 54,697 |
|
|
| 49,890 |
|
Accumulated depreciation and amortization |
|
| (16,218 | ) |
|
| (15,234 | ) |
Total property, plant and equipment, net |
|
| 38,479 |
|
|
| 34,656 |
|
Deferred Charges and Other Assets |
|
|
|
|
|
| ||
Pension and other postretirement benefit assets(1) |
|
| 518 |
|
|
| 431 |
|
Intangible assets, net |
|
| 536 |
|
|
| 395 |
|
Regulatory assets |
|
| 4,247 |
|
|
| 4,130 |
|
Other(1) |
|
| 1,207 |
|
|
| 1,233 |
|
Total deferred charges and other assets |
|
| 6,508 |
|
|
| 6,189 |
|
Total assets |
| $ | 53,194 |
|
| $ | 47,932 |
|
At December 31, |
| 2020 |
|
| 2019 |
| ||
(millions) |
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 35 |
|
| $ | 17 |
|
Customer receivables (less allowance for doubtful accounts of $23 and $9) |
|
| 1,315 |
|
|
| 1,163 |
|
Other receivables (less allowance for doubtful accounts of $2 at both dates) |
|
| 91 |
|
|
| 106 |
|
Affiliated receivables |
|
| 5 |
|
|
| 27 |
|
Inventories (average cost method): |
|
|
|
|
|
|
|
|
Materials and supplies |
|
| 581 |
|
|
| 549 |
|
Fossil fuel |
|
| 281 |
|
|
| 324 |
|
Prepayments |
|
| 32 |
|
|
| 27 |
|
Regulatory assets |
|
| 295 |
|
|
| 433 |
|
Other(1) |
|
| 27 |
|
|
| 30 |
|
Total current assets |
|
| 2,662 |
|
|
| 2,676 |
|
Investments |
|
|
|
|
|
|
|
|
Nuclear decommissioning trust funds |
|
| 3,197 |
|
|
| 2,881 |
|
Other |
|
| 3 |
|
|
| 3 |
|
Total investments |
|
| 3,200 |
|
|
| 2,884 |
|
Property, Plant and Equipment |
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
| 46,736 |
|
|
| 47,038 |
|
Accumulated depreciation and amortization |
|
| (14,167 | ) |
|
| (14,156 | ) |
Total property, plant and equipment, net |
|
| 32,569 |
|
|
| 32,882 |
|
Deferred Charges and Other Assets |
|
|
|
|
|
|
|
|
Pension and other postretirement benefit assets(1) |
|
| 354 |
|
|
| 287 |
|
Intangible assets, net |
|
| 334 |
|
|
| 271 |
|
Regulatory assets |
|
| 3,509 |
|
|
| 1,863 |
|
Other(1) |
|
| 1,026 |
|
|
| 565 |
|
Total deferred charges and other assets |
|
| 5,223 |
|
|
| 2,986 |
|
Total assets |
| $ | 43,654 |
|
| $ | 41,428 |
|
|
|
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
99
|
| 2022 |
|
| 2021 |
| ||
(millions) |
|
|
|
|
|
| ||
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY |
|
|
|
|
|
| ||
Current Liabilities |
|
|
|
|
|
| ||
Securities due within one year |
| $ | 1,164 |
|
| $ | 313 |
|
Short-term debt |
|
| 941 |
|
|
| 745 |
|
Accounts payable |
|
| 600 |
|
|
| 402 |
|
Payables to affiliates |
|
| 255 |
|
|
| 121 |
|
Affiliated current borrowings |
|
| 2,024 |
|
|
| 699 |
|
Accrued interest, payroll and taxes |
|
| 270 |
|
|
| 274 |
|
Asset retirement obligations |
|
| 350 |
|
|
| 191 |
|
Regulatory liabilities |
|
| 506 |
|
|
| 647 |
|
Derivative liabilities (1) |
|
| 298 |
|
|
| 134 |
|
Other current liabilities |
|
| 826 |
|
|
| 567 |
|
Total current liabilities |
|
| 7,234 |
|
|
| 4,093 |
|
Long-Term Debt |
|
|
|
|
|
| ||
Long-term debt |
|
| 14,916 |
|
|
| 13,453 |
|
Other |
|
| 65 |
|
|
| 503 |
|
Total long-term debt |
|
| 14,981 |
|
|
| 13,956 |
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
| ||
Deferred income taxes and investment tax credits |
|
| 3,452 |
|
|
| 3,183 |
|
Asset retirement obligations |
|
| 3,743 |
|
|
| 3,732 |
|
Regulatory liabilities |
|
| 5,499 |
|
|
| 5,740 |
|
Other (1) |
|
| 1,040 |
|
|
| 1,248 |
|
Total deferred credits and other liabilities |
|
| 13,734 |
|
|
| 13,903 |
|
Total liabilities |
|
| 35,949 |
|
|
| 31,952 |
|
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 |
|
| 10,385 |
|
|
| 9,170 |
|
Accumulated other comprehensive income (loss) |
|
| 9 |
|
|
| (41 | ) |
Total common shareholder’s equity |
|
| 17,245 |
|
|
| 15,980 |
|
Total liabilities and shareholder’s equity |
| $ | 53,194 |
|
| $ | 47,932 |
|
At December 31, |
| 2020 |
|
| 2019 |
| ||
(millions) |
|
|
|
|
|
|
|
|
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY |
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Securities due within one year |
| $ | 8 |
|
| $ | 4 |
|
Short-term debt |
|
| 45 |
|
|
| 243 |
|
Accounts payable |
|
| 332 |
|
|
| 334 |
|
Payables to affiliates |
|
| 266 |
|
|
| 210 |
|
Affiliated current borrowings |
|
| 380 |
|
|
| 107 |
|
Accrued interest, payroll and taxes |
|
| 253 |
|
|
| 253 |
|
Asset retirement obligations |
|
| 166 |
|
|
| 340 |
|
Regulatory liabilities |
|
| 425 |
|
|
| 167 |
|
Derivative liabilities (1) |
|
| 390 |
|
|
| 243 |
|
Customer deposits |
|
| 114 |
|
|
| 121 |
|
Other current liabilities |
|
| 448 |
|
|
| 450 |
|
Total current liabilities |
|
| 2,827 |
|
|
| 2,472 |
|
Long-Term Debt |
|
|
|
|
|
|
|
|
Long-term debt |
|
| 13,207 |
|
|
| 12,325 |
|
Other |
|
| 480 |
|
|
| 16 |
|
Total long-term debt |
|
| 13,687 |
|
|
| 12,341 |
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
|
|
|
Deferred income taxes and investment tax credits |
|
| 2,779 |
|
|
| 2,962 |
|
Asset retirement obligations |
|
| 3,654 |
|
|
| 3,241 |
|
Regulatory liabilities |
|
| 5,338 |
|
|
| 5,074 |
|
Pension and other postretirement benefit liability(1) |
|
| 436 |
|
|
| 782 |
|
Other (1) |
|
| 376 |
|
|
| 567 |
|
Total deferred credits and other liabilities |
|
| 12,583 |
|
|
| 12,626 |
|
Total liabilities |
|
| 29,097 |
|
|
| 27,439 |
|
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 |
|
| 7,758 |
|
|
| 7,167 |
|
Accumulated other comprehensive loss |
|
| (52 | ) |
|
| (29 | ) |
Total common shareholder’s equity |
|
| 14,557 |
|
|
| 13,989 |
|
Total liabilities and shareholder’s equity |
| $ | 43,654 |
|
| $ | 41,428 |
|
|
|
|
|
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
100
Virginia Electric and Power Company
|
| Common Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Common Stock |
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||
|
| Shares |
|
| Amount |
|
| Other Paid-In Capital |
|
|
| Retained Earnings |
|
| AOCI |
|
| Total |
|
| Shares |
|
| Amount |
|
| Other Paid-In Capital |
|
| Retained Earnings |
|
| AOCI |
|
| Total |
| |||||||||||||||||||
(millions, except for shares) |
| (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
December 31, 2017 |
|
| 275 |
|
| $ | 5,738 |
| $ | 1,113 |
| $ | 5,311 |
| $ | 62 |
| $ | 12,224 |
| ||||||||||||||||||||||||||||||||||||
Cumulative-effect of changes in accounting principles |
|
|
|
|
|
|
|
|
|
|
|
| 79 |
|
| (76 | ) |
|
| 3 |
| |||||||||||||||||||||||||||||||||||
Net income |
|
|
|
|
|
|
|
|
|
| 1,282 |
|
|
|
|
| 1,282 |
| ||||||||||||||||||||||||||||||||||||||
Dividends |
|
|
|
|
|
|
|
|
|
| (464 | ) |
|
|
|
|
| (464 | ) | |||||||||||||||||||||||||||||||||||||
Other comprehensive income, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2 |
|
| 2 |
| ||||||||||||||||||||||||||||||||||||
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 |
|
|
| 275 |
|
| $ | 5,738 |
|
| $ | 1,113 |
|
| $ | 7,167 |
|
| $ | (29 | ) |
| $ | 13,989 |
| |||||||||||
Net income |
|
|
|
|
|
|
|
|
|
|
|
| 1,021 |
|
|
|
|
| 1,021 |
|
|
|
|
|
|
|
|
|
|
|
| 1,021 |
|
|
|
|
| 1,021 |
| |||||||||||||||||
Dividends |
|
|
|
|
|
|
|
|
|
| (430 | ) |
|
|
| (430 | ) |
|
|
|
|
|
|
|
|
|
|
| (430 | ) |
|
|
|
| (430 | ) | ||||||||||||||||||||
Other comprehensive loss, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (23 | ) |
|
| (23 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| (23 | ) |
|
| (23 | ) | |||||||||||||||
December 31, 2020 |
|
| 275 |
|
| $ | 5,738 |
| $ | 1,113 |
| $ | 7,758 |
| $ | (52 | ) |
| $ | 14,557 |
|
|
| 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 |
| ||||||||||||||||||||||||||||||||
Net income |
|
|
|
|
|
|
|
|
|
|
| 1,215 |
|
|
|
|
|
| 1,215 |
| ||||||||||||||||||||||||||||||||||||
Other comprehensive income, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 50 |
|
|
| 50 |
| ||||||||||||||||||||||||||||||||||||
December 31, 2022 |
|
| 275 |
|
| $ | 5,738 |
|
| $ | 1,113 |
|
| $ | 10,385 |
|
| $ | 9 |
|
| $ | 17,245 |
|
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
101
Virginia Electric and Power Company
Consolidated Statements of Cash Flows
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
|
| 2018 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Net income |
| $ | 1,021 |
|
| $ | 1,149 |
| $ | 1,282 |
|
| $ | 1,215 |
|
| $ | 1,712 |
|
| $ | 1,021 |
| |||||
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Depreciation and amortization (including nuclear fuel) |
|
| 1,421 |
|
| 1,392 |
| 1,309 |
|
|
| 1,892 |
|
|
| 1,521 |
|
|
| 1,421 |
| |||||||
Deferred income taxes and investment tax credits |
|
| (206 | ) |
| (80 | ) |
| 224 |
|
|
| 191 |
|
|
| 343 |
|
|
| (206 | ) | ||||||
Charge (revision) for future ash pond and landfill closure costs |
|
| 11 |
|
| (113 | ) |
| 81 |
| ||||||||||||||||||
Impairment of assets and other charges |
|
| 1,079 |
|
|
|
| 624 |
|
|
|
|
| — |
| |||||||||||||
Provision for rate credits to customers |
|
| — |
|
|
|
| — |
|
|
|
|
| 77 |
| |||||||||||||
Charges related to a voluntary retirement program |
|
| — |
|
| 116 |
| — |
| |||||||||||||||||||
Impairment of assets and other charges (benefits) |
|
| 493 |
|
|
| (269 | ) |
|
| 1,079 |
| ||||||||||||||||
Provision for refunds to customers |
|
| — |
|
|
| 356 |
|
|
| — |
| ||||||||||||||||
Other adjustments |
|
| (61 | ) |
| (86 | ) |
| (21 | ) |
|
| 24 |
|
|
| 19 |
|
|
| (50 | ) | ||||||
Changes in: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Accounts receivable |
|
| (266 | ) |
| (196 | ) |
| (60 | ) |
|
| (629 | ) |
|
| (112 | ) |
|
| (266 | ) | ||||||
Affiliated receivables and payables |
|
| 78 |
|
| 75 |
| (14 | ) |
|
| 165 |
|
|
| (175 | ) |
|
| 78 |
| |||||||
Inventories |
|
| 10 |
|
| (56 | ) |
| 13 |
|
|
| (71 | ) |
|
| (10 | ) |
|
| 10 |
| ||||||
Prepayments |
|
| (5 | ) |
| 1 |
| (1 | ) |
|
| (7 | ) |
|
| (4 | ) |
|
| (5 | ) | |||||||
Deferred fuel expenses, net |
|
| 131 |
|
| 243 |
| (269 | ) |
|
| (1,393 | ) |
|
| (652 | ) |
|
| 131 |
| |||||||
Accounts payable |
|
| 6 |
|
| (31 | ) |
| (26 | ) |
|
| 145 |
|
|
| 19 |
|
|
| 6 |
| ||||||
Accrued interest, payroll and taxes |
|
| (4 | ) |
| 5 |
| (8 | ) |
|
| (4 | ) |
|
| 21 |
|
|
| (4 | ) | |||||||
Margin deposit assets and liabilities |
|
| (143 | ) |
|
| (166 | ) |
|
| (1 | ) | ||||||||||||||||
Net realized and unrealized changes related to derivative activities |
|
| (6 | ) |
| 21 |
| 119 |
|
|
| 109 |
|
|
| — |
|
|
| (6 | ) | |||||||
Other operating assets and liabilities |
|
| (309 | ) |
|
| (280 | ) |
|
| 134 |
|
|
| (159 | ) |
|
| (106 | ) |
|
| (308 | ) | ||||
Net cash provided by operating activities |
|
| 2,900 |
|
|
| 2,784 |
|
| 2,840 |
|
|
| 1,828 |
|
|
| 2,497 |
|
|
| 2,900 |
| |||||
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Plant construction and other property additions |
|
| (3,138 | ) |
| (2,642 | ) |
| (2,228 | ) |
|
| (4,909 | ) |
|
| (3,521 | ) |
|
| (3,138 | ) | ||||||
Purchases of nuclear fuel |
|
| (199 | ) |
| (157 | ) |
| (173 | ) |
|
| (201 | ) |
|
| (160 | ) |
|
| (199 | ) | ||||||
Acquisition of solar development projects |
|
| (35 | ) |
| (182 | ) |
| (141 | ) |
|
| (77 | ) |
|
| (75 | ) |
|
| (35 | ) | ||||||
Proceeds from sales of securities |
|
| 884 |
|
| 858 |
| 887 |
|
|
| 1,538 |
|
|
| 1,791 |
|
|
| 884 |
| |||||||
Purchases of securities |
|
| (936 | ) |
| (905 | ) |
| (925 | ) |
|
| (1,580 | ) |
|
| (1,789 | ) |
|
| (936 | ) | ||||||
Other |
|
| 21 |
|
|
| (37 | ) |
|
| (63 | ) |
|
| 34 |
|
|
| — |
|
|
| 21 |
| ||||
Net cash used in investing activities |
|
| (3,403 | ) |
|
| (3,065 | ) |
|
| (2,643 | ) |
|
| (5,195 | ) |
|
| (3,754 | ) |
|
| (3,403 | ) | ||||
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Repayment of short-term debt, net |
|
| (198 | ) |
| (71 | ) |
| (228 | ) | ||||||||||||||||||
Issuance (repayment) of affiliated current borrowings, net |
|
| 273 |
|
| (117 | ) |
| 191 |
| ||||||||||||||||||
Issuance (repayment) of short-term debt, net |
|
| 196 |
|
|
| 700 |
|
|
| (198 | ) | ||||||||||||||||
Issuance of affiliated current borrowings, net |
|
| 1,325 |
|
|
| 319 |
|
|
| 273 |
| ||||||||||||||||
Issuance and remarketing of long-term debt |
|
| 1,327 |
|
| 1,248 |
| 1,300 |
|
|
| 2,338 |
|
|
| 1,000 |
|
|
| 1,327 |
| |||||||
Repayment and repurchase of long-term debt |
|
| (427 | ) |
| (591 | ) |
| (964 | ) |
|
| (438 | ) |
|
| (450 | ) |
|
| (427 | ) | ||||||
Common dividend payments to parent |
|
| (430 | ) |
| (190 | ) |
| (464 | ) |
|
| — |
|
|
| (300 | ) |
|
| (430 | ) | ||||||
Other |
|
| (31 | ) |
|
| (12 | ) |
|
| (18 | ) |
|
| (56 | ) |
|
| (21 | ) |
|
| (31 | ) | ||||
Net cash provided by (used in) financing activities |
|
| 514 |
|
|
| 267 |
|
| (183 | ) | |||||||||||||||||
Net cash provided by financing activities |
|
| 3,365 |
|
|
| 1,248 |
|
|
| 514 |
| ||||||||||||||||
Increase (decrease) in cash, restricted cash and equivalents |
|
| 11 |
|
|
| (14 | ) |
|
| 14 |
|
|
| (2 | ) |
|
| (9 | ) |
|
| 11 |
| ||||
Cash, restricted cash and equivalents at beginning of year |
|
| 24 |
|
|
| 38 |
|
| 24 |
|
|
| 26 |
|
|
| 35 |
|
|
| 24 |
| |||||
Cash, restricted cash and equivalents at end of year |
| $ | 35 |
|
| $ | 24 |
| $ | 38 |
|
| $ | 24 |
|
| $ | 26 |
|
| $ | 35 |
|
See Note 2 for disclosure of supplemental cash flow information.
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
102
Combined Notes to Consolidated Financial Statements
NOTE 1. NATURE OF OPERATIONS
Dominion Energy, headquartered in Richmond, Virginia, is one of the nation’s largest producers and distributors of energy. Dominion Energy’s operations are conducted through various subsidiaries, including Virginia Power. Dominion Energy’s operations also include DESC, regulated gas distribution operations primarily in the eastern and Rocky Mountain regions of the U.S., nonregulated electric generation and, following the completion of the GT&S Transaction in November 2020, a noncontrolling interest in Cove Point. See Note 3 for a description of the sale of substantially all of Dominion Energy’s gas transmission and storage operations to BHE through the GT&S Transaction completed in November 2020 and the proposed Q-Pipe Transaction of Dominion Energy’s remaining regulated gas transmission and storage services in the Rocky Mountain regionsale of the U.S.Q-Pipe Group completed in December 2021.
Beginning in September 2020, Dominion Energy manages its daily operations through 4four primary operating segments: Dominion Energy Virginia, Gas Distribution, Dominion Energy South Carolina and Contracted Assets. Dominion Energy also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) as well as nonregulated retail energy marketing operations, including Dominion Energy’s noncontrolling interest in Wrangler.Dominion Privatization. Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the operating segments’ performance or in allocating resources. In addition, Corporate and Other includes the net impact of discontinued operations consisting 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 1one primary operating segment: Dominion Energy Virginia. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources.
See Note 26 for further discussion of the Companies’ operating segments.
NOTE 2. SIGNIFICANT ACCOUNTING POLICIES
General
The Companies make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues, expenses and cash flows for the periods presented. Actual results may differ from those estimates.
The Companies’ Consolidated Financial Statements include, after eliminating intercompany transactions and balances, their accounts, those of their respective majority-owned subsidiaries and non-wholly-owned entities in which they have a controlling financial interest. For certain partnership structures, income is allocated based on the liquidation value of the underlying contractual arrangements. At December 31, 2020 Dominion Energy owns 50% of the voting interests in Four Brothers and Three Cedars and has a controlling financial interest over the entities through its right to control operations. In August 2018, NRG’sClearway’s ownership interest in Four Brothers and Three Cedars was transferred to GIP. GIP’s ownership interest in Four Brothers and Three Cedars,(through December 2021), Terra Nova Renewable Partners’ 33%33% interest in certain Dominion Energy nonregulated solar projects (through December 2021) and Brookfield’s 25%25% interest in Cove Point (effective December 2019 until(through November 2020) and the non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019) are reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. Terra Nova Renewable Partners has a future option to buy all or a portion of Dominion Energy’s remaining 67% ownership in certain nonregulated projects upon the occurrence of certain events, including any proposed sale by Dominion Energy of its interest.
The Companies report certain contracts, instruments and investments at fair value. See below and 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’ 20192021 and 20182020 Consolidated Financial Statements and Notes have been reclassified to conform to the 20202022 presentation for comparative purposes; however, such reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows. Effective in 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 was previously conformed to this presentation, which did 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, 20202022 and 20192021 included $1.1$1.1 billion and $829$779 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility customers. Virginia Power’s customer receivables at December 31, 20202022 and 20192021 included $740$620 million and $512$398 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 as well as 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 (through December 2022) and revenue associated with services provided to entities presented in discontinued operations under transition services agreements.
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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 primary types of sales and service activities reported as operating revenue for Virginia Power are as follows:
Revenue from Contracts with Customers
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Other Revenue
• Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues. 104
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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 or to be sold to BHE as part of the GT&S Transaction and sold to Southwest Gas as part of the Q-Pipe TransactionGroup sale primarily consistsconsisted of FERC-regulated sales of transmission and storage services, LNG terminalling services, sales of extracted products and associated hedging activities and NGL activities, including gathering and processing and sales of production and condensate as well as services performed for Atlantic Coast Pipeline. This revenue is included in discontinued operations in Dominion Energy’s Consolidated Statements of Income.
Transportation and storage contracts associated with the operations sold or to be sold to BHE as part of the GT&S Transaction and sold to Southwest Gas as part of the Q-Pipe Transaction areGroup 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 continuescontinued 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, expectedExpected credit losses are estimated and recorded based on historical experience, current conditions and reasonable and supportable forecasts that affect the collectability of financial assets held at amortized cost as well as expected credit losses on commitments with respect to financial guarantees.
Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs
Where permitted by regulatory authorities, the differences between the Companies’ actual electric fuel and purchased energy expenses and Dominion Energy’s purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.
Of the cost of fuel used in electric generation and energy purchases to serve Virginia utility customers, at December 31, 2020,2022, approximately 85%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, 2020,2022, approximately 96%96% is subject to DESC���sDESC’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.
Dominion Energy can earn certain cost saving sharing incentives under the Wexpro Agreements to the extent that the cost of gas supplied to Questar Gas is a certain amount lower than third-party market rates. In 2022, Dominion Energy recorded $27 million for such incentives. No amounts were recorded for the years ended December 31, 2021 or 2020.
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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, 2020,2022, Virginia Power had ana net income tax-related affiliated payable of $19$22 million, comprised of $17$25 million of federal income taxes payable to, and $2$3 million of state income taxes due toreceivable from, Dominion Energy. TheseVirginia Power’s net affiliated balances are expected to be paid to Dominion Energy.
At December 31, 2019,2021, Virginia Power had an income tax-related affiliated payablereceivable of $35$35 million, comprised of $15$33 million of federal income taxes and $20$2 million of state income taxes due toreceivable from Dominion Energy. Virginia Power’s netThese affiliated balances were paid toreceived from 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. The IRA allows the election of either the investment tax credit or production tax credit for certain technologies including solar and wind. Such election is made on a project-by-project basis and the choice of credit may vary based on a combination of factors including, but not limited to, capital expenditures and net capacity factors.
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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, |
| 2022 |
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| 2021 |
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(millions) |
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Dominion Energy |
| $ | 49 |
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| $ | 70 |
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Virginia Power |
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| 21 |
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| 15 |
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At December 31, |
| 2020 |
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| 2019 |
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(millions) |
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Dominion Energy |
| $ | 50 |
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| $ | 29 |
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Virginia Power |
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| 30 |
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| 9 |
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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, 2022, 2021, 2020 and 2019:
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| Cash, Restricted Cash and Equivalents at End/Beginning of Year |
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| December 31, 2022 |
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| December 31, 2021 |
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| December 31, 2020 |
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| December 31, 2019 |
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(millions) |
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Dominion Energy |
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Cash and cash equivalents(1) |
| $ | 153 |
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| $ | 283 |
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| $ | 179 |
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| $ | 166 |
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Restricted cash and equivalents(2)(3) |
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| 188 |
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| 125 |
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| 68 |
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| 103 |
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Cash, restricted cash and equivalents shown in the |
| $ | 341 |
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| $ | 408 |
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| $ | 247 |
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| $ | 269 |
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Virginia Power |
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Cash and cash equivalents |
| $ | 22 |
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| $ | 26 |
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| $ | 35 |
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| $ | 17 |
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Restricted cash and equivalents(3) |
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| 2 |
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| — |
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| — |
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| 7 |
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Cash, restricted cash and equivalents shown in the |
| $ | 24 |
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| $ | 26 |
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| $ | 35 |
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| $ | 24 |
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| Cash, Restricted Cash and Equivalents at End/Beginning of Year |
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| December 31, 2020 |
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| December 31, 2019 |
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| December 31, 2018 |
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| December 31, 2017 |
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(millions) |
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Dominion Energy |
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Cash and cash equivalents(1) |
| $ | 179 |
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| $ | 166 |
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| $ | 268 |
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| $ | 120 |
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Restricted cash and equivalents(2)(3) |
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| 68 |
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| 103 |
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| 123 |
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| 65 |
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Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows |
| $ | 247 |
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| $ | 269 |
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| $ | 391 |
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| $ | 185 |
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Virginia Power |
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Cash and cash equivalents |
| $ | 35 |
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| $ | 17 |
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| $ | 29 |
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| $ | 14 |
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Restricted cash and equivalents(3) |
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| 7 |
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| 9 |
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| 10 |
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Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows |
| $ | 35 |
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| $ | 24 |
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| $ | 38 |
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| $ | 24 |
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(2) At December 31, 2020 and December 31, 2019, Dominion Energy had $3 million and $12 million of restricted cash and equivalents included in current assets held for sale, respectively. No amounts were included in current assets held for sale at December 31, 2022 and 2021. (3) Restricted cash and equivalent balances are presented within other current assets in the Companies’ Consolidated Balance Sheets.
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Supplemental Cash Flow Information
The following table provides supplemental disclosure of cash flow information related to Dominion Energy:
Year Ended December 31, |
| 2022 |
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| 2021 |
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| 2020 |
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(millions) |
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Cash paid during the year for: |
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Interest and related charges, excluding capitalized amounts |
| $ | 1,408 |
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| $ | 1,340 |
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| $ | 1,519 |
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Income taxes |
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| 139 |
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| 160 |
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| 292 |
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Significant noncash investing and financing activities:(1)(2) |
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Accrued capital expenditures |
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| 979 |
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| 637 |
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| 485 |
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Leases(3) |
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| 144 |
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| 96 |
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| 173 |
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Year Ended December 31, |
| 2020 |
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| 2019 |
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| 2018 |
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Cash paid during the year for: |
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Interest and related charges, excluding capitalized amounts |
| $ | 1,519 |
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| $ | 1,643 |
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| 1,362 |
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Income taxes |
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| 292 |
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| 106 |
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| 89 |
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Significant noncash investing and financing activities:(1)(2)(3)(4)(5) |
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Accrued capital expenditures |
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| 485 |
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| 555 |
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| 307 |
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Leases(6) |
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| 173 |
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| 157 |
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| — |
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Receivables from sales of assets and equity method investments |
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| — |
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| 5 |
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| 159 |
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The following table provides supplemental disclosure of cash flow information related to Virginia Power:
Year Ended December 31, |
| 2022 |
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| 2021 |
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| 2020 |
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(millions) |
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Cash paid (received) during the year for: |
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Interest and related charges, excluding capitalized amounts |
| $ | 599 |
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| $ | 501 |
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| $ | 491 |
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Income taxes |
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| (54 | ) |
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| 109 |
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| 452 |
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Significant noncash investing activities:(1) |
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Accrued capital expenditures |
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| 665 |
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| 363 |
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| 262 |
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Leases(2) |
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| 116 |
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| 79 |
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| 32 |
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Year Ended December 31, |
| 2020 |
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| 2019 |
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| 2018 |
| |||
Cash paid during the year for: |
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Interest and related charges, excluding capitalized amounts |
| $ | 491 |
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| $ | 495 |
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| $ | 498 |
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Income taxes |
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| 452 |
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| 272 |
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| 128 |
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Significant noncash investing activities:(1), (2) |
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Accrued capital expenditures |
|
| 262 |
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| 292 |
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| 204 |
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Leases (3) |
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| 32 |
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| 55 |
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| — |
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(2) Includes $26 million of finance leases and $90 million of operating leases entered in 2022, $37 million of finance leases and $42 million of operating leases entered in 2021 and $32 million of finance leases entered in 2020.
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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.
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.
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For options and contracts with option-like characteristics where observable pricing information is not available from external sources, the Companies generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. The Companies use other option models under special circumstances, including but not limited to Spread Approximation Model and a Swing Option Model. For contracts with unique characteristics, the Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.
The inputs and assumptions used in measuring fair value include the following:
Derivative Contracts | ||||||||
Inputs and assumptions | Commodity | Interest Rate | Foreign Currency Exchange Rate | Investments | ||||
Forward commodity prices | X | |||||||
Transaction prices | X | |||||||
Price volatility | X | |||||||
Price correlation | X | |||||||
Volumes | X | |||||||
Commodity location | X | |||||||
Interest rate curves | X | |||||||
Foreign currency forward exchange rates | X | |||||||
Quoted securities prices and indices | X | |||||||
Securities trading information including volume and restrictions | X | |||||||
Maturity | X | |||||||
Interest rates | X | X | X | |||||
Credit quality of counterparties and the Companies | X | X | X | X | ||||
Credit enhancements | X | X | ||||||
Notional value | X | X | ||||||
Time value | X | X | X |
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:
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.
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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.
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 riskand 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, and interest rate and/or foreign currency exchange rate risks of their business operations.
All derivatives, except those for which an exception applies,Derivative assets and liabilities are required to be reported inpresented gross on the Companies’ Consolidated Balance Sheets at fair value.Sheets. 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. All derivatives, except those for which an exception applies, are required to be reported at fair value. 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 6Fair Value Measurements above for furtheradditional information about fair value measurements and associated valuation methods for derivatives.
The Companies' 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 offset through master netting arrangements, derivative clearing agreements and contract default provisions. In addition, the contracts are subject to conditional rights of offset 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.
The Companies do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion Energy had margin assets of $19$480 million and $42$678 million associated with cash collateral at December 31, 20202022 and 2019,2021, respectively. Dominion Energy had margin liabilities of $5 million and $2 million associated with cash collateral at December 31, 2020 and 2019, respectively. Virginia Power had margin assets of $1 million and less than $1 million associated with cash collateral at December 31, 2020 and 2019, respectively. Virginia Power had 0no margin liabilities associated with cash collateral at December 31, 20202022 and 2019.2021. Virginia Power had margin assets of $310 million and $167 million associated with cash collateral at December 31, 2022 and 2021, respectively. Virginia Power had no margin liabilities associated with cash collateral at December 31, 2022 and 2021. 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 represent economic hedges that mitigate their exposure to fluctuations in commodity prices.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.
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Cash Flow Hedges
-AA majority of the Companies’ hedge strategies represents cash flow hedges of the variable price risk primarily associated with the purchaseuse of natural gas. The Companies also use interest rate swaps to hedge their exposure to variable interest rates on long-term debt. For transactions in which the Companies are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item.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
-DominionDominion Energy hasmay also designateddesignate interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting.
Property, Plant and Equipment
Property, plant and equipment is recorded at lower of original cost or fair value, if impaired. Capitalized costs include labor, materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is generally charged to expense as it is incurred.
In 2020, 2019,2022, 2021 and 2018,2020, Dominion Energy capitalized interest costs and AFUDC to property, plant and equipment of $103$112 million, $78$117 million and $109$103 million, respectively. In 2020, 2019,2022, 2021 and 2018,2020, Virginia Power capitalized AFUDC to property, plant and equipment of $60$66 million, $34$78 million and $56$60 million, respectively.
Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2020, 2019,2022, 2021 and 2018,2020, Virginia Power recorded $11$34 million, $11$35 million and $4$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 March 2020, Virginia Power committed to retire certain coal- and 2019,oil-fired generating units before the Companies hadend of their useful lives based on economic and other factors, including but not limited to market power prices and the following charges, primarilyVCEA. These units will be retired after they meet their capacity obligations to PJM in 2023. As a result, Virginia Power recorded a charge of $751 million ($559 million after-tax) in impairment of assets and other charges in theits Consolidated Statements of Income (reflected in the Corporate and Other segment) for the year ended December 31, 2020. This charge was 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 2022 and 2020, Virginia Power recorded charges of $167 million ($124 million after-tax) and $54 million ($40 million after-tax), related to early retirements:respectively, in impairment of assets and other charges in its Consolidated Statements of Income (reflected in the Corporate and Other segment) associated with dismantling certain of these electric generation facilities.
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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:
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Year Ended December 31, |
| 2020 |
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| 2019 |
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| 2018 |
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(percent) |
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Dominion Energy(1) |
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Generation |
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| 2.51 |
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| 2.84 |
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| 2.71 |
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Transmission |
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| 2.48 |
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| 2.50 |
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| 2.50 |
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Distribution |
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| 2.76 |
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| 2.80 |
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| 2.97 |
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Storage |
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| 1.59 |
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| 1.49 |
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| 2.20 |
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General and other |
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| 4.35 |
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| 3.99 |
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| 4.11 |
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Virginia Power |
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Generation |
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| 2.52 |
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| 2.94 |
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| 2.71 |
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Transmission |
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| 2.52 |
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| 2.54 |
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| 2.52 |
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Distribution |
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| 3.19 |
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| 3.14 |
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| 3.31 |
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General and other |
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| 5.09 |
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| 4.40 |
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| 4.52 |
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Year Ended December 31, |
| 2022 |
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| 2021 |
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| 2020 |
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(percent) |
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Dominion Energy(1) |
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Generation |
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| 2.71 |
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| 2.63 |
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| 2.51 |
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Transmission |
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| 2.29 |
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| 2.47 |
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| 2.48 |
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Distribution |
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| 2.57 |
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| 2.76 |
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| 2.76 |
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Storage |
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| 1.89 |
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| 1.79 |
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| 1.59 |
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General and other |
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| 3.89 |
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| 3.85 |
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| 4.35 |
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Virginia Power |
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Generation |
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| 2.84 |
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| 2.69 |
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| 2.52 |
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Transmission |
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| 2.29 |
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| 2.51 |
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| 2.52 |
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Distribution |
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| 2.76 |
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| 3.18 |
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| 3.19 |
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General and other |
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| 4.78 |
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| 5.08 |
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| 5.09 |
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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$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$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 resulted in an annual decrease of depreciation expense of $16 million ($12 million after-tax), including $6 million ($4 million after-tax) at Virginia Power, and increased Dominion Energy’s EPS by approximately $0.02.
In 2018,the first quarter of 2022, Virginia Power revised the depreciation rates for regulated nuclear plantsits assets to comply with Virginia Commission requirements. Forreflect the year ended December 31, 2018, this adjustmentresults of a new depreciation study. The change resulted in a decrease of $60 million ($44 million after-tax) in depreciation expense in Virginia Power’s Consolidated Statements of Income of $60 million ($45 million after-tax) and an increase toincreased Dominion Energy’s EPS of $0.07 per share. This change resulted in an annual decrease in depreciation expense of $30 million ($23 million after-tax)by $0.05.
Virginia Power’s non-jurisdictional solar generation property, plant and equipment is depreciated using the straight-line method over an estimated useful life of 30 years.35 years, effective January 2022.
Capitalized costs of development wells and leaseholds are amortized on a field-by-field basis using the unit-of-production method and the estimated proved developed or total proved gas and oil reserves, at a rate of $1.97$1.67 and $1.80$1.92 per mcfe in 20202022 and 2019,2021, 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-other |
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Depreciation and amortization related to Virginia Power’s nonutility property, plant and equipment and Dominion Energy’s exploration and production properties was immaterial for the years ended December 31, 2020, 2019, and 2018.
Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. The Companies report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.
Long-Lived and Intangible Assets
The Companies perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 6 for further discussion on the impairment of long-lived assets.
Regulatory Assets and Liabilities
The accounting for the Companies’ regulated electric and gas operations differs from the accounting for nonregulated operations in that the Companies are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated
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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. |
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Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. A regulatory liability, if considered probable, will be recorded in the period such assessment is made or reversed into earnings if no longer probable. See Notes 12 and 13 to the Consolidated Financial Statements for additional information.
Leases
The Companies lease certain assets including vehicles, real estate, office equipment and other operational assets under both operating and finance leases. For the Companies’ operating leases, rent expense is recognized on a straight-line basis over the term of the lease agreement, subject to regulatory framework. Rent expense associated with operating leases, short-term leases and variable leases is primarily recorded in other operations and maintenance expense in the Companies’ Consolidated Statements of Income. Rent expense associated with finance leases results in the separate presentation of interest expense on the lease liability and amortization expense of the related right-of-use asset in the Companies’ Consolidated Statements of Income 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.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 primarily over an estimated useful life of 30 years.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
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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.
Investments
Debt and Equity Securities with Readily Determinable Fair Values
Dominion Energy accounts for and classifies investments in debt securities as trading or available-for-sale securities. Virginia Power classifies investments in debt securities as available-for-sale securities.
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In determining realized gains and losses for debt securities, the cost basis of the security is based on the specific identification method.
Equity securities with readily determinable fair values include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans and securities held by the Companies in the nuclear decommissioning trusts. The Companies record all equity securities with a readily determinable fair value, or for which they are permitted to estimate fair value using NAV (or its equivalent), at fair value in nuclear decommissioning trust funds and other investments in the Consolidated Balance Sheets. However, the Companies may elect a measurement alternative for equity securities without a readily determinable fair value. Under the measurement alternative, equity securities are reported at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. The Companies qualitatively assess equity securities reported using the measurement alternative to determine whether an investment is impaired on an ongoing basis. Net realized and unrealized gains and losses on equity securities held in the nuclear decommissioning trusts are deferred to a regulatory asset or liability, as applicable, for certain jurisdictions subject to cost-based regulation. For all other equityavailable-for-sale debt securities, including those held in Dominion Energy’s nonregulated generation nuclear decommissioning trusts, and rabbi trusts, net realized gains and losses (including any credit-related impairments) are included in other income and unrealized gains and losses are included in other income inreported as a component of AOCI, after-tax.
In determining realized gains and losses for debt securities, the Consolidated Statementscost basis 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:
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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,based on the investment is written down to its fair value at the end of the reporting period.specific identification method.
Credit Impairment
Effective January 2020, theThe 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.factors
InventoriesEquity 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
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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:
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 $2$14 million and $19$26 million at December 31, 20202022 and December 31, 2019,2021, respectively. Based on the average price of gas purchased during 20202022 and 2019,2021, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by $52$129 million and $60$74 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.In 2022, Dominion Energy values these imbalances due to, or from, shipperswrote off certain inventory balances associated with certain nonrenewable electric generation facilities resulting in a $40 million charge ($30 million after-tax) recorded in impairments 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 liabilitiescharges (reflected in the Corporate and Other segment) in its Consolidated Balance Sheets.Statements of Income, including $19 million ($14 million after-tax) at Virginia Power for inventory not expected to be utilized at such facilities prior to their planned retirement in the first half of 2023.
Goodwill
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 date is for Dominion Energy’s interim and annual reporting periods beginning January 1, 2022 and may be adopted through a modified retrospective or fully retrospective method of transition.2022. Upon adoption, Dominion Energy willapplied the guidance using a modified
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retrospective approach and continued 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, such as the Series A Preferred Stock.
Revenue Recognition
In May 2014, the FASB issued revised accounting guidance for revenue recognition from contracts with customers. The Companies adopted this revised accounting guidance for interim and annual reporting periods beginning January 1, 2018 using the modified retrospective method. Upon the adoption of the standard, Dominion Energy recorded the cumulative-effect of a change in accounting principle of $3 million to retained earnings, and to establish a contract asset related to changes in the timing of revenue recognition for three existing contracts with customers at DETI.
Financial Instruments
In January 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of financial instruments. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018 and the Companies adopted the standard using the modified retrospective method. Upon adoption of this guidance for equity securities held at January 1, 2018, The Companies recorded the cumulative-effect of a change in accounting principle to reclassify net unrealized gains from AOCI to retained earnings and to recognize equity securities previously categorized as cost method investments at fair value (using NAV) in nuclear decommissioning trust funds in the Consolidated Balance Sheets and a cumulative-effect adjustment to retained earnings. Dominion Energy and Virginia Power reclassified approximately $1.1 billion ($734 million after-tax) and $119 million ($73 million after-tax), respectively, of net unrealized gains from AOCI to retained earnings. The Companies also
cash.recorded approximately $36 million ($22 million after-tax) in net unrealized gains on equity securities previously classified as cost method investments, of which $3 million was recorded to retained earnings and $33 million was recorded to regulatory liabilities for net unrealized gains subject to cost-based regulation. As a result of adopting this revised accounting guidance, Dominion Energy recorded unrealized losses on equity securities, net of regulatory deferrals, of $190 million ($142 million after-tax) in other income in the Consolidated Statements of Income for the year ended December 31, 2018, resulting in an $0.22 loss per share for the year ended December 31, 2018. Virginia Power recorded unrealized losses on equity securities, net of regulatory deferrals, of $24 million ($18 million after-tax) in other income in the Consolidated Statements of Income for the year ended December 31, 2018.
Leases
In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases classified as operating leases, while also refining the definition of a lease. In addition, lessees are required to disclose key information about the amount, timing and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged.
The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2019. The Companies adopted this revised accounting guidance using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Companies utilized the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Companies also applied the other practical expedients, which required no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. In connection with the adoption of this revised accounting guidance, Dominion Energy and Virginia Power recorded $504 million and $209 million, respectively, of offsetting right-of-use assets and liabilities for operating leases in effect at the adoption date. As a result of the GT&S and Q-Pipe Transactions, $43 million of such right-of-use assets and liabilities for operating leases recorded were associated with discontinued operations. See Note 15 for additional information.
Derecognition and Partial Sales of Nonfinancial Assets
In February 2017, the FASB issued revised accounting guidance clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018, and the Companies adopted the standard using the modified retrospective method. Upon adoption of the standard, Dominion Energy recorded the cumulative-effect of a change in accounting principle to reclassify $127 million from noncontrolling interests to common stock related to the sale of a noncontrolling interest in certain nonregulated solar projects completed in December 2015 and January 2016.
Tax Reform
In February 2018, the FASB issued revised accounting guidance to provide clarification on the application of the 2017 Tax Reform Act for balances recorded within AOCI. The revised guidance provides for stranded amounts within AOCI from the impacts of the 2017 Tax Reform Act to be reclassified to retained earnings. The Companies adopted this guidance for interim and annual reporting periods beginning January 1, 2018 on a prospective basis. In connection with the adoption of this guidance, Dominion Energy reclassified a benefit of $289 million from AOCI to retained earnings and Virginia Power reclassified a benefit of $3 million from AOCI to retained earnings. The amounts reclassified reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of the Companies’ AOCI.
NOTE 3. ACQUISITIONS AND DISPOSITIONS
Dominion Energy
Disposition of Gas Transmission & Storage Operations to BHE
In July 2020, Dominion Energy entered into an agreement with BHE with a total value of approximately $10$10 billion, comprised of approximately $4.0$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%100% of the general partner interest and 25%25% of the total limited partner interests). The agreement provides that Dominion Energy retains the assets and obligations of the pension and other postretirement employee benefit plans associated with the operations included in the transaction and relating to services provided through closing. In October 2020, pursuant to a provision in the agreement with BHE, Dominion Energy elected to exclude Dominion Energy Questar Pipelinethe 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 willwould sell Dominion Energy Questar Pipelinethe Q-Pipe Group and certain other affiliated entities to BHE for cash consideration of $1.3$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$2.7 billion. This transaction iswas structured as an asset sale for tax purposes. Dominion Energy retained a 50%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$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$127 million (net of a $1.4$1.4 billion write-off of goodwill and a $222$222 million closing adjustment paid to BHE in December 2020) and an associated tax expense of $336$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.closing, subsequently extended through June 2023 for certain services. In addition, BHE will provideprovided certain administrative services to Dominion Energy.Energy through December 2022. Dominion Energy recorded revenue of $4$20 million, $21 million and $4 million associated with the transition serviceservices agreement in operating revenue in the Consolidated Statements of Income for the years ended December 31, 2022, 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 was 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 provided that Dominion Energy retain 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 was 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. In 2022, Dominion Energy recognized a gain of $27 million ($20 million after-tax) in discontinued operations in its Consolidated Statements of Income associated with the finalization of working capital adjustments.
116
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, subsequently extended through July 2023 for certain services. Dominion Energy recorded $6 million associated with the transition services agreement in operating revenue in the Consolidated Statements of Income for the year ended December 31, 2020.
2022.
Also in November 2020, BHE provided a $1.3 billion deposit to Dominion Energy on the Q-Pipe Transaction. Dominion Energy will be required to repay all or substantially all of this deposit, or issue to BHE an equivalent value in shares of Dominion Energy common stock at Dominion Energy’s option, if the Q-Pipe Transaction does not close by December 30, 2021. Dominion Energy may not solicit or accept offers from alternative buyers for all or a material portion of the Q-Pipe Transaction until after March 31, 2021 and either party may terminate the Q-Pipe Transaction if closing has not occurred on or before June 30, 2021. If the Hart-Scott-Rodino Act approval has not been obtained by June 30, 2021, upon BHE’s request, Dominion Energy will seek an alternative buyer for all or a material portion of the Q-Pipe Transaction. The Q-Pipe Transaction is structured as an asset sale for tax purposes and is expected to close in early 2021, contingent on clearance or approval under the Hart-Scott-Rodino Act, and other customary closing and regulatory conditions. Based on the recorded balances at December 31, 2020, Dominion Energy expects to recognize a pre-tax gain of approximately $450 million ($320 million after tax) upon closing, including the write-off of $191 million of goodwill, but excluding the effects of any closing adjustments.
The operations included in both the GT&S Transaction and the Q-Pipe TransactionGroup 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 furtheradditional information regarding Dominion Energy’s equity method investment in Cove Point.
The following table represents selected information regarding the results of operations, which arewere reported within discontinued operations in Dominion Energy’s Consolidated Statements of Income:
|
| Year Ended |
|
| Year Ended |
| ||||||
|
| Q-Pipe Group(1) |
|
| GT&S Transaction(1) |
|
| Q-Pipe Group |
| |||
(millions) |
|
|
|
|
|
|
|
|
| |||
Operating revenue |
| $ | 254 |
|
| $ | 1,710 |
|
| $ | 246 |
|
Operating expense(2) |
|
| 76 |
|
|
| 1,289 |
|
|
| 96 |
|
Other income(3) |
|
| 28 |
|
|
| 88 |
|
|
| 1 |
|
Interest and related charges(4) |
|
| 25 |
|
|
| 372 |
|
|
| 20 |
|
Income before income taxes |
|
| 181 |
|
|
| 137 |
|
|
| 131 |
|
Income tax expense (benefit)(5) |
|
| 36 |
|
|
| 334 |
|
|
| (9 | ) |
Net income (loss) including noncontrolling interests |
|
| 145 |
|
|
| (197 | ) |
|
| 140 |
|
Noncontrolling interests |
|
| — |
|
|
| 106 |
|
|
| — |
|
Net income (loss) attributable to Dominion Energy |
| $ | 145 |
|
| $ | (303 | ) |
| $ | 140 |
|
|
| Year Ended December 31, 2020 |
|
| Year Ended December 31, 2019 |
|
| Year Ended December 31, 2018 |
| |||||||||||||||
|
| GT&S Transaction(1) |
|
| Q-Pipe Transaction |
|
| GT&S Transaction |
|
| Q-Pipe Transaction |
|
| GT&S Transaction |
|
| Q-Pipe Transaction |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 1,710 |
|
| $ | 246 |
|
| $ | 2,213 |
|
| $ | 251 |
|
| $ | 2,134 |
|
| $ | 247 |
|
Operating Expense(2)(3) |
|
| 1,289 |
|
|
| 96 |
|
|
| 1,367 |
|
|
| 131 |
|
|
| 1,663 |
|
|
| 135 |
|
Other income (loss) |
|
| 88 |
|
|
| 1 |
|
|
| 58 |
|
|
| 4 |
|
|
| 68 |
|
|
| 5 |
|
Interest and related charges(4) |
|
| 372 |
|
|
| 20 |
|
|
| 267 |
|
|
| 20 |
|
|
| 183 |
|
|
| 20 |
|
Income (loss) before income taxes |
|
| 137 |
|
|
| 131 |
|
|
| 637 |
|
|
| 104 |
|
|
| 356 |
|
|
| 97 |
|
Income tax expense (benefit) |
|
| 334 |
|
|
| (9 | ) |
|
| 120 |
|
|
| 23 |
|
|
| 40 |
|
|
| 18 |
|
Net income (loss) including noncontrolling interests |
|
| (197 | ) |
|
| 140 |
|
|
| 517 |
|
|
| 81 |
|
|
| 316 |
|
|
| 79 |
|
Noncontrolling interests |
|
| 106 |
|
|
| — |
|
|
| 11 |
|
|
| — |
|
|
| 92 |
|
|
| — |
|
Net income (loss) attributable to Dominion Energy |
| $ | (303 | ) |
| $ | 140 |
|
| $ | 506 |
|
| $ | 81 |
|
| $ | 224 |
|
| $ | 79 |
|
|
|
|
|
|
|
|
|
The carrying amounts of major classes of assets and liabilities relating to the disposal groups, which are reported as held for sale in Dominion Energy’s Consolidated Balance Sheets, were as follows:
|
| At December 31, 2020(1) |
|
| At December 31, 2019 |
| ||||||
|
| Q-Pipe Transaction |
|
| GT&S Transaction |
|
| Q-Pipe Transaction |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Current assets(2) |
| $ | 47 |
|
| $ | 445 |
|
| $ | 49 |
|
Equity method investments(3) |
|
| 35 |
|
|
| 276 |
|
|
| 36 |
|
Property, plant and equipment, net |
|
| 1,113 |
|
|
| 10,764 |
|
|
| 1,103 |
|
Other deferred charges and other assets, including goodwill(4) and intangible assets |
|
| 224 |
|
|
| 1,553 |
|
|
| 225 |
|
Current liabilities(5) |
|
| 30 |
|
|
| 1,002 |
|
|
| 37 |
|
Long-term debt |
|
| 426 |
|
|
| 4,401 |
|
|
| 425 |
|
Other deferred credits and liabilities |
|
| 154 |
|
|
| 773 |
|
|
| 155 |
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures and significant noncash items relating to the disposal groups included the following:
|
| Year Ended |
|
| Year Ended |
| ||||||
|
| Q-Pipe Group(1) |
|
| GT&S Transaction(1) |
|
| Q-Pipe Group |
| |||
(millions) |
|
|
|
|
|
|
|
|
| |||
Capital expenditures |
| $ | 34 |
|
| $ | 292 |
|
| $ | 38 |
|
Significant noncash items |
|
|
|
|
|
|
|
|
| |||
Impairment of assets and other charges |
|
| — |
|
|
| 469 |
|
|
| — |
|
Depreciation, depletion and amortization |
|
| — |
|
|
| 177 |
|
|
| 27 |
|
Accrued capital expenditures |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| Year Ended December 31, 2020 |
|
| Year Ended December 31, 2019 |
|
| Year Ended December 31, 2018 |
| |||||||||||||||
|
| GT&S Transaction(1) |
|
| Q-Pipe Transaction |
|
| GT&S Transaction |
|
| Q-Pipe Transaction |
|
| GT&S Transaction |
|
| Q-Pipe Transaction |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
| $ | 292 |
|
| $ | 38 |
|
| $ | 386 |
|
| $ | 42 |
|
| $ | 728 |
|
| $ | 34 |
|
Significant noncash items |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of assets and other charges |
|
| 469 |
|
|
| 0 |
|
|
| 13 |
|
|
| 1 |
|
|
| 391 |
|
|
| 0 |
|
Charge related to a voluntary retirement program |
|
| 0 |
|
|
| 0 |
|
|
| 19 |
|
|
| 3 |
|
|
| 0 |
|
|
| 0 |
|
Depreciation, depletion and amortization |
|
| 177 |
|
|
| 27 |
|
|
| 322 |
|
|
| 51 |
|
|
| 283 |
|
|
| 57 |
|
Accrued capital expenditures |
|
| 0 |
|
|
| 1 |
|
|
| 25 |
|
|
| 2 |
|
|
| 56 |
|
|
| 2 |
|
|
|
In October 2020, Dominion Energy settled various derivatives related to, but not included in, the GT&S Transaction for a payment of $165$165 million.
Acquisition
117
Sale of SCANAHope
In January 2019,February 2022, Dominion Energy issued 95.6entered into an agreement to sell 100% of the equity interests in Hope to Ullico for $690 million shares of cash consideration, subject to customary closing adjustments, which closed in August 2022 after all customary closing and regulatory conditions were satisfied, including clearance under the Hart-Scott-Rodino Act and approval from the West Virginia Commission. The sale was treated as a stock sale for tax purposes.
In connection with closing, Dominion Energy common stock, valued at $6.8 billion, representing 0.6690recognized a pre-tax gain of a share$14 million, inclusive of Dominion Energy common stockcustomary closing adjustments, (net of $110 million write-off of goodwill which was not deductible for each sharetax purposes) in losses (gains) on sales of SCANA common stock,assets in connection withits Consolidated Statements of Income. The transaction resulted in an after-tax loss of $84 million. Upon meeting 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 operatesclassification 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 responsibleheld 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,sale in the first quarter of 2019, DESC2022 and through the second quarter of 2022, Dominion Energy had recorded a reductioncharges of $90 million 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’sdeferred income tax expense in its Consolidated Statements of Income to reflect the recognition of deferred taxes on the outside basis of Hope’s stock. This deferred income tax expense reversed upon closing of the sale and became a component of current income tax expense on the sale disclosed above. See Note 5 for the year ended December 31, 2019 includesadditional information. In addition, a $756 million after-tax charge whichcurtailment was recorded related to other postretirement benefit plans as discussed in Note 22.
All activity related to Hope prior, or not related, to closing is included in Gas Distribution, with remaining activity reflected in the Corporate and Other segment.
NND ProjectSale of Kewaunee
AsIn 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 sale closed in June 2022 following approval from the Wisconsin Commission in May 2022 and NRC approval of a conditionrequested license transfer in March 2022. The sale was treated as an asset sale for tax purposes and Dominion Energy retained the assets and obligations of the pension and other postretirement employee benefit plans. EnergySolutions is subject to the SCANA Merger Approval Order, DESC committedWisconsin regulatory conditions agreed to excluding from rate recovery $2.4 billionby Dominion Energy upon its acquisition of costsKewaunee, including the return of any excess decommissioning funds to WPSC and WP&L customers following completion of all decommissioning activities.
In the second quarter of 2022, Dominion Energy recorded a loss of $649 million ($513 million after-tax), recorded in losses (gains) on sales of assets in its Consolidated Statements of Income, primarily related to the NND Projectdifference between the nuclear decommissioning trust and $180AROs. Prior to its receipt, there had been uncertainty as to the timing of or ability to obtain approval from the Wisconsin Commission. Prior to closing, Dominion Energy withdrew $80 million from the nuclear decommissioning trust to recover certain spent nuclear fuel and other permitted costs.
All activity related to Kewaunee prior to closing is included in Contracted Assets, with remaining activity reflected in the Corporate and Other segment.
Acquisition of costs associated with the purchaseBirdseye
In May 2021, Dominion Energy acquired 100% of the Columbia Energy Center power station. Regulatory assets includedownership interest in SCANA’s historical balance sheet at December 31, 2018 reflected these disallowances.
The remaining regulatory asset associated with the NND ProjectBirdseye from BRE Holdings, LLC for total consideration of $2.8 billion,$46 million, consisting of which $138$28 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 Termscash and Conditions
$18 |
|
|
|
|
|
|
|
|
|
Purchase Price Allocation
SCANA’s assets acquired and liabilities assumed have been measured at estimated fair value at closing, of consideration contingent on the achievement of certain revenue targets and are includedfuture development project sales. Birdseye is primarily engaged in the Dominion Energy South Carolina and Gas Distribution operating segments.development of solar energy projects in southeastern states in the U.S. with 2.5 GW of solar generation projects under development at acquisition. The majorityallocation of the operations acquired are subject topurchase 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 rate setting authorityvalue associated with enhancing Dominion Energy's development of FERCregulated and the Northlong-term contracted solar generating 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.
electric storage projects. The fair value measurements, including of SCANA’sthe 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 inherentflows. Birdseye is included in the future market prices.Contracted Assets.
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was reflected as goodwill. The goodwill reflects the value associated with enhancing Dominion Energy’s portfolio of regulated operations in the growing southeast region of the U.S. The goodwill recognized is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to goodwill.
The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at closing, which reflects certain adjustments related to income taxes, as discussed in Note 5, from the preliminary valuation recognized during the measurement period.
118
| 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations and Unaudited Pro Forma Information
The impact of the SCANA Combination on Dominion Energy’s operating revenue was an increase of $3.3 billion and $3.1 billion for the years ended December 31, 2020 and 2019, respectively, in the Consolidated Statements of Income. The impact of the SCANA Combination on Dominion Energy’s net income attributable to Dominion Energy was an increase of $277 million and a decrease of $1.1 billion for the years ended December 31, 2020 and 2019, respectively, in the Consolidated Statements of Income.
Dominion Energy incurred merger and integration-related costs of $97 million for the year ended December 31, 2020, all of which is recorded in other operations and maintenance expense in the Consolidated Statements of Income. Dominion Energy incurred merger and integration-related costs of $646 million for the year ended December 31, 2019. The amount for the year ended December 31, 2019 includes $427 million for a charge related to a voluntary retirement program. See Note 22 for additional information. Of the remaining merger and integration-related costs, $210 million is recorded in other operations and maintenance expense and $9 million was recorded in interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2019. During the year ended December 31, 2018, Dominion Energy incurred merger and integration-related costs of $27 million, recorded primarily in other operations and maintenance expense in the Consolidated Statements of Income. These costs consist of professional fees, the charitable contribution commitment described above, employee-related expenses, certain financing costs and other miscellaneous costs.
The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion Energy assuming the SCANA Combination had taken place on January 1, 2018. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.
|
| Twelve Months Ended December 31, |
| |||||
|
| 2019(1) |
|
| 2018(1) |
| ||
(millions, except EPS) |
|
|
|
|
|
|
|
|
Operating Revenue |
| $ | 15,408 |
|
| $ | 15,344 |
|
Net income attributable to Dominion Energy |
|
| 3,266 |
|
|
| 2,081 |
|
Earnings Per Common Share – Basic |
| $ | 4.04 |
|
| $ | 2.78 |
|
Earnings Per Common Share – Diluted |
| $ | 4.00 |
|
| $ | 2.77 |
|
|
|
Sale of Interest in Cove Point
In October 2019, Dominion Energy signed an agreement to sell its 25% noncontrolling limited partnership interests in Cove Point to Brookfield. In December 2019, the sale was completed and Dominion Energy received cash consideration of $2.1 billion, subject to working capital adjustments. The sale was accounted for by Dominion Energy following the guidance for a change in a parent company’s ownership interest in a consolidated subsidiary. Because Dominion Energy controlled Cove Point both before and after the sale of the noncontrolling interest, the changes in Dominion Energy’s ownership interest in Cove Point was accounted for as an equity transaction and no gain or loss was recognized.
NOTE 4. OPERATING REVENUE
The Companies’ operating revenue consists of the following:
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||||||||||
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Regulated electric sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Residential |
| $ | 5,261 |
|
| $ | 4,509 |
|
| $ | 4,833 |
|
| $ | 4,039 |
|
| $ | 3,366 |
|
| $ | 3,677 |
|
Commercial |
|
| 4,480 |
|
|
| 3,194 |
|
|
| 3,102 |
|
|
| 3,647 |
|
|
| 2,417 |
|
|
| 2,342 |
|
Industrial |
|
| 901 |
|
|
| 748 |
|
|
| 730 |
|
|
| 472 |
|
|
| 367 |
|
|
| 380 |
|
Government and other retail |
|
| 1,235 |
|
|
| 921 |
|
|
| 868 |
|
|
| 1,172 |
|
|
| 862 |
|
|
| 804 |
|
Wholesale |
|
| 234 |
|
|
| 175 |
|
|
| 128 |
|
|
| 132 |
|
|
| 107 |
|
|
| 90 |
|
Nonregulated electric sales |
|
| 1,249 |
|
|
| 1,005 |
|
|
| 823 |
|
|
| 68 |
|
|
| 44 |
|
|
| 19 |
|
Regulated gas sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Residential |
|
| 1,816 |
|
|
| 1,455 |
|
|
| 1,283 |
|
|
|
|
|
|
|
|
|
| |||
Commercial |
|
| 714 |
|
|
| 527 |
|
|
| 457 |
|
|
|
|
|
|
|
|
|
| |||
Other |
|
| 208 |
|
|
| 135 |
|
|
| 88 |
|
|
|
|
|
|
|
|
|
| |||
Nonregulated gas sales |
|
| 25 |
|
|
| 96 |
|
|
| 174 |
|
|
|
|
|
|
|
|
|
| |||
Regulated gas transportation and storage |
|
| 1,047 |
|
|
| 945 |
|
|
| 801 |
|
|
|
|
|
|
|
|
|
| |||
Other regulated revenues |
|
| 313 |
|
|
| 265 |
|
|
| 327 |
|
|
| 277 |
|
|
| 234 |
|
|
| 299 |
|
Other nonregulated revenues(1)(2) |
|
| 242 |
|
|
| 195 |
|
|
| 138 |
|
|
| 61 |
|
|
| 73 |
|
|
| 50 |
|
Total operating revenue from |
|
| 17,725 |
|
|
| 14,170 |
|
|
| 13,752 |
|
|
| 9,868 |
|
|
| 7,470 |
|
|
| 7,661 |
|
Other revenues(1)(3)(4) |
|
| (551 | ) |
|
| (206 | ) |
|
| 420 |
|
|
| (214 | ) |
|
| — |
|
|
| 102 |
|
Total operating revenue |
| $ | 17,174 |
|
| $ | 13,964 |
|
| $ | 14,172 |
|
| $ | 9,654 |
|
| $ | 7,470 |
|
| $ | 7,763 |
|
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated electric sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
| $ | 4,833 |
|
| $ | 4,325 |
|
| $ | 3,413 |
|
Commercial |
|
| 3,102 |
|
|
| 3,219 |
|
|
| 2,503 |
|
Industrial |
|
| 730 |
|
|
| 683 |
|
|
| 490 |
|
Government and other retail |
|
| 868 |
|
|
| 873 |
|
|
| 854 |
|
Wholesale |
|
| 128 |
|
|
| 176 |
|
|
| 137 |
|
Nonregulated electric sales |
|
| 803 |
|
|
| 926 |
|
|
| 1,294 |
|
Regulated gas sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
| 1,283 |
|
|
| 1,343 |
|
|
| 818 |
|
Commercial |
|
| 457 |
|
|
| 457 |
|
|
| 221 |
|
Other |
|
| 88 |
|
|
| 109 |
|
|
| 11 |
|
Nonregulated gas sales |
|
| 174 |
|
|
| 495 |
|
|
| 210 |
|
Regulated gas transportation and storage |
|
| 801 |
|
|
| 742 |
|
|
| 640 |
|
Other regulated revenues |
|
| 327 |
|
|
| 252 |
|
|
| 178 |
|
Other nonregulated revenues(1)(2) |
|
| 158 |
|
|
| 145 |
|
|
| 122 |
|
Total operating revenue from contracts with customers |
|
| 13,752 |
|
|
| 13,745 |
|
|
| 10,891 |
|
Other revenues(3)(4) |
|
| 420 |
|
|
| 656 |
|
|
| 308 |
|
Total operating revenue |
| $ | 14,172 |
|
| $ | 14,401 |
|
| $ | 11,199 |
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated electric sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
| $ | 3,677 |
|
| $ | 3,657 |
|
| $ | 3,413 |
|
Commercial |
|
| 2,342 |
|
|
| 2,712 |
|
|
| 2,503 |
|
Industrial |
|
| 380 |
|
|
| 455 |
|
|
| 490 |
|
Government and other retail |
|
| 804 |
|
|
| 823 |
|
|
| 854 |
|
Wholesale |
|
| 90 |
|
|
| 128 |
|
|
| 137 |
|
Other regulated revenues |
|
| 299 |
|
|
| 190 |
|
|
| 132 |
|
Other nonregulated revenues(1)(2) |
|
| 69 |
|
|
| 71 |
|
|
| 55 |
|
Total operating revenue from contracts with customers |
|
| 7,661 |
|
|
| 8,036 |
|
|
| 7,584 |
|
Other revenues(1)(3) |
|
| 102 |
|
|
| 72 |
|
|
| 35 |
|
Total operating revenue |
| $ | 7,763 |
|
| $ | 8,108 |
|
| $ | 7,619 |
|
(2) Includes sales which are considered to be goods transferred at a point in time of $45 million, $34 million and $22 million for the years ended December 31, 2022, 2021 and 2020, 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 $42 million, $33 million and $20 million for the years ended December 31, 2022, 2021 and 2020, respectively, at Dominion Energy and $18 million, $21 million and $11 million for the years ended December 31, 2022, 2021 and 2020, respectively, at Virginia Power. (3) Includes alternative revenue of $95 million, $56 million and $119 million at Dominion Energy and $72 million, $44 million and $82 million at Virginia Power for years ended December 31, 2022, 2021 and 2020, respectively. (4) Includes revenue associated with services provided to discontinued operations of $5 million and $4 million for the years ended December 31, 2021 and 2020, respectively, at Dominion Energy.
|
|
|
|
|
|
|
|
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 |
| 2023 |
|
| 2024 |
|
| 2025 |
|
| 2026 |
|
| 2027 |
|
| Thereafter |
|
| Total |
| |||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Dominion Energy(1) |
| $ | 68 |
|
| $ | 61 |
|
| $ | 54 |
|
| $ | 48 |
|
| $ | 46 |
|
| $ | 402 |
|
| $ | 679 |
|
Revenue expected to be recognized on multi-year contracts in place at December 31, 2020 |
| 2021 |
|
| 2022 |
|
| 2023 |
|
| 2024 |
|
| 2025 |
|
| Thereafter |
|
| Total |
| |||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy(1) |
| $ | 67 |
|
| $ | 66 |
|
| $ | 64 |
|
| $ | 57 |
|
| $ | 50 |
|
| $ | 466 |
|
| $ | 770 |
|
|
|
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, 20202022 and 2019,2021, Dominion Energy’s contract liability balances were $130$150 million and $102$124 million, respectively. At December 31, 20202022 and 2019,2021, Virginia Power’s contract liability balances were $36$39 million and $24$33 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’Companies recognize revenue as they fulfill their obligations to provide service to their customers. During the years ended December 31, 20202022 and 2019,2021, Dominion Energy recognized revenue of $97$118 million and $85$124 million from the beginning contract liability balance. During the years ended December 31, 20202022 and 2019,2021, Virginia Power recognized revenue of $24$33 million and $22$36 million, respectively, from the beginning contract liability balance.
119
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.
In August 2022, the IRA was enacted which, among other things, extends the investment and production tax credits for clean energy technologies until at least 2032 and imposes a 15% alternative minimum tax on GAAP net income, as adjusted for certain items, of corporations greater than $1 billion for tax years beginning after December 31, 2022. The IRA did not impact the measurement of the Companies’ deferred income taxes or change the assessment of the realizability of deferred tax assets. The Companies have accounted forcontinue to monitor and evaluate the effectsimpacts of the 2017 Tax Reform Act, although additionalIRA, including changes could occurin interpretations, if any, as guidance is issued and finalized as described below.finalized.
In March 2020, the CARES Act was enacted which includes several significant business tax provisions that modify or temporarily suspend certain provisions of the 2017 Tax Reform Act. The CARES Act provisions are intended to improve cash flow and liquidity by, among other things, providing a temporary five-year carryback for certain net operating losses, accelerating the refund of previously generated corporate alternative minimum tax credits and temporarily increased the business interest limitation to 50% of adjusted taxable income for certain businesses. Dominion Energy utilized the income tax provisions of the CARES Act to accelerate the recognition of certain tax attributes, but they did not provide a material benefit.
In July 2020, the U.S. Department of Treasury issued final regulations providing guidance about the limitation on the deduction for business interest expenses under the 2017 Tax Reform Act. Under the 2017 Tax Reform Act, as modified bydeductions for net interest expense are limited to 30% of adjusted taxable income, which prior to 2022, was defined similarly to EBITDA (earnings before interest, taxes, depreciation and amortization). For tax years beginning after December 31, 2021, the CARES Act.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.
Continuing Operations
Details of income tax expense for continuing operations including noncontrolling interests were as follows:
|
| Dominion Energy |
|
| Virginia Power |
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||||||||||||||||||||||||||||
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
|
| 2020 |
|
| 2019 |
|
| 2018 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Federal |
| $ | (314 | ) |
| $ | (94 | ) |
| $ | 294 |
|
| $ | 364 |
|
| $ | 286 |
|
| $ | 36 |
|
| $ | 7 |
|
| $ | (162 | ) |
| $ | (314 | ) |
| $ | 17 |
|
| $ | 67 |
|
| $ | 364 |
|
State |
|
| (81 | ) |
|
| 58 |
|
|
| 82 |
|
|
| 71 |
|
|
| 58 |
|
|
| 40 |
|
|
| 46 |
|
|
| 45 |
|
|
| (81 | ) |
|
| (17 | ) |
|
| (13 | ) |
|
| 71 |
|
Total current expense (benefit) |
|
| (395 | ) |
|
| (36 | ) |
|
| 376 |
|
|
| 435 |
|
|
| 344 |
|
|
| 76 |
|
|
| 53 |
|
|
| (117 | ) |
|
| (395 | ) |
|
| — |
|
|
| 54 |
|
|
| 435 |
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Federal |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Taxes before operating loss carryforwards, investment tax credits and tax reform |
|
| 12 |
|
|
| 168 |
|
|
| 30 |
|
|
| (226 | ) |
|
| (128 | ) |
|
| 199 |
| ||||||||||||||||||||||||
2017 Tax Reform Act |
|
| 0 |
|
|
| 0 |
|
|
| 46 |
|
|
| 0 |
|
|
| 0 |
|
|
| 21 |
| ||||||||||||||||||||||||
Taxes before operating loss |
|
| 62 |
|
|
| 151 |
|
|
| 12 |
|
|
| 212 |
|
|
| 145 |
|
|
| (226 | ) | ||||||||||||||||||||||||
Tax utilization expense of operating loss carryforwards |
|
| 44 |
|
|
| 119 |
|
|
| 92 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 36 |
|
|
| 43 |
|
|
| 44 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Investment tax credits |
|
| 311 |
|
|
| (51 | ) |
|
| (56 | ) |
|
| (27 | ) |
|
| (34 | ) |
|
| (51 | ) |
|
| (129 | ) |
|
| 250 |
|
|
| 311 |
|
|
| (148 | ) |
|
| (39 | ) |
|
| (27 | ) |
State |
|
| 72 |
|
|
| (50 | ) |
|
| 34 |
|
|
| 7 |
|
|
| 22 |
|
|
| 55 |
|
|
| 32 |
|
|
| (19 | ) |
|
| 72 |
|
|
| 112 |
|
|
| 118 |
|
|
| 7 |
|
Total deferred expense (benefit) |
|
| 439 |
|
|
| 186 |
|
|
| 146 |
|
|
| (246 | ) |
|
| (140 | ) |
|
| 224 |
|
|
| 1 |
|
|
| 425 |
|
|
| 439 |
|
|
| 176 |
|
|
| 224 |
|
|
| (246 | ) |
Investment tax credit-gross deferral |
|
| 42 |
|
|
| 62 |
|
|
| 2 |
|
|
| 42 |
|
|
| 62 |
|
|
| 2 |
|
|
| 18 |
|
|
| 121 |
|
|
| 42 |
|
|
| 18 |
|
|
| 121 |
|
|
| 42 |
|
Investment tax credit-amortization |
|
| (3 | ) |
|
| (3 | ) |
|
| (2 | ) |
|
| (2 | ) |
|
| (2 | ) |
|
| (2 | ) |
|
| (4 | ) |
|
| (4 | ) |
|
| (3 | ) |
|
| (3 | ) |
|
| (2 | ) |
|
| (2 | ) |
Total income tax expense |
| $ | 83 |
|
| $ | 209 |
|
| $ | 522 |
|
| $ | 229 |
|
| $ | 264 |
|
| $ | 300 |
|
| $ | 68 |
|
| $ | 425 |
|
| $ | 83 |
|
| $ | 191 |
|
| $ | 397 |
|
| $ | 229 |
|
In 2021, Dominion Energy’s current income taxes reflect a benefit from continuing operations as the income tax expense associated with the Q-Pipe 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 current income tax expense associated with gas transmission and storage operations, including taxes on the gain, is reflected in discontinued operations. Dominion Energy’s income tax expense reflects the utilization of investment tax credit carryforwards to offset a portion of the federal tax gain on the sale. In addition, an $18$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.
120
Discontinued Operations
Income tax expense (benefit) reflected in discontinued operations is $(204)$8 million, $142$188 million, and $58$(204) million for the years ended December 31, 2022, 2021 and 2020, 2019respectively. 2021 income taxes include a $14 million benefit related to finalizing income tax returns on the GT&S Transaction and 2018, respectively.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$81 million for the write-off of tax-related regulatory assets associated with the Atlantic Coast Pipeline Project and the absence of a $236$236 million benefit on non-deductible goodwill written off in connection with the GT&S Transaction.
Continuing Operations
For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to the Companies’ effective income tax rate as follows:
|
| Dominion Energy |
|
| Virginia Power | ||||||||||||||||||||
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
|
| 2020 |
|
| 2019 |
|
| 2018 |
|
| ||||||
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 |
|
| 2.0 |
|
|
| 1.5 |
|
|
| 4.3 |
|
|
| 4.8 |
|
|
| 4.5 |
|
|
| 4.7 |
|
|
Investment tax credits |
|
| (9.6 | ) |
|
| (11.4 | ) |
|
| (2.3 | ) |
|
| (4.5 | ) |
|
| (2.9 | ) |
|
| (3.5 | ) |
|
Production tax credits |
|
| (0.7 | ) |
|
| (2.1 | ) |
|
| (0.8 | ) |
|
| (0.7 | ) |
|
| (0.7 | ) |
|
| (0.7 | ) |
|
Valuation allowances |
|
| 0.9 |
|
|
| 0.5 |
|
|
| 0.4 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
Reversal of excess deferred income taxes |
|
| (5.4 | ) |
|
| (3.2 | ) |
|
| (2.3 | ) |
|
| (2.2 | ) |
|
| (3.1 | ) |
|
| (3.2 | ) |
|
Federal legislative change |
|
| 0 |
|
|
| 0 |
|
|
| 1.8 |
|
|
| 0 |
|
|
| 0 |
|
|
| 1.3 |
|
|
State legislative change |
|
| 0 |
|
|
| 0 |
|
|
| (0.8 | ) |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
Write-off of regulatory assets |
|
| 0 |
|
|
| 21.7 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
Change in tax status |
|
| (1.7 | ) |
|
| (5.5 | ) |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
AFUDC—equity |
|
| (0.2 | ) |
|
| (0.2 | ) |
|
| (0.3 | ) |
|
| 0 |
|
|
| 0 |
|
|
| (0.5 | ) |
|
Changes in state deferred taxes associated with assets held for sale |
|
| (3.2 | ) |
|
| 0 |
|
|
| 0 |
|
|
|
|
|
|
| 0 |
|
|
| 0 |
|
|
Absence of tax on noncontrolling interest |
|
| 3.8 |
|
|
| (0.2 | ) |
|
| (0.1 | ) |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
Employee stock ownership plan deduction |
|
| (0.9 | ) |
|
| (1.4 | ) |
|
| (0.5 | ) |
|
| 0 |
|
|
| 0 |
|
|
| — |
|
|
Nondeductible goodwill |
|
| 0 |
|
|
| 1.8 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
Other, net |
|
| (0.1 | ) |
|
| 1.5 |
|
|
| (0.4 | ) |
|
| (0.1 | ) |
|
| (0.2 | ) |
|
| (0.1 | ) |
|
Effective tax rate |
|
| 5.9 |
| % |
| 24.0 |
| % |
| 20.0 |
| % |
| 18.3 |
| % |
| 18.6 |
| % |
| 19.0 |
| % |
|
| Dominion Energy |
|
| Virginia Power | ||||||||||||||||||||
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
|
| ||||||
U.S. statutory rate |
|
| 21.0 |
| % |
| 21.0 |
| % |
| 21.0 |
| % |
| 21.0 |
| % |
| 21.0 |
| % |
| 21.0 |
| % |
Increases (reductions) resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Recognition of taxes - sale of |
|
| 8.7 |
|
|
| — |
|
|
| — |
|
|
|
|
|
|
|
|
|
|
| |||
Recognition of taxes - privatization |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2.4 |
|
|
| — |
|
|
| — |
|
|
State taxes, net of federal benefit |
|
| 3.9 |
|
|
| 2.6 |
|
|
| 2.0 |
|
|
| 4.6 |
|
|
| 4.6 |
|
|
| 4.8 |
|
|
Investment tax credits |
|
| (12.7 | ) |
|
| (3.2 | ) |
|
| (9.6 | ) |
|
| (9.1 | ) |
|
| (3.0 | ) |
|
| (4.5 | ) |
|
Production tax credits |
|
| (1.4 | ) |
|
| (0.4 | ) |
|
| (0.7 | ) |
|
| (1.0 | ) |
|
| (0.6 | ) |
|
| (0.7 | ) |
|
Valuation allowances |
|
| — |
|
|
| 0.1 |
|
|
| 0.9 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
Reversal of excess deferred income |
|
| (11.5 | ) |
|
| (3.2 | ) |
|
| (5.4 | ) |
|
| (3.8 | ) |
|
| (2.1 | ) |
|
| (2.2 | ) |
|
State legislative change |
|
| (0.2 | ) |
|
| (0.7 | ) |
|
| — |
|
|
| — |
|
|
| (0.7 | ) |
|
| — |
|
|
Change in tax status |
|
| — |
|
|
| — |
|
|
| (1.7 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
AFUDC—equity |
|
| (0.7 | ) |
|
| (0.4 | ) |
|
| (0.2 | ) |
|
| (0.4 | ) |
|
| (0.5 | ) |
|
| — |
|
|
Changes in state deferred taxes |
|
| 0.5 |
|
|
| (0.3 | ) |
|
| (3.2 | ) |
|
|
|
|
|
|
|
|
|
| |||
Absence of tax on noncontrolling |
|
| — |
|
|
| (0.1 | ) |
|
| 3.8 |
|
|
|
|
|
|
|
|
|
|
| |||
Settlements of uncertain tax positions |
|
| — |
|
|
| (1.2 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
Employee stock ownership plan |
|
| (0.8 | ) |
|
| (0.3 | ) |
|
| (0.9 | ) |
|
|
|
|
|
|
|
|
|
| |||
Other, net |
|
| (0.3 | ) |
|
| (0.2 | ) |
|
| (0.1 | ) |
|
| (0.1 | ) |
|
| 0.1 |
|
|
| (0.1 | ) |
|
Effective tax rate |
|
| 6.5 |
| % |
| 13.7 |
| % |
| 5.9 |
| % |
| 13.6 |
| % |
| 18.8 |
| % |
| 18.3 |
| % |
ForAs described in Note 3, Dominion Energy sold 100% of the Companies’ rate-regulated entities, deferred taxes will reverse at the weighted average rate used to originate the deferred tax liability, whichequity interests in some cases will be 35%. The Companies have recorded an estimate of excess deferredHope in a stock sale for income tax amortization in 2020, and changes in estimates of amounts probable of collection from or return to customers. The reversal of these excess deferred income taxes will impact thepurposes. Dominion Energy’s 2022 effective tax rate reflects the current income tax expense on the sale of Hope’s stock. As described in Note 9, Virginia Power transferred its existing privatization operations in Virginia to Dominion Energy, and Dominion Energy contributed these assets to Dominion Privatization. As the original owner of these privatization assets, Virginia Power is required to recognize the income tax expense on Dominion Energy’s transaction with Dominion Privatization. As such, Virginia Power’s effective tax rate reflects an income tax expense of $34 million on this transaction.
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 charged to customers. See Note 13reflect the benefit of a state legislative change enacted in April 2021 for current year developments.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$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$55 million attributable to the noncontrolling interest primarily associated with the impairment of non-wholly-owned nonregulated solar facilities held in partnerships discussed in Note 10.
In connection with the SCANA Combination, Dominion Energy committed to forgo, or limit, the recovery of certain income tax-related regulatory assets associated with the NND Project. Dominion Energy’s effective tax rate reflects deferred income tax expense of $194 million in satisfaction of this commitment. Dominion Energy’s effective tax rate also reflects the changes in consolidated state income taxes resulting from the SCANA Combination.
In 2018, the Companies applied the provisions of proposed regulations addressing the availability of federal bonus depreciation for the period beginning after September 27, 2017 through December 31, 2017. The application of these changes increased Dominion Energy’s 2017 net operating loss carryforward, the benefit of which will be recognized at the 21% rate. As a result, Dominion Energy’s effective tax rate reflects a $23 million increase to deferred income tax expense associated with the remeasurement of this deferred tax asset. The effects of these changes at Virginia Power were immaterial. These amounts and adjustments represent the Companies’ best estimate based on available information, and could be subject to change based on additional guidance in yet to be finalized regulations. In addition, changes in estimates of amounts probable of return to or collection from customers increased deferred income tax expense at Virginia Power by $23 million and increased regulatory liabilities by $31 million. At Dominion Energy, similar changes in estimates decreased income tax expense by $5 million, which is reflected in income tax expense from continuing operations in the Consolidated Statements of Income, and regulatory liabilities by $8 million, which are reflected in noncurrent liabilities of discontinued operations on the 2019 Consolidated Balance Sheets. In addition, Dominion Energy effective tax rates reflects the impacts of a state legislative change enacted in the second quarter of 2018 that was retroactive to January 1, 2018 associated with discontinued operations.121
The Companies’ deferred income taxes consist of the following:
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||
At December 31, |
| 2022 |
|
| 2021 |
|
| 2022 |
|
| 2021 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Deferred income taxes: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Total deferred income tax assets |
| $ | 2,869 |
|
| $ | 3,025 |
|
| $ | 1,535 |
|
| $ | 1,373 |
|
Total deferred income tax liabilities |
|
| 9,267 |
|
|
| 9,397 |
|
|
| 4,701 |
|
|
| 4,286 |
|
Total net deferred income tax liabilities |
| $ | 6,398 |
|
| $ | 6,372 |
|
| $ | 3,166 |
|
| $ | 2,913 |
|
Total deferred income taxes: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Plant and equipment, primarily depreciation method and basis differences |
| $ | 5,545 |
|
| $ | 6,017 |
|
| $ | 3,355 |
|
| $ | 3,327 |
|
Excess deferred income taxes |
|
| (1,060 | ) |
|
| (1,107 | ) |
|
| (616 | ) |
|
| (629 | ) |
Unrecovered NND Project costs |
|
| 479 |
|
|
| 508 |
|
|
|
|
|
|
| ||
DESC rate refund |
|
| (89 | ) |
|
| (113 | ) |
|
|
|
|
|
| ||
Toshiba Settlement |
|
| (162 | ) |
|
| (189 | ) |
|
|
|
|
|
| ||
Nuclear decommissioning |
|
| 1,001 |
|
|
| 1,114 |
|
|
| 311 |
|
|
| 324 |
|
Deferred state income taxes |
|
| 892 |
|
|
| 857 |
|
|
| 566 |
|
|
| 420 |
|
Federal benefit of deferred state income taxes |
|
| (199 | ) |
|
| (179 | ) |
|
| (119 | ) |
|
| (88 | ) |
Deferred fuel, purchased energy and gas costs |
|
| 579 |
|
|
| 189 |
|
|
| 403 |
|
|
| 126 |
|
Pension benefits |
|
| 414 |
|
|
| 362 |
|
|
| (105 | ) |
|
| (119 | ) |
Other postretirement benefits |
|
| 73 |
|
|
| 73 |
|
|
| 111 |
|
|
| 93 |
|
Loss and credit carryforwards |
|
| (1,790 | ) |
|
| (1,571 | ) |
|
| (751 | ) |
|
| (537 | ) |
Valuation allowances |
|
| 138 |
|
|
| 140 |
|
|
| 7 |
|
|
| 6 |
|
Partnership basis differences |
|
| 470 |
|
|
| 398 |
|
|
|
|
|
|
| ||
Other |
|
| 107 |
|
|
| (127 | ) |
|
| 4 |
|
|
| (10 | ) |
Total net deferred income tax liabilities |
| $ | 6,398 |
|
| $ | 6,372 |
|
| $ | 3,166 |
|
| $ | 2,913 |
|
Deferred Investment Tax Credits – Regulated Operations |
|
| 300 |
|
|
| 286 |
|
|
| 286 |
|
|
| 270 |
|
Total Deferred Taxes and Deferred Investment Tax Credits |
| $ | 6,698 |
|
| $ | 6,658 |
|
| $ | 3,452 |
|
| $ | 3,183 |
|
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||
At December 31, |
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax assets |
| $ | 3,285 |
|
| $ | 3,736 |
|
| $ | 1,204 |
|
| $ | 1,207 |
|
Total deferred income tax liabilities |
|
| 9,069 |
|
|
| 9,883 |
|
|
| 3,832 |
|
|
| 4,058 |
|
Total net deferred income tax liabilities |
| $ | 5,784 |
|
| $ | 6,147 |
|
| $ | 2,628 |
|
| $ | 2,851 |
|
Total deferred income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant and equipment, primarily depreciation method and basis differences |
| $ | 5,824 |
|
| $ | 6,616 |
|
| $ | 3,227 |
|
| $ | 3,359 |
|
Excess deferred income taxes |
|
| (1,142 | ) |
|
| (1,306 | ) |
|
| (656 | ) |
|
| (672 | ) |
Unrecovered NND Project costs |
|
| 529 |
|
|
| 553 |
|
|
| 0 |
|
|
| 0 |
|
DESC rate refund |
|
| (140 | ) |
|
| (169 | ) |
|
| 0 |
|
|
| 0 |
|
Toshiba Settlement |
|
| (204 | ) |
|
| (219 | ) |
|
| 0 |
|
|
| 0 |
|
Nuclear decommissioning |
|
| 991 |
|
|
| 909 |
|
|
| 303 |
|
|
| 290 |
|
Deferred state income taxes |
|
| 702 |
|
|
| 863 |
|
|
| 305 |
|
|
| 302 |
|
Federal benefit of deferred state income taxes |
|
| (147 | ) |
|
| (184 | ) |
|
| (64 | ) |
|
| (63 | ) |
Deferred fuel, purchased energy and gas costs |
|
| (28 | ) |
|
| 30 |
|
|
| (34 | ) |
|
| 1 |
|
Pension benefits |
|
| 239 |
|
|
| 174 |
|
|
| (105 | ) |
|
| (153 | ) |
Other postretirement benefits |
|
| (14 | ) |
|
| (37 | ) |
|
| 76 |
|
|
| 62 |
|
Loss and credit carryforwards |
|
| (1,534 | ) |
|
| (1,832 | ) |
|
| (354 | ) |
|
| (280 | ) |
Valuation allowances |
|
| 155 |
|
|
| 161 |
|
|
| 6 |
|
|
| 5 |
|
Partnership basis differences |
|
| 593 |
|
|
| 823 |
|
|
| 0 |
|
|
| 0 |
|
Other |
|
| (40 | ) |
|
| (235 | ) |
|
| (76 | ) |
|
| 0 |
|
Total net deferred income tax liabilities |
| $ | 5,784 |
|
| $ | 6,147 |
|
| $ | 2,628 |
|
| $ | 2,851 |
|
Deferred Investment Tax Credits – Regulated Operations |
|
| 169 |
|
|
| 130 |
|
|
| 151 |
|
|
| 111 |
|
Total Deferred Taxes and Deferred Investment Tax Credits |
| $ | 5,953 |
|
| $ | 6,277 |
|
| $ | 2,779 |
|
| $ | 2,962 |
|
At December 31, 2020,2022, Dominion Energy had the following deductible loss and credit carryforwards:
|
| Deductible |
|
| Deferred |
|
| Valuation |
|
| Expiration |
| Deductible |
|
| Deferred |
| Valuation |
| Expiration | ||||||||
|
| Amount |
|
| Tax Asset |
|
| Allowance |
|
| Period |
| Amount |
|
| Tax Asset |
|
| Allowance |
|
| Period | ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Federal losses |
| $ | 1,169 |
|
| $ | 246 |
|
| $ | — |
|
| 2037 |
| $ | 794 |
|
| $ | 167 |
|
| $ | — |
|
| 2037 |
Federal investment credits |
| — |
|
|
| 736 |
|
| — |
|
| 2036-2040 |
| — |
|
|
| 874 |
|
| — |
|
| 2036-2042 | ||||
Federal production credits |
| — |
|
|
| 86 |
|
| — |
|
| 2036-2040 | ||||||||||||||||
Other federal credits |
| — |
|
|
| 14 |
|
| — |
|
| 2036-2039 | ||||||||||||||||
Federal production and other credits |
| — |
|
|
| 84 |
|
| — |
|
| 2036-2042 | ||||||||||||||||
State losses |
|
| 3,661 |
|
|
| 198 |
|
|
| (61 | ) |
| 2020-2040 |
|
| 5,711 |
|
|
| 306 |
|
|
| (51 | ) |
| 2023-2042 |
State minimum tax credits |
| — |
|
|
| 139 |
|
| — |
|
| No expiration |
| — |
|
|
| 271 |
|
| — |
|
| No expiration | ||||
State investment and other credits |
| — |
|
|
| 142 |
|
|
| (94 | ) |
| 2020-2031 |
| — |
|
|
| 128 |
|
|
| (87 | ) |
| 2023-2032 | ||
Total |
| $ | 4,830 |
|
| $ | 1,561 |
|
| $ | (155 | ) |
|
|
| $ | 6,505 |
|
| $ | 1,830 |
|
| $ | (138 | ) |
|
|
122
At December 31, 2020,2022, 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 |
| — |
|
|
| 631 |
|
| — |
|
| 2036-2042 | ||
Federal production and other credits |
| — |
|
|
| 80 |
|
| — |
|
| 2036-2042 | ||
State losses |
|
| 513 |
|
|
| 31 |
|
| — |
|
| 2042 | |
State investment and other credits |
| — |
|
|
| 9 |
|
|
| (7 | ) |
| 2024 | |
Total |
| $ | 513 |
|
| $ | 751 |
|
| $ | (7 | ) |
|
|
|
| Deductible |
|
| Deferred |
|
| Valuation |
|
| Expiration | |||
|
| Amount |
|
| Tax Asset |
|
| Allowance |
|
| Period | |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal losses |
| $ | — |
|
| $ | — |
|
| $ | — |
|
|
|
Federal investment credits |
| — |
|
|
| 294 |
|
| — |
|
| 2036-2040 | ||
Federal production and other credits |
| — |
|
|
| 51 |
|
| — |
|
| 2036-2040 | ||
State investment credits |
| — |
|
|
| 9 |
|
|
| (6 | ) |
| 2024 | |
Total |
| $ | — |
|
| $ | 354 |
|
| $ | (6 | ) |
|
|
A reconciliation of changes in the Companies’Dominion Energy’s unrecognized tax benefits follows:follows. Virginia Power does not have any unrecognized tax benefits in the periods presented:
|
| Dominion Energy |
|
| Virginia Power |
|
| Dominion Energy |
|
| |||||||||||||||||||||||||||||
|
| 2020 |
|
| 2019 |
|
|
| 2018 |
|
| 2020 |
|
| 2019 |
|
| 2018 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
|
| ||||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Balance at January 1 |
| $ | 175 |
|
| $ | 44 |
|
|
|
| $ | 38 |
|
| $ | 0 |
|
| $ | 2 |
|
| $ | 4 |
| |||||||||||||
Acquired unrecognized tax benefits |
|
| 0 |
|
|
| 129 |
|
| (1 | ) |
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
| |||||||||||||
Beginning balance |
| $ | 128 |
|
| $ | 167 |
|
| $ | 175 |
|
| ||||||||||||||||||||||||||
Increases-prior period positions |
|
| 18 |
|
|
| 0 |
|
|
|
|
| 10 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 8 |
|
|
| 48 |
|
|
| 18 |
|
|
Decreases-prior period positions |
|
| (19 | ) |
|
| 0 |
|
|
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| (8 | ) |
|
| (59 | ) |
|
| (19 | ) |
|
Increases-current period positions |
|
| 1 |
|
|
| 9 |
|
|
|
|
| 10 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 2 |
|
|
| 2 |
|
|
| 1 |
|
|
Settlements with tax authorities |
|
| 0 |
|
|
| (7 | ) |
|
|
|
| (6 | ) |
|
| 0 |
|
|
| (2 | ) |
|
| (1 | ) |
|
| (3 | ) |
|
| (26 | ) |
|
| — |
|
|
Expiration of statutes of limitations |
|
| (8 | ) |
|
| 0 |
|
|
|
|
| (8 | ) |
|
| 0 |
|
|
| 0 |
|
|
| (1 | ) |
|
| (10 | ) |
|
| (4 | ) |
|
| (8 | ) |
|
Balance at December 31 |
| $ | 167 |
|
| $ | 175 |
|
|
|
| $ | 44 |
|
| $ | 0 |
|
| $ | 0 |
|
| $ | 2 |
| |||||||||||||
Ending balance |
| $ | 117 |
|
| $ | 128 |
|
| $ | 167 |
|
|
|
|
Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations. For Dominion Energy and its subsidiaries, these unrecognized tax benefits were $140$64 million, $141$72 million and $37$140 million at December 31, 2022, 2021 and 2020, 2019,respectively. In discontinued operations, these unrecognized tax benefits were $33 million at both December 31, 2022 and 2018, respectively.2021. For Dominion Energy, the change in these unrecognized tax benefits decreased income tax expense by $6$7 million, $34 million and $6 million in 2022, 2021 and 2020, and increased income tax expense by $3 million and $6 million in 2019 and 2018, respectively, in continuing operations.respectively. For discontinued operations, the change in these unrecognized tax benefits increased income tax expense by $5$5 million in 2020 and decreased income tax expense by less than $1 million in both 2019 and 2018.2020.
For Virginia Power, these unrecognized tax benefits were less than $1 million at December 31, 2019 and $2 million at December 31, 2018. For Virginia Power, the change in these unrecognized tax benefits decreased income tax expense by $2 million in both 2019 and 2018.
Dominion Energy participates in the IRS Compliance Assurance Process which provides the opportunity to resolve complex tax matters with the IRS before filing its federal income tax returns, thus achieving certainty for such tax return filing positions agreed to by the IRS. In 2018, Dominion Energy submitted carryback claims for specified liability losses involving prior tax years. The IRS concluded its examination of these claims in 2020 with no material adjustments. The IRS has completed its audit of tax years through 2018.2019. The statute of limitations has not yet expired for years after 2016.2018. Although Dominion Energy has not received a final letter indicating no changes to its taxable income for tax year 2019,years 2021 and 2020, no material adjustments are expected. The IRS examination of tax year 20202022 is ongoing.
It is reasonably possible that settlement negotiations and expiration of statutes of limitations could result in a decrease in unrecognized tax benefits in 20212023 by up to $69$39 million for Dominion Energy. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, earnings could increase by up to $7$26 million for Dominion Energy. Otherwise, with regard to 20202022 and prior years, the Companies cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2021.2023.
For each of the major states in which Dominion Energy operates or previously operated, the earliest tax year remaining open for examination is as follows:
State | Earliest Open Tax Year | |
| ||
|
| |
Pennsylvania |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(1) | 2012 |
Connecticut | 2019 | |
Virginia(2) | 2019 | |
| 2019 | |
South Carolina | 2019 |
123
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 theThe Companies’ own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion Energy applies fair value measurements to certain assets and liabilities including commodity, interest rate, and foreign currency derivative instruments, and other investments including those held in nuclear decommissioning, Dominion Energy’s rabbi, and pension and other postretirement benefit plan trusts,are made in accordance with the requirementspolicies discussed above. Virginia Power applies fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments and other investments including those held in the nuclear decommissioning trust, in accordance with the requirements discussed above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above.
Inputs and Assumptions
Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, priceNote 2. See Note 7 for additional information is sought from external sources, including industry publications, and to a lesser extent, broker quotes. When evaluating pricing information provided by Designated Contract Market settlement pricing, other pricing services, or brokers, the Companies consider the ability to transact at the quoted price, i.e. if the quotes are based on an active market or an inactive market and to the extent which pricing models are used, if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases the unobservable inputs are developed and substantiated using historical information, available market data, third-party data and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships and changes in third-party sources.
For options and contracts with option-like characteristics where observable pricing information is not available from external sources, the Companies generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. The Companies use other option models under special circumstances, including but not limited to Spread Approximation Model and a Swing Option Model. For contracts with unique characteristics, the
Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.
The inputs and assumptions used in measuring fair value include the following:
For commodity derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For interest rate derivative contracts:
|
|
|
|
|
|
|
|
|
|
For foreign currency derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
For investments:
|
|
|
|
|
|
|
|
|
|
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:
|
|
|
|
|
|
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 andabout the Companies’ measurement date. Alternative investments recorded at NAV are not classified in the fair value hierarchy.derivative and hedge accounting activities.
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,options, 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’sthe Companies' quantitative information about Level 3 fair value measurements at December 31, 2020.2022. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.
|
|
|
|
|
|
|
| Dominion Energy |
|
| Virginia Power | |||||||||||
|
|
| Valuation |
| Unobservable |
|
| Fair Value (millions) |
| Range |
| Weighted |
|
| Fair Value (millions) |
|
| Range |
| Weighted | ||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Physical and financial forwards: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
FTRs |
|
| Discounted |
| Market price | (3) |
| $ | 214 |
| 2-24 |
| 6 |
|
| $ | 214 |
|
| 2-24 |
| 6 |
Electricity |
|
| Discounted |
| Market price | (3) |
|
| 201 |
| 27-110 |
| 51 |
|
|
| — |
|
| — |
| — |
Physical options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Natural gas(2) |
|
| Option model |
| Market price | (3) |
|
| 22 |
| 3-16 |
| 10 |
|
|
| 22 |
|
| 3-16 |
| 10 |
|
|
|
|
| Price volatility | (4) |
|
|
| 11%-63% |
| 45% |
|
|
|
|
| 11%-63% |
| 45% | ||
Total assets |
|
|
|
|
|
|
| $ | 437 |
|
|
|
|
|
| $ | 236 |
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Physical and financial forwards: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Natural gas(2) |
|
| Discounted |
| Market price | (3) |
| $ | 10 |
| (2)-4 |
| (1) |
|
| $ | 10 |
|
| (2)-4 |
| (1) |
FTRs |
|
| Discounted |
| Market price | (3) |
|
| 5 |
| 2-12 |
| 5 |
|
|
| 5 |
|
| 2-12 |
| 5 |
Total |
|
|
|
|
|
|
| $ | 15 |
|
|
|
|
|
| $ | 15 |
|
|
|
|
|
|
| Fair Value (millions) |
|
| Valuation Techniques |
| Unobservable Input |
|
| Range |
| Weighted Average(1) |
| ||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical and financial forwards: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas(2) |
| $ | 95 |
|
| Discounted cash flow |
| Market price (per Dth) | (3) |
| (1) - 4 |
|
| (1 | ) |
FTRs |
|
| 15 |
|
| Discounted cash flow |
| Market price (per MWh) | (3) |
| (1) - 4 |
|
| 1 |
|
Total assets |
| $ | 110 |
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial forwards: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FTRs |
| $ | 5 |
|
| Discounted cash flow |
| Market price (per MWh) | (3) |
| (4) - 3 |
|
| 0 |
|
Physical options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
| 2 |
|
| Option model |
| Market price (per Dth) | (3) |
| 2 - 5 |
|
| 4 |
|
|
|
|
|
|
|
|
| Price volatility | (4) |
| 20% - 56% |
|
| 38 | % |
Total liabilities |
| $ | 7 |
|
|
|
|
|
|
|
|
|
|
|
|
(2) Includes basis. (3) Represents market prices beyond defined terms for Levels 1 and 2. (4) Represents volatilities unrepresented in published markets.
|
|
|
|
|
|
|
|
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
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) |
124
Nonrecurring Fair Value Measurements
See Note 3 for information on the nonrecurring fair value measurement associated with Dominion Energy
Energy's acquisition of Birdseye and its retained noncontrolling interest in Cove Point. See Note 9 for information regarding nonrecurring fair value measurements associated with Dominion Energy’s retained noncontrolling interest in Cove Point, charges related to Fowler Ridge, Dominion Energy’s sale of its interest in Blue Racer and Dominion Energy’s retainedEnergy's noncontrolling interest in businesses and assets contributed to Wrangler.Wrangler and Dominion Energy's noncontrolling ownership interest in Dominion Privatization. See Note 10 for information regarding an impairment chargecharges recorded by Dominion Energy associated with nonregulated solar facilities and 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 both December 31, 2022 and 2021.
125
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’sthe Companies' pension and other postretirement benefit plans are presented in Note 22.
Dominion Energy
The following table presents Dominion Energy’sthe Companies' assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||||||||||||||||||
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
December 31, 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Commodity |
| $ | — |
|
| $ | 332 |
|
| $ | 437 |
|
| $ | 769 |
|
| $ | — |
|
| $ | 32 |
|
| $ | 236 |
|
| $ | 268 |
|
Interest rate |
|
| — |
|
|
| 1,407 |
|
|
| — |
|
|
| 1,407 |
|
|
| — |
|
|
| 614 |
|
|
| — |
|
|
| 614 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
U.S. |
|
| 3,810 |
|
|
| — |
|
|
| — |
|
|
| 3,810 |
|
|
| 2,028 |
|
|
| — |
|
|
| — |
|
|
| 2,028 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Corporate debt instruments |
|
| — |
|
|
| 576 |
|
|
| — |
|
|
| 576 |
|
|
| — |
|
|
| 360 |
|
|
| — |
|
|
| 360 |
|
Government securities |
|
| 161 |
|
|
| 1,059 |
|
|
| — |
|
|
| 1,220 |
|
|
| 90 |
|
|
| 542 |
|
|
| — |
|
|
| 632 |
|
Total assets |
| $ | 3,971 |
|
| $ | 3,374 |
|
| $ | 437 |
|
| $ | 7,782 |
|
| $ | 2,118 |
|
| $ | 1,548 |
|
| $ | 236 |
|
| $ | 3,902 |
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Commodity |
| $ | — |
|
| $ | 911 |
|
| $ | 15 |
|
| $ | 926 |
|
| $ | — |
|
| $ | 333 |
|
| $ | 15 |
|
| $ | 348 |
|
Interest rate |
|
| — |
|
|
| 377 |
|
|
| — |
|
|
| 377 |
|
|
| — |
|
|
| 7 |
|
|
| — |
|
|
| 7 |
|
Foreign currency exchange |
|
| — |
|
|
| 101 |
|
|
| — |
|
|
| 101 |
|
|
| — |
|
|
| 101 |
|
|
| — |
|
|
| 101 |
|
Total liabilities |
| $ | — |
|
| $ | 1,389 |
|
| $ | 15 |
|
| $ | 1,404 |
|
| $ | — |
|
| $ | 441 |
|
| $ | 15 |
|
| $ | 456 |
|
December 31, 2021 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Commodity |
| $ | — |
|
| $ | 52 |
|
| $ | 230 |
|
| $ | 282 |
|
| $ | — |
|
| $ | 36 |
|
| $ | 110 |
|
| $ | 146 |
|
Interest rate |
|
| — |
|
|
| 323 |
|
|
| — |
|
|
| 323 |
|
|
| — |
|
|
| 146 |
|
|
| — |
|
|
| 146 |
|
Foreign currency exchange |
|
| — |
|
|
| 8 |
|
|
| — |
|
|
| 8 |
|
|
| — |
|
|
| 8 |
|
|
| — |
|
|
| 8 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
U.S. |
|
| 5,241 |
|
|
| — |
|
|
| — |
|
|
| 5,241 |
|
|
| 2,420 |
|
|
| — |
|
|
| — |
|
|
| 2,420 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Corporate debt instruments |
|
| — |
|
|
| 881 |
|
|
| — |
|
|
| 881 |
|
|
| — |
|
|
| 531 |
|
|
| — |
|
|
| 531 |
|
Government securities |
|
| 199 |
|
|
| 1,256 |
|
|
| — |
|
|
| 1,455 |
|
|
| 93 |
|
|
| 506 |
|
|
| — |
|
|
| 599 |
|
Cash equivalents and other |
|
| (29 | ) |
|
| — |
|
|
| — |
|
|
| (29 | ) |
|
| (3 | ) |
|
| — |
|
|
| — |
|
|
| (3 | ) |
Total assets |
| $ | 5,411 |
|
| $ | 2,520 |
|
| $ | 230 |
|
| $ | 8,161 |
|
| $ | 2,510 |
|
| $ | 1,227 |
|
| $ | 110 |
|
| $ | 3,847 |
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Commodity |
| $ | — |
|
| $ | 461 |
|
| $ | 8 |
|
| $ | 469 |
|
| $ | — |
|
| $ | 125 |
|
| $ | 8 |
|
| $ | 133 |
|
Interest rate |
|
| — |
|
|
| 399 |
|
|
| — |
|
|
| 399 |
|
|
| — |
|
|
| 337 |
|
|
| — |
|
|
| 337 |
|
Total liabilities |
| $ | — |
|
| $ | 860 |
|
| $ | 8 |
|
| $ | 868 |
|
| $ | — |
|
| $ | 462 |
|
| $ | 8 |
|
| $ | 470 |
|
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 0 |
|
| $ | 57 |
|
| $ | 110 |
|
| $ | 167 |
|
Interest rate |
|
| 0 |
|
|
| 230 |
|
|
| 0 |
|
|
| 230 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 4,648 |
|
|
| 0 |
|
|
| 0 |
|
|
| 4,648 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
| 0 |
|
|
| 629 |
|
|
| 0 |
|
|
| 629 |
|
Government securities |
|
| 508 |
|
|
| 730 |
|
|
| 0 |
|
|
| 1,238 |
|
Cash equivalents and other |
|
| 32 |
|
|
| 15 |
|
|
| 0 |
|
|
| 47 |
|
Total assets |
| $ | 5,188 |
|
| $ | 1,661 |
|
| $ | 110 |
|
| $ | 6,959 |
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 0 |
|
| $ | 48 |
|
| $ | 7 |
|
| $ | 55 |
|
Interest rate |
|
| 0 |
|
|
| 431 |
|
|
| 0 |
|
|
| 431 |
|
Total liabilities |
| $ | 0 |
|
| $ | 479 |
|
| $ | 7 |
|
| $ | 486 |
|
December 31, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 0 |
|
| $ | 55 |
|
| $ | 19 |
|
| $ | 74 |
|
Interest rate |
|
| 0 |
|
|
| 11 |
|
|
| 0 |
|
|
| 11 |
|
Foreign currency |
|
| 0 |
|
|
| 8 |
|
|
| 0 |
|
|
| 8 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 4,195 |
|
|
| 0 |
|
|
| 0 |
|
|
| 4,195 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
| 0 |
|
|
| 463 |
|
|
| 0 |
|
|
| 463 |
|
Government securities |
|
| 473 |
|
|
| 719 |
|
|
| 0 |
|
|
| 1,192 |
|
Cash equivalents and other |
|
| 19 |
|
|
| 1 |
|
|
| 0 |
|
|
| 20 |
|
Total assets |
| $ | 4,687 |
|
| $ | 1,257 |
|
| $ | 19 |
|
| $ | 5,963 |
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 0 |
|
| $ | 75 |
|
| $ | 56 |
|
| $ | 131 |
|
Interest rate |
|
| 0 |
|
|
| 606 |
|
|
| 0 |
|
|
| 606 |
|
Foreign currency |
|
| 0 |
|
|
| 3 |
|
|
| 0 |
|
|
| 3 |
|
Total liabilities |
| $ | 0 |
|
| $ | 684 |
|
| $ | 56 |
|
| $ | 740 |
|
126
|
|
The following table presents the net change in Dominion Energy’sthe Companies' assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||||||||||||||||||||||
|
| 2020 |
|
| 2019 |
|
| 2018 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Balance at January 1, |
| $ | (37 | ) |
| $ | 64 |
|
| $ | 150 |
| ||||||||||||||||||||||||
Beginning balance |
| $ | 222 |
|
| $ | 103 |
|
| $ | (37 | ) |
| $ | 102 |
|
| $ | 103 |
|
| $ | (37 | ) | ||||||||||||
Total realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Included in earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Operating Revenue |
|
| 0 |
|
|
| (1 | ) |
|
| (2 | ) |
|
| 2 |
|
|
| (9 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Electric fuel and other energy-related purchases |
|
| (33 | ) |
|
| (22 | ) |
|
| (15 | ) |
|
| 444 |
|
|
| 10 |
|
|
| (33 | ) |
|
| 382 |
|
|
| 4 |
|
|
| (33 | ) |
Purchased gas |
|
| 0 |
|
|
| 2 |
|
|
| 0 |
| ||||||||||||||||||||||||
Discontinued operations |
|
| 1 |
|
|
| 0 |
|
|
| 0 |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Included in other comprehensive income |
|
| 0 |
|
|
| 0 |
|
|
| 1 |
| ||||||||||||||||||||||||
Included in regulatory assets/liabilities |
|
| 140 |
|
|
| (90 | ) |
|
| (44 | ) |
|
| 183 |
|
|
| 119 |
|
|
| 140 |
|
|
| 102 |
|
|
| (1 | ) |
|
| 140 |
|
Settlements |
|
| 33 |
|
|
| 17 |
|
|
| (27 | ) |
|
| (455 | ) |
|
| (10 | ) |
|
| 33 |
|
|
| (393 | ) |
|
| (4 | ) |
|
| 33 |
|
Purchases |
|
| 0 |
|
|
| (10 | ) |
|
| 0 |
|
|
| 28 |
|
|
| — |
|
|
| — |
|
|
| 28 |
|
|
| — |
|
|
| — |
|
Sales |
|
| (1 | ) |
|
| 6 |
|
|
| 0 |
|
|
| — |
|
|
| — |
|
|
| (1 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Transfers out of Level 3 |
|
| 0 |
|
|
| (3 | ) |
|
| 1 |
|
|
| (2 | ) |
|
| 9 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Balance at December 31, |
| $ | 103 |
|
| $ | (37 | ) |
| $ | 64 |
| ||||||||||||||||||||||||
Ending balance |
| $ | 422 |
|
| $ | 222 |
|
| $ | 103 |
|
| $ | 221 |
|
| $ | 102 |
|
| $ | 103 |
|
There were 0The Companies’ had no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2020, 20192022, 2021 and 2018.2020.
Virginia Power
The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at December 31, 2020. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.
|
| Fair Value (millions) |
|
| Valuation Techniques |
| Unobservable Input |
|
| Range |
| Weighted Average(1) |
| ||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical and financial forwards: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas(2) |
| $ | 95 |
|
| Discounted cash flow |
| Market price (per Dth) | (3) |
| (1) - 4 |
|
| (1 | ) |
FTRs |
|
| 15 |
|
| Discounted cash flow |
| Market price (per MWh) | (3) |
| (1) - 4 |
|
| 1 |
|
Total assets |
| $ | 110 |
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial forwards: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FTRs |
| $ | 5 |
|
| Discounted cash flow |
| Market price (per MWh) | (3) |
| (4) - 3 |
|
| 0 |
|
Physical options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
| 2 |
|
| Option model |
| Market price (per Dth) | (3) |
| 2 - 5 |
|
| 4 |
|
|
|
|
|
|
|
|
| Price volatility | (4) |
| 20% - 56% |
|
| 38 | % |
Total liabilities |
| $ | 7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
|
|
|
| |||
|
|
|
| |||
|
|
|
| |||
|
|
|
| |||
|
|
|
|
The following table presents Virginia Power’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 0 |
|
| $ | 5 |
|
| $ | 110 |
|
| $ | 115 |
|
Interest rate |
|
| 0 |
|
|
| 66 |
|
|
| 0 |
|
|
| 66 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 2,171 |
|
|
| 0 |
|
|
| 0 |
|
|
| 2,171 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
| 0 |
|
|
| 348 |
|
|
| 0 |
|
|
| 348 |
|
Government securities |
|
| 201 |
|
|
| 309 |
|
|
| 0 |
|
|
| 510 |
|
Cash equivalents and other |
|
| 13 |
|
|
| 0 |
|
|
| 0 |
|
|
| 13 |
|
Total assets |
| $ | 2,385 |
|
| $ | 728 |
|
| $ | 110 |
|
| $ | 3,223 |
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 0 |
|
| $ | 22 |
|
| $ | 7 |
|
| $ | 29 |
|
Interest rate |
|
| 0 |
|
|
| 376 |
|
|
| 0 |
|
|
| 376 |
|
Total liabilities |
| $ | 0 |
|
| $ | 398 |
|
| $ | 7 |
|
| $ | 405 |
|
December 31, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 0 |
|
| $ | 3 |
|
| $ | 19 |
|
| $ | 22 |
|
Interest rate |
|
| 0 |
|
|
| 2 |
|
|
| 0 |
|
|
| 2 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 1,920 |
|
|
| 0 |
|
|
| 0 |
|
|
| 1,920 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
| 0 |
|
|
| 256 |
|
|
| 0 |
|
|
| 256 |
|
Government securities |
|
| 186 |
|
|
| 361 |
|
|
| 0 |
|
|
| 547 |
|
Cash equivalents and other |
|
| 0 |
|
|
| 1 |
|
|
| 0 |
|
|
| 1 |
|
Total assets |
| $ | 2,106 |
|
| $ | 623 |
|
| $ | 19 |
|
| $ | 2,748 |
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 0 |
|
| $ | 47 |
|
| $ | 56 |
|
| $ | 103 |
|
Interest rate |
|
| 0 |
|
|
| 363 |
|
|
| 0 |
|
|
| 363 |
|
Total liabilities |
| $ | 0 |
|
| $ | 410 |
|
| $ | 56 |
|
| $ | 466 |
|
|
|
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:
|
| 2020 |
|
| 2019 |
|
| 2018 |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1, |
| $ | (37 | ) |
| $ | 60 |
|
| $ | 147 |
|
Total realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
Electric fuel and other energy-related purchases |
|
| (33 | ) |
|
| (22 | ) |
|
| (17 | ) |
Included in regulatory assets/liabilities |
|
| 140 |
|
|
| (88 | ) |
|
| (45 | ) |
Settlements |
|
| 33 |
|
|
| 13 |
|
|
| (25 | ) |
Balance at December 31, |
| $ | 103 |
|
| $ | (37 | ) |
| $ | 60 |
|
There were 0 unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2020, 2019 and 2018.
Fair Value of Financial Instruments
Substantially all of the Companies’ financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash, restricted cash and equivalents, customer and other receivables, affiliated receivables, short-term debt, affiliated current borrowings, payables to affiliates and accounts payable are representative of fair value because of the short-term nature of these instruments. For the Companies’ financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:
December 31, |
| 2020 |
|
| 2019 |
| ||||||||||
|
| Carrying Amount |
|
| Estimated Fair Value(1) |
|
| Carrying Amount |
|
| Estimated Fair Value(1) |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt(2)(3) |
| $ | 31,996 |
|
| $ | 38,773 |
|
| $ | 32,055 |
|
| $ | 36,155 |
|
Supplemental 364-Day credit facility borrowings |
|
| 225 |
|
|
| 225 |
|
|
| — |
|
|
| — |
|
Junior subordinated notes(4) |
|
| 3,411 |
|
|
| 3,633 |
|
|
| 4,797 |
|
|
| 4,953 |
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt(4) |
| $ | 13,207 |
|
| $ | 16,455 |
|
| $ | 12,326 |
|
| $ | 14,281 |
|
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||
|
| Carrying |
|
| Estimated Fair Value(1) |
|
| Carrying |
|
| Estimated Fair Value(1) |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
December 31, 2022 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Long-term debt(2) |
| $ | 39,680 |
|
| $ | 36,426 |
|
| $ | 15,616 |
|
| $ | 14,067 |
|
Supplemental credit facility borrowings |
|
| 450 |
|
|
| 450 |
|
|
|
|
|
|
| ||
Junior subordinated notes(2) |
|
| 1,387 |
|
|
| 1,340 |
|
|
|
|
|
|
| ||
December 31, 2021 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Long-term debt(2) |
| $ | 35,996 |
|
| $ | 40,947 |
|
| $ | 13,753 |
|
| $ | 16,021 |
|
Junior subordinated notes(2) |
|
| 1,386 |
|
|
| 1,470 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 7. DERIVATIVES AND HEDGE ACCOUNTING ACTIVITIES
See Note 2 for the Companies’ accounting policies, objectives, and strategies for using derivative instruments. See NoteNotes 2 and 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 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
127
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’sthe Companies' 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:
|
| Dominion Energy Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
| Virginia Power Gross Amounts Not Offset in the Consolidated Balance Sheet |
| ||||||||||||||||||||||||||
|
| Gross Assets |
|
| Financial |
|
| Cash |
|
| Net |
|
| Gross Assets |
|
| Financial |
|
| Cash |
|
| Net |
| ||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
December 31, 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Over-the-counter |
| $ | 408 |
|
| $ | 28 |
|
| $ | — |
|
| $ | 380 |
|
| $ | 238 |
|
| $ | 7 |
|
| $ | — |
|
| $ | 231 |
|
Exchange |
|
| 160 |
|
|
| 159 |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Over-the-counter |
|
| 1,407 |
|
|
| 248 |
|
|
| — |
|
|
| 1,159 |
|
|
| 614 |
|
|
| 38 |
|
|
| — |
|
|
| 576 |
|
Total derivatives, |
| $ | 1,975 |
|
| $ | 435 |
|
| $ | — |
|
| $ | 1,540 |
|
| $ | 852 |
|
| $ | 45 |
|
| $ | — |
|
| $ | 807 |
|
December 31, 2021 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Over-the-counter |
| $ | 153 |
|
| $ | 13 |
|
| $ | — |
|
| $ | 140 |
|
| $ | 110 |
|
| $ | 8 |
|
| $ | — |
|
| $ | 102 |
|
Exchange |
|
| 9 |
|
|
| 7 |
|
|
| — |
|
|
| 2 |
|
|
| 7 |
|
|
| 7 |
|
|
| — |
|
|
| — |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Over-the-counter |
|
| 323 |
|
|
| 49 |
|
|
| — |
|
|
| 274 |
|
|
| 146 |
|
|
| 20 |
|
|
| — |
|
|
| 126 |
|
Foreign currency exchange rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Over-the-counter |
|
| 8 |
|
|
| — |
|
|
| — |
|
|
| 8 |
|
|
| 8 |
|
|
| — |
|
|
| — |
|
|
| 8 |
|
Total derivatives, |
| $ | 493 |
|
| $ | 69 |
|
| $ | — |
|
| $ | 424 |
|
| $ | 271 |
|
| $ | 35 |
|
| $ | — |
|
| $ | 236 |
|
|
| December 31, 2020 |
|
| December 31, 2019 |
| ||||||||||||||||||||||||||
|
| 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 |
| $ | 117 |
|
| $ | 9 |
|
| $ | 0 |
|
| $ | 108 |
|
| $ | 35 |
|
| $ | 21 |
|
| $ | 0 |
|
| $ | 14 |
|
Exchange |
|
| 49 |
|
|
| 24 |
|
|
| 0 |
|
|
| 25 |
|
|
| 37 |
|
|
| 21 |
|
|
| 0 |
|
|
| 16 |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 230 |
|
|
| 13 |
|
|
| 0 |
|
|
| 217 |
|
|
| 11 |
|
|
| 3 |
|
|
| 0 |
|
|
| 8 |
|
Foreign currency contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 8 |
|
|
| 8 |
|
|
| 0 |
|
|
| 0 |
|
Total derivatives, subject to a master netting or similar arrangement |
| $ | 396 |
|
| $ | 46 |
|
| $ | 0 |
|
| $ | 350 |
|
| $ | 91 |
|
| $ | 53 |
|
| $ | 0 |
|
| $ | 38 |
|
|
|
|
| December 31, 2020 |
|
| December 31, 2019 |
| ||||||||||||||||||||||||||
|
| 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 |
| $ | 30 |
|
| $ | 9 |
|
| $ | 0 |
|
| $ | 21 |
|
| $ | 105 |
|
| $ | 21 |
|
| $ | 0 |
|
| $ | 84 |
|
Exchange |
|
| 24 |
|
|
| 24 |
|
|
| 0 |
|
|
| 0 |
|
|
| 21 |
|
|
| 21 |
|
|
| 0 |
|
|
| 0 |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 431 |
|
|
| 13 |
|
|
| 17 |
|
|
| 401 |
|
|
| 606 |
|
|
| 8 |
|
|
| 35 |
|
|
| 563 |
|
Foreign currency contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 3 |
|
|
| 3 |
|
|
| 0 |
|
|
| 0 |
|
Total derivatives, subject to a master netting or similar arrangement |
| $ | 485 |
|
| $ | 46 |
|
| $ | 17 |
|
| $ | 422 |
|
| $ | 735 |
|
| $ | 53 |
|
| $ | 35 |
|
| $ | 647 |
|
|
|
Volumes
128
|
| Dominion Energy Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
| Virginia Power Gross Amounts Not Offset in the Consolidated Balance Sheet |
| ||||||||||||||||||||||||||
|
| Gross Liabilities |
|
| Financial |
|
| Cash |
|
| Net |
|
| Gross Liabilities |
|
| Financial |
|
| Cash |
|
| Net |
| ||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
December 31, 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Over-the-counter |
| $ | 443 |
|
| $ | 34 |
|
| $ | 71 |
|
| $ | 338 |
|
| $ | 146 |
|
| $ | 13 |
|
| $ | 71 |
|
| $ | 62 |
|
Exchange |
|
| 483 |
|
|
| 159 |
|
|
| 324 |
|
|
| — |
|
|
| 176 |
|
|
| — |
|
|
| 176 |
|
|
| — |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Over-the-counter |
|
| 377 |
|
|
| 210 |
|
|
| 1 |
|
|
| 166 |
|
|
| 7 |
|
|
| — |
|
|
| — |
|
|
| 7 |
|
Foreign currency exchange rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Over-the-counter |
|
| 101 |
|
|
| 32 |
|
|
| — |
|
|
| 69 |
|
|
| 101 |
|
|
| 32 |
|
|
| — |
|
|
| 69 |
|
Total derivatives, |
| $ | 1,404 |
|
| $ | 435 |
|
| $ | 396 |
|
| $ | 573 |
|
| $ | 430 |
|
| $ | 45 |
|
| $ | 247 |
|
| $ | 138 |
|
December 31, 2021 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Over-the-counter |
| $ | 95 |
|
| $ | 13 |
|
| $ | 54 |
|
| $ | 28 |
|
| $ | 84 |
|
| $ | 8 |
|
| $ | 54 |
|
| $ | 22 |
|
Exchange |
|
| 374 |
|
|
| 7 |
|
|
| 367 |
|
|
| — |
|
|
| 43 |
|
|
| 7 |
|
|
| 36 |
|
|
| — |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Over-the-counter |
|
| 399 |
|
|
| 49 |
|
|
| 11 |
|
|
| 339 |
|
|
| 337 |
|
|
| 20 |
|
|
| — |
|
|
| 317 |
|
Total derivatives, |
| $ | 868 |
|
| $ | 69 |
|
| $ | 432 |
|
| $ | 367 |
|
| $ | 464 |
|
| $ | 35 |
|
| $ | 90 |
|
| $ | 339 |
|
Volumes
The following table presents the volume of Dominion Energy’sthe Companies' derivative activity as of December 31, 2020.2022. 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.
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||
|
| Current |
|
| Noncurrent |
|
| Current |
|
| Noncurrent |
| ||||
Natural Gas (bcf): |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Fixed price |
|
| 50 |
|
|
| 2 |
|
|
| 41 |
|
|
| 2 |
|
Basis(1) |
|
| 154 |
|
|
| 414 |
|
|
| 140 |
|
|
| 407 |
|
Electricity (MWh in millions): |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Fixed price |
|
| 16 |
|
|
| 35 |
|
|
| 8 |
|
|
| 9 |
|
FTRs |
|
| 45 |
|
|
| — |
|
|
| 45 |
|
|
| — |
|
Oil (Gal in millions) |
|
| 6 |
|
|
| — |
|
|
| 6 |
|
|
| — |
|
Interest rate(2) (in millions) |
| $ | 2,003 |
|
| $ | 10,707 |
|
| $ | 1,600 |
|
| $ | 1,950 |
|
Foreign currency exchange rate(2) (in millions) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Danish Krone |
| 394 kr. |
|
| 4,167 kr. |
|
| 394 kr. |
|
| 4,167 kr. |
| ||||
Euro |
| €780 |
|
| €2,131 |
|
| €780 |
|
| €2,131 |
|
129
|
| Current |
|
| Noncurrent |
| ||
Natural Gas (bcf): |
|
|
|
|
|
|
|
|
Fixed price (1) |
|
| 65 |
|
|
| 0 |
|
Basis |
|
| 190 |
|
|
| 477 |
|
Electricity (MWh): |
|
|
|
|
|
|
|
|
Fixed price |
|
| 7,932,760 |
|
|
| 6,825,680 |
|
FTRs |
|
| 45,249,553 |
|
|
| 0 |
|
Interest rate(2) |
| $ | 850,000,000 |
|
| $ | 6,058,894,892 |
|
(1)
AOCI
|
|
AOCI
The following table presents selected information related to gains (losses)losses on cash flow hedges included in AOCI in Dominion Energy’sthe Companies' Consolidated Balance Sheets at December 31, 2020:2022:
|
| Dominion Energy |
| Virginia Power | ||||||||||||||||||||||||||
|
| AOCI After-Tax |
|
| Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax |
|
| Maximum Term |
| AOCI After-Tax |
|
| Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax |
|
| Maximum Term |
| AOCI After-Tax |
|
| Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax |
|
| Maximum Term | ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Commodities: |
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Gas |
| $ | (1 | ) |
| $ | (1 | ) |
| 12 months | ||||||||||||||||||||
Interest rate |
|
| (418 | ) |
|
| (42 | ) |
| 396 months |
| $ | (249 | ) |
| $ | (33 | ) |
| 396 months |
| $ | 16 |
|
| $ | (1 | ) |
| 396 months |
Total |
| $ | (419 | ) |
| $ | (43 | ) |
|
|
| $ | (249 | ) |
| $ | (33 | ) |
|
|
| $ | 16 |
|
| $ | (1 | ) |
|
|
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated purchases)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 market prices and interest rates.
In connection with the GT&S Transaction, certain cash flow hedges of debt-related items became probable of not occurring. See Note 3 for further information.
Fair Value Hedges
For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings and presented in the same line item. Gains and losses on derivatives inThere were no derivative instruments designated as fair value hedge relationships were immaterial forhedges during the years ended December 31, 2020, 20192022, 2021 and 2018.2020.
The following table presents the amounts recorded on the balance sheetDominion Energy's Consolidated Balance Sheets related to cumulative basis adjustments for fair value hedges:
|
| Carrying Amount of the Hedged Asset (Liability)(1) |
|
| Cumulative Amount of Fair Value Hedging Adjustments Included in the Carrying Amount of the Hedged Assets (Liabilities)(2) |
| ||||||||||
|
| December 31, 2020 |
|
| December 31, 2019 |
|
| December 31, 2020 |
|
| December 31, 2019 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
| $ | (1,153 | ) |
| $ | (1,154 | ) |
| $ | (3 | ) |
| $ | (4 | ) |
|
|
(2) Includes $(3) million and $3 million of hedging adjustments on discontinued hedging relationships at both December 2022 and 2021, respectively:
|
| Carrying Amount of the Hedged Assets |
|
| Cumulative Amount of Fair Value |
| ||||||||||
|
| December 31, 2022 |
|
| December 31, 2021 |
|
| December 31, 2022 |
|
| December 31, 2021 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Long-term debt |
| $ | — |
|
| $ | (352 | ) |
| $ | — |
|
| $ | (2 | ) |
Virginia Power had no amounts recorded in its Consolidated Balance Sheets related to fair value hedges at December 31, 2020 and December 31, 2019, respectively.2022 or 2021.
130
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Dominion Energy’sthe Companies' derivatives and where they are presented in their Consolidated Balance Sheets:
131
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||||||||||
|
| Fair Value – |
|
| Fair Value – |
|
| Total Fair |
|
| Fair Value – |
|
| Fair Value – |
|
| Total Fair |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
At December 31, 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Commodity |
| $ | — |
|
| $ | 532 |
|
| $ | 532 |
|
| $ | — |
|
| $ | 264 |
|
| $ | 264 |
|
Interest rate |
|
| 501 |
|
|
| 104 |
|
|
| 605 |
|
|
| 501 |
|
|
| — |
|
|
| 501 |
|
Total current derivative assets |
|
| 501 |
|
|
| 636 |
|
|
| 1,137 |
|
|
| 501 |
|
|
| 264 |
|
|
| 765 |
|
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Commodity |
|
| — |
|
|
| 237 |
|
|
| 237 |
|
|
| — |
|
|
| 4 |
|
|
| 4 |
|
Interest rate |
|
| 113 |
|
|
| 689 |
|
|
| 802 |
|
|
| 113 |
|
|
| — |
|
|
| 113 |
|
Total noncurrent derivative assets(1) |
|
| 113 |
|
|
| 926 |
|
|
| 1,039 |
|
|
| 113 |
|
|
| 4 |
|
|
| 117 |
|
Total derivative assets |
| $ | 614 |
|
| $ | 1,562 |
|
| $ | 2,176 |
|
| $ | 614 |
|
| $ | 268 |
|
| $ | 882 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Commodity |
| $ | — |
|
| $ | 700 |
|
| $ | 700 |
|
| $ | — |
|
| $ | 290 |
|
| $ | 290 |
|
Interest rate |
|
| — |
|
|
| 70 |
|
|
| 70 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Foreign currency |
|
| — |
|
|
| 8 |
|
|
| 8 |
|
|
| — |
|
|
| 8 |
|
|
| 8 |
|
Total current derivative liabilities |
|
| — |
|
|
| 778 |
|
|
| 778 |
|
|
| — |
|
|
| 298 |
|
|
| 298 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Commodity |
|
| — |
|
|
| 226 |
|
|
| 226 |
|
|
| — |
|
|
| 58 |
|
|
| 58 |
|
Interest rate |
|
| 7 |
|
|
| 300 |
|
|
| 307 |
|
|
| 7 |
|
|
| — |
|
|
| 7 |
|
Foreign currency |
|
| — |
|
|
| 93 |
|
|
| 93 |
|
|
| — |
|
|
| 93 |
|
|
| 93 |
|
Total noncurrent derivative liabilities(2) |
|
| 7 |
|
|
| 619 |
|
|
| 626 |
|
|
| 7 |
|
|
| 151 |
|
|
| 158 |
|
Total derivative liabilities |
| $ | 7 |
|
| $ | 1,397 |
|
| $ | 1,404 |
|
| $ | 7 |
|
| $ | 449 |
|
| $ | 456 |
|
At December 31, 2021 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Commodity |
| $ | — |
|
| $ | 103 |
|
| $ | 103 |
|
| $ | — |
|
| $ | 74 |
|
| $ | 74 |
|
Interest rate |
|
| 1 |
|
|
| 17 |
|
|
| 18 |
|
|
| 1 |
|
|
| — |
|
|
| 1 |
|
Foreign currency |
|
| — |
|
|
| 1 |
|
|
| 1 |
|
|
| — |
|
|
| 1 |
|
|
| 1 |
|
Total current derivative assets |
|
| 1 |
|
|
| 121 |
|
|
| 122 |
|
|
| 1 |
|
|
| 75 |
|
|
| 76 |
|
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Commodity |
|
| — |
|
|
| 179 |
|
|
| 179 |
|
|
| — |
|
|
| 72 |
|
|
| 72 |
|
Interest rate |
|
| 145 |
|
|
| 160 |
|
|
| 305 |
|
|
| 145 |
|
|
| — |
|
|
| 145 |
|
Foreign currency |
|
| — |
|
|
| 7 |
|
|
| 7 |
|
|
| — |
|
|
| 7 |
|
|
| 7 |
|
Total noncurrent derivative assets(1) |
|
| 145 |
|
|
| 346 |
|
|
| 491 |
|
|
| 145 |
|
|
| 79 |
|
|
| 224 |
|
Total derivative assets |
| $ | 146 |
|
| $ | 467 |
|
| $ | 613 |
|
| $ | 146 |
|
| $ | 154 |
|
| $ | 300 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Commodity |
| $ | — |
|
| $ | 304 |
|
| $ | 304 |
|
| $ | — |
|
| $ | 92 |
|
| $ | 92 |
|
Interest rate |
|
| 42 |
|
|
| 13 |
|
|
| 55 |
|
|
| 42 |
|
|
| — |
|
|
| 42 |
|
Total current derivative liabilities |
|
| 42 |
|
|
| 317 |
|
|
| 359 |
|
|
| 42 |
|
|
| 92 |
|
|
| 134 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Commodity |
|
| — |
|
|
| 165 |
|
|
| 165 |
|
|
| — |
|
|
| 41 |
|
|
| 41 |
|
Interest rate |
|
| 295 |
|
|
| 49 |
|
|
| 344 |
|
|
| 295 |
|
|
| — |
|
|
| 295 |
|
Total noncurrent derivative liabilities(2) |
|
| 295 |
|
|
| 214 |
|
|
| 509 |
|
|
| 295 |
|
|
| 41 |
|
|
| 336 |
|
Total derivative liabilities |
| $ | 337 |
|
| $ | 531 |
|
| $ | 868 |
|
| $ | 337 |
|
| $ | 133 |
|
| $ | 470 |
|
|
| Fair Value – Derivatives under Hedge Accounting |
|
| Fair Value – Derivatives not under Hedge Accounting |
|
| Total Fair Value |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 0 |
|
| $ | 58 |
|
| $ | 58 |
|
Interest rate |
|
| 0 |
|
|
| 9 |
|
|
| 9 |
|
Total current derivative assets(1) |
|
| 0 |
|
|
| 67 |
|
|
| 67 |
|
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| 0 |
|
|
| 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 |
| $ | 0 |
|
| $ | 42 |
|
| $ | 42 |
|
Interest rate |
|
| 363 |
|
|
| 10 |
|
|
| 373 |
|
Total current derivative liabilities(3) |
|
| 363 |
|
|
| 52 |
|
|
| 415 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| 0 |
|
|
| 13 |
|
|
| 13 |
|
Interest rate |
|
| 19 |
|
|
| 39 |
|
|
| 58 |
|
Total noncurrent derivative liabilities(4) |
|
| 19 |
|
|
| 52 |
|
|
| 71 |
|
Total derivative liabilities |
| $ | 382 |
|
| $ | 104 |
|
| $ | 486 |
|
At December 31, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 30 |
|
| $ | 37 |
|
| $ | 67 |
|
Interest rate |
|
| 1 |
|
|
| 0 |
|
|
| 1 |
|
Total current derivative assets(1) |
|
| 31 |
|
|
| 37 |
|
|
| 68 |
|
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| 1 |
|
|
| 6 |
|
|
| 7 |
|
Interest rate |
|
| 10 |
|
|
| 0 |
|
|
| 10 |
|
Foreign currency |
|
| 8 |
|
|
| 0 |
|
|
| 8 |
|
Total noncurrent derivative assets(2) |
|
| 19 |
|
|
| 6 |
|
|
| 25 |
|
Total derivative assets |
| $ | 50 |
|
| $ | 43 |
|
| $ | 93 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 6 |
|
| $ | 77 |
|
| $ | 83 |
|
Interest rate |
|
| 321 |
|
|
| 1 |
|
|
| 322 |
|
Foreign currency |
|
| 3 |
|
|
| 0 |
|
|
| 3 |
|
Total current derivative liabilities(3) |
|
| 330 |
|
|
| 78 |
|
|
| 408 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| 1 |
|
|
| 47 |
|
|
| 48 |
|
Interest rate |
|
| 267 |
|
|
| 17 |
|
|
| 284 |
|
Total noncurrent derivative liabilities(4) |
|
| 268 |
|
|
| 64 |
|
|
| 332 |
|
Total derivative liabilities |
| $ | 598 |
|
| $ | 142 |
|
| $ | 740 |
|
(2) Virginia Power’s noncurrent derivative liabilities are presented in other deferred credits and other liabilities in its Consolidated Balance Sheets. 132
|
|
|
|
|
|
|
|
The following tables present the gains and losses on Dominion Energy’sthe Companies' derivatives, as well as where the associated activity is presented in itstheir Consolidated Balance Sheets and Statements of Income:
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||||||||||
Derivatives in cash flow |
| Amount of Gain |
|
| Amount of Gain |
|
| Increase (Decrease) |
|
| Amount of Gain |
|
| Amount of Gain |
|
| Increase (Decrease) |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Year Ended December 31, 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Interest rate(3) |
| $ | 89 |
|
| $ | (57 | ) |
| $ | 855 |
|
| $ | 80 |
|
| $ | (2 | ) |
| $ | 854 |
|
Total |
| $ | 89 |
|
| $ | (57 | ) |
| $ | 855 |
|
| $ | 80 |
|
| $ | (2 | ) |
| $ | 854 |
|
Year Ended December 31, 2021 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Commodity(4) |
|
|
|
| $ | (1 | ) |
|
|
|
|
|
|
|
|
|
|
|
| |||||
Interest rate(3) |
| $ | 21 |
|
|
| (60 | ) |
| $ | 135 |
|
| $ | 17 |
|
| $ | (3 | ) |
| $ | 130 |
|
Total |
| $ | 21 |
|
| $ | (61 | ) |
| $ | 135 |
|
| $ | 17 |
|
| $ | (3 | ) |
| $ | 130 |
|
Year Ended December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Operating revenue |
|
|
|
| $ | 25 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Purchased gas |
|
|
|
|
| (4 | ) |
|
|
|
|
|
|
|
|
|
|
|
| |||||
Discontinued |
|
|
|
|
| 2 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total commodity |
| $ | — |
|
| $ | 23 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
Interest rate: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Interest and |
|
|
|
| $ | (83 | ) |
|
|
|
| $ | (37 | ) |
| $ | (2 | ) |
| $ | (338 | ) | ||
Discontinued |
|
|
|
|
| (236 | ) |
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total interest rate |
| $ | (309 | ) |
| $ | (319 | ) |
| $ | (332 | ) |
| $ | (37 | ) |
| $ | (2 | ) |
| $ | (338 | ) |
Foreign currency |
|
| (11 | ) |
|
| (6 | ) |
|
| — |
|
|
|
|
|
|
|
|
| — |
| ||
Total |
| $ | (320 | ) |
| $ | (302 | ) |
| $ | (332 | ) |
| $ | (37 | ) |
| $ | (2 | ) |
| $ | (338 | ) |
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, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
| $ | 25 |
|
|
|
|
|
Purchased gas |
|
|
|
|
|
| (4 | ) |
|
|
|
|
Discontinued operations |
|
|
|
|
|
| 2 |
|
|
|
|
|
Total commodity |
| $ | 0 |
|
| $ | 23 |
|
| $ | 0 |
|
Interest rate: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest and related charges |
|
|
|
|
| $ | (83 | ) |
|
|
|
|
Discontinued operations |
|
|
|
|
|
| (236 | ) |
|
|
|
|
Total interest rate |
| $ | (309 | ) |
| $ | (319 | ) |
| $ | (332 | ) |
Foreign currency(3) |
|
| (11 | ) |
|
| (6 | ) |
|
| 0 |
|
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 |
|
| $ | 0 |
|
Interest rate: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest and related charges |
|
|
|
|
| $ | (49 | ) |
|
|
|
|
Discontinued operations |
|
|
|
|
|
| (5 | ) |
|
|
|
|
Total interest rate |
| $ | (252 | ) |
| $ | (54 | ) |
| $ | (255 | ) |
Foreign currency(3) |
|
| (18 | ) |
|
| (6 | ) |
|
| 0 |
|
Total |
| $ | (145 | ) |
| $ | 83 |
|
| $ | (255 | ) |
Year Ended December 31, 2018 |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
| $ | (82 | ) |
|
|
|
|
Electric fuel and other energy-related purchases |
|
|
|
|
|
| 14 |
|
|
|
|
|
Discontinued operations |
|
|
|
|
|
| (8 | ) |
|
|
|
|
Total commodity |
| $ | 64 |
|
| $ | (76 | ) |
| $ | — |
|
Interest rate: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest and related charges |
|
|
|
|
| $ | (43 | ) |
|
|
|
|
Discontinued operations |
|
|
|
|
|
| (5 | ) |
|
|
|
|
Total interest rate |
| $ | (18 | ) |
| $ | (48 | ) |
| $ | 39 |
|
Foreign currency(3) |
|
| (6 | ) |
|
| (13 | ) |
|
| 0 |
|
Total |
| $ | 40 |
|
| $ | (137 | ) |
| $ | 39 |
|
(2) |
|
| Represents net |
|
|
Derivatives not designated as hedging instruments |
| Amount of Gain (Loss) Recognized in Income on Derivatives(1) |
| |||||||||
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 73 |
|
| $ | 41 |
|
| $ | (11 | ) |
Purchased gas |
|
| (20 | ) |
|
| (22 | ) |
|
| 4 |
|
Electric fuel and other energy-related purchases |
|
| (104 | ) |
|
| (46 | ) |
|
| (9 | ) |
Discontinued operations |
|
| (11 | ) |
|
| (2 | ) |
|
| (10 | ) |
Interest rate: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest and related charges |
|
| 87 |
|
|
| 3 |
|
|
| 0 |
|
Discontinued operations |
|
| 5 |
|
|
| 0 |
|
|
| 0 |
|
Foreign currency: |
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations |
|
| 12 |
|
|
| 0 |
|
|
| 0 |
|
Total |
| $ | 42 |
|
| $ | (26 | ) |
| $ | (26 | ) |
|
|
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, 2020 |
|
| December 31, 2019 |
| ||||||||||||||||||||||||||
|
| 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 |
| $ | 111 |
|
| $ | 6 |
|
| $ | 0 |
|
| $ | 105 |
|
| $ | 19 |
|
| $ | 18 |
|
| $ | 0 |
|
| $ | 1 |
|
Exchange |
|
| 1 |
|
|
| 1 |
|
|
| 0 |
|
|
| 0 |
|
|
| — |
|
|
| 0 |
|
|
| 0 |
|
|
| — |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 66 |
|
|
| 7 |
|
|
| 0 |
|
|
| 59 |
|
|
| 2 |
|
|
| 0 |
|
|
| 0 |
|
|
| 2 |
|
Total derivatives, subject to a master netting or similar arrangement |
| $ | 178 |
|
| $ | 14 |
|
| $ | 0 |
|
| $ | 164 |
|
| $ | 21 |
|
| $ | 18 |
|
| $ | 0 |
|
| $ | 3 |
|
|
|
|
| December 31, 2020 |
|
| December 31, 2019 |
| ||||||||||||||||||||||||||
|
| 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 |
| $ | 6 |
|
| $ | 6 |
|
| $ | 0 |
|
| $ | 0 |
|
| $ | 59 |
|
| $ | 18 |
|
| $ | 0 |
|
| $ | 41 |
|
Exchange |
|
| 1 |
|
|
| 1 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 376 |
|
|
| 7 |
|
|
| 0 |
|
|
| 369 |
|
|
| 363 |
|
|
| 0 |
|
|
| 0 |
|
|
| 363 |
|
Total derivatives, subject to a master netting or similar arrangement |
| $ | 383 |
|
| $ | 14 |
|
| $ | 0 |
|
| $ | 369 |
|
| $ | 422 |
|
| $ | 18 |
|
| $ | 0 |
|
| $ | 404 |
|
|
|
Volumes
The following table presents the volume of Virginia Power’s derivative activity at December 31, 2020. These volumes are based on open derivative positionsdeferred into and represent the combined absolute valueamortized out of their long and short positions, exceptregulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in the caseCompanies' Consolidated Statements of offsetting transactions, for which they representIncome.
|
| Amount of Gain (Loss) Recognized in Income on Derivatives(1)(2) |
| |||||||||||||||||||||
Derivatives not designated as hedging instruments |
| Dominion Energy |
|
| Virginia Power |
| ||||||||||||||||||
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Operating revenue |
| $ | (721 | ) |
| $ | (487 | ) |
| $ | 73 |
|
| $ | (303 | ) |
| $ | (62 | ) |
| $ | (104 | ) |
Purchased gas |
|
| 13 |
|
|
| (1 | ) |
|
| (20 | ) |
|
|
|
|
|
|
|
|
| |||
Electric fuel and other energy-related purchases |
|
| 514 |
|
|
| 16 |
|
|
| (104 | ) |
|
| 453 |
|
|
| 9 |
|
|
| — |
|
Discontinued operations |
|
| — |
|
|
| — |
|
|
| (11 | ) |
|
|
|
|
|
|
|
|
| |||
Interest rate: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Interest and related charges |
|
| 650 |
|
|
| 97 |
|
|
| 87 |
|
|
|
|
|
|
|
|
|
| |||
Discontinued operations |
|
| — |
|
|
| — |
|
|
| 5 |
|
|
|
|
|
|
|
|
|
| |||
Foreign currency exchange rate: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Discontinued operations |
|
| — |
|
|
| — |
|
|
| 12 |
|
|
|
|
|
|
|
|
|
| |||
Total |
| $ | 456 |
|
| $ | (375 | ) |
| $ | 42 |
|
| $ | 150 |
|
| $ | (53 | ) |
| $ | (104 | ) |
133
|
| Current |
|
| Noncurrent |
| ||
Natural Gas (bcf): |
|
|
|
|
|
|
|
|
Fixed price(1) |
|
| 30 |
|
|
| — |
|
Basis |
|
| 134 |
|
|
| 473 |
|
Electricity (MWh): |
|
|
|
|
|
|
|
|
Fixed price |
|
| 928,560 |
|
|
| 350,400 |
|
FTRs |
|
| 45,249,553 |
|
|
| — |
|
Interest rate(2) |
| $ | 850,000,000 |
|
| $ | 1,200,000,000 |
|
|
|
|
|
AOCI
The following table presents selected information(2)
|
| AOCI After-Tax |
|
| Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax |
|
| Maximum Term | ||
(millions) |
|
|
|
|
|
|
|
|
|
|
Interest rate |
| $ | (60 | ) |
| $ | (2 | ) |
| 396 months |
Total |
| $ | (60 | ) |
| $ | (2 | ) |
|
|
The amountsforeign currency exchange rate derivatives that are deferred to plant under construction within property, plant and equipment and regulatory assets/liabilities that will be reclassified from AOCIbegin to earnings will generally be offset byamortize once the recognition of the hedged transactions (e.g., interest payments)CVOW Commercial Project is placed in earnings, thereby achieving the realization of interest rates contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in interest rates.
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets:
|
| Fair Value – Derivatives under Hedge Accounting |
|
| Fair Value – Derivatives not under Hedge Accounting |
|
| Total Fair Value |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 0 |
|
| $ | 22 |
|
| $ | 22 |
|
Total current derivative assets(1) |
|
| 0 |
|
|
| 22 |
|
|
| 22 |
|
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| 0 |
|
|
| 93 |
|
|
| 93 |
|
Interest rate |
|
| 66 |
|
|
| 0 |
|
|
| 66 |
|
Total noncurrent derivative assets(2) |
|
| 66 |
|
|
| 93 |
|
|
| 159 |
|
Total derivative assets |
| $ | 66 |
|
| $ | 115 |
|
| $ | 181 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 0 |
|
| $ | 28 |
|
| $ | 28 |
|
Interest rate |
|
| 362 |
|
|
| 0 |
|
|
| 362 |
|
Total current derivative liabilities |
|
| 362 |
|
|
| 28 |
|
|
| 390 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| 0 |
|
|
| 1 |
|
|
| 1 |
|
Interest rate |
|
| 14 |
|
|
| 0 |
|
|
| 14 |
|
Total noncurrent derivatives liabilities (3) |
|
| 14 |
|
|
| 1 |
|
|
| 15 |
|
Total derivative liabilities |
| $ | 376 |
|
| $ | 29 |
|
| $ | 405 |
|
At December 31, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 0 |
|
| $ | 20 |
|
| $ | 20 |
|
Interest rate |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
Total current derivative assets(1) |
|
| 0 |
|
|
| 20 |
|
|
| 20 |
|
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| 0 |
|
|
| 2 |
|
|
| 2 |
|
Interest rate |
|
| 2 |
|
|
| 0 |
|
|
| 2 |
|
Total noncurrent derivative assets(2) |
|
| 2 |
|
|
| 2 |
|
|
| 4 |
|
Total derivative assets |
| $ | 2 |
|
| $ | 22 |
|
| $ | 24 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 0 |
|
| $ | 58 |
|
| $ | 58 |
|
Interest rate |
|
| 185 |
|
|
| 0 |
|
|
| 185 |
|
Total current derivative liabilities |
|
| 185 |
|
|
| 58 |
|
|
| 243 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| 0 |
|
|
| 45 |
|
|
| 45 |
|
Interest rate |
|
| 178 |
|
|
| 0 |
|
|
| 178 |
|
Total noncurrent derivatives liabilities (3) |
|
| 178 |
|
|
| 45 |
|
|
| 223 |
|
Total derivative liabilities |
| $ | 363 |
|
| $ | 103 |
|
| $ | 466 |
|
|
|
|
|
|
|
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, 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 | ) |
Year Ended December 31, 2018 |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate(3) |
| $ | 2 |
|
| $ | (1 | ) |
| $ | 39 |
|
Total |
| $ | 2 |
|
| $ | (1 | ) |
| $ | 39 |
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments |
| Amount of Gain (Loss) Recognized in Income on Derivatives(1) |
| |||||||||
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity(2) |
| $ | (104 | ) |
| $ | (45 | ) |
| $ | 2 |
|
Total |
| $ | (104 | ) |
| $ | (45 | ) |
| $ | 2 |
|
|
|
|
|
NOTE 8. EARNINGS PER SHARE
The following table presents the calculation of Dominion Energy’s basic and diluted EPS:
|
| 2022 |
|
| 2021 |
|
| 2020 |
| |||
(millions, except EPS) |
|
|
|
|
|
|
|
|
| |||
Net income attributable to Dominion Energy from continuing operations |
| $ | 985 |
|
| $ | 2,647 |
|
| $ | 1,583 |
|
Preferred stock dividends (see Note 19) |
|
| (93 | ) |
|
| (68 | ) |
|
| (65 | ) |
Net income attributable to Dominion Energy from continuing operations - Basic |
|
| 892 |
|
|
| 2,579 |
|
|
| 1,518 |
|
Dilutive effect of 2019 Equity Units(1) |
|
| — |
|
|
| — |
|
|
| (11 | ) |
Net income attributable to Dominion Energy from continuing operations - Diluted |
| $ | 892 |
|
| $ | 2,579 |
|
| $ | 1,507 |
|
Net income (loss) attributable to Dominion Energy from discontinued operations - |
| $ | 9 |
|
| $ | 641 |
|
| $ | (1,984 | ) |
Average shares of common stock outstanding – Basic |
|
| 823.9 |
|
|
| 807.8 |
|
|
| 831.0 |
|
Net effect of dilutive securities(2) |
|
| 0.9 |
|
|
| 0.7 |
|
|
| — |
|
Average shares of common stock outstanding – Diluted |
|
| 824.8 |
|
|
| 808.5 |
|
|
| 831.0 |
|
EPS from continuing operations - Basic |
| $ | 1.08 |
|
| $ | 3.19 |
|
| $ | 1.83 |
|
EPS from discontinued operations - Basic |
|
| 0.01 |
|
|
| 0.79 |
|
|
| (2.39 | ) |
EPS attributable to Dominion Energy - Basic |
| $ | 1.09 |
|
| $ | 3.98 |
|
| $ | (0.56 | ) |
EPS from continuing operations - Diluted |
| $ | 1.08 |
|
| $ | 3.19 |
|
| $ | 1.82 |
|
EPS from discontinued operations - Diluted |
|
| 0.01 |
|
|
| 0.79 |
|
|
| (2.39 | ) |
EPS attributable to Dominion Energy - Diluted |
| $ | 1.09 |
|
| $ | 3.98 |
|
| $ | (0.57 | ) |
|
| 2020 |
|
| 2019 |
|
| 2018 |
| |||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Dominion Energy from continuing operations |
| $ | 1,583 |
|
| $ | 653 |
|
| $ | 2,087 |
|
Preferred stock dividends (see Note 19) |
|
| (65 | ) |
|
| (17 | ) |
|
| — |
|
Net income attributable to Dominion Energy from continuing operations - Basic |
|
| 1,518 |
|
|
| 636 |
|
|
| 2,087 |
|
Dilutive effect of Series A Preferred Stock |
|
| (11 | ) |
|
| (28 | ) |
|
| — |
|
Net income attributable to Dominion Energy from continuing operations - Diluted |
| $ | 1,507 |
|
| $ | 608 |
|
| $ | 2,087 |
|
Net income (loss) attributable to Dominion Energy from discontinued operations - Basic & Diluted |
| $ | (1,984 | ) |
| $ | 705 |
|
| $ | 360 |
|
Average shares of common stock outstanding – Basic |
|
| 831.0 |
|
|
| 808.8 |
|
|
| 654.2 |
|
Net effect of dilutive securities(1) |
|
| — |
|
|
| 0.1 |
|
|
| 0.7 |
|
Average shares of common stock outstanding – Diluted |
|
| 831.0 |
|
|
| 808.9 |
|
|
| 654.9 |
|
EPS from continuing operations - Basic |
| $ | 1.83 |
|
| $ | 0.79 |
|
| $ | 3.19 |
|
EPS from discontinued operations - Basic |
|
| (2.39 | ) |
|
| 0.87 |
|
|
| 0.55 |
|
EPS attributable to Dominion Energy - Basic |
| $ | (0.56 | ) |
| $ | 1.66 |
|
| $ | 3.74 |
|
EPS from continuing operations - Diluted |
|
| 1.82 |
|
| $ | 0.75 |
|
| $ | 3.19 |
|
EPS from discontinued operations - Diluted |
|
| (2.39 | ) |
|
| 0.87 |
|
|
| 0.55 |
|
EPS attributable to Dominion Energy - Diluted |
| $ | (0.57 | ) |
| $ | 1.62 |
|
| $ | 3.74 |
|
|
|
The 2019 Equity Units, the 2016 Equity Units, the Dominion Energy Midstream convertible preferred unitsprior to settlement in June 2022, and the Q-Pipe Transaction deposit, areprior to being settled in cash in July 2021, were potentially dilutive instruments. See Notes 3 18,and 19 and 20 for additional information. The
For the year ended December 31, 2022, the 2019 Equity Units, applying the if converted method as updated effective January 2022, for the period prior to settlement in June 2022, were excluded from the calculation of diluted earnings per share from continuing operations as the effects were anti-dilutive.
For the years ended December 31, 2021 and 2020, the forward stock purchase contracts included within the 2019 Equity Units were excluded from the calculation of diluted EPS from continuing operations for the years ended December 31, 2020 and 2019 as the dilutive stock price threshold was not met. ForThe Series A Preferred Stock included within the years2019 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 year ended December 31, 2020, based upon the expectation that the conversion would 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 was payable in cash, and 2019,any amount in excess of $1,000 per share could have been 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 dilutive EPS from continuing operations, but a fair value adjustment is reflected within net income from continuing operations attributable to Dominion Energy for the calculation of diluted EPS from continuing operations, based uponas such fair value adjustment was not dilutive during the expectation that the conversion will be settled in cash rather than through the issuance of Dominion Energy common stock. period.
The impact of settling the deposit associated with the Q-Pipe Transaction in shares is excluded from the calculation for the year endedyears 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 years ended December 31, 2019 and 2018 as the dilutive stock price threshold was not met. The Dominion Energy Midstream convertible preferred units were potentially dilutive securities but had no effect on the calculation of diluted EPS from continuing operations for the year ended December 31, 2018. In calculating diluted EPS from continuing operations in connection with the Dominion Energy Midstream convertible preferred units, Dominion Energy applied the if-converted method.common stock.
134
NOTE 9. INVESTMENTS
Dominion Energy
Equity and Debt Securities
Short-Term Deposit
In May 2022, Dominion Energy entered into an agreement with a financial institution and committed to make a short-term deposit of at least $1.6 billion but not more than $2.0 billion to be posted as collateral to secure its $1.6 billion redemption obligation of the Series A Preferred Stock as described in Note 19. In May 2022, Dominion Energy funded the short-term deposit in the amount of $2.0 billion, which earned interest income at an annual rate of 1.75% through its maturity in September 2022.
Rabbi Trust Securities
Equity and fixed income securities and cash equivalents in Dominion Energy’s rabbi trusts and classified as trading totaled $134$111 million and $120$122 million at December 31, 20202022 and 2019,2021, respectively.
135
Decommissioning Trust Securities
Dominion Energy holdsThe Companies hold equity and fixed income securities insurance contracts and cash equivalents, and Dominion Energy also holds insurance contracts, in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion Energy���sThe Companies' decommissioning trust funds are summarized below:
|
| Amortized Cost |
|
| Total Unrealized Gains |
|
| Total Unrealized Losses |
|
| Allowance for Credit Losses |
|
| Fair Value |
| |||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
December 31, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 1,807 |
|
| $ | 2,451 |
|
| $ | (20 | ) |
|
|
|
|
| $ | 4,238 |
|
Fixed income securities:(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
| 434 |
|
|
| 29 |
|
|
| 0 |
|
|
|
|
|
|
| 463 |
|
Government securities |
|
| 1,108 |
|
|
| 39 |
|
|
| (2 | ) |
|
|
|
|
|
| 1,145 |
|
Common/collective trust funds |
|
| 115 |
|
|
| 4 |
|
|
| — |
|
|
|
|
|
|
| 119 |
|
Insurance contracts |
|
| 214 |
|
|
| — |
|
|
| — |
|
|
|
|
|
|
| 214 |
|
Cash equivalents and other |
|
| 13 |
|
|
| 0 |
|
|
| 0 |
|
|
|
|
|
|
| 13 |
|
Total |
| $ | 3,691 |
|
| $ | 2,523 |
|
| $ | (22 | ) | (4) |
|
|
|
| $ | 6,192 |
|
|
|
| Dominion Energy |
|
|
|
| Virginia Power |
| ||||||||||||||||||||||||
| Amortized |
| Total |
| Total |
|
| Allowance for Credit Losses |
| Fair |
|
| Amortized |
| Total |
| Total |
|
| Allowance for Credit Losses |
| Fair |
| ||||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
December 31, 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Equity securities:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
U.S. | $ | 1,378 |
| $ | 2,501 |
| $ | (46 | ) |
|
|
| $ | 3,833 |
|
| $ | 858 |
| $ | 1,304 |
| $ | (35 | ) |
|
|
| $ | 2,127 |
| ||
Fixed income securities:(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Corporate debt |
| 640 |
|
| 1 |
|
| (65 | ) |
| $ | — |
|
| 576 |
|
|
| 406 |
|
| 1 |
|
| (47 | ) |
| $ | — |
|
| 360 |
|
Government |
| 1,252 |
|
| 4 |
|
| (70 | ) |
|
| — |
|
| 1,186 |
|
|
| 664 |
|
| 2 |
|
| (35 | ) |
|
| — |
|
| 631 |
|
Common/ |
| 98 |
|
| — |
|
| — |
|
|
| — |
|
| 98 |
|
|
| 61 |
|
| — |
|
| — |
|
|
| — |
|
| 61 |
|
Insurance contracts |
| 221 |
|
| — |
|
| — |
|
|
|
|
| 221 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Cash equivalents |
| 43 |
|
| — |
|
| — |
|
|
| — |
|
| 43 |
|
|
| 23 |
|
| — |
|
| — |
|
|
| — |
|
| 23 |
|
Total | $ | 3,632 |
| $ | 2,506 |
| $ | (181 | ) | (4) | $ | — |
| $ | 5,957 |
|
| $ | 2,012 |
| $ | 1,307 |
| $ | (117 | ) | (4) | $ | — |
| $ | 3,202 |
|
December 31, 2021 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Equity securities:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
U.S. | $ | 1,567 |
| $ | 3,734 |
| $ | (13 | ) |
|
|
| $ | 5,288 |
|
| $ | 841 |
| $ | 1,720 |
| $ | (11 | ) |
|
|
| $ | 2,550 |
| ||
Fixed income securities:(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Corporate debt |
| 854 |
|
| 32 |
|
| (5 | ) |
| $ | — |
|
| 881 |
|
|
| 517 |
|
| 17 |
|
| (3 | ) |
| $ | — |
|
| 531 |
|
Government |
| 1,382 |
|
| 43 |
|
| (7 | ) |
|
| — |
|
| 1,418 |
|
|
| 584 |
|
| 16 |
|
| (2 | ) |
|
| — |
|
| 598 |
|
Common/ |
| 168 |
|
| 4 |
|
| — |
|
|
| — |
|
| 172 |
|
|
| 53 |
|
| — |
|
| — |
|
|
| — |
|
| 53 |
|
Insurance contracts |
| 255 |
|
| — |
|
| — |
|
|
|
|
| 255 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Cash equivalents |
| 9 |
|
| 2 |
|
| (75 | ) |
|
| — |
|
| (64 | ) |
|
| 2 |
|
| — |
|
| — |
|
|
| — |
|
| 2 |
|
Total | $ | 4,235 |
| $ | 3,815 |
| $ | (100 | ) | (4) | $ | — |
| $ | 7,950 |
|
| $ | 1,997 |
| $ | 1,753 |
| $ | (16 | ) | (4) | $ | — |
| $ | 3,734 |
|
|
|
|
|
|
|
|
|
136
The portion of unrealized gains and losses that relates to equity securities held within Dominion Energy’sEnergy and Virginia Power's nuclear decommissioning trusts is summarized below:
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||||||
Year Ended December 31, |
| 2022 |
| 2021 |
| 2020 |
|
| 2022 |
| 2021 |
| 2020 |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Net gains (losses) recognized during the period |
| $ | (848 | ) | $ | 1,072 |
| $ | 512 |
|
| $ | (436 | ) | $ | 552 |
| $ | 224 |
|
Less: Net (gains) losses recognized during the |
|
| 8 |
|
| (346 | ) |
| (16 | ) |
|
| (7 | ) |
| (190 | ) |
| (6 | ) |
Unrealized gains (losses) recognized during the |
| $ | (840 | ) | $ | 726 |
| $ | 496 |
|
| $ | (443 | ) | $ | 362 |
| $ | 218 |
|
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Net gains (losses) recognized during the period |
| $ | 512 |
|
| $ | 919 |
|
| $ | (245 | ) |
Less: Net gains recognized during the period on securities sold during the period |
|
| (16 | ) |
|
| (80 | ) |
|
| (58 | ) |
Unrealized gains (losses) recognized during the period on securities still held at period end(1) |
| $ | 496 |
|
| $ | 839 |
|
| $ | (303 | ) |
|
|
The fair value of Dominion Energy’sEnergy and Virginia Power's fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 20202022 by contractual maturity is as follows:
|
| Dominion Energy |
|
| Virginia Power |
| ||
(millions) |
|
|
|
|
|
| ||
Due in one year or less |
| $ | 146 |
|
| $ | 80 |
|
Due after one year through five years |
|
| 511 |
|
|
| 280 |
|
Due after five years through ten years |
|
| 442 |
|
|
| 279 |
|
Due after ten years |
|
| 761 |
|
|
| 413 |
|
Total |
| $ | 1,860 |
|
| $ | 1,052 |
|
|
| Amount |
| |
(millions) |
|
|
|
|
Due in one year or less |
| $ | 227 |
|
Due after one year through five years |
|
| 506 |
|
Due after five years through ten years |
|
| 505 |
|
Due after ten years |
|
| 750 |
|
Total |
| $ | 1,988 |
|
Presented below is selected information regarding Dominion Energy’sEnergy and Virginia Power's equity and fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds.
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||||||||||
Year Ended December 31, |
| 2022 |
|
| 2021 |
|
| 2020 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Proceeds from sales |
| $ | 3,282 |
|
| $ | 3,985 |
|
| $ | 4,278 |
|
| $ | 1,538 |
|
| $ | 1,791 |
|
| $ | 884 |
|
Realized gains(1) |
|
| 143 |
|
|
| 441 |
|
|
| 340 |
|
|
| 48 |
|
|
| 228 |
|
|
| 88 |
|
Realized losses(1) |
|
| 296 |
|
|
| 91 |
|
|
| 297 |
|
|
| 107 |
|
|
| 35 |
|
|
| 68 |
|
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sales |
| $ | 4,278 |
|
| $ | 1,712 |
|
| $ | 1,804 |
|
Realized gains(1) |
|
| 340 |
|
|
| 195 |
|
|
| 140 |
|
Realized losses(1) |
|
| 297 |
|
|
| 96 |
|
|
| 91 |
|
| Includes realized gains and losses recorded to the |
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:regulatory liability as discussed in Note 2.
137
|
| Amortized Cost |
|
| Total Unrealized Gains |
|
| Total Unrealized Losses |
|
| Allowance for Credit Losses |
|
| Fair Value |
| |||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
| 0 |
|
|
| — |
|
|
| 509 |
|
Common/collective trust funds |
|
| 58 |
|
|
| — |
|
|
| — |
|
|
|
|
|
|
| 58 |
|
Cash equivalents and other |
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3 |
|
Total |
| $ | 1,789 |
|
| $ | 1,429 |
|
| $ | (21 | ) | (4) | $ | — |
|
| $ | 3,197 |
|
December 31, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 894 |
|
| $ | 1,144 |
|
| $ | (11 | ) |
|
|
|
|
| $ | 2,027 |
|
Fixed income securities:(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
| 241 |
|
|
| 15 |
|
|
| — |
|
|
|
|
|
|
| 256 |
|
Government securities |
|
| 534 |
|
|
| 14 |
|
|
| (2 | ) |
|
|
|
|
|
| 546 |
|
Common/collective trust funds |
|
| 51 |
|
|
| — |
|
|
| — |
|
|
|
|
|
|
| 51 |
|
Cash equivalents and other |
|
| 1 |
|
|
| — |
|
|
| — |
|
|
|
|
|
|
| 1 |
|
Total |
| $ | 1,721 |
|
| $ | 1,173 |
|
| $ | (13 | ) | (4) |
|
|
|
| $ | 2,881 |
|
|
|
|
|
|
|
|
|
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, |
| 2020 |
|
| 2019 |
|
| 2018 |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Net gains (losses) recognized during the period |
| $ | 224 |
|
| $ | 423 |
|
| $ | (105 | ) |
Less: Net gains recognized during the period on securities sold during the period |
|
| (6 | ) |
|
| (20 | ) |
|
| (32 | ) |
Unrealized gains (losses) recognized during the period on securities still held at end of period (1) |
| $ | 218 |
|
| $ | 403 |
|
| $ | (137 | ) |
|
|
The fair value of Virginia Power’s fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2020, by contractual maturity is as follows:
|
| Amount |
| |
(millions) |
|
|
|
|
Due in one year or less |
| $ | 79 |
|
Due after one year through five years |
|
| 238 |
|
Due after five years through ten years |
|
| 297 |
|
Due after ten years |
|
| 301 |
|
Total |
| $ | 915 |
|
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, |
| 2020 |
|
| 2019 |
|
| 2018 |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sales |
| $ | 884 |
|
| $ | 858 |
|
| $ | 887 |
|
Realized gains(1) |
|
| 88 |
|
|
| 58 |
|
|
| 60 |
|
Realized losses(1) |
|
| 68 |
|
|
| 22 |
|
|
| 27 |
|
|
|
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, |
|
|
|
| 2022 |
|
| 2021 |
|
|
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
| |||
Cove Point |
|
| 50 | % |
| $ | 2,673 |
|
| $ | 2,738 |
|
| LNG import/export and storage facility |
Atlantic Coast Pipeline |
|
| 53 | % |
|
| — |
| (3) |
| — |
| (3) | Gas transmission system |
Wrangler |
|
| — |
| (2) |
| — |
|
|
| 68 |
|
| Nonregulated retail energy marketing |
Align RNG(1) |
|
| 50 | % |
|
| 103 |
|
|
| 74 |
|
| Renewable natural gas |
Dominion Privatization |
|
| 50 | % |
|
| 176 |
|
|
| — |
|
| Military electric and gas |
Other |
| various |
|
|
| 60 |
|
|
| 52 |
|
|
| |
Total |
|
|
|
| $ | 3,012 |
|
| $ | 2,932 |
|
|
|
|
|
|
|
|
| Investment |
|
|
| |||||
Company |
| Ownership% |
|
| Balance |
|
| Description | ||||||
As of December 31, |
|
|
|
|
| 2020 |
|
| 2019 |
|
|
| ||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cove Point |
|
| 50 | % | (2) | $ | 2,784 |
|
| $ | 0 |
|
| LNG import/export and storage facility |
Atlantic Coast Pipeline |
|
| 53 | % | (3) |
| 0 |
| (5) |
| 1,123 |
|
| Gas transmission system |
Wrangler |
|
| 20 | % |
|
| 74 |
|
|
| 77 |
|
| Nonregulated retail energy marketing |
Fowler Ridge |
|
| 50 | % | (4) |
| 0 |
|
|
| 74 |
|
| Wind-powered nonregulated generation facility |
Other(1) |
| various |
|
|
| 76 |
|
|
| 60 |
|
|
| |
Total |
|
|
|
|
| $ | 2,934 |
|
| $ | 1,334 |
|
|
|
(2) Dominion Energy’s sold its remaining 15% ownership interest in March 2022, following a previous sale of 5% of its ownership interest in 2021. See discussion below. (3) Dominion Energy’s Consolidated Balance Sheets include a liability associated with its investment in Atlantic Coast Pipeline of $114 million and $113 million at December 31, 2022 and 2021, respectively, presented in other current liabilities. See discussion below for additional information.
|
|
|
|
|
|
|
|
|
|
Dominion Energy recorded equity earnings on its investments of $40$299 million, $8$276 million and $76$40 million infor the years ended December 31, 2022, 2021 and 2020, 2019, and 2018, respectively, in other income in its Consolidated Statements of Income. In addition, Dominion Energy recorded equity earnings (losses)losses of $(2.3) billion, $117$7 million, $20 million and $67 million in$2.3 billion for the years ended December 31, 2022, 2021 and 2020, 2019 and 2018, respectively, in discontinued operations related to its investment in Atlantic Coast Pipeline. Dominion Energy received distributions from these investments of $102$355 million, $38$328 million and $111$102 million infor the years ended December 31, 2022, 2021 and 2020, 2019, and 2018, respectively. As of December 31, 20202022 and 2019,2021, the net difference between the carrying amount of Dominion Energy’s investments and its share of underlying equity in net assets was $213$223 million and $(35)$244 million, respectively. At December 31, 2020,2022, these differences are comprised of $27$9 million of equity method goodwill that is not being amortized, $227$215 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 $(41)$(1) million basis difference primarily attributable to capitalized interest. 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, 2019 these differences are comprised of $11 million of equity method goodwill that is not being amortized and a net $(46) million basis difference from Dominion Energy’s investments in Fowler Ridge, Atlantic Coast Pipeline and an unfunded commitment made to Align RNG.
Cove Point
Prior to January 2019, Dominion Energy owned all of the common equity interest in Cove Point except for a preferred equity interest held by Dominion Energy Midstream (entitled to the first $50 million of annual cash distributions made by Cove Point), in which Dominion Energy owned a controlling financial interest and consolidated. As discussed in Note 20, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned by Dominion Energy in January 2019. In December 2019, Dominion Energy closed on an agreement to sell a 25% noncontrolling limited partnership interests in Cove Point. In November 2020, in conjunction with the GT&S Transaction, Dominion Energy sold 100%100% of its general partner interest and 25%25% of the total limited partner interest in Cove Point. Dominion Energy retained a 50%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.GT&S Transaction.
Income before income taxes recorded byfor 100% of Cove Point for the years ended December 31, 2022, 2021 and 2020 2019 and 2018 was $511$574 million, $471$528 million and $292$511 million, respectively. For the periods prior to closing of the GT&S Transaction, earnings attributable to Dominion Energy are presented in discontinued operations. Subsequent to the closing of the GT&S Transaction, through December 31,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$40 million are presented within other incomeearnings from equity method investees in its Consolidated Statements of Income.
Dominion Energy recorded distributions from Cove Point of $70$344 million, $300 million and 0$70 million for the years ended December 31, 2022, 2021 and 2020 (after the date of disposal), respectively. Dominion Energy made no contributions to Cove Point fromfor the years ended December 31, 2022, 2021 or 2020 (after the date of disposal through December 31, 2020.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-mile600
138
-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-year20-year contracts.
In March 2020, Dominion Energy completed the acquisition from Southern of its 5%5% membership interest in Atlantic Coast Pipeline and its 100%100% ownership interest in Pivotal LNG, Inc., for $184$184 million in aggregate, subject to certain purchase price adjustments. Pivotal LNG, Inc. includes a 50%50% noncontrolling interest in JAX LNG. Following completion of the acquisition, Dominion Energy owns a 53%53% noncontrolling membership interest in Atlantic Coast Pipeline with Duke Energy owning the remaining interest.
Atlantic Coast Pipeline continues to be reflectedaccounted 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 U.S. 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 U.S. Army Corps of Engineers of Atlantic Coast Pipeline’s Huntington District 404 verification and the U.S. Court of Appeals for the Fourth Circuit’s remand to the National Park Service of Atlantic Coast Pipeline’s Blue Ridge Parkway right-of-way. In June 2019, the Solicitor General of the U.S. and Atlantic Coast Pipeline filed petitions requesting that the Supreme Court of the U.S. hear the case regarding the Appalachian Trail crossing and in June 2020, the Supreme Court of the U.S. ruled in favor of the Atlantic Coast Pipeline, reversing the lower court’s decision and remanding the case back to the U.S. Court of Appeals for the Fourth Circuit.
The project also faced new and serious challenges from uncertainty related to NWP 12, specifically, from the decision of the U.S. District Court for the District of Montana in April 2020 vacating an NWP 12 issued by the U.S. Army Corps of Engineers, including among other things gas pipelines, followed by a U.S. Court of Appeals for the Ninth Circuit ruling in May 2020 denying a stay of that decision. In July 2020, the Supreme Court of the U.S. issued an order allowing other new oil and gas pipeline projects to use the NWP 12 process pending appeal to the U.S. Court of Appeals for the Ninth Circuit; however, that did not decrease the uncertainty associated with an eventual ruling. The Montana district court decision was viewed as likely to prompt similar challenges in other federal circuit courts related to permits issued under NWP 12, including for the Atlantic Coast Pipeline Project.
In July 2020, as a result of the continuedongoing 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.
AsDominion Energy recorded equity method 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, Dominion Energy recorded equity method earnings (losses) of $(2.3) billion ($(1.8) billion after-tax) for the year ended December 31, 2020, $117and $7 million ($1185 million after-tax) and $20 million ($14 million after-tax) for the yearyears ended December 31, 20192022 and $67 million ($67 million after-tax) for the year ended December 31, 2018.2021, 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, 2020 includes2022 and 2021 include a liability of $1.1 billion which reflects$114 million and $113 million, respectively, presented in other current liabilities and reflecting Dominion Energy’s obligations to Atlantic Coast Pipeline related to its credit facility and AROs.
In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under a $3.4$3.4 billion revolving credit facility with a stated maturity date of October 2021. Atlantic Coast Pipeline informed Dominion Energy it intends to terminate and repay the outstanding balance of the revolving credit facility in the first quarter of 2021. As of December 31, 2020, Atlantic Coast Pipeline had borrowed $1.8 billion against the revolving credit facility. In July 2020, the capacity of the revolving credit facility was reduced from $3.4$3.4 billion to $1.9$1.9 billion. In February 2021, Atlantic Coast Pipeline repaid the outstanding borrowed amounts and terminated its revolving credit facility. Concurrently, Dominion Energy’s Consolidated Balance Sheets include a liability of $6 million and $14 million associated with thisrelated guarantee agreement at December 31,to support its portion of the Atlantic Coast Pipeline’s borrowings was also terminated. In 2020, and 2019, respectively. The $1.1 billion liability at December 31, 2020 discussed above includesDominion Energy recorded a $48$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 thea new credit loss standard in January 2020.
Dominion Energy recorded contributions of $107$3 million, $186$965 million and $414$107 million during 2020, 2019the years ended December 31, 2022, 2021 and 2018,2020, respectively, to Atlantic Coast Pipeline. At December 31, 2019, Dominion Energy had $7 million of contributions payable to Atlantic Coast Pipeline included within other current liabilities in its Consolidated Balance Sheets.
139
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$49 million $103 million and $203 million induring the year ended December 31, 2020 (prior to closing of the GT&S Transaction), 2019 and 2018, respectively, included in discontinued operations in Dominion Energy’s Consolidated Statements of Income. Amounts receivable related to these services were $7 million at December 31, 2019, composed entirely of accrued unbilled revenue, included in current assets held for sale in Dominion Energy’s Consolidated Balance Sheets.
All activity relating to Atlantic Coast Pipeline is recorded within the Corporate and Other segment.
Blue Racer
In December 2018, Dominion Energy sold its 50% limited partnership interest in Blue Racer for up-front cash consideration of $1.05 billion and additional consideration of $150 million, subject to increase for interest costs effective March 2019, payable upon the purchaser’s availability of cash. The additional consideration was recorded at a fair value of $150 million on the date of sale following a discounted cash flow model and is included within other receivables in the Consolidated Balance Sheets at December 31, 2018. The valuation is considered a Level 3 fair value measurement due to the use of judgment and unobservable inputs, including projected timing and amount of future cash flows and a discount rate reflecting risks inherent in the future cash flows. As a result of the sale, Dominion Energy recognized a gain of $546 million ($390 million after-tax), included in other income in its Consolidated Statements of Income for the year ended December 31, 2018. In addition, the purchaser agreed to pay additional consideration contingent upon the achievement of certain financial performance milestones of Blue Racer from 2019 through 2021. Pursuant to the purchase agreement, the aggregate will not exceed $300 million, which represents a gain contingency, and, as a result, Dominion Energy will not recognize any additional gain unless such consideration is realizable. Blue Racer did not achieve the 2019 or 2020 financial performance milestones set forth in the sale agreement. In the first quarter of 2019, Dominion Energy received $151 million of additional consideration, including applicable interest, in connection with this sale.
All activity relating to Blue Racer is recorded within the Corporate and Other segment.
Fowler Ridge
In September 2020, Dominion Energy sold its 50%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$150 million. The $150$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$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
Wrangler
In September 2019, Dominion Energy entered into an agreement to form Wrangler, a partnership with Interstate Gas Supply, Inc. Wrangler will operateoperated 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 hashad a 20%15% noncontrolling ownership interest in Wrangler, which iswas accounted for as an equity method investment as Dominion Energy hashad the ability to exercise significant influence, but not control, over the investee.
TheAfter an initial contribution consisting of SEMI, closedassets to Wrangler in December 2019 for which Dominion Energy received $301cash and a 20% noncontrolling ownership interest in Wrangler, Dominion Energy completed a second contribution in November 2020, consisting of certain nonregulated natural gas retail energy contracts for which Dominion Energy received $74 million in cash proceeds and retained a 20%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 $75$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 $147$87 million, net of a $73$14 million write-off of goodwill, presented in gainslosses (gains) on sales of assets, and an associated tax expense of $82$32 million, in the Consolidated Statements of Income for the year ended December 31, 2019. 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. In March 2022, Dominion Energy sold its remaining 15% noncontrolling partnership interest in Wrangler to Interstate Gas Supply, Inc. for cash consideration of $85 million. Dominion Energy recognized a gain of $11 million ($8 million after-tax), included in other income, in its Consolidated Statements of Income for the year ended December 31, 2022.
All activity relating to Wrangler is recorded within the Corporate and Other segment.
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 would contribute its existing privatization operations, excluding contracts held by DESC, and Patriot would contribute cash.
140
The secondinitial contribution, consisting of certain nonregulated natural gas retail energy contracts,privatization operations in South Carolina, Texas and Pennsylvania, closed in November 2020March 2022 for which Dominion Energy received $74total consideration of $120 million, subject to customary closing adjustments, comprised of $60 million in cash proceeds and retained a 20%50% noncontrolling ownership interest through its ownership interest in Wrangler in the contracts valued at $13Dominion Privatization with an initial fair value of $60 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,first quarter of 2022, Dominion Energy recorded a gain of $64$23 million ($16 million after-tax), presented in gainslosses (gains) on sales of assets and an associated tax expense of $19 million, in theits Consolidated Statements of Income for the year ended December 31, 2020.Income. Dominion Energy’s Consolidated Balance Sheets at December 31, 2019 included $41 million presented in current assets held for sale.
In 2021, under the terms of the agreement, Dominion Energy expects to contribute its remaining nonregulated natural gas retail energy marketing operations to Wrangler. As a result of this contribution, Dominion Energy will receive additional cash consideration which will be based upon future financial performance. When this future contribution occurs, Dominion Energy expects to retain a 20%50% noncontrolling ownership interest in Wrangler.Dominion Privatization is accounted for as an equity method investment as Dominion Energy has the ability to exercise significant influence, but not control, over the investee.
AsThe second contribution, consisting of privatization operations in Virginia, closed in December 31, 2020, $632022 for which Dominion Energy received total consideration of $215 million, subject to customary closing adjustments, comprised of $108 million in cash proceeds and retention of its 50% noncontrolling ownership interest valued at $107 million using the market approach. This is considered a Level 2 fair value measurement given that it is based on the agreed-upon sales price. In the fourth quarter of 2022, Dominion Energy recorded a gain of $133 million ($99 million after-tax), presented in losses (gains) on sales of assets and $15 millionin its Consolidated Statements of liabilities associated with the remaining nonregulated retail energy marketing operations to be contributed to Wrangler in December 2021 were classified as held for sale and were included in current assets held for sale and current liabilities held for sale on Dominion Energy’s Consolidated Balance Sheets, respectively. The related disposal group is primarily comprised of customer receivables, goodwill, inventories, and account payables.Income.
All activity relatingrelated to WranglerDominion Privatization is recordedreflected within the Corporate and Other segment.
Other- Catalyst Old River Hydroelectric Limited Partnership
In September 2018, Dominion Energy completed the sale of its 25% limited partnership interest in Catalyst Old River Hydroelectric Limited Partnership and received proceeds of $91 million. The sale resulted in a gain of $87 million ($63 million after-tax), which is included in other income in Dominion Energy’s Consolidated Statements of Income, reflected in the Corporate and Other segment.
NOTE 10. PROPERTY, PLANT AND EQUIPMENT
Major classes of property, plant and equipment and their respective balances for the Companies are as follows:
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||||||||||
At December 31, |
| 2020 |
|
| 2019 |
|
| 2022 |
|
| 2021 |
|
| 2022 |
|
| 2021 |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Utility: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Generation |
| $ | 22,697 |
|
| $ | 25,317 |
|
| $ | 23,720 |
|
| $ | 23,378 |
|
| $ | 17,611 |
|
| $ | 17,325 |
|
Transmission |
|
| 14,351 |
|
|
| 13,472 |
|
|
| 16,857 |
|
|
| 15,430 |
|
|
| 13,034 |
|
|
| 11,760 |
|
Distribution |
|
| 27,311 |
|
|
| 25,746 |
|
|
| 30,624 |
|
|
| 28,953 |
|
|
| 14,681 |
|
|
| 13,621 |
|
Storage |
|
| 436 |
|
|
| 428 |
|
|
| 491 |
|
|
| 455 |
|
|
| — |
|
|
| — |
|
Nuclear fuel |
|
| 2,283 |
|
|
| 2,296 |
|
|
| 2,373 |
|
|
| 2,306 |
|
|
| 1,823 |
|
|
| 1,702 |
|
General and other |
|
| 4,130 |
|
|
| 3,978 |
|
|
| 4,630 |
|
|
| 4,373 |
|
|
| 1,019 |
|
|
| 912 |
|
Plant under construction |
|
| 3,350 |
|
|
| 2,377 |
|
|
| 5,678 |
|
|
| 3,898 |
|
|
| 4,685 |
|
|
| 2,865 |
|
Total utility |
|
| 74,558 |
|
|
| 73,614 |
|
|
| 84,373 |
|
|
| 78,793 |
|
|
| 52,853 |
|
|
| 48,185 |
|
Non-jurisdictional - including plant under construction |
|
| 1,225 |
|
|
| 854 |
|
|
| 1,834 |
|
|
| 1,694 |
|
|
| 1,834 |
|
|
| 1,694 |
|
Nonutility: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Nonregulated generation-nuclear |
|
| 1,736 |
|
|
| 1,652 |
|
|
| 1,935 |
|
|
| 1,773 |
|
|
| — |
|
|
| — |
|
Nonregulated generation-other |
|
| 3,268 |
|
|
| 3,985 |
| ||||||||||||||||
Nonregulated generation-solar |
|
| 495 |
|
|
| 2,026 |
|
|
| — |
|
|
| — |
| ||||||||
Nuclear fuel |
|
| 1,012 |
|
|
| 930 |
|
|
| 954 |
|
|
| 1,056 |
|
|
| — |
|
|
| — |
|
Other-including plant under construction |
|
| 1,160 |
|
|
| 1,008 |
|
|
| 1,611 |
|
|
| 1,161 |
|
|
| 10 |
|
|
| 11 |
|
Total nonutility |
|
| 7,176 |
|
|
| 7,575 |
|
|
| 4,995 |
|
|
| 6,016 |
|
|
| 10 |
|
|
| 11 |
|
Total property, plant and equipment |
| $ | 82,959 |
|
| $ | 82,043 |
|
| $ | 91,202 |
|
| $ | 86,503 |
|
| $ | 54,697 |
|
| $ | 49,890 |
|
Virginia Power |
|
|
|
|
|
|
|
| ||||||||||||||||
Utility: |
|
|
|
|
|
|
|
| ||||||||||||||||
Generation |
| $ | 16,769 |
|
| $ | 19,552 |
| ||||||||||||||||
Transmission |
|
| 11,000 |
|
|
| 10,229 |
| ||||||||||||||||
Distribution |
|
| 12,839 |
|
|
| 12,095 |
| ||||||||||||||||
Nuclear fuel |
|
| 1,709 |
|
|
| 1,688 |
| ||||||||||||||||
General and other |
|
| 845 |
|
|
| 825 |
| ||||||||||||||||
Plant under construction |
|
| 2,338 |
|
|
| 1,784 |
| ||||||||||||||||
Total utility |
|
| 45,500 |
|
|
| 46,173 |
| ||||||||||||||||
Non-jurisdictional - including plant under construction |
|
| 1,225 |
|
|
| 854 |
| ||||||||||||||||
Other |
|
| 11 |
|
|
| 11 |
| ||||||||||||||||
Total property, plant and equipment |
| $ | 46,736 |
|
| $ | 47,038 |
|
Jointly-Owned Power Stations
The Companies proportionate share of jointly-owned power stations at December 31, 20202022 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 |
|
| 1,066 |
|
|
| 2,540 |
|
|
| 611 |
|
|
| 1,487 |
|
|
| 1,532 |
|
Accumulated depreciation |
|
| (730 | ) |
|
| (1,402 | ) |
|
| (282 | ) |
|
| (563 | ) |
|
| (724 | ) |
Nuclear fuel |
|
| — |
|
|
| 792 |
|
|
| — |
|
|
| 551 |
|
|
| 550 |
|
Accumulated amortization of nuclear fuel |
|
| — |
|
|
| (602 | ) |
|
| — |
|
|
| (459 | ) |
|
| (347 | ) |
Plant under construction |
|
| 3 |
|
|
| 253 |
|
|
| — |
|
|
| 68 |
|
|
| 87 |
|
|
| 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 |
|
| 1,064 |
|
|
| 2,587 |
|
|
| 609 |
|
|
| 1,292 |
|
|
| 1,519 |
|
Accumulated depreciation |
|
| (688 | ) |
|
| (1,359 | ) |
|
| (260 | ) |
|
| (482 | ) |
|
| (676 | ) |
Nuclear fuel |
|
| — |
|
|
| 793 |
|
|
| — |
|
|
| 573 |
|
|
| 575 |
|
Accumulated amortization of nuclear fuel |
|
| — |
|
|
| (661 | ) |
|
| — |
|
|
| (444 | ) |
|
| (354 | ) |
Plant under construction |
|
| 3 |
|
|
| 158 |
|
|
| 1 |
|
|
| 78 |
|
|
| 61 |
|
141
|
|
|
|
The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. The Companies report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes, etc.) in the Consolidated Statements of Income.
Sale of Certain Retail Energy Marketing Assets
In October 2017, Dominion Energy entered into an agreement to sell certain assets associated with its nonregulated retail energy marketing operations. The first phase of the agreement closed in December 2017. Dominion Energy closed the second phase of the agreement in October 2018 for $63 million, which resulted in the recognition of a $65 million ($49 million after-tax) benefit included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. Pursuant to the agreement, Dominion Energy entered into a commission agreement with the buyer upon the first closing in December 2017 under which the buyer will pay a commission in connection with the right to use Dominion Energy’s brand in marketing materials and other services over a ten-year term.
Sale of Certain Nonregulated Generation Facilities
In December 2018, Dominion Energy completed the sale of Fairless and Manchester for total consideration of $1.2 billion, subject to customary closing adjustments. Dominion Energy recognized a gain of $210 million ($198 million after-tax) included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. The after-tax gain reflects Dominion Energy’s assessment and more-likely-than-not conclusion that the utilization of state tax incentives will reduce the income tax expense associated with the sale of these facilities.
Acquisition of Solar Projects
The following table presents acquisitions by Virginia Power of non-jurisdictional solar projects.projects (reflected in Dominion Energy Virginia). Virginia Power has claimed or expects to claim federal investment tax credits on the projects.projects, except as otherwise noted.
Project Name |
| Date Agreement |
| Date Agreement |
| Project Location |
| Project Cost |
|
| Date of Commercial |
| MW Capacity |
| ||
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 |
|
| 210 |
|
| December 2022 |
|
| 120 |
|
Rochambeau |
| December 2019 |
| January 2020 |
| Virginia |
|
| 35 |
|
| December 2021 |
|
| 20 |
|
Pumpkinseed |
| May 2020 |
| May 2020 |
| Virginia |
|
| 138 |
|
| September 2022 |
|
| 60 |
|
Bookers Mill |
| February 2021 |
| June 2021 |
| Virginia |
|
| 225 |
|
| Expected 2023(4) |
|
| 127 |
|
Date Agreement Entered |
| Date Agreement Closed | Project Location |
| Project Name |
| Project Cost (millions)(1) |
|
| Date of Commercial Operations |
| MW Capacity |
| ||
September 2017 |
| October 2018 | North Carolina |
| Pecan |
| $ | 140 |
|
| December 2018 |
|
| 75 |
|
September 2017 |
| June 2019 | North Carolina |
| Gutenberg |
|
| 142 |
|
| September 2019 |
|
| 80 |
|
June 2018 |
| February 2019 | Virginia |
| Gloucester |
|
| 37 |
|
| April 2019 |
|
| 20 |
|
August 2018 |
| May 2019 | Virginia |
| Grasshopper |
|
| 128 |
|
| October 2020 |
|
| 80 |
|
August 2018 |
| May 2019 | North Carolina |
| Chestnut |
|
| 127 |
|
| January 2020 |
|
| 75 |
|
June 2019 |
| June 2019 | Virginia |
| Ft. Powhatan |
|
| 270 |
|
| Expected 2021 |
|
| 150 |
|
June 2019 |
| August 2019 | Virginia |
| Belcher |
|
| 165 |
|
| Expected 2021 |
|
| 88 |
|
August 2019 |
| November 2019 | Virginia |
| Bedford |
|
| 110 |
|
| Expected 2021 |
|
| 70 |
|
October 2019 |
| October 2019 | Virginia |
| Maplewood |
|
| 185 |
|
| Expected 2022 |
|
| 120 |
|
December 2019 |
| January 2020 | Virginia |
| Rochambeau |
|
| 35 |
|
| Expected 2021 |
|
| 20 |
|
May 2020 |
| May 2020 | Virginia |
| Pumpkinseed |
|
| 130 |
|
| Expected 2022 |
|
| 60 |
|
(1)
TheIn addition, the following table presents acquisitions by Dominion Energy of solar projects.projects (reflected in Contracted Assets). Dominion Energy has claimed or expects to claim federal investment tax credits on the projects.projects, except as otherwise noted.
Project Name |
| Date Agreement |
| Date Agreement |
| Project Location |
| Project Cost |
|
| Date of Commercial |
| MW Capacity |
| ||
Greensville |
| August 2019 |
| August 2019 |
| Virginia |
| $ | 127 |
|
| December 2020 |
|
| 80 |
|
Myrtle |
| August 2019 |
| August 2019 |
| Virginia |
|
| 32 |
|
| June 2020 |
|
| 15 |
|
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 |
|
| 165 |
|
| Expected 2024(3) |
|
| 62 |
|
Hardin II |
| August 2020 |
| Terminated(4) |
|
|
|
|
|
|
|
|
|
| ||
Atlanta Farms |
| March 2022 |
| May 2022 |
| Ohio |
|
| 390 |
|
| Expected split(3)(5) |
|
| 200 |
|
Date Agreement Entered |
| Date Agreement Closed | Project Location |
| Project Name |
| Project Cost (millions)(1) |
|
| Date of Commercial Operations |
| MW Capacity |
| ||
August 2019 |
| August 2019 | Virginia |
| Greensville |
| $ | 127 |
|
| December 2020 |
|
| 80 |
|
August 2019 |
| August 2019 | Virginia |
| Myrtle |
|
| 32 |
|
| June 2020 |
|
| 15 |
|
September 2019 |
| September 2019 | South Carolina |
| Seabrook |
|
| 103 |
|
| December 2019 |
|
| 72 |
|
November 2019 |
| November 2019 | North Carolina |
| Wilkinson |
|
| 153 |
|
| December 2019 |
|
| 74 |
|
May 2020 |
| May 2020 | South Carolina |
| Blackville |
|
| 12 |
|
| December 2020 |
|
| 7 |
|
May 2020 |
| May 2020 | South Carolina |
| Denmark |
|
| 14 |
|
| December 2020 |
|
| 6 |
|
May 2020 |
| August 2020 | South Carolina |
| Yemassee |
|
| 17 |
|
| January 2021 |
|
| 10 |
|
May 2020 |
| October 2020 | South Carolina |
| Trask |
|
| 25 |
|
| Expected 2021 |
|
| 12 |
|
June 2020 |
| June 2020 | Ohio |
| Hardin I |
|
| 240 |
|
| Split(2) |
|
| 150 |
|
July 2020 |
| July 2020 | Virginia |
| Madison |
|
| 125 |
|
| Expected 2022 |
|
| 62 |
|
August 2020 |
| Expected 2022 | Ohio |
| Hardin II |
|
| 295 |
|
| Expected 2023 |
|
| 150 |
|
(1)
In addition to the facilities discussed above, Dominion Energy has also entered into various agreements to install solar facilities (reflected in Dominion Energy Virginia), primarily at schools in Virginia, with in-service dates in 2020 or 2021. Through February 2021,Virginia. As of December 31, 2022, Dominion Energy had placed in service solar facilities with an aggregate generation capacity of 23 MW at a cost of $48 million and anticipates aplacing additional facilities in service by the end of 2023 with an estimated total projected cost of approximately $61$39 million under these agreements withand an associated aggregate generation capacity of 3017 MW. Dominion Energy has claimed or expects to claim federal investment tax credits on the projects.
Impairment
AcquisitionIn the fourth quarter of Gathering2022, Dominion Energy modified its intentions for the ongoing growth and Processingdevelopment of its nonregulated solar generation assets as part of the preliminary stages of its comprehensive business review announced in November 2022. In connection with that determination, Dominion Energy expects that it is more likely than not that the nonregulated solar generation projects within Contracted Assets will be sold before the end of their useful lives and therefore evaluated the associated long-lived assets for recoverability. Given their strategic alignment with Virginia Power’s operations, the non-jurisdictional solar generation projects reflected in Dominion Energy Virginia were not further evaluated for recoverability. Using a probability-weighted approach,
In March 2020, Wexpro closed on142
Dominion Energy determined Contracted Assets’ nonregulated solar generation assets were impaired and recorded a charge of $1.5 billion ($1.1 billion after-tax) 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, 2022 to adjust the property, plant and equipment, intangible assets and right-of-use lease assets down to an agreement withestimated fair value of $665 million in aggregate. The fair value was estimated using an income approach. The valuation is considered a natural gas gathering systems operatorLevel 3 fair value measurement due to purchase existing natural gas gathering systemsthe use of significant judgmental and unobservable inputs, including pipelines, compressorsprojected timing and dehydration equipment for total considerationamount of $38 million. These facilities gather natural gasfuture cash flows and discount rates reflecting risks inherent in Colorado, Utahthe future cash flows and Wyoming.market prices.
Non-Wholly-Owned Nonregulated Solar Facilities
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 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$665 million ($293 million after-tax attributable to Dominion Energy and $267$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$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.
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.
Acquisition of Gathering and Processing Assets
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.
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.
Sale of Utility Property
In 2022, Dominion Energy completed the sales of certain utility property in South Carolina, as approved by the South Carolina Commission, for total cash consideration of $20 million. In connection with the sales, Dominion Energy recognized a gain of $20 million ($15 million after-tax), recorded in losses (gains) on sales of assets, in its Consolidated Statements of Income (reflected in Dominion Energy South Carolina) for the year ended December 31, 2022.
143
NOTE 11. GOODWILL AND INTANGIBLE ASSETS
Goodwill
In September 2020, Dominion Energy updated its operating segments following the July 2020 agreement to sell its gas transmission and storage operations to BHE. See Note 3 for information on the goodwill recast to held for sale associated with the GT&S Transaction and Q-Pipe Transaction. In addition, goodwill associated with Dominion Energy’s nonregulated retail energy marketing operations was reassigned to the Corporate and Other segment using a relative fair value allocation approach with the historical information recast herein. The changes in Dominion Energy’s carrying amount and segment allocation of goodwill are presented below:
|
| Dominion Energy Virginia |
|
| Gas Distribution |
|
| Dominion Energy South Carolina |
|
| Contracted Assets |
|
| Corporate and Other |
|
| Total |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Balance at December 31, 2020(1) |
| $ | 2,106 |
|
| $ | 3,512 |
|
| $ | 1,521 |
|
| $ | 242 |
|
| $ | — |
|
| $ | 7,381 |
|
Acquisition of Birdseye(2) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 24 |
|
|
| — |
|
|
| 24 |
|
Balance at December 31, 2021(1) |
| $ | 2,106 |
|
| $ | 3,512 |
|
| $ | 1,521 |
|
| $ | 266 |
|
| $ | — |
|
| $ | 7,405 |
|
Sale of Hope(2) |
|
| — |
|
|
| (110 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (110 | ) |
Balance at December 31, 2022(1) |
| $ | 2,106 |
|
| $ | 3,402 |
|
| $ | 1,521 |
|
| $ | 266 |
|
| $ | — |
|
| $ | 7,295 |
|
|
| Dominion Energy Virginia |
|
| Gas Distribution |
|
| Dominion Energy South Carolina |
|
| Contracted Assets |
|
| Corporate and Other |
| Total |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2018(1) |
| $ | 2,106 |
|
| $ | 2,497 |
|
| $ | — |
|
| $ | 242 |
|
| $ | 14 |
| $ | 4,859 |
|
SCANA Combination (2) |
|
| — |
|
|
| 1,015 |
|
|
| 1,521 |
|
|
| — |
|
|
| 73 |
|
| 2,609 |
|
Contribution of SEMI to Wrangler(3) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (73 | ) |
| (73 | ) |
Balance at December 31, 2019(1) |
| $ | 2,106 |
|
| $ | 3,512 |
|
| $ | 1,521 |
|
| $ | 242 |
|
| $ | 14 |
| $ | 7,395 |
|
Contribution to Wrangler(3) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (14 | ) |
| (14 | ) |
Balance at December 31, 2020(1) |
| $ | 2,106 |
|
| $ | 3,512 |
|
| $ | 1,521 |
|
| $ | 242 |
|
| $ | — |
| $ | 7,381 |
|
(1)
(3) See Note 9 for additional information including amounts reclassified to held for sale at December 31, 2020.
Other Intangible Assets
The Companies’ other intangible assets are subject to amortization over their estimated useful lives. Dominion Energy’s amortization expense for intangible assets was $69$115 million, $95$79 million and $72$69 million for 2020, 2019the years ended December 31, 2022, 2021 and 2018,2020, respectively. In 2020,2022, Dominion Energy acquired $152$488 million of intangible assets, primarily representing softwareRGGI allowances and right-of-use assets,software, with an estimated weighted-average amortization period of approximately 11 years.3 years. Amortization expense for Virginia Power’s intangible assets was $28$67 million, $30$31 million and $31$28 million for 2020, 2019the years ended December 31, 2022, 2021 and 2018,2020, respectively. In 2020,2022, Virginia Power acquired $95$430 million of intangible assets, primarily representing RGGI allowances and software, with an estimated weighted-average amortization period of 11 years.2 years.
The components of intangible assets are as follows:
|
| 2022 |
|
| 2021 |
| ||||||||||
At December 31, |
| Gross Carrying Amount |
|
| Accumulated Amortization |
|
| Gross Carrying Amount |
|
| Accumulated Amortization |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Software, licenses and other(1) |
| $ | 1,854 |
|
| $ | 986 |
|
| $ | 1,459 |
|
| $ | 675 |
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Software, licenses and other(1) |
| $ | 1,113 |
|
| $ | 577 |
|
| $ | 685 |
|
| $ | 290 |
|
|
| 2020 |
|
| 2019 |
| ||||||||||
At December 31, |
| Gross Carrying Amount |
|
| Accumulated Amortization |
|
| Gross Carrying Amount |
|
| Accumulated Amortization |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Software, licenses and other |
| $ | 1,295 |
|
| $ | 530 |
|
| $ | 1,162 |
|
| $ | 477 |
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Software, licenses and other |
| $ | 482 |
|
| $ | 148 |
|
| $ | 406 |
|
| $ | 135 |
|
Annual amortization expense for these intangible assets is estimated to be as follows:
|
| 2021 |
| 2022 |
| 2023 |
| 2024 |
| 2025 |
|
|
| 2023 |
|
| 2024 |
|
| 2025 |
|
| 2026 |
|
| 2027 |
| |||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Dominion Energy |
| $ | 77 |
| $ | 56 |
| $ | 42 |
| $ | 34 |
| $ | 26 |
|
| $ | 74 |
| $ | 67 |
| $ | 59 |
| $ | 47 |
| $ | 29 |
|
Virginia Power |
| $ | 32 |
| $ | 18 |
| $ | 12 |
| $ | 9 |
| $ | 6 |
|
| $ | 33 |
| $ | 30 |
| $ | 26 |
| $ | 20 |
| $ | 10 |
|
144
NOTE 12. REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities include the following:
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||
At December 31, |
| 2022 |
|
| 2021 |
|
| 2022 |
|
| 2021 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Regulatory assets: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Deferred cost of fuel used in electric generation(1) |
| $ | 603 |
|
| $ | 251 |
|
| $ | 133 |
|
| $ | 131 |
|
Deferred project costs and DSM programs for gas utilities(2) |
|
| 68 |
|
|
| 53 |
|
|
|
|
|
|
| ||
Unrecovered gas costs(3) |
|
| 374 |
|
|
| 191 |
|
|
|
|
|
|
| ||
Deferred rider costs for Virginia electric utility(4) |
|
| 152 |
|
|
| 72 |
|
|
| 152 |
|
|
| 72 |
|
Ashpond and landfill closure costs(5) |
|
| 221 |
|
|
| 193 |
|
|
| 221 |
|
|
| 193 |
|
Deferred nuclear refueling outage costs(6) |
|
| 83 |
|
|
| 79 |
|
|
| 83 |
|
|
| 79 |
|
NND Project costs(7) |
|
| 138 |
|
|
| 138 |
|
|
|
|
|
|
| ||
Deferred early plant retirement charges(8) |
|
| 226 |
|
|
| 226 |
|
|
| 226 |
|
|
| 226 |
|
Derivatives(9) |
|
| 262 |
|
|
| 112 |
|
|
| 251 |
|
|
| 105 |
|
Other |
|
| 213 |
|
|
| 177 |
|
|
| 74 |
|
|
| 44 |
|
Regulatory assets-current |
|
| 2,340 |
|
|
| 1,492 |
|
|
| 1,140 |
|
|
| 850 |
|
Unrecognized pension and other postretirement benefit costs(10) |
|
| 989 |
|
|
| 548 |
|
|
| 4 |
|
|
| 3 |
|
Deferred rider costs for Virginia electric utility(4) |
|
| 363 |
|
|
| 489 |
|
|
| 363 |
|
|
| 489 |
|
Deferred project costs for gas utilities(2) |
|
| 703 |
|
|
| 675 |
|
|
|
|
|
|
| ||
Interest rate hedges(11) |
|
| 169 |
|
|
| 899 |
|
|
| — |
|
|
| 604 |
|
AROs and related funding(12) |
|
| 398 |
|
|
| 329 |
|
|
|
|
|
|
| ||
NND Project costs(7) |
|
| 2,088 |
|
|
| 2,226 |
|
|
|
|
|
|
| ||
Ash pond and landfill closure costs(5) |
|
| 2,051 |
|
|
| 2,223 |
|
|
| 2,049 |
|
|
| 2,223 |
|
Deferred cost of fuel used in electric generation(1) |
|
| 1,551 |
|
|
| 409 |
|
|
| 1,551 |
|
|
| 409 |
|
Deferred early plant retirement charges(8) |
|
| — |
|
|
| 226 |
|
|
| — |
|
|
| 226 |
|
Derivatives(9) |
|
| 255 |
|
|
| 35 |
|
|
| 148 |
|
|
| 34 |
|
Other |
|
| 520 |
|
|
| 584 |
|
|
| 132 |
|
|
| 142 |
|
Regulatory assets-noncurrent |
|
| 9,087 |
|
|
| 8,643 |
|
|
| 4,247 |
|
|
| 4,130 |
|
Total regulatory assets |
| $ | 11,427 |
|
| $ | 10,135 |
|
| $ | 5,387 |
|
| $ | 4,980 |
|
Regulatory liabilities: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Provision for future cost of removal and AROs(13) |
|
| 127 |
|
|
| 181 |
|
|
| 111 |
|
|
| 154 |
|
Reserve for refunds and rate credits to electric utility |
|
| 125 |
|
|
| 420 |
|
|
| 25 |
|
|
| 306 |
|
Income taxes refundable through future rates(15) |
|
| 152 |
|
|
| 153 |
|
|
| 65 |
|
|
| 63 |
|
Monetization of guarantee settlement(16) |
|
| 67 |
|
|
| 67 |
|
|
|
|
|
|
| ||
Derivatives(9) |
|
| 327 |
|
|
| 69 |
|
|
| 176 |
|
|
| 51 |
|
Other |
|
| 148 |
|
|
| 96 |
|
|
| 129 |
|
|
| 73 |
|
Regulatory liabilities-current |
|
| 946 |
|
|
| 986 |
|
|
| 506 |
|
|
| 647 |
|
Income taxes refundable through future rates(15) |
|
| 4,054 |
|
|
| 4,260 |
|
|
| 2,272 |
|
|
| 2,335 |
|
Provision for future cost of removal and AROs(13) |
|
| 2,510 |
|
|
| 2,331 |
|
|
| 1,135 |
|
|
| 1,043 |
|
Nuclear decommissioning trust(17) |
|
| 1,685 |
|
|
| 2,158 |
|
|
| 1,685 |
|
|
| 2,158 |
|
Monetization of guarantee settlement(16) |
|
| 702 |
|
|
| 831 |
|
|
|
|
|
|
| ||
Interest rate hedges(11) |
|
| 240 |
|
|
| — |
|
|
| 240 |
|
|
| — |
|
Reserve for refunds and rate credits to electric utility |
|
| 325 |
|
|
| 448 |
|
|
| — |
|
|
| 25 |
|
Unrecognized pension and other postretirement benefit costs(10) |
|
| 22 |
|
|
| 200 |
|
|
|
|
|
|
| ||
Overrecovered other postretirement benefit costs(18) |
|
| 140 |
|
|
| 105 |
|
|
|
|
|
|
| ||
Derivatives(9) |
|
| 235 |
|
|
| 236 |
|
|
| — |
|
|
| 62 |
|
Other |
|
| 194 |
|
|
| 144 |
|
|
| 167 |
|
|
| 117 |
|
Regulatory liabilities-noncurrent |
|
| 10,107 |
|
|
| 10,713 |
|
|
| 5,499 |
|
|
| 5,740 |
|
Total regulatory liabilities |
| $ | 11,053 |
|
| $ | 11,699 |
|
| $ | 6,005 |
|
| $ | 6,387 |
|
145
At December 31, |
| 2020 |
|
| 2019 |
| ||
(millions) |
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
Regulatory assets: |
|
|
|
|
|
|
|
|
Deferred cost of fuel used in electric generation(1) |
| $ | — |
|
| $ | 48 |
|
Deferred project costs and DSM programs for gas utilities(2) |
|
| 35 |
|
|
| 21 |
|
Unrecovered gas costs(3) |
|
| 78 |
|
|
| 99 |
|
Deferred rider costs for Virginia electric utility(4)(5) |
|
| 98 |
|
|
| 109 |
|
Deferred nuclear refueling outage costs(6) |
|
| 53 |
|
|
| 68 |
|
NND Project costs(7) |
|
| 138 |
|
|
| 138 |
|
PJM transmission rates(8) |
|
| 71 |
|
|
| 121 |
|
Other |
|
| 226 |
|
|
| 267 |
|
Regulatory assets-current |
|
| 699 |
|
|
| 871 |
|
Pension and other postretirement benefit costs(9) |
|
| 1,363 |
|
|
| 1,431 |
|
Deferred rider costs for Virginia electric utility(4)(5)(10)(11) |
|
| 311 |
|
|
| 235 |
|
PJM transmission rates(8) |
|
| 46 |
|
|
| 85 |
|
Deferred project costs for gas utilities(2) |
|
| 632 |
|
|
| 521 |
|
Interest rate hedges(12) |
|
| 1,042 |
|
|
| 709 |
|
AROs and related funding(13) |
|
| 331 |
|
|
| 311 |
|
Cost of reacquired debt(14) |
|
| 245 |
|
|
| 262 |
|
NND Project costs(7) |
|
| 2,364 |
|
|
| 2,503 |
|
Ash pond and landfill closure costs(15) |
|
| 2,301 |
|
|
| 1,016 |
|
Other |
|
| 498 |
|
|
| 579 |
|
Regulatory assets-noncurrent |
|
| 9,133 |
|
|
| 7,652 |
|
Total regulatory assets |
| $ | 9,832 |
|
| $ | 8,523 |
|
Regulatory liabilities: |
|
|
|
|
|
|
|
|
Deferred cost of fuel used in electric generation(1) |
| $ | 58 |
|
| $ | — |
|
Provision for future cost of removal and AROs(16) |
|
| 183 |
|
|
| 124 |
|
Reserve for refunds and rate credits to electric utility customers(17) |
|
| 128 |
|
|
| 143 |
|
Reserve for future credits to Virginia electric customers(18) |
|
| 120 |
|
|
| — |
|
Cost-of-service impact of 2017 Tax Reform Act(19) |
|
| 12 |
|
|
| 4 |
|
Income taxes refundable through future rates(20) |
|
| 124 |
|
|
| 71 |
|
Monetization of guarantee settlement(21) |
|
| 67 |
|
|
| 67 |
|
Other |
|
| 117 |
|
|
| 46 |
|
Regulatory liabilities-current |
|
| 809 |
|
|
| 455 |
|
Income taxes refundable through future rates(20) |
|
| 4,376 |
|
|
| 4,529 |
|
Provision for future cost of removal and AROs(16) |
|
| 2,150 |
|
|
| 2,208 |
|
Nuclear decommissioning trust(22) |
|
| 1,719 |
|
|
| 1,471 |
|
Monetization of guarantee settlement(21) |
|
| 903 |
|
|
| 970 |
|
Reserve for refunds and rate credits to electric utility customers(17) |
|
| 540 |
|
|
| 656 |
|
Overrecovered other postretirement benefit costs(23) |
|
| 111 |
|
|
| 54 |
|
Other |
|
| 388 |
|
|
| 316 |
|
Regulatory liabilities-noncurrent |
|
| 10,187 |
|
|
| 10,204 |
|
Total regulatory liabilities |
| $ | 10,996 |
|
| $ | 10,659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
| 2020 |
|
| 2019 |
| ||
(millions) |
|
|
|
|
|
|
|
|
Virginia Power |
|
|
|
|
|
|
|
|
Regulatory assets: |
|
|
|
|
|
|
|
|
Deferred cost of fuel used in electric generation(1) |
| $ | — |
|
| $ | 48 |
|
Deferred rider costs(2)(3) |
|
| 98 |
|
|
| 109 |
|
Deferred nuclear refueling outage costs(4) |
|
| 53 |
|
|
| 68 |
|
PJM transmission rates(5) |
|
| 71 |
|
|
| 121 |
|
Other |
|
| 73 |
|
|
| 87 |
|
Regulatory assets-current |
|
| 295 |
|
|
| 433 |
|
Deferred rider costs(2)(3)(6)(7) |
|
| 311 |
|
|
| 235 |
|
PJM transmission rates(5) |
|
| 46 |
|
|
| 85 |
|
Interest rate hedges(8) |
|
| 733 |
|
|
| 404 |
|
Ash pond and landfill closure costs(9) |
|
| 2,301 |
|
|
| 1,016 |
|
Other |
|
| 118 |
|
|
| 123 |
|
Regulatory assets-noncurrent |
|
| 3,509 |
|
|
| 1,863 |
|
Total regulatory assets |
| $ | 3,804 |
|
| $ | 2,296 |
|
Regulatory liabilities: |
|
|
|
|
|
|
|
|
Deferred cost of fuel used in electric generation(1) |
| $ | 58 |
|
| $ | — |
|
Provision for future cost of removal(10) |
|
| 152 |
|
|
| 103 |
|
Reserve for future credits to Virginia electric customers(11) |
|
| 120 |
|
|
| — |
|
Income taxes refundable through future rates(12) |
|
| 54 |
|
|
| 54 |
|
Other |
|
| 41 |
|
|
| 10 |
|
Regulatory liabilities-current |
|
| 425 |
|
|
| 167 |
|
Income taxes refundable through future rates(12) |
|
| 2,404 |
|
|
| 2,438 |
|
Nuclear decommissioning trust(13) |
|
| 1,719 |
|
|
| 1,471 |
|
Provision for future cost of removal(10) |
|
| 980 |
|
|
| 1,054 |
|
Deferred cost of fuel used in electric generation(1) |
|
| 54 |
|
|
| 30 |
|
Other |
|
| 181 |
|
|
| 81 |
|
Regulatory liabilities-noncurrent |
|
| 5,338 |
|
|
| 5,074 |
|
Total regulatory liabilities |
| $ | 5,763 |
|
| $ | 5,241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2020,2022, Dominion Energy and Virginia Power regulatory assets include $4.5$5.5 billion and $3.2$2.7 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.years.
NOTE 13. REGULATORY MATTERS
Regulatory Matters Involving Potential Loss Contingencies
As a result of issues generated in the ordinary course of business, the Companies are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for the Companies to estimate a range of possible loss. For regulatory matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters that the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on the Companies’ financial position, liquidity or results of operations.
FERC—ELECTRIC
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and, under its market based rate authority, sells electricity in the PJM wholesale market and to wholesale purchasers in Virginia and North Carolina. DESC sells electricity to wholesale purchasers in its balancing authority area under its electric cost based tariff and to wholesale purchasers outside of its balancing authority area under its market based rate authority. Dominion Energy’s nonregulated generators sell electricity in the PJM, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California, Ohio, South Carolina and Utah, under Dominion Energy’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.
FERC—GAS146
In July 2017, FERC audit staff communicated to DETI that it had substantially completed an audit of DETI’s compliance with the accounting and reporting requirements of FERC’s Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report which had the potential to result in adjustments which could have been material to Dominion Energy’s results of operations. In December 2017, DETI provided its response to the audit report. In 2018, DETI recognized a charge of $129 million ($94 million after-tax) recorded within discontinued operations in Dominion Energy’s Consolidated Statements of Income for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with FERC. In November 2020, Dominion Energy completed the sale of DETI as part of the GT&S Transaction.
2017 Tax Reform Act
Subsequent to the enactment of the 2017 Tax Reform Act, the Companies’ state regulators issued orders requesting that public utilities evaluate the total tax impact on the entity’s cost of service and accrue a regulatory liability attributable to the benefits of the reduction in the corporate income tax rate. Certain of the orders requested that the public utilities submit a response to the state regulatory commissions detailing the total tax impact on the utility’s cost of service.
The Companies began to reserve the impacts of the cost-of-service reduction as regulatory liabilities in January 2018 and will continue until rates are reset pursuant to state regulators’ approvals. The Companies have recorded a reasonable estimate of net income taxes refundable through future rates in the jurisdictions in which they operate.
In September 2018, the Virginia Commission issued an order directing Virginia Power to submit a filing quantifying the impacts of the 2017 Tax Reform Act. In March 2019, the Virginia Commission issued an order approving an annual revenue reduction of approximately $183 million effective April 2019 and ordered Virginia Power to implement the one-time customer credit on or before July 1, 2019. In the second quarter of 2019, Virginia Power refunded to customers $132 million.
In August 2018, Virginia Power filed with FERC to waive protocols and begin reflecting projected tax reform benefits of approximately $100 million through the transmission formula rate prior to the normal formula rate process. FERC granted the waiver and the amounts began being reflected in customer billings in November 2018 reflecting the adjustment effective January 1, 2018.
In October 2018, the North Carolina Commission issued an order requesting companies file to reduce base rates expeditiously. In March 2019, the North Carolina Commission issued an order approving Virginia Power’s proposed annual base rate revenue decrease of approximately $14 million effective in early 2019 and one-time bill credit for its 2018 tax savings collected provisionally from customers. In the second quarter of 2019, Virginia Power refunded to customers $13 million.
In March 2019, Questar Gas filed with the Utah and Wyoming Commissions as to the impact of excess deferred income taxes resulting from the 2017 Tax Reform Act. Questar Gas proposed to return the 2018 amortization of excess deferred income taxes to customers and to incorporate the remaining excess deferred income tax impact in its next general rate cases in each jurisdiction. The Utah Commission issued an order effective March 2020 approving Questar Gas’ proposal to refund the January 2019 through February 2020 amortization of excess deferred income taxes over 12 months beginning in June 2020. Additionally, new base rates that went into effect in Utah on March 1, 2020 include the prospective impacts of sharing excess deferred income taxes with customers. In April 2020, at the request of the Wyoming Commission, this matter was considered in conjunction with the base rate case that was filed in November 2019. In June 2020, the Wyoming Commission approved a proposal to share the benefits of deferred income taxes for the period January 2018 through August 2020 with customers over a one year period beginning in September 2020. In addition, new base rates that went into effect in Wyoming in September 2020 include the prospective impacts of sharing excess deferred income taxes with customers.
In October 2018, the Ohio Commission issued an order requiring rate-regulated utilities to file an application reflecting the impact of the 2017 Tax Reform Act on current rates by January 1, 2019. In December 2018, East Ohio filed its application proposing an approach to establishing rates and charges by and through which to return tax reform benefits to its customers. In December 2019, the Ohio Commission issued an order approving customer credits of approximately $600 million that will be shared with customers primarily over the remaining book life of the property to which the excess deferred income taxes relate. In addition, East Ohio will reduce rates approximately $19 million per year to account for the 2017 Tax Reform Act’s impact on its equity return component of rates charged to customers. A tax savings credit, which passes through the reduction in the federal income tax rate under the 2017 Tax Reform Act to customers in accordance with the settlement agreement approved by the Ohio Commission, became effective with the first billing cycle in April 2020.
In connection with the SCANA Merger Approval Order, the South Carolina Commission approved DESC’s provision of approximately $100 million in bill credits related to the 2017 Tax Reform Act’s impact on retail electric customer rates for the period beginning January 2018 through January 2019. These credits have been included in bills rendered on and after the first billing cycle of February 2019. In addition, the South Carolina Commission approved a tax rider whereby the effects of the reduction in the corporate income tax rate resulting from the 2017 Tax Reform Act will benefit retail electric customers. This tax rider reduced base rates to customers by $63 million in 2019 and $66 million in 2020. Unamortized excess deferred income taxes that remained at the end of 2020 will be considered in future rate proceedings.
In October 2018, the South Carolina Commission issued an order approving adjustment to DESC’s natural gas rate schedules, under the terms of the Natural Gas Rate Stabilization Act, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. The approved natural gas rate schedules also included a tax reform rate rider to refund certain income tax amounts previously collected from customers. These lower rates, representing a $20 million decreased revenue requirement, became effective for bills rendered on and after the first billing cycle in November 2018.
In December 2018, the North Carolina Commission issued an order approving PSNC’s proposed adjustments to customer rates, representing a $13 million decreased revenue requirement, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. These lower rates became effective for service rendered on and after January 1, 2019. Amounts collected in customer rates during 2018 and amounts arising from excess deferred income taxes have been recorded in regulatory liabilities and must be considered in PSNC’s next general rate case proceeding or in three years, whichever is sooner. The reduction in the federal corporate tax rate and its impact on PSNC’s various rate riders will be addressed in future proceedings related to those riders.
Other Regulatory Matters
Virginia Regulation – Key Legislation Affecting Operations
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.
In November 2019, the Virginia Commission approved a 9.2% general ROE for Virginia Power’s non-transmission rate adjustment clauses and for purposes of determining Virginia Power’s base rate earnings in the 2021 Triennial Review.
In 2020, Virginia Power recorded a charge of $130 million ($97 million after-tax) in impairment of assets and other charges in its Consolidated Statements of Income (reflected in the Corporate and Other segment) for benefits expected to be provided through the use of a CCRO in accordance with the GTSA. This charge reflects benefits expected to be provided to jurisdictional customers as a result of the 2021 Triennial Review as well as the impact on certain non-jurisdictional customers which follow Virginia Power’s jurisdictional customer rate methodology.
Grid Transformation and Security Act of 2018
In March 2018, theThe GTSA reinstated base rate reviews commencing with the 2021 Triennial Review which will occur one year earlier than under the Regulation Act legislation enacted in February 2015.
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 customersand served as the basis for a reduction in future rates, may be reduced by Virginia Commission-approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects to include in a CCRO. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that the costs of such projects may be recovered through a rate adjustment clause if not the subject of a CCRO. Any costs that are the subject of a CCRO may not beare deemed recovered in base rates forduring the service life of the projectstriennial 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 review,Triennial Review, any such rate reduction iswas limited to $50$50 million.
The legislation also includes provisions requiring Virginia Power to provide current customers one-time rate credits totaling $200 million and to reduce base rates to reflect reductions in income tax expense resulting from the 2017 Tax Reform Act. As a result, Virginia Power incurred a $215 million ($160 million after-tax) charge (reflected in the Corporate and Other segment during 2018) in connection with this legislation, including the impact on certain non-jurisdictional customers which follow Virginia Power’s jurisdictional customer rate methodology. In July 2018 and January 2019, Virginia Power credited $138 million and $77 million, respectively, to current customers’ bills.
In addition, Virginia Power reduced base rates on an annual basis by $125 million effective July 2018, to reflect the estimated effect of the 2017 Tax Reform Act. In March 2019, the Virginia Commission directed an annual revenue reduction of $183 million in rates for generation and distribution services pursuant to the GTSA effective April 2019.
In January 2019, the Virginia Commission issued an order approving capital spending for the first three years of Virginia Power’s ten-year plan totaling $68 million for electric distribution grid transformation projects as authorized by the GTSA on cyber and physical security and related telecommunications infrastructure (Phase IA). The Virginia Commission declined to approve certain of the proposed components for the first three years of the plan, the proposed spending for which was not found reasonable and prudent based on the record in the proceeding.
In September 2019, Virginia Power filed a revised plan which included six components: (i) smart meters; (ii) customer information platform; (iii) grid improvement projects; (iv) telecommunications infrastructure; (v) cyber security; and (vi) a smart charging electric vehicle infrastructure pilot program (Phase IB). For Phase IB, the total proposed capital investment during 2019 – 2021 is $503 million and the proposed operations and maintenance investment was $78 million. In March 2020 the Virginia Commission issued an order approving $212 million of costs related to a new customer information platform, targeted grid hardening and corridor improvements, an electric vehicle Smart Charging Infrastructure Pilot Program, cyber security, stakeholder engagement and customer education and denied the costs associated with AMI, self-healing grid and certain other grid hardening projects alleging that Virginia Power did not prove the reasonableness and prudency of these costs. In April 2020, Virginia Power filed a petition for reconsideration of the Virginia Commission’s order and requested clarification of certain matters, including the Smart Charging Infrastructure Pilot Program. Additionally, Virginia Power requested clarification of certain matters relating to an AMI time-of-use rate and the smart charging electric vehicle infrastructure pilot program. Subsequently, in April 2020, the Virginia Commission denied in full Virginia Power’s petition for reconsideration; however, it stated that its March 2020 order contained all necessary approvals for the smart charging electric vehicle infrastructure pilot program. Virginia Power intends to file a revised plan in 2021.
Utility Disconnection Moratorium Legislation
In November 2020, legislation was enacted in Virginia relating to the moratorium on utility disconnections during the COVID-19 pandemic and resulted in Virginia Power forgiving Virginia jurisdictional retail electric customer balances that were more than 30 days past due as of September 30, 2020. As a result, Virginia Power recorded a charge of $127 million ($94 million after-tax) in impairment of assets and other charges (reflected in the Corporate and Other segment). For the purposes of Virginia Power’s 2021 Triennial Review, the charge is excluded from Virginia Power’s cost of service for purposes of determining any test period earnings and determining any future rates. To the extent that the Virginia Commission determines total earnings for the test period to be above Virginia Power’s authorized earnings band, the forgiven balance amounts are offset against the excess earnings in the determination of any customer bill credits, or utilization of a CCRO, as part of the 2021 Triennial Review.
Virginia 2020 Legislation
In April 2020, the Governor of Virginia signed into law the VCEA, which along with related legislation forms a comprehensive framework affecting Virginia Power’s operations. The VCEA replaces Virginia’s voluntary renewable energy portfolio standard for Virginia Power with a mandatory program setting annual renewable energy portfolio standard requirements based on the percentage of total electric energy sold by Virginia Power, excluding existing nuclear generation and certain new carbon-free resources, reaching 100%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 Virginiaprovides for cost recovery related to participateparticipation 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$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. 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.
147
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.
Virginia Regulation – Recent Developments
2021 Triennial Review
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 (reflected
148
in the Corporate and Other segment) 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.
Virginia Fuel Expenses
In February 2020,May 2022, Virginia Power filed its annual fuel factor filing with the Virginia Commission to recover an estimated $1.2$2.3 billion in Virginia jurisdictional projected fuel expensesexpense for the rate year beginning July 1, 20202022 and a projected over-recovery of approximately $81 million for the prior year$1.0 billion under-recovered balance as of June 30, 2020. Virginia Power requested that the new fuel factor rate be implemented on an interim basis two months early, beginning on May 1, 2020. In March 2020, the Virginia Commission approved interim rates.2022. Virginia Power’s proposed fuel rate represents a fuel revenue decreaseincrease of approximately $393 million$1.8 billion when applied to projected kilowatt-hour sales for that period. Virginia Power also proposed alternatives to recover this under-collected balance over a two- or three-year period. Under these alternatives, Virginia Power’s fuel revenues for the rate year would increase by $1.3 billion or $1.2 billion, respectively. In addition, Virginia Power proposed a change in the timing of fuel cost recovery for certain customers who elect market-based rates that would consider those customers’ portion of the projected under-recovered balance to have been recovered as of June 30, 2022. In July 2022, Virginia Power, the Virginia Commission staff and another party filed a comprehensive settlement agreement with the Virginia Commission for approval. The comprehensive settlement agreement provides for the collection of the requested under-recovered projected fuel expense over a three-year period beginning MayJuly 1, 2020.2022 and that Virginia Power will exclude from recovery through base rates one half of the related financing costs over the three-year period. In June 2020,addition, the proposed settlement agreement affirmed Virginia Power’s proposal regarding fuel cost recovery for market-based rate customers. As a result, Virginia Power recorded a $191 million ($142 million after-tax) charge in the second quarter of 2022 within impairment of assets and other charges in its Consolidated Statement of Income (reflected in the Corporate and Other segment). In September 2022, the Virginia Commission approved a revised fuel rate based on an updated projected over-recovery of $103 million from the prior year balance as of June 30, 2020.comprehensive settlement agreement.
Renewable Generation Projects – Construction
Solar Facility Projects
In May 2020 and July 2020, Virginia Power entered into and closed on separate agreements to acquire Grassfield Solar, Norge Solar and Sycamore Solar. The projects are expected to cost approximately $170 million in aggregate once constructed, including the initial acquisition cost. The facilities are expected to generate 82 MW combined and be placed into service inSeptember 2021, and 2022. In October 2020, Virginia Power filed an applicationa petition with the Virginia Commission for CPCNs to construct and operate these13 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.This matter is pending.
In December 2020, Virginia Power entered into and closed on separate agreements to acquire Fountain Creek Solar and Otter Creek Solar. The projects are expected to cost approximately $280 million$1.4 billion in the aggregate, once constructed, including the initial acquisition cost. The facilities are expected to generate 140 MW combinedexcluding financing costs, and be placed into service between 2022 and 2023. In March 2022, the Virginia Commission approved the petition.
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. In August 2022, the Virginia Commission approved the application for certification of the Virginia Facilities component of the CVOW Commercial Project and noted that no further action was required with respect to Virginia Power’s foreign currency risk mitigation plan. Also in August 2022, Virginia Power filed a petition for limited reconsideration relating to the performance standard for operation of the CVOW Commercial Project included in the Virginia Commission’s August order. The Virginia Commission granted reconsideration and suspended in part the August order pending its reconsideration. In October 2022, Virginia Power, Office of the Attorney General of Virginia and other parties filed a settlement agreement with the Virginia Commission for approval. The settlement agreement provides for certain cost sharing mechanisms of total construction costs between $10.3 billion and $13.7 billion, as subject to potential adjustment to the extent construction costs are decreased by the endIRA, and includes enhanced performance reporting provisions associated with operation of 2023.the CVOW Commercial Project in lieu of a performance guarantee. In December 2022, the Virginia Commission approved the settlement agreement.
In October 2022, Virginia Power expects to filefiled a petition with the Virginia Commission for CPCNs to construct and operate theseeight utility-scale projects totaling approximately 474 MW of solar generation and 16 MW of energy storage as part of its efforts to meet the renewable generation development requirements under the VCEA. The projects, as well asof October 2022, are expected to cost approximately $1.2 billion in the aggregate, excluding financing costs, and be placed into service between 2024 through 2025. This matter is pending.
Nuclear Life Extension Program
In October 2021, Virginia Power filed a rider to recover the costs associatedpetition with the recoveryVirginia 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 certain renewable generation facilities inSurry 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. In July 2022, the Virginia byCommission approved the end of 2021.petition.
149
Riders
Below is a discussion of significantSignificant riders associated with various Virginia Power projects:projects are as follows:
Rider Name |
| Application Date |
| Approval Date |
| Rate Year |
| Total Revenue Requirement (millions) |
|
| Increase (Decrease) Over Previous Year (millions) |
| ||
Rider B |
| June 2022 |
| January 2023 |
| April 2023 |
|
| 34 |
|
| $ | 18 |
|
Rider B |
| June 2022 |
| January 2023 |
| April 2024 |
|
| 34 |
|
|
| — |
|
Rider BW |
| October 2021 |
| May 2022 |
| September 2022 |
|
| 145 |
|
|
| 32 |
|
Rider BW |
| October 2021 |
| May 2022 |
| September 2023 |
|
| 120 |
|
|
| (25 | ) |
Rider CCR |
| February 2022 |
| October 2022 |
| December 2022 |
|
| 231 |
|
|
| 15 |
|
Rider CE(1) |
| September 2021 |
| March 2022 |
| May 2022 |
|
| 71 |
|
|
| 61 |
|
Rider CE(2) |
| October 2022 |
| Pending |
| May 2023 |
|
| 89 |
|
|
| 18 |
|
Rider E |
| January 2022 |
| September 2022 |
| November 2022 |
|
| 101 |
|
|
| 34 |
|
Rider E |
| January 2023 |
| Pending |
| November 2023 |
|
| 109 |
|
|
| 8 |
|
Rider GT |
| August 2021 |
| May 2022 |
| June 2022 |
|
| 56 |
|
| N/A |
| |
Rider GT |
| August 2022 |
| Pending |
| June 2023 |
|
| 16 |
|
|
| (40 | ) |
Rider GV |
| June 2021 |
| December 2021 |
| April 2023 |
|
| 127 |
|
|
| (15 | ) |
Rider OSW |
| November 2021 |
| August 2022(3) |
| September 2022 |
|
| 79 |
|
| N/A |
| |
Rider OSW |
| November 2022 |
| Pending |
| September 2023 |
|
| 271 |
|
|
| 192 |
|
Rider PPA |
| December 2022 |
| Pending |
| September 2023 |
|
| (22 | ) |
|
| (17 | ) |
Rider R |
| June 2021 |
| March 2022 |
| April 2022 |
|
| 59 |
|
|
| 1 |
|
Rider R |
| June 2021 |
| March 2022 |
| April 2023 |
|
| 55 |
|
|
| (4 | ) |
Rider RGGI(4) |
| December 2021 |
| Withdrawn |
|
|
|
|
|
|
|
| ||
Rider RGGI(5) |
| December 2022 |
| Pending |
| September 2023 |
|
| 373 |
|
| N/A |
| |
Rider RPS |
| December 2021 |
| June 2022 |
| September 2022 |
|
| 140 |
|
|
| 127 |
|
Rider RPS |
| December 2022 |
| Pending |
| September 2023 |
|
| 111 |
|
|
| (29 | ) |
Rider S |
| June 2021 |
| February 2022 |
| April 2023 |
|
| 191 |
|
|
| (1 | ) |
Rider SNA(6) |
| October 2021 |
| July 2022 |
| September 2022 |
|
| 107 |
|
| N/A |
| |
Rider SNA(6) |
| October 2022 |
| Pending |
| September 2023 |
|
| 50 |
|
|
| (57 | ) |
Rider T1(7) |
| May 2022 |
| July 2022 |
| September 2022 |
|
| 706 |
|
|
| (168 | ) |
Rider U(8) |
| June 2021 |
| March 2022 |
| April 2022 |
|
| 95 |
|
|
| 15 |
|
Rider U(9) |
| June 2022 |
| Pending |
| April 2023 |
|
| 74 |
|
|
| (21 | ) |
Rider US-2 |
| October 2021 |
| June 2022 |
| September 2022 |
|
| 11 |
|
|
| 2 |
|
Rider US-3 |
| August 2021 |
| March 2022 |
| June 2022 |
|
| 50 |
|
|
| 12 |
|
Rider US-3 |
| August 2022 |
| Pending |
| June 2023 |
|
| 40 |
|
|
| (10 | ) |
Rider US-4 |
| August 2021 |
| March 2022 |
| June 2022 |
|
| 15 |
|
|
| 5 |
|
Rider US-4 |
| August 2022 |
| Pending |
| June 2023 |
|
| 17 |
|
|
| 2 |
|
Rider W |
| June 2022 |
| Pending |
| April 2023 |
|
| 106 |
|
|
| (15 | ) |
Rider W |
| June 2022 |
| Pending |
| April 2024 |
|
| 109 |
|
|
| 3 |
|
DSM Riders(10) |
| December 2021 |
| August 2022 |
| September 2022 |
|
| 91 |
|
|
| 17 |
|
DSM Riders(11) |
| December 2022 |
| Pending |
| September 2023 |
|
| 107 |
|
|
| 16 |
|
(1) Associated with solar generation and energy storage projects approved in March 2022, solar generation projects approved in April 2021 and certain small-scale solar projects. (2) Associated with solar generation and energy storage projects requested for approval in October 2022 and certain small-scale solar projects in addition to previously approved Rider CE projects. (3) In August 2022, Virginia Power filed a petition for limited reconsideration relating to a performance standard for operation of the CVOW Commercial Project included in the Virginia Commission’s August order. The Virginia Commission granted reconsideration and suspended in part the August order pending its reconsideration with Rider OSW approved on an interim basis. In December 2022, the Virginia Commission issued an order reinstating its August 2022 order granting approval of Rider OSW. (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. The Virginia Commission granted Virginia Power’s motion in April 2022. In May 2022, Virginia Power filed a petition with the Virginia Commission requesting a suspension of Rider RGGI approved in August 2021. Virginia Power also requested that RGGI compliance costs incurred and unrecovered through July 2022 be recovered through existing base rates in effect during the period incurred. The Virginia Commission approved the request in June 2022. In the second quarter of 2022, Virginia Power recorded a charge of $180 million ($134 million after-tax) in impairment of assets and other charges (reflected in the Corporate and Other segment) for the amount deemed recovered through base rates through June 30, 2022, including the impact of certain non-jurisdictional customers which follow Virginia Power’s jurisdictional rate methodology. Virginia Power recorded $33 million ($25 million after-tax) in depreciation and amortization in the third quarter of 2022. (5) In December 2022, Virginia Power filed a petition to update and reinstate Rider RGGI to recover RGGI compliance costs incurred after July 2022 and those projected to occur through December 2023, with rate recovery from September 2023 through August 2024. For purposes of this proceeding, Virginia Power has assumed that Virginia will withdraw from RGGI on December 31, 2023, and accordingly did not project any RGGI compliance costs to be incurred after that date. (6) 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. In April 2022, Virginia Power, the Virginia Commission staff and certain interested parties filed a proposed stipulation recommending that costs incurred after February 2022 associated with the first phase of the nuclear life extension program for North Anna be deferred and requested for recovery in a subsequent Rider SNA filing. 150 (7) Consists of $482 million for the transmission component of Virginia Power’s base rates and $224 million for Rider T1. (8) Consists of $60 million for previously approved phases and $35 million for phase six costs for Rider U. (9) As amended in June 2022, application consists of $74 million for previously approved phases of Rider U. (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%. (11) Associated with an additional four new energy efficiency programs, one new demand response program and four new program bundles with a $150 million cost cap, with the ability to exceed the cost cap by no more than 15%.
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|
|
Rider Name |
| Application Date |
| Approval Date |
| Rate Year Beginning |
| Total Revenue Requirement (millions) |
|
| Increase (Decrease) Over Previous Year (millions) |
| ||
Rider US-3 |
| July 2019 |
| March 2020 |
| June 2020 |
| $ | 28 |
|
| $ | 18 |
|
Rider BW |
| October 2019 |
| June 2020 |
| September 2020 |
| 99 |
|
|
| (20 | ) | |
Rider US-2 |
| October 2019 |
| July 2020 |
| September 2020 |
| 10 |
|
|
| (5 | ) | |
Rider E |
| January 2020 |
| September 2020 |
| November 2020 |
| 85 |
|
|
| (19 | ) | |
Rider B |
| June 2020 |
| Pending |
| April 2021 |
| 24 |
|
|
| (8 | ) | |
Rider GV |
| June 2020 |
| Pending |
| April 2021 |
| 154 |
|
|
| 22 |
| |
Rider R |
| June 2020 |
| Pending |
| April 2021 |
| 59 |
|
|
| 15 |
| |
Rider S |
| June 2020 |
| Pending |
| April 2021 |
| 194 |
|
|
| (1 | ) | |
Rider W |
| June 2020 |
| Pending |
| April 2021 |
| 120 |
|
|
| 14 |
| |
Rider US-3 |
| July 2020 |
| Pending |
| June 2021 |
| 39 |
|
|
| 10 |
| |
Rider US-4 |
| July 2020 |
| Pending |
| June 2021 |
| 12 |
|
|
| 4 |
| |
Rider BW |
| October 2020 |
| Pending |
| September 2021 |
| 113 |
|
|
| 14 |
| |
Rider US-2 |
| October 2020 |
| Pending |
| September 2021 |
| 10 |
|
|
| — |
| |
Rider E |
| January 2021 |
| Pending |
| November 2021 |
| 67 |
|
|
| (18 | ) |
Electric Transmission Projects
Significant Virginia Power electric transmission projects approved or applied for are as follows:
Description and Location |
| Application |
| Approval |
| Type of |
| Miles of |
| Cost Estimate |
| |
Elmont-Ladysmith rebuild and related projects in the |
| April 2021 |
| April 2022 |
| 500 kV |
| 26 |
| $ | 95 |
|
Rebuild transmission lines and related projects in the |
| November 2021 |
| August 2022 |
| 230 kV |
| 21 |
|
| 45 |
|
Build new Dulles Towne Center substation and line |
| December 2021 |
| July 2022 |
| 230 kV |
| 1 |
|
| 105 |
|
Build new Aviator substation and line loop in the |
| February 2022 |
| November 2022 |
| 230 kV |
| 1 |
|
| 80 |
|
Nimbus line loop and substation and new 230 kV line |
| February 2022 |
| October 2022 |
| 230 kV |
| 1 |
|
| 40 |
|
Partial rebuild of Bristers-Ox 115 kV line in Fauquier |
| August 2022 |
| Pending |
| 115 kV |
| 15 |
|
| 40 |
|
Construct new switching station, substations, |
| October 2022 |
| Pending |
| 230 kV |
| 18 |
|
| 230 |
|
Construct new switching station, substation, |
| October 2022 |
| Pending |
| 230kV |
| 26 |
|
| 215 |
|
Construct new Mars and Wishing Star substations, |
| October 2022 |
| Pending |
| 500/230 kV |
| 4 |
|
| 720 |
|
Construct new Altair switching station, |
| November 2022 |
| Pending |
| 230 kV |
| 2 |
|
| 50 |
|
Construct new Cirrus and Keyser switching stations, |
| November 2022 |
| Pending |
| 230 kV |
| 5 |
|
| 65 |
|
In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 77 miles of new overhead 500500 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 2020 miles of new 230230 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
pending.
In December 2019, Virginia Power filed an application with the Virginia Commission for a CPCN to construct a new Evergreen Mills switching station and add approximately one mile of overhead 230 kV double circuit transmission lines from both the existing Brambleton-Yardley Ridge line and Brambleton-Poland Road line in Loudoun County, Virginia, estimated to cost approximately $30 million. In May 2020, the Virginia Commission issued an order approving in part and denying in part the petition. The Virginia Commission approved Virginia Power’s request to construct the new Evergreen Mills switching station and the new 230 kV double circuit transmission line from the existing Brambleton-Yardley Ridge line with a total estimated cost of $25 million.
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Additional 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) |
Rebuild and operate five segments between the Loudoun and Ox substations |
| August 2019 |
| June 2020 |
| 230 kV |
| 19 |
| 70 |
Build new Lockridge substation and line loop in Loudon County, Virginia |
| December 2019 |
| October 2020 |
| 230 kV |
| < 1 |
| 35 |
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 |
| Pending |
| 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 |
| Pending |
| 230 kV |
| 41 |
| 100 |
Rebuild Clubhouse - Dry Bread Line and Dry Bread - Lakeview Line in Greensville County, Virginia |
| November 2020 |
| Pending |
| 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 |
| Pending |
| 230 kV |
| 11 |
| 30 |
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%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.In June 2022, the Supreme Court of North Carolina affirmed the North Carolina Commission’s order.
Virginia Power North Carolina Fuel Filing
In August 2020,2022, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. In January 2021,Virginia Power updated its filing in October 2022 to reflect the North Carolina Commission approvedincreased commodity cost of fuel and proposed a total $16$107 million decreaseincrease to the fuel component of its electric rates for the rate year beginning February 1, 2021.
Pipeline Integrity and Safety Program
The North Carolina Commission has authorized PSNC to use a tracker mechanism2023. Virginia Power also submitted an alternative to recover the incurred capital investment and associated costsincrease over a two-year period. Under this approach, Virginia Power proposed a total $80 million increase to the fuel component of complyingits electric rates implemented on a staggered timeline for the rate year beginning February 1, 2023 with federal standards for pipeline integrity and safety requirements that are notremaining unrecovered balances to be recovered in current base rates.the rate year beginning February 1, 2024. In September 2020,January 2023, the North Carolina Commission approved PSNC’s requestthe filing for recovery over the two-year period.
PSNC Rider D
Rider D allows PSNC to increaserecover from customers all prudently incurred gas costs and the integrity management annual revenue requirement to $31 million, an increaserelated portion of $3 million over its previousuncollectible expenses as well as losses on negotiated gas and transportation sales. In May 2022, PSNC submitted a filing effective September 2020.
In February 2021,with, and received approval from, the North Carolina Commission approved PSNC’s request tofor a $56 million gas cost increase with rates effective June 2022. In September 2022, PSNC submitted a filing with, and received approval from, the integrity management annual revenue requirement to $33North Carolina Commission for a $126 million angas cost increase of $2with rates effective October 2022. In November 2022, PSNC submitted a filing with, and received approval from, the North Carolina Commission for a net $41 million over its previousgas cost decrease with rates effective December 2022.
In January 2023, PSNC submitted a filing with, and received approval from, the North Carolina Commission for a $154 million gas cost decrease with rates effective February 2023. In February 2023, PSNC submitted a filing with the North Carolina Commission for a $56 million gas cost decrease with rates effective March 2021.2023. This matter is pending.
PSNC Customer Usage Tracker
PSNC utilizes a customer usage tracker, a decoupling mechanism, which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption. In September 2022, PSNC submitted a filing with the North Carolina Commission for a $46 million increase relating to the customer usage tracker. The North Carolina Commission approved the filing in September 2022 with rates effective October 2022.
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 JanuaryJuly 2021, the South Carolina Commission approved a proposal made by the South Carolina Office of Regulatory Staff, and agreed to by DESC and other intervenors, to stay the base rate case due to the current economic conditions and to allow the parties more time to negotiate a settlement with a final order to be issued no later than August 2021. In connection with this order, DESC, the South Carolina Office of Regulatory Staff and other parties of record are to provide monthly updates tofiled a comprehensive settlement agreement with the South Carolina Commission for approval. The comprehensive settlement agreement provided 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 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 progress towards reachingcomprehensive settlement agreement, DESC would not file a negotiated settlement. This matter is pending.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.
152
In January 2020,2022, DESC filed an application with the South Carolina Commission seeking approval to recover $40$60 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. In April 2020, The2022, the South Carolina Commission approved the filing. request, effective with the first billing cycle of May 2022.
In January 2021,2023, DESC filed an application with the South Carolina Commission seeking approval to recover $48$46 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. DESC requested that rates be effective with the first billing cycle of May 2023. This matter is pending.
Natural Gas Rates
In June 2020,2022, DESC filed with the South Carolina Commission its monitoring report for the 12-month period ended March 31, 20202022 with a total revenue requirement of $409$553 million. This represents a $9$129 million overall annual increase to its natural gas rates including a $16 million base rate increase under the terms of the Natural Gas Rate Stabilization Act effective with the first billing cycle of November 2020.2022. In October 2020,2022, the South Carolina Commission approvedissued an order approving a total revenue requirement of $406$549 million effective with the first billing cycle of November 2020.2022. This represents a $6$125 million overall annual increase to DESC’s natural gas rates. Additionally,rates including a $12 million base rate increase under the South Carolina Commission authorized an allowed ROEterms of 9.90%, a reduction from the prior ROE of 10.25%. The South Carolina Commission also approved an agreement between the South Carolina Office of Regulatory Staff and DESC that DESC will file its next retail natural gas general rate proceeding no later than April 2023.Natural Gas Rate Stabilization Act.
Cost of Fuel
DESC’s retail electric rates include a cost of fuel component approved by the South Carolina Commission which may be adjusted periodically to reflect changes in the price of fuel purchased by DESC.
In February 2020, DESC filed a proposal with the South Carolina Commission to decrease the total fuel cost component of retail electric rates. DESC’s proposed decrease would reduce annual base fuel component recoveries by approximately $44 million and is projected to return to customers the existing over-collected balance while recovering DESC’s current base fuel costs over the 12-month period beginning with the first billing cycle of May 2020. In addition, DESC proposed an increase to its variable environmental and distributed energy resource components. In April 2020, the South Carolina Commission approved the filing.
In February 2021,2022, DESC filed with the South Carolina Commission a proposal to increase the total fuel cost component of retail electric rates. DESC’s proposed adjustment would increase annual base fuel component recoveries by approximately $36 million and is designed to recover DESC’s current base fuel costs, net of theincluding its existing over-collectedunder-collected balance, over the 12-month period beginning with the first billing cycle of May 2021.2022. 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. In April 2022, the South Carolina Commission approved the filing.
In August 2022, DESC filed an application with the South Carolina Commission seeking a mid-period adjustment to increase the base fuel component of retail electric rates for the recovery of electric fuel costs. The application requested an increase of the base fuel cost component of $399 million, with rates expected to be effective with the first billing cycle of January 2023. In November 2022, DESC, the South Carolina Office of Regulatory Staff and other parties of record filed a stipulation agreement with the South Carolina Commission for approval that reflects updated fuel cost experience and forecasts. The stipulation agreement proposes an increase of the base fuel cost component to be effective with the first billing cycle of January 2023, with an estimated annual increase of $168 million. In December 2022, the South Carolina Commission approved the stipulation agreement and issued a final order.
In February 2023, 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 2023. In addition, DESC proposed a decrease to its variable environmental component and anavoided capacity cost component. The net effect is a proposed annual increase to its distributed energy resource component.of $176 million. This matter is pending.
Electric - Other
Electric Transmission Projects
In 2020, DESC began several electric transmission projects in connection with two new nuclear plants under developmentutilizes a pension costs rider approved by Southern. These transmission projects are required to be in place prior to these plants beginning operations to maintain reliability. DESC anticipates the projects to go into service in phases, costing approximately $75 million in aggregate. In February 2020, DESC filed an application with the South Carolina Commission requesting approvalwhich is designed to construct and operate 28 milesallow recovery of 230 kV transmission linesprojected pension costs, including under-collected balances or net of over-collected balances, as applicable. The rider is typically reviewed for adjustment every 12 months with any resulting increase or decrease going into effect beginning with the first billing cycle in Aiken County, South Carolina estimated to cost approximately $30 million.May. In June 2020,February 2023, DESC requested that the South Carolina Commission approved the filing.approve an adjustment to this rider to increase annual revenue by $24 million. This matter is pending.
Ohio Regulation
PIR Program
In 2008, East Ohio began PIR, aimed at replacing approximately 25%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$200 million by 2018 and 3%3% per year thereafter subject to the cost recovery rate increase caps proposed by East Ohio.
In April 2020,2022, the Ohio Commission approved an extension of East Ohio’s PIR program for capital investments through 2026 with continuation of 3% increases of annual capital expenditures per year.
In June 2022, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 20192021 costs. The filing reflects gross plant investment for 20192021 of $209$225 million, cumulative gross plant investment of $1.8$2.2 billion and a revenue requirement of $218$273 million.
In December 2020, East Ohio filed an application with the Ohio Commission requesting approval to extend the PIR program for an additional five years upon expiration of the current authorization at the end of 2021. East Ohio proposed continued capital investment increases of 3% per year, with related increases in the annual rate-increase caps. In its application, East Ohio proposed that the new five-year period should include investment through December 31, 2026. This case is pending.
153
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%6.5% on capital investments not covered by its PIR program to expand, upgrade or replace its pipeline systeminfrastructure and information technology systems as well as investments necessary to comply with the Ohio Commission or other government regulation. In May 2019,April 2022, certain parties filed an appeal with the Supreme Court of Ohio appealing the Ohio Commission’s December 2020 order establishing the CEP rider, including the rate of return utilized in determining the revenue requirement. This matter is pending.
In April 2021, East Ohio filed an application requesting approval to adjust the CEP cost recovery rates for an alternative rate plan to establish a CEP rider to recover existing CEP-related deferrals2019 and to establish an ongoing recovery mechanism for future deferrals.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 $723 million through 2018 and a revenue requirement of $83 million. In December 2020, the Ohio Commission approved a cumulative gross plant investment of $721$957 million and a revenue requirement of $83$119 million. In February 2022, the Ohio Commission approved adjustments to CEP cost recovery rates for 2019 and 2020 costs. The approved rates reflect gross plant investment for 2019 and 2020 of $231 million, cumulative gross plant investment of $952 million and a revenue requirement of $118 million. The Ohio Commission also ordered that East Ohio should file its next base rate case by October 2023.
West VirginiaIn November 2022, the Ohio Commission approved adjustments to CEP cost recovery rates for 2021 costs. The approved rates reflect gross plant investment for 2021 of $146 million, cumulative gross plant investment of $1.1 billion and a revenue requirement of $131 million.
PIPP Plus Program
Under the Ohio PIPP Plus Program, eligible customers can make reduced payments based on their ability to pay their bill. The difference between the customer’s total bill and the PIPP amount is deferred and collected under the PIPP rider in accordance with the rules of the Ohio Commission. In July 2022, East Ohio’s annual update of the PIPP rider filed in May 2022 with the Ohio Commission was approved. The revised rider rate reflects recovery over the twelve-month period from July 2022 through June 2023 of projected deferred program costs of approximately $22 million from April 2022 through June 2023, net of over-recovery of accumulated arrearages of approximately $4 million as of March 31, 2022.
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 2022, the Ohio Commission approved East Ohio’s application to adjust its UEX Rider to reflect an annual revenue requirement of $20 million to provide for recovery of an under-recovered accumulated bad debt expense of $7 million as of March 31, 2022, and recovery of net bad debt expense projected to total $13 million for the twelve-month period ending March 2023.
Utah Regulation
West VirginiaUtah Base Rate Case
In September 2020, HopeMay 2022, Questar Gas filed its base rate case and schedules with the West VirginiaUtah Commission. HopeQuestar Gas proposed a non-fuel, base rate increase of $28 million.$71 million effective January 2023. 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 VirginiaUtah customers. The proposed rates would provide for an ROE of 10.25%10.3% compared to the currently authorized ROE of 9.45%9.5%. The rates are expected to go into effect in July 2021. This matter is pending.
PREP
In May 2020, Hope filed a PREP application with the West Virginia Commission requesting approval to recover PREP costs related to$39 million and $54 million of projected capital investment for 2020 and 2021, respectively. The application also includes a true-up of PREP costs related to the 2019 actual capital investment of$27 million and sets forth$13 million of annual PREP costs to be recovered in proposed rates effective November 1, 2020. In October 2020, the West Virginia Commission approved PREP rates effective November 1, 2020.
Utah Regulation
Purchased Gas
In September 2020, Questar Gas submitted a filing with the Utah Commission for a $40 million gas cost increase. In October 2020,December 2022, the Utah Commission approved a non-fuel, base rate increase of $48 million for rates effective January 2023 with an ROE of 9.6%.
Purchased Gas
In July 2022, the application on an interim basis,Utah Commission approved Questar Gas’ request for a $94 million gas cost increase with rates effective August 2022. In October 2022, the Utah Commission approved Questar Gas’ request for a $128 million gas cost increase with rates effective November 2020.2022.
Rural Expansion Program
In December 2019,February 2023, Questar Gas filed an application with the Utah Commission seeking approval for a CPCN to construct natural$92 million gas infrastructure to extend service to Eureka, Utah. The project is expected to include 11 miles of high-pressure pipeline and up to 360 service lines and to be in service in late 2021. Questar Gas also requested approval of a rural expansion rate adjustment tracker to recover the construction costs of the project.In August 2020, the Utah Commission approved the CPCN and the rural expansion rate adjustment tracker.
Wyoming Regulation
Wyoming Base Rate Case
In November 2019, Questar Gas filed its base rate case and schedules with the Wyoming Commission. Questar Gas proposed a non-fuel, base ratecost increase of $4 million effective September 2020. The base rate increase was proposed to replace aging infrastructure and expand its system. Questar Gas presented an earned return of 7.46%, based upon a fully-adjusted test period, compared to its authorized 9.5% return, and proposed a 10.5% ROE. In June 2020, the Wyoming Commission approved a base rate increase of $2 million annually, with rates effective September 1, 2020.March 2023. This revenue requirement increase was based on an approved ROE of 9.35%.matter is pending.
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.
154
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 20192021 and 20202022 were as follows:
(millions) | Dominion Energy |
|
| Virginia Power |
| ||
AROs at December 31, 2020 | $ | 5,583 |
|
| $ | 3,820 |
|
Obligations incurred during the period |
| 31 |
|
|
| 26 |
|
Obligations settled during the period |
| (165 | ) |
|
| (131 | ) |
Revisions in estimated cash flows(1) |
| (151 | ) |
|
| 67 |
|
Accretion |
| 224 |
|
|
| 141 |
|
Sale of non-wholly-owned nonregulated solar facilities |
| (49 | ) |
|
|
| |
AROs at December 31, 2021(2) | $ | 5,473 |
|
| $ | 3,923 |
|
Obligations incurred during the period |
| 144 |
|
|
| 132 |
|
Obligations settled during the period |
| (129 | ) |
|
| (155 | ) |
Revisions in estimated cash flows(3) |
| 46 |
|
|
| 48 |
|
Accretion |
| 217 |
|
|
| 145 |
|
Sales of Kewaunee and Hope |
| (175 | ) |
|
|
| |
AROs at December 31, 2022(2) | $ | 5,576 |
|
| $ | 4,093 |
|
| Amount |
| |
(millions) |
|
|
|
Dominion Energy |
|
|
|
AROs at December 31, 2018 | $ | 2,444 |
|
Obligations incurred during the period(1) |
| 2,413 |
|
AROs acquired in the SCANA Combination |
| 577 |
|
Obligations settled during the period |
| (134 | ) |
Revisions in estimated cash flows(2) |
| (324 | ) |
Accretion |
| 208 |
|
AROs at December 31, 2019(3) | $ | 5,184 |
|
Obligations incurred during the period |
| 67 |
|
Obligations settled during the period |
| (114 | ) |
Revisions in estimated cash flows(4) |
| 228 |
|
Accretion |
| 218 |
|
AROs at December 31, 2020(3) | $ | 5,583 |
|
Virginia Power |
|
|
|
AROs at December 31, 2018 | $ | 1,445 |
|
Obligations incurred during the period(1) |
| 2,408 |
|
Obligations settled during the period |
| (81 | ) |
Revisions in estimated cash flows(2) |
| (323 | ) |
Accretion |
| 132 |
|
AROs at December 31, 2019 | $ | 3,581 |
|
Obligations incurred during the period |
| 48 |
|
Obligations settled during the period |
| (85 | ) |
Revisions in estimated cash flows(5) |
| 139 |
|
Accretion |
| 137 |
|
AROs at December 31, 2020 | $ | 3,820 |
|
(2) Includes $198 million and $368 million reported in other current liabilities for Dominion Energy at December 31, 2021 and 2022, respectively. (3) Primarily reflects revisions to asbestos abatement costs associated with the early retirement of certain retired electric generation facilities.
|
|
|
|
|
|
|
|
|
|
Dominion Energy’s AROs at December 31, 20202022 and 2019,2021, include $1.9$1.9 billion and $1.7$2.0 billion, respectively, with $0.9$0.9 billion and $0.8$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, 20202022 and 2019,2021, the aggregate fair value of Dominion Energy’s trusts, consisting primarily of equity and debt securities, totaled $6.9$6.0 billion and $6.2$8.0 billion, respectively. At December 31, 20202022 and 2019,2021, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $3.2$3.2 billion and $2.9$3.7 billion, respectively.
In addition, AROs at December 31, 20202022 and 20192021 include $2.8$2.8 billion and $2.6$2.9 billion, respectively, related to Virginia Power’s future ash pond and landfill closure costs. Regulatory mechanisms, primarily associated with legislation described below,enacted in Virginia in 2019, provide for recovery of costs to be incurred.
In April 2018, the Governor of Virginia signed legislation into law extending an existing permit moratorium on the VDEQ issuing solid waste permits for the closure of ash ponds at Virginia Power’s Bremo, Chesapeake, Chesterfield and Possum Point power stations until July 2019. The legislation also required Virginia Power to solicit and compile by November 2018, information from third parties on the suitability, cost and market demand for beneficiation or recycling of coal ash from these units. In connection with this legislation, Virginia Power recorded an $81 million ($60 million after-tax) charge recorded in other operations and maintenance expense in its Consolidated Statements of Income.
In March 2019, the Governor of Virginia signed into law legislation which requires any CCR unit located at Virginia Power’s Bremo, Chesapeake, Chesterfield or Possum Point power stations that stopped accepting CCR prior to July 2019 be closed by removing the
CCR to an approved landfill or through recycling for beneficial reuse. Costs associated with the closure of these CCR units, including costs allocated to customers outside of Virginia, are recoverable through a rider approved by the Virginia Commission. In connection with this legislation, Virginia Power recorded a $2.4 billion ARO related to the cost of landfills and beneficial reuse, with an offsetting increase to property, plant and equipment of $1.3 billion for the Chesterfield power station and an increase primarily to regulatory assets for the remaining portion related to the Bremo, Chesapeake and Possum Point power stations in 2019. In connection with the March 2020 commitment for the planned early retirement of the Chesterfield power station, these costs were reclassified from property, plant and equipment primarily to regulatory assets for amounts recoverable through riders and the remaining $185 million associated with nonjurisdictional customers was reclassified to other deferred charges and other assets. In 2020, Virginia Power recorded a $140 million increase to the landfill and beneficial use AROs from revisions to post closure monitoring costs, the execution of a coal beneficiation contract and a landfill at the Chesterfield power station. See Note 12 for additional information.
In addition, Virginia Power revised its estimated cash flows for the existing ARO related to future ash pond and landfill closure costs, which resulted in a decrease of $202 million and a corresponding $113 million ($84 million after-tax) benefit in other operations and maintenance expense in the Consolidated Statements of Income in 2019.155
NOTE 15. LEASES
At December 31, 20202022 and 2019,2021, the Companies had the following lease assets and liabilities recorded in the Consolidated Balance Sheets:
| Dominion Energy |
|
| Virginia Power |
| ||||||||||
At December 31, | 2022 |
|
| 2021 |
|
| 2022 |
|
| 2021 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
| ||||
Lease assets: |
|
|
|
|
|
|
|
|
|
|
| ||||
Operating lease assets(1) | $ | 415 |
|
| $ | 506 |
|
| $ | 294 |
|
| $ | 256 |
|
Finance lease assets(2) |
| 144 |
|
|
| 144 |
|
|
| 82 |
|
|
| 71 |
|
Total lease assets | $ | 559 |
|
| $ | 650 |
|
| $ | 376 |
|
| $ | 327 |
|
Lease liabilities: |
|
|
|
|
|
|
|
|
|
|
| ||||
Operating lease liabilities(3) | $ | 39 |
|
| $ | 44 |
|
| $ | 21 |
|
| $ | 25 |
|
Finance lease liabilities(4) |
| 46 |
|
|
| 36 |
|
|
| 17 |
|
|
| 13 |
|
Total lease liabilities - current |
| 85 |
|
|
| 80 |
|
|
| 38 |
|
|
| 38 |
|
Operating lease liabilities (5) |
| 514 |
|
|
| 464 |
|
|
| 273 |
|
|
| 227 |
|
Finance lease liabilities(6) |
| 104 |
|
|
| 112 |
|
|
| 65 |
|
|
| 57 |
|
Total lease liabilities - noncurrent |
| 618 |
|
|
| 576 |
|
|
| 338 |
|
|
| 284 |
|
Total lease liabilities | $ | 703 |
|
| $ | 656 |
|
| $ | 376 |
|
| $ | 322 |
|
| December 31, 2020 |
|
| December 31, 2019 |
| ||
(millions) |
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
Lease assets: |
|
|
|
|
|
|
|
Operating lease assets(1) | $ | 564 |
|
| $ | 462 |
|
Finance lease assets(2) |
| 148 |
|
|
| 134 |
|
Total lease assets | $ | 712 |
|
| $ | 596 |
|
Lease liabilities: |
|
|
|
|
|
|
|
Operating lease liabilities(3) | $ | 54 |
|
| $ | 53 |
|
Finance lease liabilities(4) |
| 32 |
|
|
| 27 |
|
Total lease liabilities - current |
| 86 |
|
|
| 80 |
|
Operating lease liabilities (5) |
| 516 |
|
|
| 413 |
|
Finance lease liabilities(6) |
| 108 |
|
|
| 100 |
|
Total lease liabilities - noncurrent |
| 624 |
|
|
| 513 |
|
Total lease liabilities | $ | 710 |
|
| $ | 593 |
|
Virginia Power |
|
|
|
|
|
|
|
Operating lease assets(1) | $ | 185 |
|
| $ | 212 |
|
Finance lease assets(2) |
| 45 |
|
|
| 19 |
|
Total lease assets | $ | 230 |
|
| $ | 231 |
|
Lease liabilities: |
|
|
|
|
|
|
|
Operating lease liabilities(3) | $ | 28 |
|
| $ | 30 |
|
Finance lease liabilities(4) |
| 8 |
|
|
| 3 |
|
Total lease liabilities - current |
| 36 |
|
|
| 33 |
|
Operating lease liabilities (5) |
| 155 |
|
|
| 180 |
|
Finance lease liabilities(6) |
| 36 |
|
|
| 16 |
|
Total lease liabilities - noncurrent |
| 191 |
|
|
| 196 |
|
Total lease liabilities | $ | 227 |
|
| $ | 229 |
|
(2) Included in property, plant and equipment in the Companies’ Consolidated Balance Sheets, net of $114 million and $33 million of accumulated amortization at Dominion Energy and Virginia Power, respectively, at December 31, 2022 and net of $81 million and $18 million of accumulated amortization at Dominion Energy and Virginia Power, respectively, at December 31, 2021. (3) Included in other current liabilities in the Companies’ Consolidated Balance Sheets. (4) Included in securities due within one year in the Companies’ Consolidated Balance Sheets. (5) Included in other deferred credits and other liabilities in the Companies’ Consolidated Balance Sheets. (6) Included in other long-term debt in the Companies’ Consolidated Balance Sheets.
|
|
|
|
|
|
|
|
|
|
|
|
In addition to the amounts disclosed above, Dominion Energy’s Consolidated Balance Sheets at December 31, 20202022 and 2019 includes2021 include property, plant and equipment of $2.2 billion and $2.8 billion, respectively, and accumulated depreciation of $68$183 million and $364 million,$1.2 billion, respectively, related to facilities subject to power purchase agreements under which Dominion Energy is the lessor. Accumulated depreciation related to these facilities was $106 million at December 31, 2021. There was no accumulated depreciation related to these facilities recorded in Dominion Energy’s Consolidated Balance Sheets at December 31, 2022.
For the years ended December 31, 20202022, 2021 and 2019,2020, total lease cost associated with the Companies’ leasing arrangements consisted of the following:
| Dominion Energy |
|
| Virginia Power |
| ||||||||||||||||||
Year ended December 31, | 2022 |
|
| 2021 |
|
| 2020 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Finance lease cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Amortization | $ | 41 |
|
| $ | 40 |
|
| $ | 33 |
|
| $ | 15 |
|
| $ | 12 |
|
| $ | 7 |
|
Interest |
| 3 |
|
|
| (3 | ) |
|
| — |
|
|
| 3 |
|
|
| 1 |
|
|
| 1 |
|
Operating lease cost |
| 53 |
|
|
| 66 |
|
|
| 68 |
|
|
| 32 |
|
| $ | 30 |
|
| $ | 36 |
|
Short-term lease cost |
| 31 |
|
|
| 32 |
|
|
| 20 |
|
|
| 21 |
|
|
| 19 |
|
|
| 12 |
|
Variable lease cost |
| 4 |
|
|
| 5 |
|
|
| 8 |
|
|
| 1 |
|
|
| 1 |
|
|
| 4 |
|
Total lease cost | $ | 132 |
|
| $ | 140 |
|
| $ | 129 |
|
| $ | 72 |
|
| $ | 63 |
|
| $ | 60 |
|
156
| Year Ended December 31, 2020 |
|
| Year Ended December 31, 2019 |
| ||
(millions) |
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
Finance lease cost: |
|
|
|
|
|
|
|
Amortization | $ | 33 |
|
| $ | 20 |
|
Interest |
| — |
|
|
| 4 |
|
Operating lease cost |
| 68 |
|
|
| 79 |
|
Short-term lease cost |
| 20 |
|
|
| 26 |
|
Variable lease cost |
| 8 |
|
|
| 5 |
|
Total lease cost | $ | 129 |
|
| $ | 134 |
|
Virginia Power |
|
|
|
|
|
|
|
Operating lease cost | $ | 36 |
|
| $ | 41 |
|
Short-term lease cost |
| 12 |
|
|
| 13 |
|
Variable lease cost |
| 4 |
|
|
| 2 |
|
Total lease cost | $ | 52 |
|
| $ | 56 |
|
For the years ended December 31, 20202022, 2021 and 2019,2020, 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, 2020 |
|
| Year Ended December 31, 2019 |
| ||
(millions) |
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
Operating cash flows for finance leases | $ | — |
|
| $ | 4 |
|
Operating cash flows for operating leases |
| 96 |
|
|
| 111 |
|
Financing cash flows for finance leases |
| 33 |
|
|
| 20 |
|
Virginia Power |
|
|
|
|
|
|
|
Operating cash flows for operating leases |
| 52 |
|
|
| 56 |
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||||||||||
Year ended December 31, | 2022 |
|
| 2021 |
|
| 2020 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Operating cash flows for | $ | 3 |
|
| $ | (3 | ) |
| $ | — |
|
| $ | 3 |
|
| $ | 1 |
|
| $ | 1 |
|
Operating cash flows for |
| 82 |
|
|
| 103 |
|
|
| 96 |
|
|
| 50 |
|
|
| 53 |
|
|
| 52 |
|
Financing cash flows for |
| 32 |
|
|
| 40 |
|
|
| 33 |
|
|
| 12 |
|
|
| 12 |
|
|
| 7 |
|
In addition to the amounts disclosed above, Dominion Energy’s Consolidated Statements of Income for the years ended December 31, 2022, 2021 and 2020, and 2019, include $175$16 million, $168 million and $174$175 million, respectively, of rental revenue, included in operating revenue and $102$34 million, $110 million and $94$102 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, 20202022 and 2019,2021, the weighted average remaining lease term and weighted discount rate for the Companies’ finance and operating leases were as follows:
| December 31, 2020 |
|
| December 31, 2019 |
| ||
Dominion Energy |
|
|
|
|
|
|
|
Weighted average remaining lease term - finance leases | 5 years |
|
| 5 years |
| ||
Weighted average remaining lease term - operating leases | 26 years |
|
| 22 years |
| ||
Weighted average discount rate - finance leases |
| 3.17 | % |
|
| 3.83 | % |
Weighted average discount rate - operating leases |
| 4.07 | % |
|
| 4.48 | % |
Virginia Power |
|
|
|
|
|
|
|
Weighted average remaining lease term - finance leases | 6 years |
|
| 6 years |
| ||
Weighted average remaining lease term - operating leases | 21 years |
|
| 20 years |
| ||
Weighted average discount rate - finance leases |
| 2.51 | % |
|
| 4.12 | % |
Weighted average discount rate - operating leases |
| 4.26 | % |
|
| 4.29 | % |
| Dominion Energy |
|
| Virginia Power |
| ||||||||||
December 31, | 2022 |
|
| 2021 |
|
| 2022 |
|
| 2021 |
| ||||
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
| ||||
Weighted average remaining lease term - | 4 years |
|
| 5 years |
|
| 6 years |
|
| 6 years |
| ||||
Weighted average remaining lease term - | 29 years |
|
| 27 years |
|
| 30 years |
|
| 25 years |
| ||||
Weighted average discount rate - |
| 5.77 | % |
|
| 2.77 | % |
|
| 6.12 | % |
|
| 2.27 | % |
Weighted average discount rate - |
| 3.91 | % |
|
| 3.96 | % |
|
| 3.90 | % |
|
| 4.00 | % |
The Companies’ lease liabilities have the following maturities:
Maturity of Lease Liabilities |
| Dominion Energy |
|
| Virginia Power |
|
| Dominion Energy |
|
| Virginia Power |
| ||||||||||||||||||||
(millions) |
| Operating |
|
| Finance |
|
| Operating |
|
| Finance |
|
| Operating |
|
| Finance |
|
| Operating |
|
| Finance |
| ||||||||
2021 |
| $ | 64 |
|
| $ | 36 |
|
| $ | 31 |
|
| $ | 9 |
| ||||||||||||||||
2022 |
|
| 56 |
|
|
| 34 |
|
|
| 25 |
|
|
| 8 |
| ||||||||||||||||
2023 |
|
| 47 |
|
|
| 31 |
|
|
| 20 |
|
|
| 8 |
|
| $ | 44 |
|
| $ | 52 |
|
| $ | 23 |
|
| $ | 21 |
|
2024 |
|
| 40 |
|
|
| 29 |
|
|
| 15 |
|
|
| 7 |
|
|
| 36 |
|
|
| 45 |
|
|
| 19 |
|
|
| 20 |
|
2025 |
|
| 34 |
|
|
| 21 |
|
|
| 11 |
|
|
| 6 |
|
|
| 30 |
|
|
| 25 |
|
|
| 15 |
|
|
| 17 |
|
After 2025 |
|
| 756 |
|
|
| 14 |
|
|
| 194 |
|
|
| 9 |
| ||||||||||||||||
2026 |
|
| 27 |
|
|
| 20 |
|
|
| 12 |
|
|
| 14 |
| ||||||||||||||||
2027 |
|
| 25 |
|
|
| 14 |
|
|
| 10 |
|
|
| 11 |
| ||||||||||||||||
After 2027 |
|
| 642 |
|
|
| 15 |
|
|
| 314 |
|
|
| 13 |
| ||||||||||||||||
Total undiscounted lease payments |
|
| 997 |
|
|
| 165 |
|
|
| 296 |
|
|
| 47 |
|
|
| 804 |
|
|
| 171 |
|
|
| 393 |
|
|
| 96 |
|
Present value adjustment |
|
| (427 | ) |
|
| (25 | ) |
|
| (113 | ) |
|
| (3 | ) |
|
| (251 | ) |
|
| (21 | ) |
|
| (99 | ) |
|
| (14 | ) |
Present value of lease liabilities |
| $ | 570 |
|
| $ | 140 |
|
| $ | 183 |
|
| $ | 44 |
|
| $ | 553 |
|
| $ | 150 |
|
| $ | 294 |
|
| $ | 82 |
|
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 impairment of assets and other charges (reflected in the Corporate and Other segment) 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 (subsequently amended in December 2022) with a lessor to complete construction of and lease a Jones Act compliant offshore wind installation vessel. This vessel is designed to handle current turbine
157
technologies as well as next generation turbines. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $465$550 million, to fund the estimated project costs. If Dominion Energy ultimately proceeds with the project through completion, the The project is expected to be completed by September 2024. ready for the 2024 offshore wind turbine installation season. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs, which totaled $61$334 million as of December 31, 2020. If the project is terminated under certain events, Dominion Energy could be required to pay up to 100% of the then funded amount.
The lease term will commence once construction is substantially complete and the facility is able to be occupied and will end in December 2027. At the end of the initial lease term, Dominion Energy can (i) extend the term of the lease for an additional five years, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property on behalf of the lessor to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the project costs, Dominion Energy may be required to make a payment to the lessor, up to 83% of project costs, for the difference between the project costs and sale proceeds.
Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.
Offshore Wind Vessel Leasing Arrangement
In December 2020, Dominion Energy signed an agreement with a lessor to complete construction of and lease a Jones Act compliant offshore wind installation vessel. This vessel is designed to handle current turbine technologies as well as next generation turbines. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $550 million, to fund the estimated project costs. The project is expected to be completed by the end of 2023. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs, which totaled $187 million as of December 31, 2020.2022. If the project is terminated under certain events of default, Dominion Energy could be required to pay up to 100%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 2027.2027. At the end of the initial lease term, Dominion Energy can (i) extend the term of the lease for an additional term, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the outstanding project costs or, (iii) subject to certain terms and conditions, sell the property on behalf of the lessor to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the outstanding project costs, Dominion Energy may be required to make a payment
to the lessor for the difference between the outstanding project costs and sale proceeds. Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.
NOTE 16. VARIABLE INTEREST ENTITIES
The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
Dominion Energy
At December 31, 2020, Dominion Energy owns the manager and 67% of the membership interest in certain nonregulated solar facilities, as discussed in Note 2. Dominion Energy has concluded that these entities are VIEs due to the members lacking the characteristics of a controlling financial interest. In addition, in 2016 Dominion Energy created a wholly owned subsidiary, SBL Holdco, as a holding company of its interest in the VIE nonregulated solar facilities and accordingly SBL Holdco is a VIE. Dominion Energy is the primary beneficiary of SBL Holdco and the nonregulated solar facilities, as it has the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. Dominion Energy’s securities due within one year and long-term debt include $32 million and $239 million, respectively, of debt issued by SBL Holdco net of issuance costs that is nonrecourse to Dominion Energy and is secured by SBL Holdco’s interest in certain nonregulated solar facilities.
At December 31, 2020,2022, Dominion Energy owns a 50%50% membership interest in Cove Point, as discussed in Notes 3 and 9. Dominion Energy concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. As a result of the GT&S Transaction, effective November 1, 2020, Dominion Energy is no longer the primary beneficiary of Cove Point as BHE retains the power to direct the activities that most significantly impact Cove Point’s economic performance. Dominion Energy’s maximum exposure to loss is limited to its current and future investment, as well as any obligations under a guaranteeguarantees provided. See Note 23 for moreadditional information.
At December 31, 2020,2022, Dominion Energy owns a 53%53% membership interest in Atlantic Coast Pipeline. Dominion Energy concluded that Atlantic Coast Pipeline is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion Energy has concluded that it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance, as the power to direct is shared with Duke Energy. Dominion Energy is obligated to provide capital contributions based on its ownership percentage. Dominion Energy’s maximum exposure to loss is limited to any future investment as well as any obligations under a guarantee provided.investment. See Note 9 for moreadditional 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 furtheradditional 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 1 non-utility generator with an aggregate summer generation capacity of approximately 218 MW. The contract contained certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considered to be variable interests and for which Virginia Power had previously concluded if the generation facility were to be a VIE that it would not be the primary beneficiary. In May 2019, Virginia Power entered into an agreement and paid $135 million to terminate the remaining contract with the non-utility generator. A $135 million ($100 million after-tax) charge was recorded in impairment of assets and other charges in Virginia Power’s Consolidated Statements of Income (reflected in the Corporate and Other segment) during the second quarter of 2019. Virginia Power paid $13 million and $50 million for
electric capacity to non-utility generators and $1 million and $18 million for electric energy to non-utility generators for the years ended December 31, 2019 and 2018, respectively.
Virginia Power purchased shared services from DES, an affiliated VIE, of $349$396 million, $387$380 million and $335$349 million for the years ended December 31, 2020, 20192022, 2021 and 2018,2020, respectively. Virginia Power’s Consolidated Balance Sheets included amounts due to DES of $175$28 million at December 31, 2020,2022, and $102$20 million at December 31, 2019,2021, 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
158
Dominion Energy subsidiaries, including Virginia Power. Virginia Power has no obligation to absorb more than its allocated share of DES costs.
NOTE 17. SHORT-TERM DEBT AND CREDIT AGREEMENTS
The Companies use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion Energy utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion Energy’s credit ratings and the credit quality of its counterparties.
Dominion Energy
Dominion Energy’s short-term financing is supported throughby its access to the$6.0 billion joint revolving credit facility described below.that 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. 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, 2022 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Joint revolving credit facility(2) |
| $ | 6,000 |
|
| $ | 3,076 |
|
| $ | 202 |
|
| $ | 2,722 |
|
At December 31, 2021 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Joint revolving credit facility(2) |
| $ | 6,000 |
|
| $ | 1,883 |
|
| $ | 131 |
|
| $ | 3,986 |
|
|
| Facility Limit |
|
| Outstanding Commercial Paper(1) |
|
| Outstanding Letters of Credit |
|
| Facility Capacity Available |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility(2)(3) |
| $ | 6,000 |
|
| $ | 627 |
|
| $ | 100 |
|
| $ | 5,273 |
|
At December 31, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility(2) |
| $ | 6,000 |
|
| $ | 836 |
|
| $ | 89 |
|
| $ | 5,075 |
|
|
|
|
|
|
|
DESC and Questar Gas’ short-term financings are supported through access as co-borrowers to the joint revolving credit facility discussed above with the Companies. At December 31, 2020,2022, the sub-limits for DESC and Questar Gas were $500$500 million and $250$250 million, respectively.
In January 2020, DESC and GENCO applied to FERC for a two-year short-term borrowing authorization. In March 2020,2021, FERC granted DESC authority through March 20212023 to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act) in amounts not to exceed $2.2$2.2 billion outstanding with maturity dates of one year or less. In addition, in March 2020,2021, FERC granted GENCO authority through March 20212023 to issue short-term indebtedness not to exceed $200$200 million outstanding with maturity dates of one year or less. In January 2021,2023, DESC and GENCO applied to FERC for a two-year short-term borrowing authorization. The applications are pending.
In addition to the joint revolving credit facility mentioned above, Dominion Energy also has a credit facility which had an original stated maturity date of June 2020 and allowedallows Dominion Energy to issue up to $21approximately $30 million in letters of credit.credit and was scheduled to mature in June 2022. In May 2020, the creditApril 2022, Dominion Energy entered into an agreement to amend and restate this facility was amended to increase the facility capacity to approximately $30 million and extend the maturity date to June 2025. In May 2022, Dominion Energy further amended and restated this facility to have a maturity date of June 2024. At December 31, 20202022 and 2019,2021, Dominion Energy had $30$25 million and $21$29 million respectively, in letters of credit outstanding under this agreement.facility, respectively.
In addition toDecember 2021, in connection with the creditsale of certain non-wholly owned nonregulated solar facilities, mentioned above,as discussed in Note 10, SBL Holdco has $30terminated $30 million of credit facilities which had an original stated maturity date of December 2017 with automatic one-year renewals through the maturity of the SBL Holdco term loan agreement in December 2023.and Dominion Solar Projects III, Inc. has $25terminated $25 million of credit facilities which had an original stated maturity date of May 2018 with automatic facilities.one-year renewals through the maturity of the Dominion Solar Projects III, Inc. term loan agreement in May 2024. At both December 31, 2020 and 2019, 0 amounts were outstanding under either of these facilities.
In March 2020,July 2021, Dominion Energy entered into a $900 million 364-Day Revolving Credit Agreement.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 agreement bears interestterm loan was scheduled to mature in December 2021, with the ability to extend maturity at a variable rate. At December 31, 2020, $225 million was outstanding under the agreement. The proceeds from these borrowings were used to provide for general working capital and other general corporate purposes. The maximum allowed total debt to total capital ratio under this supplemental agreement is consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility.
In March 2020, Dominion Energy borrowed $500 million under a 364-Day Term Loan Credit Agreement that bore interest at a variable rate. The proceeds were usedoption to provide for general working capitalJune 2022 and other general corporate purposes. In November 2020, Dominion Energy repaid the outstanding balance in full.
In April 2020, Dominion Energy borrowed $625 million under a 364-Day Term Loan Credit Agreement that bore interest at a variable rate. The proceeds were usedutilized to provide for general working capital and other general corporate purposes.repay the deposit received from BHE on the Q-Pipe Transaction. In June 2020,December 2021, Dominion Energy repaidused the net proceeds from the completion of the sale of the Q-Pipe Group to Southwest Gas to repay the principal outstanding balanceunder the term loan plus accrued interest.
In December 2021, DECP Holdings entered into a credit facility, which allows it to issue up to $110 million in full.letters of credit with automatic one-year renewals through the maturity of the facility in December 2024. At both December 31, 2022 and 2021, $110 million in letters of credit were outstanding under this agreement with no amounts drawn under the letters of credit.
159
Dominion Energy has an effective shelf registration statement with the SEC for the sale of up to $3.0$3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability InvestmentInvestmentSM. The registration limits the principal amount that may be outstanding at any one time to $1.0$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, 20202022 and December 31, 2019,2021, Dominion Energy’s Consolidated Balance Sheets include $268$347 million and $75$431 million, respectively, presented within short-term debt.debt with weighted-average interest rates of 4.24% and 1.25%, respectively. The proceeds are used for general corporate purposes and to repay debt.
In January 2023, Dominion Energy entered into a $2.5 billion 364-Day term loan facility which bears interest at a variable rate and will mature in January 2024 with the proceeds to be used to repay existing long-term debt and short-term debt upon maturity and for other general corporate purposes. Concurrently, Dominion Energy borrowed an initial $1.0 billion with the proceeds used to repay long-term debt. The maximum allowed total debt to total capital ratio under the facility is consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility. Dominion Energy may make up to two additional borrowings under this agreement through March 31, 2023, at which point any unused capacity will cease to be available to Dominion Energy.
Virginia Power
Virginia Power’s short-term financing is supported through its access as co-borrower to theDominion Energy’s $6.0 billion joint revolving credit facility. The credit facility can be used for working capital, as support for the combined commercial paper programs of the borrowers under the credit facility and for other general corporate purposes.
Virginia Power’s share of commercial paper and letters of credit outstanding under the joint revolving credit facility with Dominion Energy, Questar Gas and DESC were as follows:
|
| Facility Limit |
|
| Outstanding Commercial Paper(1) |
|
| Outstanding Letters of Credit |
| |||
(millions) |
|
|
|
|
|
|
|
|
| |||
At December 31, 2022 |
|
|
|
|
|
|
|
|
| |||
Joint revolving credit facility(2) |
| $ | 6,000 |
|
| $ | 941 |
|
| $ | 140 |
|
At December 31, 2021 |
|
|
|
|
|
|
|
|
| |||
Joint revolving credit facility(2) |
| $ | 6,000 |
|
| $ | 745 |
|
| $ | 40 |
|
|
| Facility Limit | �� |
| Outstanding Commercial Paper(1) |
|
| Outstanding Letters of Credit |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility(2)(3) |
| $ | 6,000 |
|
| $ | 45 |
|
| $ | 12 |
|
At December 31, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility(2) |
| $ | 6,000 |
|
| $ | 243 |
|
| $ | 7 |
|
(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 pursuant to the terms of the facility but can be changed at the option of the borrowers multiple times per year. At December 31, 2022, 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. |
|
|
|
In January 2023, Virginia Power entered into a letter of credit facility which allows Virginia Power to issue up to $125 million in letters of credit and matures in January 2026. Through February 2023, less than $1 million in letters of credit were issued and outstanding under this facility with no amounts drawn under the letters of credit. |
|
160
NOTE 18. LONG-TERM DEBT
|
| 2022 |
|
|
| Dominion Energy |
|
| Virginia Power |
| |||||||||||
At December 31, |
|
|
|
|
| 2022 |
|
| 2021 |
|
| 2022 |
|
| 2021 |
| |||||
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Sustainability Revolving Credit Agreement, variable rate, due 2024(2) |
|
| 5.24 | % |
|
| $ | 450 |
|
| $ | — |
|
|
|
|
|
|
| ||
Unsecured Senior Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Variable rate, due 2023 |
|
| 5.30 | % |
|
|
| 1,000 |
|
|
| 1,000 |
|
|
|
|
|
|
| ||
1.45% to 7.0%, due 2022 to 2052(3)(4) |
|
| 4.01 | % |
|
|
| 12,476 |
|
|
| 11,238 |
|
|
|
|
|
|
| ||
Unsecured Junior Subordinated Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
3.071% due 2024 |
|
| 3.07 | % |
|
|
| 700 |
|
|
| 700 |
|
|
|
|
|
|
| ||
Payable to Affiliated Trust, 8.4%, due 2031 |
|
| 8.40 | % |
|
|
| 10 |
|
|
| 10 |
|
|
|
|
|
|
| ||
Enhanced Junior Subordinated Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
5.75% due 2054 |
|
| 5.75 | % |
|
|
| 685 |
|
|
| 685 |
|
|
|
|
|
|
| ||
Virginia Electric and Power Company: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Unsecured Senior Notes, 2.30% to 8.875%, due 2022 to 2052 |
|
| 3.99 | % |
|
|
| 15,135 |
|
|
| 13,238 |
|
| $ | 15,135 |
|
| $ | 13,238 |
|
Tax-Exempt Financings, 0.75% to 1.90%, due 2032 to 2041(5) |
|
| 1.32 | % |
|
|
| 625 |
|
|
| 625 |
|
|
| 625 |
|
|
| 625 |
|
DECP Holdings, Term Loan, variable rate, due 2024(6) |
|
| 5.71 | % |
|
|
| 2,349 |
|
|
| 2,500 |
|
|
|
|
|
|
| ||
Questar Gas, Unsecured Senior Notes, 2.21% to 7.20%, due 2024 to 2052 |
|
| 3.99 | % |
|
|
| 1,250 |
|
|
| 1,000 |
|
|
|
|
|
|
| ||
East Ohio, Unsecured Senior Notes, 1.30% to 6.38%, due 2025 to 2052 |
|
| 3.13 | % |
|
|
| 2,300 |
|
|
| 1,800 |
|
|
|
|
|
|
| ||
PSNC, Senior Debentures and Notes, 3.10% to 7.45%, due 2026 to 2051 |
|
| 4.34 | % |
|
|
| 800 |
|
|
| 800 |
|
|
|
|
|
|
| ||
DESC: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
First Mortgage Bonds, 2.30% to 6.625%, due 2028 to 2065 |
|
| 5.09 | % |
|
|
| 3,634 |
|
|
| 3,634 |
|
|
|
|
|
|
| ||
Tax-Exempt Financings(7): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Variable rate due 2038 |
|
| 3.70 | % |
|
|
| 35 |
|
|
| 35 |
|
|
|
|
|
|
| ||
3.625% and 4.00%, due 2028 and 2033 |
|
| 3.90 | % |
|
|
| 54 |
|
|
| 54 |
|
|
|
|
|
|
| ||
GENCO, variable rate due 2038 |
|
| 3.70 | % |
|
|
| 33 |
|
|
| 33 |
|
|
|
|
|
|
| ||
Other |
|
| 3.63 | % |
|
|
| 1 |
|
|
| 1 |
|
|
|
|
|
|
| ||
Secured Senior Notes, 4.82%, due 2042(8) |
|
| 4.82 | % |
|
|
| 308 |
|
|
| 314 |
|
|
|
|
|
|
| ||
Tax-Exempt Financing, 3.8% due 2033 |
|
| 3.80 | % |
|
|
| 27 |
|
|
| 27 |
|
|
|
|
|
|
| ||
Total Principal |
|
|
|
|
| $ | 41,872 |
|
| $ | 37,694 |
|
| $ | 15,760 |
|
| $ | 13,863 |
| |
Fair value hedge valuation(9) |
|
|
|
|
|
| — |
|
|
| 2 |
|
|
|
|
|
|
| |||
Securities due within one year(10) |
|
|
|
|
|
| (2,848 | ) |
|
| (805 | ) |
|
| (700 | ) |
|
| (300 | ) | |
Unamortized discount, premium and debt issuance costs, net |
|
|
|
|
|
| (355 | ) |
|
| (315 | ) |
|
| (144 | ) |
|
| (110 | ) | |
Derivative restructuring(11) |
|
|
|
|
|
| 141 |
|
|
| 738 |
|
|
| — |
|
|
| 446 |
| |
Finance leases |
|
|
|
|
|
| 104 |
|
|
| 112 |
|
|
| 65 |
|
|
| 57 |
| |
Total long-term debt |
|
|
|
|
| $ | 38,914 |
|
| $ | 37,426 |
|
| $ | 14,981 |
|
| $ | 13,956 |
|
161
At December 31, |
| 2020 Weighted- average Coupon(1) |
|
| 2020 |
|
| 2019 |
| |||
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
|
|
|
Virginia Electric and Power Company: |
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Senior Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
2.45% to 8.875%, due 2022 to 2050 |
|
| 4.14 | % |
| $ | 12,689 |
|
| $ | 11,789 |
|
Tax-Exempt Financings(2): |
|
|
|
|
|
|
|
|
|
|
|
|
0.45% to 1.90%, due 2032 to 2041 |
|
| 1.14 | % |
|
| 625 |
|
|
| 625 |
|
Virginia Electric and Power Company total principal |
|
|
|
|
| $ | 13,314 |
|
| $ | 12,414 |
|
Securities due within one year |
|
|
|
|
|
| — |
|
|
| (1 | ) |
Unamortized discount, premium and debt issuances costs, net |
|
|
|
|
|
| (107 | ) |
|
| (88 | ) |
Derivative restructuring |
|
|
|
|
|
| 444 |
|
|
| — |
|
Finance leases |
|
|
|
|
|
| 36 |
|
|
| 16 |
|
Virginia Electric and Power Company total long-term debt |
|
|
|
|
| $ | 13,687 |
|
| $ | 12,341 |
|
Dominion Energy, Inc.: |
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental 364-Day credit facility, variable rate, due 2021 |
|
| 1.18 | % |
| $ | 225 |
|
| $ | — |
|
Unsecured Senior Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
Variable rates, due 2020 and 2023 |
|
| 0.75 | % |
|
| 1,000 |
|
|
| 300 |
|
2.0% to 7.0%, due 2021 to 2049(3) |
|
| 3.98 | % |
|
| 9,938 |
|
|
| 7,688 |
|
Unsecured Junior Subordinated Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
2.579% to 4.104%, due 2020 to 2024(4) |
|
| 3.23 | % |
|
| 1,950 |
|
|
| 2,950 |
|
Payable to Affiliated Trust, 8.4%, due 2031 |
|
| 8.40 | % |
|
| 10 |
|
|
| 10 |
|
Enhanced Junior Subordinated Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
Variable rates, due 2066(5) |
|
|
|
|
|
| — |
|
|
| 397 |
|
5.25% and 5.75%, due 2054 and 2076 |
|
| 5.48 | % |
|
| 1,485 |
|
|
| 1,485 |
|
Questar Gas, Unsecured Senior Notes, 2.98% to 7.20%, due 2024 to 2051 |
|
| 4.25 | % |
|
| 750 |
|
|
| 750 |
|
East Ohio, Unsecured Senior Notes, 1.30% to 3.00%, due 2025 to 2050 |
|
| 2.25 | % |
|
| 1,800 |
|
|
| — |
|
SCANA: |
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Medium Term Notes, 4.125% to 6.25%, due 2020 to 2022(6) |
|
|
|
|
|
| — |
|
|
| 508 |
|
Unsecured Senior Notes, variable rate, due 2034 (7) |
|
|
|
|
|
| — |
|
|
| 66 |
|
PSNC, Senior Debentures and Notes, 4.05% to 7.45%, due 2020 to 2047 |
|
| 4.62 | % |
|
| 800 |
|
|
| 700 |
|
DESC: |
|
|
|
|
|
|
|
|
|
|
|
|
First Mortgage Bonds, 3.22% to 6.625%, due 2021 to 2065 |
|
| 5.42 | % |
|
| 3,267 |
|
|
| 3,267 |
|
Tax-Exempt Financings(8): |
|
|
|
|
|
|
|
|
|
|
|
|
Variable rate due 2038 |
|
| 0.13 | % |
|
| 35 |
|
|
| 35 |
|
GENCO, variable rate due 2038 |
|
| 0.13 | % |
|
| 33 |
|
|
| 33 |
|
3.625% and 4.00%, due 2028 and 2033 |
|
| 3.90 | % |
|
| 54 |
|
|
| 54 |
|
Other |
|
| 3.67 | % |
|
| 1 |
|
|
| 1 |
|
Secured Senior Notes, 4.82%, due 2042(9) |
|
| 4.82 | % |
|
| 331 |
|
|
| 345 |
|
Term Loans, variable rates, due 2023 and 2024(9) |
|
| 2.55 | % |
|
| 476 |
|
|
| 527 |
|
Tax-Exempt Financing, 1.7% due 2033 |
|
| 1.70 | % |
|
| 27 |
|
|
| 27 |
|
Virginia Electric and Power Company total principal (from above) |
|
|
|
|
|
| 13,314 |
|
|
| 12,414 |
|
Dominion Energy, Inc. total principal(10) |
|
|
|
|
| $ | 35,496 |
|
| $ | 31,557 |
|
Fair value hedge valuation(11) |
|
|
|
|
|
| 3 |
|
|
| 4 |
|
Securities due within one year(12) |
|
| 3.14 | % |
|
| (1,905 | ) |
|
| (2,435 | ) |
Supplemental 364-Day credit facility borrowings |
|
|
|
|
|
| (225 | ) |
|
| — |
|
Unamortized discount, premium and debt issuance costs, net |
|
|
|
|
|
| (293 | ) |
|
| (228 | ) |
Derivative restructuring |
|
|
|
|
|
| 773 |
|
|
| — |
|
Finance leases |
|
|
|
|
|
| 108 |
|
|
| 100 |
|
Dominion Energy, Inc. total long-term debt |
|
|
|
|
| $ | 33,957 |
|
| $ | 28,998 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2020,2022, were as follows:
|
| 2021 |
|
| 2022 |
|
| 2023 |
|
| 2024 |
|
| 2025 |
|
| Thereafter |
|
| Total |
| 2023 |
| 2024 |
| 2025 |
| 2026 |
| 2027 |
| Thereafter |
| Total |
| ||||||||||||||
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||
Term Loans | $ | 134 |
| $ | 2,215 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2,349 |
| ||||||||||||||||||||||||||||
Sustainability Revolving Credit |
| — |
| 450 |
| — |
| — |
| — |
| — |
| 450 |
| ||||||||||||||||||||||||||||||||||
First Mortgage Bonds |
| — |
| — |
| — |
| — |
| — |
| 3,634 |
| 3,634 |
| ||||||||||||||||||||||||||||||||||
Unsecured Senior Notes |
| 2,700 |
| 690 |
| 2,000 |
| 2,220 |
| 1,893 |
| 23,459 |
| 32,962 |
| ||||||||||||||||||||||||||||||||||
Secured Senior Notes |
| 17 |
| 31 |
| 19 |
| 20 |
| 21 |
| 200 |
| 308 |
| ||||||||||||||||||||||||||||||||||
Tax-Exempt Financings |
| — |
| — |
| — |
| — |
| — |
| 774 |
| 774 |
| ||||||||||||||||||||||||||||||||||
Unsecured Junior Subordinated |
| — |
| — |
| — |
| — |
| — |
| 10 |
| 10 |
| ||||||||||||||||||||||||||||||||||
Unsecured Junior Subordinated |
| — |
| 700 |
| — |
| — |
| — |
| — |
| 700 |
| ||||||||||||||||||||||||||||||||||
Enhanced Junior Subordinated |
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 685 |
|
| 685 |
| ||||||||||||||||||||||||||||
Total | $ | 2,851 |
| $ | 4,086 |
| $ | 2,019 |
| $ | 2,240 |
| $ | 1,914 |
| $ | 28,762 |
| $ | 41,872 |
| ||||||||||||||||||||||||||||
Weighted-average Coupon |
| 3.69 | % |
| 4.81 | % |
| 3.01 | % |
| 2.84 | % |
| 3.74 | % |
| 4.34 | % |
|
| |||||||||||||||||||||||||||||
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Unsecured Senior Notes |
| $ | — |
|
| $ | 750 |
|
| $ | 700 |
|
| $ | 350 |
|
| $ | 350 |
|
| $ | 10,539 |
|
| $ | 12,689 |
| $ | 700 |
| $ | 350 |
| $ | 350 |
| $ | 1,150 |
| $ | 1,350 |
| $ | 11,235 |
| $ | 15,135 |
|
Tax-Exempt Financings |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
|
|
|
|
| 625 |
|
|
| 625 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 625 |
|
| 625 |
|
Total |
| $ | — |
|
| $ | 750 |
|
| $ | 700 |
|
| $ | 350 |
|
| $ | 350 |
|
| $ | 11,164 |
|
| $ | 13,314 |
| $ | 700 |
| $ | 350 |
| $ | 350 |
| $ | 1,150 |
| $ | 1,350 |
| $ | 11,860 |
| $ | 15,760 |
|
Weighted-average Coupon |
|
| — |
|
|
| 3.15 | % |
|
| 2.75 | % |
|
| 3.45 | % |
|
| 3.10 | % |
|
| 4.18 | % |
|
|
|
|
| 2.75 | % |
| 3.45 | % |
| 3.10 | % |
| 3.08 | % |
| 3.61 | % |
| 4.10 | % |
|
| |
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Supplemental 364-Day Credit Facility |
| $ | 225 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 225 |
| |||||||||||||||||||||
Term Loans(1) |
|
| 35 |
|
|
| 34 |
|
|
| 250 |
|
|
| 157 |
|
|
| — |
|
|
| — |
|
|
| 476 |
| |||||||||||||||||||||
First Mortgage Bonds |
|
| 33 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3,234 |
|
|
| 3,267 |
| |||||||||||||||||||||
Unsecured Senior Notes(2)(3) |
|
| 550 |
|
|
| 1,500 |
|
|
| 2,700 |
|
|
| 690 |
|
|
| 2,000 |
|
|
| 19,537 |
|
|
| 26,977 |
| |||||||||||||||||||||
Secured Senior Notes |
|
| 17 |
|
|
| 19 |
|
|
| 16 |
|
|
| 17 |
|
|
| 19 |
|
|
| 243 |
|
|
| 331 |
| |||||||||||||||||||||
Tax-Exempt Financings |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 775 |
|
|
| 775 |
| |||||||||||||||||||||
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 10 |
|
|
| 10 |
| |||||||||||||||||||||
Unsecured Junior Subordinated Notes(4) |
|
| 1,250 |
|
|
| — |
|
|
| — |
|
|
| 700 |
|
|
| — |
|
|
| — |
|
|
| 1,950 |
| |||||||||||||||||||||
Enhanced Junior Subordinated Notes(5) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,485 |
|
|
| 1,485 |
| |||||||||||||||||||||
Total |
| $ | 2,110 |
|
| $ | 1,553 |
|
| $ | 2,966 |
|
| $ | 1,564 |
|
| $ | 2,019 |
|
| $ | 25,284 |
|
| $ | 35,496 |
| |||||||||||||||||||||
Weighted-average Coupon |
|
| 2.93 | % |
|
| 2.96 | % |
|
| 1.98 | % |
|
| 3.17 | % |
|
| 3.01 | % |
|
| 4.45 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companies’ short-term credit facilityfacilities and debt agreements, both short-term and long-term, debt agreements contain customary covenants and default provisions. As of December 31, 2020,2022, there were no events of default under these covenants.
Enhanced Junior Subordinated Notes
Senior Note IssuancesIn 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, assuming three-month LIBOR has been terminated and the October 2014 hybrids remain outstanding, interest will accrue at a SOFR-based rate selected by, and subject to any spread adjustment or other benchmark conforming changes implemented by, the Board of Governors of the Federal Reserve in accordance with the Adjustable Interest Rate (LIBOR) Act of 2022.
In FebruaryJuly 2016, Dominion Energy issued $800 million of 5.25% July 2016 hybrids. In August 2021, PSNC entered into an agreement with certain investors to issue through private placement in March 2021, $150 million 3.10% 30-year senior notes. The proceeds will be used for the repayment of existing indebtedness and for general corporate purposes.
Senior Note Redemptions
In March 2020, SCANADominion Energy redeemed its floating rate senior notes at the remaining principal balanceoutstanding of $66$800 million plus accrued interest. The notesof its July 2016 hybrids, which would have otherwise matured in June 2034.2076 and were listed on the NYSE under the symbol DRUA. Expenses related to the early redemption of the senior noteshybrids were $7$23 million reflected within interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2020.2021.
In March 2020, SCANA redeemed the remaining principal outstanding of $183 million of its 4.75% medium-term notes and $155 million of its 4.125% medium-term notes plus accrued interest and make-whole premiums. The notes would have otherwise matured in May 2021 and February 2022, respectively. Total expenses related to the early redemption of the medium-term notes were $14 million reflected within interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2020.
Enhanced Junior Subordinated Notes
In June 2006 and September 2006, Dominion Energy issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids and the September 2006 hybrids bore interest at the three-month LIBOR plus 2.825%, reset quarterly and at the three-month LIBOR plus 2.3%, reset quarterly, respectively. Dominion Energy executed RCCs in connection with its issuance of the June 2006 hybrids and the September 2006 hybrids. Under the terms of the RCCs, redemptions of the hybrids were subject to certain conditions. In 2019, Dominion Energy purchased and cancelled $12 million and $13 million of its June 2006 hybrids and September 2006 hybrids, respectively. In February 2020, Dominion Energy redeemed the remaining $111 million and $286 million of its June 2006 hybrids and September 2006 hybrids, respectively, both of which would have otherwise matured in 2066. All purchases were conducted in compliance with the applicable RCC, each of which was terminated in February 2020. Expenses related to the early redemption of the hybrids were $10 million reflected within interest and related charges in the Consolidated Statements of Income for the year ended December 31, 2020.
In October 2014, Dominion Energy issued $685 million of October 2014 hybrids that will bear interest at 5.75% per year until October 1, 2024. Thereafter, they will bear interest at the three-month LIBOR plus 3.057%, reset quarterly.
In July 2016, Dominion Energy issued $800 million of 5.25% July 2016 hybrids. The July 2016 hybrids are listed on the NYSE under the symbol DRUA.
Dominion Energy may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion Energy may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments during the deferral period. Also, during the deferral period, Dominion Energy may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids.
Remarketable Subordinated Notes
In June 2019, Dominion Energy successfully remarketed the $700 million 2016 Series A-1 2.0% RSNs due 2021 and $700 million 2016 Series A-2 2.0% RSNs due 2024 pursuant to the terms of the related 2016 Equity Units. In connection with the remarketing, the interest rates on the Series A-1 and Series A-2 notes were reset to 2.715% and 3.071%, respectively, payable on a semi-annual basis, and Dominion Energy ceased to have the ability to redeem the notes at its option or defer interest payments.
Dominion Energy did not receive any proceeds from the remarketing. Remarketing proceeds belonged to the investors holding the 2016 Equity Units and were temporarily used to purchase a portfolio of treasury securities. Upon maturity of the portfolio, the proceeds were applied on behalf of the investors on the related stock purchase contract settlement date to pay the purchase price to Dominion Energy for issuance of 18.5 million shares of its common stock in August 2019.
Derivative Restructuring
In June 2020, Dominion Energy amended a portfolio of interest rate swaps with a notional value of $2.0$2.0 billion, extending the mandatory termination dates from 2020 and 2021 to December 2024. The transaction is viewed as2024. As a result of this noncash financing activity with an embedded interest rate swap. As a result, in June 2020,swap, Dominion Energy recorded $326$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%1.19%, in its Consolidated Balance Sheets with an embedded
162
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 2022, Dominion Energy settled certain of the outstanding interest rate swaps which would have otherwise matured in December 2024, resulting in a $154 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$900 million, extending the mandatory termination dates from 2020 to December 2023. The transaction is viewed as2023. As a result of this noncash financing activity with an
embedded interest rate swap. As a result, in August 2020,swap, Virginia Power recorded $443$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%0.34%, in its Consolidated Balance Sheets with an embedded interest rate derivative that had a fair value of zero at inception. The interest rate swaps were in a hedge relationship prior to the transaction. Virginia Power de-designated the hedge relationships prior to the transaction and then designated the new interest rate swap in a hedge relationship after the transaction.
NOTE 19. PREFERRED STOCK
Dominion Energy is authorized to issue up to 20 million shares of preferred stock,which may be designated into separate classes. At both December 31, 2020 and 2019,2022, Dominion Energy had issued and outstanding 2.41.8 million shares preferred stock, 1.60.8 million and 1.0 million of which were designated as the Series B Preferred Stock and the Series C Preferred Stock, respectively. 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, and the Series B Preferred Stock and the Series C Preferred Stock, respectively.
DESC is authorized to issue up to 20 million shares of preferred stock. At both December 31, 20202022 and 2019,2021, 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$100 liquidation preference; however, 0nenone were issued and outstanding at December 31, 20202022 or 2019.2021.
2019 Corporate Units
In June 2019, Dominion Energy issued $1.6$1.6 billion of 2019 Equity Units, initially in the form of 2019 Series A Corporate Units. The Corporate Units arewere listed on the NYSE under the symbol DCUE. The net proceeds were used for general corporate purposes and to repay short-term debt, including commercial paper.
Each 2019 Series A Corporate Unit consistsconsisted of a stock purchase contract and a 1/10, or 10%10%, undivided beneficial ownership interest in one share of Series A Preferred Stock. Beginning in June 2022, the Series A Preferred Stock iswas convertible at the option of the holder into Dominion Energyholder. Settlement of any conversion was initially payable in cash, common stock underor a formula based uponcombination 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 average closing pricefirst $1,000 per share and in shares of Dominion Energy common stock, priorcash 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 conversion date.holders elect to convert the Series A Preferred Stock, $1.6 billion was reclassified from equity to mezzanine equity in 2021. The Series A Preferred Stock iswas redeemable in cash by Dominion Energy beginning September 2022 at the liquidation preference. Settlement of any conversion is payable in cash, common stock or a combination thereof, at Dominion Energy’s election.
The stock purchase contracts obligateobligated 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 $100was $100 per Corporate Unit and the number of shares to be purchased will bewas determined under a formula based upon the average closing price of Dominion Energy common stock near the settlement date. See Note 20 for additional information. The Series A Preferred Stock washad been pledged upon issuance as collateral to secure the purchase of common stock under the related stock purchase contracts.
Dominion Energy payspaid cumulative dividends on the Series A Preferred Stock and quarterly contract adjustment payments on the stock purchase contracts, at the rates described below.
163
Pursuant to the terms of the 2019 Equity Units, Dominion Energy may elect to pay such dividends and/or payments in cash,conducted a final remarketing of substantially all shares of Dominion Energy common stock or a combination of cash andSeries A Preferred Stock in May 2022 which resulted in the dividend rate for all shares of Dominion Energy common stock. Dominion Energy may deferSeries A Preferred Stock being reset to 1.75% for 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 deferralJune 2022 through August 2022 dividend 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 dividends6.75% effective September 2022. The conversion rate on the Series A Preferred Stock have been declared and paid,did not increase as a result of the remarketing. In May 2022, Dominion Energy may not make any distributions on anyreceived a commitment from a financial institution to purchase up to 1.6 million shares 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,in the final remarketing. Accordingly, following the settlement of the successful remarketing and approval from its Board of Directors in June 2022, Dominion Energy also may not make any contract adjustment payments or other similar typesbecame obligated to redeem all outstanding shares of payments, subjectSeries A Preferred Stock in September 2022. As such, effective June 2022, the Series A Preferred Stock was considered to certain exceptions.
be mandatorily redeemable and was classified as a current liability. In addition, Dominion Energy has recordedmade a short-term deposit at the present valuefinancial institution as described further in Note 9. Proceeds from the final remarketing were used on behalf of holders of 2019 Series A Corporate Units at the time of the stockremarketing to pay the purchase contract payments as a liability offsetprice to common stock. Stock purchase contract payments are recorded against this liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense. In calculating diluted EPS, Dominion Energy appliesfor the treasuryissuance of its common stock method tounder the stock purchase contracts and the if-converted method to theincluded in such corporate units in June 2022. In September 2022, Dominion Energy redeemed all outstanding shares of Series A Preferred Stock. Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, the maximum number of shares of common stock Dominion Energy will issue in June 2022 is 21.8 million.Stock for $1.6 billion.
Selected information about Dominion Energy’s 2019 Equity Units is presented below:
Issuance Date |
| Units Issued |
| Total Net |
|
| Total Preferred |
|
| Cumulative |
|
| Stock Purchase |
|
| Stock Purchase |
|
| Stock Purchase | |||||
(millions except interest rates) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
6/14/2019 |
| 16 |
| $ | 1,582 |
|
| $ | 1,610 |
|
|
| 1.75 | % |
|
| 5.5 | % |
| $ | 250 |
|
| 6/1/2022 |
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$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 Consolidated Balance Sheets at December 31, 2019.
issuance costs originally recognized as a reduction to preferred stock were reclassified to common stock.
In addition, Dominion Energy recorded interest expense of $
7 million on the Series A Preferred Stock for the year ended December 31, 2022, following the reclassification of these shares to a mandatorily redeemable liability effective June 2022 as discussed above.Series B Preferred Stock
In December 2019, Dominion Energy issued 800,000 shares of Series B Preferred Stock for $791$791 million, net of $9$9 million of issuance costs. The preferred stock has a liquidation preference of $1,000$1,000 per share and currently pays a 4.65%4.65% dividend per share on the liquidation preference. Dividends are paid cumulatively on a semi-annual basis, commencing June 15, 2020. Dominion Energy recorded dividends of $37$37 million ($46.50 per share) and $2 million ($1.9375 per share) for each of the years ended December 31, 20202022, 2021 and 2019, respectively.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%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$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$1,020 per share plus any accumulated and unpaid dividends at any time within a certain period of time following any change in the criteria ratings agencies use to assign equity credit to securities such as the Series B Preferred Stock that has certain adverse effects on the equity credit actually received by the Series B Preferred Stock.
Holders of the Series B Preferred Stock have no voting rights except in the limited circumstances provided for in the terms of the Series B Preferred Stock or as otherwise required by applicable law. The Series B Preferred Stock is not subject to any sinking fund or other obligation of ours to redeem, repurchase or retire the Series B Preferred Stock. The preferred stock contains no conversion rights.
NOTE 20. EQUITY
CommonSeries C Preferred Stock
Dominion Energy
During 2020, 2019, and 2018, Dominion Energy recorded, net of fees and commissions, $481 million, $11.0 billion and $2.5 billion from the issuance of approximately 7 million, 157 million and 36 million shares of common stock, respectively, for acquisitions, settlements of stock purchase contracts and litigation and through various programs including Dominion Energy Direct®, employee savings plans and an at-the-market program.
Acquisitions
During 2019,In December 2021, Dominion Energy issued 95.6 million750,000 shares of common stock in connection with the acquisitionSeries C Preferred Stock for $742 million, net of SCANA. At the time$8 million of issuance these common stockcosts. Also in December 2021, Dominion Energy issued 250,000 shares wereof Series C Preferred Stock valued at $6.8 billion. See Note 3 for further information on the issuance of Dominion Energy common stock in connection with the SCANA Combination.
In January 2019, Dominion Energy and Dominion Energy Midstream closed on an agreement and plan of merger pursuant to which Dominion Energy acquired each outstanding common unit representing limited partner interests in Dominion Energy Midstream not already owned by Dominion Energy through the issuance of 22.5 million shares of common stock valued at $1.6 billion. Under the terms of the agreement and plan of merger, each publicly held outstanding common unit representing limited partner interests in Dominion Energy Midstream was converted into the right to receive 0.2492 shares of Dominion Energy common stock. Immediately prior to the closing, each Series A Preferred Unit representing limited partner interests in Dominion Energy Midstream was converted into common units representing limited partner interests in Dominion Energy Midstream in accordance with the terms of Dominion Energy Midstream’s partnership agreement. The merger was accounted for by Dominion Energy following the guidance for a change
$250in 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 0 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. 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 $44 million ($43.50 per share) and $3 million ($2.6583 per share) and for the years ended December 31, 2022 and 2021, respectively. The dividend rate for the Series C Preferred Stock will be reset every five years beginning on April 15, 2027 to equal the
164
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 2022, 2021 and 2020, Dominion Energy recorded, net of fees and commissions, $2.0 billion, $340 million and $481 million from the issuance of approximately 25 million, 4 million and 7 million shares of common stock, respectively, as described below.
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$159 million from the issuance of 2.1 million of such shares through Dominion Energy Direct® and employee savings plans.In January 2021, Dominion Energy began issuing new shares of common stock for these direct stock purchase plans.
Stock Purchase Contracts
In August 2019, During 2022 and 2021, Dominion Energy issued 18.52.4 million shares under the related stock purchase contracts entered into as partand 2.6 million, respectively, of Dominion Energy’s 2016 Equity Unitssuch shares and received proceeds of $1.4 billion. See Note 18 for further information surrounding these stock purchase contracts.$179 million and $192 million, respectively.
Other Issuances
In September 2020, Dominion Energy issued 4.1 million shares of its common stock to satisfy its obligation under a settlement agreement for the Santee Cooper Ratepayer Case discussed in Note 23. These shares were immediately repurchased as discussed below.
At-the-Market Program
In June 2017, Dominion Energy entered into sales agency agreements to effect sales under an at-the-market program. In January 2018, Dominion Energy issued 6.6 million shares and received cash proceeds of $495 million, net of fees and commissions paid of $5 million, which completed the program.
In February 2018, Dominion Energy entered into sales agency agreements to effect sales under an at-the-market program. In the fourth quarter of 2018, Dominion Energy issued 2.7 million shares and received cash proceeds of $197 million, net of fees and commissions paid of $2 million. In the first quarter of 2019, Dominion Energy issued 2.1 million shares and received cash proceeds of $154 million, net of fees and commissions paid of $2 million. In the fourth quarter of 2019, Dominion Energy issued 7.8 million shares and received cash proceeds of $639 million, net of fees and commissions paid of $6 million. Following these issuances, Dominion Energy had no remaining capacity under this program.
In March 2020, Dominion Energy entered into sales agency agreements to effect sales under a $500$500 million at-the-market common stock program. Dominion Energy did 0tnot issue any shares under this program which expired in June 2020.
In August 2020, Dominion Energy entered into sales agency agreements to effect sales under a new at-the-market program. Under the sales agency agreements, Dominion Energy may, from time to time, offer and sell shares of its common stock through the sales agents or enter into one or more forward sale agreements with respect to shares of its common stock. Sales by Dominion Energy through the sales agents or by forward sellers pursuant to a forward sale agreement cannot exceed $1.0$1.0 billion in the aggregate. In November 2021, Dominion Energy has 0t issued any shares or entered into any forward sale agreements under this new program.
Forward Sale Agreements
In 2018,for approximately 1.1 million shares of its common stock to be settled by November 2022 at an initial forward price of $74.66 per share. Except in certain circumstances, Dominion Energy entered into separatecould have elected physical, cash or net settlement of the forward sale agreements. In November 2022, Dominion Energy provided notice to elect physical settlement of the forward sale agreements with Goldman Sachs & Co. LLC and Credit Suisse Capital LLC, as forward purchasers, and an underwriting agreement with Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC, as representativesin December 2022 received total proceeds of the several underwriters named therein, relating to an aggregate of 20$78 million.
Other Issuances
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 May 2022, Dominion Energy
issued 0.9common stock. The underwriting agreement granted the underwriters a 30-day option to purchase up to an additional 3 million shares of its common stock, valued at $72 million, to partially satisfy DESC’s remaining obligation under the settlement agreement.
In June 2022, Dominion Energy issued 0.4 million shares of its common stock, whichvalued at $30 million, to partially satisfy its obligation under a settlement agreement for the underwriters exercised with respect to approximately 2.1State Court Merger Case discussed in Note 23.
165
In June 2022, Dominion Energy issued 19.4 million shares of its common stock to settle the stock purchase contract component of the 2019 Equity Units, as discussed in April 2018. Dominion Energy entered into separate forward sale agreements with the forward purchasers with respect to the additional shares. In December 2018, Dominion EnergyNote 19, and received proceeds of $1.4 billion (after deducting underwriting discounts, but before deducting expenses, and subject$1.6 billion.
In July 2021, Dominion Energy issued 1.4 million shares of its common stock, valued at $104 million, to forward price adjustmentssatisfy DESC’s obligation under a settlement agreement for the forward sale agreements) upon the physical settlement of 22.1 million shares.FILOT litigation 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.
Repurchase of Common Stock
Dominion Energy did not repurchase any shares in 2022 or 2021, 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$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$3.0 billion of Dominion Energy’s common stock and rescinded its prior repurchase authorization approved in February 2005 and modified in June 2007. Dominion2007. 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$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$562 million. During the fourth quarter of 2020, Dominion energyEnergy repurchased 3.7 million shares of Dominion Energy common stock for $295$295 million.
In September 2020, Dominion Energy repurchased 4.1 million shares of Dominion Energy common stock in a private transaction for $323$323 million.
In September 2020, Dominion Energy entered into 2two prepaid accelerated share repurchase agreements with separate financial institutions as counterparties. Dominion Energy made payments totaling $1.5$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$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$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$400 million to the counterparty in exchange for an aggregate of 5.0 million shares of Dominion Energy common stock, which represented all $400$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$400 million.
In addition to the repurchases described above, Dominion Energy also repurchases shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which do not count against its stock repurchase authorization. Dominion Energy did 0t repurchase any shares in 2019 or 2018 except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock.
Virginia Power
In 2020, 2019,2022, 2021 and 2018,2020, 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%25% controlling interest in Cove Point to BHE
166
resulting in Dominion Energy’s remaining 50%50% noncontrolling interest accounted for as an equity method investment prospectively. As a result, the $1.4$1.4 billion of noncontrolling interest related to the 25%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 PointNon-Wholly-Owned Nonregulated Solar Facilities
In December 2019,2021, Dominion Energy completed the sale of its 25% noncontrolling limited partnershipSBL Holdco, which held Dominion Energy’s 67% controlling 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 oncertain nonregulated solar projects, and the sale of this interest.its
Remeasurement of Dominion Energy Midstream Units
In May 2018, all of the subordinated units of Dominion Energy Midstream held by Dominion Energy were converted into common units on a 1:1 ratio following the payment of Dominion Energy Midstream’s distribution for the first quarter of 2018. In June 2018, Dominion Energy, as general partner, exercised an incentive distribution right reset as defined50% controlling interest in Dominion Energy Midstream’s partnership agreementFour Brothers and received 27 million common units representing limited partner interests in Dominion Energy Midstream.Three Cedars. As a result of the increase in its ownership interest in Dominion Energy Midstream, Dominion Energythese sales, all balances recorded a decrease inas noncontrolling interest, and a corresponding increase in shareholders’ equity, of $375 million reflecting the change in the carrying value of the interest in the net assets of Dominion Energy Midstream held by others.interests associated with these entities were written off. See Note 10 for more information.
Accumulated Other Comprehensive Income (Loss)
Presented in the table below is a summary of AOCI by component:
At December 31, |
| 2020 |
|
| 2019 |
| ||
(millions) |
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
Net deferred losses on derivatives-hedging activities, net of $141 and $135 tax |
| $ | (419 | ) |
| $ | (407 | ) |
Net unrealized gains on nuclear decommissioning trust funds, net of $(21) and $(13) tax |
|
| 62 |
|
|
| 37 |
|
Net unrecognized pension and other postretirement benefit costs, net of $478 and $492 tax |
|
| (1,359 | ) |
|
| (1,421 | ) |
Other comprehensive loss from equity method investees, net of $— and $1 tax |
|
| (1 | ) |
|
| (2 | ) |
Total AOCI |
| $ | (1,717 | ) |
| $ | (1,793 | ) |
Virginia Power |
|
|
|
|
|
|
|
|
Net deferred losses on derivatives-hedging activities, net of $21 and $11 tax |
| $ | (60 | ) |
| $ | (34 | ) |
Net unrealized gains on nuclear decommissioning trust funds, net of $(3) and $(1) tax |
|
| 8 |
|
|
| 5 |
|
Total AOCI |
| $ | (52 | ) |
| $ | (29 | ) |
Dominion Energy
The following table presents Dominion Energy’s changes in AOCI by component, net(net of tax:
|
| Deferred gains and losses on derivatives-hedging activities |
|
| Unrealized gains and losses on investment securities |
|
| Unrecognized pension and other postretirement benefit costs |
|
| Other comprehensive loss from equity method investees |
|
| Total |
| |||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (407 | ) |
| $ | 37 |
|
| $ | (1,421 | ) |
| $ | (2 | ) |
| $ | (1,793 | ) |
Other comprehensive income before reclassifications: gains (losses) |
|
| (239 | ) |
|
| 43 |
|
|
| 25 |
|
|
| 1 |
|
|
| (170 | ) |
Amounts reclassified from AOCI: (gains) losses(1) |
|
| 227 |
|
|
| (18 | ) |
|
| 37 |
|
|
| — |
|
|
| 246 |
|
Net current period other comprehensive income (loss) |
|
| (12 | ) |
|
| 25 |
|
| �� | 62 |
|
|
| 1 |
|
|
| 76 |
|
Ending balance |
| $ | (419 | ) |
| $ | 62 |
|
| $ | (1,359 | ) |
| $ | (1 | ) |
| $ | (1,717 | ) |
Year Ended December 31, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (235 | ) |
| $ | 2 |
|
| $ | (1,465 | ) |
| $ | (2 | ) |
| $ | (1,700 | ) |
Other comprehensive income before reclassifications: gains (losses) |
|
| (110 | ) |
|
| 39 |
|
|
| (22 | ) |
|
| — |
|
|
| (93 | ) |
Amounts reclassified from AOCI: (gains) losses(1) |
|
| (62 | ) |
|
| (4 | ) |
|
| 66 |
|
|
| — |
|
|
| — |
|
Net current period other comprehensive income (loss) |
|
| (172 | ) |
|
| 35 |
|
|
| 44 |
|
|
| — |
|
|
| (93 | ) |
Ending balance |
| $ | (407 | ) |
| $ | 37 |
|
| $ | (1,421 | ) |
| $ | (2 | ) |
| $ | (1,793 | ) |
|
|
The following table presents Dominion Energy’stax) and reclassifications out of AOCI by component:
167
|
| Commodity |
|
| Interest |
|
| Total |
|
| Investment |
|
| Pension and |
|
| Equity |
|
| Total |
| |||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Year Ended December 31, 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Beginning balance |
| $ | — |
|
| $ | (358 | ) |
| $ | (358 | ) |
| $ | 37 |
|
| $ | (1,133 | ) |
| $ | (4 | ) |
| $ | (1,458 | ) |
Other |
|
| — |
|
|
| 67 |
|
|
| 67 |
|
|
| (100 | ) |
|
| (218 | ) |
|
| 1 |
|
|
| (250 | ) |
Amounts reclassified from AOCI (gains) losses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Interest and |
|
| — |
|
|
| 57 |
|
|
| 57 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 57 |
|
Other income |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 25 |
|
|
| 102 |
|
|
| — |
|
|
| 127 |
|
Total |
|
| — |
|
|
| 57 |
|
|
| 57 |
|
|
| 25 |
|
|
| 102 |
|
|
| — |
|
|
| 184 |
|
Income tax |
|
| — |
|
|
| (15 | ) |
|
| (15 | ) |
|
| (6 | ) |
|
| (27 | ) |
|
| — |
|
|
| (48 | ) |
Total, net of tax |
|
| — |
|
|
| 42 |
|
|
| 42 |
|
|
| 19 |
|
|
| 75 |
|
|
| — |
|
|
| 136 |
|
Net current |
|
| — |
|
|
| 109 |
|
|
| 109 |
|
|
| (81 | ) |
|
| (143 | ) |
|
| 1 |
|
|
| (114 | ) |
Ending balance |
| $ | — |
|
| $ | (249 | ) |
| $ | (249 | ) |
| $ | (44 | ) |
| $ | (1,276 | ) |
| $ | (3 | ) |
| $ | (1,572 | ) |
Year Ended December 31, 2021 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Beginning balance |
| $ | (1 | ) |
| $ | (418 | ) |
| $ | (419 | ) |
| $ | 62 |
|
| $ | (1,359 | ) |
| $ | (1 | ) |
| $ | (1,717 | ) |
Other |
|
| — |
|
|
| 15 |
|
|
| 15 |
|
|
| (7 | ) |
|
| 144 |
|
|
| (3 | ) |
|
| 149 |
|
Amounts reclassified from AOCI (gains) losses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Purchased gas |
|
| 1 |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
Interest and |
|
| — |
|
|
| 60 |
|
|
| 60 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 60 |
|
Other income |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (23 | ) |
|
| 111 |
|
|
| — |
|
|
| 88 |
|
Total |
|
| 1 |
|
|
| 60 |
|
|
| 61 |
|
|
| (23 | ) |
|
| 111 |
|
|
| — |
|
|
| 149 |
|
Income tax |
|
| — |
|
|
| (15 | ) |
|
| (15 | ) |
|
| 5 |
|
|
| (29 | ) |
|
| — |
|
|
| (39 | ) |
Total, net of tax |
|
| 1 |
|
|
| 45 |
|
|
| 46 |
|
|
| (18 | ) |
|
| 82 |
|
|
| — |
|
|
| 110 |
|
Net current |
|
| 1 |
|
|
| 60 |
|
|
| 61 |
|
|
| (25 | ) |
|
| 226 |
|
|
| (3 | ) |
|
| 259 |
|
Ending balance |
| $ | — |
|
| $ | (358 | ) |
| $ | (358 | ) |
| $ | 37 |
|
| $ | (1,133 | ) |
| $ | (4 | ) |
| $ | (1,458 | ) |
Details about AOCI components |
| Amounts reclassified from AOCI |
|
| Affected line item in the Consolidated Statements of Income | |
(millions) |
|
|
|
|
|
|
Year Ended December 31, 2020 |
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
|
Commodity contracts |
| $ | (25 | ) |
| Operating revenue |
|
|
| 4 |
|
| Purchased gas |
|
|
| (2 | ) |
| Discontinued operations |
Interest rate contracts |
|
| 83 |
|
| Interest and related charges |
|
|
| 236 |
|
| Discontinued operations |
Foreign currency contracts |
|
| 6 |
|
| Discontinued operations |
Total |
|
| 302 |
|
|
|
Tax |
|
| (75 | ) |
| Income tax expense |
Total, net of tax |
| $ | 227 |
|
|
|
Unrealized (gains) and losses on investment securities: |
|
|
|
|
|
|
Realized (gain) loss on sale of securities |
| $ | (24 | ) |
| Other income |
Total |
|
| (24 | ) |
|
|
Tax |
|
| 6 |
|
| Income tax expense |
Total, net of tax |
| $ | (18 | ) |
|
|
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
|
Amortization of prior-service costs (credits) |
| $ | (84 | ) |
| Other income |
Amortization of actuarial losses |
|
| 134 |
|
| Other income |
Total |
|
| 50 |
|
|
|
Tax |
|
| (13 | ) |
| Income tax expense |
Total, net of tax |
| $ | 37 |
|
|
|
Year Ended December 31, 2019 |
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
|
Commodity contracts |
| $ | (142 | ) |
| Operating revenue |
|
|
| 3 |
|
| Purchased gas |
|
|
| (4 | ) |
| Discontinued operations |
Interest rate contracts |
|
| 49 |
|
| Interest and related charges |
|
|
| 5 |
|
| Discontinued operations |
Foreign currency contracts |
|
| 6 |
|
| Discontinued operations |
Total |
|
| (83 | ) |
|
|
Tax |
|
| 21 |
|
| Income tax expense |
Total, net of tax |
| $ | (62 | ) |
|
|
Unrealized (gains) and losses on investment securities: |
|
|
|
|
|
|
Realized (gain) loss on sale of securities |
| $ | (5 | ) |
| Other income |
Total |
|
| (5 | ) |
|
|
Tax |
|
| 1 |
|
| Income tax expense |
Total, net of tax |
| $ | (4 | ) |
|
|
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
|
Prior-service costs (credits) |
| $ | (24 | ) |
| Other income |
Actuarial losses |
|
| 113 |
|
| Other income |
Total |
|
| 89 |
|
|
|
Tax |
|
| (23 | ) |
| Income tax expense |
Total, net of tax |
| $ | 66 |
|
|
|
168
Virginia Power
The following table presents Virginia Power’s changes in AOCI by component, net(net of tax:
|
| Deferred gains and losses on derivatives-hedging activities |
|
| Unrealized gains and losses on investment securities |
|
| Total |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (34 | ) |
| $ | 5 |
|
| $ | (29 | ) |
Other comprehensive income before reclassifications: gains (losses) |
|
| (28 | ) |
|
| 6 |
|
|
| (22 | ) |
Amounts reclassified from AOCI: (gains) losses(1) |
|
| 2 |
|
|
| (3 | ) |
|
| (1 | ) |
Net current period other comprehensive income (loss) |
|
| (26 | ) |
|
| 3 |
|
|
| (23 | ) |
Ending balance |
| $ | (60 | ) |
| $ | 8 |
|
| $ | (52 | ) |
Year Ended December 31, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (13 | ) |
| $ | 1 |
|
| $ | (12 | ) |
Other comprehensive income before reclassifications: gains (losses) |
|
| (22 | ) |
|
| 5 |
|
|
| (17 | ) |
Amounts reclassified from AOCI: gains (losses)(1) |
|
| 1 |
|
|
| (1 | ) |
|
| — |
|
Net current period other comprehensive income (loss) |
|
| (21 | ) |
|
| 4 |
|
|
| (17 | ) |
Ending balance |
| $ | (34 | ) |
| $ | 5 |
|
| $ | (29 | ) |
|
|
The following table presents Virginia Power’s reclassificationstax) and reclassification out of AOCI by component:
|
| Interest Rate |
|
| Total |
|
| Investment |
|
| Total |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Year Ended December 31, 2022 |
|
|
|
|
|
|
|
|
|
| ||||||
Beginning balance |
| $ | (45 | ) |
| $ | (45 | ) |
| $ | 4 |
|
| $ | (41 | ) |
Other |
|
| 60 |
|
|
| 60 |
|
|
| (11 | ) |
|
| 49 |
|
Amounts reclassified from AOCI (gains) losses: |
| |||||||||||||||
Interest and related |
|
| 2 |
|
|
| 2 |
|
|
| — |
|
|
| 2 |
|
Total |
|
| 2 |
|
|
| 2 |
|
|
| — |
|
|
| 2 |
|
Income tax expense |
|
| (1 | ) |
|
| (1 | ) |
|
| — |
|
|
| (1 | ) |
Total, net of tax |
|
| 1 |
|
|
| 1 |
|
|
| — |
|
|
| 1 |
|
Net current period other |
|
| 61 |
|
|
| 61 |
|
|
| (11 | ) |
|
| 50 |
|
Ending balance |
| $ | 16 |
|
| $ | 16 |
|
| $ | (7 | ) |
| $ | 9 |
|
Year Ended December 31, 2021 |
|
|
|
|
|
|
|
|
|
| ||||||
Beginning balance |
| $ | (60 | ) |
| $ | (60 | ) |
| $ | 8 |
|
| $ | (52 | ) |
Other |
|
| 13 |
|
|
| 13 |
|
|
| (2 | ) |
|
| 11 |
|
Amounts reclassified from AOCI (gains) losses: |
| |||||||||||||||
Interest and related |
|
| 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 |
|
| 15 |
|
|
| 15 |
|
|
| (4 | ) |
|
| 11 |
|
Ending balance |
| $ | (45 | ) |
| $ | (45 | ) |
| $ | 4 |
|
| $ | (41 | ) |
Details about AOCI components |
| Amounts reclassified from AOCI |
|
| Affected line item in the Consolidated Statements of Income | |
(millions) |
|
|
|
|
|
|
Year Ended December 31, 2020 |
|
|
|
|
|
|
(Gains) losses on cash flow hedges: |
|
|
|
|
|
|
Interest rate contracts |
| $ | 2 |
|
| Interest and related charges |
Total |
|
| 2 |
|
|
|
Tax |
|
| — |
|
| Income tax expense |
Total, net of tax |
| $ | 2 |
|
|
|
Unrealized (gains) and losses on investment securities: |
|
|
|
|
|
|
Realized (gain) loss on sale of securities |
| $ | (4 | ) |
| Other income |
Total |
|
| (4 | ) |
|
|
Tax |
|
| 1 |
|
| Income tax expense |
Total, net of tax |
| $ | (3 | ) |
|
|
Year Ended December 31, 2019 |
|
|
|
|
|
|
(Gains) losses on cash flow hedges: |
|
|
|
|
|
|
Interest rate contracts |
| $ | 1 |
|
| Interest and related charges |
Total |
|
| 1 |
|
|
|
Tax |
|
| — |
|
| Income tax expense |
Total, net of tax |
| $ | 1 |
|
|
|
Unrealized (gains) and losses on investment securities: |
|
|
|
|
|
|
Realized (gain) loss on sale of securities |
| $ | (2 | ) |
| Other income |
Total |
|
| (2 | ) |
|
|
Tax |
|
| 1 |
|
| Income tax expense |
Total, net of tax |
| $ | (1 | ) |
|
|
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.years. Option terms are
set at the discretion of the CGNCompensation 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, 2020,2022, approximately 2018 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 ofAt December 31, 2020,2022 and December 31, 2021, unrecognized compensation cost related to nonvested goal-based stock awards was immaterial.inconsequential.
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, 2022, 2021 and 2020 2019, and 2018 include $64$36 million, $46$42 million and $48$64 million,respectively, of compensation costs and $16$7 million, $11$9 million and $12$16 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.
169
Restricted Stock
Restricted stock grants are made to officers under Dominion Energy’s LTIP and may also be granted to certain key non-officer employees. The fair value of Dominion Energy’s restricted stock awards is equal to the closing price of Dominion Energy’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2020, 2019,2022, 2021 and 2018:2020:
|
| Shares (millions) |
|
| Weighted - Average Grant Date Fair Value |
| ||
Nonvested at December 31, 2019 |
|
| 1.4 |
|
| $ | 74.77 |
|
Granted |
|
| 0.5 |
|
|
| 81.74 |
|
Vested |
|
| (0.4 | ) |
|
| 74.39 |
|
Cancelled and forfeited |
|
| (0.1 | ) |
|
| 81.59 |
|
Nonvested at December 31, 2020 |
|
| 1.4 |
|
| $ | 77.41 |
|
Granted |
|
| 0.5 |
|
|
| 71.78 |
|
Vested |
|
| (0.5 | ) |
|
| 73.54 |
|
Cancelled and forfeited |
|
| (0.1 | ) |
|
| 75.57 |
|
Nonvested at December 31, 2021 |
|
| 1.3 |
|
| $ | 76.65 |
|
Granted |
|
| 0.6 |
|
|
| 75.08 |
|
Vested |
|
| (0.4 | ) |
|
| 77.87 |
|
Cancelled and forfeited |
|
| (0.1 | ) |
|
| 73.15 |
|
Nonvested at December 31, 2022 |
|
| 1.4 |
|
| $ | 75.56 |
|
|
| Shares |
|
| Weighted - average Grant Date Fair Value |
| ||
|
| (thousands) |
|
|
|
|
| |
Nonvested at December 31, 2017 |
|
| 1,043 |
|
| $ | 73.32 |
|
Granted |
|
| 534 |
|
|
| 72.92 |
|
Vested |
|
| (316 | ) |
|
| 73.59 |
|
Cancelled and forfeited |
|
| (53 | ) |
|
| 74.25 |
|
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 |
|
As of December 31, 2020,2022, unrecognized compensation cost related to nonvested restricted stock awards totaled $61$58 million and is expected to be recognized over a weighted-average period of 2.0 years. The fair value of restricted stock awards that vested was $35$31 million, $23$37 million and $23$35 million in 2020, 2019,2022, 2021 and 2018,2020, 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 0zero and 200%200% of the targeted amount based on the level of performance metrics achieved.
In February 2018,2019, a cash-based performance grant was made to officers. Payout of the performance grant occurred in January 20212022 based on the achievement of two performance metrics during 2018, 2019, 2020 and 2020:2021: 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 $6 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 occurred in January 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 with an additional payout based on Dominion Energy’s price-earnings ratio relative to that of the members of Dominion Energy’s peer compensation group. The total of the payout under the grant was $15$4 million, all of which was accrued aton December 31, 2020. 2022.
In February 2019,2021, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 20222024 based on the achievement of two performance metrics during 2019, 20202021, 2022 and 2021:2023: TSR relative to that of companies that are members of Dominion Energy’sEnergy’s compensation peer group and ROIC.There areis an additional opportunitiesopportunity to earn a portion of the award based on Dominion Energy’s absolute TSR or relative price-earnings ratio performance. At December 31, 2020,2022, the targeted amount of the three-year grant was $15$11 million and a liability of $14$4 million had been accrued for this award.
In February 2020,2022, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 20232025 based on the achievement of twothree performance metrics during 2020, 20212022, 2023 and 2022:2024: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group, Cumulative Operating EPS, 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.Non-Carbon Emitting Generation Capacity Performance. At December 31, 2020,2022, the targeted amount of the three-year grant was $16$17 million and a liability of $8$3 million had been accrued for this award.
170
NOTE 21. DIVIDEND RESTRICTIONS
The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be inconsistent with the public interest. At December 31, 2020,2022, 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%45%.
The Ohio and Utah Commissions may prohibit any public service company, including East Ohio and Questar Gas, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2020,2022, neither the Ohio Commission nor the Utah Commission had restricted the payment of dividends by East Ohio.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.
DESC’s bond indenture under which it issues first mortgage bonds contains provisions that could limit the payment of cash dividends on its common stock. DESC's bond indenture permits the payment of dividends on DESC's common stock only either (1) out of its Surplus (as defined in the bond indenture) or (2) in case there is no Surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. In addition, pursuant to the SCANA Merger Approval Order, the amount of any DESC dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry.
At December 31, 2020,2022, 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 established 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 AB Preferred Stock or Series BC 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.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
171
returns, including dividends, interest and realized and unrealized investment gains and losses. Since the market-related value recognizes changes in fair value over a four-year period, the future market-related value of pension plan assets will be impacted as previously unrecognized changes in fair value are recognized.
Dominion Energy’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns (losses) of $1.9$(3.0) billion and $2.1$1.5 billion in 20202022 and 2019,2021, respectively, versus expected returns of $933 million$1.1 billion and $848 million,$1.0 billion, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.
In the third quarter of 2020,2021, Dominion Energy remeasuredrecognized the effects of a curtailment for certain pension plans due to a curtailment resulting from entering an agreementoption that provided certain active employees a one-time choice to sell substantially alltransition to an enhanced defined contribution plan in lieu of its gas transmission and storage operations to BHE.accruing pension benefits for future services. The remeasurementcurtailment resulted in an increase in the pension benefit obligation of $497 million and a decrease in the fair value of the pension plan assets of $87 million. The impact of the remeasurement on net periodic pension benefit cost (credit) was recognized prospectively from the remeasurement date. The remeasurement increased the net periodic benefit credit by approximately $4 million for the year ending December 31, 2020, excluding the impacts of curtailments. The discount rate used for the remeasurement was 3.11% - 3.16% with all other assumptions used for the remeasurement consistent with the measurement as of December 31, 2019.
In the fourth quarter of 2020, Dominion Energy remeasured certain other postretirement benefit plans due to a curtailment and settlement resulting from Dominion Energy completing the GT&S Transaction. The remeasurement resulted in an increase in the accumulated postretirement benefit obligation of $16 million and a decrease in the fair value of the other postretirement benefit plan assets of $25 million. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 3.07% - 3.11%. The initial healthcare cost trend rate used for the remeasurement was 6.25% and decreased to 5.00% by 2025-2026. All other assumptions used for the remeasurement consistent with the measurement as of December 31, 2019.
Voluntary Retirement Program
In March 2019, the Companies announced a voluntary retirement program to employees that meet certain age and service requirements. In 2019, upon the determinations made concerning the number of employees that elected to participate in the program, Dominion Energy recorded a charge of $427 million ($319 million after-tax) included within other operations and maintenance expense ($251 million), other taxes ($21 million), other income ($111 million) and discontinued operations ($44 million) and Virginia Power recorded a charge of $198 million ($146 million after-tax) included within other operations and maintenance expense ($190 million) and other taxes ($8 million) in their respective Consolidated Statements of Income.
In the second quarter of 2019, Dominion Energy remeasured its pension and other postretirement benefit plans as a result of the voluntary retirement program. The remeasurement resulted in an increase in the pension benefit obligation of $484$26 million and an increase to net periodic pension cost of $2 million. The effects of the curtailment are included in the fair valuemeasurement of theDominion Energy’s 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. 2021.
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.
172
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, |
| 2022 |
|
| 2021 |
|
| 2022 |
|
| 2021 |
| ||||
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Changes in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Benefit obligation at beginning of year |
| $ | 10,890 |
|
| $ | 11,363 |
|
| $ | 1,537 |
|
| $ | 1,746 |
|
Service cost |
|
| 142 |
|
|
| 170 |
|
|
| 22 |
|
|
| 25 |
|
Interest cost |
|
| 333 |
|
|
| 317 |
|
|
| 45 |
|
|
| 46 |
|
Benefits paid |
|
| (511 | ) |
|
| (488 | ) |
|
| (97 | ) |
|
| (105 | ) |
Actuarial (gains) losses during the year |
|
| (2,716 | ) |
|
| (413 | ) |
|
| (361 | ) |
|
| (161 | ) |
Plan amendments |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (14 | ) |
Sale of Hope |
|
| (64 | ) |
|
| — |
|
|
| (19 | ) |
|
| — |
|
Settlements and curtailments(1) |
|
| (8 | ) |
|
| (59 | ) |
|
| — |
|
|
| — |
|
Benefit obligation at end of year |
| $ | 8,066 |
|
| $ | 10,890 |
|
| $ | 1,127 |
|
| $ | 1,537 |
|
Changes in fair value of plan assets: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Fair value of plan assets at beginning of year |
| $ | 11,945 |
|
| $ | 10,979 |
|
| $ | 2,323 |
|
| $ | 2,100 |
|
Actual return (loss) on plan assets |
|
| (2,556 | ) |
|
| 1,202 |
|
|
| (416 | ) |
|
| 294 |
|
Employer contributions |
|
| 9 |
|
|
| 284 |
|
|
| — |
|
|
| — |
|
Benefits paid |
|
| (511 | ) |
|
| (488 | ) |
|
| (62 | ) |
|
| (71 | ) |
Sale of Hope |
|
| (188 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Settlements(2) |
|
| (5 | ) |
|
| (32 | ) |
|
| — |
|
|
| — |
|
Fair value of plan assets at end of year |
| $ | 8,694 |
|
| $ | 11,945 |
|
| $ | 1,845 |
|
| $ | 2,323 |
|
Funded status at end of year |
| $ | 628 |
|
| $ | 1,055 |
|
| $ | 718 |
|
| $ | 786 |
|
Amounts recognized in the Consolidated Balance Sheets |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Noncurrent pension and other postretirement benefit assets |
| $ | 875 |
|
| $ | 1,246 |
|
| $ | 910 |
|
| $ | 1,064 |
|
Other current liabilities |
|
| (12 | ) |
|
| (12 | ) |
|
| (13 | ) |
|
| (15 | ) |
Noncurrent pension and other postretirement benefit liabilities |
|
| (235 | ) |
|
| (179 | ) |
|
| (179 | ) |
|
| (263 | ) |
Net amount recognized |
| $ | 628 |
|
| $ | 1,055 |
|
| $ | 718 |
|
| $ | 786 |
|
Significant assumptions used to determine benefit |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Discount rate |
| 5.65%-5.75% |
|
| 3.06%-3.19% |
|
| 5.69%-5.70% |
|
| 3.04%-3.11% |
| ||||
Weighted average rate of increase for compensation |
| 4.38% |
|
| 4.51% |
|
| n/a |
|
| n/a |
| ||||
Crediting interest rate for cash balance and similar plans |
| 4.40%-4.50% |
|
| 1.81%-1.94% |
|
| n/a |
|
| n/a |
|
|
| Pension Benefits |
|
| Other Postretirement Benefits |
| ||||||||||
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
| $ | 10,446 |
|
| $ | 8,500 |
|
| $ | 1,769 |
|
| $ | 1,363 |
|
Dominion Energy SCANA Combination (See Note 3) |
|
| — |
|
|
| 854 |
|
|
| — |
|
|
| 253 |
|
Service cost |
|
| 173 |
|
|
| 162 |
|
|
| 28 |
|
|
| 26 |
|
Interest cost |
|
| 351 |
|
|
| 394 |
|
|
| 58 |
|
|
| 68 |
|
Benefits paid |
|
| (461 | ) |
|
| (470 | ) |
|
| (120 | ) |
|
| (96 | ) |
Actuarial (gains) losses during the year |
|
| 992 |
|
|
| 1,054 |
|
|
| 33 |
|
|
| 111 |
|
Plan amendments |
|
| — |
|
|
| — |
|
|
| (6 | ) |
|
| — |
|
Settlements, curtailments and special termination benefits(1) |
|
| (138 | ) |
|
| (48 | ) |
|
| (16 | ) |
|
| 44 |
|
Benefit obligation at end of year |
| $ | 11,363 |
|
| $ | 10,446 |
|
| $ | 1,746 |
|
| $ | 1,769 |
|
Changes in fair value of plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
| $ | 9,631 |
|
| $ | 7,197 |
|
| $ | 1,880 |
|
| $ | 1,581 |
|
Dominion Energy SCANA Combination (See Note 3) |
|
| — |
|
|
| 727 |
|
|
| — |
|
|
| — |
|
Actual return (loss) on plan assets |
|
| 1,602 |
|
|
| 1,747 |
|
|
| 300 |
|
|
| 349 |
|
Employer contributions |
|
| 278 |
|
|
| 557 |
|
|
| 13 |
|
|
| 12 |
|
Benefits paid |
|
| (461 | ) |
|
| (470 | ) |
|
| (93 | ) |
|
| (62 | ) |
Settlements(2) |
|
| (71 | ) |
|
| (127 | ) |
|
| — |
|
|
| — |
|
Fair value of plan assets at end of year |
| $ | 10,979 |
|
| $ | 9,631 |
|
| $ | 2,100 |
|
| $ | 1,880 |
|
Funded status at end of year |
| $ | (384 | ) |
| $ | (815 | ) |
| $ | 354 |
|
| $ | 111 |
|
Amounts recognized in the Consolidated Balance Sheets at December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent pension and other postretirement benefit assets |
| $ | 1,054 |
|
| $ | 1,266 |
|
| $ | 650 |
|
| $ | 442 |
|
Other current liabilities |
|
| (14 | ) |
|
| (29 | ) |
|
| (15 | ) |
|
| (17 | ) |
Noncurrent pension and other postretirement benefit liabilities |
|
| (1,424 | ) |
|
| (2,052 | ) |
|
| (281 | ) |
|
| (314 | ) |
Net amount recognized |
| $ | (384 | ) |
| $ | (815 | ) |
| $ | 354 |
|
| $ | 111 |
|
Significant assumptions used to determine benefit obligations as of December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
| 2.73%–2.95% |
|
| 3.47%–3.63% |
|
| 2.69%–2.80% |
|
| 3.44%–3.52% |
| ||||
Weighted average rate of increase for compensation |
|
| 4.53 | % |
|
| 4.23 | % |
| n/a |
|
| n/a |
| ||
Crediting interest rate for cash balance and similar plans |
| 1.93% - 2.15% |
|
| 2.67-2.83% |
|
| n/a |
|
| n/a |
|
|
|
|
|
Actuarial lossesgains recognized during 2020 and 20192022 in Dominion Energy’s pension benefit obligations include a $1.0were $2.7 billion and a $1.1 billion loss, respectively, resultingprimarily driven by an increase in the discount rate. Actuarial gains recognized during 2021 in Dominion Energy’s pension benefit obligations were $413 million primarily from decreasesan increase in discount rates.rate. Actuarial lossesgains recognized during 20202022 in Dominion Energy’s other postretirement benefit obligations include a $149were $360 million loss resulting from a decreaseprimarily driven by an increase in the discount rates, and were partially offset by a $85 million actuarial gain as a result of a completed experience study in one of Dominion Energy’s other postretirement plans and the impact of an update to healthcare claims assumptions.rate. Actuarial lossesgains recognized during 20192021 in Dominion Energy’s other postretirement benefit obligations include a $168were $161 million loss resulting from a decreasean increase in discount rates, better than expected per capita claims experience and were partially offset by a $55 million actuarial gain as a result of the impact ofchanges in demographic and economic assumptions based on an update to healthcare claims and other healthcare-related cost assumptions.experience study completed in 2021.
The ABO for all of Dominion Energy’s defined benefit pension plans was $10.6$7.7 billion and $9.7$10.2 billion at December 31, 20202022 and 2019,2021, 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$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 millionThe shares of its commonpreferred stock valued at $499 million. The shares were contributed through athough private placement,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
registrations registration rights on customary terms with respect to the shares.shares of preferred stock. Dominion Energy expectsis not required to make $17 million ofany contributions forto its qualified defined benefit pension plans in 2021.2023. Dominion Energy considers voluntary contributions from time to time, either in the form of cash or equity securities.
173
Certain of Dominion Energy’s subsidiaries fund other postretirement benefit costs through VEBAs. Dominion Energy’s remaining subsidiaries do notnot prefund other postretirement benefit costs but instead pay claims as presented. Dominion Energy did 0tnot make any contributions to VEBAs associated with its other postretirement plans in 2020.2022 and 2021. Dominion Energy is not required to make any contributions to its VEBAs associated with its other postretirement plans in 2023. 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 |
| ||||||||||
As of December 31, |
| 2022 |
|
| 2021 |
|
| 2022 |
|
| 2021 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Benefit obligation |
| $ | 7,655 |
|
| $ | 9,420 |
|
| $ | 197 |
|
| $ | 261 |
|
Fair value of plan assets |
|
| 7,410 |
|
|
| 9,229 |
|
|
| 5 |
|
|
| 7 |
|
|
| Pension Benefits |
|
| Other Postretirement Benefits |
| ||||||||||
As of December 31, |
| 2020 |
|
| 2019 |
|
| 2020(1) |
|
| 2019 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation |
| $ | 10,697 |
|
| $ | 9,552 |
|
| $ | 305 |
|
| $ | 341 |
|
Fair value of plan assets |
|
| 9,259 |
|
|
| 7,471 |
|
|
| 9 |
|
|
| 10 |
|
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, |
| 2022 |
|
| 2021 |
| ||
(millions) |
|
|
|
|
|
| ||
Accumulated benefit obligation |
| $ | 776 |
|
| $ | 127 |
|
Fair value of plan assets |
|
| 623 |
|
|
| 53 |
|
As of December 31, |
| 2020 |
|
| 2019 |
| ||
(millions) |
|
|
|
|
|
|
|
|
Accumulated benefit obligation |
| $ | 9,970 |
|
| $ | 8,852 |
|
Fair value of plan assets |
|
| 9,259 |
|
|
| 7,471 |
|
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 |
|
| Estimated Future Benefit Payments |
| ||||||||||
|
| Pension Benefits |
|
| Other Postretirement Benefits |
|
| Pension Benefits |
|
| Other Postretirement |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Dominion Energy |
|
|
|
|
|
|
|
| ||||||||
2021 |
| $ | 486 |
|
| $ | 110 |
| ||||||||
2022 |
|
| 512 |
|
|
| 108 |
| ||||||||
2023 |
|
| 515 |
|
|
| 106 |
|
| $ | 518 |
|
| $ | 99 |
|
2024 |
|
| 533 |
|
|
| 104 |
|
|
| 527 |
|
|
| 97 |
|
2025 |
|
| 535 |
|
|
| 101 |
|
|
| 542 |
|
|
| 96 |
|
2026-2030 |
|
| 2,792 |
|
|
| 478 |
| ||||||||
2026 |
|
| 551 |
|
|
| 94 |
| ||||||||
2027 |
|
| 560 |
|
|
| 93 |
| ||||||||
2028-2032 |
|
| 2,925 |
|
|
| 433 |
|
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 long-term strategic target asset allocations for substantially all of Dominion Energy’s pension funds are 28%26% U.S. equity, 18%19% non-U.S. equity, 35%32% fixed income, 3%3% real estateassets and 16%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, mid-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 equityassets include investments in real estate investment trusts and investments inprivate partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.
174
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 6.2.
The fair values of Dominion Energy’s pension plan assets by asset category are as follows:
At December 31, |
| 2022 |
|
| 2021 |
| ||||||||||||||||||||||||||
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Cash and cash equivalents |
| $ | 14 |
|
| $ | 11 |
|
| $ | — |
|
| $ | 25 |
|
| $ | 25 |
|
| $ | 5 |
|
| $ | — |
|
| $ | 30 |
|
Common and preferred stocks: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
U.S.(1) |
|
| 1,653 |
|
|
| 170 |
|
|
| — |
|
|
| 1,823 |
|
|
| 2,592 |
|
|
| 244 |
|
|
| — |
|
|
| 2,836 |
|
International |
|
| 1,034 |
|
|
| 5 |
|
|
| — |
|
|
| 1,039 |
|
|
| 1,773 |
|
|
| 19 |
|
|
| — |
|
|
| 1,792 |
|
Insurance contracts |
|
| — |
|
|
| 166 |
|
|
| — |
|
|
| 166 |
|
|
| — |
|
|
| 279 |
|
|
| — |
|
|
| 279 |
|
Corporate debt instruments |
|
| 65 |
|
|
| 805 |
|
|
| — |
|
|
| 870 |
|
|
| 81 |
|
|
| 1,439 |
|
|
| — |
|
|
| 1,520 |
|
Government securities |
|
| 46 |
|
|
| 1,377 |
|
|
| — |
|
|
| 1,423 |
|
|
| 39 |
|
|
| 914 |
|
|
| — |
|
|
| 953 |
|
Total recorded at fair value |
| $ | 2,812 |
|
| $ | 2,534 |
|
| $ | — |
|
| $ | 5,346 |
|
| $ | 4,510 |
|
| $ | 2,900 |
|
| $ | — |
|
| $ | 7,410 |
|
Assets recorded at NAV(2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Common/collective trust funds |
|
|
|
|
|
|
|
|
|
|
| 1,780 |
|
|
|
|
|
|
|
|
|
|
|
| 3,010 |
| ||||||
Alternative investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Real estate funds |
|
|
|
|
|
|
|
|
|
|
| 66 |
|
|
|
|
|
|
|
|
|
|
|
| 116 |
| ||||||
Private equity funds |
|
|
|
|
|
|
|
|
|
|
| 1,284 |
|
|
|
|
|
|
|
|
|
|
|
| 1,233 |
| ||||||
Debt funds |
|
|
|
|
|
|
|
|
|
|
| 192 |
|
|
|
|
|
|
|
|
|
|
|
| 162 |
| ||||||
Hedge funds |
|
|
|
|
|
|
|
|
|
|
| 2 |
|
|
|
|
|
|
|
|
|
|
|
| 14 |
| ||||||
Total recorded at NAV |
|
|
|
|
|
|
|
|
|
| $ | 3,324 |
|
|
|
|
|
|
|
|
|
|
| $ | 4,535 |
| ||||||
Total investments(3) |
|
|
|
|
|
|
|
|
|
| $ | 8,670 |
|
|
|
|
|
|
|
|
|
|
| $ | 11,945 |
|
At December 31, |
| 2020 |
|
| 2019 |
| ||||||||||||||||||||||||||
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 20 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 21 |
|
| $ | 22 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 23 |
|
Common and preferred stocks: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.(1) |
|
| 2,405 |
|
|
| — |
|
|
| — |
|
|
| 2,405 |
|
|
| 2,284 |
|
|
| — |
|
|
| — |
|
|
| 2,284 |
|
International |
|
| 1,727 |
|
|
| — |
|
|
| — |
|
|
| 1,727 |
|
|
| 1,634 |
|
|
| — |
|
|
| — |
|
|
| 1,634 |
|
Insurance contracts |
|
| — |
|
|
| 409 |
|
|
| — |
|
|
| 409 |
|
|
| — |
|
|
| 360 |
|
|
| — |
|
|
| 360 |
|
Corporate debt instruments |
|
| 32 |
|
|
| 1,385 |
|
|
| — |
|
|
| 1,417 |
|
|
| 273 |
|
|
| 859 |
|
|
| — |
|
|
| 1,132 |
|
Government securities |
|
| 30 |
|
|
| 772 |
|
|
| — |
|
|
| 802 |
|
|
| 58 |
|
|
| 757 |
|
|
| — |
|
|
| 815 |
|
Total recorded at fair value |
| $ | 4,214 |
|
| $ | 2,567 |
|
| $ | — |
|
| $ | 6,781 |
|
| $ | 4,271 |
|
| $ | 1,977 |
|
| $ | — |
|
| $ | 6,248 |
|
Assets recorded at NAV(2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common/collective trust funds |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2,905 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2,355 |
|
Alternative investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Real estate funds |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 108 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 91 |
|
Private equity funds |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 856 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 787 |
|
Debt funds |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 168 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 159 |
|
Hedge funds |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 14 |
|
Total recorded at NAV |
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 4,050 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 3,406 |
|
Total investments(3) |
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 10,831 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 9,654 |
|
175
|
|
|
|
|
|
The fair values of Dominion Energy’s other postretirement plan assets by asset category are as follows:
At December 31, |
| 2022 |
|
| 2021 |
| ||||||||||||||||||||||||||
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Cash and cash equivalents |
| $ | 3 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 4 |
|
| $ | 3 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 4 |
|
Common and preferred stocks: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
U.S.(1) |
|
| 685 |
|
|
| 10 |
|
|
| — |
|
|
| 695 |
|
|
| 898 |
|
|
| 14 |
|
|
| — |
|
|
| 912 |
|
International |
|
| 181 |
|
|
| — |
|
|
| — |
|
|
| 181 |
|
|
| 256 |
|
|
| 1 |
|
|
| — |
|
|
| 257 |
|
Insurance contracts |
|
| — |
|
|
| 10 |
|
|
| — |
|
|
| 10 |
|
|
| — |
|
|
| 16 |
|
|
| — |
|
|
| 16 |
|
Corporate debt instruments |
|
| 4 |
|
|
| 38 |
|
|
| — |
|
|
| 42 |
|
|
| 5 |
|
|
| 61 |
|
|
| — |
|
|
| 66 |
|
Government securities |
|
| 3 |
|
|
| 79 |
|
|
| — |
|
|
| 82 |
|
|
| 2 |
|
|
| 47 |
|
|
| — |
|
|
| 49 |
|
Total recorded at fair value |
| $ | 876 |
|
| $ | 138 |
|
| $ | — |
|
| $ | 1,014 |
|
| $ | 1,164 |
|
| $ | 140 |
|
| $ | — |
|
| $ | 1,304 |
|
Assets recorded at NAV(2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Common/collective trust funds |
|
|
|
|
|
|
|
|
|
|
| 649 |
|
|
|
|
|
|
|
|
|
|
|
| 840 |
| ||||||
Alternative investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Real estate funds |
|
|
|
|
|
|
|
|
|
|
| 11 |
|
|
|
|
|
|
|
|
|
|
|
| 13 |
| ||||||
Private equity funds |
|
|
|
|
|
|
|
|
|
|
| 158 |
|
|
|
|
|
|
|
|
|
|
|
| 152 |
| ||||||
Debt funds |
|
|
|
|
|
|
|
|
|
|
| 11 |
|
|
|
|
|
|
|
|
|
|
|
| 9 |
| ||||||
Hedge funds |
|
|
|
|
|
|
|
|
|
|
| — |
|
|
|
|
|
|
|
|
|
|
|
| 1 |
| ||||||
Total recorded at NAV |
|
|
|
|
|
|
|
|
|
| $ | 829 |
|
|
|
|
|
|
|
|
|
|
| $ | 1,015 |
| ||||||
Total investments(3) |
|
|
|
|
|
|
|
|
|
| $ | 1,843 |
|
|
|
|
|
|
|
|
|
|
| $ | 2,319 |
|
At December 31, |
| 2020 |
|
| 2019 |
| ||||||||||||||||||||||||||
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | — |
|
| $ | 2 |
|
| $ | — |
|
| $ | 2 |
|
| $ | 2 |
|
| $ | — |
|
| $ | — |
|
| $ | 2 |
|
Common and preferred stocks: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 817 |
|
|
| — |
|
|
| — |
|
|
| 817 |
|
|
| 719 |
|
|
| — |
|
|
| — |
|
|
| 719 |
|
International |
|
| 240 |
|
|
| — |
|
|
| — |
|
|
| 240 |
|
|
| 206 |
|
|
| — |
|
|
| — |
|
|
| 206 |
|
Insurance contracts |
|
| — |
|
|
| 23 |
|
|
| — |
|
|
| 23 |
|
|
| — |
|
|
| 21 |
|
|
| — |
|
|
| 21 |
|
Corporate debt instruments |
|
| 2 |
|
|
| 60 |
|
|
| — |
|
|
| 62 |
|
|
| 1 |
|
|
| 50 |
|
|
| — |
|
|
| 51 |
|
Government securities |
|
| 2 |
|
|
| 42 |
|
|
| — |
|
|
| 44 |
|
|
| 2 |
|
|
| 44 |
|
|
| — |
|
|
| 46 |
|
Total recorded at fair value |
| $ | 1,061 |
|
| $ | 127 |
|
| $ | — |
|
| $ | 1,188 |
|
| $ | 930 |
|
| $ | 115 |
|
| $ | — |
|
| $ | 1,045 |
|
Assets recorded at NAV(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common/collective trust funds |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 765 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 717 |
|
Alternative investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Real estate funds |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 8 |
|
Private equity funds |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 117 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 100 |
|
Debt funds |
|
|
|
|
|
|
| �� |
|
|
|
|
|
| 10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 10 |
|
Hedge funds |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 1 |
|
Total recorded at NAV |
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 903 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 836 |
|
Total investments(2) |
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 2,091 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 1,881 |
|
|
|
|
|
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—Represents interest-bearing cash, foreign cash, and money market fund. Interest bearing cash and money market fund are valued at cost plus accrued interest. The foreign cash balances are valued at the amount held and translated on the reporting date based on prevailing exchange rates. Foreign cash and money market funds are classified as Level 1. The interest bearing cash is held in variation margin and with various brokers, which are less liquid and therefore has been classified as Level 2. 2021 investments were held primarily in short-term notes and treasury bills, 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. Investments in preferred stocks are classified as Level 2 and 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. • Insurance Contracts—Investments in Group Annuity Contracts 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 176 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 restrictions during the term of the investment. • Alternative Investments—Investments in real estate funds, private equity funds, debt funds and hedge funds are stated at fair value based on the NAV of the plan’s proportionate share of the partnership, joint venture or other alternative investment’s fair value as determined by reference to audited financial statements or NAV statements provided by the investment manager. The NAV, which is used as a practical expedient to estimate fair value, is adjusted for contributions and distributions occurring between the investment manager and Dominion Energy’s measurement date. These valuations also involve assumptions and methods that are reviewed, evaluated, and adjusted, if necessary, by Dominion Energy.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Periodic Benefit (Credit) Cost
The service cost component of net periodic benefit (credit) cost is reflected in other operations and maintenance expense in Dominion Energy’s Consolidated Statements of Income,, except for $13 million, $16$1 million and $18$13 million for the years ended December 31, 2020, 20192021 and 2018,2020, respectively, presented in discontinued operations. There were no such amounts reflected in discontinued operations for 2022. 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, |
| 2022 |
|
| 2021 |
|
| 2020 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Service cost |
| $ | 142 |
|
| $ | 170 |
|
| $ | 173 |
|
| $ | 22 |
|
| $ | 25 |
|
| $ | 28 |
|
Interest cost |
|
| 333 |
|
|
| 317 |
|
|
| 351 |
|
|
| 45 |
|
|
| 46 |
|
|
| 58 |
|
Expected return on plan assets |
|
| (886 | ) |
|
| (834 | ) |
|
| (777 | ) |
|
| (191 | ) |
|
| (173 | ) |
|
| (156 | ) |
Amortization of prior service (credit) cost |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| (38 | ) |
|
| (42 | ) |
|
| (49 | ) |
Amortization of net actuarial (gain) loss |
|
| 159 |
|
|
| 193 |
|
|
| 206 |
|
|
| (2 | ) |
|
| 4 |
|
|
| 6 |
|
Settlements, curtailments and special termination |
|
| — |
|
|
| 10 |
|
|
| 14 |
|
|
| (8 | ) |
|
| — |
|
|
| (59 | ) |
Net periodic benefit (credit) cost |
| $ | (252 | ) |
| $ | (144 | ) |
| $ | (32 | ) |
| $ | (172 | ) |
| $ | (140 | ) |
| $ | (172 | ) |
Changes in plan assets and benefit obligations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Current year net actuarial (gain) loss |
| $ | 726 |
|
| $ | (782 | ) |
| $ | 166 |
|
| $ | 246 |
|
| $ | (282 | ) |
| $ | (110 | ) |
Prior service (credit) cost |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (13 | ) |
|
| (6 | ) |
Settlements and curtailments(1) |
|
| (3 | ) |
|
| (36 | ) |
|
| (81 | ) |
|
| 10 |
|
|
| — |
|
|
| 59 |
|
Less amounts included in net periodic benefit |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Amortization of net actuarial gain (loss) |
|
| (159 | ) |
|
| (193 | ) |
|
| (206 | ) |
|
| 2 |
|
|
| (4 | ) |
|
| (6 | ) |
Amortization of prior service credit (cost) |
|
| — |
|
|
| — |
|
|
| (1 | ) |
|
| 38 |
|
|
| 42 |
|
|
| 49 |
|
Sale of Hope |
|
| (47 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total recognized in other comprehensive |
| $ | 517 |
|
| $ | (1,011 | ) |
| $ | (122 | ) |
| $ | 296 |
|
| $ | (257 | ) |
| $ | (14 | ) |
Significant assumptions used to determine |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Discount rate |
| 3.06%-3.19% |
|
| 2.73%-3.29% |
|
| 2.77%-3.63% |
|
| 3.04%-5.03% |
|
| 2.69%-2.80% |
|
| 3.07%-3.52% |
| ||||||
Expected long-term rate of return on plan assets |
| 7.00%-8.35% |
|
| 7.00%-8.45% |
|
| 7.00%-8.60% |
|
| 8.35% |
|
| 8.45% |
|
| 8.50% |
| ||||||
Weighted average rate of increase for |
| 4.51% |
|
| 4.53% |
|
| 4.23% |
|
| n/a |
|
| n/a |
|
| n/a |
| ||||||
Crediting interest rate for cash balance and similar |
| 1.81%-1.94% |
|
| 1.93%-2.15% |
|
| 2.31-2.83% |
|
| n/a |
|
| n/a |
|
| n/a |
| ||||||
Healthcare cost trend rate(2) |
|
|
|
|
|
|
|
|
|
| 6.25% |
|
| 6.25% |
|
| 6.25% |
| ||||||
Rate to which the cost trend rate is assumed to |
|
|
|
|
|
|
|
|
|
| 5.00% |
|
| 5.00% |
|
| 5.00% |
| ||||||
Year that the rate reaches the ultimate trend rate(2) |
|
|
|
|
|
|
|
|
|
| 2026-2027 |
|
| 2026-2027 |
|
| 2025-2026 |
|
177
|
| Pension Benefits |
|
| Other Postretirement Benefits |
| ||||||||||||||||||
Year Ended December 31, |
| 2020 |
|
| 2019 |
|
| 2018 |
|
| 2020 |
|
| 2019 |
|
| 2018 |
| ||||||
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
| $ | 173 |
|
| $ | 162 |
|
| $ | 157 |
|
| $ | 28 |
|
| $ | 26 |
|
| $ | 27 |
|
Interest cost |
|
| 351 |
|
|
| 394 |
|
|
| 337 |
|
|
| 58 |
|
|
| 68 |
|
|
| 56 |
|
Expected return on plan assets |
|
| (777 | ) |
|
| (708 | ) |
|
| (663 | ) |
|
| (156 | ) |
|
| (140 | ) |
|
| (143 | ) |
Amortization of prior service (credit) cost |
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
|
| (49 | ) |
|
| (52 | ) |
|
| (52 | ) |
Amortization of net actuarial loss |
|
| 206 |
|
|
| 172 |
|
|
| 193 |
|
|
| 6 |
|
|
| 10 |
|
|
| 11 |
|
Settlements, curtailments and special termination benefits |
|
| 14 |
|
|
| 72 |
|
|
| — |
|
|
| (59 | ) |
|
| 42 |
|
|
| — |
|
Net periodic benefit (credit) cost |
| $ | (32 | ) |
| $ | 93 |
|
| $ | 25 |
|
| $ | (172 | ) |
| $ | (46 | ) |
| $ | (101 | ) |
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current year net actuarial (gain) loss |
| $ | 166 |
|
| $ | 16 |
|
| $ | 490 |
|
| $ | (110 | ) |
| $ | (98 | ) |
| $ | 78 |
|
Prior service (credit) cost |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (6 | ) |
|
| 2 |
|
|
| (4 | ) |
Settlements and curtailments |
|
| (81 | ) |
|
| 6 |
|
|
| — |
|
|
| 59 |
|
|
| — |
|
|
| — |
|
Less amounts included in net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of net actuarial loss |
|
| (206 | ) |
|
| (172 | ) |
|
| (193 | ) |
|
| (6 | ) |
|
| (10 | ) |
|
| (11 | ) |
Amortization of prior service credit (cost) |
|
| (1 | ) |
|
| (1 | ) |
|
| (1 | ) |
|
| 49 |
|
|
| 52 |
|
|
| 52 |
|
Total recognized in other comprehensive income and regulatory assets and liabilities |
| $ | (122 | ) |
| $ | (151 | ) |
| $ | 296 |
|
| $ | (14 | ) |
| $ | (54 | ) |
| $ | 115 |
|
Significant assumptions used to determine periodic cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
| 2.77%-3.63% |
|
| 3.57%-4.43% |
|
| 3.80%-3.81% |
|
| 3.07%-3.52% |
|
| 4.05% to 4.41% |
|
| 3.76% |
| ||||||
Expected long-term rate of return on plan assets |
| 7.00%-8.60% |
|
| 7.00% -8.65% |
|
|
| 8.75 | % |
|
| 8.50 | % |
|
| 8.50 | % |
|
| 8.50 | % | ||
Weighted average rate of increase for compensation |
|
| 4.23 | % |
|
| 4.20 | % |
|
| 4.09 | % |
| n/a |
|
| n/a |
|
| n/a |
| |||
Crediting interest rate for cash balance and similar plans |
| 2.31-2.83% |
|
| 2.77-3.63% |
|
| 3.00-3.01% |
|
| n/a |
|
| n/a |
|
| n/a |
| ||||||
Healthcare cost trend rate(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 6.25 | % |
| 6.50% to 6.60% |
|
|
| 7.00 | % | |
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) |
|
|
|
|
|
|
|
|
|
|
|
|
| 2025-2026 |
|
| 2023-2025 |
|
| 2022 |
|
|
|
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 |
| ||||||||||
At December 31, |
| 2022 |
|
| 2021 |
|
| 2022 |
|
| 2021 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Net actuarial loss |
| $ | 2,714 |
|
| $ | 2,198 |
|
| $ | 84 |
|
| $ | (166 | ) |
Prior service (credit) cost |
|
| 3 |
|
|
| 2 |
|
|
| (157 | ) |
|
| (203 | ) |
Total(1) |
| $ | 2,717 |
|
| $ | 2,200 |
|
| $ | (73 | ) |
| $ | (369 | ) |
|
| Pension Benefits |
|
| Other Postretirement Benefits |
| ||||||||||
At December 31, |
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial loss |
| $ | 3,207 |
|
| $ | 3,327 |
|
| $ | 120 |
|
| $ | 241 |
|
Prior service (credit) cost |
|
| 4 |
|
|
| 5 |
|
|
| (232 | ) |
|
| (339 | ) |
Total(1) |
| $ | 3,211 |
|
| $ | 3,332 |
|
| $ | (112 | ) |
| $ | (98 | ) |
|
|
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 2022, 2021 and 2020, Virginia Power made a paymentpayments to Dominion Energy for $313of $172 million, $151 million and $313 million, respectively, related to its participation in the Dominion Energy Pension Plan. In addition, in December 2020, Dominion Energy notified Virginia Power of a required contribution of $151 million, recorded in payables to affiliates in Virginia Power’s Consolidated Balance Sheets at December 31, 2020. Virginia Power’s net periodic pension cost related to this plan was $118$72 million, $152$86 million and $126$118 million in 2020, 20192022, 2021 and 2018,2020, respectively. Net periodic benefit (credit) cost is reflected in other operations and maintenance expense in Virginia Power’s Consolidated Statements of IncomeIncome. The funded status of various Dominion Energy subsidiary groups and employee compensation are the basis for determining the share of total pension costs for participating Dominion Energy subsidiaries. See Note 25 for Virginia Power amounts due to/from Dominion Energy related to this plan.
Retiree healthcare and life insurance benefits, for Virginia Power employees are covered by the Dominion Energy Retiree Health and Welfare Plan described above. Virginia Power’s net periodic benefit (credit) cost related to this plan was $(58)$(81) million, $(27)$(72) million and $(51)$(58) million in 2020, 20192022, 2021 and 2018,2020, respectively. Net periodic benefit (credit) cost is reflected in other operations and
178
maintenance expense in Virginia Power’s Consolidated Statements of Income. Employee headcount is the basis for determining the share of total other postretirement benefit costs for participating Dominion Energy subsidiaries. See Note 25 for Virginia Power amounts due to/from Dominion Energy related to this plan.
Dominion Energy holds investments in trusts to fund employee benefit payments for the pension and other postretirement benefit plans in which Virginia Power’s employees participate. Any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that Virginia Power will provide to Dominion Energy for its share of employee benefit plan contributions.
Virginia Power funds other postretirement benefit costs through VEBAs. During 20202022, 2021 and 2019,2020, Virginia Power made 0no contributions to the VEBAs and does 0tnot expect to contribute to the VEBAs in 2021.2023.
Defined Contribution Plans
Dominion Energy also sponsors defined contribution employee savings plans that cover substantially all employees. During 2020, 20192022, 2021 and 2018,2020, Dominion Energy recognized $67$75 million, $69$65 million and $46$67 million, respectively, as employer matching contributions to these plans, excluding discontinued operations. Virginia Power also participates in these employee savings plans. During 2020, 20192022, 2021 and 2018,2020, Virginia Power recognized $19$22 million, $20$20 million and $20$19 million, respectively, as employer matching contributions to these plans.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 address allmeet 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.
MATS
In February 2019, the EPA published a proposed rule to reverse its previous finding that it is appropriate and necessary to regulate hazardous air pollutant emissions from coal- and oil-fired electric generating units. In May 2020, the EPA’s final rule became effective. The final rule is consistent with the EPA’s February 2019 proposal, and determines that it is not appropriate and necessary to regulate mercury and hazardous air pollutant emissions from coal- and oil-fired electric generating units. The final rule also states
that the MATS rule remains in place and the emissions standards for affected coal- and oil-fired electric generating units will not change. The Companies are complying with the applicable requirements of the rule and do not expect any material impacts to their operations.
Ozone Standards
The EPA published final non-attainment designations for the October 2015 ozone standard in June 2018. States have until August 20212018 with states required to develop plans to address the new standard. UntilCertain states in which the statesCompanies 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
179
expenditures required to implement additional controls could have a material impact on the Companies’ results of operations and cash flows.
Oil and Gas NSPS
In August 2012, the EPA issued an NSPS impacting new and modified facilities in the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of VOC emissions for natural gas production wells, tanks, pneumatic controllers and compressors in the upstream sector. In June 2016, the EPA issued another NSPS regulation for the oil and natural gas sector, to regulate methane and VOC emissions from new and modified facilities in transmission and storage, gathering and boosting, production and processing facilities. All projects which commenced construction after September 2015 are required to comply with this regulation. In October 2018, the EPA published a proposed rule reconsidering and amending portions of the 2016 rule, including but not limited to, the fugitive emissions requirements at well sites and compressor stations. The amended portions of the 2016 rule were effective immediately upon publication. In August 2020, the EPA issued two final amendments related to the reconsideration of the NSPS for the oil and natural gas sector applicable to VOC and methane emissions. Together, the two amendments have the effect of rescinding the methane portion of the NSPS for all segments of the oil and natural gas sector, rescinding all methane and VOC NSPS for the transmission and storage segment and modifying some of the NSPS VOC requirements for facilities in the production and processing segments. The two amendments have been challenged in the U.S. Court of Appeals for the D.C. Circuit but remain in effect pending the outcome of the litigation. Dominion Energy has completed an evaluation of the potential impacts and expects that any impact would be insignificant to its results of operations, financial condition and/or cash flows.
ACE Rule
In July 2019, the EPA published the final rule informally referred to as the ACE Rule, as a replacement for the Clean Power Plan. 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 willwould take effect upon issuance of the court’s mandate. TheIn March 2021, the court issued a partial mandate vacating and remanding all parts of the ACE Rule appliesexcept for the portion of the ACE Rule that repealed the Clean Power Plan. In October 2021, the U.S. Supreme Court agreed to existing coal-fired power plants and would require states to develop plans by Julyhear a challenge of the U.S. Court of Appeals for the D.C. Circuit’s decision on the ACE Rule. In June 2022, establishing unit-specific performance standards for existing coal-fired power plants. It is unknown at this time if or how the EPA will replaceU.S. Supreme Court reversed the D.C. Circuit’s decision on the ACE Rule and how that replacement will affectremanded the Companies’case back to the D.C. Circuit. Until the case is resolved by the D.C. Circuit and/or the EPA issues new rulemaking, the Companies cannot predict an impact to its 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 flowsflows..
In December 2018, the EPA proposed revised Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources. The proposed rule would amend the previous determination that the best system of emission reduction for newly constructed coal-fired steam generating units is no longer partial carbon capture and storage. Instead, the proposed revised best system of emission reduction for this source category is the most efficient demonstrated steam cycle (e.g., supercritical steam conditions for large units and subcritical steam conditions for small units) in combination with the best operating practices. In January 2021, the EPA published a final rule affirming that electric generating units are included for the purposes of regulating GHG emissions from new, modified and reconstructed stationary sources. The proposed revision to the performance standards 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.
State Regulations
In May 2019, VDEQ issued a final rule establishing a state carbon regulation program with a 28.0 million ton initial state-wide carbon cap in 2020. The cap was to be reduced by approximately 3 percent per year through 2030, resulting in an ultimate cap of 19.6 million tons. The final rule included a provision for VDEQ to delay implementation of the rule pending authorization from the General Assembly and Governor of Virginia. In April 2020, Virginia legislation was enacted authorizing VDEQ to implement the final rule. In June 2020, the VDEQ signed the CO2 Budget Trading Program rule outlining the requirements for Virginia’s direct participation in RGGI starting in 2021. As a result of joining RGGI in 2021, Virginia’s allotment of the regional cap was adjusted to approximately 27.1 million tons, although Virginia Power may purchase additional allowances from the secondary market and other states in the RGGI program. The regulatory framework in Virginia provides rate recovery mechanisms that are expected to substantially mitigate any such impact.Water
The legislation discussed above is considered related legislation to the VCEA as discussed in Note 13. The VCEA institutes a mandatory renewable portfolio standard, enhances renewable generation and energy storage development, requires the retirement of certain generation facilities, establishes energy efficiency targets, expands net metering and directs Virginia’s participation in a market-based carbon trading program through 2050.
Water
The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. The Companies must comply with applicable aspects of the CWA programs at their operating facilities.
Regulation 316(b)
In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of 5five mandatory facility-specific factors, including a social cost-benefit test, and 6six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above twotwo MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Dominion Energy and Virginia Power currently have 15 and 9nine facilities, respectively, that are subject to the final regulations. Dominion Energy is also working with the EPA and state regulatory agencies to assess the applicability of Section 316(b) to eight hydroelectric facilities, including three Virginia Power facilities. The Companies anticipate that they may have to install impingement control technologies at certain of these stations that have once-through cooling systems. The Companies are currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology,technological, and cost and benefit studies. DESC is conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications at certain facilities to ensure compliance with this rule. While the impacts of this rule could be material to the Companies’ results of operations, financial condition and/or cash flows, the existing regulatory
180
frameworks in South Carolina and Virginia provide rate recovery mechanisms that could substantially mitigate any such impacts for the regulated electric utilities.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 2two 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 2028.2028. 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.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 1213 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 commenced remediation activities at one site in the second quarter of 2022. In addition, Dominion Energy has proposed or expects to propose remediation plans associated with 3 sites, including 1for one site at Virginia Power and expects to conductcommence remediation activities primarily by the endin 2023 depending on receipt of 2021.final permits and approvals. At December 31, 20202022 and 2019,2021, Dominion Energy had $42$47 million and $34$45 million, respectively, of reserves recorded. Dominion Energy’s reserves include charges of $14$14 million ($11 million after-tax) and $16 million ($12 million after-tax) recorded in 2020, and 2018, respectively, in other operations and maintenance expense in the Consolidated Statements of Income. At both December 31, 20202022 and 2019,2021, Virginia Power had $26$25 million and $16 million, respectively, of reserves recorded. Virginia Power’s reserves include charges of $10$10 million ($7 million after-tax) and $16 million ($12 million after-tax) recorded in 2020, and 2018, respectively, in other operations and maintenance expense in the Consolidated Statements of Income. In addition, for 1 site associated with Dominion Energy, an updated work plan submitted to SCDHEC in September 2018, would increase costs by approximately $11 million if approved by federal and state agencies. In September 2020, this plan was submitted to the Army Corps of Engineers. Dominion Energy is associated with 12 additional sites, including 2two associated with Virginia Power, which are not under investigation by any state or federal environmental agency nor the subject of any current or proposed plans to perform remediation activities. Due to the uncertainty surrounding such sites, the Companies are unable to make an estimate of the potential financial statement impacts.
Other Legal Matters
The Companies are defendants in a number of lawsuits and claims involving unrelated incidents of property damage and personal injury. Due to the uncertainty surrounding these matters, the Companies are unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on results of operations, financial condition and/or cash flows.
SCANA Legal Proceedings
The following describes certain legal proceedings involving Dominion Energy, SCANA or DESC relating primarily to events occurring before closing of the SCANA Combination. Dominion Energy intends to vigorously contest the lawsuits, claims and assessments which have been filed or initiated against SCANA and DESC. No reference to, or disclosure of, any proceeding, item or matter described below shall be construed as an admission or indication that such proceeding, item or matter is material. For certain of these matters,
181
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, 20202022 and 20192021 include reserves of $208$94 million and $696$274 million, respectively, included in other current liabilities, and insurance receivables of $8$68 million and $111$118 million, respectively, included within other receivables. These balances at December 31, 2022 and 2021 include $68 million and $85 million, respectively, of offsetting reserves and insurance receivables related to personal injury or wrongful death cases which are currently pending. During the year ended December 31, 2022, charges included in Dominion Energy’s Consolidated Statements of Income were inconsequential. Dominion Energy’s Consolidated Statements of Income for the yearyears ended December 31, 2021 and 2020 include charges of $90$100 million ($6875 million after-tax) includedand $90 million ($68 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$25 million ($25 million after-tax) included within other income (expense). Dominion Energy’s Consolidated Statements of Income for the year ended December 31, 2019 includes charges of $641 million ($480 million after-tax), included within impairment of assets and other charges (reflected in the Corporate and Other segment).
Ratepayer Class Actions
In May 2018, a consolidated complaint against DESC, SCANA and the State of South Carolina was filed in the State Court of Common Pleas in Hampton County, South Carolina (the DESC Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege, among other things, that DESC was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the NND Project, and that DESC committed unfair trade practices and violated state anti-trust laws. The plaintiffs sought a declaratory judgment that DESC may not charge its customers for any past or continuing costs of the NND Project, sought to have SCANA and DESC’s assets frozen and all monies recovered from Toshiba Corporation and other sources be placed in a constructive trust for the benefit of ratepayers and sought specific performance of the alleged implied contract to construct the NND Project.
In December 2018, the State Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the DESC Ratepayer Case. The settlement agreement, contingent upon the closing of the SCANA Combination, provided that SCANA and DESC would establish an escrow account and proceeds from the escrow account would be distributed to the class members, after payment of certain taxes, attorneys' fees and other expenses and administrative costs. The escrow account would include (1) up to $2.0 billion, net of a credit of up to $2.0 billion in future electric bill relief, which would inure to the benefit of the escrow account in favor of class members over a period of time established by the South Carolina Commission in its order related to matters before the South Carolina Commission related to the NND Project, (2) a cash payment of $115 million and (3) the transfer of certain DESC-owned real estate or sales proceeds from the sale of such properties, which counsel for the DESC Ratepayer Class estimate to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA and DESC funded the cash payment portion of the escrow account. The court held a fairness hearing on the settlement in May 2019. In June 2019, the court entered an order granting final approval of the settlement, which order became effective July 2019. In July 2019, DESC transferred $117 million representing the cash payment, plus accrued interest, to the plaintiffs. Through August 2020, property, plant and equipment with a net recorded value of $27 million had been transferred to the plaintiffs in coordination with the court-appointed real estate trustee to satisfy the settlement agreement. In September 2020, the court entered an order approving a final resolution of the transfer of real estate or sales proceeds with a cash contribution of $38.5 million by DESC and the conveyance of property, plant and equipment with a net recorded value of $3 million. In October 2020, DESC completed the conveyance of property, plant and equipment and funded this cash contribution.
In September 2017, a purported class action was filed by Santee Cooper ratepayers against Santee Cooper, DESC, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the State Court of Common Pleas in Hampton County, South Carolina (the Santee Cooper Ratepayer Case). The allegations are substantially similar to those in the DESC Ratepayer Case. The plaintiffs seek a declaratory judgment that the defendants may not charge the purported class for reimbursement for past or future costs of the NND Project. In March 2018, the plaintiffs filed an amended complaint including as additional named defendants, including certain then current and former directors of Santee Cooper and SCANA. In June 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of South Carolina. In December 2018, Santee Cooper filed its answer to the plaintiffs' fourth amended complaint and filed cross claims against DESC, which was denied. In October 2019, Santee Cooper voluntarily consented to stay its cross claims against DESC pending the outcome of the trial of the underlying case. In November 2019, DESC removed the case to the U.S. District Court for the District of South Carolina. In December 2019, the plaintiffs and Santee Cooper filed a motion to remand the case to state court. In January 2020, the case was remanded to state court. In March 2020, the parties executed a settlement agreement relating to this matter as well as the Luquire Case and the Glibowski Case described below. The settlement agreement provides that Dominion Energy and Santee Cooper will establish a fund for the benefit of class members in the amount of $520 million, of which Dominion Energy’s portion is $320 million of shares of Dominion Energy common stock. Also in March 2020, the court granted preliminary approval for the settlement agreement. In July 2020, the court issued a final approval of the settlement agreement. In September 2020, Dominion Energy issued $322 million of shares of Dominion Energy common stock to satisfy its obligation under the settlement agreement, including interest charges.
In July 2019, a similar purported class action was filed by certain Santee Cooper ratepayers against DESC, SCANA, Dominion Energy and former directors and officers of SCANA in the State Court of Common Pleas in Orangeburg, South Carolina (the Luquire Case). In August 2019, DESC, SCANA and Dominion Energy were voluntarily dismissed from the case. The claims are similar to the Santee Cooper Ratepayer Case. In March 2020, the parties executed a settlement agreement as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Glibowski Case. This case was dismissed as part of the Santee Cooper Ratepayer Case settlement described above.
RICO Class Action
In January 2018, a purported class action was filed, and subsequently amended, against SCANA, DESC and certain former executive officers in the U.S. District Court for the District of South Carolina (the Glibowski Case). The plaintiff alleges, among other things, that SCANA, DESC and the individual defendants participated in an unlawful racketeering enterprise in violation of RICO and conspired to violate RICO by fraudulently inflating utility bills to generate unlawful proceeds. The DESC Ratepayer Class Action
settlement described previously contemplates dismissal of claims by DESC ratepayers in this case against DESC, SCANA and their officers. In August 2019, the individual defendants filed motions to dismiss. In March 2020, the parties executed a settlement agreement as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Luquire Case. This case was dismissed as part of the Santee Cooper Ratepayer Case settlement described above.
SCANA Shareholder Litigation
In September 2017, a purported class action was filed against SCANA and certain former executive officers and directors in the U.S. District Court for the District of South Carolina. Subsequent additional purported class actions were separately filed against all or nearly all of these defendants (collectively the SCANA Securities Class Action). In January 2018, the U.S. District Court for the District of South Carolina consolidated these suits, and the plaintiffs filed a consolidated amended complaint in March 2018. The plaintiffs allege, among other things, that the defendants violated §10(b) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated thereunder, and that the individually named defendants are liable under §20(a) of the same act. In June 2018, the defendants filed motions to dismiss. In March 2019, the U.S. District Court for the District of South Carolina granted in part and denied in part the defendants’ motions to dismiss. In December 2019, the parties executed a settlement agreement pursuant to which SCANA will pay $192.5 million, up to $32.5 million of which can be satisfied through the issuance of shares of Dominion Energy common stock, subject to approval by the U.S. District Court for the District of South Carolina. In February 2020, the U.S. District Court for the District of South Carolina granted preliminary approval of the settlement agreement, pending a fairness hearing. In March 2020, SCANA funded an escrow account with $160 million in cash and the balance of the settlement will be paid upon final approval of the settlement by the court. In July 2020, the court granted final approval of the settlement agreement. In August 2020, SCANA paid the balance of $32.5 million in cash to satisfy the settlement.
In September 2017, a shareholder derivative action was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina.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 case is pending.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 to 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 June 2022, the State Court of Common Pleas in Richland County, South Carolina issued final approval of the settlement agreement with the funds utilized to satisfy a portion of the State Court Merger Case as discussed below.
In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors of SCANA in the State Court of Common Pleas in Lexington County, South Carolina (the City of Warren Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In June 2018, the case was remanded back to the State Court of Common Pleas in Lexington County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal was consolidated with a similar appeal in the Metzler Lawsuit discussed below. In June 2019, the U.S. Court of Appeals for the Fourth Circuit reversed the order remanding the case to state court.
In February 2018, a purported class action was filed against Dominion Energy and certain former directors of SCANA and DESC in the State Court of Common Pleas in Richland County, South Carolina (the Metzler Lawsuit). The allegations made and the relief sought by the plaintiffs are substantially similar to that described for the City of Warren Lawsuit. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In August 2018, the case was remanded back to the State Court of Common Pleas in Richland County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal was consolidated with the City of Warren Lawsuit. In June 2019, the U.S. Court of Appeals for the Fourth Circuit reversed the order remanding the case to state court.
In September 2019, the U.S. District Court for the District of South Carolina granted the plaintiffs’ motion to consolidate the City of Warren Lawsuit and the Metzler Lawsuit.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 to 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. In June 2022, this case is pending.was dismissed in connection with the final approval by the State Court of Common Pleas in Richland County, South Carolina of the settlement agreement.
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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.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. This case is pending.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. In June 2022, the State Court of Common Pleas in Richland County, South Carolina issued final approval of the settlement agreement. Also in June 2022, Dominion Energy utilized the $33 million of insurance proceeds from the State Court Derivative Case settlement, the issuance of 0.4 million shares of its common stock and the payment of $2 million in cash to satisfy its obligations under the settlement agreement.
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$100 million for 100%100% of the NND Project. In January 2021, the U.S. District Court for the District of South Carolina granted summary judgment in favor of SCANA, DESC, Fluor Corporation and Fluor Enterprises, Inc. In February 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fourth Circuit. This case is pending.In November 2021, the U.S Court of Appeals for the Fourth Circuit affirmed the lower court ruling. In March 2022, the deadline to file an appeal to the Supreme Court of the United States expired.
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. As a result of the ruling in favor of the defendants in the aforementioned case, DESC was able to resolve Fluor’s claims for an inconsequential amount.
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 May 2022, Dominion Energy issued an additional 0.9 million shares of its common stock to partially satisfy DESC’s remaining obligation under the settlement agreement. In June 2022, DESC requested approval from the South Carolina Commission to transfer certain real estate with a total settlement value of $51 million to satisfy its remaining obligation under the settlement agreement. In July 2022, the South Carolina Commission voted to approve the request and issued its final order in August 2022. In September 2022, DESC transferred certain non-utility property with a fair value of $28 million to the SCDOR under the settlement agreement, resulting in a gain of $18 million ($14 million after-tax) recorded in losses (gains) on sales of assets (reflected in Dominion Energy South Carolina) in Dominion Energy’s Consolidated Statements of Income for the year ended December 31, 2022. In December 2022, DESC transferred additional utility property with a fair value of $3 million to the SCDOR, resulting in an inconsequential gain. In October 2022, DESC filed for approval to transfer the remaining real estate with FERC which was received in November 2022. The transfers of such utility properties are expected to be completed by early 2024 and to result in a gain of approximately $20 million upon completion.
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Matters Fully Resolved Prior to 2022
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 is pending.was dismissed as part of the Santee Cooper Ratepayer Case settlement described above.
RICO Class Action
In January 2018, a purported class action was filed, and subsequently amended, against SCANA, DESC and certain former executive officers in the U.S. District Court for the District of South Carolina (the Glibowski Case). The plaintiff 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
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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.
FILOT Litigation and Related Matters
In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against DESC in the State Court of Common Pleas in Fairfield County, South Carolina, making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of implied duty of good faith and fair dealing and unfair trade practices related to DESC’s termination of the FILOT agreement between DESC and Fairfield County related to the NND Project. The plaintiff sought a temporary and permanent injunction to prevent DESC from terminating the FILOT agreement. The plaintiff withdrew the motion for temporary injunction in December 2017. This case is pending.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 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$25 million, and SCANA and DESC to pay disgorgement and prejudgment interest totaling $112.5$112.5 million, which disgorgement and prejudgment interest amount were deemed satisfied by the settlements in the SCANA Securities Class Action and the DESC Ratepayer Case. SCANA paid the civil penalty in December 2020. The SEC civil action against two former executive officers of SCANA remains pending and is currently subject to a stay granted by the court in June 2020 at the request of the U.S. Attorney’s Office for the District of South Carolina.
In addition, the South Carolina Law Enforcement Division is conducting a criminal investigation into the handling of the NND Project by SCANA and DESC. Dominion Energy is cooperating fully with the investigations by the U.S. Attorney’s Office and the South
Carolina Law Enforcement Division, including responding to additional subpoenas and document requests. Dominion Energy has also entered into a cooperation agreement with the U.S. Attorney’s Office and the South Carolina Attorney General’s Office. The cooperation agreement provides that in consideration of its full cooperation with these investigations to the satisfaction of both agencies, neither such agency will criminally prosecute or bring any civil action against Dominion Energy or any of its current, previous, or future direct or indirect subsidiaries related to the NND Project. A former executive officer of SCANA entered a plea agreement with the U.S. Attorney’s Office and the South Carolina Attorney General’s Office in June 2020 and entered a guilty plea with the U.S. District Court for the District of South Carolina in July 2020. Another former executive officer of SCANA entered a plea agreement with the U.S. Attorney's Office and the South Carolina Attorney General's Office in November 2020. These matters are pending.
Other Litigation
In December 2018, arbitration proceedings commenced between DESC2020 and Cameco Corporationentered 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 a supply agreement signed in May 2008. This agreement provides the terms and conditions under which DESC agreed to purchase uranium hexafluoride from Cameco Corporation over a period from 2010 to 2020. Cameco Corporation alleges that DESC violated this agreement by failing to purchase the stated quantities of uranium hexafluoride for the 2017 and 2018 delivery years. DESC denies that it is in breach of the agreement and believes that it has reduced its purchase quantity within the terms of the agreement. In January 2021, the parties entered into a mutual release of claims and dismissed the arbitration.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%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
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construction under the abandonment provisions of the Base Load Review Act or through other means. This decision by SCANA became the focus of numerous legislative, regulatory and legal proceedings. Some of these proceedings remain unresolved and are described above.
In September 2017, DESC, for itself and as agent for Santee Cooper, filed with the U.S. Bankruptcy Court for the Southern District of New York Proofs of Claim for unliquidated damages against each of Westinghouse and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by Westinghouse and WECTEC of the contract, and assert against Westinghouse and WECTEC any and all claims that are based thereon or that may be related thereto.
Westinghouse’s reorganization plan was confirmed by the U.S. Bankruptcy Court for the Southern District of New York and became effective in August 2018. In connection with the effectiveness of the reorganization plan, the contract associated with the NND Project was deemed rejected. DESC is contestingcontested approximately $285$285 million of filed liens in Fairfield County, South Carolina. Most of these asserted liens arewere claims that relate to work performed by Westinghouse subcontractors before the Westinghouse bankruptcy, although some of them arewere claims arising from work performed after the Westinghouse bankruptcy.
Westinghouse has indicated that some unsecured creditors have sought or may seek amounts beyond what Westinghouse allocated when it submitted its reorganization plan to the U.S. Bankruptcy Court for the Southern District of New York. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the bankruptcy reorganization plan allocated by Westinghouse, it is possible that the reorganization plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant.
DESC and Santee Cooper were responsible for amounts owed to Westinghouse for valid work performed by Westinghouse subcontractors on the NND Project after the Westinghouse bankruptcy filing until termination of the interim assessment agreement. In December 2019, DESC and Santee Cooper entered into a confidential settlement agreement with W Wind Down Co LLC resolving claims relating to the interim assessment agreement.
Further, some Westinghouse subcontractors who havethat 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 have also asserted construction liens against the NND Project site. DESC also intendsIn December 2021, settlements were reached to oppose theseresolve all remaining claims and liens. With respect to claims ofmade by Westinghouse subcontractors, DESC believes there were sufficientsubcontractors. All amounts previously funded during the interim assessment agreement period to pay such validly asserted claims. With respect to the Westinghouse subcontractor claimsfor which relate to other periods, DESC understands that such claims will be paid pursuant to Westinghouse’s confirmed bankruptcy reorganization plan. DESC further understands that the amounts paid under the plan may satisfy such claims in full. Therefore, DESC believes that the Westinghouse subcontractors may be paid substantially (and potentially in full) by Westinghouse. While Dominion Energy cannot be assured that it willwas ultimately responsible were funded utilizing, and did not have any exposure on account of unpaid Westinghouse subcontractor claims, which DESC is presently disputing, Dominion Energy believes it is unlikely that it will be required to make payments on account of such claims.
Nuclear Matters
In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage atexceed, the Fukushima Daiichi nuclear power station in northeast Japan. These events resulted in significant nuclear safety reviews by the NRC and industry groups such as the Institute of Nuclear Power Operations. Like other U.S. nuclear operators, Dominion Energy has gathered supporting data and participated in industry initiatives focused on the ability to respond to and mitigate the consequences of, design-basis and beyond-design-basis events at its stations.
In July 2011, an NRC task force provided initial recommendations based on its reviewportion of the Fukushima Daiichi accident andToshiba Settlement allocated for such balances within the SCANA Merger Approval Order recorded in October 2011 the NRC staff prioritized these recommendations into Tiers 1, 2 and 3. Tier 1 recommendations consisted of actions which the NRC staff determined should be started without unnecessary delay. Tier 2 and 3 items consisted of items which could not be initiated in the near term because of resource restraints, the need for further technical assessment, or were dependentregulatory liabilities on activities related to the higher priority Tier 1 issues. In December 2011, the NRC Commissioners approved the agency staff’s prioritization and recommendations, and that same month an appropriations act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as soon as possible.Dominion Energy’s Consolidated Balance Sheets.
Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactor licensees, construction permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion Energy requiring implementation of safety enhancements related to mitigation strategies for responding to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation have been implemented. The information requests issued by the NRC requested each reactor licensee to reevaluate the seismic and external flooding hazards at their facility using present-day methods and information, conduct walkdowns of their facility to ensure protection against these hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. The walkdowns of each unit have been completed, audited by the NRC and found to be adequate. Reevaluation of the emergency communications systems and staffing levels was completed as part of the effort to comply with the orders. Reevaluation of the seismic hazards is complete and final with NRC acceptance received for all Dominion Energy facilities. Reevaluation of the external flooding hazards is complete for all Dominion Energy facilities. The NRC approved the external flooding hazards for Surry in May 2020 and Millstone in August 2020. The Companies do not currently expect that compliance with the NRC's information requests will materially impact their financial position, results of operations or cash flows during the implementation period. The NRC staff has resolved the Tier 2 and Tier 3 recommendations and no additional future actions on the part of Dominion Energy are anticipated with respect to these recommendations. Therefore, the Companies do not expect material financial impacts related to compliance with Tier 2 and Tier 3 recommendations.
Nuclear Operations
Nuclear Decommissioning – Minimum Financial Assurance
The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. The 20202022 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 arethis unit is in a decommissioning state, was $2.8$3.6 billion and $1.8$2.1 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 20202022 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 20202022 U.S. Bureau of Labor Statistics indices. Dominion Energy believes that the amounts currently available in its decommissioning trustsfunds and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power alsoIn 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 $13.8$13.7 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 secondthird quarter of 2020,2022, the total liability protection per nuclear incident available to all participants in the Secondary Financial Protection Program decreasedincreased from $13.9$13.5 billion to $13.8$13.7 billion. This decreaseincrease does not impact Dominion Energy’s responsibility per active unit under the Price-Anderson Amendments Act of 1988. The Companies have purchased $450$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$138 million for each of their licensed reactors not to exceed $21$20 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 unitsMillstone, Summer, Surry and North Anna are as follows:all $1.06 billion.
|
| Coverage |
| |
(billions) |
|
|
|
|
Dominion Energy |
|
|
|
|
Millstone |
| $ | 1.70 |
|
Kewaunee |
|
| 0.05 |
|
Summer |
|
| 2.75 |
|
Virginia Power(1) |
|
|
|
|
Surry |
| $ | 1.70 |
|
North Anna |
|
| 1.70 |
|
186
|
|
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$1.06 billion per reactor site. In March 2015, the NRC granted an exemption which allowed Kewaunee to reduce its property insurance limit to $50 million. This reduction was implemented in January 2018, following the removal and storage of the spent nuclear fuel from the spent fuel pool. This includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion Energy and Virginia Power's maximum retrospective premium assessment for the current policy period is $99$65 million and $48$33 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$1 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.an inconsequential amount.
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$32 million and $9$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 provideand provided for periodic payments for damages incurred through December 31, 2022. In November 2022, the DOE notified the Companies that it intends to extend these agreements through December 31, 2025 and future additional extensions are contemplated by the settlement agreements. A similar agreement for Summer extends until the DOE has accepted the same amount of spent fuel from the facility as if it has fully performed its contractual obligations.
In June 2018, a lawsuit for Kewaunee was filed in the U.S. Court of Federal Claims for recovery of spent nuclear fuel storage costs incurred after 2013. In March 2019, Dominion Energy amended its filing for recovery of spent nuclear fuel storage to include costs incurred for the year ended December 31, 2018. This matter is pending.In January 2022, a settlement agreement was entered into for $48 million. Dominion Energy received the settlement funds in February 2022.
In 2022, Virginia Power received payments of $17 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2020 through December 31, 2020. In addition, Dominion Energy received payments of $7 million for resolution of claims incurred at Millstone for the period of July 1, 2020 through June 30, 2021 and $1 million for resolution of its share of claims incurred at Summer for the period of January 1, 2021 through December 31, 2021.
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$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$11 million for resolution of claims incurred at Millstone for the period of July 1, 2018 through June 30, 2019 and $4$4 million for resolution of its share of claims incurred at Summer for the period of January 1, 2019 through December 31, 2019.
In 2019, Virginia Power received payments of $15 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2017 through December 31, 2017. In addition, Dominion Energy received $11 million for resolution of claims incurred at Millstone for the period of July 1, 2017 through June 30, 2018 and $3 million for resolution of its share of claims incurred at Summer for the period of January 1, 2018 through December 31, 2018.
In 2018, Virginia Power received payments of $16 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2016 through December 31, 2016. In addition, Dominion Energy received payment of $13 million for resolution of claims incurred at Millstone for the period of July 1, 2016 through June 30, 2017.187
The Companies continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion Energy’s receivables for spent nuclear fuel-related costs totaled $46$56 million and $52$52 million at December 31, 20202022 and 2019,2021, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $35$37 million and $39 million at both December 31, 20202022 and 2019.2021, respectively.
The Companies will continue to manage their spent fuel until it is accepted by the DOE.
Long-Term Purchase Agreements
At December 31, 2020,2022, 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:
|
| 2023 |
|
| 2024 |
|
| 2025 |
|
| 2026 |
|
| 2027 |
|
| Thereafter |
|
| Total |
| |||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Purchased electric capacity(1) |
| $ | 71 |
|
| $ | 70 |
|
| $ | 70 |
|
| $ | 73 |
|
| $ | 73 |
|
| $ | 630 |
|
| $ | 987 |
|
|
| 2021 |
|
| 2022 |
|
| 2023 |
|
| 2024 |
|
| 2025 |
|
| Thereafter |
|
| Total |
| |||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased electric capacity(1) |
| $ | 67 |
|
| $ | 66 |
|
| $ | 66 |
|
| $ | 66 |
|
| $ | 65 |
|
| $ | 749 |
|
| $ | 1,079 |
|
|
|
Guarantees, Surety Bonds and Letters of Credit
Upon the closing of the GT&S Transaction,At December 31, 2022, Dominion Energy retained its 4had issued four guarantees related to Cove Point, an equity method investment, in support of terminal services, transportation and construction. NaNTwo of the Cove Point guarantees have a cumulative maximum exposure of $1.9$1.9 billion while the other 2two guarantees have 0no maximum limit. No amounts related to these guarantees have been recorded.
In addition, at December 31, 2022, Dominion Energy’s guarantee agreementEnergy had issued an additional $20 million of guarantees, primarily to support a portion of Atlantic Coast Pipeline’s obligation under a revolving credit facility is described in Note 9.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, 2020,2022, Dominion Energy had issued the following subsidiary guarantees:
|
| Maximum |
| |
(millions) |
|
|
| |
Commodity transactions(1) |
| $ | 2,567 |
|
Nuclear obligations(2) |
|
| 243 |
|
Solar(3) |
|
| 304 |
|
Other(4) |
|
| 1,229 |
|
Total(5)(6) |
| $ | 4,343 |
|
|
| Maximum Exposure |
| |
(millions) |
|
|
|
|
Commodity transactions(1) |
| $ | 1,854 |
|
Nuclear obligations(2) |
|
| 202 |
|
Solar(3) |
|
| 467 |
|
Other(4) |
|
| 1,004 |
|
Total(5) |
| $ | 3,527 |
|
(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. (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 guarantee of an offshore wind installation vessel discussed in Note 15. (6) In July 2016, Dominion Energy signed an agreement with a lessor to construct and lease a new corporate office property in Richmond, Virginia. The lessor provided equity and obtained financing commitments from debt investors, totaling $365 million, which funded total project costs. The project became substantially complete in August 2019 at which point the facility was available for Dominion Energy’s use and the five-year lease term commenced. At the end of the initial lease term, Dominion Energy can (i) extend the term of the lease for an additional 188 five years, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property on behalf of the lessor to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the project costs, Dominion Energy may be required to make a payment to the lessor, up to 87% of project costs, for the difference between the project costs and sale proceeds. At December 31, 2022, no amounts have been recorded related to this guarantee.
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|
|
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|
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|
|
|
|
Additionally, at December 31, 2020,2022, Dominion Energy had purchased $157$249 million of surety bonds, including $88$172 million at Virginia Power, and authorized the issuance of letters of credit by financial institutions of $100$202 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.
Indemnifications
As part of commercial contract negotiations in the normal course of business, the Companies may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Companies are unable to develop an estimate of the maximum potential amount of any other future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2020,2022, 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$80 million in other income in its Consolidated Statements of Income.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 $73$32 million and $43 million in other deferred credits and other liabilities at December 31, 2020.2022 and 2021, respectively and $11 million and $26 million in other current liabilities at December 31, 2022 and 2021, respectively.
NOTE 24. CREDIT RISK
Dominion Energy
As a diversified energy company, Dominion Energy transacts primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic, Midwest and Rocky Mountain and Southeast regions of the U.S. Dominion Energy does not believe that this geographic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Energy is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations.
Dominion Energy’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion Energy transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include marketing of nonregulated generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of any collateral. At December 31, 2020,2022, Dominion Energy’s credit exposure totaled $107$281 million. Of this amount, investment grade counterparties, including those internally rated, represented 96%89%, and 0no single counterparty, whether investment grade or non-investment grade, exceeded $41$77 million of exposure.
189
Virginia Power
Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2020,2022, Virginia Power’s credit exposure totaled $15$25 million. Of this amount, investment grade counterparties, including those internally rated, represented 97%76%, and 0no single counterparty exceeded $6$8 million of exposure.
Credit-Related Contingent Provisions
Certain of Dominion Energy’sEnergy and Virginia Power's derivative instruments contain credit-related contingent provisions. These provisions require Dominion Energy and 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, 2020Dominion Energy and 2019, Dominion EnergyVirginia Power would have been required to post $14 million and $10 million, respectively, of additional collateral to its counterparties.counterparties of $140 million and $28 million, respectively, as of December 31, 2022, and $31 million and $22 million, respectively, as of December 31, 2021. 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 and Virginia Power had both posted $1collateral of $72 million of collateral at December 31, 20202022, and $66 million and $54 million, respectively, at December 31, 2021, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cashcash. In addition, Dominion Energy and Virginia Power had both posted 0letters of credit as collateral with counterparties covering $20 million of fair value of derivative instruments in a liability position at December 31, 2019.2022. 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 for Dominion Energy and Virginia Power was $212 million and $99 million, respectively, as of December 31, 20202022 and 2019 was $15$97 million and $10$76 million, respectively, as of December 31, 2021, which does not include the impact of any offsetting asset positions.
If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of December 31, 2020 and 2019, Virginia Power would have been required to post an additional $2 million and $8 million, respectively, of collateral to its counterparties.
See Note 7 for further information about derivative instruments.
NOTE 25. RELATED-PARTY TRANSACTIONS
Dominion Energy’s transactions with equity method investments are described in Note 9. 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 Virginia Power's significant related party transactions follows.
Virginia Power
Transactions with Affiliates
Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of forward commodity purchases, to manage commodity price risks associated with purchases of natural gas. See Notes 7 and 20 for more information. At December 31, 2020,2022, Virginia Power’s derivative assets and liabilities with affiliates were $3$33 million and $22$31 million, respectively. At December 31, 2019,2021, Virginia Power’s derivative assets and liabilities with affiliates were $3$29 million and $53$6 million, respectively.
Virginia Power participates in certain Dominion Energy benefit plans as described in Note 22. At December 31, 20202022 and 2019,2021, Virginia Power’s amounts due to Dominion Energy associated with the Dominion Energy Pension Plan and reflected in noncurrent pension and other postretirement benefit liabilities in the Consolidated Balance Sheets were $436$422 million and $782$522 million, respectively. At December 31, 20202022 and 2019,2021, Virginia Power’s amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $354$518 million and $287$431 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
190
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, |
| 2020 |
|
| 2019 |
|
| 2018 |
|
| 2022 |
|
| 2021 |
|
| 2020 |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Commodity purchases from affiliates |
| $ | 569 |
|
| $ | 690 |
|
| $ | 930 |
|
| $ | 1,423 |
|
| $ | 742 |
|
| $ | 569 |
|
Services provided by affiliates(1) |
|
| 455 |
|
|
| 503 |
|
|
| 450 |
|
|
| 519 |
|
|
| 494 |
|
|
| 455 |
|
Services provided to affiliates |
|
| 18 |
|
|
| 24 |
|
|
| 24 |
|
|
| 18 |
|
|
| 18 |
|
|
| 18 |
|
(1) Includes capitalized expenditures of $177 million, $161 million and $141 million for the years ended December 31, 2022, 2021 and 2020, respectively.
|
|
Virginia Power has borrowed funds from Dominion Energy under short-term borrowing arrangements. In November 2022, Virginia Power amended its intercompany credit facility with Dominion Energy to increase the maximum capacity to $3.0 billion. There were $380 million$2.0 billion and $107$699 million in short-term demand note borrowings from Dominion Energy as of December 31, 20202022 and 2019,2021, respectively. The weighted-average interest rate of these borrowings was 0.30%4.68% and 3.22%0.26% at December 31, 20202022 and 2019,2021, respectively. Virginia Power had 0no outstanding borrowings, net of repayments under the Dominion Energy money pool for its nonregulated subsidiaries as of December 31, 20202022 and 2019.2021. Interest charges related to Virginia Power’s borrowings from Dominion Energy were immaterial$15 million for the year ended December 31, 2022 and $1 million for both the years ended December 31, 2020, 20192021 and 2018.2020.
There were 0no issuances of Virginia Power’s common stock to Dominion Energy in 2020, 20192022, 2021 or 2018.2020.
In January 2023, Virginia Power entered into a lease contract with an affiliated entity for the use of a Jones Act compliant offshore wind installation vessel currently under development with commencement of the 20-month lease term in August 2025 at a total cost of approximately $240 million plus ancillary services.
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 |
(2)
In addition to the operating segments above, the Companies also report a Corporate and Other segment.
Dominion Energy
The Corporate and Other Segment of Dominion Energy includes its corporate, service companiescompany and other functions (including unallocated debt) as well as its noncontrolling interest in Dominion Privatization and its nonregulated retail energy marketing operations (prior to December 2021), including Dominion Energy’sits noncontrolling interest in Wrangler.Wrangler (through March 2022). 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, heldincluding its noncontrolling interest in Atlantic Coast Pipeline, reported as discontinued operations which are discussed in Note 3.Notes 3 and 9.
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In 2022, Dominion Energy reported after-tax net expenses of $2.6 billion in the Corporate and Other segment, including $2.5 billion of after-tax net expenses for specific items with $2.8 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 2022 primarily related to the impact of the following items:
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:
192
In 2020, Dominion Energy reported after-tax net expenses of $3.7$3.7 billion in the Corporate and Other segment, including $3.4$3.4 billion of after-tax net expenses for specific items with $1.2$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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In 2018, Dominion Energy reported after-tax net income of $117million in the Corporate and Other segment, including $322 million of after-tax net income for specific items with $196 million of after-tax net expenses attributable to its operating segments.
The net expenses for specific items attributable to Dominion Energy’s operating segmentsEnergy Virginia;
193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents segment information pertaining to Dominion Energy’s operations:
194
Year Ended December 31, |
| Dominion Energy Virginia |
|
| Gas Distribution |
|
| Dominion Energy South Carolina |
|
| Contracted Assets |
|
| Corporate |
|
| Adjustments & |
|
| Consolidated |
| |||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Total revenue from external customers |
| $ | 9,666 |
|
| $ | 3,331 |
|
| $ | 3,323 |
|
| $ | 890 |
|
| $ | (36 | ) |
| $ | — |
|
| $ | 17,174 |
|
Intersegment revenue |
|
| (13 | ) |
|
| 2 |
|
|
| 7 |
|
|
| 18 |
|
|
| 925 |
|
|
| (939 | ) |
|
| — |
|
Total operating revenue |
|
| 9,653 |
|
|
| 3,333 |
|
|
| 3,330 |
|
|
| 908 |
|
|
| 889 |
|
|
| (939 | ) |
|
| 17,174 |
|
Depreciation, depletion and |
|
| 1,454 |
|
|
| 384 |
|
|
| 507 |
|
|
| 123 |
|
|
| 362 |
|
|
| — |
|
|
| 2,830 |
|
Equity in earnings of equity method |
|
| — |
|
|
| 3 |
|
|
| — |
|
|
| 277 |
|
|
| 19 |
|
|
| — |
|
|
| 299 |
|
Interest income (expense) |
|
| 17 |
|
|
| 9 |
|
|
| 6 |
|
|
| 75 |
|
|
| 86 |
|
|
| (76 | ) |
|
| 117 |
|
Interest and related charges (benefit) |
|
| 647 |
|
|
| 119 |
|
|
| 220 |
|
|
| 95 |
|
|
| (39 | ) |
|
| (76 | ) |
|
| 966 |
|
Income tax expense (benefit) |
|
| 408 |
|
|
| 146 |
|
|
| 132 |
|
|
| 106 |
|
|
| (724 | ) |
|
| — |
|
|
| 68 |
|
Net income from discontinued |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 9 |
|
|
| — |
|
|
| 9 |
|
Net income (loss) attributable to |
|
| 2,008 |
|
|
| 697 |
|
|
| 505 |
|
|
| 335 |
|
|
| (2,551 | ) |
|
| — |
|
|
| 994 |
|
Investment in equity method |
|
| — |
|
|
| 146 |
|
|
| — |
|
|
| 2,673 |
|
|
| 193 |
|
|
| — |
|
|
| 3,012 |
|
Capital expenditures |
|
| 5,206 |
|
|
| 1,458 |
|
|
| 708 |
|
|
| 342 |
|
|
| 44 |
|
|
| — |
|
|
| 7,758 |
|
Total assets (billions) |
|
| 55.4 |
|
|
| 19.6 |
|
|
| 17.2 |
|
|
| 9.7 |
|
|
| 8.1 |
|
|
| (5.8 | ) |
|
| 104.2 |
|
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 |
|
| 1,299 |
|
|
| 380 |
|
|
| 486 |
|
|
| 162 |
|
|
| 151 |
|
|
| — |
|
|
| 2,478 |
|
Equity in earnings of equity method |
|
| — |
|
|
| — |
|
|
| (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 |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 641 |
|
|
| — |
|
|
| 641 |
|
Net income (loss) attributable to |
|
| 1,919 |
|
|
| 600 |
|
|
| 437 |
|
|
| 431 |
|
|
| (99 | ) |
|
| — |
|
|
| 3,288 |
|
Investment in equity method |
|
| — |
|
|
| 106 |
|
|
| — |
|
|
| 2,738 |
|
|
| 88 |
|
|
| — |
|
|
| 2,932 |
|
Capital expenditures |
|
| 3,762 |
|
|
| 1,252 |
|
|
| 694 |
|
|
| 277 |
|
|
| 76 |
|
|
| — |
|
|
| 6,061 |
|
195
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 |
|
| 1,247 |
|
|
| 344 |
|
|
| 474 |
|
|
| 182 |
|
|
| 85 |
|
|
| — |
|
|
| 2,332 |
|
Equity in earnings of equity method |
|
| — |
|
|
| — |
|
|
| (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 |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 167 |
|
|
| (2,045 | ) |
|
| — |
|
|
| (1,878 | ) |
Net income (loss) attributable to |
|
| 1,891 |
|
|
| 560 |
|
|
| 419 |
|
|
| 402 |
|
|
| (3,673 | ) |
|
| — |
|
|
| (401 | ) |
Capital expenditures |
|
| 3,406 |
|
|
| 1,151 |
|
|
| 700 |
|
|
| 649 |
|
|
| 425 |
|
|
| — |
|
|
| 6,331 |
|
Year Ended December 31, |
| Dominion Energy Virginia |
|
| Gas Distribution |
|
| Dominion Energy South Carolina |
|
| Contracted Assets |
|
| Corporate and Other |
|
| Adjustments & Eliminations |
|
| Consolidated Total |
| |||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
| 0 |
|
|
| 2,332 |
|
Equity in earnings of equity method investees |
|
| 0 |
|
|
| 0 |
|
|
| (1 | ) |
|
| 35 |
|
|
| 6 |
|
|
| 0 |
|
|
| 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 | ) |
|
| 0 |
|
|
| 83 |
|
Net income (loss) from discontinued operations |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 167 |
|
|
| (2,045 | ) |
|
| 0 |
|
|
| (1,878 | ) |
Net income (loss) attributable to Dominion Energy |
|
| 1,891 |
|
|
| 560 |
|
|
| 419 |
|
|
| 402 |
|
|
| (3,673 | ) |
|
| 0 |
|
|
| (401 | ) |
Investment in equity method investees(1) |
|
| 0 |
|
|
| 55 |
|
|
| 0 |
|
|
| 2,784 |
|
|
| 95 |
|
|
| 0 |
|
|
| 2,934 |
|
Capital expenditures |
|
| 3,406 |
|
|
| 1,151 |
|
|
| 700 |
|
|
| 649 |
|
|
| 425 |
|
|
| 0 |
|
|
| 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 |
|
|
| 0 |
|
|
| 2,283 |
|
Equity in earnings of equity method investees |
|
| 0 |
|
|
| 2 |
|
|
| (4 | ) |
|
| (1 | ) |
|
| 11 |
|
|
| 0 |
|
|
| 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 | ) |
|
| 0 |
|
|
| 209 |
|
Net income from discontinued operations |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 183 |
|
|
| 533 |
|
|
| 0 |
|
|
| 716 |
|
Net income (loss) attributable to Dominion Energy |
|
| 1,786 |
|
|
| 487 |
|
|
| 430 |
|
|
| 460 |
|
|
| (1,805 | ) |
|
| 0 |
|
|
| 1,358 |
|
Investment in equity method investees |
|
| 0 |
|
|
| 37 |
|
|
| 0 |
|
|
| 74 |
|
|
| 1,223 |
|
|
| 0 |
|
|
| 1,334 |
|
Capital expenditures |
|
| 3,002 |
|
|
| 853 |
|
|
| 562 |
|
|
| 367 |
|
|
| 537 |
|
|
| 0 |
|
|
| 5,321 |
|
Total assets (billions) |
|
| 43.7 |
|
|
| 16.0 |
|
|
| 15.8 |
|
|
| 10.2 |
|
|
| 24.0 |
|
|
| (5.9 | ) |
|
| 103.8 |
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from external customers |
| $ | 8,401 |
|
| $ | 1,769 |
|
| $ | 0 |
|
| $ | 813 |
|
| $ | 27 |
|
| $ | 177 |
|
| $ | 11,187 |
|
Intersegment revenue |
|
| (552 | ) |
|
| 16 |
|
|
| 0 |
|
|
| 621 |
|
|
| 602 |
|
|
| (675 | ) |
|
| 12 |
|
Total operating revenue |
|
| 7,849 |
|
|
| 1,785 |
|
|
| 0 |
|
|
| 1,434 |
|
|
| 629 |
|
|
| (498 | ) |
|
| 11,199 |
|
Depreciation, depletion and amortization |
|
| 1,158 |
|
|
| 263 |
|
|
| 0 |
|
|
| 213 |
|
|
| 26 |
|
|
| 0 |
|
|
| 1,660 |
|
Equity in earnings of equity method investees |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 18 |
|
|
| 58 |
|
|
| 0 |
|
|
| 76 |
|
Interest income |
|
| 10 |
|
|
| 0 |
|
|
| 0 |
|
|
| 84 |
|
|
| 94 |
|
|
| (108 | ) |
|
| 80 |
|
Interest and related charges |
|
| 516 |
|
|
| 79 |
|
|
| 0 |
|
|
| 124 |
|
|
| 668 |
|
|
| (108 | ) |
|
| 1,279 |
|
Income tax expense (benefit) |
|
| 380 |
|
|
| 95 |
|
|
| 0 |
|
|
| 75 |
|
|
| (28 | ) |
|
| 0 |
|
|
| 522 |
|
Net income from discontinued operations |
|
| 0 |
|
|
| 0 |
|
|
| 0 |
|
|
| 116 |
|
|
| 336 |
|
|
| 0 |
|
|
| 452 |
|
Net income attributable to Dominion Energy |
|
| 1,596 |
|
|
| 373 |
|
|
| 0 |
|
|
| 361 |
|
|
| 117 |
|
|
| 0 |
|
|
| 2,447 |
|
Capital expenditures |
|
| 2,640 |
|
|
| 647 |
|
|
| 0 |
|
|
| 247 |
|
|
| 871 |
|
|
| 0 |
|
|
| 4,405 |
|
|
|
Intersegment sales and transfers for Dominion Energy are based on contractual arrangements and may result in intersegment profit or loss that is eliminated in consolidation, including amounts related to entities presented within discontinued operations.
Virginia Power
The Corporate and Other Segment of Virginia Power primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources.
In 2020,2022, Virginia Power reported after-tax net expenses of $863$792 million in the Corporate and Other segment, including $915$773 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 2022 primarily related to the impact of the following items:
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:
196
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$751 million ($559 million after-tax) charge related to the planned early retirement of certain electric generation facilities, a $130$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$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:
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|
|
|
|
|
|
|
|
|
|
|
In 2018, Virginia Power reported after-tax net expenses of $312 million in the Corporate and Other segment, all of which was for specific items attributable to its operating segment.
The net expenses for specific items attributable to its operating segment in 2018 primarily related to the impact of the following items:197
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|
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) |
|
|
|
|
|
|
|
|
|
|
|
|
2020 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 7,763 |
|
| $ | 0 |
|
| $ | 7,763 |
|
Depreciation and amortization |
|
| 1,245 |
|
|
| 7 |
|
|
| 1,252 |
|
Interest income |
|
| 11 |
|
|
| 0 |
|
|
| 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 |
|
|
| 0 |
|
|
| 3,372 |
|
Total assets (billions) |
|
| 43.7 |
|
|
| 0 |
|
|
| 43.7 |
|
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 8,137 |
|
| $ | (29 | ) |
| $ | 8,108 |
|
Depreciation and amortization |
|
| 1,215 |
|
|
| 8 |
|
|
| 1,223 |
|
Interest income |
|
| 11 |
|
|
| 0 |
|
|
| 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 |
|
|
| 0 |
|
|
| 2,981 |
|
Total assets (billions) |
|
| 41.4 |
|
|
| 0 |
|
|
| 41.4 |
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 7,835 |
|
| $ | (216 | ) |
| $ | 7,619 |
|
Depreciation and amortization |
|
| 1,157 |
|
|
| (25 | ) |
|
| 1,132 |
|
Interest income |
|
| 10 |
|
|
| 0 |
|
|
| 10 |
|
Interest expense (benefit) and related charges |
|
| 516 |
|
|
| (5 | ) |
|
| 511 |
|
Income tax expense (benefit) |
|
| 378 |
|
|
| (78 | ) |
|
| 300 |
|
Net income (loss) |
|
| 1,594 |
|
|
| (312 | ) |
|
| 1,282 |
|
Capital expenditures |
|
| 2,542 |
|
|
| 0 |
|
|
| 2,542 |
|
NOTE 27. QUARTERLY FINANCIAL DATA (UNAUDITED)
A summary of the Companies’ quarterly results of operations for the years ended December 31, 2020 and 2019 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors. In addition, Dominion Energy’s results have been recast reflecting the presentation of operations included in the GT&S Transaction, Q-Pipe Transaction and investment in Atlantic Coast Pipeline as discontinued operations. See Notes 3 and 9 for more information.
Year Ended December 31, |
| Dominion Energy Virginia |
|
| Corporate and Other |
|
| Consolidated |
| |||
(millions) |
|
|
|
|
|
|
|
|
| |||
2022 |
|
|
|
|
|
|
|
|
| |||
Operating revenue |
| $ | 9,643 |
|
| $ | 11 |
|
| $ | 9,654 |
|
Depreciation and amortization |
|
| 1,452 |
|
|
| 284 |
|
|
| 1,736 |
|
Interest income |
|
| 17 |
|
|
| — |
|
|
| 17 |
|
Interest and related charges (benefit) |
|
| 645 |
|
|
| (3 | ) |
|
| 642 |
|
Income tax expense (benefit) |
|
| 411 |
|
|
| (220 | ) |
|
| 191 |
|
Net income (loss) |
|
| 2,007 |
|
|
| (792 | ) |
|
| 1,215 |
|
Capital expenditures |
|
| 5,187 |
|
|
| — |
|
|
| 5,187 |
|
Total assets (billions) |
|
| 53.2 |
|
|
| — |
|
|
| 53.2 |
|
2021 |
|
|
|
|
|
|
|
|
| |||
Operating revenue |
| $ | 7,976 |
|
| $ | (506 | ) |
| $ | 7,470 |
|
Depreciation and amortization |
|
| 1,296 |
|
|
| 68 |
|
|
| 1,364 |
|
Interest income |
|
| 11 |
|
|
| — |
|
|
| 11 |
|
Interest and related charges (benefit) |
|
| 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 and related charges (benefit) |
|
| 524 |
|
|
| (8 | ) |
|
| 516 |
|
Income tax expense (benefit) |
|
| 500 |
|
|
| (271 | ) |
|
| 229 |
|
Net income (loss) |
|
| 1,884 |
|
|
| (863 | ) |
|
| 1,021 |
|
Capital expenditures |
|
| 3,372 |
|
|
| — |
|
|
| 3,372 |
|
Dominion Energy
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 3,938 |
|
| $ | 3,106 |
|
| $ | 3,607 |
|
| $ | 3,521 |
|
Income from continuing operations |
|
| 368 |
|
|
| 804 |
|
|
| 27 |
|
|
| 856 |
|
Net income (loss) from continuing operations including noncontrolling interests |
|
| (468 | ) |
|
| 869 |
|
|
| 112 |
|
|
| 815 |
|
Net income (loss) from discontinued operations including noncontrolling interest |
|
| 229 |
|
|
| (2,001 | ) |
|
| 19 |
|
|
| (125 | ) |
Net income (loss) including noncontrolling interests |
|
| (239 | ) |
|
| (1,132 | ) |
|
| 131 |
|
|
| 690 |
|
Net income (loss) attributable to Dominion Energy |
|
| (270 | ) |
|
| (1,169 | ) |
|
| 356 |
|
|
| 682 |
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations |
|
| (0.57 | ) |
|
| 1.01 |
|
|
| 0.42 |
|
|
| 0.98 |
|
Net income (loss) from discontinued operations |
|
| 0.23 |
|
|
| (2.42 | ) |
|
| (0.01 | ) |
|
| (0.16 | ) |
Net income (loss) attributable to Dominion Energy |
|
| (0.34 | ) |
|
| (1.41 | ) |
|
| 0.41 |
|
|
| 0.82 |
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations |
|
| (0.57 | ) |
|
| 0.90 |
|
|
| 0.42 |
|
|
| 0.98 |
|
Net income (loss) from discontinued operations |
|
| 0.23 |
|
|
| (2.42 | ) |
|
| (0.01 | ) |
|
| (0.16 | ) |
Net income (loss) attributable to Dominion Energy |
|
| (0.34 | ) |
|
| (1.52 | ) |
|
| 0.41 |
|
|
| 0.82 |
|
Dividends declared per preferred share (Series A) |
|
| 4.375 |
|
|
| 4.375 |
|
|
| 4.375 |
|
|
| 4.375 |
|
Dividends declared per preferred share (Series B) |
|
| 11.625 |
|
|
| 11.625 |
|
|
| 11.625 |
|
|
| 11.625 |
|
Dividends declared per common share |
|
| 0.9400 |
|
|
| 0.9400 |
|
|
| 0.9400 |
|
|
| 0.6300 |
|
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 3,281 |
|
| $ | 3,443 |
|
| $ | 3,782 |
|
| $ | 3,895 |
|
Income (loss) from continuing operations |
|
| (744 | ) |
|
| 248 |
|
|
| 1,104 |
|
|
| 936 |
|
Net income (loss) from continuing operations including noncontrolling interests |
|
| (908 | ) |
|
| (199 | ) |
|
| 947 |
|
|
| 820 |
|
Net income (loss) from discontinued operations including noncontrolling interest |
|
| 231 |
|
|
| 257 |
|
|
| 38 |
|
|
| 190 |
|
Net income (loss) including noncontrolling interests |
|
| (677 | ) |
|
| 58 |
|
|
| 985 |
|
|
| 1,010 |
|
Net income (loss) attributable to Dominion Energy |
|
| (680 | ) |
|
| 54 |
|
|
| 975 |
|
|
| 1,009 |
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations |
|
| (1.14 | ) |
|
| (0.25 | ) |
|
| 1.14 |
|
|
| 0.99 |
|
Net income from discontinued operations |
|
| 0.28 |
|
|
| 0.32 |
|
|
| 0.05 |
|
|
| 0.22 |
|
Net income (loss) attributable to Dominion Energy |
|
| (0.86 | ) |
|
| 0.07 |
|
|
| 1.19 |
|
|
| 1.21 |
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) continuing operations |
|
| (1.14 | ) |
|
| (0.25 | ) |
|
| 1.12 |
|
|
| 0.99 |
|
Net income from discontinued operations |
|
| 0.28 |
|
|
| 0.32 |
|
|
| 0.05 |
|
|
| 0.22 |
|
Net income (loss) attributable to Dominion Energy |
|
| (0.86 | ) |
|
| 0.07 |
|
|
| 1.17 |
|
|
| 1.21 |
|
Dividends per share (Series A Preferred Stock) |
|
| — |
|
|
| 0.729 |
|
|
| 4.375 |
|
|
| 4.375 |
|
Dividends per share (Series B Preferred Stock) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1.9375 |
|
Dividends declared per common share |
|
| 0.9175 |
|
|
| 0.9175 |
|
|
| 0.9175 |
|
|
| 0.9175 |
|
Dominion Energy’s 2020 results include the impact of the following significant items:198
|
|
|
|
|
|
|
|
Dominion Energy’s 2019 results include the impact of the following significant items:
|
|
|
|
|
|
Virginia Power
Virginia Power’s quarterly results of operations were as follows:
|
| First Quarter |
|
| Second Quarter |
|
| Third Quarter |
|
| Fourth Quarter |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 1,930 |
|
| $ | 1,805 |
|
| $ | 2,248 |
|
| $ | 1,780 |
|
Income (loss) from operations |
|
| (133 | ) |
|
| 635 |
|
|
| 687 |
|
|
| 497 |
|
Net income (loss) |
|
| (280 | ) |
|
| 490 |
|
|
| 475 |
|
|
| 336 |
|
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 1,965 |
|
| $ | 1,938 |
|
| $ | 2,264 |
|
| $ | 1,941 |
|
Income from operations |
|
| 122 |
|
|
| 238 |
|
|
| 820 |
|
|
| 659 |
|
Net income |
|
| 20 |
|
|
| 100 |
|
|
| 602 |
|
|
| 427 |
|
Virginia Power’s 2020 results include the impact of the following significant items:
|
|
|
|
|
|
Virginia Power’s 2019 results include the impact of the following significant items:
|
|
|
|
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 20202022 Annual Report to contain a management's report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for the report, Dominion Energy tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2020,2022, Dominion Energy makes the following assertions:
Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion Energy.
There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.
Management evaluated Dominion Energy’s internal control over financial reporting as of December 31, 2020.2022. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion Energy maintained effective internal control over financial reporting as of December 31, 2020.2022.
Dominion Energy’s independent registered public accounting firm is engaged to express an opinion on Dominion Energy’s internal control over financial reporting, as stated in their report which is included herein.
February 25, 202121, 2023
199
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Dominion Energy, Inc.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Dominion Energy, Inc. and subsidiaries (“Dominion Energy”) at December 31, 2020,2022, based on criteria established in Internal Control—Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).In our opinion, Dominion Energy maintained, in all material respects, effective internal control over financial reporting at December 31, 2020,2022, based on criteria established in Internal Control—Control — Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements at and for the year ended December 31, 2020,2022, of Dominion Energy and our report dated February 25, 2021,21, 2023, expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
Dominion Energy’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Dominion Energy’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Dominion Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 25, 202121, 2023
200
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 20202022 Annual Report to contain a management's report regarding the effectiveness of internal control. As a basis for the report, Virginia Power tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2020,2022, Virginia Power makes the following assertions:
Management is responsible for establishing and maintaining effective internal control over financial reporting of Virginia Power.
There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.
Management evaluated Virginia Power's internal control over financial reporting as of December 31, 2020.2022. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Virginia Power maintained effective internal control over financial reporting as of December 31, 2020.2022.
This annual report does not include an attestation report of Virginia Power's registered public accounting firm regarding internal control over financial reporting. Management's report is not subject to attestation by Virginia Power's independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.
February 25, 202121, 2023
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Item 9B. Other Information
None.
Explanatory Note: The following information is filed in this Form 10-K in lieu of being filed pursuant to Item 5.03 in a Form 8-K. The date of the events reported below was February 20, 2023.
On February 20, 2023, the Board of Directors, as part of a periodic review of Dominion Energy’s governance documents, approved changes to Dominion Energy’s Bylaws, effective as of February 20, 2023. The amendments, among other things:
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The foregoing description of the amendments to Dominion Energy’s Bylaws is qualified in its entirety by reference to the full text of Dominion Energy’s Bylaws, a copy of which is attached hereto as Exhibit 3.2.a and is incorporated herein by reference.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
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Part III
Item 10. Directors, Executive Officers and Corporate Governance
DOMINION ENERGY
The following information for Dominion Energyrequired by this item is incorporated by reference fromto 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 20212023 Proxy Statement, which will be filed on or around March 19, 2021:Statement.
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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.Officers. Each executive officer of Dominion Energy is elected annually.
Item 11. Executive Compensation
DOMINION ENERGY
The following information about Dominion Energy is contained in the 2021 Proxy Statement andrequired by this item is incorporated by reference:
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
DOMINION ENERGY
The information concerning stock ownershiprequired by directors, executive officers and five percent beneficial owners contained underthis item is incorporated by reference to the heading sections entitled Security Ownership of Certain Beneficial Owners and Management and Executive Compensation—Equity Compensation Plans in the 20212023 Proxy Statement is incorporated by reference.Statement.
The information regarding equity securities of Dominion Energy that are authorized for issuance under its equity compensation plans contained under the heading Executive Compensation—Executive Compensation Tables—Equity Compensation Plans in the 2021 Proxy Statement is incorporated by reference.
DOMINION ENERGY
The information regarding related party transactions required by this item found underis incorporated by reference to the heading sections entitled Corporate Governance—CertainOther Governance Policies and Practices —Certain Relationships and Related Party Transactions and information regarding director independence found under the heading Corporate Governance—DirectorGovernance —Director Independence in the 20212023 Proxy Statement is incorporated by reference.Statement.
Item 14. Principal Accountant Fees and Services
DOMINION ENERGY
The information concerning principal accountant fees and services contained underrequired by this item is incorporated by reference to the heading section entitled Audit-Related Matters—Auditor Fees and Pre-Approval Policy in the 20212023 Proxy Statement is incorporated by reference.Statement.
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, 20202022 and 2019.2021.
Type of Fees |
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(millions) |
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Virginia Power |
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Audit fees |
| $ | 2.30 |
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| $ | 2.13 |
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| $ | 2.44 |
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| $ | 2.37 |
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Audit-related fees |
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| 0.08 |
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Tax fees |
| — |
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| 0.04 |
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All other fees |
| — |
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Total Fees |
| $ | 2.30 |
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| $ | 2.13 |
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| $ | 2.52 |
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| $ | 2.41 |
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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
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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 20202022 meeting, the Dominion Energy Audit Committee approved schedules of services and fees for 20212023 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.
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Part IV
Item 15. Exhibits and Financial Statement Schedules
(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.
1. Financial Statements
See Index on page 85.86.
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 | X | ||||||
2.1.b |
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3.1.a | |||||||
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3.1.b | X | ||||||
3.2.a | X | ||||||
3.2.b | 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 | X | ||||||
4.1.b | 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 | ||||
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Exhibit Number | Description | Dominion Energy | Virginia Power | ||||
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10.21* | X | |||||||
10.22* | X | |||||||
10.23* | X | |||||||
10.24* | Restricted Stock Agreement for Steven D. Ridge (filed herewith). | X | ||||||
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Exhibit Number | Description | Dominion Energy | Virginia Power | |||
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10.28* | X | |||||
21 | X | |||||
23 | X | X | ||||
31.a | X | |||||
31.b | X | |||||
31.c | X | |||||
31.d | X | |||||
32.a | X | |||||
32.b | X | |||||
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101 |
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104 | Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101. | X | X | ||||
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* Indicates management contract or compensatory plan or arrangement.
Item 16. Form 10-K Summary
None.
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Signatures
DOMINIONDOMINION ENERGY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DOMINION ENERGY, INC. | |
By: | /s/ Robert M. Blue |
(Robert M. Blue, President and Chief Executive Officer) |
Date: February 25, 202121, 2023
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 25th21st day of February, 2021.2023.
Signature | Title | |
/s/ Robert M. Blue Robert M. Blue | ||
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/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/ Kristin G. Lovejoy | Director | |
Kristin G. Lovejoy | ||
/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/
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/s/ Michele L. Cardiff Michele L. Cardiff | Senior Vice President, Controller and Chief Accounting Officer | |
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Virginia Power
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
VIRGINIA ELECTRIC AND POWER COMPANY | ||
By: | /s/ Robert M. Blue | |
(Robert M. Blue, Chief Executive Officer) |
Date: February 25, 202121, 2023
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 25th21st day of February, 2021.2023.
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/
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/s/ Michele L. Cardiff Michele L. Cardiff | Senior Vice President, Controller and Chief Accounting Officer |
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